Memorandum from the British Geological
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
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
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.
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
OF CCS AS
R&D IN, AND
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
CO2 injection demonstrations and
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.
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.
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$11/t (£6/t) CO2 stored.
16. Monitoring costs are minor and have
been estimated (Benson et al 2004) at 0.05-0.10US$/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
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.
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.
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
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
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):
Oil and gas fields of the East Irish
Sea (between the Isle of Man and Lancashire and North Wales coasts):
1Gt of CO2 (Kirk in press)
Gas fields of the South North Sea
(between the straits of Dover and Newcastle upon Tyne): 3Gt of
CO2 (Bentham in press, Holloway et al in press)
Oil fields of the Northern and Central
North Sea: 0.7Gt of CO2 (Balbinski 2001)
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:
East Irish Sea Basin: up to 0.63Gt
of CO2 (Kirk 2005)
Southern North Sea Basin: up to14.25
Gt of CO2 (Brook et al 2003, Holloway et
al in press)
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.
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.
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
FUNDING CCS R&D AND
INDUSTRIAL R&D IN
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
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
UK Research Council funding on CCS
TSEC, NERC, ESRC and EPSRC are currently
supporting the UK Carbon Capture and Storage Consortium through
their TSEC programme (BGS is a participant). This Consortium (http://www.co2storage.org.uk/)
is undertaking a CCS project that will run from July 2005-June
2008. Funding is approximately £2 million spread amongst
14 UK institutes and universities.
Tyndall Centre. BGS received £55K
between FY2002/3-5/6 from the centre's "Decarbonising Society"
Thematic Programme to support its research into CO2
storage. BGS does not know how much of the Centre's resources
apply to CCS.
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.
BGS (NERC) BGS has been investing
an average of £350k (FEC) per year of its own Science Budget
in CCS research since FY2000-1. This has risen to over £500K
(FEC) this year. Future investment at this level is uncertain
because of NERC's financial settlement in SR2004. The bulk of
BGS' spend is to align with, and co-ordinate, CO2GeoNet.
EPSRC grants for CCS amount to £103k
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