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An Unlikely Clean Energy Combo: CCS and Variable Renewables

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The impressive cost reductions of wind and solar energy has generated great enthusiasm around the future of renewable energy, but their variable and non-dispatchable nature poses an important challenge.

A lot of research is ongoing to develop mechanisms for balancing the variable output of wind and solar power. Any such method must 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

For this reason, any mechanism for balancing variable renewable energy (VRE) inherently involves low utilization rates. And when a reasonable discount rate (time-value of money) is applied, capacity under-utilization becomes very costly even for mild capital costs.

This capacity under-utilization is a particularly important challenge for low-carbon power plants like nuclear, coal or gas with CO2 capture and storage (CCS), and biomass.

All these options have high up-front costs and need to be run at the highest possible utilization rate (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-utilization 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 summarizes 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 to syngas and separates out hydrogen 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.

Flexibility is possible because the produced 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 above).

From the point of view of capacity utilization, this arrangement ensures high utilization of all process equipment shown in the figure, except for the power cycle (which is generally quite cheap). In addition, high utilization rates of the downstream CO2 transport and storage infrastructure is also ensured.

In this way, the GSR technology can produce flexible low-carbon power for balancing renewables, while minimizing the important challenge of capacity under-utilization.

Power system modeling

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 (AUSC) coal, 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 optimizes 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 main 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:

  1. A scenario where no CCS is allowed (NoCCS)
  2. A scenario where conventional CCS from NGCC and AUSC plants is allowed (CCS)
  3. A scenario where the GSR technology is also included (AllTech)

Optimal technology mix

When a CO2 price of €100/ton was considered, the following optimal capacity and generation mix was deployed:

The NoCCS scenario deployed considerable unabated NGCC (natural gas) capacity to balance VRE, resulting in significant CO2 emissions.

There will always be long periods without wind and sun, and natural gas-fired power plants are the most cost-effective option for powering the economy during these times.

In the CCS scenario, most CO2 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 its operating 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

There are many uncertainties in such a modeling 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 modeling 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 utilization factors inherent in systems with high shares of VRE.


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 decarbonize 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.

This is the original version of an article recently published on Energy Post.

Schalk Cloete's picture

Thank Schalk for the Post!

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Matt Chester's picture
Matt Chester on Mar 11, 2020 9:19 pm GMT

while the introduction of some nuclear power mainly displaces GSR generation thanks to the ability of GSR to offer cost-effective flexibility

Gas is definitely the elephant in the room when it comes to the future of decarbonization-- but I'd be curious to hear more about why nuclear can only displace GSR and not a wider base of gas, particularly if paired with hydrogen production to prevent the costly ramp up and down based on demand?

Schalk Cloete's picture
Schalk Cloete on Mar 14, 2020 8:18 am GMT

Due to the political challenges facing nuclear, we only included it in the sensitivity analysis (which was done just for the AllTech scenario). 

Nuclear actually does well in such simulations when included n a technology-neutral energy mix, but we respected the strong political constraints on nuclear and therefore excluded it in most model runs. 

Matt Chester's picture
Matt Chester on Mar 16, 2020 1:04 pm GMT

we respected the strong political constraints on nuclear and therefore excluded it in most model runs. 

That's definitely fair enough in terms of addressing the discourse and short-term realities in the energy sector. Though in any wide-ranging discussion of what the future can and perhaps should hold, confronting the disconnect with those political constraints and what may be the best solution will surely be critical!

William Hughes-Games's picture
William Hughes-Games on Mar 13, 2020 7:10 pm GMT

I was under the impression that this angst about producing power when it is not needed and needing power when it is not being produced by your wind turbines or solar panels was history following the demonstration of the incredible profitability of the Australian (Tesla) mega battery.  It is on track to earn revenue equal to it's total capital cost in a tad over 3 years.  Who has ever heard of a return on investment of this magnitude.  The cherry on the top was the vast improvement in the quality of the electricity with both voltage and signal fidelity.

If one adds such measures as graded pricing with demand balancing rather than the present supply balancing and we have entered a completely new paradigm.

By the by, wind and solar are cheaper than nuclear so it is a non starter.

As for carbon capture.  Go into pyrolysis.

Roger Arnold's picture
Roger Arnold on Mar 14, 2020 4:23 am GMT

No, the Tesla mega battery in Australia has been a great success, but it has by no means laid to rest all issues around intermittency of renewables. It has made the Hornsdale wind farm in southern Australia a "good citizen" on the power grid. It has made dispatch operations much easier to manage by buying time for orderly ramp-up and shut-down of coal-fired capacity. But it only works because of that coal-fired capacity. That capacity may sit idle much of the time, but it's still available to fill in when needed.

The Hornsdale battery has only on the order of 1% of the storage capacity that would be required for Australia to move to 100% renewables.

Schalk Cloete's picture
Schalk Cloete on Mar 14, 2020 8:35 am GMT

Batteries were included in the study and you can see in the first graph that significant battery capacity is deployed in the cost-optimal mix in all three scenarios. Batteries are great for short-term balancing services, but quickly lose competitiveness for storage timescales longer than a couple of hours (for which there is great need at higher VRE market shares). 

A payback period of 3 years in the energy industry really is not so unusual. 

Demand-side response can certainly play a part, but there are all sorts of constraints there too. Using power mainly when the wind blows and the sun shines brings a long list of practical (inconvenience and ramp capabilties) and economic (capacity under-utilization) challenges. Although I'm sure it will play a role, I think many are overestimating the amount that will be technically and economically feasible. 

When accounting for the value declines, added grid costs, balancing costs and land constraints involved in VRE-dominated clean energy futures (not only electricity but also the 80% of final energy consumption that is not electricity), one finds that nuclear should certainly be kept on the table. 

Roger Arnold's picture
Roger Arnold on Mar 14, 2020 3:31 am GMT

A clear and excellent summary of the peer-reviewed study that you and Dr. Hirth conducted. That study, which you reference in this article, is open access and easy to follow. I recommend it to any readers here interested in more details.

I do have a couple of questions. There's a well known variation on SMR that produces relatively pure streams of hydrogen and carbon dioxide. It depends on an upstream air separation unit (ASU) to supply oxygen for the partial combustion of the methane feed. Partial combustion is used to supply heat for the endothermic steam reforming reaction. Your GSR process doesn't require an upstream ASU. Instead, it uses chemical looping process to extract oxygen from the air and subsequently deliver it for partial combustion of methane.

My main question is whether the GSR approach delivers advantages above and beyond replacing the need for an upstream ASU? If someone were to invent a cheap and effective way to supply pure oxygen to a steam reformer, would the cycling fluidized beds of your GSR units still offer practical advantages over the standard zero-emission variation of SMR?

The question isn't idle. I'm thinking of the oxygen co-stream from electrolytic production of hydrogen. In most "green hydrogen" proposals, the O2 stream is just vented. That's a waste of a valuable resource stream. One can imagine a complex that combines electrolytic production of hydrogen and oxygen, zero-emission SMR to produce additional hydrogen (with CCS on the CO2 stream), and a zero-emission Allam cycle power plant for balancing supply and demand.

Schalk Cloete's picture
Schalk Cloete on Mar 14, 2020 8:51 am GMT

I guess you refer to autothermal reforming (ATR)? An important reason why most H2 today is produced by SMR and not ATR is the synergystic integration of the PSA off-gas for supplying heat to the reforming reactions. This is an excellent use of a low-grade fuel you don't get from ATR, but you do get from GSR. In addition, GSR produces a relatively pure stream of hot N2 that can be used to improve power cycle efficiency in a flexible power and H2 plant like we looked at here. 

We actually looked at the potential to use O2 from electrolysis for oxycombustion applications a couple of years ago, but we discarded the possibilty after a few preliminary economic estimates. The value of the O2 is not high enough to justify the need to liquify and store it and use the balancing oxycombustion plant and downstream CO2 transport and storage infrastructure at a low capacity factor. 

William Hughes-Games's picture
William Hughes-Games on Mar 18, 2020 2:48 am GMT

I wonder if the power from a wind turbine could be used instead of oxygen to provide the heat for the process or would it simply be more energy efficient to simply use the electricity produced directly by the final user. 

Schalk Cloete's picture
Schalk Cloete on Mar 18, 2020 6:10 pm GMT

Yes, this looks like an interesting option if electricity is extremely cheap. The challenge is that the current integration of the process gets the heat by combusting a low-grade fuel coming directly from the process (PSA off-gas in the first figure in the article). If electricity is used to provide the heat, we don't have anything useful to do with this fuel, causing a substantial loss for the plant.

Roger Arnold's picture
Roger Arnold on Mar 19, 2020 8:05 pm GMT

The ideal reforming proces would seem to be the active membrane autothermal procss that CoorsTek announced a couple of years ago. It doesn't require a PSA step. Steam and natural gas are introduced into an active ceramic membrane tube in a high temperature environment. Voltage applied across the membrane actively pumps hydrogen out of the tube. It's a driven equilibrium reaction. As hydrogen is actively removed, more of the steam and methane shift to H2 and CO2. There is ohmic resistance to the proton current through the membrane, but the resistive heating serves to supply heat to the endothermic reforming reaction. Overall efficiency is close to 100%.

Papers on the process were published a couple of years ago, but I don't have the references at hand. I remember calculating that the process would produce about six times more hydrogen per kWh than electrolysis.

The CoorsTek web site page on active ceramic membranes (here) has a PDF infographic that can be downloaded. The process is pitched for home hydrogen refueling stations for fuel cell vehicles. That market has yet to develop. But if the process is as good as the initial publications describe, I would have exptected it to quickly be taken up for industrial reforming. I haven't seen any evidence of that, however, and I haven't been able to find out anything about the current state of commercialization. My guess is that the active membranes are either very expensive to produce or have short working lifetimes. Or some combination of the two sufficient to negate the theoretical advantages.

If anyone knows about that, I'd love to hear from them.

Mark Silverstone's picture
Mark Silverstone on Mar 14, 2020 12:23 pm GMT

Thanks to the authors and to Mr. Arnold for the link to the original paper.

So much hinges on CO2 charges/taxes.  I believe $US 100/tonne CO2 translates to about $US 0.89 per gallon, not very large, especially considering today´s prices. But Figure 4 in the paper indicates that large reductions in CO2 emissions can be achieved with little more than Euros 60 per tonne.

I am not clear on just how feasible the technological part of this proposal is. I think the CCS part is feasible.  It certainly will require massive change in people´s choices and infrastructure development in favor of electricity or hydrogen transport. But, mandating it for heavy transport is much more doable in the shorter run.

There is the risk of committing to a great deal of effort to make this possible, only to be rendered obsolete by developing cheaper and simpler battery storage. But it certainly beats the risk of doing nothing, or committing to nuclear.

From a political point of view, it is harder. But, I do not think it is at all impossible.


Matt Chester's picture
Matt Chester on Mar 16, 2020 1:08 pm GMT

It certainly will require massive change in people´s choices and infrastructure development in favor of electricity or hydrogen transport. But, mandating it for heavy transport is much more doable in the shorter run.

I'd love to see government fleets (federal, state, and municipalities) lead the way with this regard-- the market for such infrastructure that gets created as these critical fleets move away from ICE and then it reduces the friction for more industries and groups of personal vehicles for making such a switch

Schalk Cloete's picture
Schalk Cloete on Mar 16, 2020 6:44 pm GMT

I don't think batteries will ever become cheap enough to balance variable renewables over timescales of days and weeks. The main competition for the GSR technology is electrolysis.

Yes, the transportation sector will be much tougher to decarbonize than the power sector. But we should keep in mind that CO2 prices will probably rise well above the €60/ton mentioned in the article to incentivise a rapid transition, which will also help decarbonize transport. 

I deeply dislike mandates, which are highly economically inefficient. Let's hope it does not come to that. 

Roger Arnold's picture
Roger Arnold on Mar 15, 2020 5:56 am GMT


I'm not sure now just what type of reforming process I was referring to. In 2005, I did a semi-deep dive into SMR technologies in connection with an article I was writing about GTL. (The article, Will GTL Nail the Coffin Lid on Cheap NG, is comically outdated now. At the time I wrote it, the fracking revolution had not yet arrived; NG production was flagging, prices were soaring, and chemical plants that required cheap NG were moving offshore.) The reforming approach I was referring to above was one I recall from that research. I know it used oxygen from an ASU to burn methane to supply heat for the endothermic reforming reaction. I thoght I recalled that the oxygen was fed in a sub-stoichiometric mix with the methane feed (partial combustion), but it could have been used for oxy-fueled combustion in the burners of an otherwise conventional tubular SMR reactor.

Whatever it was, it was being used at multiple hydrogen production facilities that fed high grade CO2 streams to the pipeline network that supports EOR operations in (mostly, I think) the Permian Basin region of Texas. Unfortunatly, I don't have / can't find notes from that research. A quick google search didn't turn up any SMR variation that exactly matched what I thought I recalled. But thanks for answering my question about further advantages of GSR process.

You commented that

We actually looked at the potential to use O2 from electrolysis for oxycombustion applications a couple of years ago, but we discarded the possibilty after a few preliminary economic estimates. The value of the O2 is not high enough to justify the need to liquify and store it and use the balancing oxycombustion plant and downstream CO2 transport and storage infrastructure at a low capacity factor.

In the process I was thinking of for utilizing the oxygen stream for an Allam cycle load balancing plant, there is no need to liquify and store O2. Hydrogen is stored or withdrawn from storage as needed, but oxygen for the Allam cycle power plant is used immediately as it's produced.

Both the Allam cycle plant and the electrolyzers are throttleabe, but both operate with good capacity factors. In the worst case "dunkelflaute" mode (extended period of dark and calm weather, hydrogen store depleted), sufficient power from the Allam cycle plant is diverted to the electrolyzers to produce enough oxygen to run the power plant full out. Some of the hydrogen output from the electrolyzers is fed into hydrogen fuel cells or combustion turbines to make up for power diverted to the electrolyzers. The rest goes into the depleted hydrogen store.

There are a lot of parameters available for balancing in this system, and a lot of scope for optimizing the settings for conditions prevailing moment to moment. Overall, however, it reduces the hydrogen storage requirement for seasonal energy storage. It looks to me like it also results in good utiliization of capital equipment.

Schalk Cloete's picture
Schalk Cloete on Mar 16, 2020 6:56 pm GMT

The challenge is that the oxygen is produced at times when the electrolysers are running (low power prices) and the Allam cycle is ramped down. Thus the oxygen must be stored until the power price ramps up again. The fact that this strategy will produce an interemittent CO2 stream is another technical and economic challenge for CO2 transport and storage. 

Running electrolysers during times of expensive electricity primarily to produce oxygen for an oxyfuel plant and hydrogen for fuel cells sounds extremely expensive. A highly efficient electrolyser coupled to a highly efficient fuel cell will produce less than 0.5 units of electricity for every unit of electricity consumed by the electrolyser, effectively consuming a lot of power. A conventional ASU will be much more economical in this scenario.  

Roger Arnold's picture
Roger Arnold on Mar 16, 2020 11:28 pm GMT

Yes, the oxygen is produced at times when the electrolysers are running, but I don't think it follows that the Allam cycle plant would necessarily be ramped down. Running the Allam cycle plant in parallel with the electrolysers means that there is more excess power to feed to the electrolysers. It lowers the threshold for the switch between generating power from stored hydrogen and producing hydrogen. It should allow the overall system to operate with less VRE over-capacity and a smaller hydrogen store.

Admittedly, an oxygen store would increase flexibility. Depending on the spedific capital costs of the various potential components -- electrolysers, ASU, hydrogen store, oxygen store, allam cycle turbine, hydrogen fuel cells, and hydrogen gas turbine -- a configuration that included an oxygen store might optimise out better than one without.

It's not a simple problem. I'm pretty sure that a standalone electrolyser supplying oxygen to an Allam cycle turbine and hydrogen to a parallel hydrogen power system (with no VRE capacity) would be economically inferior to a straight Allam cycle plant with upstream ASU. Power loss in the P2G2P part of the system is too big a handicap. But if VRE and electrolysers are givens, then the analysis is different. The Allam cycle plant as an "amplifier" for power going into the electrolsers would seem to offer better overall ecconomics.

I could be wrong though. I don't have the data needed to model the system in enough detail to see how it optimizes.

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