The ability to determine a predictive stability criterion is of great practical importance for designing stable polymer-based displacements. Where one usually resorts to a limited number of core-scale experiments or coarse-scale reservoir simulations, the first ones are potentially impacted by lengthscale issues while the second ones possibly smooth out sharp displacing fronts and physical instability due to numerical diffusion. This paper proposes a new hydrodynamical stability criterion based on previous linear stability analysis results. This criterion is tested for 2D polymer oil displacement by performing high viscosity contrasts, high-resolution numerical experiments at pilot scale. We investigate mesh resolution issues and several perturbation ideas. Different factors are considered such as mobility ratios, polymer adsorption and degradation, and heterogeneities. The analysis is based on a combination of reservoir simulation and image processing techniques. We show the development of viscous fingering in homogeneous porous media is driven by the shock mobility ratio defined as the ratio of the total fluids upstream mobility over the total fluids downstream mobility. This stability criterion proves to predict both the polymer upstream and polymer-free downstream saturation fronts stability, typical of a polymer displacement, whether polymer adsorbs on the rock or degradates, or not. The observed fingers dynamical behavior is in line with previous works addressing single phase miscible flow or immiscible oil displacement in porous media: fingers transversally merge while growing in the flow direction. Time evolution of fingers spreading and number is linear. Investigation on porous media of variable heterogeneity distributions shows how viscous fingering couples with heterogeneity and leads to even more marked, distorded and unstable flow patterns. In that cases, flow patterns are not solely driven by the porous medium heterogeneity. The more unstable the flow is, the more sensitive it is to heterogeneity. In-depth fingers analysis shows a very specific time evolution behavior, quite different from viscous fingering in homogeneous media. Such a flow pattern is related with production data such

In naturally fractured carbonate reservoirs, Gas Oil Gravity Drainage processes (GOGD) are successfully implemented but oil recovery is limited by a slow kinetics. However a gas EOR process represents a promising alternative to boost this oil production rate. Nevertheless the design of this process should address several technical challenges: the typically unfavorable wettability of the matrix (intermediate to strongly oil-wet), the densely connected fracture network and the high contrast of fracture-to-matrix permeability. We propose here the injection of a advanced EOR foam with reduced interfacial tension. The foam flow in the fracture creates an important viscous drive leading to a pressure gradient, which increases the oil recovery dynamics compared to GOGD. Besides, the reduced interfacial tension (IFT) between crude oil and aqueous phase allows the aqueous phase to enter the matrix despite the unfavorable wettability. In this paper, we demonstrate that a balance exist between IFT and foam strength performances to optimize the process. Three foam formulations are optimized with very different profiles in terms of IFT and foam performances. For their design, priority is given either to ultra-low IFT values (10-3mN/m) or to a strong foam with larger IFT (0.35mN/m) or to a balance between the two first formulations (0.03mN/m). Foams are evidenced as intrinsically less stable in ultra-low IFT conditions: apparent viscosity (in porous media) in contact with oil is respectively enhanced by a factor 40 when IFT rises from 10−3 to 10−1mN/m. Based on sandpack and coreflood experiments, we recommend an IFT in the order of 10−1 mN/mas a balance between the viscous drive in fracture and an efficient aqueous phase imbibition in the oil-wet matrix. Simulation work supports this experimental conclusion: the common target of IFT in the order of 10−3 mN/m determined by capillary desaturation curves in SP flooding can be adjusted to a higher IFT value, which can be deduced from the wettability of the reservoir. To ensure an accelerated oil recovery in naturally fractured carbonate reservoirs, we recommend the design of a low-IFT foam formulation with revised IFT performances compared to a classical Surfactant-Polymer process targeting residual oil. Indeed, the final process is likely more efficient if the target of IFT is defined by wettability requirements rather than residual oil desaturation. This article gives the target formulation parameters which arise from the mechanisms at play (viscous drive and imbibition in oil-wet matrix), and are realistically achieved with industrial surfactants.

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The CO2CRC Otway Project, in Victoria, Australia, is one of the first projects of CO2 storage in a depleted gas reservoir. CO2 injection in the sandstone reservoir, at a depth of 2,000 mSS, started in March 2008 with the objective to inject up to 100,000 tonnes of CO2 over two years. This study compares the level of predictability obtained with different cases depending on the initial data, using the same numerical compositional simulation package. We use recorded data (production and injection) to build a new numerical reservoir model. A dynamic model had already been built before the injection well started (Xu et al., 2006) and was validated by history matching using the gas production data reported. In this paper, we used the same updated static model (Dance et al. 2007) as used for the pre-injection model, which is based on the production data and the data obtained from the injection well (CRC-1). With this updated static model, a different dynamic model is built using injection data and through a newly developed simulator option, which better simulates the CO2-water behavior. The injection rate and pressure data from CRC-1 are now available and the actual breakthrough time - at which the CO2 plume reached the monitoring well (Naylor-1) located 300 m away from CRC-1 - can be history matched. Various relative permeability curves including new laboratory measurements performed on a core taken from the reservoir formation (Waarre C) were used. The results from the updated dynamic modeling using this measured relative permeability data are compared to results using data from literature. In general, experimental measurements for drainage and imbibition processes are not available This study gives a better understanding of the parameters which strongly influence simulated CO2 behavior. It shows the relation between the data availability and prediction reliability. Introduction Carbon dioxide is a greenhouse gas and has a strong impact on global climate changes. The effect of CO2 on global warming is now well recognized and possibilities to reduce the greenhouse gas emissions are currently investigated. It is not expected that the demand of fossil fuels, which produce most of the greenhouse gases (GHG), will decline in the near future (International Energy Agency, IEA) although significant efforts have been made to use more alternative energy sources. Carbon capture and storage (CCS, i.e. injection of CO2 in deep geological formations instead of being emitted in the atmosphere) is recognized as to be one of the options to reduce the emissions of GHG as described by the IEA (2008) and by the Intergovernmental Panel on Climate Change (Fisher et al., 2007). More and more CCS projects are being developed around the world. Lately, with the support of IEA and to respond to a request from the G8 nations, a CCS Roadmap has been developed to demonstrate and effectively deploy CCS projects.

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