Print this pageAbstract: Numerical Modeling of Secondary Oil Migration: Definition of Oil Pathways in Laboratory Scale
Souto Filho, João de Deus - Petrobras/E&P
The process of secondary petroleum migration is developed at pore scale and is controlled essentially by capillary, buoyancy and hydrodynamic forces. The intensity of these forces depends on permoporous system characteristics and fluid physico- chemical properties. In recent years, petroleum migration has been studied in laboratory simulations and by computer modeling. The data and results presented in this paper were obtained as one part of a larger study to determine a regional petroleum migration model for the Açu Formation, Potiguar basin, Brazil (Souto Filho, 1994). A procedure for numerical modeling in laboratory scale, in order to support regional oil migration studies, is presented. The numerical modeling approach focused on matching the oil saturation profiles at different times, tested by a direct comparison of the results with experimental data. Figure 1 shows the equipment used in the laboratory study (acrylic columns 96 cm long, with 2.91 cm inner diameter; and high density plastic pipe 200 cm long, with a 3.72 cm inner diameter). The experiments were prepared with the technique used by Catalan, et al. (1992), using quartz sand grains of fluvial deposits. Table 1 lists the physical properties of porous media, fluids and the mean migration rate of the oil front obtained for the different grain size. We studied the vertical and lateral migration process. In both cases migration was found to take place along restricted pathways, and we confirm the Catalan, et al. (1992) results observing an imbibition front often formed at the bottom of the oil zone. As a second objective of this work, we replicated the qualitative appearance of oil migration front and fluid distribution observed in the experiments, using 2-D and 3-D numeric models. The migration was assumed to occur as a diphasic fluid flow governed by Darcy's law. The oil saturation profiles presented in Figure 2 confirm that using appropriate relative permeability and capillary pressure curves, the secondary oil migration process can be accurately simulated numerically. The results show that numerical simulation is a powerful technique to analyze the evolution of pathways and to identify the main factors that control the secondary migration process in permoporous systems.
Experiment Permeability Oil Density Oil Volume Initial Oil Migration
(Darcy) (g/cm3) Injected (cm3) Height (cm) Rate (cm/b)
CS-02** 57.600 0.859 46.0 24.5 25.3
CS-05* 24.360 0.861 47.0 25.5 11.6
CS-05e** 34.700 0.861 47.0 23.5 32.6
IMS-02** 0.821 35.0 23.0 08.5
IMS-04* 29.460 0.821 45.0 25.0 09.5
IFS-02**1 10.050 0.821 42.0 25.0 01.3
CS = Coarse Sand; MS = Medium Sand; FS = Fine Sand; (*) Smooth Pipe; (**) Rough Pipe.
Obsengion: The CS-05e* experiment was made by glass spheres.
Table 1 - Experimental Conditions and Migration Rates for Vertical Oil Migration Experiments.
AAPG Search and Discovery Article #90933©1998 ABGP/AAPG International Conference and Exhibition, Rio de Janeiro, Brazil