No full-text available
To read the full-text of this research,
you can request a copy directly from the authors.
Exploiting resource complementarities to reduce energy storage need
Abstract
Resource complementarities carry significant benefit to the power grid due to their smoothing effect on the variable renewable resources output. In this paper, we show that complementarity significantly reduces energy storage requirement by using simulation results generated for Israel, Saudi Arabia, California and Finland. In a complementarity study performed using Israeli and Californian data sets (focusing on the electricity sector alone), the wind-solar complementarities were shown to significantly increase grid penetration as compared to stand-alone wind/solar systems even without the need of energy storage. At even higher grid penetration their complementarity carries significant multidimensional benefits to the power grid. The most important observation was the achievement of very high grid penetration at reduced energy storage and balancing requirements as compared to stand-alone systems. Using specific energy storage capacity (186 GWh/22 GW) and setting the solar share to 0%, 50% and 100% of the total VRE capacity, the 50-50 wind-solar capacity mix has led to significantly higher penetration as compared to the stand-alone systems. For instance, by allowing 15% energy curtailment, it was shown that grid penetration of 63%, 80% and 55% of the annual demand, respectively, can be achieved. This was because of storage being able to follow a flexible dispatch strategy, which makes it applicable for various services depending on the season of the year and the available resources. A study on a 100% renewable energy system of Finland shows that one of the best scenarios was related to a 43%-57% wind-solar capacity mix for a 70% VRE penetration by 2050. A similar study on Saudi Arabia shows that broader resource complementarity and higher level of flexibility obtained through sector coupling has reduced the required storage very significantly. The results indicate that the multiple benefits obtained from resource complementarity should be emphasized during the transition to systems of high renewable energy shares.
Supplementary resource (1)
... Additionally, correlation within a resource across space or correlation between wind and solar resources, represents a challenge to robust, continuous generation of electricity because a reduction in one resource would typically be associated with a simultaneous reduction in the other [12]. Thus, the ability to transmit electricity over large geographic areas is advantageous not only because it is most economically efficient to site wind and solar farms at relatively remote locations where it is climatologically windiest and sunniest, but also because pooling resources over large areas reduces the correlation between and within resources, making the total energy supply less variable [18][19][20][21][22][23]. ...
Wind and solar electricity generation is projected to expand substantially over the next several decades due both to rapid cost declines as well as regulation designed to achieve climate targets. With increasing reliance on wind and solar generation, future energy systems may be vulnerable to previously underappreciated synoptic-scale variations characterized by low wind and/or surface solar radiation. Here we use western North America as a case study region to investigate the historical meteorology of weekly-scale “droughts” in potential wind power, potential solar power and their compound occurrence. We also investigate the covariability between wind and solar droughts with potential stresses on energy demand due to temperature deviations away human comfort levels. We find that wind power drought weeks tend to occur in late summer and are characterized by a mid-level atmospheric ridge centered over British Columbia and high sea level pressure on the lee side of the Rockies. Solar power drought weeks tend to occur near winter solstice when the seasonal minimum in incoming solar radiation co-occurs with the tendency for mid-level troughs and low pressure systems over the U.S. southwest. Compound wind and solar power drought weeks consist of the aforementioned synoptic pattern associated with wind droughts occurring near winter solstice when the solar resource is at its seasonal minimum. We find that wind drought weeks are associated with high solar power (and vice versa) both seasonally and in terms of synoptic meteorology, which supports the notion that wind and solar power generation can play complementary roles in a diversified energy portfolio at synoptic spatiotemporal scales over western North America.
Wind and solar electricity generation is projected to expand substantially over the next several decades due both to rapid cost declines as well as regulation designed to achieve climate targets. With increasing reliance on wind and solar generation, future energy systems may be vulnerable to previously underappreciated synoptic-scale variations characterized by low wind and/or surface solar radiation. Here we use western North America as a case study region to investigate the historical meteorology of weekly-scale “droughts” in potential wind power, potential solar power and their compound occurrence. We also investigate the covariability between wind and solar droughts with potential stresses on energy demand due to temperature deviations away human comfort levels. We find that wind power drought weeks tend to occur in late summer and are characterized by a mid-level atmospheric ridge centered over British Columbia and high sea level pressure on the lee side of the Rockies. Solar power drought weeks tend to occur near winter solstice when the seasonal minimum in incoming solar radiation co-occurs with the tendency for mid-level troughs and low pressure systems over the U.S. southwest. Compound wind and solar power drought weeks consist of the aforementioned synoptic pattern associated with wind droughts occurring near winter solstice when the solar resource is at its seasonal minimum. We find that wind drought weeks are associated with high solar power (and vice versa) both seasonally and in terms of synoptic meteorology, which supports the notion that wind and solar power generation can play complementary roles in a diversified energy portfolio at synoptic spatiotemporal scales over Western North America.
Supported by conducive policy and technology cost decline, PV capacity addition is increasing rapidly. The capacity addition is forecasted to continue at a faster rate over the coming decades. With such an increase, it is important to ask about system requirement to effectively integrate large system into a power grid. This paper presents the analysis of literature data in order to clarify system requirement for large PV integration. The review shows that the most important challenges of large-scale PV penetration are matching, variability, uncertainty and system adequacy. To overcome these challenges, several enabling techniques, such as energy storage, curtailment, transmission interconnection, demand response, resource complementarities, increased grid flexibility, improved forecasting, geographic distribution of generation resources, were among the most discussed by various researcher. A closer look at some systematic studies shows that developing theoretical framework for the future system is the best way to guide the smooth development of an effective and secure system. This argument is based on the observation that (i) the role and importance of one technology, for instance specific storage technology, may change as VRE penetration increases; (ii) the increase in use of one application decreases the importance of the other; (iii) the use of some of the discussed solutions may depend on level of penetration as they also depend on season. Thus, it is important to design the system based on a criteria formulated with the understanding of system level science/theoretical framework.
Supported by conducive policy and technology cost decline, PV capacity addition is increasing rapidly. The capacity addition is forecasted to continue at a faster rate over the coming decades. With such an increase, it is important to ask about system requirement to effectively integrate large system into a power grid. This paper presents the analysis of literature data in order to clarify system requirement for large PV integration. The review shows that the most important challenges of large-scale PV penetration are matching, variability, uncertainty and system adequacy. To overcome these challenges, several enabling techniques, such as energy storage, curtailment, transmission interconnection, demand response, resource complementarities, increased grid flexibility, improved forecasting, geographic distribution of generation resources, were among the most discussed by various researcher. A closer look at some systematic studies shows that developing theoretical framework for the future system is the best way to guide the smooth development of an effective and secure system. This argument is based on the observation that (i) the role and importance of one technology, for instance specific storage technology, may change as VRE penetration increases; (ii) the increase in use of one application decreases the importance of the other; (iii) the use of some of the discussed solutions may depend on level of penetration as they also depend on season. Thus, it is important to design the system based on a criteria formulated with the understanding of system level science/theoretical framework.
Technical Report "Global Energy System based on 100% Renewable Energy – Power Sector", published at the Global Renewable Energy Solutions Showcase event (GRESS), a side event of the COP23, Bonn, November 8, 2017
A global transition to 100% renewable electricity is feasible at every hour throughout the year and more cost effective than the existing system, which is largely based on fossil fuels and nuclear energy. Energy transition is no longer a question of technical feasibility or economic viability, but of political will.
Existing renewable energy potential and technologies, including storage can generate sufficient and secure power to cover the entire global electricity demand by 2050 . The world population is expected to grow from 7.3 to 9.7 billion. The global electricity demand for the power sector is set to increase from 24,310 TWh in 2015 to around 48,800 TWh by 2050.
Total levelised cost of electricity (LCOE) on a global average for 100% renewable electricity in 2050 is 52 €/MWh (including curtailment, storage and some grid costs), compared to 70 €/MWh in 2015.
Solar PV and battery storage drive most of the 100% renewable electricity supply due to a significant decline in costs during the transition.
Due to rapidly falling costs, solar PV and battery storage increasingly drive most of the electricity system, with solar PV reaching some 69%, wind energy 18%, hydropower 8% and bioenergy 2% of the total electricity mix in 2050 globally.
Wind energy increases to 32% by 2030. Beyond 2030 solar PV becomes more competitive. Solar PV supply share increases from 37% in 2030 to about 69% in 2050.
Batteries are the key supporting technology for solar PV. Storage output covers 31% of the total demand in 2050, 95% of which is covered by batteries alone. Battery storage provides mainly short-term (diurnal) storage, and renewable energy based gas provides seasonal storage.
100% renewables bring GHG emissions in the electricity sector down to zero, drastically reduce total losses in power generation and create 36 million jobs by 2050.
Global greenhouse gas emissions significantly reduce from about 11 GtCO2eq in 2015 to zero emissions by 2050 or earlier, as the total LCOE of the power system declines.
The global energy transition to a 100% renewable electricity system creates 36 million jobs by 2050 in comparison to 19 million jobs in the 2015 electricity system. Operation and maintenance jobs increase from 20% of the total direct energy jobs in 2015 to 48% of the total jobs in 2050 that implies more stable employment chances and economic growth globally.
The total losses in a 100% renewable electricity system are around 26% of the total electricity demand, compared to the current system in which about 58% of the primary energy input is lost.
In this paper, we present issues of electricity storage requirements based on comparative studies of various results. Studies using the datasets of Israel and California show that the storage requirement was defined by the seasonal and diurnal patterns of the local demand, and the corresponding variable renewable energy (VRE) resources profile. It was found that when we increase energy supply from VRE, the use of storage and its capacity increases until we reach some threshold. After that threshold, the storage use starts to decline even if we increase the size. An optimally utilized storage of about daily average demand would be sufficient to reach grid penetration of about 90% of the total demands from VRE at 20% total energy loss. Optimizing with other RE resources will be necessary to reach a net zero energy system instead of pushing for penetration of 100% VRE, which will require larger storage size at reduced storage usability. A loose approximation shows that the largest storage requirement for such a VRE was of the order of 6 times average daily demand with a modest increase in energy loss. A diverse Finnish 100% RE system (with 70% from VRE) was reported with energy storage size of about 8.6 times average daily demand and 6% total loss. At similar loss, the same penetration was achieved by a storage size of 0.5 times daily average demand in California, suggesting further optimization in the Finish system could result in further reduction in storage with some increase in curtailment, but might lead to higher total system cost. It was also noted that the mismatch between the VRE and load profile leads to least efficient use of resources if 100% VRE grid was aspired. However, optimal designing for VRE penetration up to 90% complemented with other renewable resources could provide an efficient energy system relying on lower storage size and balancing. We conclude that understanding of the physics and economics of the future energy system is mandatory to build and operate it optimally.
A 100% renewable energy scenario was developed for Finland in 2050 using the EnergyPLAN modelling tool to find a suitable, least-cost configuration. Hourly data analysis determined the roles of various energy storage solutions. Electricity and heat from storage represented 15% of end-user demand. Thermal storage discharge was 4% of end-user heat demand. In the power sector, 21% of demand was satisfied by electricity storage discharge, with the majority (87%) coming from vehicle-to-grid (V2G) connections. Grid gas storage discharge represented 26% of gas demand. This suggests that storage solutions will be an important part of a 100% renewable Finnish energy system.
To assess the possibility of a combined use of solar and wind energy over Europe, a continental-scale dataset, with high spatial and temporal resolution and covering three years of data (2012–14), is analyzed. The 100-m wind is taken from the ECMWF analyses/short-range forecasts. To obtain hourly values of potentially generated electricity, wind is transformed into normalized electricity-generation data by considering a normalized output function representing the most common wind turbines available in the European market. A strong monthly variation is present, showing the maximum potential at high latitudes in winter and shifting to specific areas in the Mediterranean Sea region in summer. Hourly data for solar radiation are extracted from the satellite-retrieval scheme of the Satellite Application Facility on Climate Monitoring (CM SAF). The energy output of photovoltaic systems is calculated by considering the amount of solar radiation that arrives at the surface of the photovoltaic modules. Tog...
Recent work has shown that for high-penetration renewable electricity systems, it is less expensive to install higher capacity of renewables and to allow generation to exceed load during some hours, rather than to build so much storage that all electricity can be used to meet electrical load. Because excess electricity appears to be cost-optimum, this raises the question as to whether the excess electricity, which in the case of wind power is predominately produced in colder weather, might displace other fuels for purposes such as heat. This study models using excess electricity for heating, based on an analysis of electricity and heat use in a TSO in the North-Eastern part of the United States (PJM Interconnection). The heating system was modeled as heat pump based district heating (HPDH) with thermal energy storage (TES). Thus, excess electricity is transformed into heat, which is easy and cheap to store near the point of use. As an alternative to HPDH, the use of distributed electrical resistive heating coupled with high temperature thermal storage (HTS) was also assessed. In both cases, a natural gas fired boiler (NGB) was modeled to be installed in the building for back-up heat. An algorithm that calculates the total cost of a unit of heat was used to determine the economically optimal size of the system’s main components and the influence that natural gas (NG) and electricity prices have on this optimum. It was found that a system based on heat pumps (HP) and centralized thermal storage supplies building heat at a lower or similar cost than conventional systems. In most cases electric resistive heating with HTS was found to be less cost-effective than HPDH. The consumption of natural gas can be reduced to as little as 3% of that used by an entirely NG-based heater. Also, thermal energy storage was found to be crucial when it comes to reducing the need for fossil fuels for heating (in this model, as backup heat).
Flexibility is the ability of a power system to respond to changes in power demand and generation. Integrating large shares of variable renewable energy sources, in particular wind and solar, can lead to a strong increase of flexibility requirements for the complementary system, traditionally hydrothermal, which has to balance the fluctuations of variable generation. We quantify these flexibility requirements at the operational timescale of 1–12 hours and different spatial scales across Europe. Our results indicate that three major factors determine the ramping flexibility needed in future power systems: the penetration of variable renewables, their mix and the geographic system size. Compared to the variability of load, flexibility requirements increase strongly in systems with combined wind and PV (photovoltaics) contribution of more than 30% of total energy and a share of PV in the renewables mix above 20–30%. In terms of extreme ramps, the flexibility requirements of a geographically large, transnational power system are significantly lower than of smaller regional systems, especially at high wind penetration.
PV and wind power are the major renewable power technologies in most regions on earth. Depending on the interaction of solar and wind resources, PV and wind power industry will become competitors or allies. Time resolved geospatial data of global horizontal irradiation and wind speeds are used to simulate the power feed-in of PV and wind power plants assumed to be installed on an equally rated power basis in every region of a 1°x1° mesh of latitude and longitude between 65°N and 65°S. An overlap of PV and wind power full load hours is defined as measure for the complementarity of both technologies and identified as ranging between 5% and 25% of total PV and wind power feed-in. Critical overlap full load hours are introduced as a measure for energy losses that would appear if the grid was dimensioned only for one power plant of PV or wind. In result, they do not exceed 9% of total feed-in but are mainly around 3% - 4%. Thus the two major renewable power technologies must be characterized by complementing each other.
We model many combinations of renewable electricity sources (inland wind, offshore wind, and photovoltaics) with electrochemical storage (batteries and fuel cells), incorporated into a large grid system (72 GW). The purpose is twofold: 1) although a single renewable generator at one site produces intermittent power, we seek combinations of diverse renewables at diverse sites, with storage, that are not intermittent and satisfy need a given fraction of hours. And 2) we seek minimal cost, calculating true cost of electricity without subsidies and with inclusion of external costs. Our model evaluated over 28 billion combinations of renewables and storage, each tested over 35,040 h (four years) of load and weather data. We find that the least cost solutions yield seemingly-excessive generation capacity—at times, almost three times the electricity needed to meet electrical load. This is because diverse renewable generation and the excess capacity together meet electric load with less storage, lowering total system cost. At 2030 technology costs and with excess electricity displacing natural gas, we find that the electric system can be powered 90%–99.9% of hours entirely on renewable electricity, at costs comparable to today's—but only if we optimize the mix of generation and storage technologies.
Renewable energy systems are often criticized because of their intermittency and need for substantial amount of backup in terms of other energy sources or storage. The present paper proposes a method to estimate the required amount of storage backup for a mostly solar and wind system that uses also biomass and hydroenergy as minor components of the electricity mix. An hourly simulation was carried out to determine the amount of electricity that could be produced based on the meteorological conditions of year 2001 in Japan, and this was compared with the maximum electricity demands imposed in the system for each month of the year. The system thus proposed has 100% chance of meeting around 40% of the electricity demand between 11:00 and 18:00, and the optimum scenario obtained (a 2:1 mix of solar to wind energy) required around 40 TW of storage to balance the extra electricity demand that occurs during the summer in Japan. It appears unlikely that the batteries in EV in vehicles will be able to meet this storage requirement in the future, though the system is able to adequately meet the electricity demand during the majority of the year, and hence showcases the viability of renewable energy.
In this second paper, which studies the hourly generation data from the Israel Electric Corporation for the year 2006, with a view to adding very large-scale photovoltaic power (VLS-PV) plants, three major extensions are made to the results reported in our first paper. In the first extension, PV system simulations are extended to include the cases of 1- and 2-axis sun-tracking, and 2-axis concentrator photovoltaic (CPV) technologies. Secondly, the effect of distributing VLS-PV plants among 8 Negev locations, for which hourly metrological data exist, is studied. Thirdly, in addition to studying the effect of VLS-PV on grid penetration, the present paper studies its effect on grid ramping requirements. The principal results are as follows: (i) sun-tracking improves grid matching at high but not low levels of grid flexibility; (ii) geographical distribution has little effect on grid penetration; (iii) VLS-PV significantly increases grid ramping requirements, particularly for CPV systems, but not beyond existing ramping capabilities; (iv) geographical distribution considerably ameliorates this effect.
This article presents the results of analyses of large-scale integration of wind power, photo voltaic (PV) and wave power into a Danish reference energy system. The possibility of integrating Renewable Energy Sources (RES) into the electricity supply is expressed in terms of the ability to avoid excess electricity production. The different sources are analysed in the range of an electricity production from 0 to 100% of the electricity demand. The excess production is found from detailed energy system analyses on the computer model EnergyPLAN. The analyses have taken into account that certain ancillary services are needed in order to secure the electricity supply system.The idea is to benefit from the different patterns in the fluctuations of different renewable sources. And the purpose is to identify optimal mixtures from a technical point of view. The optimal mixture seems to be when onshore wind power produces approximately 50% of the total electricity production from RES. Meanwhile, the mixture between PV and wave power seems to depend on the total amount of electricity production from RES. When the total RES input is below 20% of demand, PV should cover 40% and wave power only 10%. When the total input is above 80% of demand, PV should cover 20% and wave power 30%. Meanwhile the combination of different sources is alone far from a solution to large-scale integration of fluctuating resources. This measure is to be seen in combination with other measures such as investment in flexible energy supply and demand systems and the integration of the transport sector.
The renewable power generation aggregated across Europe exhibits strong seasonal behaviors. Wind power generation is much stronger in winter than in summer. The opposite is true for solar power generation. In a future Europe with a very high share of renewable power generation those two opposite behaviors are able to counterbalance each other to a certain extent to follow the seasonal load curve. The best point of counterbalancing represents the seasonal optimal mix between wind and solar power generation. It leads to a pronounced minimum in required stored energy. For a 100% renewable Europe the seasonal optimal mix becomes 55% wind and 45% solar power generation. For less than 100% renewable scenarios the fraction of wind power generation increases and that of solar power generation decreases.
In this study, a 100% renewable energy (RE) system for Brazil in 2030 was simulated using an hourly resolution model. The optimal sets of RE technologies, mix of capacities, operation modes and least cost energy supply were calculated and the role of storage technologies was analysed. The RE generated was not only able to fulfil the electricity demand of the power sector but also able to cover the 25% increase in total electricity demand due to water desalination and synthesis of natural gas for industrial use. The results for the power sector show that the total installed capacity is formed of 165 GW of solar photovoltaics (PV), 85 GW of hydro dams, 12 GW of hydro run-of-river, 8 GW of biogas, 12 GW of biomass and 8 GW of wind power. For solar PV and wind electricity storage, 243 GWhel of battery capacity is needed. According to the simulations the existing hydro dams will function similarly to batteries, being an essential electricity storage. 1 GWh of pumped hydro storage, 23 GWh of adiabatic compressed air storage and 1 GWh of heat storage are used as well. The small storage capacities can be explained by a high availability of RE sources with low seasonal variability and an existing electricity sector mainly based on hydro dams. Therefore, only 0.05 GW of PtG technologies are needed for seasonal storage in the electricity sector. When water desalination and industrial gas sectors’ electricity demand are integrated to the power sector, a reduction of 11% in both total cost and electric energy generation was achieved. The total system levelized cost of electricity decreased from 61 €/MWh to 53 €/MWh for the
sector integration.
Saudi Arabia is in the midst of redefining the vision for the country's future and creating an economy that is not dependent on fossil fuels. This work presents a pathway for Saudi Arabia to transition from the 2015 power structure to a 100% renewable energy based system by 2050 and analyse the benefits of integrating the power sector with the growing desalination sector. It is found that Saudi Arabia can transition to a 100% renewable energy power system by 2040 whilst meeting the growing water demand through seawater reverse osmosis (SWRO) desalination plants. The dominating renewable energy sources are PV single-axis tracking and wind power plants with 210 GW and 133 GW, respectively. The levelised cost of electricity (LCOE) of the 2040 system is 48 €/MWh. By 2050, PV single-axis tracking dominates the power sector due to the further reduction in the capital costs alongside cost reductions in supporting battery technology. This results in 80% share of solar PV in the total electricity generation. Battery storage is required to meet the total electricity demand and by 2050, accounts for 48% of the total electricity demand. The LCOE is estimated at 38 €/MWh, required capacity of PV single-axis tracking is 369 GW and wind power plants 75 GW. In the integrated scenario, due to flexibility provided by the SWRO plants, there is a reduced demand for battery storage and power-togas (PtG) plants. In addition, the ratio of the energy curtailed to the total energy generated is lower in all time periods from 2020 to 2050, in the integrated scenario. As a result, the annual levelised costs of the integrated scenario is found to be 2%-4% less than the non-integrated scenario.
The global energy system has to be transformed towards high levels of sustainability for executing the COP21 agreement. Solar PV offers excellent characteristics to play a major role for this energy transition. Key objective of this work is to investigate the role of PV for the global energy transition based on respective scenarios and a newly introduced energy transition model developed by the authors at the Lappeenranta University of Technology (LUT). The available energy transition scenarios have no consensus view on the future role of PV, but a progressive group of scenarios present results of a fast growth of installed PV capacities and a high energy supply share of solar energy to the total primary energy demand in the world in the decades to come. These progressive energy transition scenarios can be confirmed by the LUT Energy system model. The model derives total installed solar PV capacity requirements of 7.1 – 9.1 TWp for today's electricity sector and 27.4 TWp for the entire energy system in the mid-term (year 2030 assumptions set as reference). The long-term capacity is expected to be 42 TWp and due to the ongoing cost reduction of PV and battery technologies, this value is found to be the lower limit for the installed capacities. The cost reductions are taken into account for the year 2030, but are expected to further proceed beyond this reference year. Solar PV electricity is expected to be the largest, least cost and most relevant source of energy in the mid-to long-term for the global energy supply.
Integrating high shares of renewable energy (RE) sources in future energy systems requires a variety of storage solutions and flexibility measures. In this work, a 100% RE scenario was developed for Finland in 2050 for all energy sectors using the EnergyPLAN modelling tool to find a least-cost system configuration that suited the national context. Hourly data was analysed to determine the roles of various energy storage solutions, including stationary batteries, vehicle-to-grid (V2G) connections, thermal energy storage and grid gas storage for Power-toGas (PtG) technologies. V2G storage and stationary batteries facilitated use of high shares of variable RE on a daily and weekly basis. Thermal energy storage and synthetic grid gas storage aided in resolving seasonality issues related to variable RE generation plus facilitated efficient use of other forms of RE, such as biomass, and Combined Heat and Power to maintain the reliability and independence of the energy system throughout the year. In this scenario, 30 GWp of installed solar PV, 35 GWe of onshore wind power and 5 GWe of offshore wind power are supported by 20 GWh of stationary Lithium-ion batteries, 150 GWh of V2G storage (Li-ion), 20 GWhth of thermal energy storage, and 3800 GWhth of grid gas storage. Discharge of electricity and heat from storage represented 15% of end-user demand. Thermal storage discharge was 4% of end-user heat demand. In the power sector, 21% of end-user demand was satisfied by electricity storage discharge, the majority of this (87%) coming from V2G connections. Grid gas storage discharge represented 26% of gas demand. These observations suggest that storage solutions will be an important part of a 100% renewable Finnish energy system.
This study demonstrates how seawater reverse osmosis (SWRO) plants, necessary to meet increasing future global water demand, can be powered solely through renewable energy. Hybrid PV–wind–battery and power-to-gas (PtG) power plants allow for optimal utilisation of the installed desalination capacity, resulting in water production costs competitive with that of existing fossil fuel powered SWRO plants. In this paper, we provide a global estimate of the water production cost for the 2030 desalination demand with renewable electricity generation costs for 2030 for an optimised local system configuration based on an hourly temporal and 0.45° × 0.45° spatial resolution. The SWRO desalination capacity required to meet the 2030 global water demand is estimated to about 2374 million m3/day. The levelised cost of water (LCOW), which includes water production, electricity, water transportation and water storage costs, for regions of desalination demand in 2030, is found to lie between 0.59 €/m3–2.81 €/m3, depending on renewable resource availability and cost of water transport to demand sites. The global system required to meet the 2030 global water demand is estimated to cost 9790 billion € of initial investments. It is possible to overcome the water supply limitations in a sustainable and financially competitive way.
In order to define a cost optimal 100% renewable energy system, an hourly resolved model has been created based on linear optimization of energy system parameters under given constrains. The model is comprised of five scenarios for 100% renewable energy power systems in North-East Asia with different high voltage direct current transmission grid development levels, including industrial gas demand and additional energy security. Renewables can supply enough energy to cover the estimated electricity and gas demands of the area in the year 2030 and deliver more than 2000 TW hth of heat on a cost competitive level of 84 €/MW hel for electricity. Further, this can be accomplished for a synthetic natural gas price at the 2013 Japanese liquefied natural gas import price level and at no additional generation costs for the available heat. The total area system cost could reach 69.4 €/MW hel, if only the electricity sector is taken into account. In this system about 20% of the energy is exchanged between the 13 regions, reflecting a rather decentralized character which is supplied 27% by stored energy. The major storage technologies are batteries for daily storage and power-to-gas for seasonal storage. Prosumers are likely to play a significant role due to favourable economics. A highly resilient energy system with very high energy security standards would increase the electricity cost by 23% to 85.6 €/MW hel. The results clearly show that a 100% renewable energy based system is feasible and lower in cost than nuclear energy and fossil carbon capture and storage alternatives.
Large power sector CO2 emission reductions are needed to meet long-term climate change targets. Intermittent renewable energy sources (intermittent-RES) such as wind and solar PV can be a key component of the resulting low-carbon power systems. Their intermittency will require more flexibility from the rest of the power system to maintain system stability. In this study, the efficacy of five complementary options to integrate intermittent-RES at the lowest cost is evaluated with the PLEXOS hourly power system simulation tool for Western Europe in the year 2050. Three scenarios to reduce CO2 emissions by 96% and maintain system reliability are investigated: 40%, 60% and 80% of annual power generation by RES. This corresponds to 22%, 41% and 59% of annual power generation by intermittent-RES. This study shows that higher penetration of RES will increase the total system costs: they increase by 12% between the 40% and 80% RES scenarios. Key drivers are the relatively high investment costs and integration costs of intermittent-RES. It is found that total system costs can be reduced by: (1) Demand response (DR) (2-3% reduction compared to no DR deployment); (2) natural gas-fired power plants with and without Carbon Capture and Storage (CCS) (12% reduction from mainly replacing RES power generation between the 80% and 40% RES scenarios); (3) increased interconnection capacity (0-1% reduction compared to the current capacity); (4) curtailment (2% reduction in 80% RES scenario compared to no curtailment); (5) electricity storage increases total system costs in all scenarios (0.1-3% increase compared to only current storage capacity). The charging costs and investment costs make storage relatively expensive, even projecting cost reductions of 40% for Compressed Air Energy Storage (CAES) and 70% for batteries compared to 2012. All scenarios are simulated as energy only markets, and experience a "revenue gap" for both complementary options and other power generators: only curtailment and DR are profitable due to their low cost. The revenue gap becomes progressively more pronounced in the 60% and 80% RES scenarios, as the low marginal costs of RES reduce electricity prices.
It is expected that an energy system faces increasing flexibility requirements in order to cope with increasing contributions from variable renewable energy sources (VRE). In general, the instant balance of temporal and spatial inequalities of the electricity system can be achieved by many compensating measures. However, a thorough and precise quantification of the flexibility demand of a VRE based energy system turns out to be a complex task. So far, literature on energy economics and engineering has provided analyses concerning various aspects of the system requirements for flexibility. Accordingly, this review paper primarily aims to categorize the scientific approaches that have been used in "flexibility demand" studies. In this context, we classify exemplary study results from the German and European energy systems into technical, economic, and market potential categories to enhance their comparability. Moreover, we conduct a methodological evaluation of the literature findings to determine further research requirements. Against this background we also discuss a conceptual framework to quantify the market potential of flexible technologies.
The paper reviews different approaches, technologies, and strategies to manage large-scale schemes of variable renewable electricity such as solar and wind power. We consider both supply and demand side measures. In addition to presenting energy system flexibility measures, their importance to renewable electricity is discussed. The flexibility measures available range from traditional ones such as grid extension or pumped hydro storage to more advanced strategies such as demand side management and demand side linked approaches, e.g. the use of electric vehicles for storing excess electricity, but also providing grid support services. Advanced batteries may offer new solutions in the future, though the high costs associated with batteries may restrict their use to smaller scale applications. Different “P2Y”-type of strategies, where P stands for surplus renewable power and Y for the energy form or energy service to which this excess in converted to, e.g. thermal energy, hydrogen, gas or mobility are receiving much attention as potential flexibility solutions, making use of the energy system as a whole. To “functionalize” or to assess the value of the various energy system flexibility measures, these need often be put into an electricity/energy market or utility service context. Summarizing, the outlook for managing large amounts of RE power in terms of options available seems to be promising.
Wind and solar energy are expected to play a major role in the current decade to help Europe reaching the renewable energy penetration targets fixed by Directive 2009/28/EC. However, it is difficult to predict the actual production profiles of wind and solar energy as they depend heavily on variable meteorological features of solar radiation and wind speed. In an ideal system, wind and solar electricity are both injected in a fast reacting grid instantaneously matching supply and demand. In such a system wind and solar electricity production profiles should complement each other as much as possible in order to minimise the need of storage and additional capacity. In the present paper the complementarity of wind and solar resources is assessed for a test year in Italy. To achieve this goal we employ data at high spatial and temporal resolution data for both solar radiation and wind speed in Italy obtained from running two state of the art models (PVGIS and MINNI). Hourly profiles for solar and wind energy produced are compared in each 4 x 4 km(2) grid cell in Italy for 2005, and hourly, daily and monthly correlation coefficients are computed in order to assess the local complementarity of the two resources. A Monte Carlo approach is also developed to estimate how large-scale wind and solar energy productions could be potentially involved to complement each other in a scenario with up to 100 production sites across Italy. The results show how local complementarity can be very interesting with monthly correlation coefficients reaching values lower than -0.8 in several areas. Large-scale complementarity is also relevant with nation-wide monthly correlation coefficients showing values between -0.65 and -0.6. These model results indicate that in this sample year of 2005, wind and solar energy potential production have shown complementary time behaviour complementary, favourably supporting their integration in the energy system.
The storage and balancing needs of a simplified European power system, which is based on wind and solar power generation only, are derived from an extensive weather-driven modeling of hourly power mismatches between generation and load. The storage energy capacity, the annual balancing energy and the balancing power are found to depend significantly on the mixing ratio between wind and solar power generation. They decrease strongly with the overall excess generation. At 50% excess generation the required long-term storage energy capacity and annual balancing energy amount to 1% of the annual consumption. The required balancing power turns out to be 25% of the average hourly load. These numbers are in agreement with current hydro storage lakes in Scandinavia and the Alps, as well as with potential hydrogen storage in mostly North-German salt caverns.
This paper addresses the dual questions: What is the appropriate storage size and its related properties for matching very large photovoltaic plants to the grid; and what are the available technologies for achieving this end. For this purpose a “Usefulness Index” is defined, which, for any grid flexibility, leads to a PV-storage combination that allows high grid-penetration without storage being wastefully large. The paper then examines the sensitivity of this “appropriate storage size” to variations in our assumptions. The specific case of the Israeli electricity grid is employed for numerical discussion, but the formalism should be useful for wider application. In particular, the “appropriate storage size” deduced in this manner is argued to be a valuable point of departure for optimizations of a more sophisticated nature. Regarding available storage technologies, none is found to have all of the required properties for massive PV-grid penetration, but hybrid combinations should be capable of achieving this end.
The United States Department of Energy's SunShot Initiative has set cost-reduction targets of $1/watt for central-station solar technologies. We use SWITCH, a high-resolution electricity system planning model, to study the implications of achieving these targets for technology deployment and electricity costs in western North America, focusing on scenarios limiting carbon emissions to 80% below 1990 levels by 2050. We find that achieving the SunShot target for solar photovoltaics would allow this technology to provide more than a third of electric power in the region, displacing natural gas in the medium term and reducing the need for nuclear and carbon capture and sequestration (CCS) technologies, which face technological and cost uncertainties, by 2050. We demonstrate that a diverse portfolio of technological options can help integrate high levels of solar generation successfully and cost-effectively. The deployment of GW-scale storage plays a central role in facilitating solar deployment and the availability of flexible loads could increase the solar penetration level further. In the scenarios investigated, achieving the SunShot target can substantially mitigate the cost of implementing a carbon cap, decreasing power costs by up to 14% and saving up to $20 billion ($2010) annually by 2050 relative to scenarios with Reference solar costs.
In Ontario (Canada), the integration of renewable power is a priority policy goal. Since 2004, the circumstances under which the integration of renewable power is evaluated have changed due to successive changes in price as well as concerns that its over-production may add to grid congestion. This research investigates the value of increasing complementarity (both proximate and geographically dispersed) of wind and solar resources as a means by which electricity planners and researchers might advance electricity sustainability in Ontario. More specifically, this paper asks the following questions: 1) Does the combination of solar and wind resources in selected locations in Ontario serve to ‘smooth out’ power production, i.e., decrease instances of both high and low values, as compared to either resource producing individually? 2) Can this ‘smoothness’ be further improved by dispersing these resources geographically amongst locations? and 3) Does increasing the number of locations with solar and wind resources further ‘smooth out’ power production? Three years (2003–2005) of synchronous, hourly measurements of solar irradiance and wind speeds from Environment Canada’s Canadian Weather Energy and Engineering Data Sets (CWEEDS) are used to derive dimensionless indices for four locations in Ontario (Toronto, Wiarton, Sault Ste. Marie and Ottawa). These indices are used to develop three transparent and accessible methods of analysis: (1) graphical representation; (2) percentile ranking; and (3) using a theoretical maximum as a proxy for capacity. The article concludes that the combination of solar and wind within locations and amongst two locations improves ‘smoothness’ in power production, as compared to when each resource is produced on its own; moreover, it is further improved once more than two resources and two locations are combined. However, there is neither further benefit, nor drawback, associated with the geographic dispersion of complementarity between solar in one location and wind in another, when compared to both resources in one location.
This paper presents a grid matching analysis of wind energy conversion systems (WECSs) and photovoltaic (PV)-WECS hybrid systems. The study was carried out using hourly load data of the Israel Electric Corporation (IEC) for the year 2006 and the corresponding simulated hourly performance of large PV and WECS plants in the Negev Desert. Our major objective was to compare the grid-matching capabilities of wind with those of our previously published PV results, and to assess the extent to which the combined employment of WECS and PV can improve the grid matching capability of either technology when used on its own. We find that, due to the differences in diurnal and seasonal output profiles of WECS and PV, their tandem employment significantly improves grid penetration compared to their use individually.
We present the results of a number of PV-grid matching simulations performed using hourly generation data from the Israel Electric Corporation (IEC) for the year 2006, together with corresponding meteorological data from Sede Boqer in the Negev Desert. The principal results of this investigation are: (1) the effective flexibility factor (ff) of the IEC grid was close to ff=0.65, but with a different plant operating strategy, ff could have been considerably higher; (2) for ff=0.65, the largest no-dump PV system could have provided only 2.7% of the annual demand, but for higher flexibilities - up to ff=1 - the percentage penetration could be as high as 17.4%; (3) considerable improvement in penetration can result by relaxing the "no-dump" criterion initially imposed on the PV system; (4) using the IEC's existing plant types, additional penetration can be expected by re-scheduling part of the base-load generating capacity to anticipate expected solar input; (5) for a radically decreased grid flexibility - that might result from IEC decisions about future generator purchases - the required employment of massive amounts of storage would render the potential contribution of PV to be insignificant.
In this work, we evaluate technologies that will enable solar photovoltaics (PV) to overcome the limits of traditional electric power systems. We performed simulations of a large utility system using hourly solar insolation and load data and attempted to provide up to 50% of this system's energy from PV. We considered several methods to avoid the limits of unusable PV that result at high penetration due to the use of inflexible baseload generators. The enabling technologies considered in this work are increased system flexibility, load shifting via demand responsive appliances, and energy storage.
In this third paper, which studies the hourly generation data for the year 2006 from the Israel Electric Corporation, with a view to incorporating very large photovoltaic (PV) power plants, we address the question: What properties should storage have in order to enhance the grid penetration of large PV systems in an efficient and substantial manner? We first impose the constraint that no PV energy losses are permitted other than those due to storage inefficiency. This constraint leads to powerful linkages between the energy capacity and power capacity of storage, and PV system size, and their combined effect on grid penetration. Various strategies are then examined for enhancing grid penetration, based upon this newfound knowledge. Specific strategies examined include PV energy dumping and baseload rescheduling both on a seasonal basis and shorter time periods. We found, inter alia, that at high grid flexibilities (in the range ff=0.8-1), PV grid penetration levels could be possible in the range 60-90% of annual requirements. Moreover, with appropriately designed storage and accurate forecasting, a future grid could be operated at ff=1.