Abstract
The world stands before the critical mission of mitigating climate change by reducing greenhouse gas emissions at such a pace that catastrophic repercussions are avoided. A primary step towards this goal is to decarbonize the energy sector. This task involves a massive rollout of renewables to replace the fossil-fueled energy supply and to meet a growing demand for electricity resulting from the transformation of all energy sectors. As variable renewable energy increasingly emerges as the predominant source of electricity, the generation of electricity becomes more volatile. Consequently, future energy systems must be equipped with adequate backup and storage infrastructure to ensure a reliable energy supply. This PhD thesis, written as a compilation of research articles, adopts a bottom-up energy system modeling approach that rely on techno-economic optimization to provide insight into this context. The investigations focus on a future sector-coupled European energy system, encompassing the determination of electricity storage technology requirements to qualify in a competitive market, an exploration of energy-related impacts of climate change and interannual weather variability, and the examination of cost-optimal measures to ensure robustness to interannual weather variability and fuel import disruptions.
The first study, presented in Chapter 2, addresses a gap in the literature concerning energy storage. While most literature has primarily focused on estimating the volume of electricity storage needed at certain decarbonization levels or in response to specific weather events driving the demand for long-duration storage, it has often assumed a limited portfolio of storage technologies. The analysis conducted in this PhD thesis evaluates a space of fictive electricity storage configurations with the following two findings: First, it demonstrates the relative importance of each of six cost and efficiency parameters used in the characterization of a storage technology. Second, it quantifies the combinations of parameters necessary for an entry into a competitive market. The findings underscore that discharge efficiency and energy capacity costs are pivotal determinants of a technology’s competitiveness, regardless of the degree of sector-coupling.
The study presented in Chapter 3 examines the long-term consequences of a reduced natural gas supply in the European transition toward 2050, considering two different CO2 emissions budgets corresponding to global warming of 1.5C and 2C. The results emphasize the significance of an early and rapid mitigation strategy to comply with the 1.5C ambitions, regardless of the European gas supply. Allowing for a higher CO2 emissions budget, corresponding to a 2C warming scenario, eases the pace of transition. This relaxation leads to the retention of Europe’s dependence on natural gas in the short term, causing a higher sensitivity to gas supply disruptions. With the constrained gas supply, and a larger CO2 emissions budget, the gas prices encounter a noticeable increase. However, the price increase incentivizes a stronger push on the rollout of renewable generation and electrified heating, which in the 1.5C scenario was predominantly driven by a more stringent CO2 emissions price.
In the following two chapters, the focus shifts to the examination of climate and weather variability. In Chapter 4, an assessment of the vulnerability of hydropower resources to future climate change is conducted. By utilizing an ensemble of regional climate models to derive time series projections of future inflow patterns, the findings reveal a North-South dipole in the changes in annual resources with statistical significance across most countries, along with a probable alteration in the frequency and duration of periods with extreme inflow levels. The study further indicates a large interannual variability of hydropower inflow, raising concerns regarding the robustness of future energy systems to general weather variability. In Chapter 5, historical weather data from 1960 to 2021 is incorporated into the optimization of capacity layouts in a European energy system, designed for net-zero CO2 emissions. By accounting for interannual variability of wind energy, solar PV, hydropower inflow, heating demand, and coefficient of performance (COP) of heat pumps, the analysis demonstrates variation of 10% in total system cost. By simulating all capacity layouts across each historical weather year, the results reveal layouts capable of withstanding all historical weather conditions without violating the net-zero CO2 emissions target, with minimal unserved energy. Achieving this necessitates an increased backup reserve fleet in central Europe, while southwestern Europe requires additional H2 infrastructure to enhance interconnection between the Iberian Peninsula and central Europe, alongside increased deployment of H2 storage in western Europe.
Chapter 6 expands the scope to encompass Europe in a global setting, employing an integrated assessment model (IAM). Alongside other factors, IAMs include intercontinental energy trades, track other greenhouse gases beyond CO2 including CH4 from livestock manure, while also employing detailed accounting of the land use, land use change, and forestry (LULUCF) sector. A gap exists in the literature between studies performed with IAMs and bottom-up energy system models, which is addressed in this analysis. First, key differences in the electricity mixes are assessed, followed by a sensitivity study of the constraints used to account for the sub-annual variability of wind and solar PV generation. The results highlight that the constraint accounting for the integration cost has the strongest impact on the renewable share of electricity. The initial stages of a soft-linking process with a bottom-up energy system model demonstrate potential for aligning outputs more closely but require further research for a complete impact assessment.
The studies included in this PhD thesis rely on open energy system modeling to ensure full transparency, and they provide key insights relevant for energy modelers, technology developers, and policy makers.
The first study, presented in Chapter 2, addresses a gap in the literature concerning energy storage. While most literature has primarily focused on estimating the volume of electricity storage needed at certain decarbonization levels or in response to specific weather events driving the demand for long-duration storage, it has often assumed a limited portfolio of storage technologies. The analysis conducted in this PhD thesis evaluates a space of fictive electricity storage configurations with the following two findings: First, it demonstrates the relative importance of each of six cost and efficiency parameters used in the characterization of a storage technology. Second, it quantifies the combinations of parameters necessary for an entry into a competitive market. The findings underscore that discharge efficiency and energy capacity costs are pivotal determinants of a technology’s competitiveness, regardless of the degree of sector-coupling.
The study presented in Chapter 3 examines the long-term consequences of a reduced natural gas supply in the European transition toward 2050, considering two different CO2 emissions budgets corresponding to global warming of 1.5C and 2C. The results emphasize the significance of an early and rapid mitigation strategy to comply with the 1.5C ambitions, regardless of the European gas supply. Allowing for a higher CO2 emissions budget, corresponding to a 2C warming scenario, eases the pace of transition. This relaxation leads to the retention of Europe’s dependence on natural gas in the short term, causing a higher sensitivity to gas supply disruptions. With the constrained gas supply, and a larger CO2 emissions budget, the gas prices encounter a noticeable increase. However, the price increase incentivizes a stronger push on the rollout of renewable generation and electrified heating, which in the 1.5C scenario was predominantly driven by a more stringent CO2 emissions price.
In the following two chapters, the focus shifts to the examination of climate and weather variability. In Chapter 4, an assessment of the vulnerability of hydropower resources to future climate change is conducted. By utilizing an ensemble of regional climate models to derive time series projections of future inflow patterns, the findings reveal a North-South dipole in the changes in annual resources with statistical significance across most countries, along with a probable alteration in the frequency and duration of periods with extreme inflow levels. The study further indicates a large interannual variability of hydropower inflow, raising concerns regarding the robustness of future energy systems to general weather variability. In Chapter 5, historical weather data from 1960 to 2021 is incorporated into the optimization of capacity layouts in a European energy system, designed for net-zero CO2 emissions. By accounting for interannual variability of wind energy, solar PV, hydropower inflow, heating demand, and coefficient of performance (COP) of heat pumps, the analysis demonstrates variation of 10% in total system cost. By simulating all capacity layouts across each historical weather year, the results reveal layouts capable of withstanding all historical weather conditions without violating the net-zero CO2 emissions target, with minimal unserved energy. Achieving this necessitates an increased backup reserve fleet in central Europe, while southwestern Europe requires additional H2 infrastructure to enhance interconnection between the Iberian Peninsula and central Europe, alongside increased deployment of H2 storage in western Europe.
Chapter 6 expands the scope to encompass Europe in a global setting, employing an integrated assessment model (IAM). Alongside other factors, IAMs include intercontinental energy trades, track other greenhouse gases beyond CO2 including CH4 from livestock manure, while also employing detailed accounting of the land use, land use change, and forestry (LULUCF) sector. A gap exists in the literature between studies performed with IAMs and bottom-up energy system models, which is addressed in this analysis. First, key differences in the electricity mixes are assessed, followed by a sensitivity study of the constraints used to account for the sub-annual variability of wind and solar PV generation. The results highlight that the constraint accounting for the integration cost has the strongest impact on the renewable share of electricity. The initial stages of a soft-linking process with a bottom-up energy system model demonstrate potential for aligning outputs more closely but require further research for a complete impact assessment.
The studies included in this PhD thesis rely on open energy system modeling to ensure full transparency, and they provide key insights relevant for energy modelers, technology developers, and policy makers.
| Translated title of the contribution | Energilagring og klimamæssige indvirkninger på fremtidens Europæiske energisystem |
|---|---|
| Original language | English |
| Place of publication | Aarhus |
|---|---|
| Publisher | Aarhus University |
| Number of pages | 165 |
| Publication status | Published - Jul 2024 |
Keywords
- energy transition
- energy storage
- Energy system modeling
- Open energy modelling
- sector-coupling
- weather variability
- climate change
- Integrated assessment modelling (IAM)