3D imaging and flow characterization of the pore space of carbonate core samples

Carbonate rocks are inherently heterogeneous having been laid down in a range of depositional environments and having undergone significant diagenesis. They are particularly difficult to characterise as the pore sizes can vary over orders of magnitudes and connectivity of pores of different scales can impact greatly on flow properties. For example, separate vuggy porosity in an underlying matrix pore system can increase the porosity, but not the permeability and lead to large residual oil saturations due to trapping in vugs. A touching vug network can have a dramatic effect on permeability and lead to higher recoveries. In this paper we image a range of carbonate core material; from model carbonate cores to core material from outcrops and reservoirs via 3D via micro-CT. Image-based calculations of porosity, MICP and permeability on 3D images of the carbonate systems are directly compared to experimental data from the same or sister core material and give good agreement. The carbonate systems studied include samples with well connected macroporous systems and other where the macroporosity is poorly connected. Simulation of permeability on these systems and direct analysis of local flow properties within the system allows one to directly illustrate the important role of the connectivity of macropores on flow properties. Pore network models generated from the images illustrate the varied topology obtained in different carbonate samples and show a dramatic difference when compared to clastic samples. Many carbonate samples can include a significant proportion of microporosity (pores of 2 microns or less in extent) which are not directly accessible via current micro-CT capabilities. We discuss how one can map the structure and the topology of microporous regions crucial in studies of flow, production and recovery in carbonates. A hybrid numerical scheme is developed to measure the contribution of microporosity to the overall core permeability. Overall these results show the important role of identifying the connectivity of the pore sizes in dictating the single phase flow properties. Implications to two phase relative permeability and recovery are briefly discussed

3D imaging and modeling of carbonate core at multiple scales

The understanding of multiphase flow properties is essential for the exploitation of hydrocarbon reserves in a reservoir; these properties in turn are dependent on the geometric properties and connectivity of the pore space. The determination of the pore size distribution in carbonate reservoirs remains challenging; carbonates exhibit complex pore structures comprising length scales from nanometers to several centimeters. A major challenge to the accurate evaluation of these reservoirs is accounting for pore scale heterogeneity on multiple scales. This is the topic of this thesis.Conventionally, this micron scale information is achieved either by building stochastic models using 2D images or by combining log and laboratory data to classify pore types and their behaviour. None of these capture the true 3D connectivity vital for flow characterisation. We present here an approach to build realistic 3D network models across a range of scales to improve property estimation through employment of X-ray micro-Computed Tomography (μCT) and Focussed Ion Beam Tomography (FIBT). The submicron, or microporous, regions are delineated through a differential imaging technique undertaken on x-ray CT providing a qualitative description of microporosity. Various 3-Phase segmentation methods are then applied for quantitative characterisation of those regions utilising the attenuation coefficient values from the 3D tomographic images. X-ray micro-CT is resolution limited and can not resolve the detailed geometrical features of the submicron pores. FIB tomography is used to image the 3D pore structure of submicron pores down to a scale of tens of nanometers. We describe the experimental development and subsequent image processing including issues and difficulties resolved at various stages.The developed methodology is implemented on cores from producing wackstone and grainstone reservoirs. Pore network models are generated to characterise the 3D interconnectivity of pores. We perform the simulations of petrophysical properties (permeability and formation resistivity) directly on the submicron scale image data. Simulated drainage capillary pressure curves are matched with the experimental data. We also present some preliminary results for the integration of multiscale pore information to build dual-scale network models. The integration of multiscale data allows one to select appropriate effective medium theories to incorporate sub-micron structure into property calculations at macro scale giving a more realistic estimation of properties

Pore scale characterization of carbonates at multiple scales: integration of micro-CT, BSEM and FIBSEM

The understanding of petrophysical and multiphase flow properties is essential for the assessment and exploitation of hydrocarbon reserves; these properties in turn are dependent on the 3D geometric and connectivity properties of the pore space. The determination of the pore size distribution in carbonate rocks remains challenging; extreme variability in carbonate depositional environments and susceptibility to a range of post-depositional processes results in complex pore structures comprising length scales from tens of nanometers to several centimeters. To increase understanding of the role of pore structure on connectivity, conductivity, permeability and recoveries requires one to probe the pore scale structure in carbonates in a continuous range across over seven decades of length scales (from 10 nm to 10 cm) and to integrate information at these different scales. In this paper experimental techniques including micro-computed tomography, backscattered scanning electron microscopy (BSEM), and Focussed ion beam SEM (FIBSEM) are used to probe the pore scale structure in carbonates across many decades of scale. Registration techniques are then used to couple information at different length scales. First an image of a 3D plug (4 cm, 20 micron voxel size) is correlated to a sample at macroporous resolutions (8 mm diameter, 4 micron voxel size). We then focus on coupling SEM and FIBSEM data at submicron resolutions to micro-CT data at ≈3-5 micron resolution. For pixel perfect registration of SEM images, an accurate template has been developed to remove warp artefacts introduced by the SEM scanning procedure and we have successfully mapped the sub-resolution porosity and pore sizes visible in the SEM image to gray scale levels in the 3D image. FIBSEM also allows one to investigate the 3D structure in samples down to tens of nanometers. We briefly discuss how this multiscale information can be used as a method for enhanced analysis of petrophysical properties of carbonates

Pore scale characterization of carbonates at multiple scales: integration of micro-CT BSEM and FIBSEM

The understanding of petrophysical and multiphase flow properties is essential for the assessment and exploitation of hydrocarbon reserves; these properties in turn are dependent on the 3D geometric and connectivity properties of the pore space. The determination of the pore size distribution in carbonate rocks remains challenging; extreme variability in carbonate depositional environments and susceptibility to a range of post-depositional processes results in complex pore structures comprising length scales from tens of nanometers to several centimeters. To increase understanding of the role of pore structure on connectivity, conductivity, permeability and recoveries requires one to probe the pore scale structure in carbonates in a continuous range across over seven decades of length scales (from 10 nm to 10 cm) and to integrate information at these different scales. In this paper experimental techniques including micro-computed tomography, backscattered scanning electron microscopy (BSEM), and Focussed ion beam SEM (FIBSEM) are used to probe the pore scale structure in carbonates across many decades of scale. Registration techniques are then used to couple information at different length scales. First an image of a 3D plug (4 cm, 20 micron voxel size) is correlated to a sample at macroporous resolutions (8 mm diameter, 4 micron voxel size). We then focus on coupling SEM and FIBSEM data at submicron resolutions to micro-CT data at ≈3-5 micron resolution. For pixel perfect registration of SEM images, an accurate template has been developed to remove warp artefacts introduced by the SEM scanning procedure and we have successfully mapped the sub-resolution porosity and pore sizes visible in the SEM image to gray scale levels in the 3D image. FIBSEM also allows one to investigate the 3D structure in samples down to tens of nanometers. We briefly discuss how this multiscale information can be used as a method for enhanced analysis of petrophysical properties of carbonates

3D Imaging of Reservoir Core at Multiple Scales; Correlations to Petrophysical Properties and Pore Scale Fluid Distributions

The prediction of hydrocarbon recovery is related to both the detailed pore scale structure of core material and fluid interfacial properties. An increased understanding of displacement efficiencies and overall recoveries requires an ability to characterize the pore structure of reservoir core in 3D and to observe fluid distributions at the pore scale. Micro-CT imaging is capable of acquiring 3D images of the pore structure of sedimentary rock with resolutions down to the micron scale. This allows the 3D pore-space of many reservoir rock samples to be imaged at the pore scale. The 3D pore-space of tighter elastics and carbonate core material includes a significant proportion of microporosity-pores at the submicron scale which are not directly accessible via current micro-CT capabilities. Porosity at all scales can affect fluid flow, production, recovery data and log responses. It is important to characterize pore structure and connectivity in a continuous range across over six decades of length scales ( om nm to cm) to better understand these petrophysical and production properties. In this paper we describe 2D and 3D imaging studies of reservoir core via micro-CT coupled with complementary petrographic techniques (thin section, mercury intrusion) and high resolution focused ion beam (FIB) scanning electron microscopy studies of a range of reservoir core. Results are given which illustrate the importance of pore structures at varying scales in determining petrophysical properties. Microtomography is then used to observe pore scale fluid distributions within the core material. Displacement experiments under controlled wettability conditions are undertaken. The local pore-scale fluid distributions identified via 3D tomographic imaging experiments. These results provide insight into the role of rock microstructure in determining recovery and production characteristics