Converting Magnus EOR to CO2: An Unconventional Route to a UK CO2 Capture and Storage Demonstration Project?

At the DTI IOR Research Dissemination Seminar in June Hannah Chalmers ( hannah.chalmers@imperial.ac.uk ) and Jon Gibbins (j.gibbins@imperial.ac.uk ) of the Department of Mechanical Engineering at Imperial College London presented a poster describing an undergraduate project examining the possibility of converting the Magnus Miscible WAG EOR Project to CO2. In this article they discuss this concept and highlight some of the uncertainties.

In 2002 BP started miscible gas injection for EOR at Magnus. The project transports gas produced at West of Shetland (WoS) to Sullom Voe Terminal, Shetland where it is enriched with natural gas liquids before it is piped to Magnus (see related BP article on Magnus, elsewhere in this issue). Rather than injecting the WoS gas directly, this project examines the feasibility of instead injecting CO2 produced from that gas as shown in Figure 1 below. A new 500MW power station with CO2 capture would be built at Sullom Voe and a subsea cable would be laid to the mainland to export the electricity produced.

Figure 1: Magnus EOR Scheme: Now and in the Future?

The 500MW power station at Sullom Voe would use two conventional 300 MW gas turbine combined cycle plants, with additional atmospheric pressure amine scrubbing systems for CO2 capture (link to MS Word Document ). The "missing" 100 MW of output represents the power lost by having to divert steam from the turbines to the amine reboiler to release the CO2, plus power to compress the CO2 to 100 bar.

For compatibility, power plant costs have been assumed to be the same as in recent DTI EOR studies (link to PDF file ), but with an additional 20% allowance for the remote site. As shown in Table 1, the total plant cost is approximately £300M, based on an assumed installed cost of £614/kW. The other significant additional capital costs for the project are the subsea cable to a mainland grid, and the modifications required to handle CO2 injection instead of hydrocarbon injection.

Table 1: Significant Capital Costs

A cable could reach electricity grids in Scotland or mainland Europe . Since any connection to mainland Europe would require a significantly longer cable this option has been ignored in this preliminary analysis. However, price differentials and UK grid constraints might make this an attractive option.

The possibility of constructing a subsea power cable from Iceland to mainland Europe has recently been studied. Based on literature describing this project (link to MS Word Document) an estimated capital cost for a cable from Shetland is approximately £240M or £300M to reach UK grid connections at Dounreay or Peterhead respectively. In addition to the output from this project, Shetland has significant potential to generate electricity from renewable sources. If the cable had extra capacity for this renewable electricity a wider number of stakeholders may be available to share the capital cost and risk of this element of the project. In addition, a cable to Dounreay would pass close to the Orkney Islands , leading to the possibility of further renewable power capacity for the Orkney-mainland section.

The third, and currently most uncertain, major element in cost estimates for this project is the work that would be required to convert Magnus to operate with CO2 injection. CO2 leaving Sullom Voe would be dry so it is assumed that the existing infrastructure could be used to transport the gas to Magnus. However, once the gas has been injected some will be produced with the oil. This wet CO2 must be recaptured and dehydrated before it can be reinjected with fresh CO2 from Sullom Voe. To avoid corrosion problems, liners and critical components in 13% chrome steel may be required in addition to the use of corrosion inhibitors. The additional separation, compression and reinjection equipment and piping may necessitate a platform extension, platform replacement or addition of a floating platform. (link to PDF file).

Since a demonstration of subsea CO2 EOR has not yet occurred, it is difficult to determine the likely cost of this element of the project. Accurate engineering and economic assessment will require the knowledge and expertise of the field operator and specialist engineers. Studies have now begun to approximate the cost of platform alterations required for CO2 EOR (link to PDF file 1 - Link to PDF file 2). Based on these studies, if the construction of a new platform at Magnus can be avoided, it is estimated that between £32M and £70M capital expenditure would be required. In addition to this expenditure, the cost of capturing, treating and reinjecting CO2 is reported to be around $1.5/bbl (link to PDF file).

Although assumed power plant costs are compatible with previous DTI studies, a 10 year project life and 15% IRR have been assumed as being more representative of offshore investments than the 20 year life and 10% IRR that might be more realistic for power plant projects (Table 2). On this basis the cost of electricity delivered to the mainland is estimated to be approximately 4.7 p/kWh for a £70M expenditure for CO2 handling (Table 3). If a larger capital cost of £250M is assumed for modifications to handle CO2 injection then electricity costs rise to 5.8 p/kWh.

Table 2: Preliminary Estimation of Power Plant Costs and Capture (Additional Values/Changes Shown in Red)

Table 3: Preliminary Estimation of Cost of Electricity including Sullom Voe GTCC and Magnus EOR Modifications (Additional Values/Changes Shown in Red)

Are electricity prices in this range likely to make the project viable? Compared to current prices of around 2 p/kWh, obviously not. But this is CO2 free (or approximately 90% CO2-free!) electricity, like renewables. If the Renewable Obligation Certificate scheme were extended to help the development of other novel sources for zero emission electricity the current ROC price of 4 p/kWh (link to web page) would make even the higher COE value of 5.8 p/kWh worth considering.

These costs are uncertain since this was a preliminary study, without access to detailed information. Many critical factors, such as the estimated lifetime of the WoS gas reserves, the value of natural gas liquids released for sale, and the possibility of eventually recovering injected hydrocarbons could not be considered. It was also assumed that CO2 would replace methane on a 1:1 molar basis in EOR performance - a detailed reservoir study would be needed to verify this, and address the possibly complex issues associated with a changeover in injected gas and matching power generation and EOR gas demands. Modifications to handle wet CO2 are also recognised to be a key, but uncertain, factor in project economics.

But these technical issues can be addressed and quantified if there is a prospect that the resulting scheme would be commercially viable. What cannot be predicted is whether or not current levels of government support for certain types of renewable electricity generation will be extended to other novel CO2 reduction technologies, to offset the inevitable risks in demonstration projects and to provide an early incentive before carbon savings reach their likely long term valuations. Whether or not to extend ROCs or their equivalent to a CO2 EOR scheme like this is a political decision. But the proposed Sullom Voe power station would make an additional ~1% of UK electricity CO2 "free". Shetland and Orkney require a connection to the mainland grid to allow any significant further development of renewables. Schemes that are able to extend the benefits as widely as possible should have the best prospects for public, and hence political, support.

The authors wopuld like to acknowledge the help given by Mike Austell, UK Co-ordinator for the CENS Project , Martin Blunt, Centre for Petroleum Studies, Imperial College London and George Marsh, Future Energy Solutions.

Disclaimer: The material available on this website is designed to provide general information only. Whilst every effort has been made to ensure that the information provided is accurate, it does not constitute legal or other professional advice.
Please note: The Department of Trade and Industry cannot be held responsible for the contents of any pages referenced by an external link.