Impacts of variation management on cost-optimal investments in wind power and solar photovoltaics

This work investigates the impacts of variation management on the cost-optimal electricity system compositions in four regions with different pre-requisites for wind and solar generation. Five variation management strategies, involving electric boilers, batteries, hydrogen storage, low-cost biomass, and demand-side management, are integrated into a regional investment model that is designed to account for variability. The variation management strategies are considered one at a time as well as combined in four different system contexts. By investigating how the variation management strategies interact with each other as well as with different electricity generation technologies in a large number of cases, this work support policy-makers in identifying variation management portfolios relevant to their context. It is found that electric boilers, demand-side management and hydrogen storage increase the cost-optimal variable renewable electricity (VRE) investments if the VRE share is sufficiently large to reduce its marginal system value. However, low-cost biomass and hydrogen storage, are found to increase cost-optimal investments in wind power in systems with a low initial wind power share. In systems with low solar PV share, variation management reduce the cost-optimal solar PV investments. In two of the regions investigated, a combination of variation management strategies results in a stronger increase in VRE capacity than the sum of the single variation management efforts

Biomass in the electricity system: A complement to variable renewables or a source of negative emissions?

Biomass is often assigned a central role in future energy system scenarios as a carbon sink, making negative greenhouse gas emissions possible through carbon capture and storage of biogenic carbon dioxide from biomass-fuelled power plants. However, biomass could also serve as a strategic complement to variable renewables by supplying electricity during hours of high residual load. In this work, we investigate the role of biomass in electricity systems with net zero or negative emissions of carbon dioxide and with different levels of biomass availability. We show that access to biomass corresponding to ca. 20% of the electricity demand in primary energy terms, is of high value to the electricity system. Biomass for flexibility purposes can be a cost-efficient support to reach a carbon neutral electricity system with the main share of electricity from wind and solar power. Biomass-fired power plants equipped with carbon capture and storage in combination with natural gas combined cycle turbines are identified as being the cost-effective choice to supply the electricity system with flexibility if the availability of biomass within the electricity system is low. In contrast, in the case of excess biomass, flexibility is supplied by biomethane-fired combined cycle turbines or by biomass-fired power plants

Design of clean steel production with hydrogen: Impact of electricity system composition

In Europe, electrification is considered a key option to obtain a cleaner production of steel at the same time as the electricity system production portfolio is expected to consist of an increasing share of varying renewable electricity (VRE) generation, mainly in the form of solar PV and wind power. We investigate cost-efficient designs of hydrogen-based steelmaking in electricity systems dominated by VRE. We develop and apply a linear cost-minimization model with an hourly time resolution, which determines cost-optimal operation and sizing of the units in hydrogen-based steelmaking including an electrolyser, direct reduction shaft, electric arc furnace, as well as storage for hydrogen and hot-briquetted iron pellets. We show that the electricity price following steelmaking leads to savings in running costs but to increased capital cost due to investments in the overcapacity of steel production units and storage units for hydrogen and hot-briquetted iron pellets. For two VRE-dominated regions, we show that the electricity price following steel production reduces the total steel production cost by 23% and 17%, respectively, as compared to continuous steel production at a constant level. We also show that the cost-optimal design of the steelmaking process is dependent upon the electricity system mix

Frequency reserves and inertia in the transition to future electricity systems

The transition towards an electricity system that is dominated by asynchronous and non-dispatchable generators, such as wind and solar power, entails challenges related to balancing the load and, thereby, keeping the grid frequency stable. Many technologies can contribute to load balancing and frequency control. This study investigates the interactions between electricity generation and frequency control in terms of investments and operation, using cost-minimizing, linear optimization modeling. The model is applied in three different geographic cases and for four future time-points, starting off with the already existing transmission and generation capacities, so as to yield insights into different systems and different stages along the energy transition. The results show that frequency control constraints in the optimization model have a weak impact on the system composition and cost, and that batteries are important for minimizing the impact. Furthermore, inertia requirements without a reserve demand show no impact on the cost or system composition. When allowing for vehicle-to-grid from battery electric vehicles, a large proportion of stationary grid battery investments is displaced, and the impact on system cost from adding frequency control constraints is removed

Interaction between electrified steel production and the north European electricity system

This study investigates the interactions between a steel industry that applies hydrogen direct reduction (H-DR) and the electricity system of northern Europe. We apply a techno-economic optimization model with the aim of achieving net-zero emissions from the electricity and steel sectors in Year 2050. The model minimizes the investment and running costs of electricity and steel production units, while meeting the demands for electricity and steel. The modeling is carried out for a number of scenarios, which differ in the following parameters: (i) cost of using new sites for steel production; (ii) transport costs; (iii) commodities export; (iv) flexibility in operation of a direct reduction (DR) shaft furnace; and (v) location of steel demand. The results reveal that a cost-efficient spatial allocation of the electrified steel production capacity is impacted by the availability of low-cost electricity and can differ from the present - day allocation of steel plants. The modeling results show that the additional electricity demand from an electrified steel industry is met mainly by increased investments in wind and solar power while natural gas - based production of electricity is reduced. Furthermore, it is found to be cost-efficient to invest in overcapacity for steel production units (electrolyzers, DR shaft furnaces and electric arc furnaces) and to invest in storage systems for hydrogen and hot briquetted iron, so that steel production can follow the variations inherent to wind and solar power

The impact of limited electricity connection capacity on energy transitions in cities

We study the impacts of the connection capacity for electricity transfer between a city and a regional energy system on the design and operation of both systems. The city energy system is represented by the aggregate energy demand of three cities in southern Sweden, and the regional energy system is represented by Swedish electricity price area SE3. We minimize the investment and running costs in the electricity and district heating sectors, considering different levels of connection capacity between the city and the regional energy systems; connection capacities equal to 100%, 75%, 50% and 0% of the maximum city electricity demand. We find that a system design with 50% connection capacity is only 3% more expensive in terms of total costs than a system with 100% connection capacity. However, shifting electricity generation capacity from the regional to the city energy system with 50%, as compared to 100%, connection capacity leads to a higher marginal cost for electricity in the city than in the region. With the highest connection capacities, 75% and 100%, the district heating sector in the city can support wind power integration in the regional energy system by means of power-to-heat operation. Modeling systems with different connection capacities makes our results applicable to other fast-growing cities with potential to increase local electricity production and sector coupling between the electricity, district heating and electrified transport sectors

A comparison of variation management strategies for wind power integration in different electricity system contexts

Variation management strategies improve the capability of the electricity system to meet variations both in the electricity demand and in the generation that relies on variable energy sources. In this work, we introduce a new, functionality-based, categorization of variation management strategies: shifting (eg, batteries), absorbing (eg, power-to-gas), and complementing (dispatchable generation, including reservoir hydropower) strategies. A dispatch model with European coverage (EU-27 plus Norway and Switzerland) is applied to compare the benefits of shifting and absorbing strategies on wind integration in regions with different amounts of complementing strategies in place. The benefits are measured in terms of the wind value factor, wind owner revenue, and average short-term generation cost. The results of the modeling show that the reduction in average short-term generation cost and the increase in revenue earned by the wind owner from shifting strategies, such as the use of batteries, are more substantial at low wind shares than at high wind shares. The opposite situation is found for absorbing strategies, such as power-to-gas, which are found to be more efficient at reducing the average generation cost and increasing profit for the wind owner as the wind share increases. In regions that have access to complementing strategies in the form of reservoir hydropower, variation management has a weak ability to reduce the average short-term generation cost, although it can increase significantly the revenue accrued by the wind power owner

The value of airborne wind energy to the electricity system

Airborne wind energy (AWE) is a new power generation technology that harvests wind energy at high altitudes using tethered wings. The potentially higher energy yield, combined with expected lower costs compared to traditional wind turbines (WTs), motivates interest in further developing this technology. However, commercial systems are currently unavailable to provide more detailed information on costs and power generation. This study estimates the economic value of AWE in the future electricity system, and by that indicates which cost levels are required for AWE to be competitive. A specific focus is put on the relation between AWE systems (AWESs) and WTs. For this work, ERA-5 wind data are used to compute the power generation of the wind power technologies, which is implemented in a cost-minimizing electricity system model. By forcing a certain share of the annual electricity demand to be supplied by AWESs, the marginal system value (MSV) of AWE is investigated. The MSV is found to be affected by the AWE share, the wind resource, and the temporal distribution of the AWES\u27s electricity generation. The MSV of AWE is location- and system-dependent and ranges between 1.4 and 2.2 (Formula presented.) at a low share of AWE supply (0%–30%). At higher shares, the MSV drops. The power generation of WTs and AWESs are related, implying that the wind technologies present a similar power source and can be used interchangeably. Thus, the introduction of AWESs will have a low impact on the cost-optimal wind power share in the electricity system, unless an AWES cost far below the system-specific MSV is attained

Flexibility provision by combined heat and power plants – An evaluation of benefits from a plant and system perspective

Variable renewable electricity generation is likely to constitute a large share of future electricity systems. In such electricity systems, the cost and resource efficiency can be improved by employing strategies to manage variations. This work investigates combined heat and power (CHP) plant flexibility as a variation management strategy in an energy system context, considering the operation and cost-competitiveness of CHP plants. An energy system optimization model with detailed representation of CHP plant flexibility is applied, covering the electricity and district heating sectors in one Swedish electricity price area. The results show that investments in CHP plants are dimensioned based on the demand for district heating rather than electricity. In the system studied, this implies that CHP plant capacity is small relative to electricity system variations, and variation management using CHP plants has a weak impact on the total system cost of supplying electricity and district heating. However, flexibility measures increase CHP plant competitiveness in scenarios with low system flexibility (assuming low availability of hydropower or no thermal energy storage) although investments in CHP capacity are sensitive to fuel cost. It is found that while district heating is the dominant CHP product (constituting 50%–90% of the annual CHP energy output), the dispatchable electricity supply has a high value and comprises around 60% of the annual CHP plant revenue. In all scenarios, operational flexibility of the boiler is more valuable than a flexible steam cycle power-to-heat ratio

Management of Wind Power Variations in Electricity System Investment Models. A Parallel Computing Strategy

Accounting for variability in generation and load and strategies to tackle variability cost-efficiently are key components of investment models for modern electricity systems. This work presents and evaluates the Hours-to-Decades (H2D) model, which builds upon a novel approach to account for strategies to manage variations in the electricity system covering several days, the variation management which is of particular relevance to wind power integration. The model discretizes the time dimension of the capacity expansion problem into 2-week segments, thereby exploiting the parallel processing capabilities of modern computers. Information between these segments is then exchanged in a consensus loop. The method is evaluated with regard to its ability to account for the impacts of strategies to manage variations in generation and load, regional resources and trade, and inter-annual linkages. Compared to a method with fully connected time, the proposed method provides solutions with an increase in total system cost of no more than 1.12%, while reducing memory requirements to 1/26’th of those of the original problem. For capacity expansion problems concerning two regions or more, it is found that the H2D model requires 1–2% of the calculation time relative to a model with fully connected time when solved on a computer with parallel processing capability