Seven oil fields on the Norwegian continental shelf have been identified as candidates for carbon dioxide injection for the purpose of improved oil recovery (IOR). The work forms part of a project to identify possible value chains for CO2 injection.
The fasttrack project, which is due to be completed by June, was instigated by the new government in January. It aims to identify and start preliminary negotiations with potential sellers and buyers as part of a CO2 value chain running from generation through capture, transportation, and use as an injection gas. The project is headed by Gassco, the state company operating Norway’s gas infrastructure, which has responsibility for investigating infrastructure and transport requirements.
Investigation of potential CO2 sources and sellers is being conducted by Gassnova, another state-owned company set up to encourage development of sustainable gas technologies, including CO2 capture. Petoro, which manages the State’s Direct Financial Interest (SDFI) in oil and gas assets, is responsible for investigating the buyers’ end of the chain, including injection issues and the possibilities for temporary CO2 storage offshore.
One aim is to provide capture and environmentally friendly disposal of CO2 emissions from the gas-fired power plant which Naturkraft plans to build alongside Gassco’s Kårstø gas terminal on the west coast of Norway.
In parallel two other projects are being carried out. One involves engineering for a CO2 capture facility at the Kårstø plant; the other is examining the legal and organizational aspects of state involvement in a CO2 chain - the government accepts that it will have to contribute financially to make such a chain economically viable.
Of more than 40 oil fields initially screened, 22 should evaluate IOR through CO2 injection at some time, says Jan Rosnes, Petoro’s project manager. The seven which have been identified as being suitable in the present timeframe are: Norske Shell’s Draugen, Talisman’s Gyda, Norsk Hydro’s Brage and Oseberg Øst, and Statoil’s Volve, Gullfaks, and Sygna.
Separately, Statoil and Shell have announced their intention to reinject CO2 from a new power plant at Tjeldbergodden in mid-Norway in the Draugen and Heidrun fields, while Statoil has said it will study possible CO2 injection on Volve.
CO2 injection offers good potential for improved oil recovery, but developing facilities offshore may take up to four years.
The fields which stand to gain most from CO2 injection are those with a low GOR - gas-to-oil ratio - says Rosnes. They are also best-suited if they have received good benefit from water injection. Miscibility of the gas with the oil is important if the gas is to be effective in releasing the remaining oil, and this depends on reservoir and reservoir fluid properties which vary from field to field. In the light of these factors, it is possible to assess the effectiveness of CO2 injection.
Petoro estimates that the CO2 requirement for each field would be between one and five million tons/year. It is too early to say what the estimated additional recovery would be, but Rosnes says its calculations are in line with those of a study carried out by the Norwegian Petroleum Directorate (NPD), which estimated additional recovery for the NCS as a whole at 1-2 Bbbl.
The NPD report, which was published last year, concluded that CO2 injection was technically feasible but uneconomic under prevailing conditions. However, some of these conditions have since become more favorable, according to Petoro’s VP for external affairs Sveinung Sletten. He says that the long-term crude oil price, on which oil companies base their investment decisions, is now considerably higher. The price of CO2 quotas on the pre-Kyoto trading market has also risen, from $4-12/ton to $24-30.
Petoro’s work indicates that a period of two to four years will be necessary for equipping field facilities to handle CO2 injection. The critical task is upgrading the topsides process equipment to handle the CO2 which comes up in the wellstream - separating the oil from the mixture of CO2 and hydrocarbon gas and reinjecting this mixture.
An injection value chain requires CO2 to be available in large quantities at sites where it is generated, such as power plants. In fact such availability is limited. The Kårstø plant will generate about one million tons/year at most, which is the injection requirement for a smaller field, Rosnes says.
In April, on the basis of the work carried out so far, Gassco, Petoro, and Gassnova will identify a small number of potential CO2 value chains. Further negotiations will be held with the relevant players to clarify the cost picture and the conditions for committing to participation in a value chain. The results will be reported to the government in June. Later in April an open meeting will be held to brief interested parties and the press on progress so far.
However, any investment decision is still some way off - this will only come after a further stage of detailed planning and the establishment of agreements and frame conditions. If the aim of including the planned Kårstø power plant in a value chain is to be achieved, all this should ideally be in place before the plant comes onstream in 2009.
Time considerations are also important with respect to the user fields, Rosnes says. There is a phase in a field’s production life when it can benefit from CO2 injection; but once depletion reaches a certain point, the additional recovery is no longer sufficient to justify the investment. •
