High-pressure Mercury Injection Research Articles

Experimental research on the influence of acid on the chemical and pore structure evolution characteristics of Wenjiaba tectonic coal.

The chemical and pore structures of coal play a crucial role in determining the content of free gas in coal reservoirs. This study focuses on investigating the impact of acidification transformation on the micro-physical and chemical structure characteristics of coal samples collected from Wenjiaba No. 1 Mine in Guizhou. The research involves a semi-quantitative analysis of the chemical structure parameters and crystal structure of coal samples before and after acidification using Fourier Transform infrared spectroscopy (FTIR) and X-ray diffraction (XRD) experiments. Additionally, the evolution characteristics of the pore structure are characterized through high-pressure mercury injection (HP-MIP), low-temperature nitrogen adsorption (LT-N2A), and scanning electron microscopy (SEM). The experimental findings reveal that the acid solution modifies the structural features of coal samples, weakening certain vibrational structures and altering the chemical composition. Specifically, the asymmetric vibration structure of aliphatic CH2, the asymmetric vibration of aliphatic CH3, and the symmetric vibration of CH2 are affected. This leads to a decrease in the contents of -OH and -NH functional groups while increasing aromatic structures. The crystal structure of coal samples primarily dissolves transversely after acidification, affecting intergranular spacing and average height. Acid treatment corrodes mineral particles within coal sample cracks, augmenting porosity, average pore diameter, and the ratio of macro-pores to transitional pores. Moreover, acidification increases fracture width and texture, enhancing the connectivity of the fracture structure in coal samples. These findings provide theoretical insights for optimizing coalbed methane (CBM) extraction and gas control strategies.

Gas–water percolation of tight sandstone reservoirs with different pore types in the Ordos Basin

AbstractTo investigate the percolation mechanism of tight sandstone reservoirs, qualitative and quantitative methods are applied to analyze the pore structure of the Ordos Basin through scanning electron microscopy and high-pressure mercury injection. Based on gas–water relative permeability data and the visualization of real sandstone models, a gas–water displacement experiment was carried out to simulate the percolation mechanism and fluid distribution of different pore types. The results show that: ① The percolation of different pore types varies greatly, and the irreducible water saturation decreases when the reservoir properties improve. The relative permeability of gas at an irreducible water saturation increases, the width of the two-phase percolation area increases, and the percolation ability is enhanced as the reservoir properties improve. ② The gas–water displacement mode changes from fingering to uniform displacement with the improvement of pore type, which is beneficial to the formation of effective reservoirs filled with natural gas under the same hydrocarbon generation conditions. ③ The time required for the pressure relief of samples with good reservoir properties is short, and the recovery is higher with the improvement of pore type. ④ The residual water in samples with a poor pore type increases, which decreases the relative permeability of gas and recovery. A reasonable development pattern should be carried out, and the production pressure difference should be strictly controlled to maximize productivity. This study provides theoretical guidance for the development of tight sandstone reservoirs in the Ordos Basin.

Pore heterogeneity analysis and control mechanisms in Cambrian shale of the Shuijingtuo Formation, Yichang area, China

This study focuses on understanding the fractal characteristics and controlling factors of micropore structures within organic-rich shale of the Cambrian Shuijingtuo Formation in the Yichang area of Hubei Province. Mineralogy, petrology, and organogeochemical characteristics were confirmed through comprehensive testing methods, including whole-rock X-ray diffraction and organic geochemical analyses. Additional experiments included low-temperature carbon dioxide adsorption, low-temperature nitrogen adsorption, and high-pressure mercury injection. Fractal dimensions of micropores, mesopores, and macropores were calculated using the V-S, FHH, and MENGER sponge models, respectively. Results indicate that the Cambrian Shuijingtuo Formation represents a typical deposit from an alkaline water body, resulting in high-calcareous shale. Fractal dimensions were as follows: micropores (D1) ranged from 2.1138 to 2.3475 (average 2.2342), mesopores (D2) ranged from 2.5327 to 2.7162 (average 2.6171), and macropores (D3) ranged from 2.7361 to 2.9316 (average 2.82905). Correlations were observed between total organic carbon (TOC) content and Ro with D1 and D2 (positive) and D3 (negative). Shale pore volume and specific surface area exhibited positive correlations with D1 and D2 but negative correlations with D3. High bio-deposited silica positively influenced micropore and mesopore development, while clay mineral compaction and dehydration transformations favored macropore development. Carbonate minerals primarily contributed to regular macropores, with complex correlations involving fractal dimensions D1, D2, and D3. The research results provide theoretical support for analyzing pore fractal characteristics of shallow old Marine shale reservoirs and the prediction and development plan of high-quality reservoirs of the Shuijingtuo Formation in the Yichang area.

Analyzing the Microscopic Production Characteristics of CO2 Flooding after Water Flooding in Tight Oil Sandstone Reservoirs Utilizing NMR and Microscopic Visualization Apparatus

The microscopic pore structure of tight sandstone reservoirs significantly influences the characteristics of CO2 flooding after water flooding. This research was conducted using various techniques such as casting thin sections, high-pressure mercury injection, scanning electron microscopy, nuclear magnetic resonance (NMR) testing, and a self-designed high-temperature and high-pressure microscopic visualization displacement system. Three types of cores with different pore structures were selected for the flooding experiments and the microscopic visualization displacement experiments, including CO2 immiscible flooding, near-miscible flooding, and miscible flooding after conventional water flooding. The characteristics of CO2 flooding and the residual oil distribution after water flooding were quantitatively analyzed and evaluated. The results show the following: (1) During the water flooding process, the oil produced from type I and type III samples mainly comes from large and some medium pores. Oil utilization of all pores is significant for type II samples. The physical properties and pore types have a greater impact on water flooding. Type I and II samples are more suitable for near-miscible flooding after water flooding. Type III samples are more suitable for miscible flooding after water flooding. (2) In CO2 flooding, oil recovery increases gradually with increasing pressure for all three types of samples. Type II core samples have the highest recovery. Before miscibility, the oil recovered from type I and type II samples is primarily from large pores; however, oil recovery mainly comes from medium pores when reaching miscibility. As for the type III samples, the oil produced in the immiscible state mainly comes from large and medium pores, and the enhanced oil recovery mainly comes from medium and small pores after reaching the near-miscible phase. (3) It can be seen from the microscopic residual oil distribution that oil recovery will increase as the petrophysical properties of the rock model improve. The oil recovery rate of near-miscible flooding after water flooding using the type II model is up to 68.11%. The oil recovery of miscible flooding after water flooding with the type III model is the highest at 74.57%. With increasing pressure, the proportion of flake residual oil gradually decreases, while the proportion of droplet-like and film-like residual oil gradually increases. Type II samples have a relatively large percentage of reticulated residual oil in the near-miscible stage.

Microscopic enrichment and porosity-permeability reduction mechanism of residual oil in tight sandstone reservoirs: an insight from Chang 8 Member, Yanchang Formation, Ordos Basin, China

AbstractThis study delves into the micro-occurrence states and enrichment mechanisms of residual oil, pivotal for advancing the production from tight sandstone reservoirs, particularly from the Chang 8 Member of the Upper Triassic Yanchang Formation, Ordos Basin. Through an analysis of 23 core samples, employing high-pressure mercury injection, field emission scanning electron microscopy, thin section, and X-ray diffraction techniques, distinct reservoir types were categorized. The utilization of environmental scanning electron microscope, multi-solvent continuous extraction, and an oil components separation system facilitated an intricate analysis of residual oil micro-occurrence states and their subsequent effects on porosity and permeability reduction across varying reservoir types. The findings accentuate the integral role of reservoir type in determining residual oil distribution within tight sandstone reservoirs. Favorable pore throat sorting and connectivity in specified reservoir types are identified as conducive to residual oil enrichment with a higher concentration of light components. In contrast, elevated carbonatite and clay content in other reservoir types leads to adsorption of heavy components, disrupting pore throat connectivity, and impeding crude oil filling. The varied interactions between oil and rock, oil–oil, and pore throat sealing significantly impact the distribution of oil components of residual oil, culminating in a notable reduction of porosity and permeability by 2.63% and 0.197 mD, with corresponding reduction rates of 27.19% and 46.69%, respectively. The insights derived from this study furnish a theoretical foundation for augmenting tight oil recovery and comprehending the enrichment mechanism of residual oil driven by the heterogeneity of tight sandstone reservoirs.

Characterization of reservoir quality in tight sandstones from the Benxi Formation, eastern Ordos Basin, China

The Benxi Formation in the eastern Ordos Basin harbors abundant natural gas resources and shows promising exploration and development potential. However, the reservoir characteristics are complex, and the primary controlling factors are unclear, presenting significant challenges for reservoir characterization. In response to these challenges, we conducted a systematic study on the characteristics of tight sandstone reservoirs in the Benxi Formation by integrating thin section analysis, scanning electron microscopy, high-pressure mercury injection, and conventional petrophysical analysis alongside well log data analysis. By applying empirical calculation formulas of a porosity evolution quantitative model, we elucidated the primary controlling factors of reservoir heterogeneity. Our research identified that the reservoirs in the eastern Ordos Basin, Benxi Formation, are predominantly composed of quartz sandstone and lithic quartz sandstone, with pore-filling cementation as the dominant cement type and the main storage spaces being intergranular pores and dissolved pores. The homogenization temperatures of fluid inclusions in authigenic quartz range from 92.8 to 185.7°C, indicating that the target layer is in the mesodiagenesis phase B. The main reasons for the differences in reservoir quality in the Benxi Formation are attributed to both sedimentation and diagenesis. In terms of sedimentation, two distinct sedimentary microfacies control the distribution of reservoir quality differences based on variations in quartz content and soluble components. Regarding diagenesis, the Benxi Formation underwent compaction, cementation, and dissolution, with compaction being the fundamental cause of widespread reservoir compaction.

High-pressure mercury intrusion analysis of pore structure in typical lithofacies shale

In this paper, statistical research on the characterization of pore and fracture structures is systematically conducted on shale reservoirs in different blocks and under different lithofacies conditions. The impact of lithological characteristics on shale pore fracture structures is revealed, and the coupling mechanism of "high-pressure mercury injection, pore fracture structure, and lithofacies" is clarified. Results show that: (a). When the capillary force is equal to 0.0035 MPa, the pore throat radius is equal to 209.661 μm. (b). There exist turning pressures both in injection curve and removal curve. When the capillary pressure is lower than 100 MPa, the slope of injection curve is high, while when the capillary pressure is higher than 100 MPa, the slope of injection curve becomes lower. (c). The majority of pores is distributed in the pore size interval range from 0.063 μm to 0.004 μm. (d). There are also a certain amount of regular pores in inorganic pores. Part of the pores are secondary intergranular dissolved pores formed by later dissolution.

Pore Structure Characteristics of Shale Oil Reservoirs with Different Lithofacies and Their Effects on Mobility of Movable Fluids: A Case Study of the Chang 7 Member in the Ordos Basin, China

The Chang 7 member of the Triassic Yanchang Formation in the Ordos Basin is a significant continent shale oil reservoir in China. Therefore, conducting an in-depth investigation into the pore structure and fluid mobility characteristics of the Chang 7 shale oil reservoir holds immense importance for advancing shale oil exploration. This study conducts a detailed analysis of the pore structures and their impact on fluid mobility of the Chang 7 shale oil reservoir using multiple methodologies, i.e., a cast thin section, scanning electron microscopy (SEM), X-ray diffraction (XRD), high-pressure mercury injection (HPMI), low-temperature nitrogen adsorption (LTNA), and nuclear magnetic resonance (NMR). The results show that the sandstone in the Yanwumao area of the Chang 7 shale oil reservoir consists mainly of lithic arkose and feldspathic litharenite, which can be classified into three lithofacies (massive fine-grained sandstone (Sfm), silt-fine sandstone with graded bedding (Sfgb), and silt-fine sandstone with parallel bedding (Sfp)). Moreover, three pore structures (Type I, II, and III), and four pore spaces (nanopores, micropores, mesopores, and macropores) can be characterized. Pore structure Type I, characterized by large pores, exhibits bimodal pore diameter curves, resulting in the highest levels of movable fluid saturation (MFS) and movable fluid porosity (MFP). Pore structure Type II demonstrates unimodal pore structures, indicating robust connectivity, and higher MFS and MFP. Pore structure Type III primarily consists of dissolved and intercrystalline pores with smaller pore radii, a weaker pore configuration relationship, and the least fluid mobility. Furthermore, a correlation analysis suggests that the pore structure significantly impacts the fluid flowability in the reservoir. Favorable petrophysical properties and large pores enhance fluid flowability. Micropores and mesopores with high fractal dimensions have a greater impact on reservoir fluid mobility compared to macropores and nanopores. Mesopores mainly control MFS and MFP, while micropores govern the shift from bound fluid to movable fluid states. Among the lithofacies types, the Sfm lithofacies exhibit the highest fluid mobility due to their significant proportion of macropores and mesopores, whereas the Sfgb lithofacies have lower values because they contain an abundance of micropores. The Sfp lithofacies also dominate macropores and mesopores, resulting in medium fluid mobility levels. This study combines lithofacies types, micro-reservoir pore structure characteristics, and mobile fluid occurrence characteristics to better understand the dominant reservoir distribution characteristics of the Chang 7 shale oil reservoirs in the Ordos Basin and provide theoretical information for further optimization of production strategies.

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.

Lithofacies Characteristics of Gulong Shale and Its Influence on Reservoir Physical Properties

The lithofacies characteristics of the Qingshankou Formation (K2qn) shale in the Gulong Depression are crucial for oil exploration and development. This study investigates the K2qn shale lithofacies characteristics and their impact on reservoir physical properties using scanning electron microscopy (SEM), high-pressure mercury injection (HPMI), and logging quantification. The results indicate that the main minerals in K2qn shale are quartz, plagioclase, and clay. The sedimentary structures are classified into three types: laminated, layered, and massive. The K2qn shale lithofacies can be categorized into 12 types based on a combination of lithology and sedimentary structure. The main types are laminated clayey shale, layered clayey shale, and layered felsic shale. The larger the average pore size of the K2qn lithofacies, the stronger the heterogeneity of pore size distribution in space and the better the pore-to-throat connectivity. The impact of K2qn shale lithofacies on reservoir physical properties is mainly due to differences in lithology, complemented by variations in the sedimentary structural model. Under certain diagenetic or tectonic conditions, a layered sedimentary structural model of lithofacies may not increase reservoir permeability. Generally, felsic and carbonate rocks in tidal flat environments promote the development of shale with high permeability and porosity, while lithofacies deposited in static water environments below the wave base in lake basins typically exhibit low permeability and porosity. The physical properties of a reservoir are primarily influenced by the differences in pore throat characteristics resulting from variations in lithology.

Comprehensive Study on Microscopic Pore Structure and Displacement Mechanism of Tight Sandstone Reservoirs: A Case Study of the Chang 3 Member in the Weibei Oilfield, Ordos Basin, China

With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications.

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.

A Novel Evaluation Technique for Mudcake of Drilling Fluid Based on the Nuclear Magnetic Resonance Method

Summary In drilling engineering, mudcake is formed when the drilling fluid invades the near-wellbore zone, which can reduce drilling fluid leakage and reservoir pollution and maintain wellbore stability. Exploring the method that can best represent the field working conditions to evaluate the mudcake is an urgent problem. At present, the macro-evaluation method cannot describe the characteristics of heterogeneity, particle accumulation, and porous media of mudcake. The micro-evaluation method needs local sampling, drying, curing, slicing, and other tedious disturbance treatments, which cannot reflect the overall characteristics of mudcake. To solve these problems, a novel technique for evaluating the pore structure of mudcake was established by taking nuclear magnetic resonance (NMR) T2 tests as the key mean and integrating high-pressure mercury injection tests, fluid isotope tracing, dynamic/static filtration experiment of drilling fluid, pore permeability parameter tests of core, and particle-size distribution tests of drilling fluid. The evaluation results of mudcake formed by drilling fluid static and dynamic filtration show that this technology can study the pore structure characteristics of the outer mudcake and intruded core and the distribution characteristics of the inner mudcake and filtrate in the intruded core. The novel evaluation technique has strong operability and less demand for experimental samples, which can study the micron-scale pore structure of mudcake and provide practical methods for drilling fluid system optimization and application effect evaluation, reservoir damage evaluation, and development or verification of the filtration model.

Study on the pore evolution of Xinjiang oil shale under pyrolysis based on joint characterization of LNTA and MIP

During the in-situ exploitation of oil shale, the evolution of pore structure will affect the heat transfer medium and the transport capacity of products. In this study, using the oil shale from Jimsar region of Xinjiang, in combination with the low-temperature nitrogen adsorption experiment (LNTA) and high-pressure mercury injection experiment (MIP), the effect of temperature on evolution law of its pores during pyrolysis were analyzed according to the LNTA and MIP joint characterization results. The results show as follows: the change curve of oil shale porosity with pyrolysis final temperature in Xinjiang shows an “S” shape. The pore volume increases slightly before 300 °C, and it shows an increasing trend in the subsequent temperature range, with the mesopore volume change being the most noticeable. However, the increase slows down after 600 °C. The evolution of full-scale pores in the pyrolysis process of oil shale is reflected by the joint characterization of LNTA and MIP, which indicates that the temperature has a controlling effect on the evolution of pore, and provides basic theoretical support for how to improve the oil recovery rate of exploitation of oil shale.

Experimental and digital investigations of heterogeneity in lower cretaceous carbonate reservoir using fractal and multifractal concepts

Characterization and prediction of reservoir heterogeneity are crucial for hydrocarbon production. This study applies the multifractal theory using both numerical and experimental data to characterize quantitatively the heterogeneity of pore structures in Lower Cretaceous limestone reservoir from the United Arab Emirates. Fractal dimensions calculated from three dimensional digital images showed good correlation (R2 =  + 0.69) with experimental high-pressure mercury injection (HPMI) measurements. Moreover, both experimental and numerical fractal dimensions correlate well with experimental HPMI porosity measurements. Multifractal parameters such as the non-uniformity degree of the pore structures Δα, the asymmetry degree in the vertical axis Δf(α), the concentration of pore size distribution α0 and the asymmetry degree in the horizontal axis Rd estimated from digital and experimental data correlated well and revealed ability to quantitatively describe samples heterogeneity. The ranges of digital and experimental multifractal parameters provided the means to differentiate between homogeneous and heterogeneous samples.

Contribution of lamellation fractures to porosity and permeability of shales: A case study of the Jiaoshiba area in the Sichuan Basin, China

Lamellation fractures are an important type of natural fracture in marine shales. These fractures affect the hydraulic connectivity of shale reservoir, however, their contribution to porosity and permeability is poorly understood. In this paper, we investigate the contribution of lamellation fractures to porosity and permeability of shale reservoirs in the Wufeng-Longmaxi Formation in Sichuan Basin. To do so, several analytical methods including scanning electron microscopy (SEM), CO2 and N2 adsorption experiments, high-pressure mercury injection (MICP), and permeability measurements under different confining pressures were combined. Results showed that the contribution of micro-pores, meso-pores, macro-pores, and fractures to pore volume is 29.1%, 35.7%, 12.6%, and 22.6%, respectively lamellation fractures can increase porosity 6%–10%. Besides, filling materials of the lamellation fractures, anhydrite, pyrite, and organic matter (OM), can improve shale petrophysical properties. Furthermore, it was found that lithofacies would cause different pressure sensitivities in permeability with clay rich shale being the highest and silty shale the lowest. In addition, samples with lamellation fractures exhibited higher pressure sensitivity while permeability steadily decreases with confining pressure, with its decreasing rate gradually slowing down in separate phases. Ultimately, lamellation fractures can increase horizontal permeability three at 5 MPa and two at 50 MPa of confining pressure. When compared to the actual formation pressure at 30 MPa, the permeability of shale samples with lamellation fractures is much higher than that without lamellation fractures. This study provides direct evidence that subsurface lamellation fractures can improve the storage space and permeability of shale reservoirs.

Heterogeneity of Pore and Fracture Structure in Coal Reservoirs by Using High-Pressure Mercury Intrusion and Removal Curve

The pore structure determines the desorption, diffusion and migration of coalbed methane, and the heterogeneity of the pore structure seriously restricts the diffusion and seepage process and productivity of coalbed methane. Therefore, this paper takes eight coal samples in the Linxing area as the research target and uses the high-pressure mercury injection test to describe the pore structure distribution. On this basis, three kinds of single and multifractal models are used to calculate the progressive mercury removal curve, and the correlation analysis is carried out to determine the physical significance of the mercury removal fractal dimension. Finally, the relationship between the fractal dimension of the mercury curve and the pore structure parameters is defined, and the applicability of fractal models in characterizing pore structure heterogeneity is discussed. The conclusions of this paper are as follows. (1) Samples can be divided into two categories according to porosity and mercury removal efficiency. Among them, the mercury removal efficiency of sample 1–3 is higher than 35%, and porosity is less than 9.5%, while those of sample 4–8 are the opposite. The seepage pore volume percentage of sample 1–3 is 35–60%, which is higher than that in sample 4–8. (2) The difference of the samples’ fractal dimension calculated with the Menger and Sierpinski models is small, indicating that the pore structure distribution heterogeneity of the two types is similar. The multifractal model shows that the adsorption pore and macro-pore heterogeneity of sample 4–8 are stronger than those of sample 1–3, and the pore distribution heterogeneity is controlled by the low value of pore volume. (3) The results of the two single fractal calculations show that the pore structure distribution heterogeneity of sample 4–8 is stronger than that of sample 1–3. The multifractal model calculation shows that the adsorption pore distribution heterogeneity of sample 4–8 is stronger, and the low value of pore volume controls the pore distribution heterogeneity. (4) The mercury fractals based on the Menger model can reflect the adsorption pore distribution and macro-pore distribution heterogeneity, while the Sierpinski model can only reflect the adsorption pore distribution heterogeneity at the mercury inlet stage.

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.

Reservoir characteristics and controlling factor of tight sandstone in Shuixigou Group in Taibei depression, Turpan-Hami basin

The positive structure belts surrounding the Taibei Sag, Turpan-Hami Basin, have been the main targets for oil and gas exploration for years and are now left with remaining resources scattering in reservoirs adjacent to source rocks in the sag, where the Shuixigou Group with substantial oil and gas potential constitutes the primary focus for near-source exploration. Consequently, characterization of development and key controlling factors of reservoir space becomes a must for future exploration in the area. This study investigates the development traits, genesis, and controlling factors of the Xishanyao and Sangonghe formations in the Shengbei and Qiudong Sub-sags of the Taibei Sag with techniques such as cast thin-section observation, porosity and permeability tests, high-pressure mercury injection, and saturation fluid NMR analysis of reservoir rocks. The findings reveal that the Shuixigou Group in the Taibei Sag consists of lithic sandstone. Reservoirs in the group are mostly poor in terms of physical properties, with undeveloped primary pores dominated by intergranular dissolved pores as a result of a strong compaction. Comparative analysis of key controlling factors of the Sangonghe Formation reveals significant distinctions in sandstone particle size, sand body thickness, genesis and distribution, provenance location, and source rock type between the Qiudong area and Shengbei area. Vertically, the coal seams of the Xishanyao Formation exhibit heightened development with shallower burial depth and lower maturity compared to those of the Sangonghe Formation. Consequently, this environment fosters the formation of organic acids, which have a stronger dissolution effect on minerals to develop secondary dissolution pores, and ultimately resulting in better reservoir physical properties. Overall, the reservoirs within the Qiudong area of the Taibei Sag demonstrate superior characteristics compared to those in the Shengbei area. Furthermore, the reservoir physical properties of the Xishanyao Formation are better than those of the Sangonghe Formation. The research findings will provide valuable guidance for the exploration and development of lithological oil and gas reservoirs within the Taibei Sag.

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.