Experimental Investigation of Drainage Capillary Pressure Computed From Digitized Tomographic Images

Abstract

This paper presents comparisons between drainage capillary pressure curves computed directly from 3D micro-tomographic images (micro-CT) and laboratory measurements conducted on the same core samples. It is now possible to calculate a wide range of petrophysical and transport properties directly from micro-CT images or from equivalent network models extracted from these images. Capillary pressure is sensitive to rock microstructure and the comparisons presented are the first direct validation of image based computations. The measured data include centrifuge and mercury injection drainage capillary pressure for fired Berea, Bentheimer and Obernkirchner sandstones and unfired Mount Gambier carbonate. The measurements cover a wide range of porosities and permeabilities. The measurements are made on core samples with different diameters (2.5 cm, 1.5 cm, 1 cm and 0.5 cm) to assess the effect of up-scaling on capillary pressure measurements. The smallest diameter samples were also used to obtain the 3D micro-CT images. Good agreement is obtained between the experimental measurements and direct computations on 3D micro-CT images. 1. Introduction Recent advances in imaging technology now make it possible to routinely image rock microstructure in 3D at the pore scale. Coupling this with an ability to computationally predict petrophysical and multiphase flow properties directly on the 3D digitised tomographic images or on equivalent networks (digital core technology) results in a powerful tool to interpret conventionally measured core data and to extend the range of available data by examining rock fragments which cannot be tested by conventional means (sidewall cores, drill cuttings and unconsolidated or poorly consolidated rocks). A number of studies (Auzerias et al., 1996; Arns et al., 2001; Knackstedt et al., 2004) suggest that computations of permeability, formation factor and mercury injection capillary pressure on digitised image of a small rock fragments cut from a core plug are consistent with laboratory measurements performed on the same plug even though the computations and measurements are performed at significantly different scales. Micro-CT imaging is currently limited to small sample sizes; pore scale imaging on most materials requires resolutions of 3–5 microns, and image size is limited to approximately 2000 cubed---this limits the sample sizes for imaging studies to 5mm-1cm which is significantly smaller than conventional core plug scale. Moreover, computational times usually limit the computational domain used to a smaller sub-set of the imaged volume. Conventional laboratory measurements, on the other hand, are carried on core plugs and composite cores at scales several orders of magnitude larger than that for the image based computations. We investigate this scale effect by performing laboratory measurements at a number of different scales from the core plug scale down to a scale closer to that imaged using micro-CT. We limit the investigation to what are usually considered to be homogeneous or model rock types. These are the rock types normally used to validate image based calculations of a wide range of rock properties.

Pore-Scale Imaging of the Oil Cluster Dynamic during Drainage and Imbibition Using In Situ X-Ray Microtomography

“…During the past ten years, the CT scanning technique has been widely used to study pore structure and fluid distribution [8][9][10]. Multiphase fluid saturations were measured in situ at the pore scale to explain deviations of saturation exponent from conventional values [11].…”

Pore Network Modeling: A New Technology for SCAL Predictions and Interpretations

“…We find that the sandstones have average coordination numbers between 4 and 5, which is in agreement with other analyses of granular media. 3,5 However, the vuggy carbonate has higher coordination numbers and a wider distribution of pore and throat sizes than the sandstones, which is also another expected result. 5 Figure 6 illustrates the extracted networks from S1, S2, and L1 samples.…”

Capillary Pressure Prediction from Rock Models Reconstructed Using Well Log Data

“…One can then perform numerical calculations of petrophysical properties directly on the measured 3D images. Good agreement is obtained between drainage capillary-pressure curves computed directly from 3D microtomographic images and laboratory measurements on the same core samples (Olafuyi et al, 2006). Although the imaging technique can provide a "realistic" 3D microstructure of a reservoir rock, it is impracticable to image the whole core due to cost and time.…”

“…An alternative approach to determine the capillary pressure-saturation relationship is to simulate the capillary-dominated fluid displacements (such as primary drainage and imbibition) in the three-dimensional (3D) microtomographic images of reservoir rocks or computer-generated numerical rock models (Hazlett, 1995, Øren et al, 1998, Hilpert and Miller, 2001, Vogel et al, 2005, Olafuyi et al, 2006, Jin et al, 2007. Recent advances in imaging technology now make it possible to routinely image rock microstructures in 3D at the pore scale (Knackstedt et al, 2004, Tomutsa et al, 2007, Grader et al, 2009.…”