Throat Size Distribution Research Articles

Rock Porous Structure Characterization: A Critical Assessment of Various State-of-the-Art Techniques

The porous structure of geomaterials is of utmost importance for various industrial and natural processes. In this study, various conventional porous structure characterization techniques such as mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), micro-X-ray computed tomography (μCT) imaging, as well as gas injection have been employed to perform a systematic and critical evaluation of all such techniques for characterization of a carbonate rock sample porous structure. The porosity obtained from μCT (5 μm/voxel) (21.5%) is closer than the overall porosity obtained by MIP (17.23%) to the gas porosimetry result (23%). The 5% difference could be due to inaccessible pores to mercury, which can be accessible to nitrogen with much smaller molecules. The porosity obtained from NMR is 21.4%. It is lower than porosity values by μCT (5 μm/voxel) and by gas injection and higher than the prediction of MIP. The porosity is obtained by μCT, but the much lower resolution (27.5 μm/voxel) results in 8.19% underestimating the porosity by around 50%. Regarding permeability, the results of the NMR technique are highly dependent on the cutoff range used and very different from other techniques, whereas the permeability obtained by MIP is around 18.42 mD, close to that obtained by gas permeameter (20 mD). The μCT imaging provides the opportunity to measure pore and throat size distribution directly, to achieve open and closed porosity, the coordination number of pores and surface and volume characteristics of the porous medium, which can hardly be performed through other techniques. The resolution of images, however, fully controls the obtained pore and throat size distribution in CT analysis. The Kolmogorov–Smirnov distribution analysis reveals that the resulting pore size distribution from MIP is rather a rough estimation of the throat size distribution obtained from μCT (5 μm/voxel), while NMR prediction can provide a rather good approximation of the pore size distribution obtained from μCT (5 μm/voxel). The NMR prediction is however dependent on the choice made for the surface relaxivity coefficient, and changing it would significantly affect the resulting distribution. The results of this study provide further insight and elucidate the differences of the quantities such as porosity, permeability, and pore and throat size distribution obtained from various techniques which are essential either as an input to numerical models of flow and transport in porous media or as a building block of the theoretical models.

A methodology to predict the gas permeability parameters of tight reservoirs from nitrogen sorption isotherms and mercury porosimetry curves

A methodology is suggested for the explicit computation of the absolute permeability and Knudsen diffusion coefficient of tight rocks (shales) from pore structure properties. The pore space is regarded as a pore-and-throat network quantified by the statistical moments of bimodal pore and throat size distributions, pore shape factors, and pore accessibility function. With the aid of percolation theory, analytic equations are developed to express the nitrogen (N2) adsorption/desorption isotherms and mercury (Hg) intrusion curve as functions of all pertinent pore structure parameters. A multistep procedure is adopted for the successive estimation of each set of parameters by the inverse modeling of N2 adsorption–desorption isotherms, and Hg intrusion curve. With the aid of critical path analysis of percolation theory, the absolute permeability and Knudsen diffusion coefficient are computed as functions of estimated pore network properties. Application of the methodology to the datasets of several shale samples enables us to evaluate the predictability of the approach.

Pore size distribution of high volatile bituminous coal of the southern Junggar Basin: a full-scale characterization applying multiple methods

Studying on the pore size distribution of coal is vital for determining reasonable coalbed methane development strategies. The coalbed methane project is in progress in the southern Junggar Basin of northwestern China, where high volatile bituminous coal is reserved. In this study, with the purpose of accurately characterizing the full-scale pore size distribution of the high volatile bituminous coal of the southern Junggar Basin, two grouped coal samples were applied for mercury intrusion porosimetry, low-temperature nitrogen adsorption, low-field nuclear magnetic resonance, rate-controlled mercury penetration, scanning electron microscopy, and nano-CT measurements. A comprehensive pore size distribution was proposed by combining the corrected mercury intrusion porosimetry data and low-temperature nitrogen adsorption data. The relationship between transverse relaxation time (T2, ms) and the pore diameter was determined by comparing the T2 spectrum with the comprehensive pore size distribution. The macro-pore and throat size distributions derived from nano-CT and rate-controlled mercury penetration were distinguishingly analyzed. The results showed that: 1) comprehensive pore size distribution analysis can be regarded as an accurate method to characterize the pore size distribution of high volatile bituminous coal; 2) for the high volatile bituminous coal of the southern Junggar Basin, the meso-pore volume was the greatest, followed by the transition pore volume or macro-pore volume, and the micro-pore volume was the lowest; 3) the relationship between T2 and the pore diameter varied for different samples, even for samples with close maturities; 4) the throat size distribution derived from nano-CT was close to that derived from rate-controlled mercury penetration, while the macro-pore size distributions derived from those two methods were very different. This work can deepen the knowledge of the pore size distribution characterization techniques of coal and provide new insight for accurate pore size distribution characterization of high volatile bituminous coal.

Methodology for Concurrent Multi-Parametric Physical Modeling of a Target Natural Unfractured Homogeneous Sandstone

In petroleum, geological and environmental science, flow through porous media is conventionally studied complementarily with numerical modeling/simulation and experimental corefloods. Despite advances in numerical modeling/simulation, experimental corefloods with actual samples are still desired for higher-specificity testing or more complex mechanistic studies. In these applications, the lack of advances in physical modeling is very apparent with the available options mostly unchanged for decades (e.g., sandpacks of unconsolidated packing materials, industry-accepted substitutes with fixed/mismatching petrophysical properties such as Berea sandstone). Renewable synthetic porous media with adjustable parameters are the most promising but have not advanced adequately. To address this, a methodology of advanced physical modeling of the fundamental parameters of dominant mineralogy, particle size distribution, packing, and cementation of a target natural porous media is introduced. Based upon the tight physical modeling of these four fundamental parameters, the other derived parameters of interests including wettability, porosity, pore throat size distribution, permeability, and capillary pressure can be concurrently modeled very close as well by further fine-tuning one of the fundamental parameters while holding the rest constant. Through this process, concurrent multi-parametric physical modeling of the primary petrophysical parameters including particle size distribution, wettability, porosity, pore throat size distribution, permeability, capillary pressure behavior in a target sandstone becomes possible.

Non-invasive quantification of throat-size distribution and corresponding capillary pressure

Pore-throat-size distribution (PSD) controls fundamental petrophysical properties regulating the fluid flow in porous rocks and impacts characterization of water and hydrocarbon reserves. However, the methods available for estimating PSD (e.g. mercury injection porosimetry, gas adsorption/condensation, and electron microscopy) require rock samples and, thus, are not adequate for field applications using borehole geophysical measurements. Therefore, the aims of this paper include (1) appraising pore geometry features (e.g., tortuosity, PSD) using multi-physics formation data, (2) introducing a new non-invasive process to estimate PSD through the combined interpretation of permittivity, resistivity, as well as nuclear magnetic resonance (NMR) measurements, and (3) demonstrating that the new process can be applied to reliably estimate capillary pressure curves and displacement pressure.We introduce a process based on a new equation for non-invasive estimation of PSD in porous media. This novel throat-size equation requires information obtained through the analysis of NMR and electric measurements. We calculate the distribution of pore sizes from the T2 distribution by assuming the pores can be approximated by spheres. The pore-to-throat size ratio and the tortuosity are estimated from the combined analysis of permittivity, resistivity, and NMR measurements. Then, we can use the pore-size distribution and the pore-to-throat ratio to calculate the PSD. The new non-intrusive process relies on fundamental petrophysics and entirely removes the necessity of calibration efforts. Results demonstrate that the relative differences between the calculated mean pore-throat sizes against the corresponding values obtained from mercury injection capillary pressure (in core samples) and the generalized network modeling results (in pore-scale images) are approximately 10% and 40%, respectively. These differences are not expressive since the effective pore-throat sizes can vary by orders of magnitude in different rock types.

Computational characterization of nonwoven fibrous media: I. Pore-network extraction and morphological analysis

Nonwoven fibrous materials are a unique class of porous materials that are widely used for filtration and separation applications. The complex pore structure in fibrous media, with high connectivity and low tortuosity, enhances filtration efficiency while preventing filter fouling. The pore size distribution is a key to predicting and improving transport properties by tailoring the microstructure of fibrous media. However, the statistical properties of the pore space are not easily accessible in experiments, and often only effective geometric properties such as hydraulic radius and specific surface area are reported. In this study, we employ a computational framework and generate realistic nonwoven fibrous media with a wide range of porosities. We obtain the pore network by extracting a subnetwork of the watershed segmentation of pore space and analyze the statistical distribution of pore and throat sizes and their connectivity. We find that a random fiber orientation has a pronounced effect on the effective geometric properties and their dependence on porosity. We investigate the influence of processing parameters such as fiber size, orientation, and overlaps between fibers as a prerequisite to predicting transport properties of nonwoven fibrous media. The computational approach can be combined with experimental imaging techniques, which enables rapid characterization of porous microstructures in terms of the statistical pore space properties resulting from specific manufacturing processes.

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.

The effect of rock type on natural water flooding and residual oil saturation below free water level and oil water contact: A case study from the Middle East

The presence of residual oil below the present day free water level (FWL) and oil water contact (OWC) is common in many fields of the Middle East. This residual oil is seen in reservoirs prior to the start of production.A rock typing study was carried out to investigate the effect of rock types on the presence and distribution of residual oil below the free water level (FWL) and oil water contact (OWC) and potential recovery from ROZ's following water flooding.The rock typing study was carried out by integration of different data sources i.e. core description, thin section study, conventional core analysis (CCAL), special core analysis (SCAL) and petrophysical logs. Six major rock types with unique reservoir quality and behaviour were classified in cored wells and subsequently predicted in un-cored wells. Reservoir quality increases from rock type 1 to 6.The residual oil saturation (Sor) of each rock type was defined and it was concluded that all rock types except for rock type 1 contain residual oil below the present day FWL and OWC. The absence of residual oil in rock type 1 was related to the fact that it is unlikely that oil migration into it ever occurred and consequently no residual oil is seen below the present day FWL and OWC. It was also revealed that rock type 6, with better porosity and permeability, includes the highest residual oil saturation. This was attributed to its bimodal pore throat size distribution and the effect of this on water flooding and hence potential recovery.

Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing.

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features

This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP porosity matched both NMR and imaging results and highlighted the different effects of solvent extraction on throat size distribution. PDP core-plug gas permeability measurements were consistent but overestimated in comparison to PSS results, with the difference reaching two orders of magnitude. SEM proved to be the only feasible method for void-scale imaging with a spatial resolution up to 5 nm. The results confirmed the presence of natural voids of two major types. The first type was organic matter (OM)-hosted pores, with dimensions of less than 500 nm. The second type was sporadic voids in the mineral matrix (biogenic clasts), rarely larger than 250 nm. Comparisons between whole-core and core-plug reservoir properties showed substantial differences in both porosity (by a factor of 2) and permeability (up to 4 orders of magnitude) caused by spatial heterogeneity and scaling.

Accessing Preferential Foam Flow Paths in 2D Micromodel Using a Graph-Based 2-Parameter Model

This study uses experimental data of pore-scale foam flow inside a high-complexity network to fit a graph-based model describing preferential flow paths using microstructural characteristics of the porous medium. Two experiments, with equal gas fractions but varying injection rates, are modeled in parallel. Proposed paths are solution paths to the k-Shortest Paths with Limited Overlap (k-SPwLO) problem, applied to a graph representation of the porous medium with edge weights representing local throat properties. A 1-parameter model based on throat radius only is tested before integrating a second parameter, describing the alignment of the pores surrounding the throat with respect to the injection pressure gradient. The preferential paths observed in both experiments differ in quantity and with respect to the specific porous zones used. As such, the best fit preferential path models for either experiment show different dependencies on the microstructural parameters. The optimized model for the high injection rate experiment markedly shows a dependence on the pore alignment with pressure gradient as well as throat size, whereas the lower injection rate experiment was best fitted to a model that only includes the throat radius. Overall, the graph-based framework was able to capture many high-flow zones in various model parameter combinations, perhaps as consequence of the relatively spiked throat size distribution of the model.

Novel Insights into the Movable Fluid Distribution in Tight Sandstones Using Nuclear Magnetic Resonance and Rate-Controlled Porosimetry

To characterize the movable fluid distribution in tight sandstones and determine its influencing factors, 20 tight sandstone core samples from the Chang-6 and Chang-8 Members of the Yanchang Formation in the Ordos Basin, NW China, were analyzed using nuclear magnetic resonance (NMR) and rate-controlled porosimetry (RCP). The conventional method of movable fluid analysis divides the whole NMR T2 spectrum into two parts, namely unmovable and movable fluids, based on a single T2cutoff value. However, this conventional method ignores pore size wherein fluid is partially movable. In this paper, the fluid in tight sandstones is divided into three parts, i.e., completely unmovable, partially movable and completely movable fluids. Based on the throat size distribution obtained from RCP, T2 spectra were converted into corresponding pore-throat sizes with the nonlinear conversion method, and then the critical pore-throat sizes for fluid distribution were derived. The research results show that the average residual liquid saturation was 46.14% under a centrifugal pressure of 900 psi. On average, the completely unmovable fluid occupied approximately 18% of the total pore volume of tight sandstones, the partially movable fluid accounted for approximately 72% of the total pore volume, and the completely movable fluid accounted for only approximately 10% of the total pore volume. The pore throats filled with completely unmovable fluid contributed very little to the permeability. Compared with the Chang-8 Member, the tight sandstones of the Chang-6 Member had higher completely unmovable fluid saturation and larger critical pore-throat size of the completely unmovable fluid.

Clay mineral content, type, and their effects on pore throat structure and reservoir properties: Insight from the Permian tight sandstones in the Hangjinqi area, north Ordos Basin, China

Clay mineral content and pore throat structure, including type, morphology, size distribution, and porosity and permeability, are very important in factors that control gas storage in tight sandstone reservoirs. In this study, integrated thin section and field emission scanning electron microscope (FE-SEM) observation, X-ray diffraction (XRD), nuclear magnetic resonance (NMR) and rate-controlled mercury porosimetry (RCP) analysis were used to investigate pore throat structure and the effects of clay minerals on pore throat connectivity, size distribution and reservoir properties of tight sandstones in the middle Permian successions of the Hangjinqi area, north Ordos Basin, China. Results show that the tight sandstones have very low porosity and permeability (averaged 9.76% and 0.968 mD) with diverse clay mineral compositions and grain sizes. The main pore types are intergranular and intragranular dissolution pores, intercrystalline and interstitial micropores. Most pores and throats are infilled with authigenic clay minerals, such as acicular chlorite, booklet kaolin, and scaly and filamentous illite with minor silica and calcareous cements. The pore and throat sizes in tight sandstones exhibit large variation, with 147.648 μm and 1.051 μm in sandy conglomerates, 160.998 μm and 1.285 μm in pebbly coarse-grained sandstones, 155.016 μm and 0.868 μm in coarse-grained sandstones, 158.134 μm and 1.178 μm in medium-grained sandstones, and 154 μm and 0.379 μm in fine-grained sandstones, respectively. The results indicate that clay minerals affected the pore throat connectivity, size distribution and reservoir properties of different lithofacies. The properties of tight sandstone reservoirs are heavily influenced by illite content, and throat size played a more important role influencing porosity and permeability. This study helps to clarify the relationship of clay minerals, pore throat structure and reservoir properties of the Permian tight sandstones in the Hangjinqi area and can guide associated work on tight sandstone reservoirs in the Ordos Basin and other basins worldwide. • The pore throat structure of the Permian tight sandstones is characterized. • Lithofacies are associated with pore and throat size distribution. • Throat size plays important role on pore throat connectivity and reservoir permeability. • Clay minerals content especially illite has negative impacts on reservoir properties.

Dolomitisation, cementation and reservoir quality in three Jurassic and Cretaceous carbonate reservoirs in north-western Iraq

Abstract Dolomitisation is a key diagenetic process, commonly improving reservoir quality in carbonate rocks. It is important in the Jurassic and Cretaceous carbonate reservoirs of north and north-western Iraq, creating primary and secondary pays in many oilfields (Kirkuk, Ain Zalah and Butmah). This paper addresses the impact of dolomitisation and cementation on the reservoir quality of three dolomitised carbonate formations (Butmah, Mauddud and Wajnah). Three different dolomitisation types were recognised: reflux dolomitisation, mixing zone, and burial dolomitisation. Extensive petrophysical measurements were carried out and have shown that differences in dolomite crystal size and cementation control the complexity of porosity, pore and pore throat size distributions, pore network connectivity, and permeability. Reflux dolomitisation exhibits widely spread porosities and permeabilities compared to the other two characterised dolomitisation models, indicating better reservoir properties wherever anhydride cement is either absent or subsequently dissolved (as in the Butmah Formation). Mixing zone dolomitisation was encountered in the Mauddud and Wajnah formations, providing moderate to good reservoir properties, whereas burial dolomitisation generally provides poor to moderate reservoir properties in all three studied formations. It was noted that dolomite cementation provides poor reservoir properties in both the Butmah and Mauddud formations. Both the Mauddud and Wajnah formations show poroperm relationships with the degree of scatter dependent on both differences in crystal size and pore connectivity, indicating the degree of formation heterogeneity. Combined, both quantitative and qualitative observations indicate that dolomitisation cannot be considered in isolation, but is co-active and co-dependent upon dissolution, cementation and fracturing. All of these processes can both cause and amplify dolomitisation, but can themselves be caused or amplified by dolomitisation. We have combined all of our observations to propose a new model which relates different reservoir quality outcomes to the occurrence, intensity and history of different diagenetic processes as a first step in the petrophysical quantification of the effect of diagenetic processes on reservoir quality.

Pore‐Scale 3D Dynamic Modeling and Characterization of Shale Samples: Considering the Effects of Thermal Maturation

AbstractThe development of shale gas necessitates accurate modeling and characterization of these complicated formations, at both small and large scales. At the small scale, the studies based on experimental techniques have uncovered that the components and pore types in shales vary dramatically. Several pore types are identified and varied when the thermal maturation of shales changes. Therefore, accurate modeling and characterization of shale samples require taking such dynamic variations into consideration. This study presents a novel, dynamic, and three‐dimensional (3D) modeling technique considering pore‐system variation when the thermal maturation changes. The technique can construct dynamic shale models based on quartet structure generation set algorithm and morphological operation. This method can include various elements available in the shale samples in a very accurate way when the dynamic processes are reproduced. To evaluate the performance of the presented technique, 12 dynamic 3D shale models of three cases are constructed. These models are then characterized by analyzing the fractions of components and pores, pore and throat size distributions, coordination number distribution, fractal dimension, and tortuosity. Besides, gas transport in these dynamic 3D shale models is also simulated using pore network modeling to demonstrate the permeability variation of these models. Moreover, the fractions of interparticle and intraparticle pores and cementation degree are changed to further illustrate the capability of the developed algorithm. This study reveals such a dynamic modeling technique is a robust tool to construct various porous media with complicated elements and pores, which is not limited to shale samples.

INJECTION OF DISPERSED OIL-IN-WATER EMULSION TO IMPROVE VOLUMETRIC SWEEP EFFICIENCY DURING WATER FLOODING OF OIL RESERVOIRS

During water flooding of heterogeneous oil reservoirs, early breakthrough of water can occur and lead to poor volumetric sweep efficiency. Macro-emulsions with oil droplets dispersed in a continuous water phase [oil-in-water (o/w) emulsions], have the potential to block high-permeability zones in these reservoirs, and thereby improve the volumetric sweep by diverting the water flow from high-permeability layers toward lower-permeability layers. In the present work, the potential for produced water with dispersed oil to block sandstone rocks (with permeability of 150-2000 mD) was investigated. Different o/w emulsions with similar oil concentrations as in the produced water were prepared using synthetic oil and crude oil. Water-soluble surfactant was dissolved in synthetic formation water and homogenized with oil using a high-shear rate mixer at different speeds and mixing times. The prepared emulsions were injected into sandstone cores. A Coulter Counter Multisizer was used to measure the droplet size distributions in the injected emulsions and the produced effluent. The droplet size distributions in the emulsions and the pore throat size distributions in rock were compared. The flooding experiments demonstrated that injection of emulsions can significantly reduce the permeability, and depending on the initial permeability of the rock the permeability reduction was up to 47%. Emulsion has the potential to accelerate and improve oil production and reduce the water cut at low-cost investment. Further work is required to qualify this method for field applications.

Pore-throat characterization of unconsolidated porous media using watershed-segmentation algorithm

Pore-throat characteristics of porous media play important roles in various flow processes. However, pore size distribution (PSD) and throat size distribution (TSD) of various porous media have rarely been reported. Watershed-segmentation (WS) is a promising pore-throat identification method. To avoid over- and under-segmentations, a trial-and-error method was devised and validated using artificially ordered packings. Afterwards, we analyzed porous media with various characteristics, and comparisons with artificially ordered packing were made. More angular particles generated larger pores and throats. TSD of spherical particles was bimodal, whereas other particles resembled a normal distribution. Pore surface area and volume relation demonstrated a fractal behavior. Compared with medial axis (MA) method, PSD and TSD from WS method were larger but exhibited similar distribution trends. Normalizing the PSD with the median pore size yielded a single Gaussian model, demonstrating a possible PSD model. However, normalization to TSD data does not produce a single Gaussian model.

The heterogeneity of pore structure in lacustrine shales: Insights from multifractal analysis using N2 adsorption and mercury intrusion

Abstract A series of parameters from a variety of techniques, such as pore size distribution, surface area, pore volume, etc., have been used to characterize the pore structure of unconventional shale reservoirs. However, the investigation on the quantification of pore structure heterogeneity is still scarce. In this aspect, a multifractal theory combined with N2 adsorption and mercury intrusion was used to obtain pore structure characteristics and quantify the heterogeneity of pore size distribution of nine lacustrine shale samples from the second member of Kongdian Formation (Ek2) in Cangdong Sag, Bohai Bay Basin, China. The results show that the Ek2 shale contains complex pore network, and pores with small pore size predominate in pore system. Both N2 adsorption branches and pore throat size distributions from mercury intrusion demonstrate multifractal nature. The width of singularity spectra from multifractal analysis is used to quantitatively characterize the heterogeneity degree of pore size distribution and shows good consistency with pore size distributions derived from N2 adsorption and mercury intrusion. The pore structure from mercury intrusion is much heterogeneous than that from N2 adsorption, indicating that an increased number of large pores will increase the heterogeneity of pore size distributions. Compared with other rock compositions, TOC has an obvious impact on the heterogeneity of pore structure in small pore size range.

Image-based simulation of formation damage during suspension injection in homogeneous and heterogeneous porous media: The impact of pore-scale characteristics on macroscopic properties

Solid invasion into the near wellbore region could be considered as the main mechanism of formation damage during drilling and completion operations. This challenge could be alleviated, to a high extent, with the correct size tailoring of the solid particle in the intruding fluids. This requires a better understanding of the effect of some pore scale properties of formation rocks on macroscopic properties. In this study, the capability of the X-ray Computed Tomography (XCT) technique was utilized to relate the local morphological and topological characteristics of porous media to macroscopic hydraulic properties. Both homogeneous and heterogeneous porous samples were considered and the damage was induced by injecting particulate fluid of poly-dispersed solid particles. The spatial variation of porosity, permeability, pore size distribution, throat size distribution, and sectional damage ratio evaluated before and after the induced damage in these samples. The results for homogeneous sample showed that the damage distribution does not follow a uniform pattern and it strongly depends on the structure of the pores in each section of the sample. As for heterogeneous sample, a wide range of damage ratios from nearly 90% in the coarse layer to 16% in the fine layer was observed. The longitudinal damage in each layer corresponds well with one-third to one-seventh of throat size at each subsection. Compared to homogeneous sample, the size exclusion effect is more evident in heterogeneous sample in which most of the damage happens near to the inlet face.

Investigation on Plugging and Profile Control of Polymer Microspheres as a Displacement Fluid in Enhanced Oil Recovery.

Polymer microspheres (PMs) are used as a new material to recover residual oil left in unswept oil areas after secondary recovery methods. The fact that the PMs plug the macropores causes the flow direction of the injection fluid to be transferred from macropores to micropores. In order to investigate the plugging and profile control mechanisms of PMs in reservoirs, four kinds of PMs with different particle sizes and four kinds of artificial cores with different permeability were selected for flooding tests, including plugging experiments and profile control experiments. The pore throat size distribution of cores was characterized by nuclear magnetic resonance (NMR) technology. The particle size distribution of PMs used in the experiment was characterized using a laser particle size analyzer. The results showed that there are six matching relationships existing simultaneously between pore throats and PMs based on theoretical analysis, which are completely plugging, single plugging, bridge plugging, smooth passing, deposition, and deformable passing. A key principle for optimizing PMs in profile control is that the particle size of the selected PMs can enter the high permeability layer well, but it is difficult for it to enter the low permeability layer. The results of this paper provide a theoretical basis for the optimal particle size of PMs during the oil field profile control process.