What is the best technology to balance the variable output of wind and solar? When there is little wind and sun the plant must produce power to compensate. When there’s too much wind and sun it must utilise that excess power. In other words, given the high capital cost of the new balancing technology it must do both profitably enough to cover the time sitting idle. A paper co-authored by Schalk Cloete looks at Gas Switching Reforming (GSR). The GSR plant (using natural gas, capturing the CO2) makes hydrogen, burnt to produce power for the grid, or sold on the open market. Here Cloete summarises the findings. Various scenarios are modelled – including one where no carbon capture (CCS) technology is available – to find the optimal mix of technologies for the whole system, including onshore wind, solar PV, natural gas combined cycle (NGCC), advanced ultra-supercritical coal (AUSC), NGCC + AUSC with CCS, open cycle gas turbine (OCGT), hydrogen fired combined and open cycle power plants, lithium-ion batteries, and polymer electrolyte membrane (PEM) electrolysis. Carbon tax assumptions are then layered on. A sensitivity analysis factors in price/cost uncertainties + nuclear + the discount rate. The models show that GSR can be a game-changing technology.
Introduction
The impressive cost reductions of wind and solar energy have prompted a lot of research into ways to balance their variable power output. A major challenge with any balancing mechanism is that it must necessarily be used at a low utilisation rate (capacity factor) because it should either:
- Produce power mostly when there is little wind and sun
- Consume or transmit power mostly when there is a lot of wind and sun
The inherent capacity under-utilisation involved in any mechanism required to balance variable renewable energy (VRE) places great emphasis on capital cost. When a reasonable discount rate (time-value of money) is applied, capacity under-utilisation becomes very costly even for mild capital costs.
This is a particularly important challenge for low-carbon power plants like nuclear, coal or gas with CCS, and biomass. All these options have high up-front costs and need to be run at the highest possible capacity factor to give an attractive rate of return. If they must be used at a low capacity factor to balance wind and solar, the cost of the entire system increases sharply.
The challenge of such capacity under-utilisation inspired our recent peer-reviewed study (open access) in the journal “Energy” that investigates a CCS power and hydrogen plant, especially designed to mitigate this fundamental challenge. This article summarises our main findings.
Flexible power and hydrogen production
The technology investigated in our paper is called Gas Switching Reforming (GSR). This technology reforms natural gas in much the same way as the steam methane reforming technology used for most global hydrogen production today. The primary difference is that all CO2 emissions are inherently separated by the process as shown in the orange blocks below.
The produced syngas is then put through conventional water-gas shift and pressure swing adsorption units to produce pure hydrogen. Flexibility is possible because this hydrogen can either be combusted to produce power during times of low VRE output or directly sold to the market during times of high VRE output (the green diamond in the figure below).
From the point of view of capacity utilisation, this arrangement ensures high utilisation of all process equipment shown in the figure, except for the power cycle (which is generally quite cheap). In addition, high utilisation rates of the downstream CO2 transport and storage infrastructure is also ensured. In this way, the GSR technology can produce flexible low-carbon power, while minimising the important challenge of capacity under-utilisation.
Power system modelling: GSR + other technologies
To quantify this system benefit, the GSR technology was implemented in a power system model next to a range of other technologies including: onshore wind, solar PV, natural gas combined cycle (NGCC), advanced ultra-supercritical coal (AUSC), NGCC and AUSC with CCS, open cycle gas turbine (OCGT), hydrogen fired combined and open cycle power plants, lithium-ion batteries, and polymer electrolyte membrane (PEM) electrolysis.
The power system model optimises investment and hourly dispatch of all these technologies, given hourly load and VRE availability factors, cost data for each technology, and CO2 emissions tax assumptions. The result is the technology mix that will result in the lowest total system cost.
Technology costs and performance data were selected to be representative of the year 2040.
Main findings
Simulations were completed based on three main technology availability scenarios:
- A scenario where no CCS was allowed (NoCCS)
- A scenario where conventional CCS from NGCC and AUSC plants is allowed (CCS)
- A scenario where the GSR technology is also included (AllTech)
Technology mix
When a CO2 price of €100/ton was considered, the following optimal capacity and generation mix was deployed:
As shown above, the NoCCS scenario deployed considerable unabated NGCC (natural gas) capacity to balance VRE, resulting in significant CO2 emissions.
In the CCS scenario, most of these emissions were avoided by deployment of NGCC-CCS plants, but the VRE share decreased substantially. This happens because CCS power plants (in addition to CO2 transport and storage infrastructure) are more capital intensive, so it is more economically efficient to operate them at high capacity factors than to balance low-cost wind and solar power.
In the AllTech scenario, GSR displaces all NGCC-CCS plants. In addition, VRE market share increases significantly relative to the CCS scenario. This is due to the more cost-effective flexibility allowed by the flexible power and hydrogen production from the GSR technology.
Specifically, GSR operates at its maximum allowable capacity factor of 90%, but it is only producing power for about half of that time to balance wind and solar. For the other half of time, it is producing hydrogen at a highly competitive sales price of €1.67/kg.
Scenario performance
The performance of each scenario was quantified by carrying out simulations at different CO2 prices. Four important system performance indicators are shown below over a wide range of CO2 prices.
When looking at CO2 emissions intensity, all three scenarios achieve a sharp reduction when the CO2 price is increased from 20 to 40 €/ton. This is the range of CO2 prices when natural gas displaces coal (as is currently happening in Europe, thanks to the ETS).
Beyond this point, the scenarios diverge. The NoCCS scenario slowly reduces emissions with higher CO2 prices by displacing more unabated NGCC power plants with wind and solar. However, this results in a gradual increase in the system cost of electricity.
A small amount of clean hydrogen production from electrolysis becomes economical at a CO2 price of €160/ton in the NoCCS scenario. When the CO2 price reaches €260/ton, all remaining NGCC plants are replaced by hydrogen combined cycle plants to eliminate all CO2 emissions. However, this requires substantial imports of clean hydrogen.
The AllTech scenario, on the other hand, manages to eliminate almost all CO2 emissions at a CO2 price of only €60/ton. It also produces a large amount of clean hydrogen, equivalent to almost 90% of total electricity demand in energy value, which can be used to decarbonize sectors other than electricity.
The CCS scenario falls in-between the NoCCS and AllTech scenarios when it comes to emissions and costs. As explained earlier, it deploys less VRE because conventional CCS operates best as baseload capacity. The relatively low VRE share also means that electrolysis is not part of the optimal energy mix in the CCS scenario.
Sensitivity analysis – dealing with uncertainties
There are many uncertainties in such a modelling study. Therefore, the optimal technology mix in the AllTech scenario at a CO2 price of €100/ton was evaluated over a range of different uncertain modelling assumptions. The results are shown below.
Since GSR runs on natural gas, the natural gas price has a large influence. At low prices (representative of the US or Middle East), GSR is responsible for all generation in the optimal mix. At high prices (e.g. Japan), some GSR is displaced with coal plants with CCS (AUSC-CCS).
The hydrogen sales price is another important parameter for GSR. When H2 prices are low, it is not profitable for GSR to export hydrogen. In these cases, it acts like a normal power plant with CCS that must operate at high capacity factors, reducing the optimal VRE share. Higher hydrogen prices allow for flexible operation of GSR, bringing more wind and solar into the optimal energy mix.
The potential of GSR cost escalations was also considered. In the base case, GSR has slightly higher capital costs than NGCC with CCS. If GSR costs increase further, it is gradually displaced by NGCC-CCS plants with an associated reduction in VRE market share.
Further cost reductions of wind and solar power increase the optimal share of these technologies, while the introduction of some nuclear power mainly displaces GSR generation thanks to the ability of GSR to offer cost-effective flexibility.
A higher discount rate increases the amount of GSR relative to wind and solar because GSR is less capital intensive. The high time-value of money in the developing world where the vast majority of future energy infrastructure will be built is one of the major challenges for the low system utilisation factors inherent to systems with high shares of VRE.
Conclusion
Flexible power and hydrogen production with CCS offers substantial benefits to a future energy system with high VRE shares. In addition, it produces large quantities of clean hydrogen to decarbonise sectors other than electricity.
The primary reason for this promising performance is the ability of such plants to use all the capital involved in CO2 capture, transport and storage at a high capacity factor, while varying power output to balance variable renewables.
When only conventional CCS is available, the optimal share of variable renewables falls significantly and the total system cost increases because conventional CCS plants function best as baseload generators.
A scenario without any CCS maintains a high share of unabated natural gas power plants in the optimal energy mix, even at high CO2 prices. This results in relatively high system costs and emissions.
Flexible power and hydrogen production with CCS is therefore a promising enabling technology for both VRE expansion and the hydrogen economy. The same philosophy can also be followed to design plants fuelled by coal or biomass, allowing for a more diverse mix of balancing fuels.
Further research is ongoing on this topic.
***
Schalk Cloete is a Research Scientist at Sintef
Rex Berglund says
Would be interesting to see the impact of the fugitive emissions from fracking on the total GHG emissions in these scenarios.
Schalk says
Yes, upstream emissions will be significant in any scenario that uses lots of natural gas. But there is plenty of scope for reducing upstream emissions at moderate cost. With the high greenhouse gas emissions taxes required for deep decarbonization, the fugitive emissions problem will probably diminish considerably.
S. Herbs says
This is interesting and I have also read the full article in Energy and recommend it. The combination of power (for VRE backup) and H2 production (for heating and industry) provides at least partial solutions for two weaknesses in the current German decarbonization plans. The realization is growing that imports of gas or liquid fuels will be necessary, and using existing natural gas pipelines almost certainly beats strings of ammonia tankers. The fugitive emissions problem may also be more tractable when the methane production and consumption are both well concentrated (Siberian gas fields as opposed to fracking in Texas or Pennsylvania, and 100 MW GSR facilities, respectively).
I do not have an idea what CCS on the scale of current natural gas consumption would require for infrastructure and how, in the case of Europe, it matches to the capacity available in North Sea reservoirs. At least for now it looks that onshore CCS is politically out of bounds; one might then wonder where to ship CO2 from a GSR plant in Bavaria.
Schalk says
Thanks for giving our paper a read!
Yes, public resistance to CO2 transport and storage is an important issue. But one should keep in mind that electricity and hydrogen transport and storage as well as wind and solar plants could become considerably more intrusive at the scales required for deep decarbonization of all sectors, particularly if CCS is not available. As the energy transition proceeds, these realities will gradually dawn on the public, and it will be interesting to see their reaction.
Depending on whether the public is more concerned about hydrogen or CO2 pipelines, one can choose to either locate CCS plants close to demand centers (in which case there is a need for long CO2 pipelines) or close to CO2 storage sites (in which case there is a need for long H2 pipelines). Of course, initial plants will be constructed at locations close to both CO2 storage and hydrogen demand (e.g. coastal industrial clusters).
Bas Gresnigt says
In NL underground CO2 storage became a no go due to public resistance. Even a small trial at our huge industrial / harbor center (Botlek) met killing resistance.
People knew what happened with that lake in Africa…
Assurances that such couldn’t occur with the trial, met references to nuclear power reactors which wouldn’t explode (chance <1 in a million years) while in reality ~1% exploded already creating more (financial & health) damage than ever imagined.
Only offshore storage has a chance. But still, a company doesn't enhance its name among the public doing that. What about fancy stories of dying fish due to escaping CO2…
Underground H2 storage has a good chance as one can convincingly show that the escaping gas will go straight up, creating little or no damage.
So present concentration of efforts to reduce the costs of PtG(H2), etc. seems to me the path with most chance on success.
Schalk says
I agree that onshore CO2 storage in densely populated regions like the Netherlands probably won’t fly. But there are many other options in remote onshore locations and offshore. Let’s wait and see.
Yes, hydrogen’s low molar mass limits risk, but it remains a highly explosive gas (a spark will explode hydrogen anywhere between 4 and 75% concentration in air). The energy value of hydrogen that must be stored underground for seasonal storage purposes is immense and if even a fraction of this explodes, it will lead to a black swan scenario that dwarfs any nuclear disaster.
Imagine this scenario: a 10 TWh underground hydrogen storage site suffers a catastrophic failure in the middle of a thunderstorm. A massive cloud of hydrogen is released and ignited by lightning, instantly releasing the energy equivalent of over 500 Hiroshima nuclear bombs.
As all black swan scenarios, this is highly unlikely, but still possible. Nuclear accidents show us how a surprisingly large number of highly unlikely events can line up perfectly to cause a disaster. So, let’s also wait and see how this pans out.
Roger Arnold says
I wouldn’t be so quick to write off geological sequestration of CO2, even under many densely populated land regions. There are options than are not only safe, but are clearly and convincingly safe to all but the most obdurate ideological opponents.
I don’t know much about the geology of Europe, but I assume it’s not radically different than North America and much of the rest of the world. Which is to say, I assume there are extensive regions underlain by sedimentary rock down to a few kilometers. Sedimentary rocks are always porous to a degree, and the pore spaces of deep sedimentary rocks are invariably saturated with brine — or occasionally, under the right circumstances, a combination of brine, oil, and gas.
I can’t find the reference I once saw for the total volume of brine trapped in the pore spaces of deep sedimentary rocks, but it ran to millions of cubic kilometers. It was an appreciable fraction of the volume of the oceans — enough to dissolve far more CO2 than is present in the atmosphere. An absolutely safe way to sequester CO2 is therefore to pump brine from a deep saline aquifer, carbonate it under pressure, and then pump the carbonated solution back down via an injection well. There isn’t actually much pumping needed, as the carbonated brine will be heavier than the extracted brine. Gravity will do most of the work.
The injection well should be located some distance from the extraction well. Operation gradually replaces the native brine in a large volume of porous rock between the wells with brine containing dissolved CO2. It’s safe against escape of sequestered CO2 because the extracted brine is carbonated at the surface under controlled pressure. It’s controlled such that the partial pressure of CO2 in the reinjected brine will be less than the hydrostatic pressure at the injection depth. Bubbles of CO2 can’t form, and the gas is held in solution. The carbonated brine, being heavier than the native brine, can’t migrate upward to where bubbles of CO2 might form.
In principle, over thousands to millions of years, the CO2 could diffuse upward to the point that it could escape from solution. But the carbonated brine is acidic, and silicate minerals are basic. Long before any dissolved CO2 could diffuse upward to where reduced hydrostatic pressure would allow it to come out of solution, carbonic acid in the carbonated brine will react with metal silicates in the sedimentary rock grains. It will form stable carbonates and silica. The CO2 will be fully mineralized and immobilized.
This approach to geological sequestration is *not* the usual one considered for sequestration of CO2 in deep saline aquifers. What’s usually considered is injection of highly compressed CO2 directly into the saline aquifer. That’s cheaper and generally more practical. But it does result in bubbles of CO2 gas occupying pore space, and those bubbles *will* tend to migrate upward. So attention must be given to characteristics of the saline aquifer. Either there must be a sufficient thickness to the aquifer above the injection point that in the course of migrating upward, the CO2 bubbles will become fully dissolved, or the aquifer must lie below an impermeable cap layer.
There’s no shortage of deep saline aquifers that meet those criteria, but the ability of injected CO2 to migrate does provide an opening for opponents to question the safety. Brine extraction, carbonation, and reinjection eliminate that opening.
Aside from being a sop to the paranoid, the approach does have some offsetting advantages of its own. Coming from a couple of kilometers down, the extracted brine will be seriously warm. Probably not hot enough for geothermal power generation, but easily enough for space heating of buildings. In addition, the brine will be rich in dissolved minerals, some with commercial value.
Schalk says
OK, that is an interesting option. I guess the expensive part can be the brine-CO2 contactor if the carbonation reaction is quite slow. I certainly agree that turning CO2 into an even lower energy compound is a completely safe way of sequestration. It just needs to be economical.
Bas Gresnigt says
Hydrogen burns very easy but doesn’t explode. Check the Hindenburg accident.
If there is a way out the hydrogen will escape and move fast to the stratosfeer because it weights far less than air.
With tbe strong winds it will spread all over the globe.
Schalk says
Hydrogen can certainly explode when pre-mixed with air before ignition (as would be the case here). With such an abrupt release of a massive H2 cloud, there will certainly be large parts of this cloud that contains H2 mixed in the right proportion with air to form an explosive mixture.
We’re actually working on building some demonstration projects for our hydrogen production concepts, and you should see the amount of effort that must go into hydrogen safety for preventing explosions even just for a small demonstration plant. I don’t want to know how the safety procedures will look for a storage facility housing hundreds of nuclear bombs worth of hydrogen energy…
Storing large quantities of high-grade energy has inherent risks that are starting to be experienced (https://www.greentechmedia.com/articles/read/the-safety-question-persists-for-energy-storage). As this currently tiny industry scales up, incidents should become less frequent, but potentially larger as the size of storage facilities increase. Let’s see what happens.
Bas Gresnigt says
There is no risk that the hydrogen mixes with air as it is stored under high pressure in the deep underground (e.g. 500meter below surface). Even when the valve on top of the pipe/jacket from/towards the underground store is destroyed by a bomb, no disaster will happen.
While burning the moment the hydrogen comes above the ground, it will escape with high speed upwards towards the stratosfeer…
In NL we store a winter supply of conditioned natural gas under high pressure in salt domes ~500m below the surface. Hence we can apply less redundancy regarding the conditioning plants (when those explode, the valves of the underground stores can be opened and supply to users continue)…
Of course, when the salt is washed away it’s taken care that no oxygen will enter the dome but either an indifferent gas or directly hydrogen (if it’s an existing dome it will contain CH4, no serious problem).
Even when a little air/oxygen is left in the deep underground dome (due to negligence) and it explodes, little chance that it will lift the 500m layer of ground.
In Germany such trial is in preparation.
Schalk says
I must say, you sound a lot like a nuclear advocate listing all the reasons why modern nuclear plants cannot possibly explode 🙂
Again, the highly-unlikely-but-still-possible scenario I’m describing is one where a massive failure in the geological storage structure instantaneously releases a huge cloud of hydrogen into the atmosphere (similar to the failure that would be needed to release a massive suffocating CO2 cloud from a CO2 storage site). This cloud will mix with air and large parts of it will be in the very wide hydrogen/air molar ratio range where the mixture is explosive, meaning that any spark will detonate a massive explosion in this huge premixed cloud.
Another terrifying scenario that just came to my mind is if terrorists take over a hydrogen storage site, pump down a large amount of air into the huge hydrogen storage site and ignite this pressurized explosive mixture…
Bas Gresnigt says
An H2 explosion needs a substantial ~20% to ~80% air/gas mixture. But that won’t occur as the escaping hydrogen moves very fast up into the air. The outside of the H2 flow will burn (which increases the upwards speed).
Your last scenario is possible, also now with the stored conditioned natural gas.
However such terrorists need to pump a lot of air 500m down unnoticed during at least some days in order to create an explosion with de power of a serious atomic bomb needed to shake / lift the 500m of earth.
Seems extremely difficult to me considering all the monitoring installed. But if substantial part of the monitoring staff of Gasunie is involved in the crime, it’s possible.
Roger Arnold says
Bas, I don’t know, but I suspect Schalk may be gently trolling you. I doubt that he’s seriously advancing the threat of huge explosions as a reason for rejecting hydrogen as a long term energy storage solution for a renewable energy economy. The point is that you’re willing to discount an improbable but potentially catastrophic threat from a system you approve of, while ringing alarm bells about equally improbable threats from systems you oppose.
In point of fact, the threat of a massive explosion from a large leak in a hydrogen storage facility is much more realistic concern than a nuclear explosion from a nuclear reactor accident. The former really could happen, while the latter is a physical impossibility.
A massive hydrogen leak, as you say, would send a plume of hydrogen rising upward into the atmosphere. But it would most definitely not be a neat column of hydrogen racing upward and separated from the air around it by a boundary layer of laminar flow. The entire flow would be extremely turbulent, and mixing would be very rapid. If nothing set it off earlier, it’s quite conceivable that a million cubic meter volume of mixed air and hydrogen could develop at an altitude of a few hundred meters.
The hydrogen storage facility does need to be designed to insure than an accident of that sort cannot occur. Just as a nuclear reactor needs to be designed so that it can’t melt down, and airplanes need to be designed so that they don’t regularly crash. Like it or not, it’s a fact of modern life that we’re very much dependent on competent engineers having done their jobs properly.
Bas Gresnigt says
Roger,
It’s difficult to create an explosion with gaseous escaping hydrogen. Far more difficult than with Natural Gas or LPG.
You can find video’s showing e.g. hydrogen escaping from a car tank (700ato), etc.
A thin flame going straight upwards. More safe for the people around than petrol.
Even the Hindenburg didn’t explode…
Other video’s show the limited risk of even liquid hydrogen, despite being that far more risky than the gaseous hydrogen stored 500m below the surface.
Nuclear
With ~400 reactors, we saw already 4 disastrous explosions resulting in major emissions of radio-active material which will result in the premature death of roughly a million people and probably even more handicapped newborn…
Roger Arnold says
Bas, I agree that hydrogen is safe in most cases. Safer in a car accident than gasoline, and safer in storage than natural gas or propane. Small leaks in an open space are no problem, as the hydrogen will mix and dissipate into the open air without a significant volume ever reaching levels at which the mix can detonate.
If the hydrogen ignites at or near the source of a leak, then you’ll have a hot invisible flame rising straight up, and not radiating much thermal energy to the surroundings. (Lot of UV radiation, however. And a plume temperature high enough to ignite anything combustible that the plume contacts.)
All that was not the point. The point was that in the case of a large leak — say a ruptured pipe from a large high pressure storage chamber — a large volume of mixed air and hydrogen at mixture ratios susceptible to detonation could theoretically form. And when that mixture did detonate, the result could — again theoretically — be similar to an aerial burst from a nuclear weapon.
There are ways to guarantee that that can’t happen. One would be to design the pipe system such that any escaping hydrogen would pick up nanoparticles that would autoignite on contact with oxygen. That would insure that the escaping hydrogen would burn immediately, and not accumulate in an air-hydrogen mix that could subsequently detonate. But that’s an engineering solution to a potential problem that needs to be thought about.
The explosions at Fukushima were in fact hydrogen gas explosions. The hydrogen was produced by the reaction of water and steam with the cladding of the overheated fuel elements after loss of cooling circulation. The hot steam and hydrogen were vented through pressure relief valves into a containment region that held a large volume of air. When enough hydrogen had mixed with the air to detonate, it did. Spectacular, but the amount of radiation released was actually small. Nothing approaching what was released by the graphite core fire in the Chernobyl accident.
Bas Gresnigt says
Despite the wind blowing ~95% of all airborne Fukushima radiation direct to the sea, the amount of escaped radiation which fell on the country was so much that it:
– created highly significant increased levels of perinatal deaths among 17million not evacuated Japanese; https://goo.gl/3HDGL1
– forced a large exclusion zone in which the radiation level is still too high;
– forced Japanese govt to increase allowable radiation for civil people towards 20mSv/a being the max that adult nuclear workers are allowed to receive (normal background radiation is 10 times smaller).
Note:
In NL any zone with increased radiation is forbidden for nuclear workers that are planning for a child. Because it’s clear that they then produce babies with increased impairment levels (sperm with increased genetic damage).
Roger Arnold says
This is an excellent and I think important study. I second S. Herb’s recommendation of the full peer-reviewed report. Thanks for making it open access.
One thing isn’t yet clear to me (admittedly after just a first quick read) is the transmission model / models that your study assumed. Transmission figures heavily into the duty cycle model for wind and solar resources. A major problem with the projections from some advocates for a 100% renewable energy economy is that they implicitly assume that low loss long distance power transmission is cheap and easy to implement. So if it’s calm and cloudy in one place, power can just be imported from some place where it isn’t. That’s of course far from the actual case, and I think popular awareness of the fact is slowly sinking in. But some level of transmission does exist, and it will affect the amount of hydrogen needed for backing generation.
Another way to reduce the amount of hydrogen consumed in backup generation is with batteries. Current storage batteries are efficient and affordable for time averaging at the one day level. Hydrogen-fueled backup will still be needed for more extended periods of low production from renewables, but batteries can substantially improve the duty cycle of electrolyzers. When surplus RE is available, the surplus can be split between battery charging and electrolysis. Then when the surplus turns to a deficit, battery discharge can be split between regular load and continued electrolysis. (That’s assuming the weather prediction is for RE production to resume before the battery capacity is depleted. If not, it’s more efficient to devote the available battery capacity to regular load.) The improved duty cycle for electrolysis under this strategy reduces its capital cost. It makes renewable hydrogen a bit more competitive.
Schalk says
Thanks Roger.
Yes, you picked up one of the main simplifying assumptions in this study: copperplate transmission. This assumption does make wind and solar look much more attractive. But on the other hand, we did use 2040 VRE costs from the IEA WEO that will likely prove too pessimistic, so these two assumptions will cancel out to some degree.
I’m currently working on a follow-up study where more details of the power and hydrogen transmission and distribution infrastructure is modeled. I also use more optimistic VRE costs. The conclusions are fairly similar to this one, although the flexibility benefits of hydrogen reduce significantly when its transmission and storage costs are included.
This study did include both batteries and electrolysis in the optimization, so the synergy you describe will be deployed when it is economically favorable. Such parallel deployment of batteries and electrolysis does take place in the NoCCS scenario at high CO2 prices, but no electrolysis is ever deployed in the scenarios with CCS.
Bas Gresnigt says
Hydrogen burns very easy but doesn’t explode. Check the Hindenburg accident.
If there is a way out the hydrogen will escape and move fast to the stratosfeer because it weights far less than air.
With tbe strong winds it will spread all over the globe.