CO 2 -EOR has been used successfully to recover incremental oil after water flooding. In the USA, more than 260,000 bbl/d are produced by using this EOR method. CO 2 Enhanced Gas Recovery (CO 2 -EGR) has also been proposed, however, only small scale projects have been performed until know.In this paper, the challenges of CO 2 -EGR are addressed at the example of three fields.The Hoeflein Field (Austria) contains gas condensate with a maximum liquid drop out of 4 %. The simulation results show that CO 2 injection can recover incremental condensate. However, owing to the shape of the reservoir, CO 2 will break through early. Hence, gas recovery will be reduced compared with conventional gas production.The second field which was investigated is located in Pakistan. This field is an elongated field. The production wells are distributed over the full length of the field. CO 2 injection can increase recovery (0.2 % maximum) only, if the surface facilities are able to handle high CO 2 contents in the produced gas (more than 50 %).The Schoenkirchen Uebertief Field (Austria) is a deep (5700 mSS), elongated structure. The production wells are located at one end of the structure. To recover incremental gas, good well placement and gas injection later in the lifetime of the field is required, about 1.5 % additional gas compared with depletion drive can be expected.The example cases of CO 2 -EGR show that even for almost ideal reservoir structures (elongated with wells at one end and injection at the other end), limited potential for CO 2 -EGR exists. To increase gas production compared with depletion, a good well placement and knowledge of the structure accordingly is required, the production facilities have to be able to handle high CO 2 contents and CO 2 injection should commence later in the life-time of the field to avoid trapping of hydrocarbon gas in unswept areas at high pressures.

CO 2 -EOR has been used successfully to recover incremental oil after water flooding. In the USA, more than 260,000 bbl/d are produced by using this EOR method. CO 2 Enhanced Gas Recovery (CO 2 -EGR) has also been proposed, however, only small scale projects have been performed until know.In this paper, the challenges of CO 2 -EGR are addressed at the example of three fields.The Hoeflein Field (Austria) contains gas condensate with a maximum liquid drop out of 4 %. The simulation results show that CO 2 injection can recover incremental condensate. However, owing to the shape of the reservoir, CO 2 will break through early. Hence, gas recovery will be reduced compared with conventional gas production.The second field which was investigated is located in Pakistan. This field is an elongated field. The production wells are distributed over the full length of the field. CO 2 injection can increase recovery (0.2 % maximum) only, if the surface facilities are able to handle high CO 2 contents in the produced gas (more than 50 %).The Schoenkirchen Uebertief Field (Austria) is a deep (5700 mSS), elongated structure. The production wells are located at one end of the structure. To recover incremental gas, good well placement and gas injection later in the lifetime of the field is required, about 1.5 % additional gas compared with depletion drive can be expected.The example cases of CO 2 -EGR show that even for almost ideal reservoir structures (elongated with wells at one end and injection at the other end), limited potential for CO 2 -EGR exists. To increase gas production compared with depletion, a good well placement and knowledge of the structure accordingly is required, the production facilities have to be able to handle high CO 2 contents and CO 2 injection should commence later in the life-time of the field to avoid trapping of hydrocarbon gas in unswept areas at high pressures.

The paper presents a methodology to develop and apply an equation-of-state (EOS) multi-fluid model for a field in Tunisia. The EOS model was developed by matching measured PVT data for a near-critical oil sample. The fluid characterization was used to estimate contamination level in oil-based-mud contaminated MDT samples, calculate decontaminated sample composition, estimate zone composition based on clean-up test measured oil-gas ratio, estimate fluid composition of some layers where samples were not available, and study the effect of gas condensate blockage and capillary number on simulated well performance. In this field, reservoir fluids range from lean gas condensate to rich gas condensate and volatile oil. Clean up tests were conducted for all four zones encountered in the well, and oil-gas ratios were measured. During the clean up test of one zone, a near critical oil sample was collected and standard PVT experiments were conducted. Oil based mud (OBM) contaminated MDT samples were collected from six of the nine non-communicating layers, with OBM contamination levels between 20–65 wt% STO. An EOS model was developed after matching measured PVT data on the near-critical oil sample. The MDT samples were decontaminated using measured mud composition. The calculated decontaminated "clean" sample compositions were used in a reservoir simulation model to initialize the layer from which the MDT sample was taken. The developed EOS model was also used to estimate the fluid composition of different zones and layers without fluid samples. The zone fluid compositions were calculated based on measured test OGR. The EOS model, zone fluid compositions, decontaminated MDT samples, and layer mobilities were used to estimate fluid composition of the layers without samples. This paper provides a methodology that can be used in any other field.

The Jenein Sud area is located in the south of Tunisia about 350 km from the Mediterranean Sea. Five successful wells have been drilled in the area and proved that structures containing various fluids are present and can be produced at economic rates. In this paper, the main challenges encountered in the area and how they were tackled is described. Pethrophysical parameters: Owing to diagenetic processes such as chloritisation, siderite cementation and quartz overgrowth, the porosity to permeability relationship is diffuse and cannot be consider for permeability estimation. Therefore, all available petrophysical datasets were integrated and clustered by using an appropriate rock typing concept, reflecting the influence of pore geometries on flow and storage. Sand distribution: Sand layers could not be correlated laterally due to the prograding environment encountered and the large distance between the drilled wells. To capture the uncertainties, a multitude of geological models was created, integrating available seismic data, outcrop studies and trends apparent from regional geology. Fluids: The individual structures consist of a large number of stacked sands. The fluids in the sands vary from dry gas to volatile oil. All the sands have individual hydrocarbon/water contacts. To determine the fluid composition of the layers and overall performance, MDT samples were taken from the sands and several production tests were performed. An overall Equation Of State model was used to describe the comingling of individual sand layers and to optimise the surface facility design. Small scale structures: To appraise the area, wells have been drilled in individual structures rather than appraisal wells into selected structures. The wells are used to prove sufficient hydrocarbons and the composition of the hydrocarbons. This information was used to select an appropriate surface facility design capable of handling the fluids and to optimise the production strategy of the area.

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