3.2. The Full Electrification of the Final Energy Consumptions
The historical data for the island of Gran Canaria indicate that there have not been major changes in the demand curves over the past decade [
29]. But when facing the total decarbonization of the whole energy system, which would represent a significant change, the present generation and demand profiles would change. Under the described scenario, it would not be enough to decarbonize the electricity generation; instead, the whole economic system (industry, transport, households, services, etc.) would have to be decarbonized. Therefore, it would imply a remarkable increase in the demand, not only in the total values but also in the hourly demand profiles. In addition, if renewable energies are used as the only generation source, there will be an additional problem: the generation–demand mismatch, making managing the current problem extremely complicated. Therefore, to cover this significant increase in demand and address the problems of decoupling between generation and demand, a solid commitment to renewable energies is necessary, together with the installation of large storage capacities. However, it would require developing several measures to implement significant changes in various aspects concerning generation and demand management.
This transition towards a fully renewable generation system and total electrification of energy consumption must be carried out gradually. This transition must be achieved with a clear commitment to this approach over relatively long periods and implemented in several stages. Obviously, in order to reach these challenging objectives, a number of steps need to be taken, the foremost of which would be the creation of a general legislative framework for energy transition planning, with the establishment of energy transition plans and climate change laws, so that this general legal framework can be applied in each region; in particular, the listed measures should be implemented: transport planning of electricity penetration in passenger transport; stimulate electric vehicles in both private and business sectors; provide the necessary charging infrastructures for the increasing electric transport; favor the replacement of old thermal equipment for DHW (Domestic Hot Water) and the use of heat pumps for air conditioning in the hotel sector; create corporate tax reductions for investments aligned with the energy transition; favor renewable generation with the elimination of administrative obstacles and/or simplification of the administrative procedures, providing legal and juridical guarantees to accelerate investments, etc.; favor the deployment of storage and demand response systems; adapt electricity tariffs to promote electrification and to shift demand to the most appropriate hours; or any other measures that can help to carry out the unavoidable change to clean energies.
The electrification of all end-use energy consumption by the year 2040 will significantly increase demand; a detailed view of the major contributions to the electric demand is displayed in
Figure 1 (considered assumptions can be consulted in references [
4,
21]). The total investment needed to meet this demand forecast is between 18 and 22 thousand million euros [
21], which was carried out for the whole Canary Archipelago.
Therefore, assuming that the present ratio between Gran Canaria’s consumption and that of the whole Archipelago (slightly less than 40%) is preserved, it would imply that of the 16.1 TWh/year of the whole Archipelago’s consumption predicted for 2040 (without taking into account the production of hydrogen necessary to supply “non-electrifiable” energy end-uses), the island would demand approximately 6.4 TWh/year. These figures are similar to the estimates made by the Government of the Canary Islands [
23]. The estimates are based on the current stabilized consumption (From 2010 it has remained stable, except for the drop caused by the COVID-19 pandemic), adding the estimated increase in consumption for electric vehicles and the other minor contributions shown in the figure, leading to an increase from almost 3.5 TWh per year in 2019 to around 6.5 TWh per year by 2040.
As shown in the figure, transport is responsible for most of this increase in electric energy consumption, with passenger transport being the main contributor by far. According to the study of the Canary Islands’ Government focused on the strategies for the implementation of electric vehicles on the islands [
23] and also extrapolating the transport contribution from the whole Canary Archipelago to Grand Canary Island (
Figure 1), forecasts of the increase in electricity consumption of about 2.2 TWh per year will be reached. The investment in recharging points to supply the fleet of electric vehicles is around EUR 1250 M; which would be the most significant investment to be made, in addition to the installation of renewable generation sources to cover this considerable increase in demand.
The hourly demand forecast will change due to the high electric car fleet. According to the type of recharging point used, the consumption pattern is different (private homes, workplaces, shopping centers, service stations, etc.) [
23]. The final demand curve is the aggregation of all these different demand curves.
Figure 2 displays the aggregate hourly demand forecasting profile of the island of Gran Canaria by 2040 [
23]. As shown in the figure, a significant increase in demand during nighttime compared to the current one occurs and flattens the demand curve. In principle, this flattened curve would be favorable for the management of the electricity system. However, if solar photovoltaic generation is significant, the generation curve sharpens during the middle of the day, and, as a consequence, a substantial generation–demand gap is shown. This must be reduced as much as reasonably possible; how to solve this drawback will be discussed in later sections.
3.3. Hydrogen or Ammonia as Energy Vectors
Analyzing the information provided in
Figure 1 for the whole Canary Archipelago, considering a scenario of total electrification of the economy, several contributions will shape the final energy demand for the year 2040. According to the Deloitte and Endesa report [
21], there will be an increase in electricity consumption (due to the economy’s growth and population and another due to the electrification of the economy). There will also be another contribution, negative in this case, due to the implementation of efficiency measures and, finally, the other category. In this last category are those energy consumptions that are “non-electrifiable”, so the report’s authors propose using hydrogen as a possible energy vector to cover these consumptions. These “non-electrifiable” energy end-consumptions come mainly from transport (heavy-duty vehicles, marine, and aviation) and some industrial sectors [
8,
9,
10].
The technologies for the complete decarbonization of heavy road transport do not present a single feasible solution, such as the electric or hydrogen fuel cell truck, although both still have a relatively low degree of maturity. For example, some pilot projects on the usage of these technologies, such as the electric Tesla Semi or the Hydrogen Nikola One and Two, have taken place over the last few years, but significant commercialization of electric and hydrogen trucks is not expected until 2025, nor are they expected to be cost-competitive until after 2030, according to leading industry analysts. In this analysis, based on the results provided in previous research [
4], it has been considered that hydrogen as an energy source for heavy-duty vehicles will eventually prevail, or at least the combined use of electricity and hydrogen.
In interisland maritime transport, there is the possibility of electrifying those routes with a fixed route between two ports with a distance of approximately less than 100 km. There are already some international examples (Norway, Denmark, Canada, and Malta) of ferries that operate regularly with this technology, combined with the existence of many ambitious projects, such as the “Europa Seaways” ferry, which is planned to be powered by a 23 MW fuel cell and will connect Copenhagen to Oslo in a roughly 48 h long roundtrip [
30]. On the Canary Islands, fewer than 100 km distance ferry journeys account for 85% of all interisland ferry journeys. Therefore, these lines could potentially be electrified with current technology. However, investments for their adaptation, both in the electric vessels themselves and in the recharging infrastructure at the ports, still need to be developed. The profitability for shipowners developing this technology will still require a reduction in battery costs or other supporting measures. But, decarbonization must rely on other technology options for ships that cover other types of longer sea voyages or require greater flexibility (i.e., that do not have a fixed port of departure and destination). Natural gas is already a viable option in those ports where such fuel is accessible, achieving a reduction in emissions compared to the fuels used today, which is a suitable option during the transition period to a green economy. Therefore, hydrogen can provide a completely emission-free solution in the longer term, at least on these longer distances and/or more flexible routes.
Interisland air transport does not have nonemitting solutions available in the short to medium term due to the more significant technical limitations, centered above all on the higher power-to-weight ratio required for this use, and therefore especially conditioned by the restrictions related to the weight of the batteries in the case of electric aircraft and to the weight of the fuel tank in the case of hydrogen aircraft. However, in the long term, hydrogen is likely to offer a real option of applicability in this sector.
Significant quantities of hydrogen are currently produced, but almost all of it is produced from fossil fuels, so large amounts of CO
2 are emitted in the process. However, hydrogen can be made by water electrolysis from electricity generated through renewable sources. Then, this hydrogen is called “green hydrogen”.
Figure 3 displays a “green hydrogen” production, storage, distribution, and consumption diagram. In the current study, the electricity surpluses have been used to produce H
2, so the island could be self-sufficient and greenhouse-gas-neutral. The H
2 production would be maximized in different scenarios and compared to the forecasted H
2 demand, demonstrating the capacity to generate the needed quantity.
The efficiencies of current commercial options of electrolyzers (particularly Alkaline Electrolysis/AEL and Proton Exchange Membrane/PEM systems) are around 60%, with relative low degradations and high lifetimes (degradation of 1.5 and 2.5% per year and lifetimes between 55–120 and 60–100 thousand hours of operation, respectively), which means 10–15 years of operation [
31]. Regarding estimations of the costs of hydrogen generated from renewable electricity, those are approximately between USD
$ 1.5 and USD% 6/kgH
2 depending on the part of the world. For Europe, in the long term, costs are expected to reduce to around USD 3/kgH
2 [
32]. By 2050, the minimum production costs for hydrogen from renewable energy sources could fall to USD 1.5/kg and below USD 1/kg under optimistic assumptions in some regions [
33].
Currently, several projects at the European and Spanish levels are developing for the generation and use of green hydrogen. For example, Iberdrola is presently working on the start-up of its Puertollano plant [
34], consisting of a 100 MW solar photovoltaic plant, a lithium-ion battery system with a storage capacity of 20 MWh, and a 20 MW hydrogen production system through electrolysis. Enagas and Naturgy are studying the production of green hydrogen from 350 MW of wind energy in Asturias [
35]. This project is contemplating the production of green hydrogen from a 250 MW offshore wind farm and a 100 MW onshore wind farm for consumption by the Asturian industry, thus decarbonizing sectors, such as steel and shipyards. It is also planned that this hydrogen will be distributed on a large scale through the gas network and exported to Europe. Acciona and Enagás, together with Cemex, Redexis, the Institute for Energy Diversification and Saving (IDAE), and the Balearic Government, are promoting the project “Power to Green Hydrogen Mallorca” [
36], which includes the construction of an electrolysis plant, the development of two photovoltaic plants that feed it, and a green hydrogen service station on the island. The solar installations located in the municipalities of Lloseta and Petra will have 6.9 MW and 6.5 MW of power, respectively. Both will produce the renewable energy needed for the green hydrogen plant, generating and distributing more than 300 tons of H
2 per year. This green hydrogen is expected to drive the decarbonization of the islands, specifically its use in public bus fleets and rental vehicles; heat and power generation for public and commercial buildings; and auxiliary power supply for ferries and port operations. Even on the Canary Islands, there are projects related to hydrogen. Enagás and the DISA Group have joined forces to promote the production, distribution, and commercialization of green hydrogen through the “Canarian Renewable Hydrogen Hub Cluster” project to contribute to the progressive decarbonization of the Archipelago [
37]. In this project, 20 institutions are brought together, including companies and public organizations, leading private companies in their sector, technology centers, and academic institutions. In its first phase, the project requires an investment of 100 million euros and may reach up to 1000 million in 2030, depending on the growth in the consumption of green hydrogen as a clean energy alternative. In addition, part of this renewable hydrogen will be injected into the island’s gas network, mixed with natural gas, reducing the total CO
2 emissions.
Regarding the different Canarian transport and industrial sectors, it should be said that heavy-duty vehicles, marine, and aviation are a sector with relatively high importance in the Archipelago. At the same time, the subsectors of metallic and nonmetallic mineral products (manufacturing glass, cement, ceramics, etc.) comprise more than 50% of industrial energy consumption [
21]. All these industrial sectors have processes that require high temperatures, such as clinkerization in the cement industry, high-temperature furnace processing in the glass industry, or calcination and heat treatment processes in the metal products industry. Consequently, the decarbonization of these nonelectrifiable transport and industrial sectors must rest on the distant horizon of the deployment of hydrogen.
The decarbonization of the last-mentioned percentage of the final energy consumption with electricity, would require an unaffordable additional investment (around 19–20 thousand million euros for the whole Canary Archipelago, according to the Deloitte and Endesa report [
21]). As a result, another technology is needed to provide cost-effective seasonal back-up, such as hydrogen (3–9 thousand million euros of investment to cover this last percentage [
21]), although this technology is still under development. In any case, decisions in this regard will not be made until at least well into the 2030s and may be accepted depending on the maturity of the options available. Consequently, considering that the present proportion of final energy demand between the island of Gran Canaria and the whole Canary Archipelago remains practically constant over time (around 40%), it would imply that of the 2.5 TWh/year of “non-electrifiable” final energy consumption of the whole Archipelago (
Figure 1), approximately1 TWh/year would come from the island of Gran Canaria. Then, hydrogen could be used to cover this last quantity; this production could be obtained from the electricity generation surpluses. So, in numbers, this TWh of final energy consumption would be converted into a hydrogen demand of 3 × 10
7 kg per year, which means considering that the hydrogen demand is quite constant over a year, consumption of approximately 8.2 × 10
4 kg per day. Additional costs to desalinate the water needed for the hydrolysis process have to be considered since the hydric resources are very limited on Grand Canary Island. The total amount of water would be around 3 × 10
5 m
3, meaning less than 10% of the desalination capacity of the recently projected plant associated with the Chira-Soria project [
28]. The total costs of this facility are around EUR 20 million, and typical desalination costs are in the order of EUR 1/m
3 [
38], which means that these costs have to be considered, even though they are reduced compared with the rest of the hydrogen generation costs (EUR ~1 cent/kgH
2 produced). But the energy required to bring this hydrogen available for consumption will be much higher given the current poor yields (electrolyzation process efficiency, storage and transport losses, etc.). However, this technology does not need to be available immediately, as this “non-electrifiable” part of energy consumption should be the last to be addressed in the final zero-emission scenario.
The above costs of hydrogen production are not the final costs of hydrogen use, since it has to be delivered to the end users. Consequently, storage, transport, distribution, and delivery costs must be added. Then, mainly depending on the end users’ distance, another possible energy carrier vector could be considered, the use of ammonia instead of hydrogen. The main advantages and disadvantages of ammonia are described below [
18], the evaluation of both of which raises the question of its use. Ammonia can be easily liquefied due to strong hydrogen bonds, which makes it suitable for handling in thermally insulated containers, and ammonia has a higher volumetric energy density, approximately up to three times higher than hydrogen. Concerning transport and storage requirements, unlike hydrogen, ammonia can be contained at moderate pressure (around ten bars, compared to hundreds for hydrogen) at ambient temperature (much like propane).
Regarding safety, ammonia presents lower risks than other fuels used in transportation, such as hydrogen, gasoline, and propane, although some precautions must be taken into account. Ammonia vapors can be toxic, corrosive, and potentially life-threatening when inhaled in high concentrations; however, leaks are easily detected because of ammonia’s strong odor and because it is lighter than air and dispersed quickly. Additionally, ammonia’s low reactivity makes it less dangerous in case of fires or accidental explosions compared to other fuels. Consequently, this low reactivity makes the combustion of pure ammonia very difficult. Then, it should be checked if there is higher efficiency in the production and use of ammonia than with the direct use of hydrogen.
On the one hand, the efficiency of storing, transporting, distributing, and consuming hydrogen should be analyzed. While on the other hand the efficiency of carrying out the intermediate step of ammonia production (producing this ammonia from electrolyzed hydrogen and nitrogen separated from air, together with the necessary electrical energy, also obtained from the excess renewable generation), storage, transport, distribution, and consumption of the ammonia will be analyzed. Then, it can be checked which of them is more efficient in each of the possible consumptions of both energetic vectors. In any case, in all probability, in the more or less near future, the excess green electricity will be used in water electrolysis. The only question to be answered will be whether it is more efficient to use green hydrogen directly or, on the contrary, if it will be more efficient to use ammonia as an additional energy carrier.
Thus, the total costs of supplying hydrogen to end users must consider the various possible stages of the supply chain. In this sense, depending on the hydrogen carriers (pressurized H
2, liquid H
2, ammonia, and liquid organic) and modes of transport (truck, pipeline, and ship), the costs of conversion, transmission, distribution, storage, and reconversion are very different (
Figure 4 and
Figure 5). Therefore, one option may be a priori the most economical for certain conditions, while a different option may be the most economical for others. Moreover, the degrees of maturity of the different technologies involved are not the same and, therefore, have very different cost reduction potentials in the future. In addition, there may be scope for synergies among power, heat, and storage needs. But in the case of relatively isolated and small islands, like the Canary Archipelago, the most suitable option is to produce H
2 in situ, while the best option for storage and distribution would be as a compressed gas. Consequently, added to the production costs, the costs of distribution by pressurized trucks must be considered as the best option. According to the IES report [
32], since the distances to be covered on Grand Canary Island are less than 100 km, the costs are between EUR 0.3 and EUR 0.6/kgH
2 depending on the distance covered (
Figure 4b).
3.4. Smart Grids and Demand Management
Smart grids are necessary for the adequate management of all the new actors joining both generation, storage, and consumption [
39]. This is understood as one that incorporates information and communication technologies (ICTs) to control and manage all aspects of the generation, transmission, distribution, and consumption of electricity to meet the demand of end users while minimizing the environmental impact, improving markets, reliability, service, and efficiency; and reducing costs.
Traditionally, in distribution grids, size was the main consideration; i.e., a significant size was required to achieve a reduced cost due to the economy of scale. But the integration of renewables into the traditional generation system has encouraged the decentralization of electricity systems, promoting both distributed generation and storage.
Together with this distributed generation and storage, the management of these systems has also been developed independently, or at least partially independently, but integrated within larger grids, systems known as microgrids. Modern microgrids are integrated energy systems consisting of a localized grouping of distributed electricity generation with storage and multiple electrical loads, which can be independently controlled as its own entity or microgrid or connected to the existing power grid [
40]. In cases where there is no possibility to connect to the public grid, usually because it is located in a remote or isolated location, a standalone microgrid (SAM) is an answer to the challenges of power supply.
The automation and monitoring of energy in these smart grids are usually carried out in multilevel architectures, with different studies with grids ranging from a single level to around ten [
41]. So, the grid’s functionalities are controlled at different levels so that local controls are covered from the lowest levels. In contrast, the global optimization of the network is covered at the highest level.
Through ICTs, control, monitoring, and self-diagnosis of these factors, smart grids seek to achieve at least the following objectives:
To strengthen and automate the network, improving its operation, quality indexes, and losses.
To favor the integration of renewable energies, also improving the integration of intermittent renewable generation (mainly wind and solar photovoltaic) by developing new storage technologies and enhancing the existing ones.
To favor the integration of hydrogen production, intermittent renewable generation and storage technologies aim to manage the generation–demand balance for both electric and hydrogen, using electric energy surpluses to produce hydrogen.
Develop decentralized generation plants or systems, allowing for the operation of smaller installations closer to the final consumer, in harmony with the rest of the system (distributed generation), which would reduce losses.
Active demand management, allowing consumers to manage their consumption more efficiently.
Incentivize active demand management by promoting energy offers with hourly tariffs that encourage consumers to incentivize users to carry out smart recharging during off-peak hours.
Integrate V2G technology, allowing the entry of a large amount of distributed and renewable energy and the active participation of customers in the electricity system. This technology allows bidirectional management of the grid since, on the one hand, it consumes energy from the grid, but, on the other hand, it can return it during peak demand hours. This allows advanced load control in smart grids. Even V2G policies could also be useful for supplying stationary demands, particularly home demand.
One of the key achievements of smart grids could be the implementation of demand-side management, which is a very powerful weapon to improve the performance of power systems, particularly in the current situation where there is a transition process in power systems. Demand-side management in households is possibly the most widely used strategy to shift the demand’s curve toward the generation’s one [
38,
42].
Until now, generation and demand estimates have been considered separately. However, it is also necessary to know how daily generation and demand are distributed, in order to try to match them as much as possible, so that the storage capacity needed to manage this inevitable decoupling can be optimized. For this reason, the generation patterns of the different renewable sources that constitute the generation mix, i.e., in our case wind and solar photovoltaic, must be analyzed. Given the predictability of solar photovoltaic generation, it fits very well with storage technologies, which makes it possible to perform a more accurate sizing of the storage capacity needed to manage it. As is well known, solar photovoltaic production is concentrated in the central day hours and always with the same pattern (except for variations among seasons, but which are also well-known), which makes the daily day–night charge and discharge cycles easier. Moreover, the irradiation on the Canary Islands in general is very high, as well as on Grand Canary Island. In addition, days with a shortage of sunshine are few and do not usually occur on consecutive days.
On the other hand, wind generation can have several days with low production periods, although it also has a good performance on the Canary Islands. These possible low wind speeds mean that greater storage capacity is required. In addition, in the opposite direction, there can be periods of several days producing practically at total capacity, which saturates the storage system and can generate substantial surpluses, which would imply its waste. However, in the case of Grand Canary Island, the winds are high and very stable. Therefore, the optimal generation MIX will probably be close to a balance of installed power with significant contributions from both technologies.
As a result, especially with high amounts of solar PV generation, appropriate demand management is imperative. These measures make it possible to bring the electricity consumption profile closer to the generation profile, reducing the required storage capacities. In a general way, it is estimated that both in the Canary Archipelago and on Grand Canary Island it is possible to displace the demand curve toward the generation curve, i.e., toward the central hours of the day, by approximately 20–30% of the total daily consumption [
21]. So, through these demand management measures, it is possible to shift the demand curve from a rather flat shape to a curved shape that follows a typical fully electrified final energy consumption curve quite well. This change in the shape of the demand curve could be achieved by influencing fundamentally two aspects, firstly by favoring the recharging of electric vehicles in the central hours of the day and, secondly, by bringing household consumption (DHW and household appliances) to these same intervals.
Given that in these central hours, there is an immense generation peak produced by solar photovoltaic generation, which is impossible to absorb unless the storage system is significantly oversized, with the consequent cost overrun of the system. To this end, measures should be taken in the electricity tariff and hourly price signals to encourage consumer demand during these hours of increased renewable production. These procedures will be differentiated for each consumer, including demand aggregators, connected electric vehicle management systems, or changes in the interruptibility tariff for major consumption users. It would be necessary to develop an appropriate regulatory scheme for this service and an operational procedure that allows the system operator to handle it clearly, efficiently, and transparently.
This distributed generation and storage could be extended to hydrogen production; although this centralized mass production is more economical nowadays, the high transport costs can minimize these advantages. Consequently, integrating distributed hydrogen production on renewable energy microgrids is considered a practical and attractive way to reduce production, storage, and transportation costs. Distributed generation is becoming a possible electric generation alternative along with hydrogen production [
43,
44]. Examples of hybridized systems between renewable generation and hydrogen as energy carriers have been proposed for smart microgrid systems [
41,
44]. The current study goes one step further, as it integrates hydrogen generation within a more extensive system; i.e., it integrates hydrogen production into the island’s electric generation network. This research explores the use of electric energy surpluses to produce hydrogen, being able to cover the island’s needs, both electric energy and hydrogen (used to cover the nonelectrifiable uses).