There have also been numerous screening studies undertaken to assess the scope to use CO2 as a miscible gas for EOR on the NSCS; however, few of these are available in the public domain. These studies have provided some useful insights regarding barriers to implementation, described below from the perspective of the operator:
- Oil price assumptions – studies previously assumed an oil price in the range from US$14 to US$17.50 per barrel (BBL) and have recently considered prices in the range of US$20 to US$25 BBL. Governments are not at risk of committing large capital sums for EOR projects and can afford a different view on oil price. With the 10-year forward price curve on Brent crude in excess of US$37 BBL, Governments can be assured that fiscal incentives will be funded from incremental taxation from incremental EOR produced oil.
- Alternative options – while many mature field operators have chosen to extend water flooding, blow down the field or use hydrocarbon gas for miscible injection; if the right incentive mechanisms were implemented, it is not too late to reconsider CO2 for EOR.
- Project cash flow – a major objection to CO2- floods by operators in the US and Canada has been the relatively high initial investment and CO2 costs coupled with a possible long response time of one to two years before noticeable incremental oil production. For smaller independent operators moving into the North Sea, such considerations can be just as important as maximising total recovered reserves.
- Security of CO2 delivery – while working on the CENS Project, the interest in CO2 sources to provide in excess of 25 million tonnes per year (TPY) of CO2 and the interest in parties to build the CO2 infrastructure under the right contractual structures, has been established. The delivered price for CO2 should range between €20 to €35/tCO2 without consideration of CO2 credits. CO2 emission credits will further reduce the delivered cost but unfortunately are not bankable at this time and require further clarification beyond 2012. An incentive programme for sources of CO2 that helped further reduce the delivered cost of CO2 will encourage an even wider uptake for CCS as each reduction of €6/tCO2 is nearly equivalent to €2/BBL of oil. An incentive programme that encourages EOR will realise for the respective Government 40%, 70% or 78% of any further delivered cost reductions through oilfield taxation.
- Project risk management – operators know that CO2 will enable them to recover significant quantities of incremental oil and the technology does exist to do this; however, North Sea operators are not provided with an incentive to encourage them to make the significant investments required in a CO2 for EOR project. They do not receive sufficient rewards to compete for internal capital against a new field development in another oil region with lower production costs. Governments are in competition for investment capital in their oil regions and more costly tertiary recovery will not take place without incentives that address this fact.
Incentive mechanisms to encourage CO2 for EOR could take many forms. The US experience indicates that investment tax credits of 15% to 25% help reduce the pain for the large investments and purchased CO2 required before incremental oil production is realised. One scheme that does appear to handle several of the aforementioned issues was suggested by the Norwegian Confederation of Oil Industry (OLF) as a ‘volume allowance’ on incremental oil. The allowance was a non-cash deduction from revenues for tax purposes equivalent to $2.25/BBL; however, because there were substantial investment allowances already available for the project, the impact of this additional allowance was not realised for some years into production. It has therefore been proposed, and has been evaluated, that the use of a tax credit should be provided for all incremental oil production. The absolute value may be similar to that proposed by the OLF although this needs further discussion between the operators and respective governments.
A ‘volume credit’ provides investment incentive by providing a known minimum after tax profit margin to an operator independent of oil price and encourages the maximum extraction of EOR oil. The incremental oil production will be that production over an agreed decline curve. While these curves have been difficult to establish for new oil fields, they are readily understood and already provided to the governments on existing oil fields. The use of a minimum margin in this way helps offset the significant increase in operating costs that an operator has with tertiary production in comparison with their alternative investments when evaluated at moderately low oil prices. Again, profits above this minimum level will be taxed at the respective rates of 40%, 70% or 78% depending on the prevailing rate.
Summary and the Way Forward
Key issues for the oilfield operators are:
- perception of market oil price;
- incentives to investment; and
- security of CO2 supply.
For the CO2-supplier, it is:
- cost for capturing and gathering the CO2;
- future regulations constraining CO2-emissions; and
- cost of alternative options for CO2-avoidance.
To address these issues there needs to be dialogue across several industrial sectors (e.g., oil and gas, power, process, chemical and refining) as well as with three government bodies (finance, energy and environment). The key facilitating parameters are market oil price, CO2 delivered price and government incentives. It is the type and magnitude of the incentives that will draw the parties together to realise as much of the potential incremental oil prize. No other commercial solution has the potential to reduce CO2 emissions as much as CO2 for EOR.
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