HS5.2

Wind and hydropower are generally more prevalent in stormy weather conditions when solar radiation is relatively lower, which is why these renewables show complimentary characteristics over time. Similarly, weather patterns show spatial covariance. This means that spatio-temporal coordination of renewable energy production can reduce significantly the variance in the system power, hence, contribute to a virtual energy storage similar as has previously been done by matching the demand response to power availability. The 130,000 km² Yalong River Basin in southwest China is used as an example in this study and for this basin we found typical climate-controlled periods in the renewable energy variations on periods of half a year, one year and 11-years. Based on historical hydro-climatic records, results for a planned combined wind-PV-hydropower system show that the maximum virtual energy storage has similar trends under different periods, i.e. it decreases with coordination distance and stabilizes on a coordination range of between 200 – 400 km. The maximum virtual energy storage gain was found to be 737 MWh . The project developed an existing spectral method for the analysis of the variance of the potential power and virtual energy storage in combined wind-PV-hydropower systems under different climate periods. Two different scenarios were analyzed, one in which all power stations were matched regardless of transmission constraints and one in which coordination of PV and wind power is fully centralized around single hydropower stations. The virtual energy storage gain obtained at decadal long periods, such as the 11-year cycle, can also be seen as an alternative to reserve power capacity that is activated only to avoid energy droughts. This study focused on the theoretical maximum potential for virtual energy storage, but the feasibility of this potential is limited by the uncertainty associated with production optimization and the meteorologic forecasts of future energy availability.

How to cite: Hu, J., Wörman, A., Li, Y., Zhang, B., Ding, W., and Zhou, H.: Potential for virtual energy storage in a wind-PV-hydropower system in Yalong River Basin, China., EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-10162, https://doi.org/10.5194/egusphere-egu22-10162, 2022.

Multi-sector modelling frameworks are fundamental platforms for exploring the complex interactions between the water and energy sectors. While acknowledging the pivotal role of hydropower within the energy system, it is essential to understand the feedback mechanisms between power and water systems to guide the design of hydropower operations and enhance water-energy management strategies. Here, we developed a novel modelling approach that hard-couples a reservoir system model and a power system model. The two-way dynamic feedback mechanism between the models allows for operational decisions to be made contingent upon the states of both water and energy systems. Operating the system as a whole offers flexibility in managing the physical storage of hydropower reservoirs to buffer the variability in other renewables, such as wind or solar. We evaluate the framework on a real-world case study based on the Cambodian grid, which relies on hydropower, coal, oil and imports from neighboring countries. In light of the country’s plan to further decarbonize its grid, we tested the framework on three grid configurations, the as-is grid, and the grid with two different levels of installed solar. To evaluate the effects of hard coupling, the experiments were simulated with and without feedback, and external inputs were varied with 1,000 stochastic generations of streamflow, solar and load. As demonstrated in our results, hard-coupling the water and energy systems brings benefits such as reduced operating costs, and boosts decarbonization efforts by supporting the integration of renewables in the grid. The two main external factors that determine the effectiveness of the feedback mechanism are streamflow and load. Under favorable conditions (large reservoir inflow and low electricity demand), the system experienced a 44% saving in annual operating costs and 53% reduction of CO₂ emissions. A spatio-temporal analysis on the reservoir operations and transmission line usage reveals that the timing of the monsoon and interconnections between the grid components also play significant roles in influencing the system’s responses to the hard coupling. Overall, our modeling framework paves way for optimized operations within the water-energy nexus. By accounting for the interdependencies between the reservoir and power system, a more efficient operating scheme for hydropower reservoirs can be derived, leading to greater complementarity of renewable energy sources.

How to cite: Koh, R., Kern, J., and Galelli, S.: Hard-coupling of water and power system models increases the complementarity of renewable energy sources, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-5384, https://doi.org/10.5194/egusphere-egu22-5384, 2022.

Intermittent sources, especially wind, have experienced accelerated growth - in the last decade, wind power grew 13 times in Brazil, reaching 19 GW of installed capacity in 726 wind farms and became the second largest source in the electricity mix (10%). According to the Ten Year Expansion Plan, in 2029 the wind power installed capacity will increase more than 2.5 times, reaching 39,500 MW (17.3% of the country's electricity mix).

 In Brazil, expansion and long term operation planning studies have been carried out since 1998 with the support of the NEWAVE model, which has been used in the routine and official activities of sector entities: generation dispatch by the National System Operator; calculation of the spot prices by the Whole Sale Energy Market Entity; expansion planning by the Ministry of Mines and Energy and the Energy Research Company; parameters of public auctions for the purchase of electricity by the Electricity Regulatory Agency; as well as by utilities of the power industry to develop corporate strategies.

 Currently, in accordance with the guidelines of the Electricity Regulatory Agency, the representation of wind generation in the NEWAVE model is currently carried out in a simplified manner, based on the monthly average of the last five years of net generation of each wind farm, aggregated by sub-system and load level, for the entire planning horizon.

 The objective of this work is to describe an approach to be used by the Brazilian power industry to represent the uncertainties of monthly wind power production in the SDDP algorithm applied in the long-term operation planning model, keeping the large-scale stochastic problem still computationally viable, when applied to large interconnected systems, especially with hydroelectric predominance, as is the case of the Brazilian system.

 The approach consists of four main stages: (i) statistical clustering of wind regimes and definition of equivalent wind farms; (ii) evaluation of monthly transfer functions (MTFs) between wind speed and power production; (iii) an integrated model for the generation of monthly multivariate synthetic series of inflows and winds, considering the correlations between wind speeds, between inflows and between wind speeds and inflows; and (iv) representation of the monthly wind power obtained through MTFs in the SDDP algorithm.

 Initial results obtained from the application of the proposed approach to actual configurations of the Brazilian interconnected power system are presented and discussed.

How to cite: Maceira, M. E., Melo, A., Pessanha, J. F., Cruz, C., Almeida, V., and Justino, T.: An Approach to Representing Wind Uncertainties in the Long-Term Operation Planning of Systems with Hydropower Predominance, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-8993, https://doi.org/10.5194/egusphere-egu22-8993, 2022.

Development of hydropower in developing countries carries economic development rewards, particularly for storage hydropower which can be used to balance fluctuating supply of other renewables. Yet, dams and reservoirs carry significant environmental impacts, e.g., network fragmentation and flow alteration. While flood control has often been a motivator for reservoir construction, one environmental impact of storage hydropower on tropical rivers is the reduction of peak flows resulting in less hydraulic connectivity between floodplains and channels. In many tropical rivers, where most future dams are planned, this reduced lateral connectivity will create negative impacts on biodiversity, the biophysical functioning of floodplains, and human uses such as recession agriculture. Determining the optimal siting, design, and operation (SDO) of dam portfolios which maximises power generation and minimises this environmental impact, e.g., in terms of maintaining lateral connectivity, is a complex problem.

Simulation - Optimisation models of hydropower portfolios have often included impact on annual flood peak as a proxy objective for floodplain impacts, but have rarely explicitly included inundated area as an objective. Furthermore, when this type of analysis is done, it is usually performed at a monthly timescale, which underestimates flood peaks and neglects in-channel and floodplain hydraulics.

This work presents a multi-dam simulation - optimisation framework which uses a high-resolution hydrodynamic modelling framework (LISFLOOD-FP) to explicitly model the impact of SDO of many different dam portfolios on inundated floodplain extent, and to include this modelled extent as an optimisation objective. This incorporates channel and floodplain hydraulics at a fine time resolution, allowing a more realistic representation of the impact of hydropower development on biodiversity.

The optimisation framework is applied to the data scarce Pungwe Basin in Mozambique / Zimbabwe, and identifies significant trade-offs from mainstem damming between power production and downstream hydraulic connectivity between rivers and floodplains. It identifies Pareto Optimal combinations of site and design (large dam, small dam, and run-of-the-river installations) for these two objectives. The inclusion of hydraulically modelled inundated area represents a step forward for increasing the ability of simulation - optimisation frameworks to model complex downstream impacts of hydropower development and operation related to changing discharge and channel hydraulics.

How to cite: Hatchard, S., Schmitt, R. J. P., Pianosi, F., Savage, J., and Bates, P.: Hydropower Portfolio Site and Design using a Simulation - Optimisation Model incorporating High Resolution Hydraulic Modelling in Data Scarce Regions, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-8044, https://doi.org/10.5194/egusphere-egu22-8044, 2022.

Production Cost Models (PCMs) simulate the economic dispatch of generators across a large power grid and are used widely by planners to study the reliability of electricity supply. As energy systems transition away from the thermoelectric technologies that have traditionally balanced electricity supply and demand, hydropower and its representation in PCMs is of increasing importance for storage and ramping capabilities. A limitation of PCMs applied to continental power grids with diverse generation portfolios is that hydropower generation is simulated without full consideration of complex river dynamics, leading to possible misrepresentation of grid flexibility and performance.

Using a detailed hydropower model, we evaluate whether the hourly hydropower schedule from a PCM with simplified monthly parameterization can be attained when accounting for realistic river dynamics, such as spill requirements and general water movement through a cascading reservoir system. We perform this hydropower generation test for the “Big 10” hydropower system on the Columbia River (part of the Western Interconnect of the United States), revealing 9% overestimation of available hydropower generation in a PCM solution in an average hydrologic year.

We reflect on the sources of differences with implications onto long term planning practices expected to address uncertainties associated with energy transitions, climate change, environmental regulation and competing water uses.

How to cite: Voisin, N., Magee, T., Turner, S., Clement, M., Oikonomou, K., and Zagona, E.: On the needs to evaluate power grid models’ hydropower scheduling with a river operations model, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-13005, https://doi.org/10.5194/egusphere-egu22-13005, 2022.

Run of River (RoR) hydropower plants are one of the most cost-effective energy technologies available for rural electrification and sustainable industrial expansion. These plants are characterised by a negligible storage capacity and by generation almost completely dependent on the timing and size of river flows. Their environmental footprint is minimal compared to that of reservoir-powered plants, and they are much easier to build.

RoR plants are deployed in a world with a changing hydro-climate, and in an uncertain economic context (electricity prices, interest rates, cost overruns). Through seven plants proposed in a range of hydro-climatic regions of Turkey, this work investigates whether maximising NPV (net present value), the usual design criterion, leads to financial viability for a range of possible climatic and economic futures. To assess this financial robustness, it uses and extends HYPER, a state-of-the-art toolbox that computes technical performance, energy production, maintenance and operational costs of a design at a given site (hydraulic head, flow record).

It combines HYPER with many-objective robust decision making (MORDM) to find alternatives to NPV design and assess their robustness to changing climatic and financial conditions. Our application of MORDM uses the following steps: (1) an explicit three-objective formulation is introduced to find design parameters that balance cost, revenue, and dry year (first percentile) power generation objectives, (2) coupling of a multi-objective evolutionary algorithm with HYPER to solve the problem using 1,000 years of synthetic streamflow data obtained with the Hirsch-Nowak synthetic streamflow generator, (3) sampling of deeply uncertain factors to analyse robustness to uncertain climatic and financial futures, (4) quantification of robustness based on the probability to make the plant financially viable within 10 and 20 years in each future.

Preliminary results suggest that applying MORDM approach to RoR hydropower plant design provides insights into the trade-offs between installation cost and hydropower production, while supporting design with a range of viable alternatives to help them determine which design is most robust and reliable for given site conditions and river stream characteristics. When contrasting robustness of a design with its NPV, designs with the highest NPVs do not necessarily perform well in terms of dry period revenue unless a small turbine is installed in triple turbine configuration. They also show less robustness to both climate change (and associated drying) and to evolving financial conditions than smaller design alternatives with less installed capacity. These better balance average annual revenue with dry period revenue. Preliminary results also suggest that maximising the benefit cost ratio (BCR) yields more robust and financially viable solutions than maximising NPV, as it leads to less costly designs that generate slightly less revenue on average but tend to better exploit low flows.

How to cite: Yildiz, V., Brown, S., and Rougé, C.: Run of River hydropower: in an uncertain world, is smaller financially smarter?, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-9249, https://doi.org/10.5194/egusphere-egu22-9249, 2022.

The energy autonomy of small non-interconnected islands in the Mediterranean, taking advantage of their high renewable energy potential, has been a long-standing objective of local communities and stakeholders. This is also in line with the recently implemented European Green Deal, which has set the goal of increasing the renewable energy penetration in European countries’ power systems. However, the islands have further challenges than the large-scale inland areas. On the one hand, their population fluctuates significantly across seasons, as result of tourism, which is their key economic activity. The footprint of tourism is a substantial stress to all associated resources and infrastructures during the summer period. On the other hand, most of these areas suffer from both water and land scarcity. These features raise several challenges regarding the development of really autonomous energy systems, based on renewables and essential storage works to regulate the energy surpluses and deficits in the long run. Taking as example the Cycladic island of Sifnos, Greece, we investigate the design of a hybrid power system, combining wind, solar and hydroelectric energy. A major component of the proposed layout is the pumped-storage system. Due to the limited surface water resources of the island, we configure an upper tank at an elevation of 320 m, recycling seawater. This peculiarity introduces a significant level of uncertainty in hydraulic calculations, as well as various technical challenges, such as the erosion of pipes and the electromechanical equipment, and the waterproofing of the tank. An additional challenge is raised by the peculiar wind regime of the island, that makes essential to choose a hub height of turbines to minimize the frequency of power cut-offs. The basis of a rational design procedure for the main system components is the financial optimization that ensures a desirable level of reliability. This is achieved through a stochastic simulation approach that takes into account the stochastic nature of the underlying hydrometeorological drivers (wind velocity and solar radiation) and the energy demand.

How to cite: Zisos, A., Pantazi, M.-E., Diamanta, M., Koutsouradi, I., Kontaxopoulou, A., Tsoukalas, I., Sakki, G.-K., and Efstratiadis, A.: Towards energy autonomy of small Mediterranean islands: Challenges, perspectives and solutions, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-5468, https://doi.org/10.5194/egusphere-egu22-5468, 2022.

Micro-hydropower is necessary renewable energy to provide baseload, and it has the advantages of sustainable development and reduction of greenhouse gas emissions. There is an interrelationship between irrigation water and energy from micro-hydropower with micro-hydropower development in agricultural irrigation systems. Li et al. (2019) mentioned that the agricultural system estimated the water supply-demand, energy supply-demand, land demand, and food production and was quantitatively analyzed under different scenarios. However, the study of water for electricity generation was neglected in the agricultural system. Zhou et al. (2019) apply small-hydropower into water supply systems to lift renewable power output and uplift the synergistic benefits of the Water-Food-Energy (WFE) Nexus steered by the optimal water allocation and small-hydropower installation. Still, the adjustment of the water source by the reservoir makes the flow of the water supply system unstable, which leads to inconsistent electricity generation of small hydropower. Gaudard et al. (2018) research that hydropower plants' relationship between water and energy is set-upstream. The results show that seasonality slightly affects hydroelectric power generation.

Therefore, the study set up a micro-hydropower generation system in the Linnei channel of the Zhuoshuixi river watershed in the middle of Taiwan. Collected channel background information and used Doppel (Teledyne StreamPro ADCP) to measure the water level, velocity, and discharge of the study site, analyze potential power generation, and evaluate the profit and payback period micro-hydropower generation and the impact of micro- hydropower systems in agriculture. Furthermore, to investigate the relationship nexus of WFE and assess micro-hydropower's effectiveness in reducing carbon dioxide emissions. According to the results of this study, it can be used as a reference basis for setting up other micro-hydropower systems in the future.

How to cite: Shih, J.-C., Lin, F.-Y., Hong, M.-D., Lin, H.-R., and Wen, J.-C.: Application on the Micro-hydropower generation Benefits of Agricultural Channels and the Water- Energy-Food nexus, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-2132, https://doi.org/10.5194/egusphere-egu22-2132, 2022.

In response to the increasing environmental concerns, there has been significant research and development of power generation technologies based on renewable energy sources (RES) such as solar, and hydrogen. On the one hand, the technologies are becoming more attractive by offering higher efficiencies and lifetimes, and lower costs. On the other hand, it has become challenging to cost-effectively plan and deploy RES technologies as their characteristics have become significantly more uncertain. This can have strong impacts on other established renewable generation technologies, such as hydropower, which might become less or more attractive depending on technological change. Furthermore, in the context of interlinked water-energy systems, RES impacts on hydropower can have cascading effects on water use. Accordingly, decision makers require improved planning strategies to “adapt” to technological change when making long-term planning and investment decisions. 

This work explores how considering RES, namely solar and hydrogen, alongside their technological uncertainties related to installation costs and lifetimes, would impact hydropower investments in an adaptive plan. Based on a conceptual case study of a water-energy system, we demonstrate that hydropower investments could be delayed and/or reduced because of the possibility of efficiency improvements related to renewable energy technologies. Furthermore, we quantify the forgone financial value from not using adaptive approaches to design and plan infrastructure projects under technological uncertainty.

How to cite: Pachos, K., Gonzalez, J. M., Erfani, T., Basheer, M., Martínez-Ceseña, E., Panteli, M., and Harou, J. J.: The value of incorporating technological uncertainty in adaptive infrastructure planning – a conceptual example in hydropower investment, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-12440, https://doi.org/10.5194/egusphere-egu22-12440, 2022.

Over 93% of Norway's power production stems from hydropower. The Nordic power market is constantly transforming, current main drivers include climate change effects on hydrology, an increase of variable renewable energy production, increasing interconnector capacity, and revision of concession terms for hydropower plants. A common plant layout is comprised of a reservoir and an underground penstock leading to a downstream located hydropower plant (HPP); in many cases several reservoirs and power plants are interconnected in complex systems. Consequently, the natural hydrology of many lakes and rivers are heavily impacted by hydropower operation.

Hydropower operation is legally regulated by concessions that include regulations to limit negative environmental and societal impacts. More than 400 HPPs currently undergo a revision of terms of their concessions, which will likely impact hydropower operations and subsequently the Nordic power market. Updated or new environmental restrictions of three main types may have significant impact: 1) r 2) requirements for minimum discharge and restricted flow variation downstream of power plants and 3) filling requirements for hydropower reservoirs for the summer season. The joint effect likely has impacts on the power-balance and the hydropower system’s flexibility at multiple timescales from seconds to seasons.

The objective of this cross-disciplinary study was to investigate the impacts of an ensemble of updated or new environmental restrictions on hydropower operations and on the Norwegian power market in the future. We developed a nationwide framework to quantify probable future environmental restrictions. . Additionally, a market model dataset for a 2030 scenario was created and input data adjusted, e.g. energy mix development in grid-coupled regions such as central Europe. Implemented in a state-of-the-art market optimization model, we modelled a range of restriction scenarios for the year 2030,

We analyzed resulting future price scenarios. Preliminary results show an increase in average yearly production loss in the range of 5 TWh (or 3% of total hydropower production) due to new environmental restrictions. Modelled market response is an increase of average spot-price by about 0.8 €/MWh for all regions of Norway. Norwegian export of electricity to other countries is reduced. Another effect is that reservoir filling levels are typically higher than in the current situation, likely due to filling restrictions and model tendencies to avoid risk of violating reservoir filling restrictions, as well as increased inflow during winter.

How to cite: Schönfelder, L., Harby, A., Arvesen, A., and Graabak, I.: New environmental restrictions - aggregate effects on the Norwegian power system, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-8110, https://doi.org/10.5194/egusphere-egu22-8110, 2022.

The European Union’s endeavors to find the right path to a climate-neutral future in 2050, the so-called green shift, is the subject of heated debate. One of the currently most discussed question is: What are the electricity sources of the future? While EU’s member states arguing about the advantages and disadvantages of nuclear and gas-fired power plants during this green shift, other countries have already succeeded in achieving extensive climate-neutrality in the electricity sector. Norway is currently one of the largest producers of sustainable electricity in Europe with an annual hydropower production capacity of 136.6 TWh from around 33,000 MW installed capacity (2021)[1]. Moreover, one of Norway’s possible strategies is to become the green battery of Europe – enabling neighboring countries to store energy peaks from renewable electricity generation in the Norwegian energy system.

Its geological and climate prerequisites enabled Norway to become a forerunner for renewable energies in the global electricity market. The advantages of hydropower technology found unbroken success in Norway in the first decades after World War II, heralding the beginning of the “most intense period for hydropower development in Norway”[2]. This period ended in 1990 when most of today’s hydropower capacities were fully developed and new legislation was introduced. Today we take Norway’s hydropower legacy for granted and therefore know little about the country’s own electricity debates during this expansion period.

As part of the PhD research project “Norway’s hydropower development boom in the perception of society”, this contribution to the EGU General Assembly 2022 is intended to shed light on these electricity debates by elaborating the sociotechnical imaginaries of electricity futures in Norway from 1945 to 1990[3]. Different public debates facing electricity capacity building of this period will be presented by analyzing 62 articles of Norway’s most important newspaper of public record Aftenposten. Who participated in these debates? What is the respective imagination about Norway’s electricity future about and for what reason?

It turns out that the renewables pioneer in the north of Europe was not a hermetically sealed land of hydropower enthusiasts. Quite the opposite: In the public debates of scientists, engineers, politicians and residents in Norway, developments on the global electricity market were taken seriously, such as the introduction of nuclear power technology, the onset of transnational electricity trading, and the emerging social skepticism about ecological damages caused by hydropower. As a final remark, this contribution will face the question why hydropower remained the ‘royal road’ for Norway’s electricity development.

How to cite: Fischer, M. and Lia, L.: The reasons why hydropower remained. Sociotechnical imaginaries of electricity futures in Norway from 1945 to 1990. A media analysis based on articles from the Norwegian daily newspaper Aftenposten, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-4651, https://doi.org/10.5194/egusphere-egu22-4651, 2022.

Hydropower investment decisions in the Upper Indus take a short-sighted approach based on energy generation potential at individual hydropower sites considering historical hydro-climatology. But hydropower will increasingly be affected in the future by changing climate and demands for water, energy and food – all heavily dependent on water resources availability. The seasonality and variability in runoff are changing. Anthropogenic water consumption may see a two to three fold increase by the end of the century with socio-economic development. Climate change and interlinkages with the water-energy-food nexus are emerging as primary stressors to land and water resources availability for hydropower in the Indus. Hence, we assess the extent of the challenges posed by climate change versus the nexus linkages on hydropower potential in the Upper Indus. Our sustainable hydropower exploration framework takes a systems approach to quantify theoretical, technical, economic and sustainable hydropower potential by successively considering the impact of natural, technical, financial, anthropogenic, environmental, and geo-hazard constrains on hydropower potential at both the individual site and the basin scales. The framework explicitly considers the water available for hydropower versus other nexus usages. We combine the framework with downscaled CMIP6 general circulation models and water consumption projections to compare current and future hydropower potential. Thus, we present hydropower development portfolios that are more robust under climate change and changes across the water-energy-food nexus. Future changes in climate and water demands will increase the need for a multi-sectoral approach in the identification of potential sites to achieve sustainable hydropower development. We present a basin-scale analysis of hydropower potential in the Upper Indus, now and in the future, considering growing demands for water, food and energy to fulfill the Sustainable Development Goals.

How to cite: Dhaubanjar, S., Lutz, A., Gernaat, D., Nepal, S., Pradhananga, S., Khanal, S., Bhakta Shrestha, A., and Immerzeel, W.: Exploration of the theoretical, financial, technical and sustainable hydropower generation potential in the Upper Indus basin, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-699, https://doi.org/10.5194/egusphere-egu22-699, 2022.

In the United Kingdom (UK), the amount of electricity generated from small-scale hydropower has nearly tripled since 2010. One of the key areas of growth within the sector has been run-of-river hydropower schemes, with several hundred now operating across the UK and the Republic of Ireland (RoI), the majority situated in mountainous areas of Scotland and Wales. Although the overall grid contribution of these schemes is small (~2%), they still play an important role, not only in decarbonising the grid and contributing to national emission reduction goals, but also at local scales, where schemes often provide financial benefit to local communities and individuals. However, future climate change threatens to alter precipitation patterns and therefore streamflows, potentially impacting both the timing of hydropower generation and the total power output potential.

In this study, we quantify the impact of a worst-case future climate change scenario (Representative Concentration Pathway 8.5) on the generation potential of run-of-river hydropower schemes in the UK and RoI. EXP-HYDRO hydrological model is used to simulate future daily streamflow for the 2021-2080 hydrological years in 178 catchments containing 531 hydropower abstractions. We estimate daily abstraction potential at each site based on the local environmental regulators’ (for Scotland, England, Wales, Northern Ireland, and Ireland) general abstraction conditions. We then perform seasonal and annual Mann-Kendall trend analysis at each site to analyse changes in: 1) the number of days when abstraction is possible, 2) the number of days when maximum abstraction is reached, 3) mean abstraction volume on days when abstraction is possible, and 4) the total abstractable volume. The scale of study undertaken allows for characterisation of both the impact of regional variation in future climate forcing, as well as analysis of the impact of local environmental regulation, on the future generation potential of run-of-river hydropower in the UK and RoI.

Results show increasing annual total abstraction potential in northern England and Scotland, while a decline is seen in Wales; little change is seen in Ireland and Northern Ireland. The number of days per year that abstraction is possible declines in all areas except the northwest of Scotland, while the number of days that maximum allowable abstraction is reached increases; mean daily abstraction therefore increases. A disparity can be seen in different nations between the magnitude, and in some cases direction, of change in annual mean streamflows compared to annual abstraction potential. This is likely caused by differences in water abstraction regulations between UK nations. This poses an interesting question in terms of the impact of environmental regulations for the different nations of the UK, and how best to maximise renewable energy output by hydropower, while protecting the natural environment.

How to cite: Dallison, R. and Patil, S.: Water availability assessment for run-of-river hydropower under future climate change in the UK and Ireland, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-806, https://doi.org/10.5194/egusphere-egu22-806, 2022.

Hydropower production affects different stakeholders, levels of administration and ecosystems, which makes the question of its sustainability complex. Hydropower delivers energy, storage capacity, jobs, economic value, but also involves altered streamflow, water temperature and sediment transport conditions, fractioning of aquatic habitats and modification of the landscape. Thus, an increasing demand for renewable and climate friendly energy from hydropower also results in more pressure on aquatic habitats, thereby potentially calling into question its sustainability.

In this work, we compare climate change impacts on the future energy production of 21 hydropower plants in Switzerland, to impacts related to environmental flow requirements and to site-specific technical optimisation potential. The simulation-based study corresponds to three future periods (2020–2049, 2045–2074 and 2070–2099) under three emission scenarios (RCP2.6, RCP4.5, RCP8.5), assuming unchanged environmental flow requirements and installed machinery. The results show an increase of winter production and a decrease of summer production, which in conjunction leads to an annual decrease. The simulated impacts strongly depend on the elevation and the plant-specific characteristics. The climate induced changes in production are of a similar order of magnitude as the production loss due to environmental flow requirements and the increase potential due to technical optimisations. A key result is that the climate induced reduction is not linearly related to the underlying streamflow reduction, but is modulated by environmental flow requirements, the design discharge and streamflow projections. Taken a step further, a change in production does not necessarily mean a linear change in financial revenue. The Water-Energy Nexus in terms of hydropower concerns more than just a m³s^-1–kWh relationship: it is part of a complex framework that is namely sensitive to legal adjustments and to long lasting technical decisions taken in the past.

How to cite: Wechsler, T., Hug Peter, D., Zappa, M., and Schaefli, B.: Climate change impacts on Alpine hydropower in the context of environmental impacts and technical constraints, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-4726, https://doi.org/10.5194/egusphere-egu22-4726, 2022.