Revised Economic Assessment of CO2 EOR in Mature UK North Sea Fields David S Hughes (david.hughes@senergyworld.com) Carbon Storage Specialist Senergy Alternative Energy

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.

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)

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

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)

Size of CO2 EOR Prize Offshore UK oil in place 40-42 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

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 10-20 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

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

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

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

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%

Claymore CO2 EOR Economic Evaluation Sensitivity analysis (P30 case) Capital costs £1.1- 1.2 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 $50-120 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

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 2018-2043 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

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

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

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

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

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.”

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 (www.erp.ac.uk/sccs) and funded by both the Scottish Government and industry A summary of this study can be downloaded at http://www.scotland.gov.uk/Publications/2009/04/28114540/0 Permission to present this material is gratefully acknowledged Department of Energy and Climate Change (DECC) who have sponsored my visit here

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: www.senergyworld.com/training Previously presented in Perth, Canada, USA and on seven occasions in UK