Introduction of carbon capture paramount

20 February 2012 The use of coal is set to grow over the next decade and, despite concerns over its environmental credentials, the introduction of carbon capture and storage technologies is of utmost importance. Whilst all key elements of carbon…

20 February 2012

The use of coal is set to grow over the next decade and, despite concerns over its environmental credentials, the introduction of carbon capture and storage technologies is of utmost importance.

Whilst all key elements of carbon capture and storage (CCS) have been demonstrated in the laboratory or at small scale operation, the key challenge for the industry is to demonstrate the entire chain at commercial scale. This means incorporating CO2 capture from large sources, CO2 compression, and transportation and injection into suitable storage sites or for a use that results in permanent emissions abatement.

Despite misgivings from mainstream media, there was significant progress last year in the number of large-scale integrated projects in operation or under construction, and a clustering of projects in the advanced stages of development planning.

There are eight large-scale projects in operation around the world and six more still under construction, three of which have only recently commenced. Importantly, these include a second power project, Boundary Dam in Canada, and the first project in the US that will store CO2 in a deep saline formation: the Illinois Industrial Carbon Capture and Sequestration (ICCS) project.

The total CO2 storage capacity of all 14 projects in operation or under construction is over 33’million tonnes a year. This is broadly equivalent to preventing the emissions from more than six million cars from entering the atmosphere each year.

As with most industrial projects, building a viable business case for a CCS demonstration project is a complex and time-consuming process that requires both the project economics and the risks to be understood prior to an investment being sanctioned.

All projects in operation use CO2 separation technology as part of an already established industry process. They also use CO2 to generate revenue through enhanced oil recovery (EOR) and/or have access to lower-cost storage sites based on previous resource exploration and existing geologic information sets. Six of the eight operating projects are in natural gas processing, while the other two are in synthetic fuel production and fertiliser production, and five of these projects use EOR.

But it is not all rosy, with 11’CCS projects cancelled last year – eight in the US and three in Europe – due to it being deemed uneconomic in its current form and policy environment. The lack of financial support to continue to the next stage of project development – and uncertainty regarding carbon abatement policies and regulations – were critical factors that led several project proponents to reprioritise their investments, either within their CCS portfolio or to alternative technologies.

Power generation projects have significant additional costs and risks from scale-up and the first-of-a-kind nature of incorporating capture technology. Electricity markets do not currently support these costs and risks, even where climate policies and carbon pricing are already enacted.

One major cost for CCS is the energy penalty or ‘parasitic load’ involved in applying the technologies. Going forward a major emphasis, in pre-, post- and oxy-fuel combustion capture applied to power stations (and other industrial applications) is on research into reducing cost.

Despite these challenges, construction of a post-combustion capture project (Boundary Dam) and an integrated gasification combined cycle (IGCC) project (Kemper County) is proceeding. This indicates that the technology risk for these applications is considered manageable and the technical barriers are not insurmountable if other conditions, such as allowance for the added cost into the rate base and other incentives, are right.


Pipeline transportation of CO2 is a proven and well-developed technology, but it is the scale of the future CO2 transport requirements that will require strong investment support. While pipelines are expected to be a cost-effective transport solution with increasing distance, in certain circumstances shipping can be cost competitive and offer greater flexibility to serve multiple CO2 sources and sinks.

Significant economies of scale can result from shared transport infrastructure, but establishing a network is a large investment that can add considerable risks to early mover projects. These risks need to be understood, in particular by governments, when providing incentives for demonstration.

CCS in action

One scheme in the UK that is up and running, though only testing carbon capture rather than storage, is at SSE’s Ferrybridge Power Station in West Yorkshire. The project is a collaboration between SSE and UK-based Doosan Power Systems and’Vattenfall and is supported by the Technology Strategy Board, DECC and Northern Way. It is the first of its size to be integrated into a live power plant in the UK. As such, this represents a major step forward in proving that carbon capture technology is viable on a commercial scale.

The plant bridges the gap between the various pilot-scale trials that are under way and the commercial-scale demonstration projects envisaged by the UK government, as it captures 100t of CO2 per day from the equivalent 5MW of coal-fired power generating capacity.

Testing, testing…

SSE chief executive Ian Marchant is keen to stress the significance of Ferrybridge in the broader context of the UK energy industry: “The development of viable carbon capture technology is central to the UK’s climate change and energy security objectives. We believe projects such as this will be absolutely crucial in establishing when and how the technology can be developed. What we have at Ferrybridge will provide an invaluable source of reference and learning for the industry as a whole.”

“We are capturing CO2 and everything is going as expected,” Mark Bryant, director carbon capture at Doosan Power Systems, says. “We are extracting steam as we would on a full-scale plant and we are now in the final stages of the commissioning. We are treating the flue gas and the plant is operating in a very stable position. It’s performing well.”

Ferrybridge is a two-year test programme and the first phase will be to benchmark the performance using Major Environmental Analysis (MEA). After that, Doosan will spend several months testing some of its formulated solvents.

“At the end of that two-year period we will determine what the next steps are,” Bryant adds. “Either to look at further testing or relocating the plant to another site, mothballing it or there is a fourth option to dismantle the plant. I don’t think this fourth option would come into play – not at this stage anyway.”

The plant is a major step forward in the capture. “It gives us the confidence and certainty to go to those next phases and significantly de-risk the process for when we go to the next scale,” Bryant says.

“We have learnt a lot of lessons in the process, both from constructing the plant and working with governing bodies, providing funding and the commercial arrangements as well as the actual technology. It’s been good not just for ourselves but for the supply chain as well.”

Despite the slow progress in commercialising the technology, Bryant is adamant that its adoption within power generation is vital to the global push to reduce carbon emissions. “There is a pressing need without a doubt,” he says. “In a lot of countries you have got indigenous resources of coal and gas that are readily available. We need to face the fact that countries like India and China, that have this massive availability of coal, will be using it.”

Ferrybridge is a post-combustion capture technology, but Doosan is keeping its options open and is also developing its oxy-fuel and pre-combustion technology. Bryant says: “As we are traditionally a boiler maker, having a technology which is an intrinsic link to the boiler and the firing systems was a natural fit for the organisation, but the post-combustion is a technology that is certainly closer to a commercial operation.”

There are a number of hurdles that still need to be overcome, not least of all making the process economically viable – it is a well reported fact that the loss of efficiency and energy used in the CCS process could increase fuel use from 10 to 40’per cent. “Unless there is legislation or the price of carbon is at such a high level, economically it is not viable,” Bryant says. “Developers need some form of financial support or legislation. We certainly need government funding so that we can have the demonstration at the sizes that it needs to. Then there needs to be legislation put in place which limits the omissions of CO2 but does not favour any particular technology.”

For Bryant, the next step may prove to be the most difficult: finding the next project. “We need continuity – this is a big issue from a business point of view,” he explains.

“We have now finished the Ferrybridge project and are desperately looking for the next project, but there is a gap in terms of other projects.

“We are a business and cannot have our engineers sat on the shelf waiting indefinitely for the next major project to come about. There needs to be continuity and a natural flow.” *

case studies The world’s eight large-scale integrated CCS projects

In Salah CO2 Injection, N Africa

In Salah is a fully operational onshore gas field with CO2 injection. CO2 is separated from produced gas and re-injected in the producing hydro carbon reservoir zones. Since 2004 about 1Mt/a of CO2 has been captured during natural gas extraction and injected into the Krechba geologic formation at a depth of 1,800m.

Sleipner CO2 Injection, Norway

Sleipner is a fully operational offshore gas field with CO2 injection. CO2 is separated from produced gas and re-injected in a saline aquifer above the hydrocarbon reservoir zones.

Sn’hvit CO2 Injection, Norway

Sn’hvit is a fully operational offshore gas’field with CO2 injection. The LNG plant’is located onshore. CO2 is separated from produced gas and injected in a saline’aquifer below the H/C reservoir zones offshore. This liquefied natural gas (LNG) plant captures 0.7Mt/a of CO2 and injects it into the Tub’en sandstone formation 2,600m under the seabed for’storage.

Weyburn Operations, Canada

The oil field is currently operating while’injecting CO2 to increase oil production. This project captures about’2.8Mt/a of CO2 from a coal gasification plant located in North Dakota,’US, and transports this by pipeline’320km across the Canadian border to inject it into depleting oil fields where it is used for enhanced oil recovery (EOR).

Salt Creek Enhanced Oil Recovery,’US

Anadarko will build a pipeline to inject CO2’in existing oil field for enhanced oil recovery. Anadarko has injected 5.12 billion cubic metres of carbon dioxide into the field as part of a project to tease more oil from the field and in the process sequester a greenhouse gas that would otherwise have to be discharged into the atmosphere.

Enid Fertiliser, US

The Enid Fertiliser plant sends 675,000t of CO2 to be used for EOR. The pipeline and wells are operated by Anadarko Petroleum.

Sharon Ridge EOR, US

CO2 from Mitchell, Gray Ranch, Puckett and Turrell gas processing plants is transported via the Val Verde and CRC pipelines for EOR (including Sharon Ridge EOR field).

Rangely Weber Sand Unit CO2 Injection Project, US

ChevronTexaco, the current owner and operator of the Rangely Weber Sand Unit, has been injecting carbon dioxide into the Rangely Oil Field since 1986 to increase the total volume of recoverable crude oil.

technical terms What is geological storage?

In the long term, CO2 can be stored in many geological formations such as depleted oil reservoirs, depleted natural gas fields, deep saline aquifers and unmineable coal seams.

According to the IPCC, these have a global storage capacity of 1,000-10,000Gt CO2. With current world energy-related emissions of about 27Gt CO2 per year, this gives sufficient storage capacity, enabling CCS to play a major role in emissions abatement.

The world’s carbon is held in geological formations, and is either locked in minerals or hydrocarbons, or dissolved in seawater. Naturally occurring CO2 is found with petroleum accumulations, having either been trapped separately, or with hydrocarbons, for millions of years.

Of the geological formations that can be used to store CO2, three are most promising:

* Deep saline formations provide the largest potential volumes for geological storage of CO2. Brine-filled sedimentary reservoir rocks are found in sedimentary basins and provinces, though their quality and capacity to store CO2 depends on their geological characteristics. Saline formations need to be porous and permeable to allow CO2 to be injected in a supercritical state, and overlain by an impermeable cap rock or seal to prevent CO2 migration into overlying fresh water aquifers, other formations or the atmosphere.

* Depleted oil and gas reservoirs generally have similar properties to saline formations. Conversion of depleted oil and gas fields for CO2 storage should be possible as the fields approach the end of economic production. There is high certainty in the integrity of the reservoirs with respect to CO2 storage, as they have held oil and gas for millions of years.

* Coal beds below economic mining depth could store CO2. Carbon dioxide injected into un-mineable coal beds may be absorbed by the coal, providing permanent storage’as long as the coal is not mined or disturbed.

how it works Carbon capture and storage

Carbon capture and geological storage – also known as CO2 sequestration – is where CO2 is captured from gases produced by the combustion of fossil fuel or industrial processes, compressed, transported, and injected into deep geologic formations for permanent storage. Most of the technologies needed are available but have not been put together at commercial scale.

There are three process routes for capturing CO2 from fossil fuel combustion plants:

* Post-combustion capture, the separation of CO2 from flue gas (the exhaust from combustion) after fossil fuels are oxidised. Flue is scrubbed with a solvent such as an amine solution. The amine-CO2 complex formed is then decomposed to release high purity CO2 and the regenerated amine is recycled for the capture process.

* Pre-combustion capture increases CO2 concentration of the flue stream, requiring smaller equipment and solvents with lower regeneration energy. The process involves fuel reaction at high pressure with oxygen or steam producing carbon monoxide (CO) and hydrogen (H2). The CO reacts with steam to produce CO2 and additional H2. The CO2 is then separated, while the hydrogen is used as fuel in a combined cycle plant.

* In oxy-fuel combustion, the concentration of CO2 in flue gas can be increased by using pure or enriched oxygen (O2) instead of air, either in a boiler or gas turbine. The O2 would be produced by cryogenic air separation and the CO2-rich flue gas recycled to avoid the high flame temperature.

Each of these processes involves the separation of CO2 from a gas stream. There are five main technologies, with the choice depending on the state of the CO2 to be captured: chemical solvent scrubbing; physical solvent scrubbing; adsorption/desorption; membrane separation; and cryogenic separation.