Search

As a typical tight reservoir and an important site for unconventional hydrocarbon accumulation, the Chang 6 member of the Yanchang Formation is characterized by complex pore structures and strong heterogeneity. Analysing and characterizing the pore-throat structure is highly important for optimizing oil recovery processes. To clarify the nonhomogeneity and structural characteristics of the pore throats in the southeastern Ordos Basin, tight sandstone from the Chang 6 member was selected for analysis. Casting thin section (CTS), scanning electron microscopy (SEM), cathodoluminescence (CL), X-ray diffraction (XRD), and mercury intrusion capillary pressure (MICP) analyses were conducted. The results, revealed that intergranular pores, feldspar-dissolved pores, intergranular-dissolved pores, and microfractures were the predominant pore types found within the samples. By combining the results of MICP analysis with those of fractal theory, the pore–throat structure of each sample can be categorized into two types: large-scale and small-scale. Fractal theory was employed to characterize the complex and irregular pore–throat structure of the reservoir quantitatively. The average fractal dimension of large pores (D1) was 2.8094, whereas for small pores (D2), it was slightly lower than that of large pores, averaging 2.5325. These findings underscore that large-scale pore-throat structures are more complex and exhibit greater heterogeneity. Compared with those of large pores, the pore–throat structure parameters of small pores exhibit a more significant correlation with reservoir properties and fractal dimensions. Therefore, small pores are the primary contributors to the reservoir storage space and are key factors influencing the pore-throat structure of the Chang 6 tight sandstone. Based on the pore-throat radius and considering the influence of fractal characteristics on the pore structure, a nonlinear permeability prediction model was created using multiple regression analysis. Among these equations, the pore–throat radius corresponding to a mercury saturation of 40% (r40) emerged as the most effective predictor of permeability for tight sandstone. The investigation of micropore–throat structures in tight oil reservoirs holds practical significance for comprehending the distribution and accumulation of tight oil and guiding oil field development. [ABSTRACT FROM AUTHOR]

Introduction: With the continuous development of exploration and development, tight sandstone reservoirs have become an essential field of oil and gas exploration. The tight sandstone reservoirs are characterized by complex lithology, poor pore structure, and strong heterogeneity, which bring great difficulties to formation evaluation by well logs. Especially, the accuracy of the Archie formula for calculating the water saturation of tight sandstone reservoirs containing fractures is not high, saturation evaluation faces greater challenges. Therefore, how to calculate the saturation of tight sandstone reservoirs more accurately is an urgent problem to be solved. Methods: In this paper, the tight sandstone reservoirs of the Jurassic Ahe Formation in the Tarim Basin were taken as the research area. A saturation model that combines the effects of shale and fractures was proposed. Specifically, if the shale content is more than 20%, the Indonesian formula is used to calculate the saturation. If the shale content is less than 20%, the dual porosity model is adopted. Based on the rock resistivity and nuclear magnetic resonance (NMR) experiment results, the porosity and T2 logarithmic mean values are selected as influencing factors to calculate the key parameters of the dual porosity model. Results and Discussion: The saturation of tight sandstone reservoirs in the Jurassic Ahe Formation of the Tarim Basin is calculated through the method proposed in this paper. The case study shows that the accuracy of the proposed method is higher than that of the Archie model. The method proposed in this paper demonstrates excellent adaptability in the quantitative evaluation of saturation for tight sandstone reservoirs. [ABSTRACT FROM AUTHOR]

The tight sandstone reservoris are important exploration and production target in the Xujiahe Formation in Xinchang area of Western Sichuan. Due to the various lithofacies and diagenetic alteration in distributary channel belt sandstones, the reservoirs exhibit strong heterogeneity. The strong heterogeneity makes the identification of petrologically superior sandbodies a great challenge. In order to better understand reservoir quality, this study constructs a model between diagenetic alterations and reservoir quality within distributary channel belts. 73 plug samples were taken from 17 wells located in the channel belt. An integration of thin sections, X-ray diffraction, carbon and oxygen isotope ratios, cathodoluminescence, and micro-CT were analysed for the genesis and distribution of reservoir quality. The results show that subaqueous distributary channels are formed under various hydrodynamics, resulting in different lithofacies. The thicknesses of channels can be divided into less than 2 m, 2–6 m, and more than 6 m. The diagenetic alteration in lithofacies were identified. Coarse-grained sandstones with low content of rock fragments are relatively weakly compacted with less calcite and chlorite cementation. Fine-grained sandstones with high content of rock fragments are strongly compacted with calcite cementation during early diagenesis. The dissolution pores are related to the soluble mineral content and the distribution of mudstones. The subaqueous distributary channels formed in high-energy, moderate-energy, and low-energy hydrodynamic settings have experienced different diagenetic intensities. Additionally, fractures can effectively improve the reservoir properties. The distribution of good quality reservoirs is controlled by the combined influence of diagenetic heterogeneity and fractures. This would help to promote better understanding of reservoir quality within the subaqueous distributary channel belts in braided-river delta front. [ABSTRACT FROM AUTHOR]

Natural fractures are effective storage spaces and the main seepage channels of tight reservoirs, and the spacing and role of structural fractures of different scales in tight reservoirs are also different. However, the opening or height of underground natural fractures is often difficult to determine directly using seismic data or imaging logging, which restricts the characterization, modeling, and analysis of the formation mechanisms of reservoir fractures. This paper uses the morphology of water absorption profiles and conventional logging data to calculate the ratio of the isotope intensity of a single well to natural gamma values from logging and characterize the types of water absorption profiles. The size (opening and height) of the fractures is closely related to the height of the water absorption profile and the fluctuation in the water absorption intensity. The calculated rock mechanics parameters along a single well, combined with the internal friction angle of the rock and the fracture strike, are used to determine the magnitude and direction of the paleostress of the Y290-Y414 Block in the southeastern Ordos Basin during the Himalayan period. By establishing a single-well geomechanical model to simulate the three-dimensional distribution of paleostress and paleostrain during the formation of fractures, a database model for constructing the scale of fractures is established. Through correlation analysis, a model for predicting the strength and thickness of the water absorption profile is established. Finally, the three-dimensional distribution pattern of the scale of structural fractures is predicted, and the reliability of the prediction results is verified using dynamic development data. The research results have certain reference significance for explaining the mechanism of fracture formation, characterizing the scale of underground fractures, and modeling reservoir fractures. Highlights: A model for predicting the height and opening of structural fractures is established. The scale of fractures is closely related to the mechanical structure of the rock layers. The presence of large-scale fractures is the main cause of water channeling and flooding. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Fractures play a crucial role in tight sandstone gas reservoirs with low permeability and low effective porosity. If open, they not only significantly increase the permeability of the reservoir but also serve as channels connecting the storage space. Among numerous fracture identification methods, seismic data provide unique advantages for fracture identification owing to the provision of three-dimensional information between wells. How to accurately identify the development of fractures in geological bodies between wells using seismic data is a major challenge. In this study, a tight sandstone gas reservoir in the Kuqa Basin (China) was used as an example for identifying reservoir fractures using deep-learning-based method. First, a feasibility analysis is necessary. Intersection analysis between the fracture density and seismic attributes (the characteristics of frequency, amplitude, phase, and other aspects of seismic signals) indicates that there is a correlation between the two when the fracture density exceeds a certain degree. The development of fractures is closely related to the lithology and structure, indirectly affecting differences in seismic attributes. This indicates that the use of seismic attributes for fracture identification is feasible and reasonable. Subsequently, the effective fracture density data obtained from imaging logging were used as label data, and the optimized seismic attribute near the well data were used as feature data to construct a fracture identification sample dataset. Based on a feedforward neural network algorithm combined with natural fracture density and effectiveness control factor constraints, a trained identification model was obtained. The identification model was applied to seismic multi-attribute data for the entire work area. Finally, the accuracy of the results from the training, testing, and validation datasets were used to determine the effectiveness of the method. The relationship between the fracture identification results and the location of the fractures in the target reservoir was used to determine the reasonableness of the results. The results indicate that there is a certain relationship between multiple seismic attributes and fracture development, which can be established using deep learning models. Furthermore, the deep-learning-based seismic data fracture identification method can effectively identify fractures in the three-dimensional space of reservoirs. [ABSTRACT FROM AUTHOR]

The isotonic point of the Chang-6 tight oil reservoir in the Qilicun Oilfield in the Ordos Basin cannot be determined from experimental data on the waterflooding permeability. Furthermore, there are missing data near the isotonic point. Previous research on phase permeability trends has uncovered significant uncertainties in the application of data normalization, standardization, and interpolation processing. In current research, there is a consensus on the existence of a relationship between the relative permeability and saturation indices. However, since measurements contain relative permeabilities of 0, coefficient indices cannot be directly derived. Researchers have theorized that the first data number in the wet phase relative permeability must be changed from a 0 to non-0 minimum in order to directly establish the relationship between the relative permeability and the water saturation index. The missing intervals after the first data point are not interpolated. Not only does this method incorporate the knowledge of the permeability indices obtained by researchers, but it also eliminates the processes of normalization, standardization, and interpolation of missing data intervals for permeability data in order to avoid errors introduced by these processes. Without introducing new parameters, interference with raw data was reduced and the accuracy was improved. The results indicate that the relative permeability is highly correlated with the water saturation indices. Furthermore, the relationships between the water content and relative permeability and between the water saturation and water content were analyzed using the Leverett displacement function and percolation theory. The water saturation corresponding to the water content of 17 samples was calculated under the condition of displacement, and the relationship between the critical water saturation and water content was further established. These results provide support for studies on the relationship between phase permeability and oil-water saturation within this area. [ABSTRACT FROM AUTHOR]

By measuring the variation of the P- and S-wave velocities of tight sandstone samples under water saturation, it was confirmed that with the decrease in water saturation, the P-wave velocity first decreased and then increased. The variation in velocity was influenced by the sandstone's porosity. The commonly used Gassmann equation based on fluid substitution theory was studied. Comparing the calculated results with the measured data, it was found that the Gassmann equation agreed well with the measured data at high water saturation, but it could not explain the bending phenomenon of P-wave velocity at low saturation. This indicated that these equations could not accurately describe the relationship between fluid content and rock acoustic velocity. The reasons for this phenomenon were discussed through Taylor's expansion. The coefficients of the fitting formula were calculated and verified by fitting the measured acoustic velocity changes of the cores. The relationship between P-wave velocity and saturation was discussed, which provides experimental support for calculating saturation using seismic and acoustic logging data. [ABSTRACT FROM AUTHOR]

Poorly producing wells in sandstone gas reservoirs are often refractured to enhance production. Considering the mutual interference of initial/refractured fractures, conductivity dynamic evolution, non-uniform inflow, and variable mass flow in the fracture comprehensively, a semi-analytical reservoir-fracture coupled production model fusing spatial and time separation methods is introduced to model refractured well performance. The proposed model is verified by CMG. The field applications indicate that the refracture job should be carried out when production is lower than the desired value. Restoring the Cf-ini and constructing the Cf-ref can increase productivity, which increases over 8 D•cm. The production growth rate just obtained a slight improvement. The production increased significantly with Lf-ini increasing from 120~270 m and Lf-ref increasing from 100~150 m. Hence, it is essential to extend the Lf-ini under engineering conditions. The ks/km = 10 can obviously increase production, but further enlarging ks does not contribute to well performance. Conversely, further producing larger bs is vital to enhancing production. Subsequently, the optimal parameter combinations (ds > Lf-ini > Lf-ref > Cf-ini > ks > Cf-ref) for well(X1) are carried out by orthogonal experiments. This work proposes a novel method to simulate refractured vertical well performance in tight gas reservoirs for refracture optimization. [ABSTRACT FROM AUTHOR]

This article studies the migration and settlement laws of backflow proppants after fracturing tight sandstone. This paper proposes a fitting method based on a multi-task learning network to address the issue of interference from multiple physical parameters during the transport and settlement processes of proppants. This method can effectively handle multi-dimensional interference factors and fit the mapping logic of multiple engineering parameters to transport patterns through the continuous correction of multi-layer networks. We first introduce the characteristics of tight sandstone reservoirs and their important value in mining, as well as the status of current research on the migration and settlement laws of proppants at home and abroad. Based on this, we then deeply analyze the sedimentation rate model of proppants in tight sandstone backflow and the equilibrium height of proppants under multiple factors of interference while considering the distribution characteristics of proppants. In order to more accurately simulate the transport and settlement laws of proppants, this paper introduces a multi-task learning network. This network can comprehensively consider multi-dimensional parameters, learn the inherent laws of data through training, and achieve accurate fitting of the transport and settlement laws of proppants. This study trained and tested the model using actual production data, and the results showed that the proposed model can fit the input–output relationship well, thus effectively supporting the study of proppant transport and settlement laws. [ABSTRACT FROM AUTHOR]

Abstract As a typical tight reservoir and an important site for unconventional hydrocarbon accumulation, the Chang 6 member of the Yanchang Formation is characterized by complex pore structures and strong heterogeneity. Analysing and characterizing the pore-throat structure is highly important for optimizing oil recovery processes. To clarify the nonhomogeneity and structural characteristics of the pore throats in the southeastern Ordos Basin, tight sandstone from the Chang 6 member was selected for analysis. Casting thin section (CTS), scanning electron microscopy (SEM), cathodoluminescence (CL), X-ray diffraction (XRD), and mercury intrusion capillary pressure (MICP) analyses were conducted. The results, revealed that intergranular pores, feldspar-dissolved pores, intergranular-dissolved pores, and microfractures were the predominant pore types found within the samples. By combining the results of MICP analysis with those of fractal theory, the pore–throat structure of each sample can be categorized into two types: large-scale and small-scale. Fractal theory was employed to characterize the complex and irregular pore–throat structure of the reservoir quantitatively. The average fractal dimension of large pores (D1) was 2.8094, whereas for small pores (D2), it was slightly lower than that of large pores, averaging 2.5325. These findings underscore that large-scale pore-throat structures are more complex and exhibit greater heterogeneity. Compared with those of large pores, the pore–throat structure parameters of small pores exhibit a more significant correlation with reservoir properties and fractal dimensions. Therefore, small pores are the primary contributors to the reservoir storage space and are key factors influencing the pore-throat structure of the Chang 6 tight sandstone. Based on the pore-throat radius and considering the influence of fractal characteristics on the pore structure, a nonlinear permeability prediction model was created using multiple regression analysis. Among these equations, the pore–throat radius corresponding to a mercury saturation of 40% (r40) emerged as the most effective predictor of permeability for tight sandstone. The investigation of micropore–throat structures in tight oil reservoirs holds practical significance for comprehending the distribution and accumulation of tight oil and guiding oil field development.

Abstract To further raise the gas extraction efficiency of the tight sandstone, the liquid nitrogen (LN2) freezing-thawing cycles method can be employed to improve the permeability of the low-permeability reservoirs. Permeability is generally regarded as a macroscopic description of the pore structure and usually has functional relationship to pore structure properties. The permeability of the rock is closely related to the change of microscopic pore structure. The permeability of rock depends on how the subzero temperatures changed the microscopic pore structure of rock, but it has not yet been confirmed obviously. In this study, the nuclear magnetic resonance (NMR) technique was adopted to investigate the pore structure evolution law and permeability of the tight sandstone with different LN2 freezing-thawing cycles. The results demonstrate that the LN2 freezing-thawing cycles promotes pore development and micro-fracture connection, and enhances the pore connectivity. The proportion of meso-pores, macro-pores and micro-fractures in the sandstone samples increases significantly, which provides a channel for the sandstone gas flow and extraction. Total porosity and effective porosity of the samples present a trend of rapid increase as the number of LN2 freezing-thawing cycles increasing, while the residual porosity decreases as the number of LN2 freezing-thawing cycles increasing. Coates model, SDR model (mean T2 model) and PP model were used to calculate and evaluate the permeability of the samples subjected to different LN2 freezing-thawing cycles. Furthermore, PP model can provide a better permeability estimate than the classical Coates and SDR model.

Abstract The tight sandstone reservoris are important exploration and production target in the Xujiahe Formation in Xinchang area of Western Sichuan. Due to the various lithofacies and diagenetic alteration in distributary channel belt sandstones, the reservoirs exhibit strong heterogeneity. The strong heterogeneity makes the identification of petrologically superior sandbodies a great challenge. In order to better understand reservoir quality, this study constructs a model between diagenetic alterations and reservoir quality within distributary channel belts. 73 plug samples were taken from 17 wells located in the channel belt. An integration of thin sections, X-ray diffraction, carbon and oxygen isotope ratios, cathodoluminescence, and micro-CT were analysed for the genesis and distribution of reservoir quality. The results show that subaqueous distributary channels are formed under various hydrodynamics, resulting in different lithofacies. The thicknesses of channels can be divided into less than 2 m, 2–6 m, and more than 6 m. The diagenetic alteration in lithofacies were identified. Coarse-grained sandstones with low content of rock fragments are relatively weakly compacted with less calcite and chlorite cementation. Fine-grained sandstones with high content of rock fragments are strongly compacted with calcite cementation during early diagenesis. The dissolution pores are related to the soluble mineral content and the distribution of mudstones. The subaqueous distributary channels formed in high-energy, moderate-energy, and low-energy hydrodynamic settings have experienced different diagenetic intensities. Additionally, fractures can effectively improve the reservoir properties. The distribution of good quality reservoirs is controlled by the combined influence of diagenetic heterogeneity and fractures. This would help to promote better understanding of reservoir quality within the subaqueous distributary channel belts in braided-river delta front.

Abstract Tight sandstone reservoirs are a primary focus of research on the geological exploration of petroleum. However, many reservoir classification criteria are of limited applicability due to the inherent strong heterogeneity and complex micropore structure of tight sandstone reservoirs. This investigation focused on the Chang 8 tight reservoir situated in the Jiyuan region of the Ordos Basin. High-pressure mercury intrusion experiments, casting thin sections, and scanning electron microscopy experiments were conducted. Image recognition technology was used to extract the pore shape parameters of each sample. Based on the above, through grey relational analysis (GRA), analytic hierarchy process (AHP), entropy weight method (EWM) and comprehensive weight method, the relationship index Q1 between initial productivity and high pressure mercury injection parameters and the relationship index Q2 between initial productivity and pore shape parameters are obtained by fitting. Then a dual-coupled comprehensive quantitative classification prediction model for tight sandstone reservoirs was developed based on pore structure and shape parameters. A quantitative classification study was conducted on the target reservoir, analyzing the correlation between reservoir quality and pore structure and shape parameters, leading to the proposal of favourable exploration areas. The research results showed that when Q1 ≥ 0.5 and Q2 ≥ 0.5, the reservoir was classified as type I. When Q1 > 0.7 and Q2 > 0.57, it was classified as type I1, indicating a high-yield reservoir. When 0.32

Objective The Shengbei Depression is the largest petroliferous depression of the Tuha Basin. With the strong demand for the exploration and development of tight sandstone gas in the Middle Jurassic Sanjianfang Formation, it is urgent to study the sedimentary characteristics and predict favourable exploration zones of the Sanjianfang Formation. Methods Using core, well logging, and seismic data, the high-resolution sequences and sedimentary characteristics of the tight sandstone gas reservoir in the Sanjianfang Formation of the Shengbei Depression were studied. A lacustrine delta system was identified, and favourable exploration zones of tight gas reservoirs were predicted. Results Three long-term sequences (L1, L2, L3) and five medium-term sequences (M1, M2, M3, M4, M5) were developed in the Sanjianfang Formation in the Shengbei Depression; particularly, these medium-term sequences can be regionally identified. The deposition of the M1 to M3 sequences involved a braided river delta in the lake, but the deposition of the M4-M5 sequences involved a meandering river delta in the lake. The favourable tight gas reservoirs of the Sanjianfang Formation in the Shengbei Depression were mainly developed in subfacies of the delta front. On the plane, the Shengbei 5 and Shengshen 3 well areas of the M2 sequence, the Shengbei 5 and Shengbei 6 well areas of the M3 sequence, and the Shengbei 5, Shengbei 6, and Shengtan 1 well areas of the M5 sequence are favorable exploration areas. The favorable reservoir rarely appears in the M4 sequence. Conclusion This research can promote the exploration of tight gas reservoirs in the Sanjianfang Formation of the Shengbei Depression in the Tuha Basin.

Fractures are crucial for the high and stable production of natural gas from the tight sandstone reservoirs in the second member of the Xujiahe Formation in the Western Sichuan Depression, Sichuan Basin. The development of these fractures is controlled by the configuration interfaces of sand bodies formed under different sedimentary environments. Through field outcrop surveys, core observations, logging identification, and detailed characterization of lithofacies, a classification scheme for sand body configuration interfaces was proposed for the second member of the Xujiahe Formation in the Western Sichuan Depression. These interfaces were identified and classified into second to fourth levels. The study clarified the characteristics and geological significance of fractures under different levels of configuration interfaces. These interfaces controlled the occurrence, opening degree, development degree, and storage-permeability capacities of reservoir fractures. The effective control ranges of the second and third level interfaces were 0-0.35 m and 0-3 m, respectively, while the fourth level interface had a larger control range (0-11 m). The development characteristics of fractures differed under different configuration interfaces. Specifically, fractures were underdeveloped at the second level interfaces; fairly developed at the fourth level; and most developed at the third level, primarily as low-angle dipping fractures. Fracture orientations were predominantly NNE-SSW, SEE-NWW, and SSE-NNW, with more fractures having larger openings (>0.04 mm) and larger dip angle. There was a clear positive correlation between core porosity and permeability in the fracture development under the control of the multi-level interfaces. Fractures at the third level interface had the strongest improvement effect on reservoir physical properties and made the highest contribution to oil and gas production, followed by the fourth level interface, with the second level interface being the least effective. Clarifying the control of different levels of configuration interfaces on fracture development is conducive to the effective development of tight sandstone gas reservoirs in the study area.

To optimize the identification of sweet spots with natural fracture development in ultra-deep tight sandstone reservoirs of Cretaceous in the Kuqa Depression, Tarim Basin, this study systematically analyzed the differences in rock mechanical properties across various sedimentary microfacies in the BZ gas field. Utilizing data from outcrops, rock slices, imaging logging, and other sources, a method for optimizing the rock mechanics parameter model of reservoirs was proposed, which enhanced the prediction accuracy of natural fractures within 200 m around the wellbore. Key findings of the research include: (1) In the third member of the Cretaceous Bashijiqike Formation in the BZ gas field, different sedimentary microfacies and the same microfacies at different positions had differences in rock composition and rock assemblages (including debris content, matrix content, grain size sorting, sand-to-mud ratio, and sand-mudstone combinations). These variations affected the reservoir's Poisson's ratio and Young's modulus, and different microfacies had different rock mechanical parameters. (2) The extent of fracture development differed across various sedimentary microfacies of sand bodies. Fractures were most developed in the underwater distributary channel sandstones at the fan delta front, making them more prone to fracturing compared to the interdistributary bay microfacies and distributary channel microfacies on the delta plain. (3) By further establishing three-dimensional models of different microfacies based on geometric parameters derived from outcrops, it would be feasible to optimize sedimentary microfacies models and rock mechanical parameter models around the wellbore, thereby facilitating more accurate fracture prediction.

In this study, taking the Jurassic Lianggaoshan Formation (J1l) tight sandstones in the eastern Sichuan Basin as an example, the types and well-logging responses of main sedimentological and diagenetic facies in the lacustrine delta-front are investigated based on summarizing the sedimentary characteristics and reservoir properties. Subsequently, further validation and application are conducted in the study area through machine learning. Research results show that the J1l lacustrine delta-front in the eastern Sichuan Basin mainly develops subaqueous distributary channels and mouth bar sand bodies, exhibiting typical densification reservoirs, with porosity and permeability distributed between 0.48% and 11.24% (av. 3.87%) and 0.0003-0.653 x 10-3 µm² (av. 0.026 x 10-3 µm²), respectively. Strong compaction and strong cementation are the primary factors leading to densification, whereas chlorite coatings and weak dissolution play constructive roles in preserving some primary pores, creating a small amount of dissolution pores, and enhancing permeability. In terms of manifestation, the pore-throat content with a radius greater than 0.006 µm governs the reservoir quality. Furthermore, five types of diagenetic facies are identified in the J1l subaqueous distributary channels and mouth bars: strong compaction facies (Type I), strong cementation facies (Type II), chlorite-coating and intergranular pore facies (Type III), weak dissolution and intragranular pore facies (Type IV), and medium compaction and cementation facies (Type V). Overall, the thick and coarse-grained subaqueous distributary channels can be considered as the preferred exploration targets for tight oil and gas, with type III and type IV diagenetic facies being the most favorable reservoirs, characterized by well-logging responses of high AC and low GR, DEN, and RT. Based on the fine division of sedimentological and diagenetic facies, establishing well-logging interpretation models and then employing machine learning to achieve sweet spot reservoir prediction can provide valuable insights for tight oil and gas exploration in regions lacking core data. [ABSTRACT FROM AUTHOR]

A well-connected network formed by multi-scale fractures is a key factor in the formation of high-quality reservoirs and the achievement of high and stable oil and gas production in tight sandstones. Taking the Upper Paleozoic of the Qingshimao gas field in the Ordos Basin, China, as an example, based on data from image logs, cores, and thin sections, fine quantitative characterization of multi-scale natural fractures in tight sandstone reservoirs was carried out. We also established a method for dividing network patterns of multi-scale fractures and discussed the effect of each fracture network pattern on the gas enrichment and production capacity. Results indicate regular changes in the length, density, aperture, porosity, permeability, and connectivity of natural fractures at different scales. Based on the spatial combination patterns and connectivity of fractures of different scales, four types of fracture network patterns were established: multi-scale fracture network with high density and multi-orientations, multi-scale fracture network with moderate-high density and dual orientations, small-scale fracture network with moderate density and dual orientations, small-scale fracture network with low density and single orientation. The first fracture network pattern can destroy the integrity of the cap layer, causing natural gas leakage. The second fracture network pattern is a favorable area for natural gas enrichment. The third fracture network pattern requires the use of hydraulic fracturing to obtain commercial airflow. The fourth fracture network pattern has little effect on reservoir control and storage. The study of natural fractures in tight sandstone reservoirs is usually based on a single-scale perspective. Understanding the development characteristics of multi-scale fractures and their controlling effects on the reservoir helps to comprehensively understand the spatial configuration relationship of multiscale fracture network structure patterns and promotes the development of multi-scale fractures in tight reservoir research. [ABSTRACT FROM AUTHOR]

The Chang 6 reservoir group in the southeastern Wangjiawan area of the Ordos Basin is a tight sandstone reservoir. Reservoir sensitivity evaluation is an important means to study fluid damage to reservoirs and has important guiding significance for later water injection development. Reservoir sensitivity and its influencing factors were studied based on a scanning electron microscope, mercury injection test, and sensitivity test. The results show that the study area is mainly feldspar sandstone with high content of feldspar, quartz and rock debris, and clay minerals are mainly illite, chlorite and illite-montmorillonite mixed layer. The rock is dense, the pore structure is poor, and the pore throat distribution is uneven, which is a low porosity and low permeability reservoir. The sensitivity is characterized by medium-weak velocity sensitivity, medium-weak water sensitivity, medium-strong acid sensitivity, weak-medium-weak alkali sensitivity and medium-weak-weak salt sensitivity. The type and content of clay minerals affect the main factors of reservoir sensitivity. The mixed layer of illite and montmorillonite, illite and chlorite in clay minerals have great influence on salt sensitivity, water sensitivity and acid sensitivity respectively. Therefore, in the process of water injection development, targeted reservoir protection measures should be taken for salt sensitivity, water sensitivity and acid sensitivity. [ABSTRACT FROM AUTHOR]

To understand the effect of the spontaneous imbibition (SI) and waterflooding on oil recovery in the tight sandstone reservoirs, we selected three pairs of tight sandstone samples from the Ordos Basin in China to conduct the SI-plus-waterflooding and waterflooding-only experiments, and monitor the oil distribution and flow characteristics by using the low-field nuclear magnetic resonance (NMR) technology. One interesting observation was that oil extracted in the SI process mainly comes from macropores and micropores, which doesn't agree with the previous results wherein oil was produced from micropores, and oil was produced from the mesopores during the waterflooding after the SI process. The oil recovery factor of tight sandstone samples in the process of the SI-plus-waterflooding was more than 50%, and even more than 85%, which was greater than that in the waterflooding-only process. Moreover, we found that our tight sandstone samples behaved lower residual oil saturation, and wider oil-water two-phase co-flow region during the SI-plus-waterflooding process than that did during the waterflooding-only process. These differences in behavior appear to be linked to the fluid dynamic characteristics and capillary pressure acting on the flow fluid during the two processes. In summary, the SI-plus-waterflooding overcame the limitations related to waterflooding-only and further improved oil recovery factor in the tight sandstones. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing stands as a pivotal technological approach for enhanced tight gas recovery. This paper investigates the influences of geological and engineering parameters on the vertical extension mechanism of hydraulic fractures. In addition, the feasibility and effectiveness of fracture height prediction method and various fracture height control techniques have been examined. The results indicate that the height of hydraulic fractures decreases with an increase in the thickness of the barrier layers, the stress difference between the barrier and reservoir layers, the difference in tensile strength, and the difference in fracture toughness, whereas it increases with the increasing of difference in elastic modulus between the barrier and reservoir layers. Compred with the difference in Poisson's ratio, the volume of fracturing fluid, discharge rate, and fluid viscosity have little impactd. The influence of these factors on fracture height, in descending order, is stress difference between barrier and reservoir layers, fracturing fluid viscosity, fracturing discharge, fracturing fluid volume, barrier layer thickness, tensile strength difference between barrier and reservoir layers, elastic modulus difference between barrier and reservoir layers, Poisson's ratio difference between barrier and reservoir layers. Furthermore, based on typical geomechanic and reservoir parameters of the target area, a fracture height prediction workflow has been developed. Engineering practice has proven the reliability of fracture height prediction method. The results of this study provide theoretical support and guidance for predicting fracture morphology, controlling fracture height in the hydraulic fracturing development of the tight gas reservoir, and optimizing fracturing process design. [ABSTRACT FROM AUTHOR]

Tight sandstone reservoirs have low porosity, low permeability, and a complex pore structure. The seepage from tight sandstones is a key factor in evaluating the oil and gas accumulation in these reservoirs. Therefore, reservoir permeability prediction has become the focus of researchers. Using nuclear magnetic resonance (NMR), high-pressure mercury injection, scanning electron microscopy, and other experimental methods, scholars have established various permeability prediction models, which have obvious advantages and disadvantages. However, there is less research conducted on predicting the permeability of tight sandstone reservoirs according to their single-peak NMR T2 distribution. Based on NMR experiments and the bimodal Gaussian density formula, this study identified the criteria for determining the types of reservoir pore structures with single-peak NMR T2 distribution and established the parameters (η1 and η2) that can be used in the evaluation of reservoir pore structure. A novel model for predicting the permeability of tight sandstone reservoirs was established using η1 and η2. The results of the prediction model proposed in this study were found to be superior to the results of eight permeability prediction models established by other scholars in the studied case of the Huangliu Formation. However, permeability prediction models established using the NMR experimental results of different sources were found to be ineffective. Additionally, the new model is suitable for use with sandstone reservoirs with both single-peak and double-peak NMR T2 distributions in the studied case of the Yanchang Formation. Logging curves can be used to predict η1 and η2, and the permeability of a single well of a tight sandstone reservoir. The study findings would be useful for predicting tight sandstone reservoir permeability. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Chongqing University of Technology (Natural Science) is the property of Chongqing University of Technology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Inter-well frac-hit has become an important challenge in the development of unconventional oil and gas resources such as fractured tight sandstone. Due to the presence of hydraulic fracturing fractures, secondary induced fractures, natural fractures, and other seepage media in real formations, the acquisition of stress fields requires the coupling effect of seepage and stress. In this process, there is also stress sensitivity, which leads to unclear dynamic evolution laws of stress fields and increases the difficulty of the staged multi-cluster fracturing of horizontal wells. The use of a multi-stage stress-sensitive horizontal well production stress field prediction model is an effective means of analyzing the influence of natural fracture parameters, main fracture parameters, and multi-stage stress sensitivity coefficients on the stress field. This article considers multi-stage stress sensitivity and, based on fractured sandstone reservoir parameters, establishes a numerical model for the dynamic evolution of the production stress field in horizontal wells with matrix self-supporting fracture-supported fracture–seepage–stress coupling. The influence of various factors on the production stress field is analyzed. The results show that under constant pressure production, for low-permeability reservoirs, multi-stage stress sensitivity has a relatively low impact on reservoir stress, and the amplitude of principal stress change in the entire fracture length direction is only within the range of 0.27%, with no significant change in stress distribution; The parameters of the main fracture have a significant impact on the stress field, with a variation amplitude of within 2.85%. The ability of stress to diffuse from the fracture tip to the surrounding areas is stronger, and the stress concentration area spreads from an elliptical distribution to a semi-circular distribution. The random natural fracture parameters have a significant impact on pore pressure. As the density and angle of the fractures increase, the pore pressure changes within the range of 3.32%, and the diffusion area of pore pressure significantly increases, making it easy to communicate with the reservoir on both sides of the fractures. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Geomechanics is the property of Journal of Geomechanics Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The tight sandstone reservoirs in the Sulige Gas Field have complex pore structures and gas-water distribution, and the water production law in the complex gas-water distribution areas has not been clarified. The water production of gas wells in different regions varies greatly, and the water production of gas wells seriously affects the efficient development of natural gas. In order to improve the benefit of gas field development, this study takes stress-sensitive effects, gas-water immiscibility, and constant production conditions of gas wells under a certain gas-water ratio Rgw as constraints, and considers the fluid seepage as an isothermal seepage process, an evaluation model of the productivity of a theoretical water-producing gas well and a relative permeability model of the gas phase are constructed. Moreover, the influence of water production on the degree of pressure drop, gas well productivity, and gas well recovery was systematically analyzed. This study shows that when the water-gas ratio of gas wells is less than 1, 1-2, 2-3, 3-4, 4-5, and greater than 5, its influence on productivity is less than 40%, 52%, 50%, 58%, 61%, 65% and greater than 65%, respectively. The average water-gas ratio of the water-producing gas wells in the Sulige Gas Field is 1.27 m3/10 4 m3. The effect of water production on recovery is compared with the case of no water production: for water-producing gas wells, the recovery rate of Type I wells is reduced by 8.45%, that of Type II wells is reduced by 9.58%, and that of Type III wells is reduced by 11.54%. [ABSTRACT FROM AUTHOR]

The reservoir quality of tight sandstone is usually affected by pore throat structures, and understanding pore throat structures and their fractal characteristics is crucial for the exploration and development of tight sandstone gas. In this study, fractal dimensions of pore throat structures and the effect of diagenesis on the fractal dimension of tight sandstone sweet spot in Huagang Formation, Jiaxing area, East China Sea Basin were studied by means of thin sections, scanning electron microscopes, X-ray diffraction analysis, scanning electron microscope quantitative mineral evaluation, and high pressure mercury injection experiments. The results show that the total fractal dimension ranges of type I, type II, and type III sweet spots were 2.62–2.87, 2.22–2.56, and 2.71–2.77, respectively. The negative correlation between total fractal dimensions, porosity, and permeability of type I sweet spots was different from those of type II and type III sweet spots. The negative correlation between total fractal dimensions of type II and type III sweet spots and maximum mercury saturation, average pore throat radius, and skewness were significant, whereas the correlation between total fractal dimensions of type I sweet spots, and maximum mercury saturation, average pore throat radius and skewness were not significant. The positive correlation between the total fractal dimensions of type II and type III sweet spots and the relative sorting coefficient, displacement pressure, and efficiency of mercury withdrawal were significant, whereas the correlation between the total fractal dimension of type I sweet spots and relative sorting coefficients, displacement pressures and efficiency of mercury withdrawal were not significant. The effect of diagenesis on fractal dimensions was investigated. Compaction reduced the pore space of tight sandstone and increased fractal dimensions. Quartz cementation and calcite cementation blocked pores and throats, reduced pore space, and increased fractal dimensions. Chlorite coat can inhibit compaction, protect pore throat structures, and maintain fractal dimensions. Most clay minerals filled primary pores and secondary pores and increased fractal dimensions. Dissolution increased the pore space of tight sandstone and decreased the fractal dimensions of the pore throat structures. The pore throat structures of type I sweet spots were mainly composed of macropores, mesopores, transitional pores, and micropores, and the fractal dimension of type I sweet spots was chiefly controlled by chlorite coat formation, dissolution, and a small amount of compaction. This study provides a reference for pore throat structure and fractal dimension analysis of tight sandstone sweet spots. [ABSTRACT FROM AUTHOR]

The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures, rendering it susceptible to water-blocking damage during imbibition extraction. This study delved into the traits of tight sandstone reservoirs in the 8th member of the Shihezi Formation (also referred to as the He 8 Member) in the study area, as well as their effects on fracturing fluid imbibition. Utilizing experimental techniques such as nuclear magnetic resonance (NMR), high-pressure mercury intrusion (HPMI), and gas adsorption, this study elucidated the reservoir characteristics and examined the factors affecting the imbibition through imbibition experiments. The findings reveal that: ① The reservoir, with average porosity of 8.40% and average permeability of 0.642 × 10-3 μm², consists principally of quartz, feldspar, and lithic fragments, with feldspathic litharenite serving as the primary rock type and illite as the chief clay mineral; ② Nano-scale micro-pores and throats dominate the reservoir, with dissolution pores and intercrystalline pores serving as predominant pore types, exhibiting relatively high pore connectivity; ③ Imbibition efficiency is influenced by petrophysical properties, clay mineral content, and microscopic pore structure. Due to the heterogeneity of the tight sandstone reservoir, microscopic factors have a more significant impact on the imbibition efficiency of fracturing fluids; ④ A comparative analysis shows that average pore size correlates most strongly with imbibition efficiency, followed by petrophysical properties and clay mineral content. In contrast, the pore type has minimal impact. Micropores are vital in the imbibition process, while meso-pores and macro-pores offer primary spaces for imbibition. This study offers theoretical insights and guidance for enhancing the postfracturing production of tight sandstone reservoirs by examining the effects of these factors on the imbibition efficiency of fracturing fluids in tight sandstones. [ABSTRACT FROM AUTHOR]

Tight sandstone is rich in micron- and nano-scale pores, making the two-phase flow of gas and water complex. Establishing reliable relative permeability and productivity models is an urgent issue. In this study, we first used a slip model to correct the gas phase's no-slip Hagen–Poiseuille equation for nano- and micropores. Then, combined with the fractal theory of porous media and the tortuous capillary bundle model, we established two-phase relative permeability models for nanopores and micropores. These relative permeability models comprehensively consider the gas slippage effect, the initiation pressure gradient, the pores' fractal characteristics, and water film mechanisms. Based on these models, we developed a three-region coupling productivity model for water-bearing tight gas reservoirs with multi-stage fractured horizontal wells. This productivity model considered the micro- and nano-scale effects and the heterogeneity of fracture networks. Then, the model was solved and validated with a field case. The results indicated that the three-region composite unsteady productivity model for water-bearing tight gas reservoirs, which incorporated micro- and nano-scale effects (with consideration of micro-scale and nano-scale phenomena in the fluid flow), could accurately predict a gas well's productivity. An analysis of the factors influencing productivity showed that ignoring the micro- and nano-scale effects in water-bearing tight gas reservoirs will underestimate the reservoir's productivity. The initial water saturation, the two-phase flow's initiation pressure gradient, and capillary force are all negatively correlated with the productivity of gas wells, while the conductivity of the fractures is positively correlated with gas well productivity. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Experiment is the property of Petroleum Geology & Experiment Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Experiment is the property of Petroleum Geology & Experiment Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The pore-throat structure is a critical factor in the study of unconventional oil and gas reservoirs, drawing particular attention from petroleum geologists, and it is of paramount significance to analyze to enhance oil and gas production. In tight sandstone, which serves as a significant hydrocarbon reservoir, the internal pore-throat structure plays a decisive role in the storage and migration of fluids such as water, gases, and hydrocarbons. This paper employs casting thin section (CTS), field emission scanning electron microscope (FE-SEM), high-pressure mercury injection (HPMI), and low-temperature nitrogen gas adsorption (LT−N2−GA) experimental tests to qualitatively and quantitatively analyze the characteristics of the pore-throat structure in tight sandstone. The results indicate that the pore types in tight sandstone include intergranular residual pores, dissolution pores, intercrystalline pores, and microfractures, while the throat types encompass sheet-shaped, curved-sheet-shaped, and tubular throats. Analysis of the physical and structural parameters from 13 HPMI and 5 LT−N2−GA samples reveals a bimodal distribution of pore-throat radii. The complexity of the pore-throat structure is identified as a primary controlling factor for reservoir permeability. The fractal dimension (D) exhibits an average value of 2.45, displaying a negative correlation with porosity (R2 = 0.22), permeability (R2 = 0.65), the pore-throat diameter (R2 = 0.58), and maximum mercury saturation (R2 = 0.86) and a positive correlation with threshold pressure (R2 = 0.56), median saturation pressure (R2 = 0.49), BET specific surface area (R2 = 0.51), and BJH total pore volume (R2 = 0.14). As D increases, reservoir pores tend to decrease in size, leading to reduced flow and deteriorated physical properties, indicative of a more complex pore-throat structure. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

This study takes the tight sandstone of the lower sub‐member of the first member of the Eocene Shahejie Formation (Es1x) in the Suning area, Raoyang Sag, Bohai Bay Basin. Furthermore, it determines the rock type of the middle‐deep tight sandstone through lithologic profiling, core observation and log data analysis. The genetic control factors of tight sandstone in the study area are analysed using conventional thin section, pore‐casted thin section and scanning electron microscope, and the characteristics and genetic control factors of tight sandstone reservoirs are summarized. The research results show that the tight sandstones in this area are primarily feldspathic sandstone and feldspathic lithic sandstone, with high quartz contents, around 61.50%. The average porosity of the reservoir in the study area is 4.69%, and the average permeability is 2.92 mD, which are characteristics of low‐porosity and low‐permeability reservoirs. Through research, it has been found that the distribution of sedimentary facies and diagenesis in the study area control the development and distribution of 'sweet spots'. Both compaction and cementation reduce the physical properties of the reservoir, while dissolution can increase porosity, thereby increasing the physical properties of the reservoir; dissolution resulted in an increase of approximately 3.57%–3.69% in the porosity of the tight reservoir in the study area, with an average porosity increase of 3.63%, and is the main controlling factor for the development of 'sweet spots' in the reservoir. The results provide an important basis for guiding the exploration and development of tight sandstone oil and gas in the lower sub‐member of the first member of the Eocene Shahejie Formation (Es1x)in the Suning area. [ABSTRACT FROM AUTHOR]

Wave‐induced fluid flow is considered to be a major source of seismic attenuation and dispersion in porous rocks. From the physical description of partially saturated reservoirs, numerous analytical solutions based on upscaling homogenization theories have been employed to calculate equivalent frequency‐dependent poroelastic media. Nevertheless, dispersion and attenuation predictions are often not reasonably consistent with laboratory and field measurements in a broad frequency range, particularly due to influences of biphasic fluids and their distribution, presence of heterogeneities on various length scales, and pore microstructure. We investigate the role of pore microstructure on pressure and fluid saturation dependence of elastic velocities in tight sandstones. Previous work points out that differentiating the impacts of heterogeneities at various scales on dispersion within seismic exploration and sonic frequencies can be very difficult. In practice, this is because fluid‐related dispersion mechanisms are impossible to be independent. Thus, it is important for a theoretical and more quantitative analysis of the relative contribution of interrelated energy dissipation processes through a better understanding of combined influences due to the presence of microscopic and mesoscopic heterogeneities. Based on microscopic squirt flow and mesoscopic flow in a partially saturated medium, we develop a poroelastic model that allows evaluating the overall frequency‐dependent dispersion via considering a random distribution of fluid heterogeneities as well as the broadly distributed aspect ratio of compliant pores. Experimental validation of the model is accomplished via a comprehensive comparison of predictions with measurements of partially saturated velocities versus pressure and fluid for sandstones with specific pore microstructures. [ABSTRACT FROM AUTHOR]

This 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. [ABSTRACT FROM AUTHOR]

IntroductionWith the continuous development of exploration and development, tight sandstone reservoirs have become an essential field of oil and gas exploration. The tight sandstone reservoirs are characterized by complex lithology, poor pore structure, and strong heterogeneity, which bring great difficulties to formation evaluation by well logs. Especially, the accuracy of the Archie formula for calculating the water saturation of tight sandstone reservoirs containing fractures is not high, saturation evaluation faces greater challenges. Therefore, how to calculate the saturation of tight sandstone reservoirs more accurately is an urgent problem to be solved.MethodsIn this paper, the tight sandstone reservoirs of the Jurassic Ahe Formation in the Tarim Basin were taken as the research area. A saturation model that combines the effects of shale and fractures was proposed. Specifically, if the shale content is more than 20%, the Indonesian formula is used to calculate the saturation. If the shale content is less than 20%, the dual porosity model is adopted. Based on the rock resistivity and nuclear magnetic resonance (NMR) experiment results, the porosity and T2 logarithmic mean values are selected as influencing factors to calculate the key parameters of the dual porosity model.Results and DiscussionThe saturation of tight sandstone reservoirs in the Jurassic Ahe Formation of the Tarim Basin is calculated through the method proposed in this paper. The case study shows that the accuracy of the proposed method is higher than that of the Archie model. The method proposed in this paper demonstrates excellent adaptability in the quantitative evaluation of saturation for tight sandstone reservoirs.