Tight Sandstone Pore Research Articles

Pore Structure Characteristics and Reservoir Classification of Tight Sandstones within the Upper Permian Longtan Formation in the Laoshan Uplift, South Yellow Sea Basin: Implications for Hydrocarbon Exploration

The Upper Permian Longtan Formation in the Laoshan Uplift of the South Yellow Sea Basin hosts thick and distinctive tight sandstones. However, a comprehensive understanding of its pore structure and reservoir classification remains lacking. This study investigates the fully cored well, CSDP-2, utilizing thin section analysis, scanning electron microscopy, energy spectrum analysis, X-ray diffraction, high-pressure mercury intrusion, and nuclear magnetic resonance to characterize its petrophysical properties, pore space, and movable fluid characteristics. Additionally, fractal principles are further employed to examine reservoir heterogeneity and conduct a quantitative assessment, considering the complexity of tight sandstone pore structures. The findings reveal that the sandstones predominantly comprise feldspathic litharenites, with an average porosity of 1.567% and permeability of 0.099 mD, primarily containing intragranular pores. Two distinct sets of pores with significantly different sizes (r < 2 μm; r > 6 μm) were identified, displaying relatively high fractal dimensions and discrete distribution. Movable fluids primarily occupy pores with radii > 0.019 μm, reflecting pronounced overall heterogeneity. The reservoir was classified into three categories utilizing permeability, median radius, and movable fluid saturation as key evaluation parameters, with Class I representing a relatively high-quality reservoir. These findings advance our understanding of the pore development mechanism of tight sandstone reservoirs and provide geological evidence for further hydrocarbon exploration in this study area.

Influence of coupled dissolution-precipitation processes on the pore structure, characteristics, and evolution of tight sandstone: A case study in the upper Paleozoic reservoir of Bohai Bay Basin, eastern China

Due to the limitations of pore throat characterization techniques, in-depth studies on the evolution and influencing variables of tight sandstone reservoirs remain lacking, despite the importance of pore structure in evaluating their storage and seepage capacities. In this study, the effect of coupled dissolution–precipitation on the heterogeneity of the pore structure of tight sandstone was investigated using advanced techniques in conjunction with traditional geochemical analyses. The primary reasons for the variability in tight sandstone pore structure were different diagenetic processes and tectonic evolution. In tight sandstones, numerous burial phases led to a significant loss of porosity. However, tight sandstones that have been successively leached by meteoric water and deep burial organic acid have improved secondary pore space due to Yanshan tectonic uplift and Himalayan tectonic burial. The redistribution or blockage of pore space can occur as a result of dissolved material migrating and re-precipitating in tight sandstones that have been deeply buried and altered by organic acidic fluids. Furthermore, nuclear magnetic resonance cryoporometry and nuclear magnetic resonance experiments were used to provide precise and accurate quantitative analysis for discussing the evolution of pore structure by complex dissolution–precipitation process within the pore scale. The formation of good pore structure was mainly dependent on the increase in pore volume generated by dissolution in the submicron and micron range (less than 10 μm). Due to interfacial energy effects, authigenic minerals precipitated preferentially in macropores, resulting in a preponderance of microporosity and small changes in porosity but at least an order of magnitude reduction in permeability. This study provides a reliable reference for genesis analysis and evaluation of tight sandstones as well as a new perspective for understanding the formation and evolution of complex pore structures.

Study of Fractal and Multifractal Features of Pore Structure in Tight Sandstone Reservoirs of the Permian Lucaogou Formation, Jimsar Sag, Junggar Basin, Northwest China.

The primary factor impacting the tight sandstone reservoirs and fluid flow capacity represents the pore-throat structure. On the basis of petrophysical characteristics test, scanning electron microscopy (SEM), and casting thin-section examination of tight sandstone reservoir specimens from the Permian Lucaogou Formation in Jimsar Sag, Junggar Basin., the full-size pore-throat parameters and distribution characteristics were determined by constant-rate mercury injection (CRMI) analysis. Using fractal theory and multifractal theory, the pore architectures of sandstone pores are analyzed. Mercury intrusion capillary pressure (MICP) is used to compute the dimensions of fractals using various fractal models and multifractal characteristics. Analysis is done on the relationships between tight sandstone pore architectures and fractal and multifractal characteristics. According to the research, a network of tightly packed sandstone pores may be assessed using the dimensions of fractals computed from a 3D capillary model. When displacement pressure is increased, the dimensions of fractals rise; when permeability, pore-throat diameter, and variable coefficient are increased, it falls. Tight sandstone pores exhibit multifractal features, according to the multifractal analysis, and multifractal parameters may depict the size, concentration, and asymmetry of the pore size distribution (PSD). Sandstone’s PSD is comparable when its multifractal parameters (Δα, Δf, α0, α1, α2) are identical. Pore diameters of tight sandstone are positively connected with information dimensions D1 and correlation dimensions D2, and information dimensions D1 have a greater impact on PSD than correlation dimensions D2. Additionally, the 3D capillary model’s dimensions of fractals and D1 exhibit a substantial negative association. These findings play a significant guiding role in the quantitative characterization of unconventional reservoir pore structures. The multifractal technique is effective to define the heterogeneity of the sandstone pore system and to differentiate between distinct PSD in heterogeneity.

Effect of authigenic clay minerals and carbonate cements on quality of tight sandstone reservoirs: Insight from Triassic tight sandstones in the Huaqing area, Ordos Basin, Northern China

• Pore and throat structure can be characterized separately by XCT scanning. • Chlorite and illite produced most of the intercrystalline pores in tight sandstone . • Chlorite coatings are effective in preserving the large primary pore-throat. • The densification was completed by cementation instead of compaction. • Tight sandstone with high chlorite is the best quality reservoir in the Ordos Basin. As an important part of tight sandstone, authigenic clay minerals and carbonate cements have a strong influence on the densify of tight sandstone, but the details of these effects on pores and throats need be further clarified. The Ordos Basin is the second-largest sedimentary basin in China with the highest annual oil output and is characterized by tight sandstone. In this paper, the thin section, HPMI, XCT scanning and fluid inclusion homogenization temperature were combined to study the densification process of the tight sandstone in the Ordos Basin. The results show that early chlorite coating can effectively reduce further damage to the pore-throat space. But the pore-lining chlorite and illite led to reduce of the radius of intercrystalline micropores to <1 μm. After mechanical compaction, authigenic illite and the late ferrocalcite and ferrodolomite cements continued to grow and eventually complete the densification. Authigenic clay minerals and carbonate cements played contrasting role on evolving of pores and throats: tight sandstone with high chlorite showed obvious “right peak” PSD and TSD in XCT scanning with the largest number of throats, formed the best-quality reservoir; tight sandstone with high carbonate cement suggesting flat “right peak” TSD and increased the average length of throats; tight sandstone with high illite showed flat and “left shift” PSD and obvious “bimodal” TSD with the fewest number of throats, and formed the worst-quality reservoir.

Effects of Water Immersion and Acidification on Nano-Pores in Tight Sandstones-A Case Study of the Gaotaizi Reservoir, Songliao Basin.

Hydraulic fracturing and acidification are among the most commonly used methods for stimulating the tight oil reservoirs and improving oil recovery. Therefore, examining the effects of water immersion and acidification on tight oil reservoirs is important for oilfield development plans. Core flooding testing, which analyzes the influence of core permeability variations before and after acid injection on the reservoir quality, is the conventional research method; however, it is difficult to observe the changes in minerals and pores caused by acidulation and water immersion in situ. In this study, we conduct field-emission scanning electron microscopy (FE-SEM), MAPS, the quantitative evaluation of minerals through scanning electronic microscopy (QEM-SCAN), and describe the types of pores in tight sandstone. Further, the effects of water immersion and acidification on pores in tight sandstone were studied. The results indicate that: (1) intergranular pores, intragranular dissolution pores, clay mineral intercrystalline pores, and micro-cracks were developed in the Gaotaizi tight sandstone in Songliao Basin, with the intergranular pores observed to be dominant; (2) the hydration of clay minerals induced by water injection caused plugging of pores at the nanometer- micrometer scale, and plane porosity is slightly reduced (˜0.86%); (3) acidification resulted in the dissolution of carbonate minerals, increasing the porosity of the reservoir, therefore, the increase in porosity is influenced by the carbonate mineral content. We recommend that future studies should investigate the content, type, and distribution of carbonate minerals in the operation area. During the process of reservoir stimulation, such as acidification and CO₂ injection- and-production, the influence of carbonate minerals dissolution on oil production should be considered.

Characterization and genetic significance of mold pores in tight sandstone: A case from the lower part of the Yanchang Formation in the Wuqi–Ansai area

The lower part of the Yanchang Formation in the Wuqi–Ansai area consists of three layers which are generally characterized by low (5–10%) to extra-low (<5%) porosity and extra-low (10–100 md) to ultra-low (<10md) permeability. Based on microscopic observation of casting thin sections, mercury injection tests, micro-CT scanning, inclusion temperature measurement, and fluorescence tests, it was determined that the pore types of the reservoirs mainly included secondary pores between pores, intraparticle pores in feldspar, intercrystallite pores in clay, mold pores, and laumonite dissolution pores. With decreasing porosity and permeability of the reservoirs, the proportions of intraparticle pores in feldspar and mold pores increased; however, the proportion of interparticle pores decreased. The pores of the reservoirs, which were dominated by mold pores, mostly showed coarse skewness and good sorting with few pore throats and low coordination numbers. These pores were spatially isolated and rarely connected by throats. Quartz microcrystals were observed to be closely attached to the pore walls and growing along them. Diagenetic analysis indicated that the mold pores formed after the sandstones were intensely compacted and before the reservoirs were densified. As the hydrocarbon source rock matured and discharged acidic fluids, the grains and matrix in the sandstone reservoirs gradually dissolved to form pores, and some of the feldspar particles were even completely eroded into mold pores. In the following densification process of cements filling pores, the mold pores located on hydrocarbon migration pathways were filled by small amounts of oil and gas; thus, they could be retained after densification. Pores of this type were morphologically isolated because of the cementation of most throats. After the intense and selective corrosion of the reservoirs, some macropores were filled by small amounts of oil and gas during the later densification of reservoirs. This led to the survival of mold pores and has made the mold pores a symbol of the process in which the reservoirs were densified after hydrocarbon accumulation.

Frost Damage in Tight Sandstone: Experimental Evaluation and Interpretation of Damage Mechanisms.

Low-porosity tight rocks are widely used as building and engineering materials. The freeze–thaw cycle is a common weathering effect that damages building materials in cold climates. Tight rocks are generally supposed to be highly frost-resistant; thus, studies on frost damage in tight sandstone are rare. In this study, we investigated the deterioration in mechanical properties and changes in P-wave velocity with freeze–thaw cycles in a tight sandstone. We also studied changes to its pore structure using nuclear magnetic resonance (NMR) technology. The results demonstrate that, with increasing freeze–thaw cycles, (1) the mechanical strength (uniaxial compressive, tensile, shear strengths) exhibits a similar decreasing trend, while (2) the P-wave velocity and total pore volume do not obviously increase or decrease. (3) Nanopores account for >70% of the pores in tight sandstone but do not change greatly with freeze–thaw cycles; however, the micropore volume has a continuously increasing trend that corresponds to the decay in mechanical properties. We calculated the pressure-dependent freezing points in pores of different diameters, finding that water in nanopores (diameter <5.9 nm) remains unfrozen at –20 °C, and micropores >5.9 nm control the evolution of frost damage in tight sandstone. We suggest that pore ice grows from larger pores into smaller ones, generating excess pressure that causes frost damage in micropores and then nanopores, which is manifested in the decrease in mechanical properties.

Analysis of pore throat characteristics of tight sandstone reservoirs

Abstract The characterization of pore throat structure in tight reservoirs is the basis for the effective development of tight oil. In order to effectively characterize the pore -throat structure of tight sandstone in E Basin, China, this study used high-pressure mercury intrusion (HPMI) testing technology and thin section (TS) technology to jointly explore the characteristics of tight oil pore throat structure. The results of the TS test show that there are many types of pores in the tight sandstone, mainly the primary intergranular pores, dissolved pores, and microfractures. Based on the pore throat parameters obtained by HPMI experiments, the pore throat radius of tight sandstone is between 0.0035 and 2.6158 µm. There are two peaks in the pore throat distribution curve, indicating that the tight sandstone contains at least two types of pores. This is consistent with the results of the TS experiments. In addition, based on the fractal theory and obtained capillary pressure curve by HPMI experiments, the fractal characteristics of tight sandstone pore throat are quantitatively characterized. The results show that the tight sandstones in E Basin have piecewise fractal (multifractal) features. The segmentation fractal feature occurs at a pore throat radius of approximately 0.06 µm. Therefore, according to the fractal characteristics, the tight sandstone pore throat of the study block is divided into macropores (pore throat radius &gt; 0.06 µm) and micropores (pore throat radius &lt; 0.06 µm). The fractal dimension D L of the macropores is larger than the fractal dimension D S of the micropores, indicating that the surface of the macropores is rough and the pores are irregular. This study cannot only provide certain support for characterizing the size of tight oil pore throat, but also plays an inspiring role in understanding the tight pore structure of tight sandstone.

Predicting the Permeability of Tight Sandstone Utilizing Experimental and Mathematical Modeling Approaches

Abstract In this research, experimental and mathematical modeling were carried out to estimate the permeability of tight sandstones. The pore structure parameters such as the number of pores, pore cross-sectional area, and pore radius were obtained by microcomputed tomography (micro-CT) scanning and image processing. A mathematical model was developed to predict the permeability of tight sandstones using the pore structure parameters. In the model, hydraulic radius was used to estimate the pore hydraulic conductance, where the pore diameter variation in a sinusoidal manner was observed. The stereological correction factor was used to characterize the arbitrary angle between the pore axis and the cross-sectional area. The tortuosity model was applied to characterize the behavior of non-Darcy flow inside the tight formations. Finally, the permeability prediction model was developed based on the effective medium theory. The proposed model was validated by 21 tight sandstone samples, with the relative errors within ±20%. In addition, due to the presence of small pores in tight sandstone with little contribution to overall permeability, the permeability shows inversely proportional behavior against the number of small pores.

Multifractal characteristics of shale and tight sandstone pore structures with nitrogen adsorption and nuclear magnetic resonance

Based on the experiments of nitrogen gas adsorption (N2GA) and nuclear magnetic resonance (NMR), the multifractal characteristics of pore structures in shale and tight sandstone from the Chang 7 member of Triassic Yanchang Formation in Ordos Basin, NW China, are investigated. The multifractal spectra obtained from N2GA and NMR are analyzed with pore throat structure parameters. The results show that the pore size distributions obtained from N2GA and NMR are different, and the obtained multifractal characteristics vary from each other. The specific surface and total pore volume obtained by N2GA experiment have correlations with multifractal characteristics. For the core samples with the similar specific surface, the value of the deviation of multifractal spectra Rd increases with the increase in the proportion of large pores. When the proportion of macropores is small, the Rd value will increase with the increase in specific surface. The multifractal characteristics of pore structures are influenced by specific surface area, average pore size and adsorption volume measured from N2GA experiment. The multifractal characteristic parameters of tight sandstone measured from NMR spectra are larger than those of shale, which may be caused by the differences in pore size distribution and porosity of shale and tight sandstone.

Wettability alteration and mitigating aqueous phase trapping damage in tight gas sandstone reservoirs using mixed cationic surfactant/nonionic fluoro-surfactant solution

During drilling, completion and fracturing operations, aqueous phase from working fluids can invade into rock formations and engender phase trapping damage in the near well region. This formation damage can diminish the gas relative permeability and hinder the gas well productivity in tight gas sandstone reservoirs. In this study, we investigated the mixed surfactants system of cationic surfactant (SDCSA-1) and nonionic fluorinated surfactant (FC-0) at varied mixing mole ratios and concentrations to reduce the formation damage. Results showed that the minimum surface tension of mixed surfactants solution was relatively low with around 20 mN/m. In addition, surfactant mixtures altered the wettability of sandstone rock from water wetting to intermediate wetting condition. An optimal mixed system was obtained when the concentration is 10-4 mol/L and mole ratio of individual surfactants is 1:1. The mechanism of wettability alteration of surfactants to liquid/rock interface was further determined by adsorption experiments, atomic force microscopy(AFM) tests, and energy dispersive spectrum(EDS) tests. Two sets of spontaneous imbibition experiments were conducted including parallel imbibition tests and sequential imbibition tests. We observed that mixed surfactants solution can prominently prevent liquid invasion into sandstone rocks. We further calculated the capillary pressure to quantitatively examine the capillary effects of different imbibed fluids. When sandstone sample was treated by mixed surfactants, the capillary pressure decreased from 7.81 MPa to 0.97 MPa. Core displacement tests revealed that the liquid saturation of core sample filled with surfactants mixture decreased from 100% to 35.48% and the its gas permeability recovered to 72.86% of the core without liquid after gas flooding. NMR tests also confirmed that surfactant mixtures can be more easily drained than brine from pores in tight sandstone. Consequently, we proposed an improved method to mitigate water blocking damage based on wettability alteration by mixed cationic surfactant and nonionic fluoro-surfactant system.

Resolution effect on image-based conventional and tight sandstone pore space reconstructions: Origins and strategies

A suitable choice of spatial resolution is essential to the three-dimensional (3D) image-based reconstruction of rock pore space: a too low spatial resolution may result in the omission of sub-resolution porosity while too high spatial resolution may lead to a field of view smaller than the representative volume. In this work, the 3D pore spaces of conventional and tight sandstone specimens are reconstructed by X-ray computed tomography with spatial resolutions of 2 μm, 5 μm, 10 μm, and 20 μm and equal image voxel quantities (600 × 600 × 600) to study the influence of spatial resolution on the reconstruction quality. Petrophysical properties such as porosities, permeabilities and pore-throat structure parameters are calculated from the 3D images and measured by helium porosity, Klinkenberg-corrected permeability and mercury intrusion capillary pressure porosimetry for comparison. High-resolution images are sampled from different positions in the specimens to evaluate the core-scale heterogeneities. Rock textures and pore-throat structures of the specimens are analyzed through casting thin sections and MICP to find out the origin of the resolution effect. The results show that 3D images with any single spatial resolution have limited detectivities to recover the full pore and throat distribution of sandstone specimens, which is the root cause of the resolution effect. The contributions of different pore genetic types with various pore sizes to petrophysical properties vary with simulation targets and methods. For conventional sandstone specimens with only one dominate pore genetic type, the appropriate spatial resolution can be chosen by calibrating the simulated petrophysical properties to actual measurements. For tight sandstone specimens with several pore genetic types, the contents and contributions to the petrophysical properties should be investigated before pore space reconstructions.

A method to evaluate pore structures of fractured tight sandstone reservoirs using borehole electrical image logging

Fractures are important in improving tight sandstone pore connectivity and fluid flow capacity. However, the contribution of fractures to pore connectivity and fluid flow capability cannot be quantified using current methods. The objective of this study was to develop a method to quantitatively characterize reservoir improvement as a result of fractures. This method was proposed based on the experimental results of 37 core samples recovered from the Upper Triassic Chang 8 tight sandstone in the Jiyuan area of the Ordos Basin, China. The morphological features of the porosity spectra, the mercury injection capillary pressure curves, and the pore-throat radius distributions were analyzed. Accordingly, a method was proposed to construct pseudocapillary pressure (Pc) curves from the porosity spectra to characterize the pore structure of fractured reservoirs and to establish corresponding models based on the classified power function method. In addition, a model was developed to predict fracture formation permeability based on the Swanson parameter. The proposed method and models were applied in field applications, and the estimated results agreed well with the core and drill-stem testing data. Fractured formations contained good pore structure, high permeability, and oil production rata. The relative errors between the model-predicted pore structure evaluation parameters, permeability from Pc curves, and core-derived results are all within ±30.0%. With the integrated study of reservoir pore structure with permeability, the effective Upper Triassic Chang 8 fractured tight sandstone reservoirs with development potential were successfully identified.

An Experimental Study on Stress Sensitivity of Tight Sandstones with Different Microfractures

Aiming at the stress sensitivity problem of tight reservoirs with different microfractures, the cores of H oilfield and J oilfield with different microfractures were obtained through the fractures experiment, so as to study the change of gas permeability in tight sandstone core plug during the change of confining pressure. Besides, we use the nuclear magnetic resonance (NMR) spectra of the core before and after saturation to verify whether the core has been successfully fractured. Based on Terzaghi’s effective stress principle, the permeability damage rate (D) and the stress sensitivity coefficient (Ss) are used to evaluate the stress sensitivity of the core, which show consistency in evaluating the stress sensitivity. At the same time, we have studied the petrological characteristics of tight sandstone in detail using thin section (TS) and scanning electron microscope (SEM). The results show that the existence of microfractures is the main factor for the high stress sensitivity of tight sandstone. In addition, because of the small throat of the tight reservoir core, the throat closes when the overlying stress increases. As a result, the tight sandstone pore size is greatly reduced and the permeability is gradually reduced. Therefore, in the development of tight reservoirs, we should not only consider the complex fracture network produced by fracturing, but also pay attention to the permanent damage of reservoirs caused by stress sensitivity.

Pore Structure Characteristics Analysis of Tight Reservoir1

In the development of oil and gas reservoir, tight oil and gas reservoir refers to the oil and gas reservoir with liquid measured permeability of 0.1 milli- Darcy, and the pore structure characteristics of tight oil reservoir is an important factor affecting its development effect. In this paper, constant-rate mercury penetration, nuclear magnetic resonance and scanning electron microscopy are used to detect the rock samples of a tight oil reservoir in Daqing, and analyse the distribution of pores and throats in the reservoir. And it turns out: Tight sandstone pore throats in this block are distributed at 0.01μm1μm. The average pore throat radius was 0.43μm. The pore radius ranged from 80μm to 180μm, with an average radius of 122.7μm and the average pore radius was 124μm. The analysis of experimental data shows that the permeability of tight sandstone is mainly determined by throat radius and has nothing to do with pore size. The results of the three test methods are basically consistent and can be verified with each other.

Diagenesis and diagenetic facies distribution prediction of Chang 8 tight oil reservoir in Maling area, Ordos Basin, NW China

In this study, characteristics of Chang 8 tight sandstone pore structure and diagenesis are analyzed. A classification standard for sandstone diagenetic facies is established. Combined with the probabilistic neural network method, logging curves are used to predict the distribution of diagenetic facies. The following results are found: the Chang 8 reservoir has low porosity-low permeability characteristics, and the pore-throat structures have strong microscopic heterogeneity; both compaction and siliceous and carbonate cementation promote reservoir densification; chlorite cement lining, hydrocarbon emplacement, and the dissolution of feldspar and rock fragments have constructive effects on reservoir development; and two favorable diagenetic facies, a weakly compacted and chlorite-authigenic quartz cementation facies and an intensely compacted-dissolution facies, are developed in the middle of the thick sandstone and are a good match in their horizontal distribution with distributary channel sands. The Chang 81 member has a much larger area that is more favorable for the development of reservoir diagenetic facies than the Chang 82

Analysis of pore size distribution and fractal dimension in tight sandstone with mercury intrusion porosimetry

The pore size distribution (PSD) and fractal dimension of tight sandstone are studied with mercury intrusion porosimetry (MIP). Four different fractal models are used to calculate fractal dimensions from mercury intrusion capillary pressure (MICP) and mercury extrusion capillary pressure (MECP) respectively, and the physical meanings of the fractal dimensions calculated from different fractal models are discussed. The fractal characteristics of tight sandstone pore spaces with unimodal and bimodal PSD are compared. The correlations between fractal dimensions and tight sandstone petrophysical properties are researched, and the optimal fractal model for formation evaluation is recommended. Finally, the key parameters influencing tight sandstone permeability are investigated.

Quantitative Analysis of Micron-Scale and Nano-Scale Pore Throat Characteristics of Tight Sandstone Using Matlab

Based on micro-scale casting thin sections, nano-scale SEM images, and the pore distribution map identified through a binary image in Matlab, the pore size distribution and pore throat coordination number of the strata of Upper Paleozoic He8 section tight sandstone in the southeastern Ordos Basin were quantitatively analyzed with the above experimental data. In combination with a high-pressure mercury injection experiment, the pore throat distribution, the pore throat ratio, and the relationships between the characteristics, parameters, and pore permeability were investigated clearly. The results show that the tight sandstone pore space in the study area is dominated by micron-sized intergranular pores, dissolved pores, and intragranular pores. The nano-scale pore throat consisted of clay minerals, intercrystalline pores, and the flake intergranular pores of overgrowth quartz grains. Kaolinite and illite intercrystalline pores occupy the pore space below 600 nm, while the ones above 800 nm are mainly dominated by the intergranular pores of overgrowth quartz grains, and the 600–800 nm ones are transitional zones. The permeability of tight sandstone increases with the average pore throat radius, sorting coefficient, median pore throat radius, and average pore throat number. The porosity is positively correlated with the average pore radius and the average pore throat coordination number, and negatively correlated with the median pore throat radius.

Determining the segmentation point for calculating the fractal dimension from mercury injection capillary pressure curves in tight sandstone

Tight sandstone reservoirs usually exhibit complex pore structure and a high degree of microscopic pore structure heterogeneity. The fractal dimension of pores in tight sandstone calculated by a mercury injection capillary pressure (MICP) curve can be used for the quantitative analysis of pore structure characteristics. The MICP curve of tight sandstone in log–log coordinates can be divided into two straight lines using a segmentation point and the fractal dimension of the pores is calculated in each part. However, the selection of the segmentation point is currently one of the challenges in the studies on the pore fractal characteristics of rocks. The fractal dimensions are calculated based on the non-wetting phase saturation and the wetting phase saturation using the Swanson point, Capillary-Parachor point, and the point at r30 as the segmentation point respectively. The results indicate that the fractal dimension of small pores calculated based on non-wetting phase saturation using the Capillary-Parachor point as the segmentation point best describes the fractal characteristic of pores in tight sandstones. The relationship between the nuclear magnetic resonance transverse relaxation time geometric mean (T2LM) and the fractal dimension of pores verified the efficacy of this fractal dimension calculation method.

A tight sandstone trapezoidal pore oil saturation model

Abstract “Non-Archie” phenomena are common in tight sandstone reservoirs with complicated pore structure, bringing challenges to the logging evaluation of tight sandstone. Based on the characteristics of tight sandstone pore structure, a new trapezoidal pore saturation model considering the effect of pore structure on rock conductivity is presented, in which the pore in tight sand is divided into straight pore with constant cross-sectional area and trapezoidal pore with variable cross-sectional area, and the total rock resistance is taken as the parallel resistance of these two parts to compressively consider the influence of pore structure and conductive volume on rock conductivity. The model parameters are studied by reconstructing the trapezoidal pore structure. Based on the trapezoidal pore reconstruction, characterization methods of model parameters were studied under the constraint of rock electrical properties test, and the variation was revealed of tortuosity, straight pore proportion and trapezoidal factors. The model was used in logging evaluation of tight sandstone of several wells, the results show the oil saturation obtained from the new model considering the effect of pore structure on electrical properties from the aspects of pore length and pore cross-section is in good accordance with the real regularity and petrophysical characteristics of the reservoir, and much closer to the formation oil-bearing conditions than that from the Archie model.