Search Results (21)

To elucidate the development control factors, diagenetic evolution, and pore evolution of oil and gas reservoirs of the Huagang Formation in the East China Sea Shelf Basin Central Anticlinal Belt, this study involved geological analyses, including thin-section petrography, scanning electron microscopy (SEM), mineral analysis via TESCAN Integrated Mineral Analyzer (TIMA), X-ray diffraction (XRD), and petrophysical measurements. We investigated the reservoir characteristics and primary diagenetic processes of the Huagang Formation reservoirs using logging and nuclear magnetic resonance (NMR) data, identified provenance differences between the north-central (FN) and south-central (FS) areas, divided diagenetic environments, established distinct diagenetic sequences, and uncovered high-quality reservoir pore evolution patterns. The results showed that the provenance in the FN area of the Central Anticlinal Belt is primarily acidic igneous rocks, which exhibits low resistance to compaction but is susceptible to dissolution modification, and the “high-dissolution zone” developed at burial depths of 3600–3900 m constitutes the primary high-quality reservoir; the provenance in the FS area is a mixture of medium- and high-grade metamorphic rocks and acidic igneous rocks, which exhibits stronger resistance to compaction, but dissolution zones are poorly developed. The Huagang Formation has experienced multiple diagenetic processes, such as compaction, cementation, and dissolution. During destructive diagenesis, the average reduction in pore volume due to compaction accounts for 76% (FN area) and 81% (FS area), while cementation accounts for 18% (FN area) and 12% (FS area). Vertically, 3900 m and 4000 m are the boundaries between the acidic zone and acid-alkaline transition zone of the Huagang Formation in the FN and FS areas, respectively, and the whole Huagang Formation is considered within the meso-diagenetic A2 stage. The pore evolution is closely related to diagenesis. The porosity of the sandstones in the Upper Member of the Huagang Formation in the FN area changes from 37.5% to 10.62%, and the porosity of the sand-stones in the Lower Member of the Huagang Formation in the FS area changes from 36.5% to 8.90%. The results of this study provide a reference for the study of differential diagenetic evolution of sandstones in the Xihu Sag and the exploration of deep high-quality reservoirs. Full article

The Pinghu Oil and Gas Field in the East China Sea Shelf Basin represents a significant offshore hydrocarbon-producing region in East Asia. However, the Paleogene hydrocarbon system in the Pinghu Oil and Gas Field is complex, and the fluid properties, charging stages, and hydrocarbon accumulation process are still unclear. A comprehensive integrated analysis of the hydrocarbon accumulation characteristics, fluid properties, temperature pressure regimes, primary hydrocarbon sources and origins (genesis), charging stages, preservation conditions, and evolutionary history of hydrocarbon accumulation have been studied by utilizing a series of well data, oil and gas geochemical parameters, carbon isotope, and fluid inclusion analyses. Hydrocarbon charging in the Huagang Formation experienced one stage, and the crude oil is characterized as light and conventional, exhibiting low density and viscosity, a low pour point, and low contents of wax, resin, and sulfur. In contrast, the reservoir of the overpressured Pinghu Formation experienced a two-stage hydrocarbon charging process (oil filling and gas filling), exhibiting higher density, viscosity, and wax content compared to the Huagang Formation. The hydrocarbon charging and evolution process of the Pinghu Formation and Huagang Formation in the Pinghu Oil and Gas Field can be summarized in three different stages, including the oil filling period (10–5 Ma), gas filling period (5–2 Ma), and oil and gas adjustment period. The Pinghu Oil and Gas Field, especially in the lower Pinghu Slope Belt (Fangheting Structure), has good potential for further exploration. Full article

In recent years, significant exploration successes and research progress in volcanic hydrocarbon reservoirs across China’s offshore basins have highlighted their importance as key targets for deep hydrocarbon exploration. In the Shimentan Formation of the Xihu Sag, East China Sea Shelf Basin (ECSSB), low-yield gas flows have been encountered through exploratory drilling; however, no major reservoir breakthroughs have yet been achieved. Assessing the large-scale reservoir potential of volcanic sequences in the Shimentan Formation is thus critical for guiding future exploration strategies. Based on previous exploration studies of volcanic reservoirs in other Chinese basins, this study systematically evaluates the hydrocarbon potential of these volcanic units by microscopic thin section identification, major element analysis, integrates drilling data with seismic interpretation techniques—such as coherence cube slicing for identifying volcanic conduits, dip angle analysis for classifying volcanic edifices, and waveform classification for delineating volcanic lithofacies. The main findings are as follows: (1) The Shimentan Formation is primarily composed of intermediate to acidic pyroclastic rocks and lava flows. Volcanic facies are divided into three facies, four subfacies, and six microfacies. Volcanic edifices are categorized into four types: stratified, pseudostratified, pseudostratified-massive, and massive. (2) Extensive pseudostratified volcanic edifices are developed in the Hangzhou Slope Zone, where simple and compound lava flows of effusive facies are widely distributed. (3) Comparative analysis with prolific volcanic reservoirs in the Songliao and Bohai Bay basins indicates that productive reservoirs are typically associated with simple or compound lava flows within pseudostratified edifices. Furthermore, widespread Late Cretaceous rhyolites in adjacent areas of the study region suggest promising potential for rhyolitic reservoir development in the Hangzhou Slope Zone. These results provide a robust geological foundation for Mesozoic volcanic reservoir exploration in the Xihu Sag and offer a methodological framework for evaluating reservoir potential in underexplored volcanic regions. Full article

The tight sandstone reservoirs within the Oligocene Huagang Formation represent one of the most promising exploration targets for future hydrocarbon development in the Xihu Depression of the East China Sea Basin. The reservoir has complex sedimentary and diagenetic processes. In this paper, a variety of methods, such as microscopic image observation, particle size analysis, X-ray diffraction measurement (XRD), heavy minerals, carbon and oxygen isotopes of cement, the homogenization temperature of fluid inclusions, zircon (U-Th)/He isotopes, and high-pressure mercury intrusion (HPMI), are used to analyze the thermal evolution history, diagenetic evolution process, and the causes of differences in diagenetic processes and high-quality reservoirs. This study shows that the provenance of the southern region is derived from western metamorphic rock, while that of the northern region is dominated by northern metamorphic rock, including some eastern volcanic rock. The northern region exhibits a stronger compaction and lower porosity, primarily due to a greater proportion of volcanic rock provenance. Additionally, coarse-grained lithofacies exhibit a higher quartz content and lower proportions of clay minerals and lithic fragment compared to fine-grained lithofacies, consequently demonstrating greater resistance to compaction. The Huagang Formation reservoir has three stages of carbonate cementation, two stages of quartz overgrowth, and two stages of fluid charging. The two stages of fluid charging correspond to two stages of organic acid dissolution. In the northern region, the geothermal gradient is high, and the burial depth is large, so the diagenetic event occurred earlier and is now in the mesodiagenesis B stage, while in the southern region, the geothermal gradient is low, and the burial depth is small and is now in the mesodiagenesis A stage. The southern distributary channel sands and northern high-energy braided channel sands constitute high-quality reservoirs, characterized by a coarse grain size, large pore throats, and minimal cement content. Full article

Recent breakthrough exploration wells in the Huagang Formation in the Y-area of the central anticlinal zone of the Xihu Sag have confirmed the significant exploration potential of structure–lithology complex hydrocarbon reservoirs. However, limited understanding of the provenance system, sedimentary facies, and microfacies has hindered further progress in complex hydrocarbon exploration. Analysis of high-precision stratigraphic sequences and seismic facies data, mudstone core color, grain-size probability cumulative curves, core facies, well logging facies, lithic type, the heavy-mineral ZTR index, and conglomerate combinations in drilling sands reveals characteristics of the source sink system and provenance direction. The Huagang Formation in the Y-area represents an overall continental fluvial delta sedimentary system that evolved from a braided river delta front deposit into a meandering river channel large-scale river deposit. The results indicate that the primary provenance of the Huagang Formation in the Y-area of the Xihu Sag is the long-axis provenance of the Hupi Reef bulge in the northeast, with supplementary input from the short-axis provenance of the western reef bulge. Geochemical analysis of wells F1, F3, and G in the study area suggests that the prevailing sedimentary environment during the period under investigation was characterized by anoxic conditions in nearshore shallow waters. This confirms previous research indicating strong tectonic reversal in the northeast and a small thickness of the central sand body unrelated to the flank slope provenance system. The aforementioned findings deviate from conventional understanding and will serve as a valuable point of reference for future breakthroughs in exploration. Full article

The Central Anticline Belt of the Xihu Sag is one of the structural units with the most abundant natural gas in the East China Sea Shelf Basin. However, there are significant differences among the anticline units in terms of the scale of natural gas enrichment, occurrence horizons, types of gas reservoirs, accumulation processes, and gas-bearing properties of different strata, which influence the optimization of exploration zones and the orientation of exploration in deep-buried areas. This study conducted a comprehensive analysis in terms of the structural evolution, fault activity, hydrocarbon charging stages, and process of hydrocarbon accumulation. It clarifies that (1) the preservation condition is one of the core factors for the differential enrichment of natural gas in the Central Anticline Belt. Under the background of differential compression of the Longjing Movement, late-stage and E-W-trending faults are commonly developed in the anticline cores of the strong compression area in the south, which damage the effectiveness of traps, resulting in a large amount of natural gas escaping and being locally adjusted and accumulated in shallow effective traps. The gas reservoirs show the characteristics of multiple accumulation horizons and a small scale. In the moderately strong compression area in the north, the E-W-trending faults have weak activities and shallow incision horizons. The original gas reservoirs are not damaged, and the structures are fully filled. (2) The coupling between faults and sand bodies determines the degree of oil and gas enrichment. In the weakly compressed area in the west, late-stage E-W-trending faults are not developed, and the preservation conditions are good. The main controlled faults on the flanks of the anticline are highly active, and the coupling degree between faults and sand bodies is good, resulting in a high gas saturation. However, the transport capacity in the anticline cores is relatively poor, with a low gas saturation. (3) The differences in the paleo-structural characteristics affect the degree of oil and gas enrichment. The paleo-structures formed before the Longjing Movement provided favorable conditions for the early convergence of oil and gas. Natural gas has the characteristics of multi-stage charging, and the deep gas reservoirs have higher gas saturation than the shallow ones. On this basis, this study proposed two natural gas accumulation processes developed in the Central Anticline Belt of the Xihu Sag under the background of differential compression. One is where the hydrocarbon convergence occurs first and then oil and gas transport and accumulate into the reservoirs; the other one is where the hydrocarbon convergence and accumulation occur simultaneously, followed by gas adjustment. This paper also concludes three differential accumulation models: the local enrichment and accumulation model of gas in the strongly compressed zone, the integrated enrichment and accumulation model in the medium-strongly compressed zone, and the fault–sand coupling accumulation model in the weakly compressed zone. The results of this research have great significance for the subsequent exploration, hydrocarbon enrichment style analysis, and further strategy in the deep-buried, tight to low-permeable reservoirs in ocean exploration areas. Full article

In post-rift basins, the thickness center, fine-grained deposit center, and subsidence center rarely converge. Clearing the three centers with the thickest center is difficult. In the Huangyan district of Xihu Sag, the East China Sea Shelf Basin, an Oligocene post-rift basin beneath major potential igneous provinces, has inconsistent thickness and composition. Analysis of core samples, drilling, and 3D seismic data corroborated this finding. This means that the formation thickness center does not match the lithology center, which indicates water depth. Gravity and magnetic measurements in the studied region show that significant magmatic activity is responsible for the difference between the center of thickness and the fine-grained deposit. Thermal sinking must be restored to fix this. Therefore, we propose (1) recreating the early Oligocene residual geomorphology in Huangyan using 3D seismic data. (2) Software computing quantitative subsidence. (3) Paleogeomorphology is verified by normal and trace element paleowater depths. (4) Reconstruct the paleogeomorphology and analyze how volcanic activity affected them and the three centers in the basin formed after tectonic plates separated. A shallow water delta and thermal subsidence show that magmatic activity is persistent in the north. With less thermal subsidence and deeper water, the southern area features a shallow lake sedimentary system. The thickness and fine-grained deposition centers were in the north and south, respectively. Geophysical and geological methods were used to reproduce the post-rift paleogeomorphology shaped by magmatic processes. Full article

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. Full article

The Xihu Sag in the East China Sea Basin is located at the edge of the eastern Chinese continent and has great exploration potential. In recent years, the development of low-permeability and tight sandstone gas has become an important area of exploration and development in the Huagang Formation (E3h) of the Xihu Sag. The tight sandstone reservoir in the Xihu Sag is characterized by serious heterogeneity, high water saturation, low resistivity, and a complex gas–water relationship. Because of these characteristics of tight sandstone reservoirs, it is difficult to perform an evaluation of them. In this work, a bimodal Gaussian density function was constructed using the data of high-pressure mercury intrusion (HPMI) and nuclear magnetic resonance (NMR); this approach was used to analyze the pore structure parameters. The reservoirs were divided into four types using the fitting parameter η, and the rock electric parameters that correspond to different pore structures were quite different. When combined with the log response equation of η with acoustic interval transit time (AC), density (DEN), and natural gamma (GR) logging curves, an evaluation method of gas-bearing properties that was based on the characteristics of the pore structure was established. Compared with the water saturation test of the sealing core, it was found that the water saturation calculated by the classification of the pore structure was more accurate than that obtained by the conventional method, and the error was less than 8.35%, which proves that this method is feasible and effective. The findings of this study can help provide a better understanding of the distribution characteristics of gas and water in tight sandstone and provide help for tight gas exploration and development. Full article

The Pingbei area is the main accumulation area of oil and gas in the Xihu Sag. The phase characteristics of oil and gas in this area are complex, and the understanding of their genesis is still unclear. In this paper, based upon discussions of crude oil and natural gas geochemical data, integrated with local geological features, we discuss the sources, migration, and phase state characteristics of oil and gas in the Pingbei area of the Xihu Sag. The study results show that the crude oil and natural gas in the Pingbei area are coal-derived and the oil and gas produced by the humic organic matter during the mature stage. The oil and gas source correlation showed that crude oil and natural gas have good affinity with the Eocene Pinghu Formation (PH) coal-bearing source rocks. Crude oil has the characteristics of near-source accumulation and short-distance migration while natural gas is supplied from a dual source: the coal-derived hydrocarbon rocks of PH in the deep part of the study area, supplemented by the coal-derived hydrocarbon rocks of PH on the bottom of the slope, and adjacent hydrocarbon-bearing sub sag. The distribution characteristics and geochemical migration indices of hydrocarbon show that the oil generated from the hydrocarbon source rocks of PH in the deep Pingbei area mainly migrates vertically along the fault connecting the reservoir and the source rocks to the trap, where it accumulates, while the natural gas exhibits deep and large faults that mainly migrate vertically, supplemented by its lateral migration along the composite transport system composed of faults and sandstone layers in the slope zone. The whole area presents the phase characteristics of “upper oil and lower gas, west oil and east gas”. The mechanisms of produced-exhausted and geochromatographic effects (PGE), as well as evaporative fractionation (EF) and phase-controlled migration fractionation (PMF), result in the obvious discrepancy of hydrocarbon’s properties on the vertical profiles. Full article

Under the conditions of many faults, sandbodies, and hydrocarbon sources on the slopes of faulted basins where structural traps are scarce, only a few sandbodies are capable of forming hydrocarbon pools, while most sandbodies act as aquifers. This situation presents a challenge for predicting favorable hydrocarbon accumulation areas and understanding controlling factors. The Pinghu Formation reservoirs in the Baoyunting nose structure of the Xihu Sag in the East China Sea exemplify this characteristic. Among the 19 small-scale oil and gas reservoirs discovered in this area, 10 are faulted sandbody composite traps and 9 are lithological traps, while the majority of the remaining sand layers, especially the thick layers, act as aquifers, resulting in significantly lower accumulation probabilities compared to the adjacent northern and southern areas. We analyzed the relationship between the sandstone thickness and the amplitude through the 1-D forward modeling of wells and dissected the 3-D seismic event to obtain the planar distribution of a single sandbody. Further comprehensive research on fault sealing and kinetic reservoir formation processes suggests that the gas pool formation in this area is closely related to fault sealing and lateral oil and gas transport. A small fault-to-caprock ratio is beneficial for the sealing of mudstone caprocks, while a large fault-to-sand thickness ratio is beneficial for the lateral sealing of faults and the formation of fault–sand composite pools. The tidal microfacies sandbody has a small scale, poor lateral transport ability, and a low probability of gas reservoir formation. The barrier and delta front sandbodies have a large scale, good lateral transport, and a high probability of reservoir formation. Based on the above methods, favorable pool formation traps were identified in the area, and high-yield gas wells were drilled. Full article

Using different experimental methods, the pore radius ranges vary greatly, and most scholars use a single experiment to study pore structure, which is rarely consistent with reality. Moreover, the numerical models used in different experiments vary and cannot be directly compared. This article uniformly revised all experimental data into a cylinder model. Quantitative analysis of the full-scale pore distribution is established by mercury withdrawal–CT data, and semi-quantitative distribution is obtained by mercury–NMR–cast thin section imaging. In this paper, we introduce the tortuosity index (τ) to convert the CT ball-and-stick model into a cylinder model, and the pore shape factor (η) of the cast is used to convert the plane model into the cylinder model; the mercury withdrawal data is applied to void the influence of narrow throat cavities, and the NMR pore radius distribution is obtained using the mercury-T₂ calibration method. Studies have shown that the thickness of bound water is 0.35~0.4 μm, so the pores with different radius ranges were controlled by different mechanisms in the NMR tests, with pores < 0.35~0.4 μm completely controlled by surface relaxation, including strong bound water and weak bound water; pores in the 0.4~4 μm reange were controlled by surface relaxation; and pores > 10 μm were completely controlled by free relaxation. The surface relaxivity rate of fine sandstone was 18~20 μm/s. The tortuosity index τ was generally 1~7; the larger the value, the more irregular the pores. The pore shape factor η was generally 0.2~0.5; the smaller the value, the more irregular the pores. Mercury withdrawal–CT scan data can quantitatively determine the pore radius distribution curve. The coefficient of the logarithm is positive considering porosity, and the constant is negative considering porosity. Permeability controls the maximum pore radius, with a max pore radius > 100 μm and a permeability > 1 mD. Mercury withdrawal–NMR–cast thin section imaging data can semi-quantitatively establish a pore radius distribution histogram. The histogram represents quasi-normal, stepped, and unimodal data. When 60 μm is the inflection point, if a large proportion of pores measure > 60 μm, good reservoir quality is indicated. If a large proportion of pores measures < 60 μm, the permeability is generally <0.5 mD. Full article

The Xihu sag has two main oil−gas fields: Huagang Gas Field and Pinghu Oil Field. The Huagang formation is the reservoir of the Huagang Gas Field in the Central Tectonic Zone, while the Pinghu formation is the reservoir of the Pinghu Oil Field in the Western Slope Zone. In this paper, which mainly focusses on the Huagang formation, we conducted gas-driven water displacement–magnetic resonance imaging (GWD-MRI) experiments to simulate the charging characteristics of the sandstone migration layer, centrifugal magnetic resonance (Cen-NMR) experiments to simulate the short-term rapid trap charging process, and semi-permeable baffle (SPB) charging experiments to simulate the slow trap accumulation process. The results indicate that a start-up pressure exists for migration layer charging, where the start-up pressure for a core with a permeability of 0.3 mD is about 0.6 MPa. Our experimental simulations confirm that a planar front of changing water saturation exists, which has a width of about 1–1.5 cm. Migration layer charging is mainly influenced by two actions: the drive effect and the carrying effect. The drive effect can reduce the water saturation to 70–80%, while the carrying effect can further reduce the water saturation by 5–10%. The water saturation in the rapid charging scenario is mainly affected by the petrophysical characteristics of the rock: if the porosity is high, the water saturation is low. The water saturation decreases significantly with the increase in centrifugal force when the centrifugal force is small; however, when the centrifugal force is greater than 0.8 MPa, the water saturation decreases slowly. In the slowly charging trap experiment, the water saturation was basically stable at 40–50%, which matched the measured water saturation of the airtight cores well (ranging from 40–55%), and the petrophysical characteristics of the rock did not have a significant effect on the final water saturation. Full article

The optimization of reservoir sweet spots is the key to the efficient exploration and development of low-permeability and tight sandstone gas reservoirs. However, offshore deep, low-permeability and tight sandstone has the characteristics of large burial depth, large diagenesis heterogeneity and prominent importance of diagenetic facies, which make it difficult to predict reservoir sweet spots. This work comprehensively used logging data, core observation, conventional core analysis, thin section, powder particle size analysis, clay X-ray diffraction analysis, cathode luminescence analysis, scanning electron microscopy and energy spectrum analysis and carried out the study of diagenesis, diagenetic facies and reservoir sweet spots of low-permeability and tight sandstone of H3 and H4 (the third and fourth members of Huagang Formation) members in the Jiaxing area of the Xihu Sag. The results show that the H3 and H4 sandstones were divided into five diagenetic facies types, and chlorite-coated facies and dissolution facies were favorable diagenetic facies belts. The H3 member mainly develops chlorite-coated facies, dissolution facies and quartz-cemented facies, whereas the H4 member primarily develops quartz-cemented facies and chlorite-coated facies. The percentages of type I sweet spot, type II₁ sweet spot and type II₂ sweet spot in the H3 reservoir are approximately 21%, 23% and 26%, respectively, whereas the percentages of type I sweet spot, type II₁ sweet spot and type II₂ sweet spot in the H4 reservoir are about 16%, 15% and 16%, respectively. The distribution rules of reservoir sweet spots were investigated. Type I sweet spot was mainly developed in the areas of chlorite-coated facies and dissolution facies of medium sandstone and coarse sandstone in the channel bar and braided channel sedimentary microfacies. Type II sweet spot was primarily distributed in the areas of quartz-cemented facies, chlorite-coated facies and minor dissolution facies of medium sandstone, fine sandstone and sandy conglomerate in the braided channel, subaqueous distributary channel and channel bar sedimentary microfacies. Type III sweet spot was chiefly developed in the areas of tightly compacted facies, calcite-cemented facies and quartz-cemented facies of fine sandstone, siltstone and a small amount of sandy conglomerate in the subaqueous distributary channel sedimentary microfacies. Full article

Various experiments, including routine petrophysical measurements, thin section and scanning electronic microscope (SEM), high-pressure mercury intrusion (HPMI), and nuclear magnetic resonance (NMR), were performed to characterize the microscopic pore structure of tight sandstone in the Huagang Formation (E₃h), Xihu Sag, East China Sea Basin, China. Specifically, NMR was used to investigate the dynamic variation of fractal dimensions during centrifugation, and the comparison of HPMI and NMR were used to clarify the difference of fractal dimensions. The results showed that there were four types of pores observed in thin section and SEM images: primary intergranular pores, intergranular dissolution pores, intragranular dissolution pores, and micropores within clay aggregates. The geometric shape and pore size of different pore types showed huge differences, indicating the formation of complex and diverse pore structures in the E₃h formation. The flow capability of the reservoir was dominated by large pores, while the storage capacity was determined by small pores. The dynamic variation of fractal dimensions calculated by NMR data showed the water residing in the pore structure with low fractal dimensions was removed preferentially, and the pore structure of the resided water was always more complicated than the pore structure of removed water, which indicated the flow capability of the reservoir was affected by the complexity of the pore structure. Based on the comparison of the fractal dimension data from HPMI and NMR, it was found that the variation trends of the fractal dimensions were consistent, as the radius of the pore throat increased, the fractal dimensions increased, and the pore structure became more complicated. Both fractal dimensions of macropores (D_mac) and movable-fluid pores (D_mov) can reflect the flow capability of reservoir effectively, but the correlations between fractal dimensions from HMPI and NMR were poor, which could be due to the different working mechanism in these methods. Full article