At Frontis Energy we have spent much thought on how to recycle CO2. While high value products such as polymers for medical applications are more profitable, customer demand for such products is too low to recycle CO2 in volumes required to decarbonize our atmosphere to pre-industrial levels. Biofuel, for example from field crops or algae has long been thought to be the solution. Unfortunately, they require too much arable land. On top of their land use, biochemical pathways are too complex to understand by the human brain. Therefore, we propose a different way to quickly reach the target of decarbonizing our planet. The procedure begins with a desired target fuel and suggests a microbial consortium to produce this fuel. In a second step, the consortium will be examined in a bio-electrical system (BES).
CO2 can be used for liquid fuel production via multiple pathways. The end product, long-chain alcohols, can be used either directly as fuel or reduced to hydrocarbons. Shown are examples of high level BEEF pathways using CO2 and electricity as input and methane, acetate, or butanol as output. Subsequent processes are 1, aerobic methane oxidation, 2, direct use of methane, 3 heterotrophic phototrophs, 4, acetone-butanol fermentation, 5, heterotrophs, 6, butanol direct use, 7, further processing by yeasts
Today’s atmospheric CO2 imbalance is a consequence of fossil carbon combustion. This reality requires quick and pragmatic solutions if further CO2 accumulation is to be prevented. Direct air capture of CO2 is moving closer to economic feasibility, avoiding the use of arable land to grow fuel crops. Producing combustible fuel from CO2 is the most promising intermediate solution because such fuel integrates seamlessly into existing urban infrastructure. Biofuels have been explored intensively in recent years, in particular within the emerging field of synthetic biology. However tempting the application of genetically modified organisms (GMOs) appears, non-GMO technology is easier and faster to implement as the required microbial strains already exist. Avoiding GMOs, CO2 can be used in BES to produce C1 fuels like methane and precursors like formic acid or syngas, as well as C1+ compounds like acetate, 2-oxybutyrate, butyrate, ethanol, and butanol. At the same time, BES integrate well into urban infrastructure without the need for arable land. However, except for methane, none of these fuels are readily combustible in their pure form. While electromethane is a commercially available alternative to fossil natural gas, its volumetric energy density of 40-80 MJ/m3 is lower than that of gasoline with 35-45 GJ/m3. This, the necessary technical modifications, and the psychological barrier of tanking a gaseous fuel make methane hard to sell to automobilists. To produce liquid fuel, carbon chains need to be elongated with alcohols or better, hydrocarbons as final products. To this end, syngas (CO + H2) is theoretically a viable option in the Fischer-Tropsch process. In reality, syngas precursors are either fossil fuels (e.g. coal, natural gas, methanol) or biomass. While the former is obviously not CO2-neutral, the latter competes for arable land. The direct conversion of CO2 and electrolytic H2 to C1+ fuels, in turn, is catalyzed out by electroactive microbes in the dark (see title figure), avoiding food crop competition for sun-lit land. Unfortunately, little research has been undertaken beyond proof of concept of few electroactive strains. In stark contrast, a plethora of metabolicstudies in non-BES is available. These studies often propose the use of GMOs or complex organic substrates as precursors. We propose to systematically identify metabolic strategies for liquid bio-electrically engineered fuel (BEEF) production. The fastest approach should start by screening metabolic databases using established methods of metabolic modeling, followed by high throughput hypothesis testing in BES. Since H2 is the intermediate in bio-electrosynthesis, the most efficient strategy is to focus on CO2 and H2 as direct precursors with as few intermediate steps as possible. Scalability and energy efficiency, economic feasibility that is, are pivotal elements.
First, an electrotrophic acetogen produces acetate, which then used by heterotrophic algae in a consecutive step.
Possible pathways for BEEF production involving Clostridium, 3, or heterotrophic phototrophs, 7, further processing by yeasts
Yeasts are among the microorganisms with the greatest potential for liquid biofuel production. Baker’s yeast, (Saccharomyces cerevisiae) is the most prominent example. While known for ethanol fermentation, yeasts also produce fusel oils such as butane, phenyl, and amyl derivate aldehydes and alcohols. Unlike ethanol, which is formed via sugar fermentation, fusel oil is synthesized in branched-off amino acid pathways followed by aldehyde reduction. Many enzymes involved in the reduction of aldehydes have been identified, with alcohol dehydrogenases being the most commonly observed. The corresponding reduction reactions require reduced NADH but it is not known whether H2 produced on cathodes of BES can be involved.
Clostridia, for example Clostridium acetobutylicum and C. carboxidivorans, can produce alcohols like butanol, isopropanol, hexanol, and ketones like acetone from complex substrates (starch, whey, cellulose, etc. ) or from syngas. Clostridialmetabolism has been clarified some time ago and is different from yeast. It does not necessarily require complex precursors for NAD+ reduction and it was shown that H2, CO, and cathodes can donate electrons for alcohol production. CO2 and H2 were used in a GMO clostridium to produce high titers of isobutanol. Typical representatives for acetate production from CO2 and H2 are C. ljungdahlii, C. aceticum, and Butyribacterium methylotrophicum. Sporomusa sphaeroides produces acetate in BES. Clostridia also dominated mixed culture BESs converting CO2 to butyrate. They are therefore prime targets for low cost biofuel production. Alcohols in clostridia are produced from acetyl-CoA. This reaction is reversible, allowing acetate to serve as substrate for biofuel production with extracellular energy supply. Then, energy conservation, ATP synthesis that is, can be achieved from ethanol electron bifurcation or H2 oxidation via respiration. While possible in anaerobic clostridia, it is hitherto unknown whether electron bifurcation or respiration are linked to alcohols or ketone synthesis.
Phototrophs like Botryococcus produce C1+ biofuels as well. They synthesize a number of different hydrocarbons including high value alkanes and alkenes as well as terpenes. However, high titers were achieved by only means of genetic engineering, which is economically not feasible in many countries due to regulatory constrains. Moreover, aldehyde dehydration/deformylation to alkanes or alkenes requires molecular oxygen to be present. Also the olefin pathway of Synechococcus depends on molecular oxygen with the cytochrome P450 involved in fatty acid decarboxylation. The presence of molecular oxygen affects BES performance due to immediate product degradation and unwanted cathodic oxygen reduction. In contrast, our own preliminary experiments (see title photo) and a corrosion experiment show that algae can live in the dark using electrons from a cathode. While the enzymes involved in the production of some algal biofuels are known (such as olefin and aldehyde deformylation), it is not known whether these pathways are connected to H2 utilization (perhaps via ferredoxins). Such a connection would be a promising indicator for the possibility of growing hydrocarbon producing cyanobacteria on cathodes of BES and should be examined in future research.
At Frontis Energy we believe that a number of other microorganisms show potential for BEEF production and these deserve further investigation. To avoid GMOs, BES compatible co-cultures must be identified via in silico metabolic reconstruction from existing databases. Possible inter-species intermediates are unknown but are prerequisite for successful BES operation. Finally, a techno-economical assessment of BEEF production, with and without carbon taxes, and compared with chemical methods, will direct future research.
An abandoned or unproductive oilfield can be reused for methane production from CO2 using renewable electrical power. Exhausted oilfields can be reactors for the conversion of renewable energy to natural gas using microbes. To achieve this, an oilfield can be made electrically conductive and catalytically active to produce natural gas from renewable power sources. The use of natural gas is superior to any battery because of the existing infrastructure, the use in combustion engines, the high energy density and because it can be recycled from CO2. Oilfields are superior to any on-ground production because of the enormous storage capacities. They are already well explored and these geological formations underwent environmental risk assessments. Lastly, the microbial power-to-gas technology is already available.
Process summary
Whole process (end-to-end via methane)
50% electrical efficiency
Energy density of methane
180 kWh kg−1
Storage capacity per oilfield
3 GWh day−1
Charge/Discharge cycles
Unlimited
Investment (electrodes, for high densities)
$51,000 MW−1
Cost per kWh (>5,000 hours anode lifetime)
<$0.01 kWh−1
Electrolyte
Seawater
The Problem
To address the problem of storing renewable energy, batteries have been proposed as a possible solution. Lithium ion batteries have a maximum energy storage capacity of 0.3 kWh kg−1. To date, this is considered the best trade-off between cost and efficiency but these batteries are still too inefficient to replace gasoline, which has a capacity of about 13 kWh kg−1. This makes battery driven cars heavier than conventional cars. Lithium air batteries are considered a possible alternative because they can reach theoretical capacities of 12 kWh kg−1 but technical difficulties have prevented them from being used for transportation.
In contrast, methane has an energy density of 52 MJ kg−1 corresponding to 180 kWh kg−1 which is second only to hydrogen with 500 kWh kg−1, not counting in nuclear energy. This high energy density of methane and other hydrocarbons along with their facile usage, is the reason why they are used in combustion and jet engines that drive nearly all transportation to date. While electrical cars seem to be a tempting green alternative, the fact that combustion engines and the fueling infrastructure are so wide-spread makes it difficult to switch.
In addition to the difficulty of changing habits, battery-driven electrical cars need other limited natural resources such as lithium. To equip all 94 million automobiles produced worldwide in 2017, 3 mega tons lithium carbonate would need to be mined annually. This is nearly 10% of the entire recoverable lithium resources of 35 mega tons worldwide. Although lithium and other metals can be recycled, it is clear that metal based batteries alone will not build the bridge between green energy and traditional ways of transportation due to the low energy densities of metals. And this does not even take into account other energy demands such as industrial nitrogen fixation, aviation or heating.
For Germany, with its high proportion of renewable energy, fuel for cars is not the only problem. As renewable energy is generated in the north, but many energy consumers are in the south, the grid capacity is frequently reached during peak production hours. A steadier energy output can only be accomplished by decentralizing the production or by energy storage. To decentralize production, homeowners were encouraged to equip their property with solar panels or windmills. As tax incentives phase out, homeowners face the problem of energy storage. The best product for this group of customers so far are again lithium ion batteries but investment costs of $0.10 kWh−1 are still unattractive especially because these products store the energy as electricity which can only be used for a short time and is less efficient than natural gas when used for heating.
Natural gas is widely used as energy source today and the global energy infrastructure is designed for natural gas and other fossil fuels. Increasing demand and limited resources for these fossil fuels were the main drivers of oil and gas prices during the last years, slowed by the recent economic crises and hydraulic fracturing (fracking). The high oil price attracted investors to recover oil using techniques that become increasingly expensive and are environmental risks such as deep-sea drilling or tar sand extraction. Ironically, the high oil price made costly renewable energies an economically feasible alternative and helped driving down their cost. Since habits are difficult to change and building an entirely new infrastructure only for renewable energies does not seem economically feasible today while CO2 drives global warming, a more realistic solution needs to be found.
Microbial Power-to-Gas could be a bridging technology that integrates renewable energy into the existing fossil fuel infrastructure. It reaches break even in less than 2 years if certain preconditions are met. This is accomplished by integrating methane produced from renewable energy into the current oil and gas producing infrastructure. The principal idea is to use carbon instead of metals as energy carrier because of its high energy density when bound to hydrogen. The benefits are:
High energy density of 180 kWh kg−1 methane
Low investments due to existing infrastructure (natural gas, oilfield equipment)
Carbon is not a limited resource
Low CO2 footprint due to CO2 recycling
Methane is a transportation fuel
Methane is the energy carrier for the Haber-Bosch process
Inexpensive catalysts further reduce initial investments
Low temperatures due to bio-catalysis
No toxic compounds used
No additional environmental burden because existing oilfields are reused
The solution
Methane can be synthesized by microbes or chemically. Naturally, methane is produced by anaerobic (oxygen-free) microbial biomass decomposition. The energy for biomass synthesis is provided by sunlight or chemical energy like hydrogen. In the case of methanogens (methane producing microbes), energy is harvested after CO2 and hydrogen were released from biomass decomposition following a 1-to-4 stoichiometry:
CO2 + 4 H2 → CH4 + 2 H2O
Without microbes, methane is produced by the Nobel-prize winning Sabatier reaction and several attempts are currently underway to use it on industrial scale. It is necessary to split water into hydrogen and use this to reduce CO2 in the gas phase. A major drawback of the Sabatier reaction is the need for high temperatures around 385ºC, and a nickel catalyst that becomes quickly spent. Methanogens use iron-nickel enzymes called hydrogenases to harvest energy from hydrogen, but do so at ambient temperatures.
Power-to-Gas concept for exhausted oilfields. Electrolysis catalyzes water splitting inside the oilfield producing methane gas and O2.
The future challenge will be to accelerate methane production rates as has been reported for a high temperature oilfield cultures. Besides increasing the temperature, the most obvious solution is to use a higher reactive surface and bringing both electrodes closer together. Using carbon brushes that are poor hydrogen catalysts but provide a higher surface for microbial attachment is one possibility. Methane production correlates with microbial cell numbers in the reactors.
The number of methanogens in microbial electrolysis reactors correlates with the electrode surface.
To overcome the problem of expensive carbon (and also steel) brushes for large scale applications,exhausted gas and oilfields could be used. They provide a high surface area and are usually economic liabilities and not assets. Methanogens inhabit oilfields where they carry out the final step in anaerobic petroleum degradation. Hence, oilfields can be seen as bioreactors at geological scale. Geological formations provide ideal conditions for producing, storing and extracting methane.
Open questions and potential solutions
Oilfield porespace volume
The Californian Summerland oilfield, for instance, has been abandoned and extensively studied in the past. It produced 27 billion barrels of oil and 2.8 billion m3 methane during its lifetime of 90 years. This maximum load of 3.5 billion m3 left the same volume of porespace filled with seawater behind. Only 2% of these pores are larger than 50 µm, which is necessary for microbial growth assuming dimensions of 1 x 2 µm of a methanogen cell. Experiments showed that the resulting 70 million m3 accessible porespace have a storage capacity of 35,000 TW. That is a lot of methane assuming a solubility of 0.74 kg methane m−3 seawater at 500 m water depth. All German off-shore windfarms together have a capacity of 7,000 MW. Obviously, the limiting factor is not the volumetric storage capacity of an oilfield.
Microbial methane production rates
But how fast can microbes produce methane in an hypothetical oilfield? Under optimal conditions, methanogens that grow on electrodes (typically the genus Methanobacterium or Methanobrevibacter) can produce methane at a rate of 100-200 nmol ml−1 day−1 (equals 2.24-4.48 ml l−1 day−1) depending on catalyst and potential. Using a production rate of 15 J ml−1 day−1 of methane (190 nmol ml−1 day−1), the entire microbially accessible oilfield (2%) has a capacity of 3.6 million MBtu per year. Microbes would theoretically consume 1 TWh per year for 3.6 million MBtu methane production if there were no losses and electrical power is translated into methane 1-to-1. A power generator of 121 MW would be sufficient to supply the entire oilfield at these rates. However, all German off-shore windfarms produce 7,000 MW meaning that only 3% off-peak power can be captured by our example oilfield. Therefore, the catalytic surface and activity must be increased to accelerate methane conversion rates.
Since methanogens produce methane from hydrogen, not only the 2% porespace big enough for cells can be used resulting in an increased catalytic surface to nearly 60%. A hydrogen catalyst needs to be found that does not out-pace methanogen growth to keep the reservoir pH within the limits of 6-8 required for methanogen growth. This hydrogen catalyst must be cheap and render an oilfield electrically conductive. A chemical formulation that mimics microbial hydrogen catalysis could be used. It has the potential to turn a non-conductive and non-catalytic oilfield into a conductive hydrogen catalyst sufficient to sustain methane production needed to store all of Germany’s electricity produced by off-shore windfarms. This catalyst is soluble in water when inactive. To become active, it coats mineral surfaces by precipitation that can be triggered by indigenous microbes or by electrical polarization. The investment would be $2.3 million per MW storage capacity ($16 billion for the entire 7,000 MW). Due to microbial growth, the catalytic activity of the system improves during operation and there is no need for the second component if an immediate production is not crucial. The investments made on the cathode side would then be as low as $600 per MW ($4.2 million for 7,000 MW).
Anodes
As the cathodic side of the reaction can be excluded as limiting factor, the anode needs to be designed. Several commercially available anodes such as mixed metal oxides (up to 750 A m−2) with platinum on carbon black or niobium anodes (Pt/C, 5-10 kA m−2) could be used. Anodes based on platinum are the most cost-efficient material available on the market. Investments made for Pt/C (10%, 6 mg cm−2) anodes will amount to $50,000 per MW ($350 million for 7,000 MW). However, the exact amount of Pt needed for the reaction still needs to be evaluated in an experiment because the corrosion rate at 2 V cell voltage is unknown. An often cited value for the lifetime of fuel cells is 5,000 hours and is used here to determine the costs per kWh. For 5,000 hours lifetime, the costs per kWh will be at the targeted limit of $0.01 but may be well below that because Pt/C anodes can be recycled and the Pt load may be reduced to 3 mg cm−2 (5%). Alternatively, steel anodes (SS316, 2.5 kA m−2, $54,000 per MW) can be used but it is unclear when steel anodes fail to electrolyze. In conclusion, the anodic side is the cost-driving factor. Hopefully, better water splitting anodes will lower these costs in future.
Cost estimation summary
Windfarms
Already in place
CO2 injection
Already occurred
Natural gas capturing equipment
Already in place
Microbial seed
Wastewater from oil rig
Cathode costs
$600 MW−1
Anode costs
$50,000 MW−1
Electrolyte (seawater)
Free
Total (>5,000 hours anode lifespan)
<$0.01 kWh−1
Energy and conversion efficiencies
The whole cell voltage for microbial power-to-gas reactions varies from 0.6 to 2.0 V, depending on cathodic rates, anodic corrosion and the presence of a membrane. Higher voltages will accelerate anode corrosion, again, making anodes the limiting factor. As the voltage decreases, methane production rates become slower but also more efficient. The voltage also depends on the pH of the oilfield. An oilfield that underwent CO2 injection as enhanced recovery method will have a low pH, providing better conditions for hydrogen production but not for microbial growth and must be neutralized using seawater. As stated above, the oilfield, being the cathode, is not limiting the the system. The use of Pt/C anodes eliminates the overpotential problem on the anode side. Hence, we can assume an ideal system that splits water at 1.23 V. However, the voltage is often 2 V due to anode and cathode overpotentials. Optimized cultures and cathodes produce about 190 nmol ml−1 day−1 methane which equals 0.15 J ml−1 day−1 using the energy of combustion of 0.8 MJ mol−1. The same electrolysis cell consumes 0.2 mW at a cell voltage of 2 V which equals 0.17 J ml−1 day−1 and the resulting energy efficiency is 91%. The anodes can be simple carbon brushes and the two chambers of the cell are separated by a Nafion™ membrane. The system can still be optimized by using Pt/C anodes and by avoiding membranes.
The overall electricity-methane-electricity efficiency also depends on the consumption side efficiency where methane is used in combustion engines and gas fired power plants. Such power plants frequently operate at efficiencies of 40- 60%. Assuming a reasonable power efficiency of 80% (see above), the overall electrical power recovery using gas fired power plants will be up to 50%. Besides the high efficiency of gas fired power plants, they are also easy to build and therefore contribute the a better power grid efficiency. Coal fired power plants can be upgraded to gas fired power plants.
Experimental approach
The conversion efficiencies of charge (Coulombs) transported across the circuit are usually between 70-100% in these systems depending on the electrode material. Another efficiency limitation could arise from mass transport inhibition. Mass transport can be improved by pumping electrolyte adding more costs for pumping which still have to be determined. However, since most oilfields undergo seawater injection for enhanced oil recovery the additional cost may be negligible. The total efficiency has yet to be determined in scale-up experiments and will depend on the factors mentioned above.
The reactor simulates oilfield conditions using sand as filling material under continuous flow of electrolyte.
Controlling the pH is crucial. Alkaline pHs significantly impede hydrogen production and therefore methanogenesis. This can be addressed by a software that monitors the pH and adjusts the potential accordingly. Addition of acids is not desired as this drives the costs. The software can also act as potentiostat that then fully controls the methane production process. To test the process under more realistic conditions, a drill core from an oilfield must be obtained.
Results show methane production in the simulation reactor. The appearance of methane in the anode compartment was a result of flow from the cathode to the anode, carrying produced methane with it.
Return of investment of the microbial power-to-gas process
The the microbial power-to-gas process in unproductive oilfields is economically superior to all other storage strategies because of the low start-up and operating costs. This is achieved because the major investments are the installation of oil- and gas production equipment and renewable power plants which are already in place as a precondition. These investments break even in a short amount of time.
But how can the microbial Power-to-Gas process accelerate the return of investment in renewable energy? Only 8 out of 28 active off-shore windfarms reported their investment costs. These 8 produce roughly half the overall power of 1,600 MW corresponding to $7 billion. While the maximum production of an oilfield with unlimited supply of electricity would yield hypothetical 3.6 million MBtu natural gas per year resulting a return of $13 million per year the real production is limited by off-peak power generated by renewable energy production. Assuming that the maximum annual methane production corresponds to 10% excess electrical power, $15 million per year can by generated by selling 4.3 million MBtu methane per year on the market. These are $15 million that are not lost during off-peak shutdowns. Clearly, this conservative estimate can help to compensate the investment in renewable energy earlier. It also decreases the investment risk because the investment calculations for new wind farms can be made on a more reliable basis.
In the example using all German windfarms (7,000 MW) this compensation roughly doubles. Using the $60 million generated by methane sales per year, the investment of $4 million for the cathodic catalyst and the $36 million for the Pt/C anodes are compensated for within less than a year. No other investments are required because the target oilfield already produced oil and gas and all necessary installation are in working condition. The target oilfield is swept using seawater as secondary extraction method. Electrical installations are in place for cathodic protection of production equipment in order to prevent microbial corrosion, which, however, may need to be upgraded to pass the now higher power densities. Moreover, CO2 is used from CO2 injection as tertiary enhanced oil recovery method. Only the pH may then need to be adjusted to sustain life by sweeping with seawater.
And this is not the end of oilfield storage capacity. In theory, an oilfield can store the entire amount of renewable energy produced in one year globally, allowing more than enough head room for future development and CO2 sequestration.
Proximity to both Scandinavia and mainland Europe makes exporting and importing power rather easy for the Danish system operator, Energinet.dk. This provides Denmark with the flexibility needed to achieve significant penetration of intermittent energy sources like wind while maintaining grid stability.
While the results to-date have been promising, getting to 100 percent renewable energy will still require a significant leap and the official policies that Denmark will use to guide this transition have yet to be delivered. However, there has been some indication at what the ultimate policies may look like. In their report Energy Scenarios for 2020, 2035 and 2050, the Danish Energy Agency outlined four different scenarios for becoming fossil-free by 2050 while meeting the 100 percent renewable electricity target of 2035. The scenarios, which are primarily built around deployment of wind energy or biomass, are:
Wind Scenario – wind as the primary energy source, along with solar PV, and combined heat and power. Massive electrification of the heat and transportation sectors.
Biomass Scenario – less wind deployment that in the wind scenario, with combined heat and power providing electricity and district heating. Transportation based on biofuels.
Bio+ Scenario – existing coal and gas generation replaced with bioenergy, 50% of electricity from wind. Heat from biomass and electricity (heat pumps).
Hydrogen Scenario – electricity from wind used to produce hydrogen through electrolysis. Hydrogen used as renewable energy storage medium, as well as transportation fuel. Hydrogen scenario would require massive electrification of heat and transport sectors, while requiring wind deployment at faster rate than the wind scenario.
Agora Energiewende and DTU Management Engineering, have postulated that this scenario report does in fact show that transitioning the Danish energy sector to 100 percent renewables by 2050 is technically feasible under multiple pathways. However, Danish policy makers must decide before 2020 whether the energy system will evolve into a fuel-based biomass system, or electricity-based wind energy system (they must decided which of the four scenarios to pursue).
Energy Storage Facilities – Denmark
Regardless of which energy policy scenario Denmark decides to pursue, energy storage will be a central aspect of a successful energy transition. There are currently three EES facilities operating in Denmark, all of which are electro-chemical (batteries). A fourth EES facility – the HyBalance project – is currently under construction and will convert electricity produced by wind turbines to hydrogen through PEM electrolysis (proton exchange membrane).
The HyBalance project is the pilot plant undertaking of Power2Hydrogen, a working group comprised of major industry players and academic research institutions aimed at demonstrating the large-scale potential for hydrogen from wind energy. The plant will produce up to 500 kg/day of hydrogen, used for transportation and grid balancing.
Worth noting is the decommissioned BioCat Power-to-Gas project, a pilot plant project which operated from 2014 to 2016 in Hvidovre, Denmark. The project, a joint collaboration between Electrochaea and several industry partners (funded by Energienet.dk), was a 1 MWe Power-to-Gas (methane) facility built to demonstrate the commercial capabilities of methane power-to-gas. The BioCat project was part of Electrochaea’s goal of reaching commercialization in late 2016, however, as of early 2017 no further updates have been given.
Energy Storage Market Outlook − Denmark
The energy storage market in Denmark will be most primed for growth should policy follow the Hydrogen Scenario, where massive amounts of hydrogen production will be needed to eliminate the use of fossil fuels across all sectors.
Renewable energy produced gases (hydrogen, methane) have the potential to balance the electricity grid in two primary ways: balancing supply and demand (“smart grid”), and balancing through physical storage. The smart grid, an intelligent electricity grid where production and consumption are administered centrally, presents significant opportunity for electrolysis technologies as short-term “buffer” storage (seconds to minutes). Bulk physical storage of renewable energy produced gases can act as a longer-term storage solution (hours, days, weeks, months) to help maintain flexibility in a fossil-free energy grid (The Danish Partnership for Hydrogen and Fuel Cells).
Without the hydrogen scenario, the potential for hydrogen-based energy storage in Denmark will be limited. In their 2016 report “potential of hydrogen in energy systems”, the Power2Hydrogen working group concluded that:
hydrogen electrolysers would not provide any significant upgrade on flexibility for renewables integration over today’s sufficiently flexible system, and;
by 2035, with the increased wind production, it was concluded that hydrogen electrolysers would in fact improve system flexibility, allowing for even more extensive penetration of wind energy in the system.
The potential for renewable energy produced gases in Demark is extremely high. There is a very distinct possibility that power-to-gas type of systems will be the linchpin of Denmark’s energy transition. While there appears to be little opportunity in the short-term, there will be extensive opportunity in the medium-to-long-term should the official energy transition policy focus on the hydrogen scenario, or a similar renewable gas based policy.
In our previous post we briefed you on the energy storage potential in the United Kingdom. With Brexit, Italy will become the third largest member state after Germany and France. With extensive mountain terrain in the north, Italy has long been dependent upon hydroelectric generation. Until the mid 1960s hydropower represented nearly all electricity production in Italy. The installed capacity of hydropower has been stagnant since the mid 1960s, with a rapid growth in fossil fuel based generation driving the overall share of hydropower fall from ~90% to 22% in 2014. A detailed breakdown of electricity sources in Italy is shown below.
Electricity Production in Italy (2014)
Considerable effort has been made to transition Italy to a low carbon electricity sector. As of 2016, Italy had the 5th highest installed solar capacity in the world and the 2nd highest per capita solar capacity, behind only Germany. In addition to its impressive solar progress Italy ranks 6th worldwide in geothermal with 0.9 GW.
Italy’s solar growth was propelled by feed-in-tariffs that wer enacted in 2005. This provided residential PV owners with financial compensation for energy sold to the grid. However, the feed-in-tariff program ceased on 06 July 2014 after the €6.7 billion subsidy limit was reached.
Even with its impressive accomplishments in renewable energy, traditional thermal generation (natural gas) still account for ~60% of total electricity generation in Italy. How much effort will go into reducing this number is still unclear. Italy has committed to 18% renewables by 2020 and is nearly 70% of the way there already so there is little urgency on reducing fossil-based electricity from the perspective of meeting this target. However, Italy is heavily reliant on fossil fuel imports (Deloitte) and energy security requirements will likely continue to push the development of more domestic electricity sources like renewables.
Energy Storage Facilities
Italy is dominating the electro-chemical energy storage market in Europe. With over 6,000 GWh of planned and installed electro-chemical generating capacity (~84 MW installed capacity), Italy is far ahead of 2nd place UK. This is largely due to the massive SNAC project by TERNA (Italy’s TSO), a sodium-ion battery installation totaling nearly 35 MW over three phases. A breakdown of energy storage projects, by technology type can be seen below.
Italy is one of the top markets in the EU for energy storage and is primed for growth. The Italian TSO, TERNA, has been investigating selling energy storage as a service. In 2014 the AEEG, the electrical regulator under which TERNA operates, proposed that batteries should be treated as generation sources similar to cogeneration plants. Italy has always been a market completely dominated by a small number of big centralized utility companies and this trend is likely to continue when it comes to EES deployment. These companies have been focusing their efforts on battery technologies and are expected to continue down this path.
However, the private market could present great opportunity for P2G. The International Battery & Energy Storage Alliance have summarized the reality of Italy’s untapped energy storage market as follows: “With high solar output of 1,400 kWh/kWp, net residential electricity prices around 23 cent/kWh and currently no FIT, the Italian energy market is considered to be highly receptive for energy storage.”
Italy is now well-stocked with residential PV systems that can no longer collect subsidies. Combine this with the fact that the vast majority of homes in Italy burn natural gas imported from Russia, Libya and Algeria and it is clear that Italy presents a unique opportunity for P2G at a residential/community level. This is echoed by Energy Storage Update who in 2015 concluded that Italy was “one of the top four markets worldwide for PV-and-battery-based energy self-consumption.”
While it is unclear exactly how many residential PV systems there are in Italy, it was speculated in late 2015 that there were over 500,000 PV plants in Italy.
In our last post about the EU energy storage market we gave a brief overview of Germany’s situation. Now, we show how the United Kingdom prepared itself for its energy transition. Traditionally, the UK’s energy mix has been dominated by fossil fuels. This remains the status quo today, as approximately 60% of the electricity generated in the UK comes from fossil fuel sources, with another 20% coming from nuclear.
UK electricity production 2015 (Source: The UK Government)
While the UK has been heavily dependent on carbon-intensive sources of electricity, in 2008 they committed to a 15% renewable energy target (by 2020) and 80% reduction in CO2 emissions (by 2050; Department of Energy & Climate Change). However, the UK has stated that they will miss the 15% renewable target for 2020, due to the lack of properly designed policy measures. There has been considerable pressure to transition to a low carbon market and with one-quarter of existing generating capacity (mainly coal and nuclear) expected to close by 2021; it is expected that growth in renewable energy will lead to more energy storage capacities.
The UK has made excellent progress on its short-term clean energy goals and there is optimism that this trend will continue. Large-scale development of low carbon generation technologies such as wind and solar is expected to continue.
Energy Storage Facilities
As of late 2016, there were 27 non-PHS EES plants representing 430 MW of installed capacity in the UK (Sandia National Laboratories). The UK’s energy storage portfolio is dominated by electro-chemical based technologies (primarily lead-acid and lithium-ion battery installations). This is shown below.
Number of Existing & Planned Energy Storage Facilities in the UK, by Type (Source: Sandia National Laboratories)
As was shown for Germany, only a very small fraction of EES facilities are dedicated to renewables capacity firming. The existing EES capacity is almost exclusively dedicated to critical transmission support (on-site power). While nearly all of the EES capacity under development is dedicated to bulk energy storage (electric energy time shift).
There is still considerable uncertainty around the growth of EES in the UK, and with such a small sample size it is difficult to infer any correlation from the data in the figure above. According to the previous UK government, however, being geographically isolated and a net importer of electricity, one would expect the UK to place a heavier focus on renewables capacity firming in the long-term.
Energy Storage Market Outlook
The UK is in the midst of a major restructuring of their electricity generating portfolio and the market under which these assets operate. With a large portion of the existing capacity due for retirement in the next 10-15 years, the UK faces challenges in meeting energy needs while balancing decarbonization efforts. As part of this, major investment is needed in all areas of the electrical grid, including energy storage.
In its Smart Power publication, the National Infrastructure Commission outlined that while the UK is being faced with challenges to cover aging infrastructure this represents an opportunity to build efficient and flexible energy infrastructure. The Commission stated that energy storage was one of the three key innovations for a “smart power revolution”.
Many other official government bodies have expressed similar thoughts regarding energy storage. In its Low carbon network infrastructure report, the Energy and Climate Change Committee stated that “storage technologies should be deployed at scale as soon as possible”, while urging the Government to eliminate the outdated and unfair regulations that have been handcuffing energy storage development in the UK (Garton and Grimwood).
In April 2016, the Government acknowledged concerns regarding the regulatory hurdles facing energy storage projects (primarily double-charging of network charges) and stated that they would begin working with the National Infrastructure Commission and ECCC to investigate the issue. While there may be regulatory hurdles hindering energy storage in the UK, the Government has shown commitment through funding. Since 2012, the government has contributed over £80 million to energy storage research. In addition to this, the Department of Energy and Climate Change have developed a new £20 million fund to help drive innovation in energy storage technologies.
Overall, the outlook for energy storage in the UK is positive. There is considerable pressure to begin developing energy storage facilities at scale from not only industry, but also many government bodies. Investors are ready as well. As stated by the National Infrastructure Commission: “businesses are already queuing up to invest”.
Simply put: regulatory hurdles are holding back growth in the UK energy storage market. With the Government making major strides in renewable energy development and being vocal about its commitment to making the UK a leader in energy storage technology, these regulatory hurdles will likely be relaxed and there should be considerable growth in the UK energy storage market in the near-term.
At this point, specific technology types and service uses have not been hypothesized in detail. However, with the UK being geographically isolated and a net importer of electricity, logic would suggest an emphasis on renewables capacity firming in the long-term to maximize domestic consumption of renewable energy. Rapidly decreasing costs in electro-chemical technologies, coupled with the fact that much of the existing gas-fired capacity will be reaching end of life by 2030 suggest that the UK EES market would not be ideal for P2G technologies.
In our last posts we introduced electrical energy storage (EES) and the EU market for EES. Now, we focus on some important EU members, beginning with Germany. The country’s electrical energy portfolio reflects its status among the most progressive countries in the world in terms of climate action. As of November 2016, Germany had produced ~35% of its 2016 electricity needs from renewable sources as outlined in the Figure below.
Electricity Production in Germany (Source: Fraunhofer ISE)
However, these numbers are somewhat skewed based on the fact that the electro-mechanical category is essentially two large capacity CAES plants. In reality, electro-chemical projects (mainly batteries) are much more prevalent and represent the vast majority of growth in the German storage market. There are currently 11 electro-chemical type energy storage projects under development in Germany and no electro-mechanical projects under development (see figure below).
As outlined earlier, there are a multitude of service uses for EES technologies. Currently the existing EES fleet in Germany serves grid operations and stability applications (black start, electric supply capacity), and on-site power for critical transmission infrastructure. A breakdown of service uses in the German market is shown below.
Net Exports of Electricity with Average Day-Ahead Market Pricing for Germany in 2015 (Source: Fraunhofer ISE)
Energy Storage Market Outlook
Logic seems to indicate that with aggressive renewable energy targets, a nuclear phase-out, and increased emphasis on energy independence Germany will need to develop more EES capacity. However, many have conjectured that the lagging expansion of EES in the short and medium term will not pose a barrier to the Energiewende. In fact, some claim that EES will not be a necessity in the next 10-20 years. For example, even when Germany reaches its 2020 wind and solar targets (46 GW and 52 GW, respectively), these would generally not exceed 55 GW of supply and nearly all of this power will be consumed domestically in real-time. Thus, no significant support from EES would be required.
The German Institute for Economy Research echos these sentiments and argue that the grid flexibility needed with significant renewable energy capacity could be provided by more cost-effective options like flexible base-load power plants and better demand side management. Additionally, innovations in power-to-heat technologies which would use surplus wind and solar electricity to feed district heating systems present significant opportunity, while creating a new market of energy service companies.
While there is work being done, economically feasible production of P2G is currently not achievable due to limited excess electricity and low guaranteed capacity. This limited excess electricity, is an example of the effect of power exports discussed earlier. While there may not be a significant commercial market in the short-term, introduction of P2G for transport could act as an additional driver behind continued renewable energy development in Germany.
Electrical Energy Storage (EES) is the process of converting electrical energy from a power network into a form that can be stored for converting back to electricity when needed. EES enables electricity to be produced during times of either low demand, low generation cost, or during periods of peak renewable energy generation. This allows producers and transmission system operators (TSOs) the ability to leverage and balance the variance in supply/demand and generation costs by using stored electricity at times of high demand, high generation cost, and/or low generation capacity.
EES has many applications including renewables integration, ancillary services, and electrical grid support. This blog series aims to provide the reader with four aspects of EES:
An overview of the function and applications of EES technologies,
State-of-the-art breakdown of key EES markets in the European Union,
A discussion on the future of these EES markets, and
Applications (Service Uses) of EES.
Table: Some common service uses of EES technologies
Storage Category
Storage Technology
Pumped Hydro
Open Loop
Closed Loop
Electro-chemical
Batteries
Flow Batteries
Capacitors
Thermal Storage
Molten Salts
Heat
Ice
Chilled Water
Electro-mechanical
Compressed Air Energy Storage (CAES)
Flywheel
Gravitational Storage
Hydrogen Storage
Fuel Cells
H2 Storage
Power-to-Gas
Unlike any other commodities market, electricity-generating industries typically have little or no storage capabilities. Electricity must be used precisely when it is produced, with grid operators constantly balancing electrical supply and demand. With an ever-increasing market share of intermittent renewable energy sources the balancing act is becoming increasingly complex.
While EES is most often touted for its ability to help minimize supply fluctuations by storing electricity produced during periods of peak renewable energy generation, there are many other applications. EES is vital to the safe, reliable operation of the electricity grid by supporting key ancillary services and electrical grid reliability functions. This is often overlooked for the ability to help facilitate renewable energy integration. EES is applicable in all of the major areas of the electricity grid (generation, transmission & distribution, and end user services). A few of the most prevalent service uses are outlined in the Table above. Further explanation on service use/cases will be provide later in this blog, including comprehensive list of EES applications.
Electrical energy storage (EES) is not only a vital component in the reliable operation of modern electrical grids, but also a focal point of the global renewable energy transition. It has been often suggested that EES technologies could be the missing piece to eliminating the technical hurdles facing the implementation of intermittent renewable energy sources. In the following blog posts, selected EES markets within the European Union will be evaluated in detail.
With over 80 MW of installed wind and solar capacity, Germany is by far the leading EU nation in the renewable energy transition. However, experts have argued that Germany’s need for widespread industrial scale energy storage is unlikely to materialize in any significant quantity for up to 20-years. This is due to a number of factors. Germany’s geographic location and abundance of connections to neighbouring power grids makes exporting any electricity fluctuations relatively easy. Additionally, when Germany reaches its 2020 targets for wind and solar capacity (46 GW and 52 GW, respectively) the supply at a given time would generally not exceed 55 GW. Nearly all of this would be consumed domestically, with no/little need for storage.
When evaluating energy storage in the UK, a different story emerges. Being an isolated island nation there is considerably more focus on energy independence to go along with their low-carbon energy goals. However, the existing regulatory environment is cumbersome, and poses barriers significant enough to substantially inhibit the transition to a low-carbon energy sector – including EES. The UK government has acknowledged the existence of regulatory barriers and pledged to address them. As part of this effort, a restructuring of their power market to a capacity-based market is already underway. The outlook for EES in the UK is promising, there is considerable pressure from not only industry, but also the public and the government to continue developing EES facilities at industrial scale.
Italy, once heavily hydro-powered, has grown to rely on natural gas, coal, and oil for 50% of it’s electricity (gas representing 34% alone). The introduction of a solar FIT in 2005 lead to significant growth in the solar industry (Italy now ranks 2nd in per capita solar capacity globally) before the program ended in July 2014. In recent years there has been notable growth in electro-chemical EES capacity (~84 MW installed), primarily driven by a single large-scale project by TERNA, Italy’s transmission system operator (TSO). This capacity has made Italy the leader in EES capacity in the EU, however the market is to-date dominated by the large TSOs.
However, the combination of a reliance on imported natural gas, over 500,000 PV systems no longer collecting FIT premiums, and increasing electricity rates presents a unique market opportunity for residential power-to-gas in Italy.
Denmark is aggressively pursing a 100-percent renewable target for all sectors by 2050. While there is still no official roadmap policy on how they will get there, they have essentially narrowed it down to one of two scenario: a biomass-based scenario, or a wind + hydrogen based scenario. Under the hydrogen-based scenario there would be widespread investment to expand wind capacity and couple this capacity with hydrogen power-to-gas systems for bulk energy storage. With the Danish expertise and embodied investment in wind energy, one would expect that the future Danish energy system would be build around this strength, and hence require significant power-to-gas investment.
The renewable energy industry in Spain has completed stagnated due to retroactive policy changes and taxes on consumption of solar generated electricity introduced in 2015. The implementation of the Royal Decree 900/2015 on self-consumption has rendered PV systems unprofitable, and added additional fees and taxes for the use of EES devices. No evidence was found to suggest a market for energy storage will materialize in Spain in the near future.
The final country investigated was the Netherlands, which has been criticized by the EU for its lack of progress on renewable energy targets. With only 10% of Dutch electricity coming from renewable sources, there is currently little demand for large-scale EES. While the Netherlands may be lagging behind on renewable electricity targets, they have been a leader in EV penetration; a trend that will continue and see 1-million EVs on Dutch roads by 2025. In parallel with the EV growth, there has been a large surge in sub-100kW Li-ion installations for storing energy at electric vehicle (EV) charging stations. It is expected that these applications will continue to be the primary focus of EES in the Netherlands.
Similar to Italy, the Dutch rely heavily on natural gas for energy within their homes. This fact, coupled with an ever-increasing focus on energy independent and efficient houses could make the Netherlands a prime market for residential power-to-gas technologies.
Hurry up while stocks last, you may want to add. Carbon dioxide (CO2) is a waste product from the combustion of fossil fuels such as oil, gas and coal. It is almost worthless because it finds little use. However, technologies such as power-to-gas or electrosynthesis of methanol are able to convert CO2 directly into a valuable, albeit cheap, product. This increases the commercial interest in CO2 and ultimately the filtering from the air becomes economically interesting. That is, filtering CO2 from the air is now more than just an expensive strategy to fight global warming. Recently, a detailed economic analysis has been published in the journal Joule, which suggests that this filter technology could soon become a viable reality.
The study was published by the engineers of the Canadian company Carbon Engineering in Calgary, Canada. Since 2015, the company has been operating a pilot plant for CO2 extraction in British Columbia. This plant − based on a concept called Direct Air Capture (DAC) − formed the foundation for the presented economic analysis. It includes the costs from suppliers of all major components. According to the study, the cost of extracting a ton of CO2 from the air ranges from $94 to $232, depending on a variety of design options. The latest comprehensive analysis of DAC estimated $600 per tonne and was published by the American Physical Society in 2011.
In addition to Carbon Engineering, the Swiss company Climeworks also works on DAC in Zurich. There, the company has launched a commercial pilot that can absorb 900 tonnes of CO2 from the atmosphere every year for use in greenhouses. Climeworks has also opened a second plant in Iceland that can capture 50 tonnes of CO2 per year and bury it in subterranean basalt formations. According to Daniel Egger of Climeworks, capturing a ton of CO2 at their Swiss site costs about $600. He expect the number to fall below $100 per ton over the next five to ten years.
Technically, CO2 is dissolved in an alkaline solution of potassium hydroxide which reacts with CO2 to form potassium carbonate. After further processing, this becomes a solid residue of calcium carbonate, which releases the CO2 when heated. The CO2 could then be disposed of underground or used to make synthetic, CO2-neutral fuels. To accomplish this, Carbon Engineering has reduced the cost of its filtration plant to $94 per ton of CO2.
CO2-neutral fuel, from carbon dioxide captured from the air and electrolytic hydrogen.
Assuming, however, that CO2 is sequestered in rock, a price of $100 per ton would translate into 0.2 cent per liter gasoline. Ultimately, the economics of CO2 extraction depend on factors that vary by location, including the price of energy and whether or not a company can access government subsidies or a carbon trading market. But the cost per ton of DAC-CO2 is likely to remain above the real market price of CO2 in the near future. For example, emission certificates in the European Union’s trading system are around €16 per tonne of CO2. If CO2 extraction technology were to gain a foothold in markets where carbon can be sold at DAC price, then DAC would of course become economical. Conversion into useful products product such as plastic or fuel could help to include the DAC premium. Alberta seems a great location because its oil is of low quality and comes at high production costs. Moreover, the size of the DAC plant suggests this is done best in Canada, given the size of the country. Albertans may want to reconsider their business model.
At Frontis Energy, we are excited about this prospect. CO2 is accessible everywhere and DAC is helping us convert it into methane gas. Power-to-gas is perfect for this. However, there would still have something to happen. $100 per ton is already good (compared to $600), but to be able to economically place a product like methane on the market it should be more like $10 per tonne:
CO2 economy of power-to-gas with electrolytic hydrogen. Cal, California, EOR, enhanced oil recovery.
Sure, we always complain, but we still cannot wait to see how the price of DAC continues to fall and wish Carbon Engineering to Climeworks all the best. Keep it up!
In Paris, humanity has set itself the goal of limiting global warming to 1.5 °C. Most people believe that this will be accompanied by significant sacrifice of quality of life. That is one reason why climate protection is simply rejected by many people, even to the point of outright denial. At Frontis Energy, we think we can protect the climate and live better. The latest study published in Nature Energy by a research group around Arnulf Grubler of the International Institute for Applied Systems Analysis in Laxenburg, Austria, has now shown that we have good reasons.
The team used computer models to explore the potential of technological trends to reduce energy consumption. Among other things, the researchers said that the use of shared car services will increase and that fossil fuels will give way to solar energy and other forms of renewable energy. Their results show that global energy consumption would decrease by about 40% regardless of population, income, and economic growth. Air pollution and demand for biofuels would also decrease, which would improve health and food supplies.
In contrast to many previous assessments, the group’s findings suggest that humans can limit the temperature rise to 1.5 °C above preindustrial levels without resorting to drastic strategies to extract CO2 from the atmosphere later in the century.
Now, one can argue whether shared car services do not cut quality of life. Nevertheless, we think that individual mobility can be maintained while protecting our climate. CO2 recovery for the production of fuels (CO2 recycling that is) is such a possibility. The Power-to-Gas technology is the most advanced version of CO2 recycling and should certainly be considered in future studies. An example of such an assessment of the power-to-gas technology was published by a Swiss research group headed by Frédéric Meylan, who found that the carbon footprint can be neutralized with conventional technology after just a few cycles.
(Picture: Pieter Bruegel the Elder, The Land of Cockaigne, Wikipedia)
