Your questions answered: Carbon Capture & Storage

What’s in store? An expert panel answers your questions on the future of carbon capture and storage.


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Carbon capture and storage (CCS) is increasingly seen as a prerequisite to the continued use of fossil fuels. If you can’t prevent carbon dioxide (CO2) reaching the atmosphere, the argument goes, then you can’t burn the fuel. But CCS has still never been demonstrated at full scale and its costs are uncertain.

We invited readers to pose their questions on CCS to experts in industry and academia.

This selection of questions was answered by:

Tim Bertels (TB), manager of the CCS portfolio at Shell;
and Niall McDowell (NM) and Paul Fennell (PF) of the Energy Futures Laboratory at Imperial College London.

• What’s the parasitic load associated with the absorption, stripping, compression and transport of the recovered CO2 to storage and where will the additional power generation capacity come from? 


NM/PF: CCS plants require energy for flue gas fans, amine recirculation pumps, amine regeneration, CO2 compression, CO2 dehydration, auxiliaries, etc. The amount of energy needed is broadly equivalent to the tonnes of CO2 to be captured and compressed. The parasitic load, as loss in thermal efficiency, of specific power plants is dependent on the efficiency and CO2 intensity of the unabated plant; for example, a coal CCS plant needs to capture and store more
than twice the amount of CO2 per megawatt produced than a gas CCS plant.

Values of nine to 12 per cent/20 to 29 per cent for coal and six to 11 per cent/10 to 18 per cent for gas power have been reported for the net efficiency penalty (percentage lower heating value,
or LHV) and the relative decrease in efficiency (percentage).

This really depends on the material used, but on average a number of about 20 per cent is about right. So this means that if the power plant was 40 per cent efficient (in terms of conversion
of fuel energy to electrical energy) without CCS, it will be about 32 per cent efficient with CCS. This will be reduced as CCS technology improves. A reasonable aim would be to have technologies demonstrated at scale that halve the penalty by 2030.

• What is the main driver of private funding into CCS — concern for climate change or enhanced oil recovery (EOR)? If there was no gathering pressure under UNFCCC (especially Paris 2015) to drastically reduce CO2 emissions from all sources, would the petrol- and coal-based industries be putting any money into environmentally motivated CCS?

NM/PF: I think the main drivers for private funding are: (a) an interest in being an informed consumer/user of this technology in the event that a sufficiently high carbon price (or similar mechanism) is in place to incentivise its deployment; (b) an interest in opening this potentially lucrative market and being able to supply equipment; and also (c) EOR. However, as EOR is predicated on accessing the cheapest possible supply of CO2, one wouldn’t target power plant CCS
in the first instance, except in the absence of other options and with a very high oil price.

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• CCS is said to not be viable until there is a competitive price for carbon. What indications are you receiving from various governments that this situation will improve for you?

NM/PF: As academics, this doesn’t really affect us directly as the question is posed. However, the current carbon price floor in the UK in addition to the China-American deal in this space is cause for optimism.

 

• Once carbon is stored in geological formations, will it leak out? And if so, how long does stored carbon take to become harmless to the environment?

NM/PF: Assuming that the storage location has been properly chosen and managed, it is highly unlikely that it will ever leak out. Therefore, once it has been sequestered, it is essentially harmless.  The formations that we will be storing CO2 in are not ‘empty’; they are porous rocks, currently full of water. Once the CO2 dissolves into the water, it is no longer buoyant — so would tend to sink, not rise.

Finally, over the course of perhaps 1,000 years, the CO2 reacts with the rocks to form carbonate minerals — these are in general some of the most stable rocks there are. You might as well ask whether we are worried that the white cliffs of Dover (CaCO3) will spontaneously liberate the CO2 associated with them.

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• The carbons that we intend to capture are in the form of CO2 (mostly, I guess). Will the CCS cause imbalance in composition of atmosphere — i.e. reduction of some and increase of some?

NM/PF: No. It will prevent an increase in the amount of CO2.Essentially, some people worry that we will suck O2 out of the atmosphere with the CO2. Think of it this way: CO2 is 400ppm and O2 is 210,000ppm. If we burn enough carbon to increase the concentration of CO2 in the atmosphere to 500ppm (which is sufficient to raise global temperatures by 2°C), we drop the concentration of O2 to 209,900ppm (i.e. by 0.05 per cent) — hardly noticeable. In any case, the drop is a consequence of the combustion of the fossil fuel, not anything we do with the CO2 formed.

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• What is the monetary cost of CCS per megawatt-hour of electricity generated from coal, oil and gas?

TB: The short- and long-term per-megawatt-hour electricity cost of low-carbon fossil power from power plants where CCS is applied will be dependent on many factors — among others the capital and operational cost of both the power and the CCS parts of the plant.

First-of-a-kind-demonstration CCS plants will have higher costs than the anticipated costs of CCS plants in the commercial phase. Substantial cost reductions through learning curves when a large number of these plants will be built are probable — supported by the evidence from the multiple commercialisation of analogous technologies.

One UK-based source for both low-carbon fossil power costs and the sources for cost reduction upon commercialisation is the CCS cost reduction task force report, which builds on the regularly updated comprehensive DECC cost of generation studies. Both gas and coal power costs are reported. Oil power costs are less relevant, as the use of oil for power generation is very small in the EU. The report also shows the cost of CCS-per-megawatt-hour electricity as the additional costs of low-carbon fossil CCS power versus the unabated plant. At comparable plant utilisations, gas power generally has a lower additional per-megawatt-hour CCS costs as less CO2 needs to be captured and stored on a megawatt-hour basis.

NM/PF: Unfortunately, this doesn’t have a simple answer. The correct answer will ultimately depend on a lot of other factors external to this discussion (the price at which financing is available, for example). Current estimates put gas plus CCS at about €100/MWh and coal plus CCS at about €110/MWh.

• What is the monetary cost of CCS per tonne of CO2?


TB: The cost of CCS per tonne of CO2 is the difference between the per-megawatt-hour electricity cost of low-carbon fossil and the unabated power plants divided by the amount of CO2 captured and stored per megawatt-hour low-carbon fossil power produced.

Coal power generally has a lower-per-tonne-of-CO2 CCS cost with the economy of scale and higher CO2 concentrations in the flue gas. Analogous-to-Q6 first-of-a-kind CCS costs will be higher than commercial-phase CCS.

One source for future per-tonne-CO2 CCS costs are the Zero Emission Platform CCS cost studies.

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NM/PF: See above, but a reasonable cost might be £70 per tonne now, or £35 per tonne with newer technology. However, the important point is that the increase in cost of the overall electricity supply system to 2050 (assuming decarbonisation) is lower by a factor of two to three if CCS
is included. This is because it is necessary to build huge quantities of electricity storage for times when the wind is not blowing or the sun not shining. Fossil with CCS allows a cheaper overall supply system with guaranteed ability to respond to demand (and increasingly supply) variability.

• What are the methods used to separate the CO2 from nitrogen and unused oxygen?

TB: I assume you could use absorbants, or you can pressurise and cool the exhaust until the CO2 becomes a liquid. This means the CO2 is already under the pressure required for disposal, but the energy used to compress the nitrogen needs to be recovered — perhaps by improving the carnot efficiency of the generator. 


Current commercially available flue gas CO2 capture systems apply lean amine in absorber towers to selectively remove CO2 from the flue gas (which contains nitrogen and residual oxygen). CO2 is separated from the loaded amine in regeneration columns, after which the CO2 is compressed and dehydrated.

 The concepts of pressurising CO2-containing gases (such as flue gas) followed by partial expansion/cooling, to freeze out and separate CO2 as particles are progressed in different ‘cryogenic’ technologies in R&D programmes globally. Some examples are given in a recent DoE transformative CO2 capture technologies workshop, although alternative technologies are also progressed.

These technologies require energy to compress (and/or cool) the large flue gas streams, where expansion (and/or heat exchange) is applied in some to recover a part of this compression energy.

Both the compression of large flue gas streams and energy recovery will require equipment of substantial sizes. The carnot efficiency of coal and gas power generation technologies has been improved significantly over the past decades. Efficiency integration of amine and alternative technology CCS plants with the unabated power cycles is an option and has been studied in different programmes. All these ‘cryogenic’ technologies are at early demonstration phase (and thus not commercially available) and need development, scale-up and conformation of their capital and operating costs and energy penalty competitiveness versus commercially available technologies.

NM/PF: I think that this is a discussion about CO2 separation in post combustion, not oxyfuel. Hence there are a large number of technologies under trial, from scrubbing with liquid solvents to novel absorbent technologies.

• What are the most promising non-solvent absorption-based technologies for carbon capture (i.e. mineralisation, synthetic fuel production)?

TB: Alternative regenerative CO2 capture technologies (for CO2 storage) are being researched, next to the solvent-based ones. These are, among others, based on sorbents, membranes and cryogenics.

It is too early to tell which are the most promising ones and it’s likely different technologies may prove to be preferred for different applications such as coal and gas power plant retrofits or new-builds, hydrogen production plants, CO2-containing process streams, etc. As such, the development of a broad portfolio of technologies should be progressed.

Non-regenerative CO2 capture technologies such as mineralisation or synthetic fuels are different applications with different drivers. Mineralisation needs a large flow of solids per ton of CO2. Synthetic fuels from captured CO2 are technically feasible. However, it needs to be recognised that the process requires energy that will add substantial costs, especially when a low-carbon or renewables energy source is used. Furthermore, the captured CO2 will be released again during use of the fuel.

NM/PF: Mineral carbonation is a adsorption technology. It is the ultimate fate of the CO2 when injected into a saline aquifer (i.e. in CCS). Many people don’t consider it promising for CO2 capture owing to the vast amount of raw material (two to three times more rock than the amount of coal burned in a power station) that is required and that requires a significant amount of energy to grind it up. Synthetic fuels are not a CO2 capture technology, as once you’ve used the fuels the CO2 is then re-released to the atmosphere (you can either claim to have decarbonised a power station or your produced fuel — not both).

Essentially, why not charge an electric vehicle using decarbonised electricity — the CO2 never makes it into the atmosphere. Also, the efficiency losses in the system to convert CO2 to a fuel and then to use the fuel in an internal combustion engine mean this is a huge white elephant.

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• What are the prospects for CCS that can be retrofitted to existing power stations, rather than purpose-built plants with integrated CCS?

TB: Existing power stations can be retrofitted with post-combustion CCS on their flue gas. Often the steam and power needed to run the capture plant can be drawn from the
power plant utilities system. The scope and complexity (and thus costs) of the retrofit will be dependent on the state and the CCS readiness level of the power plant. CCS readiness can be defined at different levels with available plot space, installed tie-ins, CO2 pipeline corridor, etc. It is probable that it will not be attractive to retrofit old coal plants with lower efficiency and a limited residual technical or economic life.

NM/PF: Post-combustion options are best here — amine scrubbing or calcium looping, for example.

• Given the timescales that are demanded by international agreements, is it your impression that markets such as India and China will look to the west to buy technology; or will they develop their own, and even license it back to Europe and the US?

TB: This will depend on which countries progress first and fastest in demonstrating CCS at scale in real projects. In any case, the position of CCS markets such as India and China (currently not in the same stage of CCS demonstration) will change over time; it is likely that in the first instance, for the first set of large-scale full-value chain demonstration projects, India and probably China will look to buy technology from countries (and companies) that are more advanced in developing and demonstrating CCS technology.

Over time, this may change if markets such as India, and especially China, and potentially also other developing countries, would have accelerated their in-country CCS technology demonstration and development and would become exporters of novel CCS (capture) technologies. For example, Europe — with the exception of the UK and Norway — is currently lagging on CCS demonstration.

NM/PF: In the near term, the technology development seems to be mostly led by western companies, in addition to some organisations in South Korea and Japan. In the longer term, bearing in mind that this technology will be used until at least the end of the century, it seems inevitable that Asia’s manufacturing base will begin to play a larger role. We are starting already to lose our position as leaders, as other countries begin to take notice of climate change.

• Which has greater potential: pre- or post-combustion CCS?

TB: With the differences in CO2 sources in different industries and CCS on existing and new-build, it is probable that the different CCS technologies will develop and find their place. Specifically, post-combustion will be suited to retrofits and pre-combustion may have its place in low-carbon hydrogen production.

NM/PF: It depends on the timescale and the particular niche. In the short to medium term, it would appear that post-combustion technologies are more viable than pre-combustion technologies. It doesn’t do to forget about oxyfuel combustion options either.

• What’s the current biggest roadblock to CCS implementation, and how might this be overcome?

TB: CCS is a combination of technologies deployed solely for climate change purposes and — with reference to question three — CCS won’t really be viable until there is a competitive penalty
for carbon emissions or a price on low-carbon products produced with CCS (electricity, among others). The absence of either of these in most countries is the biggest roadblock to implementation of CCS at scale.

NM/PF: Financing the projects, and here the most important thing is credible, long-term commitment from government. Also, misguided opposition from some environmental organisations