M.A. van den Broek
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Cost, Emissions, and Resilience Trade-Offs in the Design and Operation of an Urban Port Energy System
A Case Study of the Port of Trieste
Urban ports combine electricity, heat, cooling, and fuel supply and are rapidly electrifying. Shore power, a central instrument of European port policy, does not remove the energy demand of berthed vessels but relocates it into a port network that can also supply buildings and terminal operations. Existing studies usually design such systems under a single objective, most often cost minimisation, and treat emissions, policy instruments, resilience, and physical network limits separately. It therefore remains unclear how much of the resulting design follows from the available technologies and how much from the goals and constraints imposed on the system.
This thesis develops an integrated port energy system model covering electricity, heat, cooling, and hydrogen, which jointly determines technology capacities and hourly operation over a full year using mixed integer linear programming. Unlike comparable studies, it resolves the internal electricity network at the individual bus level, so that voltage limits and cable ratings constrain flows within the port, and it represents the district heating network through hourly selectable supply temperature classes. Seven scenarios compare cost and emission minimisation, carbon pricing, an emission cap, reduced grid dependence, and tighter internal network limits against a Baseline without investment. The framework is applied to the Port of Trieste, with berth demand reconstructed from observed vessel movements.
Introducing shore power together with a system design that allows investment roughly halves annual port emissions, while final emissions differ little across scenarios in which investment is permitted. Under the assumed gas and electricity prices, cost minimisation already selects extensive heat electrification and additional photovoltaics, so the carbon price and the emission cap produce almost no design response. Approximately four fifths of the remaining emissions originate from auxiliary boilers aboard berthed vessels, which shore power does not reach. A clearer tradeoff emerges between electrification and grid dependence: peak grid import rises roughly fivefold, and only an explicit penalty on that peak reverses it. Tighter internal cable limits leave the external peak almost unchanged but restrict rooftop photovoltaic deployment, an effect that an aggregated model with a single network node would not reveal.
...
This thesis develops an integrated port energy system model covering electricity, heat, cooling, and hydrogen, which jointly determines technology capacities and hourly operation over a full year using mixed integer linear programming. Unlike comparable studies, it resolves the internal electricity network at the individual bus level, so that voltage limits and cable ratings constrain flows within the port, and it represents the district heating network through hourly selectable supply temperature classes. Seven scenarios compare cost and emission minimisation, carbon pricing, an emission cap, reduced grid dependence, and tighter internal network limits against a Baseline without investment. The framework is applied to the Port of Trieste, with berth demand reconstructed from observed vessel movements.
Introducing shore power together with a system design that allows investment roughly halves annual port emissions, while final emissions differ little across scenarios in which investment is permitted. Under the assumed gas and electricity prices, cost minimisation already selects extensive heat electrification and additional photovoltaics, so the carbon price and the emission cap produce almost no design response. Approximately four fifths of the remaining emissions originate from auxiliary boilers aboard berthed vessels, which shore power does not reach. A clearer tradeoff emerges between electrification and grid dependence: peak grid import rises roughly fivefold, and only an explicit penalty on that peak reverses it. Tighter internal cable limits leave the external peak almost unchanged but restrict rooftop photovoltaic deployment, an effect that an aggregated model with a single network node would not reveal.
...
Urban ports combine electricity, heat, cooling, and fuel supply and are rapidly electrifying. Shore power, a central instrument of European port policy, does not remove the energy demand of berthed vessels but relocates it into a port network that can also supply buildings and terminal operations. Existing studies usually design such systems under a single objective, most often cost minimisation, and treat emissions, policy instruments, resilience, and physical network limits separately. It therefore remains unclear how much of the resulting design follows from the available technologies and how much from the goals and constraints imposed on the system.
This thesis develops an integrated port energy system model covering electricity, heat, cooling, and hydrogen, which jointly determines technology capacities and hourly operation over a full year using mixed integer linear programming. Unlike comparable studies, it resolves the internal electricity network at the individual bus level, so that voltage limits and cable ratings constrain flows within the port, and it represents the district heating network through hourly selectable supply temperature classes. Seven scenarios compare cost and emission minimisation, carbon pricing, an emission cap, reduced grid dependence, and tighter internal network limits against a Baseline without investment. The framework is applied to the Port of Trieste, with berth demand reconstructed from observed vessel movements.
Introducing shore power together with a system design that allows investment roughly halves annual port emissions, while final emissions differ little across scenarios in which investment is permitted. Under the assumed gas and electricity prices, cost minimisation already selects extensive heat electrification and additional photovoltaics, so the carbon price and the emission cap produce almost no design response. Approximately four fifths of the remaining emissions originate from auxiliary boilers aboard berthed vessels, which shore power does not reach. A clearer tradeoff emerges between electrification and grid dependence: peak grid import rises roughly fivefold, and only an explicit penalty on that peak reverses it. Tighter internal cable limits leave the external peak almost unchanged but restrict rooftop photovoltaic deployment, an effect that an aggregated model with a single network node would not reveal.
This thesis develops an integrated port energy system model covering electricity, heat, cooling, and hydrogen, which jointly determines technology capacities and hourly operation over a full year using mixed integer linear programming. Unlike comparable studies, it resolves the internal electricity network at the individual bus level, so that voltage limits and cable ratings constrain flows within the port, and it represents the district heating network through hourly selectable supply temperature classes. Seven scenarios compare cost and emission minimisation, carbon pricing, an emission cap, reduced grid dependence, and tighter internal network limits against a Baseline without investment. The framework is applied to the Port of Trieste, with berth demand reconstructed from observed vessel movements.
Introducing shore power together with a system design that allows investment roughly halves annual port emissions, while final emissions differ little across scenarios in which investment is permitted. Under the assumed gas and electricity prices, cost minimisation already selects extensive heat electrification and additional photovoltaics, so the carbon price and the emission cap produce almost no design response. Approximately four fifths of the remaining emissions originate from auxiliary boilers aboard berthed vessels, which shore power does not reach. A clearer tradeoff emerges between electrification and grid dependence: peak grid import rises roughly fivefold, and only an explicit penalty on that peak reverses it. Tighter internal cable limits leave the external peak almost unchanged but restrict rooftop photovoltaic deployment, an effect that an aggregated model with a single network node would not reveal.
Net-Zero European Ethylene Production
A Modelling-Based Scenario Analysis of Cost-Competitive Routes for Net-Zero Ethylene Production in Europe
The steam cracking process currently utilized to produce ethylene and several other chemicals is one of the highest emitting individual processes in the chemical industry. This study utilizes a linear-programming (LP) model to find cost-effective production routes and abatement alternatives to reach
net-zero emissions by 2050 for EU ethylene production. Reaching net-zero results in a scenario cost between 18.8 and 24.5 billion EUR/year compared to a 12.0 billion EUR/year reference scenario with-out a net-zero constraint. This figure is impacted by the assumption of end-of-life (EoL) incineration, which contributes 9.3 Billion EUR/year to the total cost. Scenarios that preserve EU production capacity are found to be more expensive than scenarios that allow relocation, as ethane-based ethylene production is cheaper in the US under the adopted feedstock cost assumptions. Across scenarios that preserve EU capacity, bionaphtha utilization in steam crackers is found to be a cost-competitive abatement option with cost below electrification and carbon capture. Results suggest that bionaphtha utilization may result in lower net-zero cost over the whole value chain compared to an approach where
steam crackers and EoL incineration facilities focus on their own scope 1 emissions. Constraints on assessed naphtha substitutes limits their contribution to 19% of the 15 Mt/y ethylene demand assumption. Net-zero scenarios increase electricity consumption between 38.1 and 47.2 TWh/year, and are dominated by Direct Air Carbon Capture and Storage (DACCS) despite the fact that DACCS captures only a limited amount of total CO2 emissions. This result is not robust as modest changes in DACCS cost assumptions increase electric cracking adoption in lower electricity cost regions. The approach to minimize only ethylene production cost results in increased adoption of ethane-based production routes that are both less energy intensive and cheaper. The cost minimization for ethylene production does not account for the change in co-product output when ethane-based routes instead of naphtha-based routes are adopted, which is a limitation to the modelling approach. As no bio-based feedstock alternatives were identified for ethane crackers, adopting this route potentially constitutes a lock-in in utilizing CCS to reach net-zero, with the risk of higher net-zero cost if cost reductions towards 2050 do not materialize. ...
net-zero emissions by 2050 for EU ethylene production. Reaching net-zero results in a scenario cost between 18.8 and 24.5 billion EUR/year compared to a 12.0 billion EUR/year reference scenario with-out a net-zero constraint. This figure is impacted by the assumption of end-of-life (EoL) incineration, which contributes 9.3 Billion EUR/year to the total cost. Scenarios that preserve EU production capacity are found to be more expensive than scenarios that allow relocation, as ethane-based ethylene production is cheaper in the US under the adopted feedstock cost assumptions. Across scenarios that preserve EU capacity, bionaphtha utilization in steam crackers is found to be a cost-competitive abatement option with cost below electrification and carbon capture. Results suggest that bionaphtha utilization may result in lower net-zero cost over the whole value chain compared to an approach where
steam crackers and EoL incineration facilities focus on their own scope 1 emissions. Constraints on assessed naphtha substitutes limits their contribution to 19% of the 15 Mt/y ethylene demand assumption. Net-zero scenarios increase electricity consumption between 38.1 and 47.2 TWh/year, and are dominated by Direct Air Carbon Capture and Storage (DACCS) despite the fact that DACCS captures only a limited amount of total CO2 emissions. This result is not robust as modest changes in DACCS cost assumptions increase electric cracking adoption in lower electricity cost regions. The approach to minimize only ethylene production cost results in increased adoption of ethane-based production routes that are both less energy intensive and cheaper. The cost minimization for ethylene production does not account for the change in co-product output when ethane-based routes instead of naphtha-based routes are adopted, which is a limitation to the modelling approach. As no bio-based feedstock alternatives were identified for ethane crackers, adopting this route potentially constitutes a lock-in in utilizing CCS to reach net-zero, with the risk of higher net-zero cost if cost reductions towards 2050 do not materialize. ...
The steam cracking process currently utilized to produce ethylene and several other chemicals is one of the highest emitting individual processes in the chemical industry. This study utilizes a linear-programming (LP) model to find cost-effective production routes and abatement alternatives to reach
net-zero emissions by 2050 for EU ethylene production. Reaching net-zero results in a scenario cost between 18.8 and 24.5 billion EUR/year compared to a 12.0 billion EUR/year reference scenario with-out a net-zero constraint. This figure is impacted by the assumption of end-of-life (EoL) incineration, which contributes 9.3 Billion EUR/year to the total cost. Scenarios that preserve EU production capacity are found to be more expensive than scenarios that allow relocation, as ethane-based ethylene production is cheaper in the US under the adopted feedstock cost assumptions. Across scenarios that preserve EU capacity, bionaphtha utilization in steam crackers is found to be a cost-competitive abatement option with cost below electrification and carbon capture. Results suggest that bionaphtha utilization may result in lower net-zero cost over the whole value chain compared to an approach where
steam crackers and EoL incineration facilities focus on their own scope 1 emissions. Constraints on assessed naphtha substitutes limits their contribution to 19% of the 15 Mt/y ethylene demand assumption. Net-zero scenarios increase electricity consumption between 38.1 and 47.2 TWh/year, and are dominated by Direct Air Carbon Capture and Storage (DACCS) despite the fact that DACCS captures only a limited amount of total CO2 emissions. This result is not robust as modest changes in DACCS cost assumptions increase electric cracking adoption in lower electricity cost regions. The approach to minimize only ethylene production cost results in increased adoption of ethane-based production routes that are both less energy intensive and cheaper. The cost minimization for ethylene production does not account for the change in co-product output when ethane-based routes instead of naphtha-based routes are adopted, which is a limitation to the modelling approach. As no bio-based feedstock alternatives were identified for ethane crackers, adopting this route potentially constitutes a lock-in in utilizing CCS to reach net-zero, with the risk of higher net-zero cost if cost reductions towards 2050 do not materialize.
net-zero emissions by 2050 for EU ethylene production. Reaching net-zero results in a scenario cost between 18.8 and 24.5 billion EUR/year compared to a 12.0 billion EUR/year reference scenario with-out a net-zero constraint. This figure is impacted by the assumption of end-of-life (EoL) incineration, which contributes 9.3 Billion EUR/year to the total cost. Scenarios that preserve EU production capacity are found to be more expensive than scenarios that allow relocation, as ethane-based ethylene production is cheaper in the US under the adopted feedstock cost assumptions. Across scenarios that preserve EU capacity, bionaphtha utilization in steam crackers is found to be a cost-competitive abatement option with cost below electrification and carbon capture. Results suggest that bionaphtha utilization may result in lower net-zero cost over the whole value chain compared to an approach where
steam crackers and EoL incineration facilities focus on their own scope 1 emissions. Constraints on assessed naphtha substitutes limits their contribution to 19% of the 15 Mt/y ethylene demand assumption. Net-zero scenarios increase electricity consumption between 38.1 and 47.2 TWh/year, and are dominated by Direct Air Carbon Capture and Storage (DACCS) despite the fact that DACCS captures only a limited amount of total CO2 emissions. This result is not robust as modest changes in DACCS cost assumptions increase electric cracking adoption in lower electricity cost regions. The approach to minimize only ethylene production cost results in increased adoption of ethane-based production routes that are both less energy intensive and cheaper. The cost minimization for ethylene production does not account for the change in co-product output when ethane-based routes instead of naphtha-based routes are adopted, which is a limitation to the modelling approach. As no bio-based feedstock alternatives were identified for ethane crackers, adopting this route potentially constitutes a lock-in in utilizing CCS to reach net-zero, with the risk of higher net-zero cost if cost reductions towards 2050 do not materialize.
Deployment of Small Modular Reactors with cogeneration in High-Renewable energy systems
Assessment of their Cost-Effectiveness and System Impacts
Storage for electrified industry
A cost-effective solution to ensure reliable operation of a 500 MW industrial load
Master thesis
(2024)
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C.S. Tonnaer, J.L. Rueda Torres, M.A. van den Broek, G.R. Chandra Mouli, G. Van Der Ploeg
Industrial electrification has a crucial role to play in reducing carbon dioxide emissions, and ensuring power reliability is an important factor in this process. Therefore, this thesis explores cost-effective storage to ensure the reliable operation of the renewable energy-based power supply of a 500 MW electrified industrial load in the 2035 Botlek area in the Rotterdam harbour. The study focuses on integrating electrical storage solutions to mitigate external power system risks that threaten reliability.
The research identifies key external risks to be energy shortages, power outages, frequency fluctuations and voltage instability. After a comprehensive review of current and emerging storage technologies, three storage mitigation strategies are formulated based on financial, technical, practical and other aspects. A synthetic industrial model consisting of generic component representations in DIgSILENT PowerFactory 2024 SP1 based on an electrified version of the Shell Pernis refinery is used. It is adapted to represent the Botlek 2035 study case, the storage assets are integrated and inputs are defined to represent on-site wind power generation and connection to the external future Dutch power system. 20% of peak demand is assumed to be flexible based on the residual load in the Dutch power system in 2035.
Via a dispatch simulation, the performance of each strategy is assessed. The loss of load expectation and expected energy not supplied are used as reliability metrics. The costs of plant interruption, storage system costs and electricity costs are used to select a strategy. Results are subjected to several input and parametric sensitivities.
Results indicate the combination of a Lithium iron phosphate battery, an alkaline electrolyser, magnesium hydride storage and a hydrogen turbine can ensure reliable operation most cost-effectively. Hydride storage is identified as a technology with much potential for industrial integration due to the advantages of waste heat utilization for hydride dehydrogenation. Extreme weather scenarios are advised to be covered with externally sourced fuel instead of on-site storage reserves. A 10.5 GWh or 315 tonne hydrogen storage system is expected to be required for reliable operation in the Dutch power system, when 20% of peak demand is modelled as flexible. This configuration yields to an average levelized cost of energy of 45.3 €/MWh during the year compared to 45.7 €/MWh without storage while also ensuring reliable operation without significant interruption costs.
This thesis provides insight into the integration of storage assets in electrified industrial networks in the context of the future Dutch energy system and lays a foundation for further research. ...
The research identifies key external risks to be energy shortages, power outages, frequency fluctuations and voltage instability. After a comprehensive review of current and emerging storage technologies, three storage mitigation strategies are formulated based on financial, technical, practical and other aspects. A synthetic industrial model consisting of generic component representations in DIgSILENT PowerFactory 2024 SP1 based on an electrified version of the Shell Pernis refinery is used. It is adapted to represent the Botlek 2035 study case, the storage assets are integrated and inputs are defined to represent on-site wind power generation and connection to the external future Dutch power system. 20% of peak demand is assumed to be flexible based on the residual load in the Dutch power system in 2035.
Via a dispatch simulation, the performance of each strategy is assessed. The loss of load expectation and expected energy not supplied are used as reliability metrics. The costs of plant interruption, storage system costs and electricity costs are used to select a strategy. Results are subjected to several input and parametric sensitivities.
Results indicate the combination of a Lithium iron phosphate battery, an alkaline electrolyser, magnesium hydride storage and a hydrogen turbine can ensure reliable operation most cost-effectively. Hydride storage is identified as a technology with much potential for industrial integration due to the advantages of waste heat utilization for hydride dehydrogenation. Extreme weather scenarios are advised to be covered with externally sourced fuel instead of on-site storage reserves. A 10.5 GWh or 315 tonne hydrogen storage system is expected to be required for reliable operation in the Dutch power system, when 20% of peak demand is modelled as flexible. This configuration yields to an average levelized cost of energy of 45.3 €/MWh during the year compared to 45.7 €/MWh without storage while also ensuring reliable operation without significant interruption costs.
This thesis provides insight into the integration of storage assets in electrified industrial networks in the context of the future Dutch energy system and lays a foundation for further research. ...
Industrial electrification has a crucial role to play in reducing carbon dioxide emissions, and ensuring power reliability is an important factor in this process. Therefore, this thesis explores cost-effective storage to ensure the reliable operation of the renewable energy-based power supply of a 500 MW electrified industrial load in the 2035 Botlek area in the Rotterdam harbour. The study focuses on integrating electrical storage solutions to mitigate external power system risks that threaten reliability.
The research identifies key external risks to be energy shortages, power outages, frequency fluctuations and voltage instability. After a comprehensive review of current and emerging storage technologies, three storage mitigation strategies are formulated based on financial, technical, practical and other aspects. A synthetic industrial model consisting of generic component representations in DIgSILENT PowerFactory 2024 SP1 based on an electrified version of the Shell Pernis refinery is used. It is adapted to represent the Botlek 2035 study case, the storage assets are integrated and inputs are defined to represent on-site wind power generation and connection to the external future Dutch power system. 20% of peak demand is assumed to be flexible based on the residual load in the Dutch power system in 2035.
Via a dispatch simulation, the performance of each strategy is assessed. The loss of load expectation and expected energy not supplied are used as reliability metrics. The costs of plant interruption, storage system costs and electricity costs are used to select a strategy. Results are subjected to several input and parametric sensitivities.
Results indicate the combination of a Lithium iron phosphate battery, an alkaline electrolyser, magnesium hydride storage and a hydrogen turbine can ensure reliable operation most cost-effectively. Hydride storage is identified as a technology with much potential for industrial integration due to the advantages of waste heat utilization for hydride dehydrogenation. Extreme weather scenarios are advised to be covered with externally sourced fuel instead of on-site storage reserves. A 10.5 GWh or 315 tonne hydrogen storage system is expected to be required for reliable operation in the Dutch power system, when 20% of peak demand is modelled as flexible. This configuration yields to an average levelized cost of energy of 45.3 €/MWh during the year compared to 45.7 €/MWh without storage while also ensuring reliable operation without significant interruption costs.
This thesis provides insight into the integration of storage assets in electrified industrial networks in the context of the future Dutch energy system and lays a foundation for further research.
The research identifies key external risks to be energy shortages, power outages, frequency fluctuations and voltage instability. After a comprehensive review of current and emerging storage technologies, three storage mitigation strategies are formulated based on financial, technical, practical and other aspects. A synthetic industrial model consisting of generic component representations in DIgSILENT PowerFactory 2024 SP1 based on an electrified version of the Shell Pernis refinery is used. It is adapted to represent the Botlek 2035 study case, the storage assets are integrated and inputs are defined to represent on-site wind power generation and connection to the external future Dutch power system. 20% of peak demand is assumed to be flexible based on the residual load in the Dutch power system in 2035.
Via a dispatch simulation, the performance of each strategy is assessed. The loss of load expectation and expected energy not supplied are used as reliability metrics. The costs of plant interruption, storage system costs and electricity costs are used to select a strategy. Results are subjected to several input and parametric sensitivities.
Results indicate the combination of a Lithium iron phosphate battery, an alkaline electrolyser, magnesium hydride storage and a hydrogen turbine can ensure reliable operation most cost-effectively. Hydride storage is identified as a technology with much potential for industrial integration due to the advantages of waste heat utilization for hydride dehydrogenation. Extreme weather scenarios are advised to be covered with externally sourced fuel instead of on-site storage reserves. A 10.5 GWh or 315 tonne hydrogen storage system is expected to be required for reliable operation in the Dutch power system, when 20% of peak demand is modelled as flexible. This configuration yields to an average levelized cost of energy of 45.3 €/MWh during the year compared to 45.7 €/MWh without storage while also ensuring reliable operation without significant interruption costs.
This thesis provides insight into the integration of storage assets in electrified industrial networks in the context of the future Dutch energy system and lays a foundation for further research.
The decision to relocate Indonesia’s capital city from Jakarta to East Kalimantan is driven by a range of factors, including the need to decentralize economic activity and address Jakarta’s environmental issues. The New Capital City (IKN) is being developed as a sustainable urban center with the goal of becoming carbon-neutral by 2045. Law No. 3 of 2022 mandates that IKN will rely on 100 percent renewable electricity by 2045, underscoring the Indonesian government’s commitment to sustainability in the city. However, achieving this ambitious target presents significant challenges, particularly in terms of energy demand, renewable energy availability, and coordination across multiple sectors.
This research focuses on addressing these challenges by exploring the most cost-effective renewable energy sources for IKN and the necessary policies and actions to support their development and implementation. The backcasting approach was employed, which involves defining the desired future and working backward to determine the necessary steps to achieve it. Energy modeling, carried out using Calliope software, was used to simulate the future electricity system of the entire Kalimantan Island, including IKN, and to identify the least-cost combination of renewable energy sources to meet projected demand.
The study assumes that IKN’s peak electricity demand by 2045 will reach 792 MW. The least-cost vision suggests that this demand can be met primarily through solar PV and hydropower, with installed capacities of 890 MW and 792 MW, respectively. This combination results in the lowest Levelized Cost of Electricity (LCOE), calculated at 4.57 cents per kWh. Another vision explored in this study involves diversifying the energy mix by incorporating other renewable energy sources, such as floating solar PV, biomass, and battery storage. As reliance on hydropower and solar PV is reduced, the LCOE rises progressively, reaching 5.35 cents per kWh when the capacities of these two key sources are reduced by 50 percent.
While the technical feasibility of these renewable energy scenarios is promising, the political and economic barriers present the most significant challenges to their implementation. Politically, uncertainty in regulations, inconsistencies in policy frameworks, and the continuation of fossil fuel subsidies create hurdles. Economically, the lack of long-term financing options and limited resources available to developers and the national utility (PLN) present obstacles to renewable energy growth. Additionally, from a technological perspective, the current grid infrastructure in Kalimantan is not fully equipped to handle the intermittent nature of renewable sources like solar PV.
To address these challenges, several key actions and policies changes must be put in place. One crucial solution is the immediate introduction of a comprehensive new renewable energy law designed to attract investors by providing a stable and favorable regulatory environment. Financial strategies, such as government-backed loan guarantees and concessional financing from international organizations, are also crucial for making renewable projects economically viable. In addition, promoting public engagement and encouraging behavior changes, such as energy efficiency and conservation, can reduce peak demand and lower overall investment costs.
This study contributes to the body of research by providing a comprehensive strategy for renewable energy development in IKN. By combining energy modeling with a PESTEL analysis of drivers and barriers, it offers a comprehensive framework for understanding the challenges and opportunities in transitioning to 100 percent renewable electricity in IKN. Furthermore, this research lays the groundwork for future studies that can build upon its findings to explore specific sectoral actions in more detail.
...
This research focuses on addressing these challenges by exploring the most cost-effective renewable energy sources for IKN and the necessary policies and actions to support their development and implementation. The backcasting approach was employed, which involves defining the desired future and working backward to determine the necessary steps to achieve it. Energy modeling, carried out using Calliope software, was used to simulate the future electricity system of the entire Kalimantan Island, including IKN, and to identify the least-cost combination of renewable energy sources to meet projected demand.
The study assumes that IKN’s peak electricity demand by 2045 will reach 792 MW. The least-cost vision suggests that this demand can be met primarily through solar PV and hydropower, with installed capacities of 890 MW and 792 MW, respectively. This combination results in the lowest Levelized Cost of Electricity (LCOE), calculated at 4.57 cents per kWh. Another vision explored in this study involves diversifying the energy mix by incorporating other renewable energy sources, such as floating solar PV, biomass, and battery storage. As reliance on hydropower and solar PV is reduced, the LCOE rises progressively, reaching 5.35 cents per kWh when the capacities of these two key sources are reduced by 50 percent.
While the technical feasibility of these renewable energy scenarios is promising, the political and economic barriers present the most significant challenges to their implementation. Politically, uncertainty in regulations, inconsistencies in policy frameworks, and the continuation of fossil fuel subsidies create hurdles. Economically, the lack of long-term financing options and limited resources available to developers and the national utility (PLN) present obstacles to renewable energy growth. Additionally, from a technological perspective, the current grid infrastructure in Kalimantan is not fully equipped to handle the intermittent nature of renewable sources like solar PV.
To address these challenges, several key actions and policies changes must be put in place. One crucial solution is the immediate introduction of a comprehensive new renewable energy law designed to attract investors by providing a stable and favorable regulatory environment. Financial strategies, such as government-backed loan guarantees and concessional financing from international organizations, are also crucial for making renewable projects economically viable. In addition, promoting public engagement and encouraging behavior changes, such as energy efficiency and conservation, can reduce peak demand and lower overall investment costs.
This study contributes to the body of research by providing a comprehensive strategy for renewable energy development in IKN. By combining energy modeling with a PESTEL analysis of drivers and barriers, it offers a comprehensive framework for understanding the challenges and opportunities in transitioning to 100 percent renewable electricity in IKN. Furthermore, this research lays the groundwork for future studies that can build upon its findings to explore specific sectoral actions in more detail.
...
The decision to relocate Indonesia’s capital city from Jakarta to East Kalimantan is driven by a range of factors, including the need to decentralize economic activity and address Jakarta’s environmental issues. The New Capital City (IKN) is being developed as a sustainable urban center with the goal of becoming carbon-neutral by 2045. Law No. 3 of 2022 mandates that IKN will rely on 100 percent renewable electricity by 2045, underscoring the Indonesian government’s commitment to sustainability in the city. However, achieving this ambitious target presents significant challenges, particularly in terms of energy demand, renewable energy availability, and coordination across multiple sectors.
This research focuses on addressing these challenges by exploring the most cost-effective renewable energy sources for IKN and the necessary policies and actions to support their development and implementation. The backcasting approach was employed, which involves defining the desired future and working backward to determine the necessary steps to achieve it. Energy modeling, carried out using Calliope software, was used to simulate the future electricity system of the entire Kalimantan Island, including IKN, and to identify the least-cost combination of renewable energy sources to meet projected demand.
The study assumes that IKN’s peak electricity demand by 2045 will reach 792 MW. The least-cost vision suggests that this demand can be met primarily through solar PV and hydropower, with installed capacities of 890 MW and 792 MW, respectively. This combination results in the lowest Levelized Cost of Electricity (LCOE), calculated at 4.57 cents per kWh. Another vision explored in this study involves diversifying the energy mix by incorporating other renewable energy sources, such as floating solar PV, biomass, and battery storage. As reliance on hydropower and solar PV is reduced, the LCOE rises progressively, reaching 5.35 cents per kWh when the capacities of these two key sources are reduced by 50 percent.
While the technical feasibility of these renewable energy scenarios is promising, the political and economic barriers present the most significant challenges to their implementation. Politically, uncertainty in regulations, inconsistencies in policy frameworks, and the continuation of fossil fuel subsidies create hurdles. Economically, the lack of long-term financing options and limited resources available to developers and the national utility (PLN) present obstacles to renewable energy growth. Additionally, from a technological perspective, the current grid infrastructure in Kalimantan is not fully equipped to handle the intermittent nature of renewable sources like solar PV.
To address these challenges, several key actions and policies changes must be put in place. One crucial solution is the immediate introduction of a comprehensive new renewable energy law designed to attract investors by providing a stable and favorable regulatory environment. Financial strategies, such as government-backed loan guarantees and concessional financing from international organizations, are also crucial for making renewable projects economically viable. In addition, promoting public engagement and encouraging behavior changes, such as energy efficiency and conservation, can reduce peak demand and lower overall investment costs.
This study contributes to the body of research by providing a comprehensive strategy for renewable energy development in IKN. By combining energy modeling with a PESTEL analysis of drivers and barriers, it offers a comprehensive framework for understanding the challenges and opportunities in transitioning to 100 percent renewable electricity in IKN. Furthermore, this research lays the groundwork for future studies that can build upon its findings to explore specific sectoral actions in more detail.
This research focuses on addressing these challenges by exploring the most cost-effective renewable energy sources for IKN and the necessary policies and actions to support their development and implementation. The backcasting approach was employed, which involves defining the desired future and working backward to determine the necessary steps to achieve it. Energy modeling, carried out using Calliope software, was used to simulate the future electricity system of the entire Kalimantan Island, including IKN, and to identify the least-cost combination of renewable energy sources to meet projected demand.
The study assumes that IKN’s peak electricity demand by 2045 will reach 792 MW. The least-cost vision suggests that this demand can be met primarily through solar PV and hydropower, with installed capacities of 890 MW and 792 MW, respectively. This combination results in the lowest Levelized Cost of Electricity (LCOE), calculated at 4.57 cents per kWh. Another vision explored in this study involves diversifying the energy mix by incorporating other renewable energy sources, such as floating solar PV, biomass, and battery storage. As reliance on hydropower and solar PV is reduced, the LCOE rises progressively, reaching 5.35 cents per kWh when the capacities of these two key sources are reduced by 50 percent.
While the technical feasibility of these renewable energy scenarios is promising, the political and economic barriers present the most significant challenges to their implementation. Politically, uncertainty in regulations, inconsistencies in policy frameworks, and the continuation of fossil fuel subsidies create hurdles. Economically, the lack of long-term financing options and limited resources available to developers and the national utility (PLN) present obstacles to renewable energy growth. Additionally, from a technological perspective, the current grid infrastructure in Kalimantan is not fully equipped to handle the intermittent nature of renewable sources like solar PV.
To address these challenges, several key actions and policies changes must be put in place. One crucial solution is the immediate introduction of a comprehensive new renewable energy law designed to attract investors by providing a stable and favorable regulatory environment. Financial strategies, such as government-backed loan guarantees and concessional financing from international organizations, are also crucial for making renewable projects economically viable. In addition, promoting public engagement and encouraging behavior changes, such as energy efficiency and conservation, can reduce peak demand and lower overall investment costs.
This study contributes to the body of research by providing a comprehensive strategy for renewable energy development in IKN. By combining energy modeling with a PESTEL analysis of drivers and barriers, it offers a comprehensive framework for understanding the challenges and opportunities in transitioning to 100 percent renewable electricity in IKN. Furthermore, this research lays the groundwork for future studies that can build upon its findings to explore specific sectoral actions in more detail.
Energy System for a Data Center with 100% Hourly Renewable Utilization
A Techno Economic and Environmental Impact Analysis
The Paris Agreement aims to limit global warming to 2 degrees Celsius by reducing carbon dioxide emissions. Data centers are essential to the digital world and contribute approximately 1% to global electricity consumption. Major tech companies like Amazon, Microsoft, Google, and Meta are large contributors to this consumption. In countries like the Netherlands, this contribution is higher due to the Netherlands being a digital hub, accounting for 3% of the total national electricity consumption. Considering their significant energy usage, it is interesting to research how data centers can transition to using only renewable energy sources on an hourly basis so they can decrease their footprint. This thesis aims to identify a feasible and cost-effective configuration for a 100 MW data center that operates 100% on renewable energy on an hourly basis. The research will assess the environmental impacts, focusing on CO2 emissions (CO2e) and land usage, with the main goal of achieving the lowest Levelized Cost of Electricity (LCOE). First, an overview of potential energy storage technologies is provided to find suitable solutions. Based on different criteria, Lithium-ion (Li-ion), lead-acid, vanadium redox flow batteries (VRFB), zinc-bromide flow batteries (ZBFB), alkaline and PEM (proton exchange membrane) electrolyzers, storage tanks, and PEM fuel cells are chosen. With these technologies, eight different configurations are composed, combining various battery types and electrolyzer types with the storage tank and PEM fuel cell: Li-ion with alkaline (1), lead-acid with alkaline (2), Li-ion with PEM (3), lead-acid with PEM (4), VRFB with alkaline (5), ZBFB with alkaline (6), VRFB with PEM (7), and ZBFB with PEM (8). An energy model is developed to identify the most feasible and cost-effective solution, using solar, wind, and load profiles as input. The assets are modeled based on their technical parameters and limitations. A 10-year simulation of the hourly energy flows is executed. In this simulation, the constraints, degradation, and replacement of the assets are taken into account. The costs are determined based on Capital Expenditures (CAPEX), Operating Expenses (OPEX), replacement costs, and residual costs of the asset after 10-year. The connection costs are also considered. The configuration dimensions are optimized based on the LCOE using the particle swarm optimization method. The two configurations with the lowest LCOE are evaluated for environmental impacts, including CO2e and land usage. The study shows that combining a Li-ion battery or VRFB with an alkaline electrolyzer is the most cost-effective and feasible configuration for a data center. The LCOE is 0.243 and 0.241 €/kWh, respectively. Additionally, this reduces kg CO2e/kWh by 7-8 times compared to the current grid emissions in the Netherlands, which are approximately 0.037 and 0.032 kg CO2e/kWh. However, the required land usage is approximately 20 km², and the LCOE of the configuration is about 2.5 times higher than the current power purchase agreement (PPA) price for a data center, which is 0.10 €/kWh. Therefore, it is recommended to initially start with an 80% renewable scenario using only a Li-ion battery and renewable energy sources. This approach reduces the LCOE to 0.12 €/kWh, which is approximately the same as the current PPA price if an additional 0.01 €/kWh for the connection to the grid is included. Furthermore, kg CO2e/kWh is three times lower compared to the current situation, which is 0.08 kg CO2e/kWh. This strategy also mitigates the potential risks associated with the infancy of VRFB and the combination of intermittent renewable sources and an electrolyzer, as these are excluded in this scenario.
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The Paris Agreement aims to limit global warming to 2 degrees Celsius by reducing carbon dioxide emissions. Data centers are essential to the digital world and contribute approximately 1% to global electricity consumption. Major tech companies like Amazon, Microsoft, Google, and Meta are large contributors to this consumption. In countries like the Netherlands, this contribution is higher due to the Netherlands being a digital hub, accounting for 3% of the total national electricity consumption. Considering their significant energy usage, it is interesting to research how data centers can transition to using only renewable energy sources on an hourly basis so they can decrease their footprint. This thesis aims to identify a feasible and cost-effective configuration for a 100 MW data center that operates 100% on renewable energy on an hourly basis. The research will assess the environmental impacts, focusing on CO2 emissions (CO2e) and land usage, with the main goal of achieving the lowest Levelized Cost of Electricity (LCOE). First, an overview of potential energy storage technologies is provided to find suitable solutions. Based on different criteria, Lithium-ion (Li-ion), lead-acid, vanadium redox flow batteries (VRFB), zinc-bromide flow batteries (ZBFB), alkaline and PEM (proton exchange membrane) electrolyzers, storage tanks, and PEM fuel cells are chosen. With these technologies, eight different configurations are composed, combining various battery types and electrolyzer types with the storage tank and PEM fuel cell: Li-ion with alkaline (1), lead-acid with alkaline (2), Li-ion with PEM (3), lead-acid with PEM (4), VRFB with alkaline (5), ZBFB with alkaline (6), VRFB with PEM (7), and ZBFB with PEM (8). An energy model is developed to identify the most feasible and cost-effective solution, using solar, wind, and load profiles as input. The assets are modeled based on their technical parameters and limitations. A 10-year simulation of the hourly energy flows is executed. In this simulation, the constraints, degradation, and replacement of the assets are taken into account. The costs are determined based on Capital Expenditures (CAPEX), Operating Expenses (OPEX), replacement costs, and residual costs of the asset after 10-year. The connection costs are also considered. The configuration dimensions are optimized based on the LCOE using the particle swarm optimization method. The two configurations with the lowest LCOE are evaluated for environmental impacts, including CO2e and land usage. The study shows that combining a Li-ion battery or VRFB with an alkaline electrolyzer is the most cost-effective and feasible configuration for a data center. The LCOE is 0.243 and 0.241 €/kWh, respectively. Additionally, this reduces kg CO2e/kWh by 7-8 times compared to the current grid emissions in the Netherlands, which are approximately 0.037 and 0.032 kg CO2e/kWh. However, the required land usage is approximately 20 km², and the LCOE of the configuration is about 2.5 times higher than the current power purchase agreement (PPA) price for a data center, which is 0.10 €/kWh. Therefore, it is recommended to initially start with an 80% renewable scenario using only a Li-ion battery and renewable energy sources. This approach reduces the LCOE to 0.12 €/kWh, which is approximately the same as the current PPA price if an additional 0.01 €/kWh for the connection to the grid is included. Furthermore, kg CO2e/kWh is three times lower compared to the current situation, which is 0.08 kg CO2e/kWh. This strategy also mitigates the potential risks associated with the infancy of VRFB and the combination of intermittent renewable sources and an electrolyzer, as these are excluded in this scenario.