Hugh Sharman

IntroductionThe North Sea is among the most important oil and gas producing provinces in the World.  During the past thirty years, the extraction of these reserves has brought enormous benefits to the host countries, oil companies, suppliers, technology providers and the treasuries of the host nations.  At $25/bbl, oil from the North Sea is currently producing daily revenues of about $145,000,000.  To this should be added the considerable revenue from gas.

Output of oil from the North Sea Basin is cresting in the three main, producing countries, UK, Norway and Denmark.  The UK is now in its second year of production decline.

During the next ten years, unless heroic efforts are made to maintain output, the flow of oil will be halved.  The data base of Oilfield Publications shows that of the 128 large oil fields studied in this paper, at least 3 have already been decommissioned while no fewer than 35 are due to be decommissioned by 2010.  Among the latter are Brent, Embla, Fulmar, Gyda, Fife, Murchison, Siri, Statfjord North and East, Thelma, Thistle, Toni, Tor and Veslefrik. The increasing rate of decommissioning serves to emphasise that the present decade presents the best opportunity to roll out a CO2 EOR infrastructure, extending field life and recovering hydrocarbons that otherwise would be abandoned, whilst securely storing CO2 emissions away from the atmosphere. This same infrastructure (with its capital paid for during hydrocarbon production) could also be used beyond field life for dedicated CO2 storage.

According to a joint announcement made by the energy ministers of Norway and UK at Offshore Northern Seas in Stavanger, in August, 2002, the cost of decommissioning oilfields up to 2010, alone, is estimated to be $3.3 billion.  There is no off-setting revenue for this expenditure.

Other unwelcome consequences arising from the rapid fall of production include:• Dependence, after many years of being energy self-sufficient, on oil and gas from countries, some of which are notoriously unstable, all outside Europe, at a time when a growing number of industry experts foresee that World oil demand will be rising ahead of production. • Increased dependence on energy imports will raise balance of payment deficits, especially during periods of high energy prices. • Loss of many well paid jobs, as well as the need for oil towns like Aberdeen, Stavanger and Esbjerg to “re-invent” themselves. • Without tertiary recovery, the permanent loss of roughly half the unrecovered oil that is left in the ground, after decommissioning.

The “CO2 for EOR in the North Sea” (CENS) project is the name given by its developers to an ambitious plan for bringing anthropogenic CO2 from factories and power stations around the North Sea Basin to depleted oil fields, mainly in the UK, Norwegian and Danish sectors for enhanced oil recovery.Virtually all the CO2 used for enhanced oil recovery will be permanently sequestered.

Project DescriptionThe technical and financial feasibility of the project relies, to some extent, upon the way in which most of the North Sea’s oil reservoirs, coloured green on the map, are clustered.

A trunk pipeline up the Norway/UK median line would bisect important, mature, oilfield clusters from the south (Ekofisk and Fulmar) to the north (East Shetland Basin, called “Tampen” in Norwegian). All the way, from the south to the north, there are many oilfields which are close to the median line, both west and east of the proposed trunk pipeline.  There are also major oilfield “clusters”, such as the Scapa and Brage/Oseberg clusters that can be accessed by large, branch pipelines.

There are few significant, stationary CO2 sources in Norway.  However, there are at least two which, further to confirmatory studies, could supply CO2 competitively into the pipeline.   Additionally, some large-scale, natural gas based, industrial projects are planned.  These are mandated to be "CO2 neutral". If these can be realised before the end of this decade, Norway could become a significant CO2 supplier to the project, as well as a major beneficiary of the incremental oil.

There are many existing, large scale CO2 sources in the UK and Denmark, of which some of the most important are accessible to the North Sea.  Thus the developers have modelled two main feed lines, one from the west coast of Denmark and the other from the east coast of the UK.  These would deliver most of the 30 – 40 million tonnes per year required for the recovery of 90 – 120 million incremental “CO2” barrels of oil per year.

Historically, the CO2 received from a CO2 infrastructure is used many times, as co-produced CO2 is separated from the hydrocarbons, dried, liquefied and re-injected.  The base case in the CENS project assumes that this will again be the case.  Were this so, the sponsors are conservatively estimating that each tonne of freshly injected CO2 will return 3.17 barrels of “CO2” oil.  This article refers to CO2 brought to the oilfield and injected, as “fresh” CO2.  Current thinking is that once the residual oil has been extracted, the wells will be capped and the CO2 permanently sequestered (as a value is expected to be placed on CO2 left in the ground).

If the capacity of the infrastructure is sufficient and the legal issues are resolved, in some cases it might be more economical to simply dispose of CO2-rich, breakthrough gas into deep aquifers for long-term storage rather than to separate the CO2.  This might occur in gas-lean reservoirs or at the end of EOR production when gas processing is expensive in relation to simple sequestration.

If sufficiently large CO2 supply contracts can be signed at the early stages of the project, these might justify the construction of the south to north transport “spine” and the CO2 supply feeders illustrated, diagrammatically, at the beginning of this section. 

If, on the other hand, the project is begun by supplying relatively few, small floods, the project could be started by the delivery of CO2 by ship and developed by “joining floods” in a manner diagramatically illustrated by the following sketches.

There are different schemes for flooding a reservoir with CO2. The optimal injection strategy will depend on the geological properties of each field, the physical properties of the oil, reservoir temperature and pressure, and how the field has been developed. The most widely used technology is to stabilise the CO2 flood by alternating injection of CO2 and water in the same well (WAG).

However, if the value of sequestered CO2 is sufficient, there will be cases where gravity stable gas injection will be more profitable.  In this case, there will be a delay in the appearance of incremental oil.  On the other hand, the amount of incremental oil recovered will increase as will the amount of CO2 which it is possible to sequester.  A significant number of oilfields in the North Sea are technically suitable for this. 

There is a companion article about this in this issue of the SHARP IOR eNewsletter (CO2 Flooding in UKCS Reservoirs).  See also www.dti-sharp.co.uk/dissemination/openreports/ UKCS_cap_paper_02.pdf.

CO2 injection has been applied successfully in the West Texas Permian Basin (see next section - Developers).  The table below presents a comparison of geology, reservoir and fluid properties for the Permian Basin and the North Sea.

Developers

KMCO2 owns and operates much of the 1,200 km CO2 infrastructure which delivers around 22 million t per year of CO2 to about 70 floods in the West Texas Permian Basin.  The CO2 is sourced from natural CO2 domes in Colorado (the McElmo Dome) and the Bravo Dome in New Mexico.

Around 175,000 “CO2” barrels per day are produced from this infrastructure in the Permian Basin. On an historical note, KMCO2 is a successor to Shell CO2 and inherited the large scale infrastructure which was built during the early 1970s under fiscal conditions reflecting anxieties about energy security which are relevant to those in Europe today. Additionally, in 1999, KMCO2 bought and now operates the giant SACROC oilfield, raising production from 8,000 barrels per day in 1999 to almost 16,000 barrels per day at the end of 2002.

KMCO2, as the World’s largest and most experienced owner and operator of CO2 infrastructure, brings a unique, practical perspective to the CENS project.

ELSAM A/S is the largest generator of electricity in Denmark.  It owns six central power stations in West Denmark, all of which also deliver district heating to their local communities, giving a winter fuel utilisation of up to 93%.  Of these, five are coal-fired and one gas fired. The two built most recently, are also the most thermally efficient, condensing, steam power plants in the World at 47% (LHV coal) and 49% (LHV gas).

ELSAM also owns 19 decentralised CHP plants and has just commissioned the first, large, offshore wind farm in the World, at 160 MW.  ELSAM can deliver a peak electrical output of 3,500 MWe.  In recent years, ELSAM’s CO2 emissions from its central power stations have been in the range 9.5 – 12 million tonnes/y.  The concentration of CO2 in the flue gas is typically 12 – 14%.  This contrasts favourably with the flue gas from a combined cycle gas turbine plant where the concentration of CO2 is in the range 3 – 4%.

All ELSAM’s power plants are fitted with flue gas cleaning equipment to meet and exceed the requirements of the international authorities.  Thus its plants are among the most suitable power plants anywhere for retrofitting conventional, amine scrubbers that will remove up to 93% of the CO2 emitted.  After retrofit, ELSAM’s coal-fired units will emit environmentally harmless water vapour, nitrogen and only small quantities of CO2.

CO2 - Costs, Prices, Fiscal Measures and the Value of Sequestration

Extensive studies have been undertaken by ELSAM to establish the cost and a commercially attractive selling price of dry, liquid CO2 at the boundary of the power station such as the plant at Esbjerg, illustrated in previous section - Developers.  These show the price of CO2, leaving the power station boundary in Denmark, at somewhere between $23 and $25 per tonne. 

These prices are similar to those estimated for certain UK sources.

KMCO2 has performed studies for various configurations of pipeline and transport.  These show that the amortisation of the pipeline, its operation and the energy costs of transport add up to roughly $10 per tonne delivered at a “postage stamp” price. That is to say, the present, simplified postulate is that gas is delivered anywhere in the system at a single price. Thus, while the business develops, the CENS sponsors are quoting a delivery price at the platform of roughly $35/tonne CO2.

The current average price of CO2 at oilfields in the Permian Basin is about $15/tonne.  With a recovery rate of 3.3 barrels per tonne of “fresh” CO2, the CO2 cost of a “CO2” barrel is $4.55.  It should be noted that CO2 at this price supports a thriving oil producing industry at a market price of $18/bbl oil.  Higher prices for oil have recently increased demand for CO2.

At $35 per tonne, the CO2 cost to a producer in the North Sea of an incremental, “CO2” barrel would be roughly $10.61.  This cost would not leave enough to cover all the other costs of investment and production, using CO2.  However, the strong likelihood that buried carbon might have a higher value than the suppliers' price at the platform could result in disruption to traditional thinking.

The developers have always recognised that if the gas cost is not offset by the value of its permanent removal from the atmosphere, the project would be unviable.  Therefore, from the first, they have engaged in dialogue with the Governments of Denmark, Norway and the UK, all of which are aware of the CENS project and its possibilities. 

These governments are engaged in a genuine effort to meet their exacting Kyoto commitments.  Nevertheless, of the three, only the UK is currently “on track”, although CO2 emissions in the UK have now been rising for the last three years (2002-2003). 

Denmark and Norway are out of compliance and have not yet announced any clearly defined pathway toward compliance.

Accordingly, the CENS project, with its potential ability to bury on average 30 – 40 million tonnes per year, which can start during the Kyoto 1 period and reaches apogee during the early years of Kyoto 2, should encourage these three governments, backed by the EU, to devise and implement fiscal measures which will make the project viable to all participants.

The conclusion of many experts is that the EU-15 will have great difficulty in collectively meeting its obligation for an 8% reduction in greenhouse gas emissions in a timely manner.

The EU-15 obligation amounts to a reduction of 336 million t/y CO2 equivalent.  Actual CO2 emissions fell by just under 0.5% between 1990 and 2002, or just 17 million t/y. This is a massive 319 million t/y short of the target.

Furthermore, it is the EU’s intention that reductions during Kyoto 1 are just the beginning.  By 2012, the EU-15 must be demonstrating larger and deeper cuts throughout “Kyoto 2”.  This will not be credible, if it struggles to meet the fairly modest targets set during Kyoto 1.

Therefore, in order for the EU 15 to achieve their Kyoto obligation, on time, and without economic pain, during the few years left to the end of Kyoto 1 (2010), many efforts using a variety of options will have to be made.  There is no single "magic bullet". 

These options will include further energy conservation in homes, offices and factories, more efficient transport, and alternative methods for space heating, industrial steam raising and electricity generation as well as increasing renewable energy generation. 

For the UK, any emission gains from its ambitious renewables targets could be offset by decommissioning of nuclear power plant. With the EU’s ageing power plant infrastructure ( e.g. by 2005 over 30% of electricity generating plants in the UK will be more 30 years old) the next 10 years offers an excellent opportunity to build new replacement plant more suited to CO2 capture. 

Of all the major sequestration projects presently mooted for Europe, only the CENS project appears to have the potential to return a “net profit”.  At a macro-economic level, the net income could exceed all capital and operating costs by a comfortable margin (with oil at $20/bbl and over).  All this can be realised when there is a recognised value for sequestered CO2.

This will require, at least, that the EU shall approve sequestration through EOR as an emission reduction measure, prior to 2005, in order to save many fields from decommissioning prior to 2010. If this happens, the newly passed EU directive on emissions trading would help create a value for sequestered CO2 and could create a long term, contractual structure  for emission credits.  In turn, these contracts would enable CENS-like projects to raise sufficient project financing for implementation. 

If the sequestered CO2 attracts credits in the €20 - 50/t range, the oil operators could effectively enjoy “near free” delivery of CO2 at the platforms.

Most industry estimates for the cost of CO2 avoidance, including sequestration, easily exceed $35/t, as shown in the often quoted chart, reproduced below.  In this, the Professor Strömberg estimates the approximate effects and costs that various CO2 reduction measures will have for meeting the EU’s Kyoto commitment, after the "low hanging fruit" of energy efficiency has been plucked.  In the same chart, the costs of these various measures are roughly estimated.

Already, the Norwegian Government taxes oil operators in that sector at the rate of $35/t and at Sleipner has accepted underground injection of CO2 as an emission avoidance option since 1996 (http://www.ieagreen.org.uk/ and www.statoil.com ).

Fiscal Measures to Encourage Security of Supply

EU energy projections (Green Paper on Energy and Security of Supply to 2020, http://europa.eu.int/comm/energy_transport/doc-principal/pubfinal_en.pdf) show a significant, continuing dependence on fossil fuels against a backdrop of growing energy demand with approximately one third of emissions resulting from electricity generation.

So fiscal measures addressing security of supply could also play an important role in stimulating a CO2 EOR infrastructure. Security of supply has several advantages.

• It increases non-OPEC production thus weakening OPEC’s ability to dominate and swing the oil price. • Indigenous energy production has a positive effect on the EU’s and national balance of payments and currency strength, especially during times of high oil prices. • It can help protect countries from interruptions of supply.

The USA has recognised the value of security of supply since the “Oil Crisis” in the early 1970s. Measures brought in since then, especially the Crude Oil Windfall Profit Tax Act of 1980 greatly assisted the growth of CO2 EOR in the USA and its associated infrastructure.

The legislation preferentially taxed some EOR project profits at 30 %, compared with a conventional crude oil profit tax of 70 %. Section 43 of the Internal Revenue Code provides taxpayers an enhanced oil recovery (EOR) credit equal to 15 % of their qualified EOR costs. Section 43 was a part of the Omnibus Budget Reconciliation Act of 1990, which made several changes to capital cost recovery methods. The Section 43 credit is phased out if oil prices rise above a certain level, i.e. $28 per barrel (in 1991 dollars)  In order to be eligible for the credit, the taxpayer must employ certain tertiary recovery methods, such as miscible fluid replacement, carbonated water flooding, miscible floods and immiscible carbon dioxide replacement.

The UK government has recognised the need to support continued development and investment into mature North Sea fields. In the Autumn Statement (2002) it announced that royalty payments will be abolished with effect from 1 January 2003. This decision recognises the important contribution that mature fields can make to the future of the North Sea and will deliver a significant boost to companies investing in these fields. The UK Government through the DTI’s cleaner fossil fuels programme is presently conducting a review into the feasibility of CO2 capture and storage in the UK, with CO2 EOR being part of this review (http://www.dti.gov.uk/energy/coal/cct/CO2capture.shtml )

The use of CO2 for EOR is a proven industry practice for tertiary oilfield production.  The use of anthropogenic CO2 for EOR has the added benefit of reducing CO2 emissions to the atmosphere.  Mechanisms like CO2 credit trading systems are being put in place that will help set a value for sequestered CO2.  Modification to other fiscal policies also may be necessary to encourage the introduction of this practice before the infrastructure of certain, old, large oilfields are decommissioned and remaining oil is left behind for ever.IJ

Hugh Sharman

This article was first published in the IOR Newsletter, http://ior.rml.co.uk/