Print this pageMultiphase Flow Properties of Clay Bearing Rocks: Laboratory Measurement of Relative Permeability and Capillary Pressure
Clay bearing rocks can have a large impact on trapping, reservoir compartmentalization and production oil or gas in a number of ways. Faults are critical for defining the likely sealing or baffling nature of within reservoir systems. The evaluation of new prospects and reservoir production simulations include fault permeabilities based on estimates of fault clay distribution. Fault clay content has been shown to act as a useful proxy for predicting both the sealing capacity of phylosiliclastic faults. There are several clay prediction algorithms (Bouvier et al. 1989, Yielding et al. 1997; Knipe et al. 2004). Far more data has been collected on the single phase permeability and mercury capillary pressure of fault rocks (Fisher and Knipe, 1998, 2001). More recently, one of the first gas relative permeability data for cataclastic rocks has been published (Al-Hinai et Al. 2008). A key problem in production simulation and prospect evaluation is accounting for the relative permeability of clay rich rocks, and for exploration cases their threshold pressure. Therefore in this paper we attempt to start filling the knowledge gap of multiphase flow properties of clay rich bearing rocks.
An experimental study was carried out in order to study the feasibility of determining relative permeabilities and capillary pressures with brine, oil or gas. A methodology was developed to create synthetic plugs with controlled amounts of sands and clays that successfully mimic the single phase permeability behaviour of phylosiliclastic fault rocks. This methodology includes various techniques for the determination of steady state oil-brine relative permeabilities, gas relative permeabilities and air-brine capillary pressures. Samples with different clay contents and clay types have been tested. Different measurement techniques provide consistent and comparable results. The gas-brine capillary pressures of the synthetic plugs agree well with mercury results.
The oil or gas relative permeabilities measured show a larger drop within a very small variation in saturation and at relatively small capillary pressure range. The results indicate that attempting to model the impact of faults on fluid flow based on single phase permeability or using general relative permeability curves could significantly overestimate fault transmissibility and their impact on reserves evaluation.
AAPG Search and Discover Article #90100©2009 AAPG International Conference and Exhibition 15-18 November 2009, Rio de Janeiro, Brazil