The chemical pulp mill as a flexible prosumer of electricity

Chemical pulp mills act as industrial-scale prosumers of energy, in that they demand heat and electricity for the production processes while supplying heat and electricity from the combustion of by-products. As such, they have potential relevance as providers of flexibility to the electricity system, supporting the integration of variable renewable electricity generation. In this study, a novel dispatch optimisation model is presented and applied to a generic mill, covering the production processes, boilers, and turbines, together with the associated storage of intermediate products. We analyse the trade in electricity between the mill and the central grid, the economic value of pulp mill flexibility, and the internal dynamics of the mill, when flexibility measures in different parts of the mill are combined. The results show that the suggested flexibility measures increase the amount of sold electricity during high-value hours and reduce the amount of sold electricity during low-value hours. In the present electricity market, the value of the electricity traded with the central grid is, thereby, increased by 1–8% compared to steady-state operation, without impacting the pulp production volume. The results reveal both synergies and conflicts between the different flexibility measures, underlining the importance of mill-wide optimisation

Exploring the competitiveness of hydrogen-fueled gas turbines in future energy systems

Hydrogen is currently receiving attention as a possible cross-sectoral energy carrier with the potential to enable emission reductions in several sectors, including hard-to-abate sectors. In this work, a techno-economic optimization model is used to evaluate the competitiveness of time-shifting of electricity generation using electrolyzers, hydrogen storage and gas turbines fueled with hydrogen as part of the transition from the current electricity system to future electricity systems in Years 2030, 2040 and 2050. The model incorporates an emissions cap to ensure a gradual decline in carbon dioxide (CO2) levels, targeting near-zero CO2 emissions by Year 2050, and this includes 15 European countries. The results show that hydrogen gas turbines have an important role to play in shifting electricity generation and providing capacity when carbon emissions are constrained to very low levels in Year 2050. The level of competitiveness is, however, considerably lower in energy systems that still allow significant levels of CO2 emissions, e.g., in Year 2030. For Years 2040 and 2050, the results indicate investments mainly in gas turbines that are partly fueled with hydrogen, with 30–77 vol.-% hydrogen in biogas, although some investments in exclusively hydrogen-fueled gas turbines are also envisioned. Both open cycle and combined cycle gas turbines (CCGT) receive investments, and the operational patterns show that also CCGTs have a frequent cyclical operation, whereby most of the start-stop cycles are less than 20 h in duration

The cost dynamics of hydrogen supply in future energy systems – A techno-economic study

This work aims to investigate the time-resolved cost of electrolytic hydrogen in a future climate-neutral electricity system with high shares of variable renewable electricity generation in which hydrogen is used in the industry and transport sectors, as well as for time-shifting electricity generation. The work applies a techno-economic optimization model, which incorporates both exogenous (industry and transport) and endogenous (time-shifting of electricity generation) hydrogen demands, to elucidate the parameters that affect the cost of hydrogen. The results highlight that several parameters influence the cost of hydrogen. The strongest influential parameter is the cost of electricity. Also important are cost-optimal dimensioning of the electrolyzer and hydrogen storage capacities, as these capacities during certain periods limit hydrogen production, thereby setting the marginal cost of hydrogen. Another decisive factor is the nature of the hydrogen demand, whereby flexibility in the hydrogen demand can reduce the cost of supplying hydrogen, given that the demand can be shifted in time. In addition, the modeling shows that time-shifting electricity generation via hydrogen production, with subsequent reconversion back to electricity, plays an important in the climate-neutral electricity system investigated, decreasing the average electricity cost by 2%–16%. Furthermore, as expected, the results show that the cost of hydrogen from an off-grid, island-mode-operated industry is more expensive than the cost of hydrogen from all scenarios with a fully interconnected electricity system

Impact of electricity market feedback on investments in solar photovoltaic and battery systems in Swedish single-family dwellings

The profitability of investments in photovoltaics (PVs) and batteries in private households depends on the market price of electricity, which in turn is affected by the investments made in and the usage of PVs and batteries. This creates a feedback mechanism between the centralised electricity generation system, and household investments in PVs and batteries. To investigate this feedback effect, we connect a local optimisation model for household investments with a European power generation dispatch model. The local optimisation is based on the consumption profiles measured for 2104 Swedish households. The modelling compares three different scenarios for the centralised electricity supply system in Year 2032, as well as several sensitivity cases. Our results show total investment levels of 5–20 GWp of PV and 0.01–10 GWh of battery storage capacity in Swedish households in the investigated cases. These levels are up to 33% lower than before market feedback is taken into account. The profitability of PV investments is affected most by the price of electricity and the assumptions made regarding grid tariffs and taxes. The value of investments in batteries depends on both the benefits of increased self-consumption of PV electricity and market arbitrage

Impacts of demand response from buildings and centralized thermal energy storage on district heating systems

\ua9 2020 The Author(s) Energy use for space heating is a substantial part of total energy end use and heating systems can offer some flexibility in time of use, which should be important in future energy systems to maintain balance between supply and demand. This work applies a techno-economic, integrated, demand-supply optimization model to investigate the combined effect of using demand-side flexibility from buildings, by allowing for indoor temperature deviations (both up- and downward from the set-point), and supply-side flexibility, by applying thermal energy storage (TES), on the operation of district heating (DH) systems. The results indicate that the potential for increased indoor temperature, i.e., demand response (DR), is concentrated to multi-family and non-residential buildings (heavy buildings with high time-constants), while the potential for downregulation of the temperature, i.e., operational energy savings, is utilized to a greater extent by single-family buildings (light buildings). It is also evident that the value of DR diminishes in the presence of a supply-side TES. We show that applying both the demand-side flexibility and a centralized TES is complementary from the heating system perspective in that it results in the lowest total space heating load of the buildings and the lowest running cost for the DH system

Modeling the development of a carbon capture and transportation infrastructure for Swedish industry

This work presents and applies a mixed integer programming (MIP) optimization model that minimizes the net present costs for CO2 capture and storage (CCS) systems for cases with defined emissions costs and/or capture targets. The model covers capture from existing large point sources of CO2 emissions in Sweden, liquefaction, intermediate storage and transportation using trucks to hubs on the coast, followed by ship transport to a storage location (excluding storage cost). The results show that the capture and transportation infrastructure, in terms of both the sites chosen for capture and the associated transportation setup, differs depending on whether the system is incentivized to capture biogenic or fossil CO2, or both. Waste-fired combined heat and power (CHP) plants are only chosen for capture at scale when biogenic capture targets and fossil emissions costs are combined, since the emissions from these sites comprise a combination of biogenic and fossil CO2. The value for the system in mitigating the costs from fossil CO2 emissions exceeds the increased cost of BECCS at waste-fired CHPs compared to larger pulp mills given the fossil emissions cost development assumed in this work. Although the cost for capture and liquefaction dominates the total cost of the CCS system, it is not the only factor determining the choice of sites for capture. Proximity to transport hubs with short offshore transportation distances to the final storage location is also an important factor. For the transportation infrastructure, it is shown that the cost for ships is the main cost driver

Estimating national and local low-voltage grid capacity for residential solar photovoltaic in Sweden, UK and Germany

The electric grid\u27s available capacity to accommodate solar photovoltaic on national scales is currently uncertain. This makes decisions about grid capacity expansion, which can be very costly for local grid operators, difficult to make. Yet, knowledge of national solar photovoltaic grid capacity is central in order to formulate realistic solar PV targets and strategies. We present a methodology based on publicly available data to estimate the grid\u27s hosting capacity of residential solar photovoltaic at both the national and local scale. The model is applied to Sweden, Germany and the UK and shows that low-voltage grid capacity for residential solar photovoltaic is very large, 33 (+5/-7) GW (Sweden), 248 (+5/-24) GW (Germany) and 63 (+1/-14) GW UK, and similar to current total generation capacity. Based on our estimations, we find that with the capacity of the present grid Sweden can supply 24%, Germany 60% and UK 21% of their current annual net electricity consumption from residential solar photovoltaic. In addition, we find that the grid-supported individual solar PV system sizes increase as population density decreases. Finally, our work highlights the importance of implementing sizing incentives for customers when installing their solar PV systems

Generating low-voltage grid proxies in order to estimate grid capacity for residential end-use technologies: The case of residential solar PV

Due to data restrictions and power system complexity issues, it is difficult to estimate grid capacity for solar PV on regional or national scales. We here present a novel method for estimating low-voltage grid capacity for residential solar PV using publicly available data. High-resolution GIS data on demographics and dwelling dynamics is used to generate theoretical low-voltage grids. Simplified power system calculations are performed on the generated low-voltage grids to estimate residential solar PV capacity with a high temporal resolution. The method utilizes previous developments in reference network modelling and solar PV hosting capacity assessments. The method is demonstrated using datasets from Sweden, UK and Germany. Even though the method is designed to estimate residential solar PV grid capacity, the first block of the method can be utilized to estimate grid capacity or impacts from other residential end-use technologies, such as electric heating or electric vehicle charging. This method presents: • A method for estimating peak demand based on population density and dwelling type. • Generation of low-voltage grids based on peak demand. • Sizing of transformers and cables based on national low-voltage regulations and standards