Throat Structure Research Articles

Clinical and Epidemiological Profile of Otorhinolaryngology Diseases at a Tertiary Hospital in Morang District: A Descriptive Cross-Sectional Study

Introduction: Otorhinolaryngology, dealing with disorders of the ears, nose, throat, and related structures, poses significant health challenges. However, there is a dearth of extensive clinical and epidemiological data on these ailments in the specific geographic area under study. Understanding the characteristics of otorhinolaryngology diseases is crucial for effective healthcare planning and resource allocation. Objective: This study aimed to determine the clinical and epidemiological profile of otorhinolaryngology diseases at a tertiary hospital in Morang District, Nepal. Methodology: An observational descriptive cross-sectional study was conducted at the Otorhinolaryngology department of a tertiary hospital in eastern Nepal from January 15 to February 15, 2024. Data from 600 patients presenting at the department over one month were meticulously analyzed. Results: The median age of patients was 28 years, with the most prevalent age group being 21- 30 years (23%). A majority (56%) were male, and belonged to the Brahmin/Chhetri caste (44.3%). Most patients (85%) initially visited the hospital through OPD, with ear-related issues (35.2%) being the most common complaint. Epistaxis (10.3%) was the most frequent diagnosis, followed by allergic rhinitis (9%) and ear wax issues (8.2%). The prevalence of carcinoma was 12(2%). The majority (77.3%) underwent medical treatment. Outpatient admissions were observed in 68(13.3%) of cases, with emergency admissions accounting for 42(62.6%). Conclusion: Epistaxis, allergic rhinitis, and ear wax problems were commonly encountered. Most patients underwent medical treatment, with only a minority requiring hospital admission, primarily through outpatient services.

Numerical Simulation of Time-Varying Characteristics in a High-Permeability Sandstone Reservoir: A Case of Gaoqian Southern Area

In the process of long-term water flooding in the Gaoqian Southern Area with an average porosity of 30% and an average permeability of 1333.5×10−3 μm2, the fluid-solid interaction among oil, water, and rock has a great influence on the pore structure. It has resulted in changes in reservoir parameters with the extension of time. This paper used electron microscopy scanning, mercury injection, X-ray diffraction, physical properties, and oil-water relative permeability curves to study the variation of clay mineral content, pore throat structure, porosity, permeability, and relative permeability curves of high-permeability sandstone after high-pressure water flooding. The results showed that clay minerals such as montmorillonite and kaolinite were dissolved, hydrated, and migrated after long-term water flooding, which resulted in the decrease of clay mineral content in fine sandstone and medium sandstone, the increase of pore throat radius, and the decrease of displacement pressure, median pressure, and separation coefficient. The saturation of the isotonic point of the oil-water relative permeability curve was obviously shifted to the right, the hydrophilicity was significantly enhanced, and the porosity and permeability were effectively improved, but there was a blockage of the throat less than 2 μm in the fine sandstone. In addition, this paper established the equations of water injection, permeability, irreducible water saturation, residual oil saturation, and oil-water relative permeability curve coefficient and establishes the initial permeability model with the well data before water flooding. The logging interpretation results of development wells in the process of water flooding as verification data were used, and the relative error of permeability far lower than the general requirement of permeability error within an order of magnitude was less than 30%, which verified the rationality of the method.

Hydrodynamic resistance of pore–throat structures and its effect on shale oil apparent permeability

Oil transport is greatly affected by heterogeneous pore–throat structures present in shale. It is therefore very important to accurately characterize pore–throat structures. Additionally, it remains unclear how pore–throat structures affect oil transport capacity. In this paper, using finite element (FE) simulation and mathematical modeling, we calculated the hydrodynamic resistance for four pore–throat structure. In addition, the influence of pore throat structure on shale oil permeability is analyzed. According to the results, the hydrodynamic resistance of different pore throat structures can vary by 300%. The contribution of additional resistance caused by streamline bending is also in excess of 40%, even without slip length. Furthermore, Pore–throat structures can affect apparent permeability by more than 60% on the REV scale, and this influence increases with heterogeneity of pore size distribution, organic matter content, and organic matter number. Clearly, modeling shale oil flow requires consideration of porous–throat structure and additional resistance, otherwise oil recovery and flow capacity may be overestimated.

An Experimental Investigation of Interaction between CO2 Solution and Rock under Reservoir Conditions in the Jimsar Shale Oil Formation

Chemical sequestration is one important manner of CCUS. The injection of CO2 into an oil reservoir can not only sequestrate CO2 but also raise the oil recovery factor. The performance of chemical sequestration of CO2 depends on the interaction between CO2 solution and reservoir rock. In this paper, we have conducted three different scales of experiments, e.g., microscopic scale, core scale, and time scale, to fully investigate the interaction and resultant variation to mineral content, microscopic structure, porosity, and permeability under reservoir conditions (i.e., reservoir temperature of 90 °C) in Jimusar shale oil formation. The microscopic-scale experiment applied SEM and hyperspectral scanning to obtain microscopic pore throat structure and element distribution before and after soaking the rock in CO2 solution. The core-scale experiment employed XRD to evaluate mineral content variation caused by CO2 solution. Core flooding experiments were conducted to evaluate porosity and permeability variation caused by the dissolution of CO2 solution into the core samples. The third type of experiment was employed to investigate the effect of time sequence on the dissolution, in which the time ranged from 1 day to 14 days continuously. The experimental results indicate that, under Jimsar reservoir conditions, CO2 solution exhibits a relatively robust dissolution capability, causing significant alterations to the properties of the core samples. Specifically, the CO2 solution effectively dissolves carbonate upon contact. Calcite is the primary target for dissolution, followed by dolomite. In the presence of sufficient CO2, complete dissolution of all carbonates is achievable. On a microscopic scale, dissolution primarily occurs in the calcium-rich areas, leaving other regions unaffected. The typical pore size resulting from CO2 solution-induced dissolution ranges from several to dozens of micrometers. This dissolution process significantly enhances both porosity and permeability. For Jimsar shale core samples, porosity experienced an increase of over 20%, and permeability nearly doubled. Under Jimsar reservoir conditions at 90 °C, CO2 solution can consume all carbonates present in core samples within 8 days. The increase in porosity and permeability is rapid during the initial days and stabilizes around the 6th day. These research findings establish a theoretical foundation for CO2 chemical sequestration.

Effect of the pore structure characteristics of coal samples on the dynamic adsorption of water vapor

In order to study the dynamic adsorption process of water vapor in the pore structure of different coal samples (YJL for lignite, SEK for bituminous coal and BJ for anthracite). The pore structure characteristics of the three coal samples were analyzed by mercuric pressure method, liquid nitrogen adsorption method and infrared spectroscopy. Further, the water vapor adsorption capacity of the three coal samples under different humidity conditions was determined by dynamic water vapor sorption (DVS) experiments. In addition, the monolayer adsorption and multilayer adsorption at different humidity were calculated using the Dent model. The results showed that YJL had the largest surface pore volume and oxygen functional group parameter (IO = 12.41), and its water vapor adsorption capacity was also the highest. However, under high humidity conditions, the presence of a large number of pore throats in the YJL coal samples hindered multilayer adsorption, resulting in a water vapor adsorption percentage of only 18.07 %. On the other hand, SEK has a small oxygen functional group parameter (IO = 5.81), poor pore connectivity, and a certain pore throat structure, resulting in a low water vapor adsorption capacity of SEK coal samples, with a water vapor adsorption proportion of only 23.76 %. BJ coal has a large pore volume and a large number of oxygen functional groups on the surface (IO = 8.84), which has a good pore connectivity and the least number of pore throats structure, resulting in a water vapor adsorption ratio is higher at 87.38 %. On this basis, cylindrical and wedge-shaped pore models of coal samples were constructed, and molecular dynamics simulations were carried out to investigate the adsorption characteristics of water vapor in these pore models. The results show that the adsorption process of water molecules in coal develops continuously with “initial-water chain-water bridge-water lock”. By summarizing and analyzing the above experimental results, four control mechanisms of coal pore characteristics affecting water vapor adsorption were clarified. These findings are of great significance for studying the movement of water vapor in coal seams and understanding the degree of water confinement caused by hydraulic control measures.

A New Model for Predicting Permeability of Chang 7 Tight Sandstone Based on Fractal Characteristics from High-Pressure Mercury Injection

Accurately predicting permeability is important to elucidate the fluid mobility and development potential of tight reservoirs. However, for tight sandstones with the same porosity, permeability can change by nearly three orders of magnitude, which greatly increases the difficulty of permeability prediction. In this paper, we performed casting thin section, scanning electron microscopy and high-pressure mercury injection experiments to analyze the influence of pore structure parameters and fractal dimensions on the permeability of Chang 7 tight sandstones. Furthermore, the key parameters affecting the permeability were optimized, and a new permeability prediction model was established. The results show that the pore throat structure of Chang 7 tight sandstone exhibits three-stage fractal characteristics. Thus, the pore throat structure was divided into large pore throat, medium pore throat and small pore throat. The large pore throat reflects the microfracture system, whose fractal dimension was distributed above 2.99, indicating that the heterogeneity of the large pore throat was the strongest. The medium pore throat is dominated by the conventional pore throat system, and its fractal dimension ranged from 2.378 to 2.997. Small pore throats are mainly composed of the tree-shaped pore throat system, and its fractal dimension varied from 2.652 to 2.870. The medium pore throat volume and its fractal dimension were key factors affecting the permeability of Chang 7 tight sandstones. A new permeability prediction model was established based on the medium pore throat volume and its fractal dimension. Compared to other models, the prediction results of the new model are the best according to the analysis of root mean square value, average absolute percentage error and correlation coefficient. These results indicate that the permeability of tight sandstones can be accurately predicted using mesopore throat volume and fractal dimension.

Heating-induced release of trapped bubbles from dead-end pore throats filled with nonvolatile liquid

The release of trapped bubbles from dead-end pore throats filled with nonvolatile liquid has widespread applications in gas–liquid reactors, radiators, foam flooding, ceramic sintering, and droplet microcarriers. As conventional pressure-driven flow cannot induce the transport of bubbles in dead-end pores, this paper explores the possibility of using heating to control the release of bubbles from dead-end pore throats. Visualization experiments of the microfluidics within a dead-end pore throat structure are conducted to address the release process of bubbles during heating. An increase in temperature causes dissolved gas in the solution to be transferred to the bubble, which enhances the bubble pressure and enables the bubble to pass through the pore throat. We analyze the effects of the initial bubble radius and initial temperature on the critical temperature Tcr at which the bubble passes through the pore throat. A larger initial radius does not necessarily make it more difficult for the bubble to pass through the throat, but there is a critical radius above which any increase in radius produces a lower value of Tcr. A theoretical model considering diffusion mass transfer, capillary forces, and corner film flows is developed, and this model is found to be in good agreement with the experimental results. Finally, we obtain three dimensionless numbers that can be used to predict Tcr. Our work provides guidance for the effective regulation of diffusive growth and the heating-induced release of bubbles from dead-end pore throats.

Three-dimensional modeling of nanoconfined multiphase flow in clay nanopores using FIB-SEM images of shale

<p>Understanding the flow characteristics within shale nanopores is crucial for enhancing hydrocarbon recovery. However, the flow characteristics of wetting and non-wetting fluids on nanopore surfaces differ significantly, limiting the accurate prediction of hydrocarbon accumulation and migration. This work introduces the Euler-Euler volume of fluid method to establish a multiphase flow numerical model in shale nanopores, considering complex pore topology, slip flow, and capillary effects. Based on natural three-dimensional shale nanoporous systems constructed from FIB-SEM images, single-phase water/oil flow and water-oil forced imbibition simulations are carried out under the complete wetting condition. Results show that the displacement pressure is reduced and the imbibition rate is elevated considering nanoscale slip effects. As imbibition progresses, the pressure and imbibition rate gradually converge toward the values observed in conventional flows. In complete wetting nanoporous systems, water flow experiences high pressure and low velocity, whereas the pressure for oil flow is significantly reduced. Forced imbibition may undergo a transition from capillary force-dominated to viscous force-dominated, with a negative displacement pressure at the initial stage. Furthermore, the fluctuations in water-oil mass flow considering the slip effect are less pronounced than those observed in conventional flows, leading to reduced residual fluid saturation in blind-end pores and pore bodies caused by snap-off events. Pore systems with poor connectivity and narrow throat structures correspond to low displacement efficiency. The findings of this work explain the impact of nanoscale slip effects on flow characteristics in unconventional reservoirs, contributing to the reasonable assessment of fluid flow capacity and facilitating production planning.</p>

A new permeability model of the compressible tailings thickening bed based on the throat structure parameters

Microstructural and permeability changes in the compressible tailings thickening bed (CTTB) structure during the tailings thickening process are critical for preparing high-concentration filling slurry. Computer tomography (CT) is employed to obtain the pore structure of the bed at different pressures with and without shear. Based on the study of PNM and bed permeability, a new permeability model is proposed. The results indicate that the pore and throat diameters decrease with increasing bed pressure. The pore and throat diameters are smaller with rake shear compared to the situation without shear. Fluid in the CTTB structure is primarily discharged to the top of the thickening bed through the throat structure in the PNM, and the CTTB permeability decreases with increasing Tw value of the throat. The new model proposed in this study, is more accurate in predicting the CTTB permeability than the Xu and Yu, KC, and Civan models.

Pore- and Core-Scale Recovery Performance of Consortium Bacteria from Low-Permeability Reservoir.

Performance evaluation of microorganisms that have emulsifying and degrading effects on crude oil has been extensively conducted in the laboratory. However, the ultimate goal of microbial enhanced oil recovery is field application, so the pilot simulation experiments are crucial. In this study, a micro-visualization model and the real cores were chosen to investigate the actual recovery efficiency and the mechanism of the consortium bacteria B-ALL, which has been proven to have good emulsification and degradation effects in lab studies in porous media. At the same time, the cast thin sections and rate-controlled porosimetry were combined to analyze the pore throat structure of the displacement core. It was found that the recovery efficiency was positively correlated with the microbial injection volume as well as the incubation time. For the microscopic model with high pores and high permeability, the efficiency of secondary water flooding can be increased by 44.77% after six days of incubation with two pore volume microbes. For the real tight cores, the maximum secondary water flooding efficiency under the same condition was 6.98%. Through visual modeling, microorganisms increase the oil washing efficiency mainly by emulsification and changing the wettability. The generated oil droplets will play a role in plugging and improving the wave efficiency. However, tight reservoirs have the characteristics of large pores and small throats, and curved and necking throats are developed, greatly reducing permeability. The microbial recovery efficiency was lower under shorter cultivation times. This study provides a practical basis for the application of consortium bacteria in tight oil fields to enhance recovery.

Micropore Structure of Deep Shales from the Wufeng–Longmaxi Formations, Southern Sichuan Basin, China: Insight into the Vertical Heterogeneity and Controlling Factors

The microscopic pore throat structure of shale reservoir rocks directly affects the reservoir seepage capacity. The occurrence and flow channels of shale gas are mainly micron–nanometer pore throats. Therefore, to clarify the microstructural characteristics and influencing factors of the deep organic-rich shales, a study is conducted on the marine shale from the Upper Silurian to Lower Ordovician Wufeng–Longmaxi Formation in the southern Sichuan Basin. Petrographic lithofacies division is carried out in combination with petro-mineralogical characteristics, and a high-resolution scanning electron microscope, low-temperature nitrogen and low-temperature carbon dioxide adsorption, and micron-computed tomography are used to characterize the mineral composition and pore structure qualitatively and quantitatively, upon which the influencing factors of the microstructure are further analyzed. The results show that with the increase in burial depth, the total organic carbon content and siliceous mineral content decrease in the Wufeng formation to Long-11 subsection deep shale, while clay mineral content increases, which corresponds to the change in sedimentary environment from anoxic to oxidizing environment. Unexpectedly, the total pore volume of deep shale does not decrease with the increase in burial depth but increases first and then decreases. Using total organic carbon (TOC), siliceous mineral content showed a good correlation with total pore volume and specific surface area, with correlation coefficients greater than 0.7, confirming the predominant role of these two factors in controlling the pore structure of deep shales. This is mainly because the Longmaxi shale is already in the late diagenetic stage, and organic matter pores are generated in large quantities. Clay minerals have a negative correlation with the total pore volume of shale, and the correlation coefficient is 0.7591. It could be that clay minerals are much more flexible and are easily deformed to block the pores under compaction. In addition, the longitudinal heterogeneity of the deep shale reservoir structure in southern Sichuan is also controlled by the thermal effect of the Emei mantle plume on hydrocarbon generation of organic matter and the development of natural microfractures promoted by multistage tectonic movement. Overall, the complex microstructure in the deep shales of the Longmaxi Formation in the southern Sichuan Basin is jointly controlled by multiple effects, and the results of this research provide strong support for the benefit development of deep shale gas in southern Sichuan Basin.

Using digital cores and nuclear magnetic resonance to study pore-fracture structure and fluid mobility in tight volcanic rock reservoirs

Pore-fracture structure characterization and fluid mobility analysis are key to the effective development of tight reservoirs. However, it is difficult to accurately characterize the pore-fracture structure of tight volcanic rocks using a single method, and the mechanisms of fluid mobility are not fully understood. A combination of X-ray diffraction, casting thin section observations, scanning electron microscopy, high-pressure mercury injection, constant-speed mercury injection, nuclear magnetic resonance (NMR), X-ray computed tomography, and the advanced mathematical algorithms in the AVIZO visualization software was used to analyze the Permian tight volcanic rock in the ZhongGuai area of the Junggar Basin to investigate its overall pore-fracture structure characteristics. On this basis, NMR centrifugation experiments were conducted to monitor the fluid migration dynamics in the tight volcanic rocks, and the mobile fluid migration characteristics were studied based on the NMR T2 spectra. The results show that the porosity and permeability of the samples are 0.2–18.7 % (avg. of 8.3 %) and 0.001–6.680 × 10−3μm2 (avg. of 1.602 × 10−3μm2), respectively, and the various pore types are due to the differences in cementation and compaction. The distribution of the pore throats are mainly contiguous and isolated, and the connected pores are mainly distributed in enriched bands, which is due to the interconnection of gas pores, intergranular pores, and dissolution fractures; while the disconnected pores are mainly isolated, which is related to the development of inter-gravel dissolved pores and matrix dissolution pores. In addition, the contribution of the pore connectivity to seepage is greater than that at the pore scale. The pores in the tight volcanic rock have a wide range of sizes, from 3 nm to 120 μm, and are dominated by Gaussian and bimodal distribution patterns. The micron-scale pore radius in this area is mainly 4.47–31.56 μm. Also, the fractures can be divided into three types according to their occurrence and openings. They are mainly high-angle structural fractures and vertical fractures; the pore-fracture structures have strong heterogeneity, and the fractures play a larger role on the seepage of oil and gas. The connectivity of the pore throats in the tight matrix is poor, and the pore throat structure has a great influence on fluid mobility. Subsequently, the movable fluid saturation increases with increasing permeability, and the fractures and micropores have less flow resistance and are more conducive to water flow than small pores. This study provides new insights for the exploitation of similar tight reservoirs.

Experimental Simulation on the Stress Disturbance Mechanism Caused by Hydraulic Fracturing on the Mechanical Properties of Shale Formation

Hydraulic fracturing is an indispensable technology for the development of shale oil and shale gas. Knowing the changes in the rock mechanical properties and failure modes during hydraulic fracturing is the key to improving the efficiency of hydraulic fracturing. Based on experiments and simulations, it can be concluded that the injection of fracturing fluid in the hydraulic fracturing caused deformation of the fracture surface, and the rock mechanical properties experienced degradation with a maximum reduction in the rock mechanical properties of 44.24%. As indicated in the experiments, the displacement of the measurement point was decreased with the distance increase between the injection point and the measurement point. According to the numerical simulations, tensile failure is the main failure mode in hydraulic fracturing, but the percentage of shear failure had an obvious increase with the increase in distance between the injection point and the measurement point. Comparing DDS #1 and DDS #5, the DDS #5 measurement point was farther away from the injection point, and the average percentage of shear failure increased from 21.94 to 52.72%. Meanwhile, the increase in the branch fractures also caused shear failure to occur. Comparing Sample 1 and Sample 3, in Sample 3, which had more branch fractures, the average percentage of shear failure increased from 33.12 to 37.58%. Due to the porous medium of the reservoir rock, the enormous pressure generated during the injection of fracturing fluid caused significant deformation of the fracture surface, leading to the tensile failure of the rock. The displacement of the fracture surface caused by the fracturing fluid injection also led to the deformation of the pore throat structure; thus, the shear failure increased when the measurement point was away from the injection point.

Study on Matrix Damage and Control Methods of Fracturing Fluid on Tight Sandstone Gas Reservoirs.

Hydraulic fracturing is a highly effective method for stimulating the development of gas reservoirs. However, the process of pumping fracturing fluid (FF) into the reservoir unavoidably causes damage to the surrounding matrix, leading to a decrease in the overall stimulation effect. To assess the extent of matrix permeability damage caused by the intrusion of FF, as well as its impact on the pore throat structure, and to propose appropriate measures to control this damage, we conducted a series of experimental studies on tight gas reservoirs. These studies included mercury intrusion, core flow, nitrogen adsorption, linear expansion, and contact angle measurements. The findings revealed that the damage inflicted on matrix permeability by FF was significantly greater than that caused by its gel-breaking counterpart. Surprisingly, the damage rate of the rejecting fluid to the matrix was found to be comparable to that of its gel-breaking counterpart. The fractal dimension (D2) was observed to have a strong correlation with surface area, pore volume, and mean pore size, making it an effective means of characterizing pore structure characteristics. After the rock samples were displaced by the formation water, the D2 value decreased, leading to a decrease in the complexity of the pore throat structure and an increase in matrix permeability. Conversely, the displacement of the FF increased the D2 value, indicating a gradual complication of the pore throat structure and a more uneven distribution of pore sizes. The inclusion of polyamide in antiexpansion FF, as well as its gel-breaking counterpart, proved to be effective in inhibiting the hydration and expansion of clay minerals, thereby reducing water-sensitive damage. Additionally, the use of surfactants with low surface tension enhanced the flowback rate of FF by increasing the contact angle and reducing the work of adhesion. This, in turn, helped to decrease the apparent water film thickness and expand gas flow channels, ultimately improving gas permeability.

Numerical Modeling of Shale Oil Considering the Influence of Micro- and Nanoscale Pore Structures

A shale reservoir is a complex system with lots of nanoscale pore throat structures and variable permeability. Even though shale reservoirs contain both organic and inorganic matter, the slip effect and phase behavior complicate the two-phase flow mechanism. As a result, understanding how microscale effects occur is critical to effectively developing shale reservoirs. In order to explain the experimental phenomena that are difficult to describe using classical two-phase flow theory, this paper proposes a new simulation method for two-phase shale oil reservoirs that takes into account the microscale effects, including the phase change properties of oil and gas in shale micro- and nanopores, as well as the processes of dissolved gas escape, nucleation, growth and aggregation. The presented numerical simulation framework, aimed at comprehending the dynamics of the two-phase flow within fractured horizontal wells situated in macroscale shale reservoirs, is subjected to validation against real-world field data. This endeavor serves the purpose of enhancing the theoretical foundation for predicting the production capacity of fractured horizontal wells within shale reservoirs. The impact of capillary forces on the fluid dynamics of shale oil within micro- and nanoscale pores is investigated in this study. The investigation reveals that capillary action within these micro- and nanoscale pores of shale formations results in a reduction in the actual bubble point pressure within the oil and gas system. Consequently, the reservoir fluid persists in a liquid monophasic state, implying a constrained mobility and diminished flow efficiency of shale oil within the reservoir. This constrained mobility is further characterized by a limited spatial extent of pressure perturbation and a decelerated pressure decline rate, which are concurrently associated with a relatively elevated oil saturation level.

Lithofacies influence characteristics on typical shale pore structure

Clarifying the three-dimensional pore throat structure characteristics of shale is the foundation for efficient development of shale oil and gas. In this paper, firstly, by using FIB-SEM high-tech characterization technology, three-dimensional quantitative characterization of shale pore-throat structures under different lithological conditions was carried out. Secondly, reconstruct through binary images to establish a three-dimensional pore-throat structure model. Thirdly, the coupling mechanism of “pore distribution, form factor, coordination number, throat diameter” is quantitatively clarified. Results show that: (a). For six shale samples, the volume fraction is mostly concentrated in the range of pore diameter greater than 20 nm and less than 300 nm. When the pore diameter is greater than 300 nm, the proportion of volume fraction is lower. (b). For six shale samples, the pore quantity distribution is mostly concentrated in the range of pore shape factor greater than 0.04 and less than 0.07. When the pore diameter is less than 0.04 or greater than 0.07, the pore quantity distribution is lower. (c). For six shale samples, the pore volume distribution is mostly concentrated in the range of coordination number greater than 1 and less than 4. When the pore diameter is less than 1 or greater than 4, the pore volume distribution is lower. (d). For six shale samples, the throat volume distribution is mostly concentrated in the range of throat diameter greater than 8 nm and less than 120 nm. When the throat diameter is less than 8 nm or greater than 120 nm, the throat volume distribution is lower. The pore structure of shale is very complex, mainly manifested by a variety of pore types.

Investigation of the Microscopic Pore–Throat Structure Difference of Tight Sandstone/Glutenite Based on a Multifractal Method

Investigation of the Microscopic Pore–Throat Structure Difference of Tight Sandstone/Glutenite Based on a Multifractal Method

Pore Structure and Permeability Characterization of Tight Sandstone Reservoirs: From a Multiscale Perspective

Due to the influence of a sedimentary environment, sandstone characteristics, diagenesis, and geological structure, the complexity and heterogeneity of the pore structure in tight sandstone reservoirs act as key barriers for accurate characterization of the influence of different pore microparameters on reservoir physical properties. This paper obtained different scale microscopic pore–throat parameters through mercury intrusion porosimetry (MIP) and digital core reconstruction models. According to the connectivity of different scale pores, connected pore structure parameters, and pore fractal dimension, the pore structure characteristics of tight sandstone reservoirs were evaluated. Subsequently, through partial correlation analysis, the contribution rate of different scale connected pore parameters to permeability and porosity was clarified. Then, a multiparameter fitting equation for the absolute permeability and porosity of the rock was obtained through multiple regression analysis. The analysis results show that (1) the connected pores of tight sandstone reservoirs are mainly mesopores, with the pore radius distribution between 1 and 3 μm, and throat radius distribution between 0 and 2 μm. (2) The complexity of the pore structure in tight sandstone reservoirs is most strongly correlated with the fractal dimension of the pore structure at the mesoporous scale. (3) The pore radius and throat length at the mesoporous scale have the strongest correlation with the absolute permeability of the rock, and the pore radius at the mesoporous scale has the strongest correlation with the porosity of the rock. (4) The multiparameter fitting equation established by multiple regression analysis quantitatively and qualitatively analyzed the impact of microscopic parameters of the pore–throat structure at different scales on reservoir properties, achieving the purpose of predicting the absolute permeability and porosity of the tight sandstone reservoir. It provides guidance for the study of the pore structure and permeability characteristics of tight sandstones.

Quantifying the Microdistribution of Different Fluid Types in the Multiscale Pore Throat Structure of Low-Permeability Conglomerates

The volumes of different fluid types and the pore throat structure in low-permeability reservoirs are crucial parameters for understanding flow mechanisms and predicting production performance. The previously applied methods for distinguishing different fluid types are mainly based on T2 spectra under saturated, centrifugal, and heat-treated conditions. However, for rocks with different mineral compositions and pore structures, the critical temperature between capillary-bound fluid (CAF) and clay-bound fluid (CLF) differs from 60 to 100 °C. Moreover, the alteration of temperature can cause the transformation of clay minerals and a change in a nanopore structure. Herein, an improved method that integrates nuclear magnetic resonance (NMR) tests (n-dodecane-saturated, centrifugal, and spontaneous imbibition treatment conditions) and multicycle mercury intrusion porosimetry, was proposed for quantitatively evaluating the microdistributions of different fluid types, classifying the pore throat system, and analyzing the relationship between pore throat structure and different fluid types in low-permeability conglomerates. Based on the fractal characteristics and mercury intrusion/extrusion characteristics of pore throats at different scales, the pore throat system in these conglomerates was divided into macropore throats (>1 μm), mesopore throats (0.2–1 μm), and micropore throats (<0.2 μm). Macropore throats are connected to intergranular pores (>100 ms); mesopore throats are mostly connected to intergranular pores and intragranular dissolved pores (>10 ms); and micropore throats are connected to intragranular dissolved pores (<10 ms) and clay-related pores (<3 ms). The proportions of movable fluid, CAF, and CLF in the low-permeability conglomerates are 20.4–57.4%, 6.67–32.2%, and 36.0–47.4%, respectively. The movable fluids are mainly distributed in macropore throats and mesopore throats. CAF mainly exists in the micropore throats (pore throat radius <0.2 μm and pore size <10 ms). CLF is mainly distributed in pores with T2 < 3 ms, that is clay-related pores. The improved method of fluid typing is suitable for low-permeability or tight clastic reservoirs (excluding shale).

Micropore Throat Structure and Movable Fluid Characteristics of Chang 63 Tight Sandstone in Baibao Area of Ordos Basin

Tight sand is an important unconventional reservoir. Aiming at the problem of large unused reserves and the poor development effect of Chang 63 reservoir, this paper researches reunderstanding reservoir and evaluating unused reserves. Employing rock slice and scanning electron microscope (SEM), the experiment of low-field nuclear magnetic resonance (NMR), water-oil relative permeability experiment, reservoir space, movable fluid, and oil-water seepage characteristics was studied. The factors affecting NMR T 2 cutoff, controlling factors of movable fluids, and controlling factors of displacing efficiency in tight sandstone reservoirs are discussed. The study demonstrates that (1) the mean pore volume and permeability are 4.4% and 0.068 mD, respectively. The reservoir pertains to tight sandstone, mainly intergranular pore and dissolution pore, and the intercalated materials are mainly chlorite and illite. (2) The characteristic of the NMR T 2 spectrum has bimodal characteristics and can be subdivided into two classes: left peak dominant and right peak dominant. The mean value of mobile fluid saturation was 17.9%. (3) According to the relative permeability curve pattern, it is divided into four categories, and the mean bound water saturation is 29.9%. The average irreducible oil saturation was 40.6%. The mean oil flooding efficiency was 40.2%. (4) The better the pore-throat relationship, the lower the T 2 cutoff, the stronger ability of the fluid migration ability, and the higher of a percentage of active fluid. The percentage of active fluid in a low-permeability reservoir is affected by the reservoir’s physical property and pore structure.