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Abstract
Estimating the EOR potential in producing oil fields is an important input to decision making if large scale CO2-EOR is going to be employed in the North Sea. This paper describes the results from simulations of CO2 injection into conceptual reservoir models representative of water flooded oil fields in the North Sea.

Enhanced oil recovery (EOR) by CO2 injection is an attractive option because it has the potential to increase the oil, gas and condensate recovery of producing fields. In the North Sea a majority of the oil reservoirs have been subject to massive strategic and efficient water flooding resulting in high recoveries for most of the cases. However, more advanced tertiary recovery methods are sought to increase the recovery. Using CO2 as injection fluid has several advantages. Most oil compositions in the North Sea are miscible with CO2 at reservoir conditions something that will enable miscible displacement of the oil targeting residual (capillary trapped) oil after water flooding. The density of CO2 at reservoir conditions is in most cases lesser than the injected water and it may therefore reach other parts of the reservoir and consequently improve the sweep efficiency.

The North Sea shows a great variation in type of oil reservoirs and traps ranging in geological age from the Late Paleozoic to the Cenozoic. To cover the range of different geological classes, traps and recovery strategies a large number of scenarios has been simulated on conceptual sector models. Conceptual live reservoir oil is composed to represent fluid properties of a selection of 55 water flooded oil reservoirs in the North Sea that are considered potential candidates for CO2 injection. The selected reservoirs comprise 30 reservoirs in the UK sector, 20 in the Norwegian sector and 5 reservoirs in the Danish sector. The conceptual fluid model is composed and tuned to reflect the hydrocarbon pore volume (HCPV) weighted average properties of these 55 oil reservoirs.

Representative petrophysical properties and fluid compositions have been used in the models in order to schematically account for heterogeneities and phase behavior of the different reservoir types. Different injection schemes including CO2 injection with and without recirculation of CO2 breakthrough gas and CO2-WAG have been evaluated.

Introduction
Continuous CO2 injection and CO2 water-alternating-gas (WAG) injection have gained increasing interest due to the combined benifit of higher recovery efficiency in many types of petroleum reservoirs and reduction of greenhouse gas emissions by storage of CO2 in depleted petroleum reservoirs. Underground storage of CO2 in petroleum reservoirs and aquifers has a large capacity and EOR is a large-scale use where CO2 has a value. Gas and oil reservoirs are considered as safe storage sites due to their historic record of trapping buoyant fluids for millions of years. On a long term the deposition capacity in oil reservoirs is limited, but petroleum reservoirs represent significant sinks for CO2 early in a deposition era (Holt, Lindeberg and Taber 2000).

To estimate the total CO2 EOR potential in the UK and Norwegian sector of the North Sea a techno-economical model for CO2 injection into oil reservoirs and aquifers was presented and used in a scenario were many of the most feasible prospective water flooded fields are included. The project lifetime in the scenario is 40 years where CO2 is injected and stored. The CO2 is delivered through a main pipeline infrastructure that transports CO2 from industrial sources in EU. An EOR module for miscible CO2-WAG (water alternating gas) injection was developed and preliminary calculations using this module indicated that the oil recovery potential for CO2-WAG is comparable to continuous CO2 injection. More water and less CO2 are produced during WAG injection, however (Holt et al. 2008).