Abstract Resistivity Index (RI) of Fontainebleau and Bentheimer sandstones was investigated at ambient and reservoir pressures down to low water saturations using the porous plate method. The measurements compared with computations directly on high-resolution three-dimensional images of the pore space using Digital Rock Physics. The numerical computations are in reasonable agreement with the experimental measurements down to water saturations as low as Sw = 10 %. The RI measurements show that both sandstones display Archie behavior at elevated pressure. However, at ambient pressure the RI for Fontainebleau sandstone deviates from Archie behavior at low water saturations. The pore-space images suggest that the deviation from Archie behavior is due to the presence of conductive percolating grain contact regions. Bentheimer sandstone for which grain contacts do not percolate, displays Archie behaviour both at ambient and elevated pressures. The present study extends previous work on RI of clean sandstones using micro-CT based analysis to high confining pressures and shows that for such sandstones the RI at elevated pressure displays Archie behavior down to low water saturations.

Image-based computations of relative permeability for capillary-dominated quasi-static displacements require a realistic description of the distribution of the fluids in the pore space. The fluid distributions are usually computed directly on the imaged pore space or on simplified representations of the pore space extracted from the images using a wide variety of models which capture the physics of pore-scale displacements. Currently this is only possible for uniform strongly wetting conditions where fluid–fluid and rock–fluid interactions at the pore-scale can be modelled with a degree of certainty. Recent advances in imaging technologies which make it possible to visualize the actual fluid distributions in the pore space have the potential to overcome this limitation by allowing relative permeabilities to be computed directly from the imaged fluid distributions. The present study explores the feasibility of doing this by comparing laboratory measured capillary-dominated drainage relative permeabilities with relative permeabilities computed from micro-CT images of the actual fluid distributions in the same rock. The agreement between the measurements and the fluid image-based computations is encouraging. The paper highlights a number of experimental difficulties encountered in the study which should serve as a useful guide for the design of future studies.

SummaryHigh-resolution X-ray-computed-tomography (CT) images are increasingly used to numerically derive petrophysical properties of interest at the pore scale—in particular, effective permeability. Current micro-X-ray-CT facilities typically offer a resolution of a few microns per voxel, resulting in a field of view of approximately 5 mm3 for a 2,0482 charge-coupled device. At this scale, the resolution is normally sufficient to resolve pore-space connectivity and calculate transport properties directly. For samples exhibiting heterogeneity above the field of view of such a single high-resolution tomogram with resolved pore space, a second low-resolution tomogram can provide a larger-scale porosity map. This low-resolution X-ray-CT image provides the correlation structure of porosity at an intermediate scale, for which high-resolution permeability calculations can be carried out, forming the basis for upscaling methods dealing with correlated heterogeneity.In this study, we characterize spatial heterogeneity by use of overlapping registered X-ray-CT images derived at different resolutions spanning orders of magnitude in length scales. A 38-mm-diameter carbonate core is studied in detail and imaged at low resolution—and at high resolution by taking four 5-mm-diameter subsets, one of which is imaged by use of full-length helical scanning. Fine-scale permeability transforms are derived by use of direct porosity/permeability relationships, random sampling of the porosity/permeability scatter plot as a function of porosity, and structural correlations combined with stochastic simulation. A range of these methods is applied at the coarse scale. We compare various upscaling methods, including renormalization theory, with direct solutions by use of a Laplace solver and report error bounds. Finally, we compare with experimental measurements of permeability at both the small-plug and the full-plug scale.We find that both numerically and experimentally for the carbonate sample considered, which displays nonconnecting vugs and intrafossil pores, permeability increases with scale. Although numerical and experimental results agree at the larger scale, the digital core-analysis results underestimate experimentally measured permeability at the smaller scale. Upscaling techniques that use basic averaging techniques fail to provide truthful vertical permeability at the fine scale because of large permeability contrasts. At this scale, the most accurate upscaling technique uses Darcy's law. At the coarse scale, an accurate permeability estimate with error bounds is feasible if spatial correlations are considered. All upscaling techniques work satisfactorily at this scale. A key part of the study is the establishment of porosity transforms between high-resolution and low-resolution images to arrive at a calibrated porosity map to constrain permeability estimates for the whole core.

Summary It is now widely acknowledged that continuous oil-spreading films observed in 2D glass-micromodel studies for strongly water-wet three-phase oil, water, and gas systems are also present in real porous media, and they result in lower tertiary-gasflood residual oil saturations than for corresponding negative spreading systems that do not display oil-spreading behavior. However, it has not yet been possible to directly confirm the presence of continuous spreading films in real porous media in three dimensions, and little is understood of the distribution of the phases within the complex geometry and topology of actual porous media for different spreading conditions. This paper describes a study with high-resolution X-ray microtomography to image the distribution of oil, water, and gas after tertiary gasflooding to recover waterflood residual oil for two sets of fluids, one positive spreading and the other negative spreading, in strongly water-wet Bentheimer sandstone. We show that, for the positive spreading system, oil-spreading films maintain the connectivity of the oil phase down to low oil saturation. At similar oil saturation, no oil films are observed for the negative spreading system, and the oil phase is disconnected. The spatial continuity of the oil-spreading films over the imaged volume is confirmed by the computed Euler characteristic for the oil phase.

We study the resistivity index of Fontainebleau and Bentheimer sandstones at ambient conditions down to low water saturations both experimentally and numerically. Numerical simulations are in good agreement with experimental measurements of capillary drainage resistivity index by the porous plate method down to water saturations as low as S w = 10 %. Fontainebleau sandstone exhibits a percolating network of grain contacts, while the higher porosity Bentheimer sandstone does not. We show that this difference in the topological connection of conductive films at low water saturations is responsible for the non-Archie behaviour of Fontainebleau sandstone. Furthermore, it is necessary to attribute a grain contact conductivity to the grain contacts in Fontainebleau sandstone to reconcile experiment and numerical simulation. Conductive films organised as pendular rings around grain contacts are not able to explain this result.

This paper presents the results of drainage capillary pressure and relative permeability measurements made on cores having different bulk volumes ranging from 0.5 to 12 cm(3). The aim of the experiments was to provide reliable experimental data which can be used to validate the predictive value of micro-CT based network models for capillary pressure and relative permeability. The micro-CT based network models use realistic networks constructed from the X-ray images of the rock samples having a typical bulk volume of 0.3 cm(3). Experimental data for drainage capillary pressure were obtained using the centrifuge technique. The results of the largest cores were verified by the data obtained on the same sample using the porous plate technique. Relative permeability data were obtained by history matching the unsteady state displacement data. Homogeneous model sandstones (Berea and Bentheim) and carbonate (Mt. Gambier) were used in the experiments. Air-brine and oil-brine fluid-systems were used for drainage capillary pressure and relative permeability measurements, respectively. The relative permeability data were compared with those predicted from empirical and geometry based models using capillary pressure data. Good agreement was obtained for the drainage capillary pressure measured on all samples used. The residual saturations obtained from the cores used in the displacement experiments were also in good agreement. The models were found to predict relative permeability of oil and water with varying degrees of success. For water relative permeability, the Pirson model predicts the experimental data successfully while the Corey, Corey-Brooks/Burdine and van Genuchten/Burdine models predict the data of oil relative permeability better than the others. The results demonstrate for the first time that reliable drainage capillary pressure and relative permeability measurements can be made on small model sandstone and carbonate cores of representative scales used in micro-CT-imaging.

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 were 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 was obtained between the experimental measurements and direct computations on 3D micro-CT images.

Abstract 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 porespace of tighter clastics 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 (from 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. Introduction Micro-CT (µ-CT) imaging [1,2] is becoming increasingly popular for characterising many macroscopic properties of porous media. From µ-CT images one is able to compute petrophysical properties such as porosity, permeability, conductivity, elasticity, and mercury injection capillary pressure (MICP). Rock properties derived from fragments of a range of cores including homogeneous and reservoir sands have been compared with conventional laboratory measurements and shown to be in good agreement [3,4]. In more complex cores (e.g., carbonates, heterogeneous sands, tight gas) one must consider the role of pore structure in a continuous range across over many decades of length scales (from nm to cm) to better understand these processes. For example, in carbonate rocks, the processes of sedimentation and diagenesis produce a complex spatial distribution of pores and pore connectivity across several decades of length scales. Therefore developing a reliable petrophysical interpretation for predicting the transport properties and producibility of complex cores such as carbonates remains difficult. In this paper we describe 2D and 3D imaging studies of complex reservoir core material via µ-CT coupled with complementary petrographic techniques (thin section, SEM) and high resolution focused ion beam tomography (FIBT). We utilize a newly developed image registration technique for aligning high-resolution 2D microscopy (SEM, Optical) images of core thin sections with the corresponding region of the micro-CT 3D image of the core. The integration of aligned high resolution (nm scale) data with 3D µ-?CT data has the potential to increase the accuracy of the physical properties predicted from the 3D µ-CT image analysis.

AbstractThis paper presents the results of drainage capillary pressure and relative permeability measurements made on cores of different size – bulk volumes ranging from 0.5 to 12 cm3. The aim of the measurements was to obtain reliable experimental data which can be used to validate the predictive value of micro-CT based network models for capillary pressure and relative permeability. Micro-CT based network models typically use realistic networks constructed from the X-ray images of the rock samples representing bulk volumes of the order of 0.3 cm3.Experimental data for drainage capillary pressure were obtained using the centrifuge technique. The results for the largest cores were comparable to data obtained on the same sample using the porous plate technique. Relative permeability data were obtained by history matching unsteady state displacement data. Homogeneous outcrop sandstones (Berea and Bentheim) and carbonate (Mt. Gambier) were used in the experiments. Air-brine and oil-brine fluid-systems were used for drainage capillary pressure and relative permeability measurements, respectively. The relative permeability data were compared with those predicted from empirical and geometry based models using capillary pressure data.Good agreement was obtained for the drainage capillary pressure measured on all samples used. The residual saturations obtained from the cores used in the displacement experiments were also in good agreement. The models were found to predict relative permeability of oil and water with varying degrees of success. For water relative permeability, the Pirson model predicts the experimental data successfully while the Corey, Corey-Brooks/Burdine and van Genuchten/Burdine models provide the best predictions for oil relative permeability. The results demonstrate for the first time that reliable drainage capillary pressure and relative permeability measurements can be made on small sandstone and carbonate cores of size similar to that used for micro-CT-imaging.

Abstract In this paper we describe a technique based on radio frequency plasma treatment in H2O vapour to reproducibly clean and modify the surface energy of clastic and carbonate core material allowing the establishment of well defined wettability conditions. We present micro-tomographic observations of the pore-scale fluid distributions in strongly water wet clastic and carbonate cores. We then establish mixed-wet states in the same cores using controlled hydrophobation. Micro-tomography is again used to reveal the three-dimensional geometry and topology of water and oil wet regions. The tomographic data shows that under water wet conditions at intermediate saturations larger pores are predominantly oil filled while smaller pores remain water wet. We perform displacement experiments using clastic and carbonate cores at well defined wettability conditions and report measurements of resistivity index. These methodologies may provide insight into the role of rock microstructure and surface energy variability in determining recovery and production characteristics of oil and gas reservoirs.

Carbonate rocks are diverse and their pore space complex. Large variations in petrophysical properties of carbonates are caused by wide variations in pore type, pore shape and pore interconnectivity. Petrophysical properties such as capillary pressure and Archie m,n values of carbonate rocks are directly related to the amount and type of porosity, the dominant feature size and the interconnectivity of different porosity groups. While the petrophysical properties strongly depend on the interconnectivity of pores and pore shapes, accurately measuring these attributes requires the analysis of pore structure in 3D. Until recently this has not been possible, and traditional descriptions of carbonate pore structure and interconnectivity have been inferred from 2D thin section analysis. In this paper we describe the imaging of a number of carbonate core samples from the UAE in 3D across a range of scales down to 2.8 microns. The samples include sucrosic dolomites and a complex bioclastic grain/packstone. We calculate drainage capillary pressure and resistivity as a function of saturation directly on the images and correlate the resultant petrophysical properties to the pore structure of the rock. While the dolomite samples exhibit a dominant and strongly interconnected macroporous phase (pore throats ≥ 4 μm), the bioclastic sample exhibits a significant proportion of meso/microporosity (pore throats ≤ 4μm). Pore connectivity is studied for both sets of samples. The connectivity of the sucrosic dolomite exhibits a strong trend of lower connectivity with decreasing porosity. Other pore structural properties (e.g., pore size, pore-to-throat aspect ratio, pore and throat shape) show little variation. The bioclastic sample has significant proportions of both connected and disconnected (separate) macropores. It is shown that inclusion of larger pores associated with the mesoporous phase results in complete connectivity of the macroporous phase. The relative interconnectivity of the macropores is systematically related to the resultant Archie cementation exponent. The saturation exponent n is calculated for water-wet and oil-wet conditions. Strong differences in n with wettability are noted for the sucrosic samples. The inclusion of microporosity has a dramatic effect on the behaviour of n for the bioclastic sample. Three dimensional imaging and analysis of carbonate core material at the pore scale can provide a basis for more accurate petrophysical models, narrow the range of uncertainty in estimates of petrophysical properties and improve the quantification of the resource within carbonate reservoirs.

Abstract This paper presents experimental data for co-current spontaneous imbibition into cores having bulk volumes from 0.1 to 12 cm3. Simple experiments of brine imbibing into air-filled cores were carried out. Homogeneous sandstone cores (Berea and Bentheim) and a carbonate core (Mt. Gambier) were used in the experiments. The experimental data were scaled using the scaling laws reported in the literature. The results demonstrate that reliable experimental data of spontaneous imbibition can be obtained for the small cores of homogeneous porous rocks. Such data are of immense interest for validating the predictive value of network models based on micro-CT images of rock fragments with bulk volumes as small as 0.3 cm3. The data for cores of different sizes were satisfactorily scaled using five different methods[6, 11, 14, 15, 18]. The recovery models proposed by Ma et al.[15] and Viksund et al.[20] produced an excellent match for the normalized gas recovery data. Although the Li and Horne model[11] successfully correlated the imbibed water volume as a function of time, the model failed to correlate the normalized recovery data. A comparison of the scaled data with data previously reported for water-gas systems showed excellent agreement.

This paper presents results of a 3D pore scale study of the resistivity properties in twelve model and reservoir core samples. Samples include sintered bead packs, homogeneous consolidated sandstones, thinly bedded sands, sucrosic dolomites, dual porosity samples and heterogeneous carbonate core material. Predictions of Archie’s cementation exponent m and saturation exponent n (under well defined wettability conditions) are in good agreement with experiment where available. We note a consistent increase in m with decreasing porosity in sandstones. The value of m in carbonates may be empirically related to the fraction of disconnected macroporosity. Under water wet conditions the simple clastic and carbonate samples exhibit Archie-type behaviour. The laminated sand exhibit strong anisotropy and the complex carbonate systems exhibit values of n that vary strongly with water saturation. Large values of n>4 are observed under idealized oil wet conditions. Pore and fluid phase connectivity is examined for the image data and used to explain trends observed in the data.