Experimental Study of Fractured Carbonate Rock Model for Oil Recovery Evaluation

Abstract

The aim of this work is the experimental study of a fractured carbonate rock model for oil recovery evaluation. For this, a new experimental routine regarding petrophysical characterization was developed and validated. The evaluation of oil recovery was performed by mass balance. Also, the heterogeneity of the fractured rock model and the distribution of the saturations was calculated by X-ray computed tomography. An induced fractured was created adding a longitudinal spacer (Lie, 2013) at a reservoir carbonate rock plug from a Brazilian pre-salt reservoir. Drainage process was performed by forced displacement using synthetic formation water and oil from the same reservoir rock. The model was aged at 63°C for 28 days. X-ray computerized tomography was used for porosity and fluid saturations calculations. The initial injection rate was 0.1 cm3/min. After reaching the saturation plateau, the rate was decreased to 0.05 cm3/min to evaluate possible incremental recovery. The developed methodology allowed the construction of a porous media with an induced fracture representative from a naturally fractured reservoir. The rock sample was cut lengthwise with a metal saw. A POM spacer was used to represent the fracture, and glass beads filled the fracture in order to give a representative porosity to the fractured rock model. The petrophysical properties of the matrix and the fracture were obtained during each step of the fractured rock model construction. The matrices porosities obtained were 8% and 14%, and the permeabilities 68 mD and 40 mD, respective to each semicylinder of the plug. The fracture porosity and permeability obtained were 1.6% and 146 Darcy, respectively. For the entire fractured rock model, the porosity was 12.5% and the permeability 5 Darcy. The approach to mimic a drainage method reached an initial water saturation of 57%. The recovery factor obtained by the seawater injection at a 0.1 cm3/min flow rate was 30%. An increase of 3% was obtained when the flow was decreased to 0.05 cm3/min. The CT scan measurement yields additional information such heterogeneity of the model through the porosity profile in the fracture, matrix, and the entire fractured rock model. This work presents an innovative methodology to mimic a natural fractured reservoir model which provided a full routine for petrophysical properties evaluation of a physical model. Besides, computed tomography (CT) scans validated porosity values. Thus, a better understanding of the effects of the flow rate in oil recovery on fractured carbonates rocks and the potential of the model developed for this type of studies could be verified.