House of Commons - Science and Technology

Select Committee on Science and Technology Written Evidence

APPENDIX 4

Memorandum from the British Geological Survey

EXECUTIVE SUMMARY

1. Underground storage of CO₂ is the critical path to decarbonising fossil fuels. Without public acceptance there will be no CO₂ storage. Most concern from the public, NGOs and regulators is the risk of leakage from geological storage. This concern needs to be balanced against the current situation of 100% "leakage" direct to atmosphere from fossil fuel emissions.

2. Storage integrity will be required for many thousands of years. Methods and best practice for site selection, characterization, risk assessment, monitoring and verification of the CO₂ in the subsurface are required. Leakage tolerance thresholds need to be defined for different fluxes and modes of leakage for the purposes of carbon trading, environmental protection, health and safety, and intervention/remediation strategies. Identifying these thresholds will require deliberate release experiments and study of natural CO₂ seeps.

3. Because of its hydrocarbon infrastructure, sedimentary basins and large point source CO₂ emissions, together with the need to modernise/replace power plants, the UK is well placed to lead, develop and take advantage of CCS. With the planned level of decommissioning of North Sea infrastructure over the next 15 years there is a brief time window in which to harness this offshore investment before it is lost.

4. CO₂ capture from natural gas streams and injection into oil fields, for enhanced hydrocarbon production are well-proven technologies that have been used extensively in the oil and gas industry for over 30 years, particularly in North America. There are over 70 such projects. CO₂ storage is a passive bi-product of these operations, only a few of which are being monitored for storage performance. Dedicated geological CO₂ storage is relatively new with only two large-scale industrial projects, worldwide (Algeria and Norway) injecting into in aquifers (since 1996 and 2004) at c 1Mt/year scale.

5. Storage estimates for oil and gas fields can be made relatively accurately. If CO₂ is injected as part of oil and gas production, there are no regulatory barriers for the UK.

6. Saline aquifers, principally offshore in the UK, offer even greater potential storage capacities, but estimating their capacity is more difficult. In addition, greater risks of possible leakage could be associated with these unproven "traps". Major research effort should be focused on improving these estimates. Regulation is unclear outside hydrocarbon production operations.

7. CO₂ capture from power plant, especially post-combustion, is the highest cost of the CO₂ capture and storage (CCS) chain. Significant efficiency improvements to the capture process would bring more opportunities to deploy CCS. Transport costs are dependent on the distance to storage and whether new or existing infrastructure is used. The most efficient transport is by pipeline. Costs for geological storage, including subsequent monitoring, are significantly less than capture.

INTRODUCTION

8. BGS is the national geological survey (www.bgs.ac.uk) and is a component body of the Natural Environment Research Council. Since 1992 BGS has been the UK's leading research centre on the geological storage of CO₂. It co-ordinates the European Research Network of Excellence (CO₂GeoNet) and is involved in the bulk of EC Framework projects on geological storage. BGS is closely involved with the DTI which recently launched the DTI/DEFRA Carbon Abatement Technology (CAT) Strategy. BGS participated in DTI missions to North America and Australia to assess the state of CCS technology there. It is also involved with the UKERC and TSEC joint research council initiatives. BGS ran the workshop on geological storage at the recent G8 energy research workshop and is on technical working groups of the US led Carbon Sequestration Leadership Forum (CSLF) and the IEA. BGS is also a member of BP's scientific advisory board. BGS has co-authored the forthcoming UN IPCC assessment report on CCS. The benefits of international collaboration, transparency and close involvement with stakeholders in developing CCS technologies have been at the core of BGS science strategy and delivery; a full project list is given in the Appendix.

9. BGS evidence, addressing each point raised by the Committee, will concentrate on underground CO₂ storage.

THE VIABILITY OF CCS AS A CARBON ABATEMENT TECHNOLOGY FOR THE UK

THE CURRENT STATE OF R&D IN, AND DEPLOYMENT OF, CCS TECHNOLOGIES

10. Research on underground storage focuses on improving storage capacity estimates and on developing technologies to monitor CO₂ both in the deep subsurface (in and around the storage reservoir), and also at the near-surface (should leakage ultimately occur). It is likely that for future large-scale implementation, a typical storage site will need to assess the risks of CO₂ storage to both humans and ecosystems over 5,000-10,000 year timescales. This will require careful, systematic, wide-ranging, transparent and auditable risk assessments, which demand an understanding of the processes that could affect site performance. Reservoir simulators, geochemical, and geomechanical models are used to predict these processes and their interactions, combining detailed site-specific geological models with generic data derived from studies of industrial-scale demonstrations, laboratory- and field-scale experiments, and natural analogues. Simulators and models for CO₂ behaviour are still in their infancy. More field trials at laboratory and industrial scale are needed to history-match and refine these tools. This will enable confidence with forward modelling and long term performance prediction. Also needed are a wider array of monitoring technologies with improved resolution and sensitivity. Tool testing, monitoring and verification at field-scale across the spectrum of geology, site conditions and ecosystems that could apply to storage operations is required.

CO₂ injection demonstrations and tests

11. Although there are numerous CO₂ injection operations associated with onshore-enhanced oil production (EOR; not CO₂ storage) in North America and, to a lesser extent, in Eastern Europe, few have been accessible to researchers. Projects in which the broad research community is involved include; Sleipner (Norwegian North Sea) where nearly 1Mt/year has been injected since 1996 into an aquifer; and an EOR project at the Weyburn oilfield (Canada) where over 2mt have been injected since 2000. In 2004, CO₂ injection into an aquifer started at InSalah, Algeria. Similar projects are also planned for Norway (2006), Australia (c 2009). Small-scale field laboratory aquifer storage pilots (<100Kt CO₂) have recently been conducted in Japan, and the USA. Further small pilots are planned in Australia, Canada, France, Germany and the USA. A pilot injection into a coal seam has recently been completed in Poland. In the Netherlands, a small pilot is injecting into an offshore gas field (K12b). The UK may have its first large-scale injection at the Miller Field, by 2009 (subject to commercial decisions by BP and its partners). Miller could become the first offshore CO₂ EOR project in the world.

12. Despite having very different reservoir properties and conditions, Sleipner and Weyburn have demonstrated that large-scale CO₂ injection is feasible. Monitoring operations at both sites show that the CO₂ plumes in the reservoir can be satisfactorily imaged using repeated 3D seismic techniques (similar to echo-sounding) and indicate that, at least in the short-term, site behaviour can be predicted with reasonable confidence. No leakage has been detected. Extending predictions into the longer-term and, in particular, well beyond the monitoring phase is more challenging and needs further research.

PROJECTED TIMESCALES FOR PRODUCING MARKET-READY, SCALABLE TECHNOLOGIES

13. It is technically feasible to deploy CCS at industrial scales now. Sleipner and Weyburn are examples where fiscal and regulatory regimes and technologies are in place with CCS operating commercially. CCS technology is market ready for pioneering implementation now in the UK. Technology improvement requires commercial scale projects to work with and learn from.

14. The low risk of leakage, in early projects, has to be balanced against the global impacts that will ensue if CCS is not made commercially viable; this is a matter for governments to address through policy, fiscal and regulatory initiatives.

COSTS

Storage costs

15. There are few published details of storage costs. They are field specific. Some details are available for Sleipner (Torpe & Brown 2004), which refer to the incremental cost of storage only. The capital costs were approximately US$96 million (based on a projected total storage of 25 MtCO₂ = US$3.8/tCO₂ stored) and the operating costs are approximately US$7 million/year (7US$/t stored) respectively. Therefore, total storage costs are about US$11/t (£6/t) CO₂ stored.

Monitoring costs

16. Monitoring costs are minor and have been estimated (Benson et al 2004) at 0.05-0.10US$/t of CO₂ stored (discounted at 10% per year), 0.16-0.31US$/t of CO₂ stored undiscounted, 2.7-5.4p and 8.7-17p per tonne CO₂ respectively.

Enhanced Oil Recovery

17. In many oil field conditions, CO₂ is miscible with oil and can be injected to enhance oil recovery (EOR). There are over 70 CO₂ EOR projects in North America. CO₂ storage is a passive bi-product of these operations. Offshore EOR using CO₂ has not yet been deployed and costs and risks would be higher. Economic viability is field specific, dependent on the oil price, supply of CO₂, re-engineering costs of existing infrastructure and tax regime. Costs will be higher offshore because of the larger capital and operational investment needed.

GEOPHYSICAL FEASIBILITY

18. Geophysical techniques are feasible for CO₂ monitoring and verification, as part of a technology portfolio including geochemical, remote sensing and biological monitoring techniques that include invasive and non-invasive deployment. There is a need to improve sensitivity and resolution as well as discover limitations and appropriateness. Some technologies will apply to all sites; others will be site specific.

OTHER OBSTACLES OR CONSTRAINTS

19. Major issues connected with large-scale deployment of CCS in the UK include, large initial capital investment, ultimate useable storage capacity, possible environmental impacts and regulation.

Storage capacity

20. Many of the deep reservoir rocks (porous rock formations) of the UK are suitable for the large-scale underground storage of CO₂. There are opportunities for CO₂ storage in hydrocarbon fields (producing and depleted), other saline water-bearing reservoirs (saline aquifers) and possibly, to a minor extent, in coal seams. Storage potential lies mainly offshore beneath the UK continental shelf, although niche opportunities may exist onshore.

Storage in oil and gas fields

21. Hydrocarbon fields have entrapped buoyant fluids for periods up to millions of years. Because of exploration and production activity, they are geologically well characterized and their reservoir properties are well understood. The main risk issue with CO₂ storage in hydrocarbon fields is the possibility that CO₂ may eventually leak upwards along pre-existing exploration and production wells.

22. The CO₂ storage capacity of UK hydrocarbon fields can be assessed with reasonable accuracy because the field data is in the public domain. However, not all of the theoretical storage potential could necessarily be exploited economically.

23. Provisional figures are as follows for the UK (excluding gas and condensate fields for the central and northern North Sea which have yet to be calculated):

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et al

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24. With the exception of Wytch Farm, onshore fields are too small for significant CO₂ storage. However, some could be suitable for testing or feasibility trials.

25. Reservoir simulation is required to make more accurate storage calculations on a field-by-field basis, particularly of the amount of CO₂ that could be stored by EOR. This is a function of geology and individual field economics and will be investigated by the UK Carbon Capture and Storage Consortium (UKCCSC) over the next three years.

Storage in saline aquifers

26. The CO₂ storage capacity of the UK deep saline aquifers is more uncertain than that for hydrocarbon fields, and should be the subject of major further research. Aquifer storage likely represents the bulk of the available UK storage capacity (possibly, together with Norway, the largest capacity in Western Europe), but there is no standard methodology for calculating it from the sparse public domain data available. BGS has provisionally estimated the CO₂ storage capacity of saline water-bearing reservoir rocks in closed structures around the UK as follows:

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et al

27. No recent estimate has been made for the Central and Northern North Sea basins or other parts of the UK Continental Shelf such as the English Channel Basin. An estimate of 250Gt was calculated in the BGS led Joule 2 (1995) Project for all the aquifers (open and closed) in the UK North Sea. With UK emissions at over 0.6Gt/year, a third of which comes from power generation it is clear that even if only 10% of this capacity was realized it would serve the UK's needs to beyond the period of fossil fuel dependency.

Knowledge of potential impacts

28. The generic knowledge that underpins our ability to make long-term predictive risk assessments is far from complete and many issues are, as yet, poorly understood (West et al 2005). A particular challenge is to assess the localised impacts of CO₂ leakage on ecosystems. One way is to study natural accumulations of CO₂ where this has remained underground for thousands to millions of years or, in some cases, reached the surface.

29. Industrial demonstration projects associated with hydrocarbon production are unlikely to leak during operational life, and any short-term, transient leak would be remediated as part of routine operations. These projects are generally not appropriate to develop and test the models used in risk assessment to predict leaks and their impacts. Short-term but well-constrained deliberate release laboratory and field experiments, and longer-term but less well constrained natural analogues can provide ideal opportunities to assess our ability to demonstrate long-term safety and risk.

Well performance

30. Another key issue for long-term safety is the ability of wells to retain their sealing integrity. CO₂, in the presence of moisture, can attack the cements and metals used in well completions. While modern wells are designed to minimise these problems, pre-existing wells will have used traditional completion materials. If the well integrity fails, then it could provide a route for the buoyant CO₂ to escape.

Regulation

31. Unlike North America, the UK does not have a history of gas disposal via wells. In the USA there are over 400 acid gas injection operations into deep saline aquifers, all carried out under EPA jurisdiction. Appropriate regulation for CO₂ storage is not in place here, outside hydrocarbon production and related operations. Underground natural gas and hydrogen storage is conducted in the UK within a regulatory framework.

32. Regulations for storage may be needed to avoid conflicts of interest between CCS and other activities, both underground (mining, hydrocarbons, groundwater) and at the surface (land use, ecosystem and public protection).

33. The IPCC and the European Emission Trading Scheme (ETS) are both evaluating how CCS may be regulated in order that avoided CO₂ emissions are counted in national allocations and recognized within carbon trading regulations.

34. Considerable uncertainty remains over environmental regulation and CCS. Members of the OSPAR and London Conventions are considering this. Current legislation is being examined at the European (DG Environment) and UK (DTI/Defra/EA) levels to see how it might interact with CCS activities and if there is a need to develop additional regulation.

35. As part of its recent Technology Status Review (TSR) for the DTI (Report URN05/103), the BGS suggested some regulatory models for consideration during the lifecycle of a CO₂ storage operation.

THE UK GOVERNMENT'S ROLE IN FUNDING CCS R&D AND PROVIDING INCENTIVES FOR TECHNOLOGY TRANSFER AND INDUSTRIAL R&D IN CCS TECHNOLOGY

On average DTI has invested c £50k/year in BGS-driven CO₂ storage research over the last 10 years. This has been to support BGS involvement in EC Framework Projects

Other DTI expenditure (costs not known to BGS).

DTI is supporting Heriott Watt University as part of a project to examine the feasibility of CO₂ storage in scottish coals. This project is also receiving support from the Scottish Executive.

A budget of £20 million has been allocated to DTI for the period 2005-08, with a further £40 million from 2006-10 to fund CATs. It is not yet decided how much of this will be apportioned to R&D in CCS (the CAT programme also includes hydrogen, fuel cells, biomass co-firing and power plant efficiency R&D).

UK Research Council funding on CCS

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— UKERC- BGS is expected to receive £112k from 2005-10 from UKERC to support its "Carbon Management" sub-theme. BGS does not know how much of UKERC's overall budget applies to CCS.

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— EPSRC grants for CCS amount to £103k for FY05-06.

Other UK Government Investment in CCS

In 2005 Heriott Watt and Edinburgh University were awarded £1.4 million over four years to form the "Scottish Centre for Carbon Management". BGS is collaborating at its own cost.

September 2005



© Parliamentary copyright 2006	Prepared 9 February 2006