Flow Physics of Profile Control Fluids in Porous Media and Implications for Enhanced Oil Recovery: A Microfluidic Study

Novel profile control agents are constantly emerging in the field of enhanced oil recovery, contributing to the extension of a stable production period. However, evaluation performed through conventional core flow experiments is usually inadequate to reveal the in-depth mechanism of profile control agents. Besides, due to different operation and production modes, there is an urgent need for a specific experimental method applicable to horizontal wells in bottom water reservoirs. In this context, this paper describes two models tailored to bottom water reservoirs and investigates the flow characteristics and mechanisms of three water-shutoff agent types. At the pore scale, further study was carried out on the water-shutoff synergism between a gel and an emulsifier. The results show that the gel is present at the edge of the pore body, while the emulsion is blocked in the center of the pore body. Hence, gel that enters a water channel (main flow and accumulation area of emulsion) can cooperate with an emulsion to achieve high-strength water shutoff, making the bottom water that re-invades mainly break through at oil-rich areas. Compared with water shutoff with gel alone (randomly distributed in the breakthrough area), the synergism improves the gel’s ability to select flow channels, inhibits emulsifier channeling, and achieves a remarkable EOR effect.

Study of the Critical Pore Radius That Results in Critical Gas Saturation during Methane Hydrate Dissociation at the Single-Pore Scale: Analytical Solutions for Small Pores and Potential Implications to Methane Production from Geological Media

We examine the critical pore radius that results in critical gas saturation during pure methane hydrate dissociation within geologic porous media. Critical gas saturation is defined as the fraction of gas volume inside a pore system when the methane gas phase spans the system. Analytical solutions for the critical pore radii are obtained for two, simple pore systems consisting of either a single pore-body or a single pore-body connected with a number of pore-throats. Further, we obtain critical values for pore sizes above which the production of methane gas is possible. Results shown in the current study correspond to the case when the depression of the dissociation temperature (due to the presence of small-sized pores; namely, with a pore radius of less than 100 nm) is considered. The temperature shift due to confinement in porous media is estimated through the well-known Gibbs-Thompson equation. The particular results are of interest to geological media and particularly in the methane production from the dissociation of natural hydrate deposits within off-shore oceanic or on-shore permafrost locations. It is found that the contribution of the depression of the dissociation temperature on the calculated values of the critical pore sizes for gas production is limited to less than 10% when compared to our earlier study where the porous media effects have been ignored.

Accurate Carbonate Pore System Characterization by Nuclear Magnetic Resonance and Micro-CT Techniques

Carbonate reservoir rocks usually have complex pore systems of broad size distributions, which determine many aspects of oil exploitation, from petrophysical properties to oil/water displacements. An accurate and complete description of these pore systems remains a challenge. A single technique often gives one measurement of complicated microscopic pore space. The new techniques (i.e., micro-CT and NMR) are utilized together with conventional methods (e.g., MICP, BET) to capture a more accurate and complete picture of pore structures. MICP measures the pore throat while the NMR T2 mainly measures the pore body. Micro-CT provides a 3D image of a limited sample size. Recently, NMR DDIF (decay due to diffusion in the internal field) for direct pore body size is extended from high to low magnetic field, which overcomes many limitations in pore system characterization. This study obtains pore throat size distributions from in-situ centrifuge capillary pressure and pore body size distributions from low field DDIF measurement and verifies them with micro-CT and BET/T2 in different types of carbonate rocks. The pore throat size distribution of the conventional sample is obtained from in-situ centrifuge capillary pressure. The major features of both macro and micro pore throat size distributions are captured. Pore size distributions are directly obtained from glass beads and carbonate rocks without calibration. Combined analysis of the pore size distribution from two methods reveals the underlying causes of their different petrophysical properties. The pore throat size distribution from in-situ centrifuge capillary pressure and pore size distribution from NMR DDIF can be employed to obtain a better understanding of conventional carbonate pore systems.

Pore Size, Tortuosity, and Permeability From NMR Restricted Diffusion in Organic-Rich Chalks

Permeability estimation is crucial for formation evaluation, but faces challenges when used in low-permeability, unconventional formations. NMR well logging is often used to estimate formation permeability, but in many unconventional formations, the current NMR methods are not adequate. We have developed a new method to estimate permeability using a modified Carman-Kozeny model with pore size, tortuosity, and porosity information inferred from NMR restricted diffusion measurements. In this study, we focus on two low-permeability, organic-rich chalks (0.017 and 0.035 md) with connate water present. They are from the same formation but have different depths, TOC (total organic carbon), and bitumen content. These differences affect pore size, tortuosity, and permeability. The core samples are pressure saturated with two hydrocarbons—high-pressure methane or decane—with connate water present. NMR measurements are conducted under pressure to obtain the restricted diffusivity of the hydrocarbon-bearing pore space. In planning the NMR restricted diffusivity measurements, an optimum series of diffusion-encoding times are chosen for the unipolar stimulated-echo pulse sequence to obtain the correlation between the restricted diffusivity (D) and free diffusion length (LD). By applying the Padé fit to the restricted diffusivity, we can better estimate the diffusive tortuosity (τ) and pore-body size (d) of the hydrocarbon-filled pore space. The estimated pore-body size, tortuosity, and porosity from NMR are then used to predict permeability. We introduce a modified Carman-Kozeny model, which shows advantages over older methods like SDR and Timur-Coates models. The advantages of the new method are shown in organic-rich chalk with complex pore structures and organic matter. This new method can potentially be used for estimating permeability by well-logging and core-log integration.

A New Multiphysics Method for Simultaneous Assessment of Permeability and Saturation-Dependent Capillary Pressure in Hydrocarbon-Bearing Rocks

Summary Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) relies on accurate description of pore structure, dynamic petrophysical properties (e.g., directional permeability, saturation-dependent capillary pressure), and fluid distribution. However, techniques for reliable quantification of permeability still rely on model calibration using core measurements. Furthermore, the assessment of saturation-dependent capillary pressure has been limited to experimental measurements, such as mercury injection capillary pressure (MICP). The objectives of this paper include developing a new multiphysics workflow to quantify rock-fabric features (e.g., porosity, tortuosity, and effective throat size) from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements; introducing rock-physics models that incorporate the quantified rock fabric and partial water/hydrocarbon saturation for assessment of directional permeability and saturation-dependent capillary pressure; and validating the reliability of the new workflow in the core-scale domain. To achieve these objectives, we introduce a new multiphysics workflow integrating NMR and electric measurements, honoring rock fabric, and minimizing calibration efforts. We estimate water saturation from the interpretation of dielectric measurements. Next, we develop a fluid-substitution algorithm to estimate the T2 distribution corresponding to fully water-saturated rocks from the interpretation of NMR measurements. We use the estimated T2 distribution for assessment of porosity, pore-body-size distribution, and effective pore-body size. Then, we develop a new physically meaningful resistivity model and apply it to obtain the constriction factor and, consequently, throat-size distribution from the interpretation of resistivity measurements. We estimate tortuosity from the interpretation of dielectric-permittivity measurements at 960 MHz by applying the concept of capacitive formation factor. Finally, throat-size distribution, porosity, and tortuosity are used to calculate directional permeability and saturation-dependent capillary pressure. We test the reliability of the new multiphysics workflow in the core-scale domain on rock samples at different water-saturation levels. The introduced multiphysics workflow provides accurate description of the pore structure in partially water-saturated formations with complex pore structure. Moreover, this new method enables real-time well-log-based assessment of saturation-dependent capillary pressure and directional permeability (in presence of directional electrical measurements) in reservoir conditions, which was not possible before. Quantification of capillary pressure has been limited to measurements in laboratory conditions, where the differences in stress field reduce the accuracy of the estimates. We verified that the estimates of permeability, saturation-dependent capillary pressure, and throat-size distribution obtained from the application of the new workflow agreed with those experimentally determined from core samples. We selected core samples from four different rock types, namely Edwards Yellow Limestone, Lueders Limestone, Berea Sandstone, and Texas Cream Limestone. Finally, because the new workflow relies on fundamental rock-physics principles, permeability and saturation-dependent capillary pressure can be estimated from well logs with minimum calibration efforts, which is another unique contribution of this work.

An Investigation into Different Correlation Methods between NMR T2 Distributions and Primary Drainage Capillary Pressure Curves Using an Extensive Sandstone Database

Many workers have recognised the link between Nuclear Magnetic Resonance (NMR) derived T2 distributions and pore size distributions in reservoir rocks. This property has been used to develop models to obtain primary drainage capillary pressure curves from T2 distributions. These models often assume that the rocks pore space resembles a simple bundle of capillary tubes. They do not consider the existence of multiple pore body connections and pore body restrictions/throats. The most successful models utilise variable scaling factors to convert T2 times to pore diameters and hence capillary pressure. The variable scaling factor approach recognises the existence of variable surface relaxivity throughout the pore space due to variations in mineralogy and pore topography. This investigation uses SCAL data from the ART NMR Sandstone Rock Catalogue to obtain core calibrated variable scaling factors for 174 reservoir sandstone samples. The depositional environments for these samples include; aeolian, fluvial, coastal and shallow and deep marine. The samples used have a wide variety of mineralogy, diagenetic overprints and cover six orders of magnitude in absolute permeability. Three different methods for obtaining the scaling factors are presented and the relative merits of each discussed. A global model to predict capillary pressure from NMR T2 distributions in reservoir sandstones has been developed using correlations between the variable scaling factors and permeability.

Measuring Simplified Pore-Throat Angularity Using Automated Mathematical Morphology

Summary Fluid flow in sedimentary rocks is controlled mainly by the morphology of pore-connecting throats. Pore throats (PTs) typically exhibit diverse converging/diverging morphologies such as biconic, parabolic, or hyperbolic geometries. These different geometries are defined by variable opening angle, or angularity, between the throat walls from the narrowest point of the throat toward the pore body. Importantly, each of these geometries imposes different constraints on fluid flow. However, current pore-level flow models usually favor simple cylindrical or biconic throat morphologies, in part because of the difficulty to extract the throat angularity from pore-space imagery. An image-analysis technique called mathematical morphology has been used to characterize porosity in laterally continuous pore networks (e.g., in sandstones) from thin-section microphotographs. This method allows the extraction of petrophysical parameters such as pore and throat diameters through successive image alterations—namely, erosion/dilation cycles using an expanding structuring element (SE). This study proposes a novel application of this technique and quantifies PT angularity. Angularity can be measured from the throat toward the pore body so that the true geometry—biconic, parabolic, or hyperbolic—can be recognized. The technique is tested on simple geometries to demonstrate the correctness of the mathematic equations involved. Because all equations assume perfect, nonpixelated geometries while images are composed of square pixels, the accuracy of measurements depends strongly on image resolution. Pixelation causes significant fluctuations of ±2 to 10° around the correct angularity values that decrease in amplitude as image resolution increases. Finally, potential implications of this parameter on fluid-flow modeling are discussed.