1. Revised Economic Assessment of CO2 EOR in Mature UK North Sea Fields
David S Hughes
Carbon Storage Specialist
Senergy Alternative Energy

2. Summary
The UK Government has decided that no new coal-fired power stations will be sanctioned unless they are fitted with Carbon Capture and Storage (CCS) on at least 300 MW of the electrical output. In the longer term the government plan the decarbonisation of all coal fired plant when it can be demonstrated that CCS is a proven technology and all gas fired plant subsequently. Such a programme would require initially around 2 million tonnes (from the first 300 MW pilot) per year but likely rising to above 100 million tonnes per year by 2035 of CO2 to be captured, transported and geologically sequestered.
The storage options include depleted NS oil and gas fields and deep saline formation beneath UK territorial waters. However, there has been a long held view by some proponents that the availability of CO2 in these quantities would stimulate its use for enhanced oil recovery (EOR) in mature NS fields thereby producing additional revenues to partially offset the costs of implementing CCS. EOR using predominantly natural CO2 has been both a technical and economic success in West Texas and other places in the USA, Canada and worldwide but has never been applied offshore. This presentation will compare and contrast the issues around implementing CO2 EOR offshore compared with onshore and present the results of a recent economic analysis looking at the implementation of CO2 EOR in a single mature NS field and in a cluster of fields.

3. Background
UK Government committed to decarbonising UK electricity supply as part of its CO2 emissions reduction strategy (by at least 34% by 2020 and 80% by 2050 – from 1990 base)
Carbon capture and storage at coal fired power stations is beginning in the UK with a 2 million tonne per year trial (from 2014)
Longer term (2030s) once CCS becomes proven technology the amount of CO2 captured will likely exceed 100 million tonnes per year
For the storage part of the CCS chain offshore depleted oil and gas fields are being considered as well as saline aquifers
With oil fields there is the opportunity to use the CO2 for enhanced oil recovery (EOR)

4. Geographic Information System for CO2 Sources and Sinks (GESTCO)
Red blobs where CO2 being vented today mainly from power generation
Either build new plant with capture at these locations or possibly retrofit existing plant with capture
Develop both onshore and offshore pipeline infrastructure making use of clusters of point sources
Opportunities for CO2 storage in gas fields mainly in SNS and nearer to English sources and for EOR in oil fields nearer Scottish sources (Scottish sources underestimated in this figure main blob at Longannet should be bigger). Also CO2 could be brought northwards to CNS and NNS for EOR by pipeline.
BGS February 2005

5. Issues Around Using CO2 for EOR in North Sea
Using CO2 for enhanced oil recovery (EOR) in UK North Sea oil fields is often held up as an opportunity to kick start the UK carbon storage industry
True that supercritical CO2 is a good solvent and at the pressures and temperatures found in North Sea reservoirs can flush remaining oil from rocks
But no offshore applications of CO2 EOR
Even onshore only amounts to one third of one percent of worldwide oil production although now expanding rapidly
Also often mentioned that CO2 can be stored in our old oil fields
But nearly all have been developed by water injection with an approximate balance between amount of water injected and the amount of oil and water produced
So not opportunity for storage-only in oil fields
But gas fields developed by pressure depletion are the leading hydrocarbon field candidates for early storage projects
But most perceived capacity is in saline water bearing formations (aquifers)

6. Size of CO2 EOR Prize
Offshore UK oil in place billion barrels, recovery to date 24 billion barrels from 220 fields
16 billion barrels from top 30 fields
DECC estimates of UK offshore CO2 EOR potential
up to 1 billion barrels incremental oil
up to 0.5 billion tonnes of CO2 stored
EOR potential very sensitive to window of opportunity
Fluctuating oil price means that COP date highly variable
More difficult to redevelop fields with CO2 injection after they have been decommissioned

7. CO2 EOR Onshore vs. Offshore
Onshore Advantages
CO2 supply network
High well density, pattern flood, relatively cheap to redrill/refurbish
Relatively low secondary oil recovery (35-45%)
Phased implementation
Large surface area available for facilities
Offshore Challenges
Limited CO2 supply at present but significant quantities likely to become available on year timescale
Fewer wells, peripheral flood, expensive new wells and workovers
High secondary oil recovery (50-70%) therefore smaller target
Single implementation (i.e. no chance to introduce the project in phases)
Existing facilities mainly incompatible with high CO2 content in fluids
Limited weight and space for new facilities

8. Offshore CO2 EOR Implementation (Capex)
Additional ~20 years from existing facilities
CO2 reception facilities and controls
Flow lines to injectors (CO2 and water) and control valves
Gas/liquid separation facilities capable of handling high content CO2 in produced fluids
Separation of CO2 and hydrocarbon gas (or just separate enough for fuel gas)
Dehydration and compression of produced gas for reinjection
Start-up CO2 pumps
Production well tubing needs replacing with stainless steel (to deal with produced CO2)
Baseline measurements for subsequent monitoring

9. Targets for CO2 Injection (SPE 78298)
Oil trapped under shales
Attic oil
Only partially swept by water
Waterflood residual oil

10. Single Field and Cluster CO2 EOR Evaluations
Earlier screening study suggested Claymore is leading candidate for single field evaluation
Around 1450 MMstb initially in place, around 46% recoverable from peripheral waterflooding (initial pressure and temperature ~3800 psi and 170°F)
Scott and Buzzard were identified from screening as other possible candidates and together with Claymore comprise the cluster
Scott has around 950 MMstb initially in place, around 47% recoverable but is deeper and hotter than any CO2 project to date
Buzzard has around 1100 MMstb initially in place, around 50% recoverable but not clear that the CO2 would be miscible
Scott pressure 8600 psia and temperature 219 F
Buzzard pressure 4630 psia and temperature 232 F

11. Claymore CO2 EOR Evaluation
Oil Recovery Rate
CO2 miscible with reservoir oil at current operating pressure
Incremental oil recovery profiles constructed for 70% probability (1/7th remaining oil) and 30% probability (1/5th remaining oil)
Incremental oil 119 million barrels (8% of oil initially in place) for P70 and 163 million barrels (11% of oil initially in place) for P30
CO2 delivered 49 million tonnes
CO2 recycled 152 million tonnes
Begin 2017 end 2043
CO2 Injection Rate
OIIP 1439 MMstb, Waterflood 46%

12. Claymore CO2 EOR Economic Evaluation
Sensitivity analysis (P30 case)
Capital costs £ billion (new auxiliary CO2 platform, adaptation of existing platform, well upgrades, baseline monitoring)
Operating costs £90 million per annum (include requirements of measurement, monitoring and verification programme)
Price assumptions
Oil £50 ($70) per barrel
CO2 neither cost nor subsidy
Discounted cash flow gives internal rate of return 12-16% (before tax)
Unrisked
$ per barrel
€ -50 (cost) to €100 (subsidy) per tonne
±20%
±20%
Oil and CO2 prices subject to market forces
Project economics can be improved by reducing capital costs and risks associated with converting facilities and wells

13. Cluster CO2 EOR Evaluation
Oil Recovery Rate
CO2 is miscible with reservoir oil at current operating pressure in Scott; more problematic in Buzzard
Incremental oil 237 million barrels for P70 and 331 million barrels for P30
Spread over
CO2 delivered 155 million tonnes at around 11 million tonnes per year for 13½ years from 2017
CO2 injection starts in Claymore and Scott in 2017 and in Buzzard in 2024
Delivered CO2 Requirement
11 million tonnes/year

14. Cluster CO2 EOR Economic Evaluation
P70 Cluster Discounted Cash Flow
Price assumptions
Oil £50 ($70) per barrel
CO2 neither cost nor subsidy
Discounted cash flow calculations give internal rate of return 13-18% (before tax)
Unrisked
Oil price $50 to 200
IRR 7% - 33% P70
IRR 12% - 40% P30
CO2 cost/subsidy €-50 (cost) to €100 (subsidy) per tonne
IRR <0% – 38% P70
IRR 6% – 41% P30
IRR Sensitivities
Capital costs for converting facilities at Scott estimated at £1.2 billion and at Buzzard £700 million (total including Claymore £3.1 billion)
Operating costs estimated at Scott £45 million per annum and at Buzzard £55 million per annum

15. Conclusions from Single Field and Cluster EOR Evaluations
Contrary to many expectations most North Sea oil fields cannot be used solely for CO2 storage because produced fluids have been replaced by water
The redevelopment of a mature North Sea field for CO2 EOR is a major undertaking equivalent in complexity, scale and cost to the original development
Each project will need to be the subject of detailed engineering design and economic appraisal including a full assessment of the risks
Unrisked CO2 EOR may be viable in the North Sea fields at an oil price of $70 per barrel or above
Taking risks into account, it is unlikely that CO2 EOR will viable in North Sea fields at an oil price less than $100 per barrel
If a subsidy is available for the CO2 stored then the project could be economic at an oil price significantly lower than $100 per barrel
CO2 EOR has never been applied offshore so early projects will carry significant additional technical and financial risks
Development of a CCS infrastructure in the UK could lead to the application of CO2 EOR in some fields

16. EOR vs. Storage
Around 85% of oil is carbon, around 75-80% of gas is carbon
If burned, a barrel of oil (30°API) would release around 0.4 tonnes CO2 and the associated gas 0.02 to 0.1 tonnes
Net CO2 injected to produce an incremental barrel of oil ranges from 0.25 to 0.8 tonnes (the lower value corresponds to when WAG is used, higher value for continuous CO2 injection)
BUT net CO2 stored is less
Energy is consumed separating CO2 from produced gas, and dehydrating and compressing it for reinjection
This energy has associated CO2 emissions which need to be accounted for
Little Creek, Mississippi
Dimensionless oil recovery
Incremental recovery factor as % of original oil in place
Figure from Denbury Resources Inc presentation, 12th Annual CO2 Flooding Conf, Midland, Tx, Dec 2006
CO2 injected in hydrocarbon pore volumes

17. So what does the future hold in UKCS?
Supply of CO2 will develop from CCS
Initial offshore projects will be storage only, but proximity and availability of CO2 likely to provide niche opportunities for EOR initially possibly in the smaller fields
If successful, redevelopment of larger mature (and abandoned?) fields may occur
New specialist CO2 operators may emerge
Once EOR phase complete some extra opportunity to store additional CO2 in ‘pressure space’ between operating pressure and original pressure
Adjustment of tax regime may be needed to make offshore EOR economic
Regulation around CO2 storage will be significant burden (CO2 is being both injected and produced)
Higher risk than conventional projects
Multi-national operators have international portfolio of projects
Higher oil price improves economics of CO2 EOR projects but also improves the economics of more conventional projects

18. Nothing’s New!
In 1977 Prof. George Stewart of Heriot-Watt University was the first person to consider the use of EOR in UKCS fields. His study was funded by the then Department of Energy (now DECC)
The conclusion of his report states: “Carbon dioxide miscible flooding is concluded to be the potentially most promising EOR technique for offshore application. The provision of the very large amounts of CO2 necessary for substantial enhanced recovery is technically feasible; in the long term the combustion of coal to provide electrical energy, low-grade heat and pure carbon dioxide for EOR may be the most attractive approach to an integrated energy and hydrocarbon resource policy.”

19. Acknowledgements
The single field and cluster economic evaluations presented were undertaken by Senergy Alternative Energy as part of the “Opportunities for CO2 Storage around Scotland an integrated strategic research study” coordinated by the Scottish Centre for Carbon Storage ( and funded by both the Scottish Government and industry
A summary of this study can be downloaded at
Permission to present this material is gratefully acknowledged
Department of Energy and Climate Change (DECC) who have sponsored my visit here

20. Senergy CO2 Storage Training Course
One day training course Introduction to the Geological Storage of Carbon Dioxide (CO2) Tuesday 29th September 2009 Mantra on Little Bourke, Melbourne Course outline and registration at: Previously presented in Perth, Canada, USA and on seven occasions in UK