Carbon capture and storage (CCS) facilities coupled to existing plants provide a climate change mitigation strategy that potentially permits the continued use of fossil fuels whilst reducing the carbon dioxide (CO2) emissions. Potential design routes for the capture, transport and storage of CO2 from United Kingdom (UK) power plants are examined, Indicative costs discussed and a review of uk carbon capture and storage is discussed in this post

Why do we need CCS?

Energy systems pervade industrial societies and weave a complex web of interactions that affect the daily lives of their citizens. Human development is therefore heated and powered by energy sources of various kinds, but these put at risk the quality and longer-term viability of the biosphere as a result of unwanted, ‘second order’ effects. Many of such adverse consequences of energy production and consumption give rise to resource uncertainties and potential environmental hazards on a local, regional and global scale. Global warming, predominately caused by the enhanced ‘greenhouse effect’ from combustion-generated pollutants, is viewed by many as the most serious of the planetary-scale environmental impacts. Carbon dioxide (CO2) – the main greenhouse gas (GHG) – is thought to have a ‘residence time’ in the atmosphere of around one hundred years. CO2 accounts for some 80% of the total GHG emissions, for example, in the United Kingdom and the energy sector is responsible for around 95% of these.

The emphasis of energy strategies around the world has consequently been on so-called ‘low or zero carbon’ (LZC) energy options: energy efficiency improvements and demand reduction measures, fossil fuelled power stations with carbon capture and storage (CCS), combined heat and power (CHP) plants, nuclear power, and renewable energy systems.

The British Government has set a challenging, legally binding target of reducing the nation’s CO2 emissions overall by 80% by 2050 (in comparison to a 1990 baseline) in their 2008 Climate Change Act. This provides the basis for the adoption of LZC energy options in the UK. Coal, one of the world’s most abundant fossil fuel sources, currently meets about 23% of the total world primary energy demand, some 38% of global electricity generation. It is an important input, for example, in steel production via the basic oxygen furnace process that produces approximately 70% of world steel output. But tougher environmental/climate change regulations mean that coal will have to reduce its environmental impact if it is to remain a significant energy source. CO2 capture and storage facilities coupled to coal-fired power plants therefore provide a climate change mitigation strategy that potentially permits the continued use of coal resources, whilst reducing the CO2 emissions. The CCS process involves three basic stages: capture and compression of CO2 from power stations, transport of CO2, and storage away from the atmosphere for hundreds to thousands of years. The principle of the various capture methods is that the CO2 is removed from other waste products so it can be compressed and transported for storage. Transport of the CO2 can be by ship or by pipeline

Grab it – CO2 Capture

There are three main methods for capturing the carbon dioxide from coal-fired power stations: post-combustion capture, pre-combustion capture, and oxy-fuel combustion capture. These three generic ‘routes’ all involve the process of removing CO2 from point-source gas streams, and this can be done in a number of ways. Technical and cost data associated with these routes have been described in the Intergovernmental Panel on Climate Change (IPCC) Special Report on CCS . They suggested that around 90% of operational carbon emissions can be captured; albeit with an energy penalty of about 16% and rises by some 140% in ‘cost of electricity’ (COE) compared with a Pulverised Coal reference plant. Kleijn et al have also recently found that power plant CCS are substantially more metal intensive than existing electricity generators. There are five main technologies to remove CO2 from a gas stream that are available for use in CCS, and the pressure, temperature and concentration of CO2 in the flue gas stream will determine which is best suited to a given process. The five technologies are:

  1. Chemical Solvents
  2. Physical Solvents
  3. Adsorption/Desorption
  4. Membrane Separation
  5. Cryogenic Separation

The method of post-combustion capture (or ‘flue gas scrubbing’) is currently the most developed and popular technique employed in industry for capturing CO2 from the exhaust gases of fossil fuel combustion. It can be retrofitted at relatively low cost to existing power stations and allows the combustion process to be kept relatively unchanged. The coal is burnt in a conventional combustion chamber, and then the exhaust gases are passed through a particle removal chamber that separates out ash and smoke particles. After a sulphur removal stage, the flue gas is transferred into a CO2 absorption unit where a solvent absorbs the CO2. The CO2 that is collected by the stripper is then compressed and stored locally before being piped or shipped directly to its final storage location.

CCS in operation
Overview of carbon capture and storage

Tag it – CO2 Transport

The International Energy Agency (IEA) in their CCS ‘Technology Roadmap’ suggest that pipelines will be the main method for CO2 transportation with ships and trains being used in the short-term in some demonstration projects worldwide. Shipping becomes more economical than piping for the transport of CO2 over long distances (>1000 km). Liquefied CO2, which has similar properties to LPG, can be shipped overseas at a pressure of around 0.7 MPa on a commercially attractive basis.

The transportation of natural gas and other liquids and gases in the UK is well established, where natural gas and oil have been piped from the North Sea reservoirs since the early 1970s. Consequently, it may be possible to use the existing pipeline infrastructure in the UK operated by National Grid to reduce the investment required to set up a CO2 new network. However, existing oil and natural gas pipelines out into the North Sea are reaching the end of their engineering life, and were designed for rather different operating conditions. CO2 pipelines would therefore need to be designed to withstand high pressure, and the resultant risk of leaks that could arise. The CO2 behaves differently in various phases, and these can influence the development of corrosion in pipes. Thus, the pipe material would have to be carefully chosen and engineered to minimise the risk of pipeline failure, especially if the pipe is located on the ocean floor.

In the medium term, it is believed that the CO2 pipeline network would work most effectively with a number of onshore ‘hubs’ that would compress and clean the CO2 transported in smaller pipes from several power stations and industrial capture plants. At these hubs, the more highly compressed and cleaned CO2 would be transported through one or two larger, stronger pipes to its offshore storage reservoir. This would not only reduce costs in installation and the length of pipeline required, but would also allow for an interconnected system that could be shared. Such a network would have the potential to evolve into a network of pipes with redundancy and security should a leak or failure occur.

The CO2 transportation needs of the UK would benefit from the fact that its storage reservoirs in the North Sea are typically located only 200 or 300 km away from the power stations. Stakeholders feel that there are no long-term technical barriers to the development of a CO2 pipeline network in the UK. But a CO2 pipeline operator runs a significant financial risk, because of the high cost of the assets and low returns. Indeed, it has been suggested that the cost increase between a network and alternative transmission means could be as high as £3 per tonne ($4.5 or €4.0/tCO2)

Bag it – CO2 Storage

Naturally occurring geological formations provide potential locations for the storage of the captured CO2: oil or gas recovery, unmineable coal beds, saline aquifers, and depleted oil or gas fields. These are favoured because of the maturity of the technology involved. CO2 has been sequestered in geological formations, for example, for over 35 years in both Norway and the United States of America. Such permeable layers are typically found at least 800m below the ocean floor. The injection of CO2 into an oil reservoir mixes the gas with the crude oil and thins the resulting mixture. It is then easier to extract from the reservoir. These techniques are presently only employed in inshore applications, and therefore they appear to have very limited application on the UK continental shelf.

Enhanced Coal Bed Methane (ECBM) makes use of unmineable coal beds by injecting the CO2 into parts of a coal seam that are not reachable or economical. The main benefit of using this method is that a large number of coal beds in the UK that are not economical to mine. In addition, most coal beds contain vast trapped pockets of methane gas that can be displaced by the CO2 and captured, much like with the EGR method

A saline aquifer is an underground geological formation in which a large quantity of salt water has become trapped during the formation of the rock layers that surround it. The CO2 can be pumped down into the deep saline aquifers, where the CO2 will be stored in the natural gas pockets, where it will dissolve in the water to an extent. Saline aquifers are the most promising long- term CO2 storage globally according to the SRCC. There has been one major storage project undertaken in a saline formation in the Norwegian sector of the North Sea: the Sleipner field. Monitoring suggests that no CO2 has currently escaped. However, the monitoring of saline formations is a lot less well developed than in the case of oil and gas wells.

The final option for CO2 storage, and the one that is most attractive for UK, is to store it in geological formations that naturally occur under the seabed of the North Sea. The CO2 storage capacity in North Sea depleted oil and gas reservoirs is estimated to be around 10,190 MtCO2. This is equivalent to roughly 59 years of storage, based on 2008 CO2 emission data. This is complimented by a further 14,466 MtCO2 of storage capacity is available in UK saline aquifers. In contrast, the Scottish Centre for Carbon Storage estimated that total of up to 46,000 MtCO2 of storage capacity could be available in ten saline aquifers in and around Scotland. This would represent 266 years of UK storage requirements, based on UK CO2 emissions from power generation in 2008.

The UK in a prime position

The 2009 IEA roadmap for the implementation of CCS suggested a need for increased funding for demonstration projects of $3.5–4.0 billion (€2.6–3.0 bn) from 2010–2020. This would lead to the construction of around 100 large-scale demonstrators by 2020, which they believe should be increased to over 3000 projects. IEA analysis indicates that without CCS the overall costs of GHG mitigation over the period 2005–2050 would increase by 70%. This thinking was then fed into the considerations of the G8 group of industrialised countries at its 2010 Muskoka (Japan) Summit. Here the IEA worked jointly with the ‘Carbon Sequestration Leadership Forum’ and the ‘Global CCS Institute’. They noted that the deployment of large-scale CCS demonstration projects is critical to the deployment of the technology. Their progress review suggests that government and regional groups had made commitments to launch 19–43 such demonstrators by 2020. These developments were identified in the USA, the European Union (EU), ”particularly the United Kingdom”, Canada and Australia. But the partners noted that implementation of such a programme would be challenging.

The 2008 economic turndown, and the more recent Eurozone financial crisis, have both made the economic situation far more difficult in terms of potential public investments in large-scale energy projects of all kinds. Indeed, the APGTF believe that there is a global funding gap associated with the construction of CCS demonstrators by governments and industries of around €7–12 bn ($9.3–16 bn). The individual technological components of CCS have reached maturity within many industrialised countries, but end-to-end commercial scale demonstrators were slow to be begin operating in Britain.

The UK Climate Change Act of 2008 set the pace for implementing low carbon technologies generally, and the potential commercial development of CCS specifically. It was preceded a year earlier by the announcement of a UK Government competition to build a full- scale CCS demonstrator: so-called ‘Competition One’. This was aimed at tackling the shortcomings to CCS acceleration in Britain in order to eventually deliver four commercial-scale demonstrators. The competition consisted of nine proposals, and went through several stages of assessment.

In March 2010 the UK Department of Energy and Climate Change (DECC) announced that funding would be awarded to E.On and a consortium led by ScottishPower (with National Grid and Shell) to develop two end-to- end CCS power plants at Kingsnorth in Kent (south east England) and at Longannet near Kincardine, Fife (Scotland) respectively. Both were sites of existing large-scale coal-fired power stations. The initial phase of the CCS demonstrator competition involved various FEED studies.

North Sea Carbon Capture and Storage
Map of potential European CCS

UK Problems – Kingsnorth power station

E.On, the German-owned electricity utility company, originally aimed to implement a 300–400 MW-sized post-combustion capture demonstrator facility linked to a new 1600MW coal-fired generation unit on a site at Kingsnorth in Kent as part of the DECC CCS competition. This would have been coupled to pipeline transport of CO2 to the North Sea for storage. The idea behind the pipeline was to ultimately provide a method of CO2 transport from the ‘Thames Cluster’: a group of ten fossil-fuelled power stations. Kingsnorth power station would have captured 8.0 MtCO2/year and the pipeline could, by 2016, have been transporting 27.9 MtCO2/year from the Thames Cluster. But the project ran into strong opposition from environmental campaigners, including those at the nearby ‘Camp of Climate Action’. E.On consequently announced in October 2009 its decision to postpone the construction of new power station at the Kingsnorth site on the grounds that electricity demand had fallen as a consequence of the recession following the 2008 economic downturn. Nevertheless, it won a share of £90M for a FEED study as part of the DECC CCS competition in March 2010, although it ultimately announced in October of that year that it would pull out of the Competition One. It stated that the market conditions were not conducive in the UK, and that it would concentrate on a CCS project in Holland. It was argued that the ”very vocal and media-savy” Climate Camp caught public attention in making the case for low carbon power generation; claiming that a new coal-fired power plant at Kingsnorth with only 20–25% of initial capture capacity did not meet environmental sustainability requirements

Not once, but twice – Longannet power station

Longannet power station at Fife (Scotland) is owned and operated by ScottishPower, and is the third largest coal-fired power station in Europe with a generation capacity of 2400MWe. The intention would have been to retrofit CO2 strippers to remove the CO2 from the exhaust gases after coal combustion. This CO2 would then be transported via a reused natural gas pipe- line to depleted oil and gas fields in the North Sea.

ScottishPower were to be responsible for retrofitting post-combustion CCS for a 300MW demonstrator facility. National Grid Carbon would then develop onshore transport and compression at the St Fergus existing natural gas terminal on the Scottish coast with a new Above Ground Installation (AGI) near Longannet, Dunipace and Kintore, as well as a coastal CCS compressor station. Shell would be responsible for offshore transport of CO2 to the North Sea geological storage site. A prototype Mobile Test Unit (MTU) commenced operation in 2009 in order to capture a small percentage of the power station’s flue gas CO2 emissions to test the complex chemistry involved in carbon capture.

In October 2011, DECC announced that negotiations with the ScottishPower CCS Consortium had concluded, but that the Longannet CCS project would not proceed to full-scale. DECC stated that there were specific technical difficulties associated with Longannet, including the length of pipeline from the Fife coast to the North Sea oil fields. However, ScottishPower claimed that the main problem appeared to be the estimated £1.5 bn UK Government subsidy required for the CCS trial at a time of economic recession.

The study co-ordinated by Markusson examined the Longannet CCS project with a view to learning the social and political lessons from potential demonstrators. They suggest that the UK Government’s CCS Competition One was aimed at addressing, in part, the element of ‘picking winners’ identified by Scrase and Watson. However, the initial CCS demonstrator competition was based only on the use of post-combustion capture technologies, and this influenced the design of the project. It had the support of the Scottish Government and the authority, and induced little public opposition on environmental or other grounds. Nevertheless, the carbon capture project at Longannet was ultimately scrapped by DECC. According to the consortium, led by ScottishPower (in collaboration with Shell and the National Grid), the failure of financial negotiations with the UK Government were partly ‘scuppered’ by the Treasury’s introduction of a carbon floor price the carbon price floor tax that became government policy after the Coalition came to power in May 2010 at £16 per tonne from 2013. [This was originally planned to rise to £30 per tonne by the end of the decade, and £70 per tonne in 2030.] Nevertheless, both technical and social learning will have been gained from these design projects. For example, FEED studies from the Longannet proposal have yielded in-depth technical reports that have been made quite broadly available.

One step forward and two steps back

Despite the failure of negotiations between the ScottishPower led consortium over the development of the demonstration project at the Longannet power station, the UK Government reaffirmed their commitment to CCS and thus potentially to Competitions Two, Three and Four. It had made available £1bn for a new process for the selection of further CCS demonstrator projects. The UK Government published its CCS ‘roadmap’ in the spring of 2012, and announced its latest competition (known as the ‘CCS Commercialisation Programme’) for £1bn capital funding to build a commercial scale, coal or natural gas fuelled, power plant and capture facility in Great Britain to be operational by 2016–2020 with an appropriate storage site offshore.

These were a natural gas retrofit scheme (the Peterhead Project in Aberdeenshire, Scotland) led by Shell with SSE and an oxy-fuel combustion project at a new ‘super-efficient’ coal-fired power station (the White Rose Project at the Drax site in North Yorkshire) from an industry consortium (Alstom, Drax Power, BOC and National Grid). The UK Government agreed terms for the White Rose CCS Project in December 2013 for FEED studies, which will last approximately 24 months. A similar agreement for FEED studies associated with the Peterhead CCS Project were signed in February 2014.

Elections, manifestos and a total reversal

The Conservative’s 2015 general election manifest said:

“We have been the greenest government ever … committing £1bn for carbon capture and storage”

The November 2015 Spending Review and Autumn Statement dramatically changed the UK’s energy policy placing the focus on building many new gas-fired power stations, winding down the existing Coal fleet and large state aid for Nuclear generation. In a statement to the London Stock market on the 25th November 2015 the Government confirmed that the £1 billion ring fenced capital budget for the CCS Competition was no longer available but, frustratingly, to meet carbon targets, any new stations would have to stop generating by 2030 unless CCS is fitted. The cancellation of the CCS competition makes a challenging goal.

In the Energy and Climate Change Committee meeting on the 20th January 2016, MP’s asked the witnesses – Richard Simon-Lewis, Prof. Jon Gibbens, Luke Warren, Chris Littlecott and Neil Kenley – whether there had been discussions prior to the announcement and they reported that the competition was cancelled four weeks before commencement.

Richard Simon-Lewis said that the first indication of something coming down the track was a Financial Times article published on the evening of the 24th November which trailed an article that indicated that something might happen in relation to the level of grant funding. The article seemed to indicate that there was a view within Government that CCS was expensive and, as such, the grant might be exposed to reduction. That is the first time that we got a sense that something was coming down the track. On the following day, the 25th we were called across by DECC at 3 o’clock and our chief executive was informed by a DECC representative of the decision.

“It is fair to say it was very unexpected from our standpoint. It was not something that we were given a huge amount of visibility around. Essentially, the day the stock exchange announcement came through was the first time that we were formally aware of it, though on the evening of the 24th there had been a sense from the FT article that something was coming down the track. I listened to the Chancellor’s statement in its entirety and clearly did not get wind of what was coming later that afternoon.”

The news was not mentioned in the Chancellor’s speech or Treasury’s Spending Review document. However, a spokesman for DECC said that the move formed part of the decision to cut spending at the department by 22 per cent over the parliament. The news has come as a huge blow to the CCS industry, which had been hoping to use the funding to develop two CCS clusters in Yorkshire and Peterhead, which advocates of the technology had claimed would be crucial to reducing the carbon emissions from industrial and power plants. Rumours had been circulating ahead of the spending review that the project may be scaled back, but industry insiders said they were “shocked” the entire funding competition had been shelved.

The underlying reasons to develop CCS are firmly established and CCS has not been removed entirely from the table as CCS could be funded through CFD’s but not until a later round. This seems remote at the current time. The Energy and Climate Change Committee highlighted the confusion that the November 2015 announcement and called upon the Government to review and publish their updated their CCS strategy.

As of January 2015 the outlook for UK CCS seems to be receding with the Government keen to pack a new “Dash for Gas” and to support the building of new nuclear power sations. At the same time, margins are tightening as existing Coal assets decommission and tighten an already restricted system. The latest round of capacity auctions have resulted in the perverse incentivisation  of backing diesel generators to meet some of the system margin. The UK had the opportunity to lay the infrastructure and to lead Europe in Carbon Capture and Storage and it, is to the regret of this blog, that that chance appears to be waning.


The prospects for coal-fired power plants with carbon capture and storage: A UK perspective – Hammond, Geoffrey P, Spargo, Jack : Energy Conversion and Management journal 2014:86:476-489

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