Carbonate Brazilian pre-salt fields have a large number of faults detected by seismic and well data. Nevertheless, because of limitations in seismic resolution, all existent faults cannot be identified. That is one of the main challenges for understanding related heterogeneities (vugs, karst) and the flow behavior. This paper deals with a fault analysis and modeling using an original approach and fault data of three pre-salt reservoirs.
One possible approach for characterizing and modeling the fault network (
The results presented on this article lead us to discuss the importance of how to choose the samples for modeling sub-seismic faults based on the ensemble of seismic faults available. This article answers the question about which available seismic faults we should use for estimating fractal dimension, should we use all available seismic faults near of the reservoir area or use only the faults inside the reservoir contour. After this short discussion on the fractal dimension choice from a spatial distribution point of view, the impact of this choice on flow was illustrated. The sub-seismic fault models were modeled using different fractal dimension. Subsequently, an upscaling step using analytical upscaling (
Characterizing sub-seismic faults has a major impact on the overall flow behavior of the field. The chosen methodology has been applied only on synthetic cases but never published using real data. This work will interest a practicing engineer. The fault network of these neighbor reservoirs allows us to illustrate the importance on the choice of fractal dimension for characterizing the fault network and its impact on the subseismic models and fluid displacement, consequently on production.
Bourbiaux, Bernard (IFP Energies Nouvelles) | Fourno, André (IFP Energies Nouvelles) | Nguyen, Quang-Long (IFP Energies Nouvelles) | Norrant, Françoise (IFP Energies Nouvelles) | Robin, Michel (IFP Energies Nouvelles) | Rosenberg, Elizabeth (IFP Energies Nouvelles) | Argillier, Jean-François (IFP Energies Nouvelles)
Bernard Bourbiaux, André Fourno, Quang-Long Nguyen, Françoise Norrant, Michel Robin, Elisabeth Rosenberg, and Jean-François Argillier, IFP Energies Nouvelles Summary Among various ways to extend the lifetime of mature fields, chemical enhanced-oil-recovery (EOR) processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR because the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs was quantified thanks to X-ray computed-tomography (CT) scanning and nuclearmagnetic-resonance (NMR) measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves were inferred from in-situ fluid-saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, viscous drive conditions were imposed between the end faces of a plug, to account for the possibly significant contribution of fracture viscous drive to matrix oil recovery. The recovery kinetics and behavior, especially the occurrence of countercurrent and cocurrent flow, are interpreted through the analysis of modified forces in the presence of a diffusing or convected WM that alters rock wettability and reduces water/oil interfacial tension (IFT) to a lesser extent. This work calls for an extensive modeling study to specify the conditions on chemical additives and recovery-process implementation that optimize the recovery kinetics. Introduction Carbonate reservoirs hold a large share of worldwide oil reserves, maybe on the order of 60% (Akbar et al. 2000). Although Manrique et al. (2006) report very few field applications of chemical EOR in carbonate reservoirs of the United States, surfactant injection seems to be a promising EOR strategy for multiple reasons lying in the low capital expenditure required for already-waterflooded mature fields, and in encouraging results obtained in surfactant pilot tests. The recovery potential from carbonate oil-wet fractured reservoirs is underlying in Allan and Qing Sun (2003) that shows a contrasted (bimodal) distribution of recovery factors in typical porous fractured reservoirs, with maximum-frequency recovery values of 10 to 20% and 30 to 40%. The present paper tries to illuminate the enhanced imbibition mechanisms taking place in the oil-wet matrix blocks of carbonate fractured reservoirs, from the interpretation of carefully monitored imbibition experiments on a realistic rock/fluid system. One can find a review of major findings and unsolved questions regarding the chemical enhancement of water/oil spontaneous imbibition in natural porous media in Bourbiaux et al. (2014).