Norway CO2 Study: Too Expensive & Risky
The Norwegian Petroleum Directorate (NPD) has, on assignment from the Ministry of Petroleum and Energy (MPE), conducted a feasibility study of projects entailing CO2 injection for increased oil recovery on the Norwegian continental shelf. The conclusion is that, at the present time, CO2 injection does not appear to be a commercial alternative for improved oil recovery for the licensees on the Norwegian shelf.
The NPD's study, which is based on current technological knowledge, provides a detailed technical description of the CO2 chain; from source, capture and transport to injection and long-term storage. It also illustrates field examples and profitability calculations.
There are several challenges that must be surmounted before CO2 injection for improved oil recovery can be implemented. CO2 injection is technically feasible, and the potential for increased recovery is substantial. However, the threshold costs for establishing a delivery chain for injection of CO2 are so high that other methods of improving recovery emerge as being more attractive for the licensees at this time. CO2 for improved oil recovery is capital-intensive, at the same time as production will take place over a long period of time. The recovery costs with CO2 injection are in the order of +/- 30 USD/bbl, with a quota price for CO2 and +/- 33 USD/bbl without a quota price. This is considerably higher than the oil prices the companies use for long-term projects with high risk.
Use of water and gas injection to increase recovery and maintain high production was implemented at an early stage on the Norwegian shelf. This has led to significant additional revenues for both the Norwegian society and the companies, beyond what was expected. The development of advanced wells, including wells with multiple long, horizontal branches, advanced seismic and more effective visualization programs are also examples of technology that the companies have used to increase oil recovery. This means that Norwegian fields contain less oil that can be produced with the aid of CO2.
CO2 injection can improve resource utilization on the Norwegian shelf, but the effect is uncertain. A total of twenty fields have been evaluated as being suitable for CO2 injection. The technical potential for increased recovery from these fields is estimated at 150-300 million Sm3 oil. However, CO2 injection is technically demanding and competes against other methods of improving oil recovery. Large volumes of CO2 are needed at the right place and at the right time in order to exploit all or parts of the technical potential. Expensive modifications to existing installations are required in order to prepare them for injection and treatment of CO2. There are more than 30 years' experience in injection of CO2 for increased oil recovery on land in the USA, however, nowhere in the world is there experience with injection of CO2 in large offshore oil fields.
Access to large volumes of CO2 is needed if we are to implement use of CO2 for improved oil recovery on the Norwegian continental shelf. To reduce capture and transport costs, the CO2 sources should be large point emissions situated as close to the fields as possible.
Many studies have been conducted with the aim of identifying CO2 sources in Norway and in Northern Europe. Only a few sources in Norway are large enough to supply fields on the Norwegian shelf with CO2. Planned new gas power plants may make interesting volumes available near the relevant fields.
There are major point emissions of CO2 in Europe, e.g. the coal power plants in Denmark, which could supply the fields on the Norwegian shelf with CO2. Large-scale import of CO2 will be a precondition for extracting the entire potential of improved recovery through CO2 injection on the Norwegian shelf.
The technology required for capture of CO2 from gas power plants is available, but has not been demonstrated for large gas power plants. Potential cost savings have been identified, but these will probably not be available for another five-six years. Research, development of technology and demonstration projects may, in the long term, contribute to reduced capture costs.
CO2 can be transported in pipelines or by ship. Given today's technology, pipelines to the fields are required, either directly from the source or from an interim storage. Transport by ship is needed if CO2 is to be transported from small or scattered sources far from established CO2 storage facilities. Delivery of CO2 from ships directly to an oil field may be a long-term alternative, if new technology is qualified and field-specific conditions so permit.
Fields with CO2 injection only require CO2 for a limited period of time - as long as the field uses CO2 for increased recovery. In addition, both planned and unplanned operational shutdowns will occur on the field. In order to avoid large emissions of CO2 during periods when the field cannot use CO2 for improved recovery, the infrastructure, capture and transport should be linked to a long-term storage alternative so that delivered CO2 can be accepted continuously throughout the lifetime of the gas power plant/source. This increases the threshold costs for the first field that may elect to use CO2 for this purpose.