Large Pore Throats Research Articles

Fractal research on pores in oil and gas reservoirs - Inspirations from over 700 high pressure mercury injection experiments

Pore fractal has now become an important research method to study reservoir pore heterogeneity and complexity, and is widely used in unconventional reservoir research. However, its guiding significance for reservoir research and the relationship between fractal dimension and reservoir pore structure parameters are not yet clear. This undoubtedly hinders the further development of fractal in reservoir research. This time, comprehensive research, including pore fractals, was conducted on over 700 high-pressure mercury injection experiments, providing guidance for reservoir pore fractal research. The research results indicate that there are significant differences in the application of fractals in different oil fields. Generally, the curves of high-pressure mercury injection experiments present 1–4 segment fractals, among which the 2 and 3 segment fractals are the most common, and the 4 segment fractals are the least common. There is a correlation between the number of the fractal segments with permeability and pore throat sorting coefficient. The lower the permeability, the more obvious the multi-segment fractal features. The more fractal segments, the greater the fractal dimension corresponding to each segment. The number of fractal segments can characterize the distribution of reservoir pore size. The fractal dimension of large pore-throats is greater than that of small pore-throats. On the whole, there is a negative correlation between fractal dimension and permeability, porosity, and pore throat radius. But this correlation is unstable in different oilfields. And the average value of the overall correlation coefficient is only about 0.5. Different fractal segments in a multi-segment fractal represent different types of pores. The application of pore fractal dimension needs to be combined with pore types.

Dispersion of silica-encapsulated DNA magnetic particles in a homogeneous sand tank

In this study, we focused on the 3D dispersion of colloids. To our knowledge, we were the first to do so. Thereto, we injected silica encapsulated DNA tagged superparamagnetic particles (SiDNAmag) in a homogeneous coarse grain sand tank. At four downstream locations, SiDNAmag concentrations were determined as a function of time. Longitudinal and transverse dispersivity values and associated uncertainties of SiDNAmag were determined using Monte Carlo modelling approach. The parameter associated uncertainties of hydraulic conductivity as well as of the effective porosity estimated from SiDNAmag breakthrough curves were statistically similar to those estimated from salt tracer breakthrough curves. Further, the SiDNAmag dispersivity uncertainty ranges were then statistically compared with the salt tracer (NaCl, and fluorescein) dispersivities. Our results indicated that time to rise, time of peak concentration and shape of the breakthrough curves of SiDNAmag were similar to those of the salt tracer breakthrough curves. Despite the size difference between the salt tracer molecules and SiDNAmag, size exclusion did not occur, probably due to the large pore throat diameter to SiDNAmag diameter ratio. The median longitudinal dispersivity (αL) of salt tracer and SiDNAmag were 4.9 and 5.8 × 10−4 m, respectively. The median ratio of horizontal and vertical transverse dispersivities to αL, (αTH /αL and αTV /αL, respectively), for salt tracer and SiDNAmag ranged between 0.52 and 0.56. Through the statistical tests, we concluded that the longitudinal and traverse dispersivities of SiDNAmag were not statistically significantly different from salt tracer in 3 dimensions and could be used to characterize the dispersive properties of the medium we used. Our work contributes to a better understanding of 3D dispersion of SiDNAmag in saturated porous media.

Study of Pore–Throat Structure in Tight Triassic Sandstone: A Case Study on the Late Triassic Yanchang Formation, Southwestern Ordos Basin, China

In order to better understand pore–throat structure characteristics, the coupling relationship between micropore–throat structure and macro reservoir quality and influencing factors caused by authigenic minerals were studied. Petrographic analyses, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) were performed on a suite of tight reservoir samples from the Chang 8 Member of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. The results show that the pore–throat sizes obtained with the combination of PMI and NMR methods varied from nano- to microscale, revealing pore–throat sizes ranging from 0.001 μm to 70 μm, and showing that pore–throats with a radius larger than 1.0 μm are rare. Larger pore–throats with good connectivity (>rapex) account for a smaller part of the total pore volume, ranging from approximately 7.58% to 38.90% with an average of 22.77%, but account for more than 80% of contributions to permeability. The effective movable fluid porosity (φemp) measured by NMR, ranging from approximately 0.10% to 7.07% with an average of 2.56%, had a positive contribution to permeability. The contents of chlorite occurrence state, other than illite, are beneficial to pore–throat preservation. A new reservoir evaluation scheme of the Chang 8 reservoir is established. These research results provide a theoretical basis for the evaluation and development of tight sandstone oil and gas exploration.

Research on the Diagenetic Facies Division and Pore Structure Characteristics of the Chang 63 Member in the Huaqing Oilfield, Ordos Basin.

In tight sandstone reservoirs, diagenesis has a significant impact on the development of reservoirs and pore structures. To clarify the effect of diagenesis on the pore structure of tight sandstone, 12 samples of the Yanchang Formation in the basin were studied based on experiments such as high-pressure mercury intrusion and low-temperature nitrogen adsorption. The diagenetic facies in the study area are divided into two categories: strong cementation facies of carbonate minerals and strong compaction facies of soft component minerals, which are relatively unfavorable diagenetic facies, and stable facies of felsic minerals and strong dissolution facies of feldspar minerals, which are dominant diagenetic facies. The pore structure of the Chang 63 reservoir in the study area has obvious fractal characteristics, with a fractal dimension D 1 greater than D 2 and a greater heterogeneity of large pore throats. Compared to compaction and cementation, dissolution has a stronger controlling effect on the pore structure of reservoirs. In tight sandstone reservoirs with low porosity and permeability, dissolution has a more important impact on reservoir transformation and development. The intensity of different types of diagenesis in the Chang 63 reservoir affects reservoir heterogeneity, and the level of the reservoir heterogeneity affects the complexity of reservoir pore structure. In tight sandstone reservoirs, cementation has a stronger controlling effect on the structural complexity of large pores, while dissolution has a stronger controlling effect on the structural complexity of small pores. The dissolution has a strong control effect on the physical properties of the reservoir. This study provides insights into the relationships among the diagenetic facies, reservoir quality, and pore structure of tight sandstone reservoirs. This study has reference significance for the exploration and development of tight oil in the research area.

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.

Microscopic pore-throat classification and reservoir grading evaluation of the Fengcheng formation in shale oil reservoir

Different basins in China have proposed various reservoir grading standards for shale oil. Based on a comprehensive understanding of the basic characteristics of the shale oil reservoir in the Mahu Depression, this paper uses data from high-pressure mercury injection, physical properties, nuclear magnetic resonance, depletion development, and CO2 displacement development tests to analyze the microscopic pore structure features of the Fengcheng Formation shale oil reservoir. On this basis, the classification boundaries of the pore throats in the shale oil reservoir were analyzed, and a reservoir grading standard suitable for the Fengcheng Formation shale was proposed: large pore throats (greater than 1000 nm), medium pore throats(100∼1000 nm), small pore throats (20∼100 nm), and ultra-small pore throats (less than 20 nm). The medium pore throat is the lower limit for depletion development, the small pore throat is the lower limit under CO2 displacement conditions, and the ultra-small pore throat cannot be utilized under current conditions. The classification effect of the shale oil reservoir is verified using the production characteristics of Well MY1, the liquid production profile, and the results of geological "sweet spots" studies. The results show that the classification scheme for the microscopic pore throats of the Fengcheng Formation shale oil is reliable and feasible.

Experimental study of the effects of a multistage pore-throat structure on the seepage characteristics of sandstones in the Beibuwan Basin: Insights into the flooding mode

To investigate the relationship between grain sizes, seepage capacity, and oil-displacement efficiency in the Liushagang Formation of the Beibuwan Basin, this study identifies the multistage pore-throat structure as a crucial factor through a comparison of oil displacement in microscopic pore-throat experiments. The two-phase flow evaluation method based on the Li–Horne model is utilized to effectively characterize and quantify the seepage characteristics of different reservoirs, closely relating them to the distribution of microscopic pores and throats. It is observed that conglomerate sandstones at different stages exhibit significant heterogeneity and noticeable differences in seepage capacity, highlighting the crucial role played by certain large pore throats in determining seepage capacity and oil displacement efficiency. Furthermore, it was found that the displacement effects of conglomeratic sandstones with strong heterogeneity were inferior to those of conventional homogeneous sandstone, as evidenced by multiple displacement experiments conducted on core samples with varying granularities and flooding systems. Subsequently, core-based experiments on associated gas flooding after water flooding were conducted to address the challenge of achieving satisfactory results in a single displacement mode for reservoirs with significant heterogeneity. The results indicate that the oil recovery rates for associated gas flooding after water flooding increased by 7.3%–16.4% compared with water flooding alone at a gas–oil ratio of approximately 7000 m3/m3. Therefore, considering the advantages of gas flooding in terms of seepage capacity, oil exchange ratio, and the potential for two-phase production, gas flooding is recommended as an energy supplement mode for homogeneous reservoirs in the presence of sufficient gas source and appropriate tectonic angle. On the other hand, associated gas flooding after water flooding is suggested to achieve a more favorable development effect compared to a single mode of energy supplementation for strongly heterogeneous sandstone reservoirs.

Tight gas charging and accumulation mechanisms and mathematical model

The gas-water distribution and production heterogeneity of tight gas reservoirs have been summarized from experimental and geological observations, but the charging and accumulation mechanisms have not been examined quantitatively by mathematical model. The tight gas charging and accumulation mechanisms were revealed from a combination of physical simulation of nuclear magnetic resonance coupling displacement, numerical simulation considering material and mechanical equilibria, as well as actual geological observation. The results show that gas migrates into tight rocks to preferentially form a gas saturation stabilization zone near the source-reservoir interface. When the gas source is insufficient, gas saturation reduction zone and uncharged zone are formed in sequence from the source-reservoir interface. The better the source rock conditions with more gas expulsion volume and higher overpressure, the thicker the gas saturation stabilization and reduction zones, and the higher the overall gas saturation. When the source rock conditions are limited, the better the tight reservoir conditions with higher porosity and permeability as well as larger pore throat, the thinner the gas saturation stabilization and reduction zones, but the gas saturation is high. The sweet spot of tight gas is developed in the high-quality reservoir near the source rock, which often corresponds to the gas saturation stabilization zone. The numerical simulation results by mathematical model agree well with the physical simulation results by nuclear magnetic resonance coupling displacement, and reasonably explain the gas-water distribution and production pattern of deep reservoirs in the Xujiaweizi fault depression of the Songliao Basin and tight gas reservoirs in the Linxing−Huangfu area of the Ordos Basin.

Cross-scale study of pore fractal characteristics and the pore structure of weathered granite

Weathering of granite leads to weakening of its crushing and mechanical properties, as well as changes in mineral composition. In order to investigate the correlation between the effects of weathering on granite and the characterization of the pore structure at the micro- and fine-scale, in this paper the pore structure of weathered granite is tested by the NMR technique. The pore distribution characteristics of weathered granite were explored in conjunction with T 2 spectral relaxation time and fractal theory. The microstructure of weathering-prone granite was monitored using scanning electron microscopy equipment. The results show that the pores can be classified into the three categories of small, medium and large pores based on their pore size distribution characteristics. Weathered granite has fractal features in the mesopores and macropores. Compared with unweathered granite, weathered granite has significantly more small pore throats and fewer medium and large pore throats, which expand into microfissures and micropores under conditions of weathering. The microstructure of weathered granite is mainly flaky and shell-like, with good connectivity, resulting in the poor overall structure of weathered granite.

Study of pore-throat structure characteristics and fluid mobility of Chang 7 tight sandstone reservoir in Jiyuan area, Ordos Basin

Abstract Quantitative studies of the pore-throat structure (PTS) characteristics of tight sandstone reservoirs and their effects on fluid mobility were proposed to accurately evaluate reservoir quality and predict sweet spots for tight oil exploration. This study conducted high-pressure mercury injection (HPMI) and nuclear magnetic resonance (NMR) experiments on 14 tight sandstone samples from the Chang 7 member of the Yanchang Formation in the Jiyuan area of the Ordos Basin. The HPMI was combined with the piecewise fitting method to transform the NMR movable fluid transverse relaxation time (T 2) spectrum and quantitatively characterize the PTS characteristics and the full pore-throat size distribution (PSD). Then, movable fluid effective porosity (MFEP) was proposed to quantitatively evaluate the fluid mobility of tight sandstone reservoirs and systematically elucidate its main controlling factors. The results showed that the PTS could be divided into four types (I, II, III, and IV), which showed gradual decreases in average pore-throat radius (R a), continuous increases in the total fractal dimension (D t), and successive deterioration of reservoir fluid mobility and percolation capacity. Moreover, the full PSD (0.001–10 μm) showed unimodal and multi-fractal characteristics. According to the Swanson parameter (r apex), the reservoir space types can be divided into small and large pore-throat and the corresponding fractal dimension has a relationship where D 1 < D 2. Large pore-throat had higher permeability contribution and pore-throat heterogeneity but a lower development degree and MFEP than small pore-throat, which had a relatively uniform and regular PSD and represented the primary location of movable fluids. Moreover, the development degree and heterogeneity of small pore throat controlled the flowability of reservoir fluids. MFEP can overcome the constraints of tiny throats and clay minerals on movable fluid, quantify the movable fluid content occupying the effective reservoir space, and accurately evaluate the reservoir fluid mobility. The combination and development of various pore-throat sizes and types in tight sandstone reservoirs results in different PTS characteristics, whereas differences in the mineral composition and content of reservoirs aggravate PTS heterogeneity, which is the main factor controlling the fluid mobility.

Clogging and permeability reduction dynamics in porous media: A numerical simulation study

The dynamics of fine particle entrainment, transport, and deposition within pore systems, and in particular, the capacity for mobile fines to impair permeability within porous media is critical in many industrial applications. Considerable effort has been expended over the past several decades to identify and parametrize the governing factors that control permeability reduction, with studies employing a combination of physical experimentation and numerical simulation toward this aim. The objective of this work was to numerically investigate the impact of pore space geometry and fine sizes on the clogging dynamics of porous media. The clogging dynamics were characterized by the length of clogging zone (LCZ), the critical throat size of clogging (CTZC), the clogged fraction of throats (CFT), and the permeability reduction (PR). We implemented a computational fluid dynamics-discrete element method (CFD-DEM) numerical framework with a four-way coupling scheme to obtain insights into throat clogging and permeability reduction within heterogeneous porous media utilizing four different monodisperse suspensions. Geometries of porous media were extracted from 3D images of sand packs obtained using micro-computed tomography. The geometries had porosity values ranging from 0.35 to 0.57 and initial permeabilities between 1.35 and 26.32 μm2. CFD-DEM simulations were performed on each geometry four times, varying the injected fine particle size from 5 to 15 μm diameters. Findings indicate that pore systems with tortuosity <1.28 and angles of solid grains orientation larger than 46o tend to have shorter length clogging zones and greater permeability reduction. Furthermore, although systems with porosities higher than 0.48 tend to have a relatively high clogged fraction of throats, they undergo lower permeability reduction. It was also observed that within the studied pore systems, injection of fine particles larger than 7 μm into systems with aspect ratios higher than 2.5, results in a lower fraction of clogged throats. Additionally, for the studied pore networks,< 7 μm fine particles injected into porous media with a large pore body (> 66 μm) and throat (> 22 μm) radii tended to result in larger clogging zones and a greater critical throat size of clogging.

Experimental Study of Pore-Scale Water Flooding with Phase Change Based on a Microfluidic Model in Volatile Carbonate Reservoirs

Carbonate reservoirs usually have strong heterogeneity, with complex pore structure and well-developed natural fractures. During reservoir development, when the formation pressure is lower than the bubble point pressure of crude oil, the fluid undergoes phase change and degassing. This leads to the subsequent waterflooding displacement under the oil–gas two-phase condition, also followed by a secondary phase change of oil and gas caused by the increase in formation pressure. In this paper, the glass etching model is used to carry out microfluidic experiments. The porous carbonate model and the fractured porous carbonate model are designed to simulate the process of depletion development and waterflooding development. In the process of depletion development, it can be observed that the crude oil degassing and gas phase occurrence areas of the porous model are in the order of the large pore throat area first, followed by the small pore throat area. And the crude oil degassing and gas phase occurrence order in the fractured porous model is as follows: fractures, large pore throat area and, finally, small pore throat area. In the process of converting to the waterflooding development, the early stage of the replacement reflects the obvious characteristic of “displace oil but not gas”; with the replenishment of formation energy, the gas redissolution area expands from the mainstream to other areas, and the waterflooding mobilization increases. The characteristics of oil, gas and water flow in different stages of carbonate reservoirs with different pore-fracture characteristics that are clarified, and the characteristics of fluid migration and the distribution under the condition of oil and gas coexisting and water flooding after crude oil degassing are explored, and the water displacement mechanism of volatile carbonate reservoirs with different pressure levels is revealed.

Probing the Effect of Young’s Modulus on the Reservoir Regulation Abilities of Dispersed Particle Gels

The mechanical strength of dispersed particle gels (DPGs), which can be directly characterized by Young's modulus, is an important parameter affecting reservoir regulation performance. However, the effect of reservoir conditions on the mechanical strength of DPGs, as well as the desired range of mechanical strength for optimum reservoir regulation performance, have not been systematically studied. In this paper, DPG particles with different Young's moduli were prepared and their corresponding migration performances, profile control capacities and enhanced oil recovery abilities were studied by simulated core experiments. The results showed that with increase in Young's modulus, the DPG particles exhibited improved performance in profile control as well as enhanced oil recovery. However, only the DPG particles with a modulus range of 0.19-0.762 kPa could achieve both adequate blockage in large pore throats and migration to deep reservoirs through deformation. Considering the material costs, applying DPG particles with moduli within the range of 0.19-0.297 kPa (polymer concentration: 0.25-0.4%; cross-linker concentration: 0.7-0.9%) would ensure optimum reservoir control performance. Direct evidence for the temperature and salt resistance of DPG particles was also obtained. When aged in reservoir conditions below 100 °C and at a salinity of 10 × 104 mg·L-1, the Young's modulus values of the DPG particle systems increased moderately with temperature or salinity, indicating a favorable impact of reservoir conditions on the reservoir regulation abilities of DPG particles. The studies in this paper indicated that the practical reservoir regulation performances of DPGs can be improved by adjusting the mechanical strength, providing basic theoretical guidance for the application of DPGs in efficient oilfield development.

Full Scale of Pore-Throat Size Distribution and Its Control on Petrophysical Properties of the Shanxi Formation Tight Sandstone Reservoir in the North Ordos Basin, China

Abstract Pore-throat size distribution is a key factor controlling the storage capacity and percolation potential of the tight sandstone reservoirs. However, the complexity and strong heterogeneity make it difficult to investigate the pore structure of tight sandstone reservoirs by using conventional methods. In this study, integrated methods of casting thin section, scanning electron microscopy, high-pressure mercury intrusion (HPMI), and constant-pressure mercury intrusion (CPMI) were conducted to study the pore-throat size distribution and its effect on petrophysical properties of the Shanxi Formation tight sandstones in the northern Ordos Basin (China). Results show that pore types of the Shanxi tight sandstone reservoirs include intergranular pores, dissolution pores, intercrystalline micropores, and microfracture, while the throats are dominated by sheet-like and tube-shaped throats. The HPMI-derived pore-throat size ranges from 0.006 to 10 μm, and the pore-throats with a radius larger than 10 μm were less frequent. The pore body size obtained from CPMI shows similar characteristics with radii ranging from 100 to 525 μm, while the throat size varies greatly with radii ranging from 0.5 to 11.5 µm, resulting in a wide range of pore-throat radius ratio. The full range of pore size distribution curves obtained from the combination of HPMI and CPMI displays multimodal with radii ranging from 0.006 to 525 µm. Permeability of the tight sandstone reservoirs is primarily controlled by relatively larger pore throats with small proportions, and the permeability decreases as the proportions of smaller pore-throats increase. The pervading nanopores in the tight gas sandstone reservoirs contribute little to the permeability but play an important role in the reservoir storage capacity. A new empirical equation obtained by multiple regression indicates that r15 (pore-throat size corresponding to 15% mercury saturation) is the best permeability estimator for tight gas sandstone reservoirs, which yields the highest correlation coefficient of 0.9629 with permeability and porosity.

Study on the Quantitative Characterization and Heterogeneity of Pore Structure in Deep Ultra-High Pressure Tight Glutenite Reservoirs

The precise characterization of a tight glutenite reservoir’s microscopic pore structure is essential for its efficient development. However, it is difficult to accurately evaluate using a single method, and its microscopic heterogeneity is not fully understood. In this study, a combination of X-ray diffraction, casting thin section observations, scanning electron microscopy, high-pressure mercury injection, constant-speed mercury injection, X-ray computed tomography, and the advanced mathematical algorithms in the AVIZO 8.0 visualization software was used to construct the three-dimensional digital core of a glutenite reservoir at the study site, and the parameters of the pore network model were extracted. The overall microscopic pore structure characteristics were quantitatively investigated from multiple scales. Based on this, the mineral quantitative evaluation system (QEMSCAN) examined the microscopic heterogeneity of the glutenite reservoir and its impact on seepage. The results show that the glutenite reservoir in the study block can be classified into three categories based on lithology and capillary pressure curve characteristics. The type I reservoir samples have large and wide pore throats, low threshold pressure, and high reservoir quality; type II reservoir samples are characterized by medium-sized pore throat, medium threshold pressure, and moderate reservoir quality; and the small and narrow pore throat, high threshold pressure, and poor reservoir quality are characteristics of type III reservoir samples. The various pore throat types and mineral distributions are due to the differences in dissolution, compaction, and cementation. The continuous sheet pores have good connectivity, which is related to the interconnection of primary intergranular pores and strip fractures, while the connectivity of isolated pores is significantly poor, which is related to the development of intragranular dissolved pores and intercrystalline pores. This suggests the deterioration of physical properties and pore throat connectivity, reduced average pore radius, and decreased pore sorting as decreasing permeability. The tight glutenite pores range in size from 5 nm to 80 μm and primarily feature Gaussian and bimodal distribution patterns, and submicron–micron pores contribute more to seepage. The effective pores were found to be attributed to the slowing effect of abnormally high pressure on the vertical stress, and the protective effect was positively correlated with the high-pressure strength. Notably, there is strong microscopic heterogeneity in the distribution of the reservoir matrix minerals and the pore throat size. As a result, the injected fluid easily flows along the preferential seepage channel with pore development and connectivity. This study provides new insights into the exploration and development of similar tight reservoirs.

Controlling effects of pore‐throat structure and fractal characteristics on the physical properties of ultra‐low permeability sandstone reservoirs: A case study of the sixth member of the Yanchang Formation in the Xiaojiahe area, Ordos Basin

Low and ultra‐low permeability reservoirs are widely developed in the Upper Triassic Yanchang Formation in the Ordos Basin, and its intricate pore throat structure has a significant impact on the physical properties and heterogeneity of reservoirs. This paper conducted a series of experiments to investigate the petrology, pore structure, fractal characteristics of ultra‐low permeability sandstone reservoirs, and influencing factors of the physical properties. The results show the sixth member of the Yanchang Formation (Chang 6) reservoir in the Xiaojiahe area is dominated by feldspathic sandstone. The main pores are intergranular pores, followed by dissolution pores. The Chang 6 sandstone has been categorized into four types (type I–IV) based on the traits of mercury intrusion curves. The high content of quartz and feldspar in the detrital components is conducive to improving the physical properties of the reservoir. The pore‐throat structure parameters, such as displacement pressure, median pressure, and pore throat radius can characterize the change in physical properties and reservoir quality. According to the capillary pressure fractal model of rapex (Pittman's plot apex radius), demonstrating the ultra‐low permeability, sandstone has a binary structure. The fractal dimensions D2 and Dp are more appropriate for characterizing the heterogeneity of the pore structure. The effects of different pore‐throat size scales on the physical properties of the reservoir have a discrepancy. Relatively large pore throats (r &gt; rapex), non‐nanoscale pore throats (Porr&gt;0.1), and effective movable pore throats (Porem) have significantly positive control effects on permeability and reservoir quality. In contrast, the development of nanoscale pore throats (Porr&lt;0.1) and micropore throats of failure to enter mercury (Porfem) are unfavourable to reservoir performance. In conclusion, combining detrital components, pore‐throat structure, fractal characteristics, and other factors controlled the reservoir quality of ultra‐low permeability sandstone.

Regular Pore Network Model to Study Dynamic Permeability Evolution in Hydrate-Bearing Sediments

Permeability is a key parameter to characterize fluid flow in hydrate-bearing sediments. Figuring out dynamic permeability evolution is of great importance for the effective development of hydrate-bearing deposits. In this paper, a grain-coating hydrate-bearing regular pore network model with complex pore throat cross-sections is first constructed. Afterward, the dynamic permeability evolution regularity is calculated. After the validation, the effects of initial aspect ratio, coordination number, and pore throat cross-sections on dynamic permeability evolution are investigated. The results show that hydrate narrows the effective flow space, which results in the exponential decrease of dynamic permeability with the increased hydrate saturation. The larger initial aspect ratio aggravates the heterogeneity of the pore network, resulting in a faster permeability decline rate. However, hydrate weakens the effect of initial aspect ratio on dynamic permeability evolution since the physical hydrate thickness in large pore bodies and throats is larger. The high initial coordination number reduces the dynamic permeability decline rate with the increased hydrate saturation since the higher coordination number increases the topology of the network, while hydrate compresses or blocks the effective pore throat space. Pore throat cross-sections have nothing to do with dynamic permeability evolution, but they dramatically influence the absolute permeability values. This study provides a novel insight into dynamic permeability evolution in hydrate-bearing sediments.

Effect of Authigenic Chlorite on the Pore Structure of Tight Clastic Reservoir in Songliao Basin.

Authigenic chlorite is a common clay mineral in clastic rock reservoirs, and it has an important influence on the pore structure of tight clastic rock reservoirs. In this paper, the tight clastic reservoirs in the Lower Cretaceous Yingcheng Formation in the Longfengshan subsag in the Changling fault depression in the Songliao Basin were investigated. Polarized light microscopy, scanning electron microscopy (SEM), X-ray diffraction (XRD), high-pressure mercury injection (HPMI), and low temperature nitrogen adsorption (LTNA) were used to study the influence of authigenic chlorite on the pore structure of tight clastic reservoirs. The results show that the authigenic chlorite in the study area was mainly generated in the form of pore linings. The formation of the authigenic chlorite was mainly controlled by the parent rock type and the sedimentary microfacies in the provenance area. The hydrolysis and dissolution of the iron- and magnesium-rich intermediate-mafic magmatic rocks and the high-energy, open, weakly alkaline reducing environment in the delta-front underwater distributary channel were the key factors controlling the formation of the authigenic chlorite in the study area. The pore-lining chlorite slowed down compaction and inhibited quartz overgrowth, protecting the original pores. Moreover, there are a large number of intercrystalline pores in the chlorite, which provided channels for the flow of acidic water and thus the formation of secondary pores, playing a positive role in the physical properties of the tight clastic rock reservoirs. However, the pore-filling chlorite also blocked the pore throats, playing a negative role in the physical properties of the tight clastic rock reservoirs. The tight clastic rock reservoirs with pore-lining chlorite generally had low displacement pressures and large pore throat radii. The morphology of the nano-scale pores was mainly parallel plate-shaped slit pores. There were many primary pores and a small number of secondary pores in the reservoir. Some of the pores were connected by narrow-necked or curved sheet-like throats, and the pore structure was relatively good. A higher relative content of chlorite led to a larger nano-scale pore throat radius, a smaller specific surface area, a smoother pore surface, and stronger homogeneity. Authigenic chlorite played a positive role in the formation of the tight clastic reservoirs in the study area.

The influence of CO2 huff and puff in tight oil reservoirs on pore structure characteristics and oil production from the microscopic scale

CO2 huff-n-puff can store CO2 and improve the recovery of tight oil reservoir. The asphaltene precipitation produced by the interaction of CO2 and oil causes damage to tight oil reservoirs. Based on the FE-SEM, CST, Nano-CT, HPMI and NMR, the microscopic classification standard is established. The experiments were carried out on different types of samples to quantitatively evaluate the influence of asphaltenes on pore structure and oil recovery. The results show that the asphaltene precipitation is positively correlated with huff-n-puff rounds and injection pressure. The asphaltene precipitation in type I sample is the highest. The asphaltene precipitation in type II sample is lower. The lowest asphaltene precipitation is in type III sample. In the CO2 immiscible state, asphaltenes are mainly deposited in larger pore throats. In the CO2 miscible state, the CO2 extraction effect is enhanced, the asphaltene deposits in the smaller pore throats. The overall oil recovery of the type II sample is the highest. The asphaltene precipitation, the blockage degree, the oil recovery interact and restrict each other. The oil recovery increases, the asphaltene increases, and the blockage degree of pore throats become more serious. Asphaltene precipitation causes damage to physical properties in reservoir, the porosity and permeability damage rates range from 1.35% to 3.17% and 2.17% to 8.24%, respectively. Asphaltene changes the wettability to lyophilic. The wettability reversal index ranges from 0.86% to 4.92%, which increases the seepage resistance of the oil phase. This research is novel for quantitative evaluation of reservoir microscopic pore throat characteristics and microscopic oil displacement mechanism by asphaltene precipitation formed during CO2 huff and puff in tight oil reservoirs. Also, the research results are of significance for optimizing the field development parameters.

Impacts of mineralogy and pore throat structure on the movable fluid of tight sandstone gas reservoirs in coal measure strata: A case study of the Shanxi formation along the southeastern margin of the Ordos Basin

Movable fluid content and permeability are important reference factors for reservoir quality evaluation and recovery enhancement. In this study, based on multiple experimental results, 10 typical samples from a tight sandstone gas reservoir in the coal measure strata of the Shanxi Formation along the southeastern margin of the Ordos Basin were divided into three lithofacies to discuss the factors influencing movable fluid content and permeability. The results show that the fluid has a strong seepage capacity and a high degree of mobility in relatively large pore throats. The relatively large pores in the study area are secondary dissolved pores of various origins. High quartz and feldspar contents are conducive to the formation of secondary pores, while the presence of carbonate minerals and clay minerals play an inhibitory role. The pore throat size range of 0.05–0.1 μm is the critical interval for the conversion of bound fluid to movable fluid. The movable fluid saturation and movable fluid porosity are affected by submicron- and micron-scale pore throats of >0.1 μm, while the permeability is controlled by micron-scale pore throats sizes of >1 μm. The volumetric proportion of the relatively large pore throats is influenced by the mineralogical composition of the rock, the size of the pore throats, and the degree of sorting, which further control the amount of moveable fluid and its percolation capacity. The highest movable fluid content and permeability appear in the massive gravel-bearing coarse to medium sandstone lithofacies (Lm) with a high proportion of submicron- and micron-scale pore throats, whereas the lowest occurs in parallel bedding or ripple laminations，medium to fine sandstone lithofacies (Lpr) with a high proportion of nano-scale pore throats. The lithofacies with cross bedding and medium sandstone (Lc) is also dominated by nano-scale pore throats, which shows the characteristics of low movable fluid content and medium permeability due to the retention of some micron-scale pore throats. This study describes the mobility of fluids with different pore throat sizes in detail and determines the pore throat size range corresponding to the transition from bound fluid to movable fluid, which can provide a reference for the evaluation of movable fluid seepage in other regions.