Introduction to carbon capture and storage

Carbon capture and storage is regarded by many to be a key future technology option in low carbon emission power and industrial sectors. The simple acronym belies a complex system acting in unison to sequester larger carbon dioxide emissions in permanent geological stores. This study provides an introduction for those wishing to know more about this key group of technologies, particularly those contemplating application to their own plant.

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Aug 30, 2017
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Author(s): James Watt

Introduction

The options available for the reduction of CO2 emissions and the mitigation of climate change are broad. As detailed in numerous reports, particularly the IEA Energy Technology Perspectives [1] and the World Energy Outlook [2] series, one of the technology families that can contribute, needs to contribute, is carbon capture and storage (CCS). The term family is also appropriate as, like the other technologies, it is in fact a broad range of applications and technology options. The potential contribution of CCS to CO2abatement is well documented and considered by the Committee on Climate Change [3] and the IEA as critical to emission reduction targets. This is despite the recent decision by the UK Government not to fund the second CCS commercialisation programme in 2015 [4]. The portfolio does offer the potential for continued use of hydrocarbon fuels and feedstocks in power generation and industrial processes and mitigate the CO2 emissions. This ability is critical for power generation until other technologies are deployed, but also for industry where CO2 emissions are part of the process such as in the oil and gas, chemical, mineral and metals sectors.

Carbon capture, conditioning, transport and sequestration

The CCS technology suite is not as simple as the acronym implies, there are multiple elements to consider. In essence it is a chain, Fig 1, of operations in broad groupings, which break down even further, Fig 2, to elements with different design and operating conditions. Typically, an emitter outputting a CO2 containing flue gas sends the gas to a process unit in turn sending the captured CO2 to a geological store with its own characteristics. There are many variations and design options from abatement options to reconfiguration and new technologies.

Fig 1: Basic elements of a full chain CCS scheme

Fig 2: Major options in a CCS scheme

Operationally the impact of CCS differs, but ultimately adds the complexity of an additional process unit to what had been a discharged emission. For power plant, there is a need to match the generation of electricity to the market place, which varies the flow of CO2 to a capture unit and store, Fig 3. Both CS need to be defined to accept this profile and the impact of the store and its operational profile in the case of geological sequestration.

Fig 3: Typical power plant CCS chain and major operational drivers

What are the options for capture?

There are multiple options for the ‘Capture’ of CO2, three major technology families that can be applied to different industrial or power sectors, Fig 4. The three technology families are:

  • Post-combustion/process – where CO2 is extracted from a flue gas.
  • Pre-combustion/process – where the incoming fuel/feedstock is treated to remove CO2 prior to use.
  • Oxy-combustion – the process where the fuel is combusted to provide heat and power in an oxygen atmosphere, providing a high purity CO2 stream.

Fig 4: Power and industrial CCS options

They can all be applied to power and industry emitters in different ways, and each has subsets of technologies.

Post-combustion/process

The broadest group is the first, post-combustion/process. Within this group there are diverse technology options from the established amine-based absorption methods to more advanced and efficient amine-based solutions. Other technologies are in various stages of research and development including promising work in ionic liquid solvents [5] or solid sorbent [6] processes which show promise in improving performance. More importantly the basic technology is well understood and mature being in use in the natural gas and chemicals industry for a significant amount of time. The most common is the absorption processes used to remove CO2 from gas streams for re-use or from natural gas streams, where it is typically vented or reinjected into a gas well. The chemicals used in such process are amines, typically dimers of ethanol amine, a relatively simple and effective means of absorbing the gas from another stream. The method is simple as the CO2 reacts to form a thermally unstable solution with the amine and remains in the liquid form of the amine. It is subsequently recovered by applying heat in a stripper column to carefully break the CO2–amine bond and recover the CO2 for compression, Fig 5; the amine is recycled and used again. The process can capture above 90% of the CO2 that would otherwise be emitted.

Fig 5: Simplified post-combustion/process capture plant

The application of these end of stack technologies does need to be considered carefully. Key considerations include:

  • Plant layout and availability of space.
  • The re-routing of stack gas to the capture plant and back.
  • Ability to run with the capture plant off-line.
  • Changes to pressure/velocity profiles in the upstream system.
  • Temperature reduction prior to the entry into the capture plant.
  • Pre-capture treatment, for example, removal of SO x and NO x compounds harmful to the amine solution.
  • Operation load profile changes.
  • Energy impacts of the additional system.

Some of the issues are simpler for new build projects, where the CCS plant design can be integrated. For retro-fit careful consideration is needed and significant cost can arise in providing the tie-in’s to the process and stack. The complexity of retro-fit has been demonstrated in both the Longannet and Peterhead projects in the UK where significant costs are incurred for the retro-fit element. Older plant are also likely to require additional equipment as the amine solutions used in capture can be affected by contaminants common in flue gases such as SOx and NOx and are temperature sensitive. The amine is a relatively expensive chemical to replenish.

The critical factor for this current technology is an energy penalty that has to be applied to operate the plant. Recent developments such as the work in the UK on the commercialisation programme, in research and in design and operation of the Boundary Dam projects, and others, have shown that the energy penalty estimates of a decade ago from scaling up acid gas plant have been reduced significantly. This still represents a significant loss of efficiency for power generators. The process of regenerating the captured CO2 in the stripper column so that it can be recovered and compressed requires heat, typically provided by steam. A typical gas fired power station operating 60% efficiency may drop 8–10% [7–9] points of efficiency with capture plant installed. The efficiency loss is primarily through the loss of steam to the turbine and the parasitic electrical load, particularly the power requirement for compression. This impacts revenue of course, but also plant design. There are options to simplify the process rather than utilise current site services, or integrate with a power plants systems, separate heat and power plant could be provided to meet the capture plant’s needs. However, this does require additional capital outlay and economically has to be balanced against the alternatives. Research and development is driving the development of the post-combustion processes to new chemicals and new technologies to lower the impact on overall efficiency and the energy penalty.

Second generation solvents, for example, advanced amines or ammonia processes are being offered, for example, by Shell Cansolv, HTC Purenergy, Aker, Alstom and others, and have already reduced the efficiency losses. These advances are being demonstrated in the Boundary Dam project in Canada using Shells Cansolv technology. Other post-combustion technology is available, but at lower levels of maturity. They represent potential savings in terms of energy, chemical resilience and potentially improved flexibility.

Pre-combustion/process

The second option provides a technically different approach aimed at removing the CO2 prior to processing or combustion. Most typical of these is the integrated gasification and combined cycle (IGCC). This process uses a carbon-based fuel, coal, oil or biomass, for example, is gasified, reacting with steam and oxygen, or air, to produce a syngas of CO2, carbon monoxide, water, hydrocarbon gases and hydrogen. Further treatment of this gas can yield higher volumes of CO2 which is then separated, typically using well proven physical solvent technology. The remaining gas, mostly hydrogen is then used for chemical processes or combusted in a combined cycle gas turbine producing an emission of mostly water vapour. Energy loss from the system is neutral compared with post-combustion capture, the power required to operate the required air separation unit is significant and the major draw of parasitic load. The technology can also decarbonise feed stocks for both power and industrial applications, sometimes referred to as poly-generation (poly-gen) units. The syngas can be used directly as a fuel or used as a feed for conversion to other chemicals; these are typically referred to poly-gen units. Typical conversion processes can include methanol or ammonia, key chemical building blocks for the chemicals industry; therefore, decarbonising industry.

Overall the poly-gen model links well with the need to decarbonise industry, but also low carbon chemical production. The deployment of the technology in terms of global capacity is lower than that of current generation of post-combustion technology. Given its wider use in other applications and generally the cost is slightly higher in terms of the total cost per unit power produced. Therefore, there is a higher economic cost, but the technology is efficient at removing the CO2. For future deployment of hydrogen as an energy vector, this technology could be key in the provision of bulk volumes of low carbon footprint hydrogen for a hydrogen economy, producing hydrogen gas in periods of low power generation need.

Oxy-fuel

Oxy-fuel is the least mature technology of the three, but has recently reached milestone deployments in terms of size and commitment. The UK’s White Rose project was based on a new commercial scale (1–1.5 million tonnes per year [10]) oxy-fuel power plant adjacent the current Drax Power Station. Here, the process is simpler than the others as a fuel is combusted in the presence of oxygen, but not air. Hence, flue gas is predominantly CO2. Some contaminants need removal, depending on the feedstock, and then the gas is compressed.

In terms of steps in the process oxy-fuel has the fewest, in theory the simplest operating model. However, the technology is new and unproven at larger scales, particularly compared with the power generation technologies. The impact on industry is most likely limited to the local provision of decarbonised heat and power, though sulphur and nitrogen are typical by-products of the plants.

Future technologies

The established technologies are deployed, post- and pre-combustion/process are at commercial scale with the oxy-fired process close behind. The definition of commercial scale varies. For power plant, it is typically seen as 1–1.5 million tonnes/year for coal and 0.5–0.75 million tonnes/year for gas [10]. For industrial processes, the current scale for CO 2 capture is as high as the lower threshold for coal power plant at 1 million tonnes/year, but this is not typical. For industrial plants, the amine-based technology is already widely deployed, particularly in the gas treatment market, at commercially viable scales. The challenge is to reduce both capital and operational cost of the units, particularly for the large power plant units. Already there are a host of other technologies being researched and developed, at various levels of technology readiness. There are also improvements under development for the existing core technologies. Supporting technologies are also being examined to reduce cost and efficiency penalty, the core technologies are also being developed further, for example, the use of air separation units for IGCC and oxy-fuel are being examined to reduce the power loads required. The next phase technologies can be split into generations, though many interpretations exist, indicating either a performance or deployment based on the time to develop and deploy. Typically technologies can be split by Technology Readiness Level with a score of 7–9 typically the second generation, 5–7 third generation and <5 fourth generation, for example:

  • second generation (deploying):
    • advanced chemical solvents.
    • advanced physical solvents.
    • aqueous/chilled ammonia.
  • third generation:
    • hydrogen and CO2 membrane separation.
    • carbonates.
    • oxygen membranes (for air separation).
    • chemical looping.
  • fourth generation:
    • second generation oxy-fuel.
    • biological processes.
    • solid sorbents.
    • ionic liquids.
    • sodium hydroxide.
    • oligomeric solvents.

Each technology represents pathways to lower impact capture technologies in terms of cost, footprint, energy consumption, but also higher flexibility, contaminant tolerance and operability.

Application to industry

Increasingly focus is growing on two areas in CCS, industry and utilisation. For industry the issues are broad, but for the bulk of industrial emitters the emission comes from the provision of heat and power. The IEA roadmap [11] for industry CCS, considered key technology sectors, and potentially a saving of 4 G tonnes of CO2 by 2050, or ∼20–40% of all installations, depending on the installation size. Moves to electrify industry still impact CCS deployment as the required drop in carbon emissions has to be achieved by the power producers rather than direct by industry. So, low carbon electricity still requires CCS in the power sector, alongside nuclear, in providing base load power generation. The provision of heat, direct or indirect is typically achieved from the combustion of waste gases from the process or fuels such as natural gas or oil or from site power plant, co-generation, heat integration or combined heat and power units.

Process-related emissions range from large to small volumes, with the largest emitters being iron and steel, cement works and refineries. In each case, some of the emissions are likely to be from on-site power plant. For example, the Redcar steel works, part of the 2015 study on Teesside, one third of the emissions arose from the on-site power plant. Even though the plant used waste gases from the process as fuel, it was viable to retro-fit CCS onto the power plant, thus enabling other emissions sources to use the same CCS facility. For some process emissions, CCS applied to the flue gas is the only substantial option outside of reconfiguration or reformulation of the process itself. Like power plant, the re-routing of flue gases to a capture plant may require additional flue gas treatment or flow assistance in the form of a fan or blower.

The ease of application to an industrial process varies greatly. Not only are the above issues to be considered, but the emitters are diverse in age, location, technology and gas quality. No one single solution fits all, individual emitters need individual solutions, more so than in the power sector. This diversity means industrial application is best considered in sectors. Industry has to face an economic choice, which is difficult, CCS will add additional cost to any system and in a global marketplace industry has to be able to compete, so the interest in of CCS is generally low, unless the CO2 is commoditised, as are some anthropogenic sources in the USA. Here, multiple industrial plants already capture their CO2for use in enhanced oil recovery (EOR) such as the Coffeyville Gasification plant and Enid Fertiliser CO2-EOR project. The chemical plants capture 2.7 million tonnes/per year. These are in addition to the gas treatment plants, sweetening natural gas by removing the CO2. In total industrial plants in the USA capture and transport over 20 million tonnes/year for use in EOR.

Work and interest in the area of CCS for industrial emitters is growing, as for many it remains the key option for decarbonisation. In 2015, the Teesside Collective [12] project produced one of the most comprehensive studies for industrial CCS and an integrated cluster, demonstrating that over a range of emitter’s solutions can be found including the adaptation of existing modular plant used for acid gas treatment. The use of pre-designed established technology makes CCS for low volume emitters more cost effective as the costs and risks associated with first of a kind deployment are not present, the technology is deployed already in a competitive market.

There is still research and development to be done for industrial capture systems, but also in the re-tooling of processes to eliminate CO2, Table 1, in addition to the current deployable technology. For many large emitters re-tooling seems to be the more economical route to be taken in the long term, particularly in the Cement and iron and steel sectors. In iron and steel, for example, the current post-combustion technology can be applied to flue gas streams, particularly where on-site power or steam generation is provided. The core technology of the steel making process can also be refined or replaced such as those examined under the ULCOS programme which looks at four alternative methods of steel making or enhancements to the core processes. The readiness of the technology varies from processes being examined or proposed to those that are being tested such as the Hlsarna steel process. There remain challenges, but they are becoming better understood in a broad sector that understands it has economic challenges to overcome, under increasing social pressure to produce lower carbon intensity goods.

Sector

Potential technology options

Issues and barriers

Estimated date of maturity for capture

iron and steel

post-combustion – high readiness for flue gas-based capture options to change the core technology

multiple sources of emissions – power plant, stoves, Basic Oxygen Steelmaking (BOS), coke ovens and furnace impurities in the stream

2020–2030

  • oxy-fuel blast furnace
  • gas Direct Reduced Iron (DRI)
  • Ultra-Low CO 2 Steel making (ULCOS)/FINEX steelmaking processes

retro-fit solutions  plant layout

cement

post-combustion – high readiness for flue gas-based capture

multiple emission points

2015–2030

options to change the core technology

  • oxy-fuel
  •  carbonate looping

issues on cement quality

glass/industrial heat

post-combustion – high readiness for flue gas-based capture

potential large process rebuilds

fuel switching enabled by CCS is possible

alternate fuel firing technology unknown

chemicals

post-combustion and pre-combustion deployable

cost/economics

process heating/integration changes

fuel uncertainty

fuel or feedstock switching enabled by CCS is possible

negative impacts on process – reconfiguration, costs etc.

refineries

post-combustion and pre-combustion deployable

cost/economics

currently mature – 2030 Fluidic Catalytic Cracking (FCC)

process heating/integration changes

fuel uncertainty

FCC

multiple emission points – variations in emission quality

potential for some processes to change

Table 1: Industrial CCS options and technology readiness

Utilisation

Utilisation of CO2 provides a different route to sequestering the CO2 long term, Fig 6. The term ‘utilisation’ relates to the re-use of the CO2 rather than disposal and is a broad range of options. For utilisation, the CO2 is fixed into another process and the re-emission minimised at worst, removed at best. For example, mineralisation options include the option to produce an aggregate that can be used in construction, displacing other material. Or as a new feedstock as in agriculture as is currently achieved in Teesside to grow crops in CO2 rich atmospheres. It could be used as a chemical feedstock to new or reconfigured processes, enter the commodity market or in the growth of algae, which in turn becomes a feedstock for a number of potential technologies. The route to utilisation is also open to the displacement of other carbon bearing stocks, typically derived from hydrocarbons that lower the overall carbon footprint.

Fig 6: CCS – some options for utilisation [13]

The potential for re-use could be more limited than the storage capacity of sequestration. It is also part of the sequestration/storage story too, for the largest volume of CO2 utilised is for enhanced hydrocarbon recovery (EHR), typically oil, predominantly in North America. Here, over 45 million tonnes/year of CO2 is used to support oil production, whilst some CO2 is recovered in the oil, reinjection would ensure the sequestering of large volumes of the gas.

Aside from EHR, which can be gas or oil recovery, utilisation does occur, for example, a fertiliser plant in Teesside, UK provides CO2 to the gases commodity market typically for beverage use, but also to a local agricultural facility where it is used in the growing of tomatoes. The scale of re-use or utilisation is low at ∼80 million tonnes/year, the majority for EOR, when compared with the global emissions of around 35 G tonnes/year from anthropogenic sources. However, like industrial CCS interest is growing and a number of activities are looking toward utilisation as an enabler to CCS as it may commoditise the CO2 produced. For utilisation itself the options are myriad, Fig 6, with the potential in chemical feedstocks the largest.

For chemical feedstocks and some of the routes around algae or other biologic solutions, the process of using CO2 in this manner reduces the input of carbon from other sources. Principally the re-use of CO2 displaces carbon arising from another source, so that if or when it is broken down or re-emitted the CO2 has forced a reduction of the required carbon into the process. Effectively, it displaces a feedstock that would have emitted fresh CO2, overall reducing emissions in the longer term and decreasing the reliance on other feedstocks, typically those derived from natural gas or crude oil.

Utilisation remains a growth sector, still untapped with many ideas and options being considered in early development stages. It may not always represent complete decarbonisation routes, but in displacing other sources of carbon as well as those that fix the carbon in place it remains a valid method for sequestering significant outputs of CO2.

Other uses such as EHR are more permanent and the use of mineralisation techniques do this by fixing the CO2 in a product that does not suffer from the re-emission potential from some chemical and biological processes. Mineralised material can then displace other material, particularly those in the aggregate supply chain. This not only captures and retains otherwise emitted CO2, but also reduces the overall carbon footprint of the aggregate industry by displacing other processed materials.

Overall utilisation represents options, but potentially the economic incentive by commoditising CO2. In fact utilisation for EOR in the North Sea has long been seen as a lower cost option for storage, due to the economic benefits of oil production and the value it holds.

Transport

The transport of CO2 at the scales required for CCS is in fact the most technological mature of the components. Since 1972, North America has been transporting large volumes of CO2 over long distances by pipeline. The gas is collected from geologic and anthropogenic sources and utilised for EOR in oil fields across the USA and Canada. Even shipping can have a role to play for emitters beyond the economical or practical reach of pipelines and could build on the current small CO2 bulk carrier fleet.

For transport pipeline conditions vary, but generally the gas is actually transported as a liquid or dense phase fluid (beyond the critical pressure). Typical conditions in North America are 4–38°C and 85–171 barg. For CCS applications the range is expected to be similar, the one crucial difference is the lowest temperature. In the dense phase region, properties of the fluid change and viscosity falls even at high densities making the fluid economic to compress and pump. The potential storage undersea requires sea or ocean transit temperatures to be considered.

In transporting to the storage site, it is here that the impact of the store will be felt most keenly. Limits will have to be applied to the fluid, in terms of variations in temperature and pressure, flow and contaminants, for example, the quantity of oxygen allowed in one storage site may not be suitable for another and a common entry specification would be required. This in turn defines the minimums for any pipeline or network, which in turn cascades onto the capture and conditioning plant. The definition of CO2 quality is in effect controlled by the storage site first, then the acceptable pipeline conditions and finally what the capture plant can produce. Pipeline conditions require care to be taken on the impact on the fluids physical properties and its water content. Table 2 shows a typical entry specification, in this case set for the Teesside Collective project [14].

Component

Recommended specification

Advisory notes

CO 2

95 mol%

hydrogen sulphide (safety)

<200 ppmv

health and safety

carbon monoxide

<2000 ppmv

health and safety

NO x

<100 ppmv

health and safety

SO x

<100 ppmv

health and safety

oxygen

<10 ppmv

technical: pipeline and storage

nitrogen

1 mol%

technical: EOR led

hydrogen

1 mol%

technical: EOR led

argon

1 mol%

technical: EOR led

methane

1 mol%

technical: EOR led

non-condensable

4 mol%

technical: pipeline led

water

50 ppmv

technical: hydrate and corrosion led

hydrocarbons

2 mol%

particulates

1 mg/Nm 3

technical: pipeline led

particle size, µm)

≤10 µm

technical: pipeline led

mercury

regulation

ammonia

<50 ppmv

technical

other

caution: must not negatively impact hazards of a release, pipeline/storage/well integrity

Table 2: Teesside collective proposed CO2 stream composition

The limits are driven by a variety of elements, but two can easily be demonstrated. The first is the impact of the common, non-hazardous, contaminant nitrogen. As nitrogen is added to the system, the physical properties change and the critical point and phase line change. In this case, it steepens the phase line, above which is liquid, below gas and exposes pipelines to potential for gas formation at lower pressures. The concern is that for simple contaminants major impacts are felt. This directly increases the power requirements of any compression and pump, but also the size and rating of the transporting pipeline, ultimately all issues that impact cost. Other contaminants need to be considered for health and safety reasons, particularly should the transport system fail or vent.

The second example and a major concern is water, which if allowed to form in the pipeline can combine with CO2 to form a highly corrosive acid or in cold temperature potential combine to form a wax like substance referred to as a clathrate or hydrate. This substance can build up and damage equipment and reduce performance of a pipeline. To this extent water is extensively removed, already to a low specification in the North American EOR market, but even more so for those systems considering undersea pipelines, where the lower pipeline temperatures are closer to the region of hydrate formation. Again the technology is mature and robust and bulk removal simple; however, lower water specifications are being insisted on which drives dehydration costs upwards, while they remain a marginal cost compared with the whole scheme.

The use of shipping remains viable and though seen in CCS as an option, pipelines have been considered in more detail and on more projects. The lower capital investment required is attractive, even more so over long distances. The CO2 conveyed by ship is at lower pressure than desirable for injection, so requires additional compression, and management and the infrastructure to enable shipping or direct offshore injection.

Sequestration

The critical element of CCS is not the capture or transport, but the sequestration. The use of ‘storage’ is common place, but sequestration of the CO2 is more accurate. Abatement of CO2 emissions from the atmosphere requires the permanent sequestration of the gas in either storage or utilisation methods such as mineralisation.

Geological storage

For geological related storage and utilisation there are multiple options, Fig 7, and for an engineer this can be the hardest concept to master. In each solution, two mechanisms are occurring that impacts CCS scheme operation, operational and geological changes. The operational changes are forced by the storage sites structure, pressure changes and limits, contaminant restrictions and operability/reliability of the injection facility all of which directly influence day-to-day operation. It is possible that an event at the well head, would curtail the ability to store, forcing the emitter to vent. The other issue is that stores operate on a geological timescale, it can be expected that over a stores lifetime additional wells will be required in multiple locations as the pressure around a well increases over time and can dissipate that pressure slowly. There will have to be pressure management whilst measuring, monitoring and verification will constantly monitor the progress of the store. Over time the CO2 will react, forming mineral deposits and becoming permanently fixed in place.

Fig 7: Storage options

Enhanced HR

The use of CO2 to enhance hydrocarbon production is long practised, particularly in the USA and Canada. It is also seen as an increasing option compared with water and gas assistance. The fluid is used in two ways, for gas it is used to pressurise the gas field aiding the flow of gas out of a well or in the case of liquid support to drive the gas out physically. For oil, the CO2 interacts in the formation and helps improve the motility of the oil and the pressure in the formation, making it easier to flow out of the well. Inevitably CO2 dissolves in the oil or diffuses into the gas, but generally needs to be removed prior to transport or use. By this method as with other support processes more oil and gas can be recovered from fields. Ultimately this increases the amount of carbon produced from the use of the hydrocarbons recovered. It is far more effective in carbon abatement terms to use the reservoir space for sequestration than to not do so at all. Where CO2 is extracted with the hydrocarbon, it needs to be recovered and reinjected at some point in the processing cycle to ensure that EHR remains an effective CCS process. For CCS scheme’s reinjection is preferred; however, the bulk of the injected CO2 with good management of the field can be left in the formation and stored.

Deep saline formations

Commonly referred to as aquifers deep saline formations are one of the largest potential volumes of storage for CCS. The formation is in effect a porous strata filled with highly saline water, at significant depths and capped above by an impermeable layer that retains the water in the formation. CO2 can be injected into the formation and mixing and dissolving with formation liquids it dissipates through the rock and is permanently trapped by a number of mechanisms over short or long timescales.

Depleted hydrocarbon formations

Depleted formations are former active hydrocarbon fields that have reached the end of their productive life. Where modern recovery techniques cannot recover further oil or gas, the reservoir can be used to deposit CO2 as it is effectively a proved store. The CO2 is injected, in simple terms, to the original pressure of the discovery and the wells sealed and capped.

Geology not engineering

The above is a simplification of a highly complex process and a difficult subject to grasp for those not reservoir engineers or those in the geological sciences. The storage site and trapping mechanisms are at the core of the project in terms of longevity, cost and development. As such those approaching CCS scheme’s need to be aware of the elements in the scheme. Even power plant owners need to be aware of the transport and storage issues, particularly storage. Storage sites will have an influence on the system design and dictate as much of the operational flexibility into a full system as a power plant. Here, in the storage sphere the UK is particularly fortunate as there is a huge academic presence in this field at multiple universities as well as introductory course and publications aimed at many levels. Notably offshore storage of CO2 will enter its 22nd year in 2017 at Statoil’s Sleipner field, marking the safe injection in North Sea geology of nearly 20 million tonnes since 1996.

Costs

The important issue of cost varies according to the application. The UK CCS competitions have provided a good reference source for cost, particularly around the retro-fit of capture to a coal fired power station at Longannet. It is recognised that they are project specific costs, probably higher than expected, because of the nature of the set project requirements, in particular their commercial risks. Disclosure of the knowledge from the commercialisation programme cancelled in 2015 provides more information. As an example, the cost estimate provided for the Peterhead project indicated a Capital Expenditure (CAPEX) cost of £999 million [15], £640 million for the onshore elements, of which £153 million was related to ‘power plant modifications’. The White Rose project included for larger-scale volumes of CO2 than the immediate plant to serve additional emitters in the region. This was done because scale economy dominates transport costs. The lessons learned document produced by the Carbon Capture and Storage Association [16] discusses this particular issue, whilst the UK Her Majesty’s Government (HMG) Cost Reduction Task Force discusses ways of reducing that costs in the UK.

However, the cost outcomes of projects are swayed by the conditions of the emitter asset, the extent of modification and energy penalty, but also commercial factors, they need close analysis to be compared properly. Hard data, at scale, is difficult given the first of a kind roll out and a number of projects will have to be completed for clearer cost data. At the moment, costs are demonstrated by modelling and studies typical of early deployment of a new technology stream. The costs are always freely quoted, but in terms that are not necessarily comparable such as levelised cost of electricity (LCOE) or a contract strike price (such as contracts for difference) in £/MWh or £/tonne CO2, or by capacity, £/kW. They do allow comparison between technology options to reduce CO2 emissions. Costs for CCS vary with application due to a number of variables, not least the operating profile of the plant and the concentration of CO2 in the flue gas. For power plant that operates as a two-shift or peaking plant, for example, the highly flexible capture plant may well cost more than for baseload. For comparison some quoted LCOE values are shown in Table 3, though there are differences in what is included in these costs.

Application

LCOE €/MWh, average

Avoided carbon, €/tonne CO 2

Capital cost, €/kW

CCS coal

115

35–91

3200

unabated coal

68

1900

CCS gas

102

65–125

1600

unabated gas

68

700

nuclear

>80

3500

offshore wind

138

65–127

3600

Table 3: Example CCS costs [17]

It is clear from most studies that the cost of application of CCS to emitters is significant. The costs are typically first of a kind deployment costs or at least close to this. Continued role out of the technology improves design, reduces risk and conservatism, improved reliability and performance. Therefore, technology costs will fall, potentially as much as 40% [18] in the near term from some estimates. So, there is a need to deploy the technology to prove it in the context of CCS and the need at high costs to support the projects as has been attempted by the UK government’s competitions. For the UK and many European countries, as opposed to the USA and Canada, storage is generally offshore which adds significant costs, particularly for new infrastructure. Onshore storage is less capital intensive, but repeated attempts in Europe to do onshore storage have failed mostly due to negative public reception and opinion. Costs here for offshore storage vary on location and the type of storage, but range from 3.3 to 14.3 €/tonne [19] over a typical 40 years’ lifecycle. A UK study [20] of both offshore transport and storage put costs for initial stores at less than £20/tonne.

For transport, it is clearly accepted that integrated networks for transportation also reduce costs, as does the re-use of the existing infrastructure, hence discussion in the industry now around the preservation of existing infrastructure, particularly offshore. The networks or ‘clusters’ solution is the largest driver for reduced or shared transport costs, where emitters or storage sites are co-located close enough to see the benefits of larger common user pipelines. Such clusters are heavily promoted in Humberside [21] and Teesside [22] in the UK and Rotterdam Capture and Storage Demonstration (ROAD) project [23] in the Netherlands. Costs in networks could decrease by up to 66% over time, depending on the size and location of the cluster.

Further reading

Case studies are more difficult to present; however, here the material provided in the UK CCS competition programmes in 2010 [24] and 2015 [25] is excellent. The projects required key knowledge deliverables to be published in the public domain for four projects:

  • Longannet – retro-fit on coal fired power plant, accessing existing transport solution to the depleted Goldeneye field.
  • Kingsnorth – new build coal power plant, capture and transport to a southern North Sea store.
  • Peterhead – retro-fit on gas fired power plant, with new pipeline accessing the depleted Goldeneye platform.
  • White Rose – new build oxy-fired coal power plant with new transport and storage at the proposed endurance site.

The knowledge transfer deliverables are not a complete blueprint of a project, but do offer an insight to the issues faced by projects in the UK. In addition, other information is available on successful CCS projects such as Saskpower’s Boundary Dam, Shell’s Quest or Statoil’s Sleipner storage project.

Whilst this paper provides an introduction, the subject is complicated. Therefore, reference to more detailed introductions is recommended as CCS primer material. The works by the Intergovernmental Panel on Climate Change (IPCC) [26] and International Energy Agency (IEA) [27,28] provide overall summaries, and the Global Carbon Capture and Storage Institute [29] has a large publications archive, useful guidelines are provided by the Energy Institute [30] and the World Resources Institute [31]. Reference can also be made to books by Markusson [32], Rackley [33], Smit [34] and Wilcox [35] to provide more detail for basic understanding and would be recommended for those becoming involved in the field.

References

  1. ‘International Energy Agency, Energy Technology Perspectives 2016’. Available at http://www.iea.org/bookshop/719-Energy_Technology_Perspectives_2016, accessed September 2016.
  2. ‘International Energy Agency, World Energy Outlook 2015’. Available at http://www.iea.org/bookshop/700-World_Energy_Outlook_2015, accessed September 2016.
  3. Committee on Climate Change: ‘Sectoral scenarios for the fifth carbon budget’. Available at https://www.theccc.org.uk/publication/sectoral-scenarios-for-the-fifth-carbon-budget-technical-report/, 2015.
  4. ‘HM Government Statement to Markets Regarding Carbon Capture and Storage Competition’. Available at http://www.londonstockexchange.com/exchange/news/market-news/market-news-detail/other/12597443.html, accessed September 2016 .
  5. Ramdin M. de Loos T. W. Vlugt T. J. H.: ‘State-of the art CO2 capture with ionic liquids’, Ind. Eng. Chem. Res., 2012, 51, pp. 8149–8177, American Chemistry Society. Available at http://www.dx.doi.org/10.1021/ie3003705.
  6. Glier J. C. Rubin E. S.: ‘Assessment of solid sorbents as competitive post-combustion CO2 capture technology’, GHGT-11, Energy Procedia, 2013, 371, pp. 65–72, Elsevier (doi: 10.1016/j.egypro.2013.05.086).
  7. Adams T. MacDowell N.: ‘Off-design point modelling of a 420 MW CCGT power plant integrated with an amine-based post-combustion CO2 capture and compression process’, Appl. Energy, 2016, 178, pp. 681–702, Elsevier. Available at http://www.dx.doi.org/10.1016/j.apenergy.2016.06.087.
  8. IEA Greenhouse Gas R&D Programme: ‘CO2 capture at gas fired power plants’. Report, 2012/8, 2012.
  9. OECD: ‘IEA energy technical analysis, CO capture and storage: a key carbon abatement option, Paris’ (International Energy Agency, 2008) .
  10. UK DECC: ‘UK carbon capture and storage (CCS) commercial programme, delivering projects 2-4 (further information)’ (UK HMG, London, UK, 2010).
  11. IEA & UNIDO: ‘Technology roadmap: carbon capture and storage in industrial application’ (IEA/UNIDO, Paris, France, 2011).
  12. ‘Teesside Collective’. Available at http://www.teessidecollective.co.uk/, accessed September 2016 .
  13. Styring P. de Coninck H. Armstrong K.: ‘Carbon Capture and Utilisation in the Green Economy’ (Centre for Low Carbon Futures, University of Sheffield, Sheffield, 2011).
  14. Teesside Collective: ‘CO2 entry specification’ (Teesside Collective, 2015). Available at http://www.teessidecollective.co.uk/wp-content/uploads/2015/07/WP5-CO2-Spec-2000-0005-DC00-SPC-0001-R1.pdf.
  15. Shell UK Limited: ‘11.043 PCSS-00-MM-FA-3101-00001, Cost Estimate Report’ (DECC UK CCS Programme Key Knowledge Deliverables, Peterhead CCS Project, Shell UK Limited, Aberdeen, UK, 2015).
  16. CCSA: ‘Lessons learned: lessons and evidence derived from the UK CCS programmes, 2008–2015’ (CCSA, London, UK, 2016).
  17. Bassi S.: ‘Bridging the gap: improving the economic and policy framework for carbon capture and storage in the European Union’ (Grantham Research Institute on Climate Change and the Environment, London, UK, 2015), p. 27.
  18. UK CCS Cost Reduction Task Force: ‘CCS cost reduction task force final report 2013’ (UK HMG Department of Energy and Climate Change, London, UK, 2013).
  19. ZEP: ‘The costs of CO 2 storage: post demonstration CCS in the EU ’ (European Technology Platform for Zero Emission Fossil Fuel Power Plants, Brussels, 2011). Available at http://www.zeroemissionsplatform.eu.
  20. ETI: ‘Progressing development of the UK’s strategic carbon dioxide storage resource’ (Energy Technologies Institute, Loughborough, 2016). Available at http://www.eti.co.uk/project/strategic-uk-ccs-storage-appraisal/.
  21. CO2Sense. Available at http://www.co2sense.co.uk/news/major-new-infrastructure-project-expected-to-bring-1-3bn-and-4000-jobs-to-uk-economy/, accessed September 2016.
  22. Teesside Collective. Available at http://www.teessidecollective.co.uk/, accessed September 2016 .
  23. ROAD Project. Available at http://www.road2020.nl/en/, accessed September 2016.
  24. UK DECC CCS Competition. Available at http://www.webarchive.nationalarchives.gov.uk/20111209170139/. https:/www.decc.gov.uk/en/content/cms/emissions/ccs/demo_prog/feed/feed.aspx, accessed September 2016.
  25. UK DECC CCS Commercialisation Programme. Available at https://www.gov.uk/government/collections/carbon-capture-and-storage-knowledge-sharing, accessed September 2016.
  26. IPCC. Available at http://www.ipcc.ch/report/srccs/, accessed September 2016.
  27. IEA topics. Available at https://www.iea.org/topics/ccs/, accessed September 2016.
  28. IEA: ‘20 years of carbon capture and storage: accelerating future development’ (OECD/IEA, France, 2016).
  29. GCCSI. Available at http://www.globalccsinstitute.com/, accessed September 2016.
  30. EI: ‘Good plant design and operation for onshore carbon capture and onshore pipelines’ (Energy Institute, London, UK, 2010).
  31. WRI. Available at http://www.wri.org/publication/guidelines-carbon-dioxide-capture-transport-and-storage, accessed September 2016 .
  32. Markusson N.: ‘The social dynamics of carbon capture and storage: understanding CCS representations, governance and innovation’ (Routledge, Abingdon, UK, 2012).
  33. Rackley S.: ‘Carbon capture and storage’ (Butterworth-Heinemann, Oxford, UK, 2009).
  34. Smit B.: ‘Introduction to carbon capture and sequestration’ (Imperial College Press, London, UK, 2014).
  35. Wilcox J.: ‘Carbon capture’ (Springer, New York, 2012).

 

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James Watt

Process engineering manager , Amec Foster Wheeler

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