Search Results (378)

Turbidite sandstones of the Chang 6 member and delta-front sandstones of the Chang 8 member in the Yuele Block, southwestern Yishan Slope, Ordos Basin, serve as the primary tight oil reservoirs. In this study, a total of 243 continuous core samples from multiple wells were collected for integrated analyses, including cast thin-section observation, scanning electron microscopy (SEM), X-ray diffraction (XRD) of clay minerals, routine core physical property measurements and mercury intrusion porosimetry (MIP), to systematically compare sedimentary–diagenetic disparities between semi-deep lacustrine turbidites (Chang 6) and delta-front sandstones (Chang 8). Measured data indicate that the two intervals have similar average porosities of 9.27% and 9.88%, while their respective geometric mean permeabilities differ markedly, with values of only 0.142 × 10⁻³ μm² for Chang 6 and 0.260 × 10⁻³ μm² for Chang 8. Micro-pore-throat size and connectivity dominate reservoir fluid flow capacity, and total porosity alone cannot objectively evaluate reservoir quality. Delta-front sandstones of the Chang 8 member are supplied by a proximal magmatic-rich provenance from the southwest, and widespread grain-coating chlorite forms during early diagenesis, effectively mitigating compaction damage and inhibiting quartz overgrowth, leading to well-preserved primary pores. As mixed-provenance deposits lacking protective chlorite rims, Chang 6 turbidites experience more intensive compaction, and abundant fibrous illite and carbonate cements precipitate in the subsequent diagenetic stage to fill and separate pore throats, forming an isolated micropore network. Quantitative comparison with baseline parameters of the Longdong region reveals that the Yuele Block is located closer to the southwestern sediment source, resulting in higher contents of magmatic lithics and chlorite in Chang 8 as well as elevated illite concentrations in Chang 6 relative to regional averages, which verifies that source-to-sink transport distance regulates reservoir quality by driving the differentiation of clay mineral assemblages. A complete quantitative coupling sequence of “provenance supply–authigenic clay mineral-pore evolution” is defined herein, and two distinct sedimentary–diagenetic evolutionary routes are classified: high-quality delta-front reservoirs protected by grain-coating chlorite, and low-quality turbidite reservoirs blocked by illite–carbonate cements. This research refines the diagenetic differentiation rules for continental tight sandstones with diverse sedimentary origins in the Ordos Basin and provides quantitative mineralogical criteria for identifying tight oil sweet spots in proximal provenance blocks. Full article

The traditional geological view holds that overpressure resists mechanical compaction during sedimentary burial, keeping effective stress approximately constant and thereby passively preserving porosity and permeability in deep reservoirs. However, this assumption has relied predominantly on theoretical inference and struggles to explain a widespread geomechanical paradox: in many overpressured formations, the magnitude of permeability enhancement significantly outpaces the degree of porosity preservation. To decode this paradox, we conducted a fundamental proof-of-concept study utilizing high-pressure percolation coupled with in situ micro-CT and fractal analysis to dynamically simulate the effects of overpressure on porous sandstone under constant mean effective stress. The results reveal a counterintuitive phenomenon: while the global porosity remained fundamentally stable, the absolute permeability demonstrated a significant ~8% enhancement. Microstructural analysis indicates that this enhancement is driven by localized hydraulic wedging and the reactivation of sub-resolution throats acting as topological bridges. This active topological optimization physically and mathematically manifests as: (1) the massive reconnection of macroscopic isolated pores; (2) an enhanced space-filling capacity of the flow network, evidenced by an increased coordination number and 3D pore space fractal dimension (D_f); and (3) the structural straightening of fluid pathways, rigorously quantified by a reduction in flow tortuosity and tortuosity fractal dimension (D_T). These findings, derived from a single well-characterized sandstone sample, demonstrate that overpressure-driven permeability enhancement is a physically plausible mechanism in tight sandstones. This discovery offers a candidate physical explanation for the anomalously high permeability observed in certain deep overpressured reservoirs. However, the generalizability of these results to reservoirs with differing porosities, mineralogies, and diagenetic histories remains to be evaluated through multi-sample studies. Full article

The genesis of authigenic clay minerals in tight sandstones fundamentally controls reservoir quality and micro-pore evolution. This study investigates the differential formation mechanisms of authigenic chlorite and kaolinite and their modulating effects on pore systems in the Chang-8 Member tight sandstones, Ordos Basin. Thin-section petrography, X-ray diffraction, scanning electron microscopy, and high-pressure mercury injection were utilized to quantify mineralogical and petrophysical characteristics. Results show chlorite (averaging 4.8%) and kaolinite (averaging 1.6%) are the dominant authigenic clay minerals with distinct spatiotemporal distributions. Chlorite nucleated as pore linings during early diagenesis under alkaline, oligohaline to mesohaline conditions driven by volcanic material hydration. Conversely, kaolinite precipitated as pore-filling during mid-to-late diagenesis (80–120 °C), driven by organic acid pulses from underlying source rocks causing feldspar dissolution. We conclude that early chlorite linings constructively preserve primary porosity by mechanically resisting compaction and chemically inhibiting quartz cementation, despite narrowing pore throats. Meanwhile, kaolinite acts as a pore-type modulator, restructuring macro-pores into micro-intercrystalline pores, which significantly impairs permeability only when its proportion crosses a critical threshold. The diagenetic fluid transition from alkaline to acidic ultimately dictates this mineralogical succession and subsequent reservoir heterogeneity. Full article

The Taiyuan Formation in the Daniudi Gas Field of the Ordos Basin was formed in a tidal flat mixed sedimentary environment. It represents a typical tight sandstone reservoir with significant exploration and development potential. However, current research on the reservoir evaluation of the Taiyuan Formation is relatively limited. This study focuses on the Taiyuan Formation in the Da 17 well area of the Daniudi Gas Field, employing methods such as petrographic analysis, X-ray diffraction, porosity/permeability measurements, mercury injection capillary pressure, and scanning electron microscopy to conduct a detailed investigation of sand dams in the tidal flat environment. By combining reservoir characteristics with detailed sedimentary microfacies classification, and on the basis of discussing the relationship between reservoir heterogeneity and natural gas production capacity, this study performs reservoir classification and evaluation. The characteristics and distribution patterns of relatively high-quality reservoirs are clarified. Through the analysis of lithological characteristics and sedimentary markers, it is determined that the Taiyuan Formation in the Da 17 well area represents a typical tidal flat sedimentary environment, with sand dams serving as the primary development sites for sand bodies. The Taiyuan Formation sandstone is mainly composed of medium- to fine-grained lithic quartz sandstone and lithic sandstone. The predominant pore types include primary pores, secondary pores, and fractures. The porosity of the reservoir ranges from 0.3% to 14.2%, while the permeability varies from 0.006 to 29.7 × 10⁻³ μm², classifying it as a typical tight sandstone reservoir. Using the gas testing method, the lower limit of the physical properties of the Taiyuan Formation reservoir has been determined to be 3.9%. Considering the heterogeneity characteristics and productivity information of the sand layers, the reservoirs of the Taiyuan Formation are classified into three types: Type I reservoirs are predominantly composed of pebbly coarse sandstone and coarse sandstone, with porosity > 10%, permeability > 0.8 × 10⁻³ μm², mainly developed in the center of sand dams, exhibiting medium heterogeneity; Type II reservoirs consist of coarse sandstone with porosity ranging from 4% to 10% and permeability from 0.1 to 0.8 × 10⁻³ μm², with the main body of the sand dams belonging to this reservoir type, also showing medium heterogeneity; Type III reservoirs are composed of medium to fine sandstone, with porosity < 4% and permeability < 0.1 × 10⁻³ μm², mainly developed at the edges of sand dams, exhibiting strong heterogeneity. By integrating the distribution characteristics of sedimentary facies sand bodies, the planar distribution characteristics of the various reservoir types are clarified. Full article

Direct core-scale evidence remains insufficient for evaluating hydraulic fracture–natural fracture coupling and stimulation effectiveness in tight sandstone oil reservoirs. In this study, post-fracturing full-diameter cores from the Chang 8₁ tight oil reservoir in the Xi 119 well block, Xifeng Oilfield, Ordos Basin, were investigated using core observation, computed tomography (CT) scanning, fracture-source evidence and three-dimensional fracture-network reconstruction. A total of 87.56 m of core from 11 core runs was scanned at a voxel size of 50.62 μm. Natural fractures, hydraulic fractures and engineering-induced fractures were identified and distinguished based on fracture-surface features, CT expression, spatial continuity, proppant/tracer evidence and their relationship with bedding and lithological boundaries. The results show that lithological structure exerts a first-order control on hydraulic-fracture surface morphology. Massive sandstone tends to generate straight and continuous high-conductivity main fractures, argillaceous laminated sandstone promotes bedding-controlled discontinuous fractures with limited connectivity, and cross-bedded sandstone favors fracture diversion, branching and natural-fracture activation. Based on fracture assemblage, spatial connectivity and seepage behavior, three hydraulic fracture–natural fracture coupling types were classified: single hydraulic-fracture type, single main fracture–diverted fracture–natural fracture type, and dual main fractures–diverted fractures–natural fractures type. Their equivalent permeability increases stepwise from 155 mD to 345 mD and 586 mD, respectively, indicating a positive relationship between fracture-network complexity and seepage capacity. A CT-derived stimulation-effect evaluation framework was further established by integrating pore–fracture structural modification, fracture volume increase, aperture improvement and seepage-capacity enhancement. The dual main fractures–diverted fractures–natural fractures type shows the strongest stimulation response, with the largest reduction in small-aperture pore/fracture proportion, the greatest lamina-fracture aperture enlargement and the most significant permeability improvement. These results provide direct core-scale evidence for understanding fracture-network formation in continental tight sandstone reservoirs and support more targeted hydraulic-fracturing design and stimulation-effect evaluation. Full article

Fractal analysis has been widely applied to characterize the complexity of pore systems in tight sandstone reservoirs. However, fractal parameters derived from different experimental techniques are frequently interpreted without sufficient consideration of their distinct physical meanings. In this study, tight sandstones from the Fuyu Formation in the Songliao Basin were investigated using cast thin sections, scanning electron microscopy, high–pressure mercury intrusion porosimetry, and nuclear magnetic resonance. The objective was to establish a comparative interpretation framework that distinguishes capillary–pressure–controlled geometric fractal dimensions from NMR–derived apparent relaxation–response fractal parameters (ARR fractal parameters). The pore–throat system is dominated by medium– to fine–sized throats, with the dominant pore–throat radii concentrated between 0.05 and 0.15 μm. Mercury–intrusion–derived fractal parameters primarily characterize the geometric heterogeneity of relatively large and fine pore–throat systems, whereas NMR–derived parameters mainly reflect the apparent relaxation response associated with pore–scale fluid occurrence rather than strict geometric complexity. In the present MICP–NMR subset, comparative regression trends indicate that the geometric fractal parameter representing fine pore throats is more responsive to median pore–throat radius and movable–fluid saturation, whereas the NMR–derived apparent relaxation–response parameter associated with longer relaxation times shows a relatively closer relationship with log–transformed permeability. These relationships should be regarded as exploratory response trends rather than universal predictive models. These findings demonstrate that the two types of fractal parameters provide complementary rather than interchangeable information for reservoir evaluation. The proposed comparative framework offers a physically constrained basis for integrating pore–throat geometry, relaxation response, fluid occurrence, and seepage properties in the characterization of tight sandstone reservoirs. Full article

Authigenic chlorite is a common clay mineral in tight sandstone reservoirs, where its mode of occurrence strongly influences pore preservation, pore-throat architecture, and reservoir-quality evolution. We integrated petrographic observations of cast thin sections, scanning electron microscopy, X-ray diffraction, electron-probe microanalysis, and core petrophysical measurements to characterize the petrology, chlorite microfabrics, precursor materials, and reservoir properties of the Qian-5 sandstones in the Jiaxian area, Ordos Basin. The sandstones are dominated by lithic arkose and feldspathic litharenite. Volcanic and other unstable lithic fragments, feldspar, early Fe-rich clay films, and clay-mineral precursors supplied material for authigenic chlorite. Three modes of occurrence were identified: grain-coating (Chl-1), pore-lining (Chl-2), and pore-filling (Chl-3) chlorite. Their development records progressive transformation of early Fe-rich clay films, dissolution of unstable detrital components, clay-mineral reactions, and changes in diagenetic-fluid chemistry. The reservoirs have porosities of 5.5–17.8% (mean, 10.3%) and permeabilities of 0.5–11.3 mD (mean, 7.48 mD). Early grain coatings inhibited quartz overgrowth and favored preservation of intergranular pores, whereas later pore-lining and pore-filling chlorite narrowed pore throats, increased tortuosity, and reduced effective pore volume. A statistically supported quadratic relationship between total chlorite content and porosity indicates that bulk chlorite abundance does not exert a simple monotonic control on reservoir quality. Combined with petrographic observations, the results further show that the reservoir effect of chlorite varies with its mode of occurrence and degree of pore occupancy. These findings provide a diagenetic framework for predicting comparatively high-quality intervals and evaluating reservoir heterogeneity in the Qian-5 Member. Full article

Permeability stress sensitivity influences productivity evaluation and stimulation design in tight sandstone reservoirs. Lithic-rich tight sandstone cores from the Baijiantan Formation in the Junggar Basin were investigated using X-ray diffraction and staged effective-stress permeability tests at 25 °C. The plastic mineral index (PM), defined as the summed whole-rock contents of clay minerals, calcite, siderite, and pyrite, was used to classify the samples. Weakly plastic samples S1–S4 had PM values of 28.2–33.5% (PM < 35%), whereas strongly plastic samples S5–S7 had PM values of 37.9–48.3% (PM ≥ 35%); 35% was adopted as a dataset-specific engineering threshold. A complete coupled elastoplastic damage model was developed by incorporating plastic damage and elastic-modulus degradation into the traditional exponential model. The sum of squared errors (SSE) between the measured and predicted normalized permeability values was used to assess model fit; lower SSE values indicate better agreement. Weakly plastic samples were described by the traditional exponential model, with SSE values ranging from 6.0 × 10⁻⁵ to 1.39 × 10⁻³. Strongly plastic samples exhibited pronounced nonlinear permeability decline at effective-stress increments of 10–20 MPa. Across the full 0–20 MPa dataset, the coupled model yielded SSE values ranging from 0.00309 to 0.00498 and lower prediction errors than the traditional exponential model. Sensitivity analysis showed that initial fracture compressibility dominated the overall decline, whereas characteristic plastic strain and damage evolution rate mainly controlled nonlinear decline at effective-stress increments of 10–20 MPa. These results show that mineralogical plasticity classification can guide permeability-model selection for tight sandstones. Full article

Exploration of ultra-deep tight sandstones in the Silurian Lower Kepingtage Formation, Tarim Basin, is hindered by low success rates. Here, we integrated 3D seismic, core, and petrographic data to investigate reservoir characteristics and fault controls on hydrocarbon accumulation. The formation was characterized by low porosity (3–9%) and permeability (0.01–1.1 mD), with residual intergranular and dissolution pores as primary storage. Strike–slip faults exhibited distinct Riedel shear segmentation—extensional, translational, and compressional—resulting in variable vertical connectivity. Comparative analysis of Wells W3 and W5 revealed that reservoir physical properties, rather than structural location or fault proximity, dominate accumulation outcomes. Specifically, Well W5 achieved high production on a slope due to superior reservoir quality, whereas structurally high Well W3 failed due to poor physical properties. We propose a paradigm shift from targeting “structural highs” to identifying “high-quality sandy bodies” at the intersection of fault conduits and favorable lithologies. This study provides a robust theoretical basis for ultra-deep tight oil and gas exploration. Full article

Retained water associated with water-locking can restrict gas production in heterogeneous tight sandstones, and the activity and phase stability of many surfactant treatments are reduced under high-temperature, high-salinity (HTHS) conditions. In this study, a composite surfactant formulation, CSF-1, designed to lower gas–brine capillary resistance and adjust sandstone wettability under representative reservoir constraints, is reported. Its performance was evaluated using thermal aging, surface tension and contact angle measurements, geochemical compatibility tests, laser diffraction, SEM/EDS, and core flooding combined with stagewise low-field nuclear magnetic resonance (LF-NMR). CSF-1 remained macroscopically homogeneous after aging at 170 °C in 188.314 g/L hypersaline brine and retained low gas–brine surface tension when measured at 25 °C after aging. In core flooding tests, CSF-1 increased the apparent gas permeability from 0.203 to 0.388 mD relative to the SFW-saturated water-locked state, corresponding to a 91.1% improvement. One- and two-dimensional NMR measurements provided comparative relaxation domain evidence that CSF-1 promoted the removal and redistribution of relatively mobile and weakly restricted fluid signals and reduced residual signal clustering. The shortest T₂ relaxation domains were less affected. The absence of replicate core flooding and associated LF-NMR runs, together with the non-equivalent Ref-S comparison, precludes a statistically rigorous cross-agent performance ranking. These results support the laboratory water-locking mitigation potential under the tested conditions, without implying calibrated pore-size-resolved removal or field-scale confirmation. Full article

Accurately predicting the production dynamics of multi-stage fractured horizontal wells in high-water-cut tight gas reservoirs remains challenging due to complex nonlinear flow regimes. This research aims to quantify dynamic threshold pressure gradients (TPGs) and their impact on well performance. A high-temperature, high-pressure flow testing system was utilized to measure dynamic TPG under varying water saturations in ultra-low-permeability cores. A dynamic mathematical model was established to characterize the exponential evolution of TPG. Furthermore, a comprehensive flow model was constructed using a coupled dual continuum–discrete fracture model. An entirely implicit numerical model utilizing a non-structured 3D tetrahedral mesh and a control volume finite element method enabled accurate numerical solutions. Key parameters such as water saturation, stress sensitivity, and fracture spatial asymmetry were systematically analyzed. Results: The threshold pressure gradient induces distinct dynamic boundary characteristics in pressure propagation, significantly reducing the wave propagation range compared to conventional models, with pressure drops concentrated near hydraulic fractures. Lower permeability (below 0.05 mD) and higher water saturation exponentially intensify the TPG amplification effect (exceeding 0.12 MPa/m), causing substantial reductions in both daily and cumulative gas production. The established simulation framework accurately captures the non-Darcy flow dynamics of fractured horizontal wells in high-water-cut tight gas reservoirs. It provides a reliable theoretical basis and computational tool for optimizing efficient gas field development. Full article

This study focuses on the Chang 8 Member tight sandstone reservoir in the Xifeng Oilfield. Integrated approaches including 3D reconstruction of CT digital cores, seepage simulation, and multi-parameter coupling analysis were employed to systematically classify lamina types, quantitatively characterize lamina-associated fractures, and elucidate the pore–lamina fracture coupling seepage mechanisms. The results show that laminae in the study area can be categorized into three types: banded, inclined, and cross-laminated. Lamina-associated fractures are dominated by bedding-parallel fractures, with a small number of cross-bedding fractures having developed in cross-laminated intervals. The development of lamina-associated fractures is jointly controlled by sedimentary heterogeneity and mechanical differences between interlaminar layers. A significant positive correlation exists between the volume proportion of interlaminar layers and fracture porosity (R² = 0.8913). Cross-laminated intervals exhibit the optimal fracture parameters, with fracture porosity reaching up to 3.6% and maximum fracture volume exceeding 3500 mm³, facilitating the formation of three-dimensional interconnected fracture networks. Distinct pore–lamina fracture coupling patterns are observed in different lamina types: independent development with weak coupling in banded laminae, segmented synergy with heterogeneous coupling in inclined laminae, and strong synergy with network coupling in cross-laminated intervals. In cross-laminated sections, matrix porosity and fracture porosity evolve synchronously, yielding the highest permeability (up to 7.3 mD) and superior storage–permeability performance. Seepage simulations confirm that permeability in tight reservoirs is not directly controlled by matrix porosity; instead, lamina-associated fractures act as the dominant fluid migration pathways. Cross-laminated fractures form multi-directional high-efficiency seepage networks, while banded and inclined laminae exhibit unidirectional linear seepage and segmented dominant channeling characteristics, respectively. These findings provide critical geological insights for sweet spot evaluation, horizontal well trajectory optimization, and hydraulic fracturing design in tight oil reservoirs. Full article

Spontaneous imbibition plays a critical role in enhancing oil recovery. It also helps optimize fracturing fluid design in tight oil reservoirs. Conventional evaluation methods mainly rely on nuclear magnetic resonance (NMR) experiments on intact core samples. These methods can adequately characterize matrix imbibition behavior. However, they generally neglect the presence of artificial fractures. This limits their applicability for guiding hydraulic fracturing optimization in field development. To address this gap, this study introduces artificial fractures into tight sandstone cores from the Sichuan Basin. It integrates scanning electron microscopy (SEM) with online NMR technology. The imbibition performance of an oil-displacement slickwater system was systematically evaluated. The evaluation considered varying agent concentrations, injection rates, and initial oil saturation conditions. The results demonstrate that using a high-concentration oil-displacement fracturing fluid significantly enhances imbibition efficiency. For example, slickwater containing 0.3% oil-displacement agent increased oil recovery by 12.9%. This was compared with slickwater containing 0.1% agent. The high-concentration fluid also substantially improved oil mobilization from small pores. Furthermore, increasing the injection rate proved particularly beneficial for oil recovery across the micropore to mesopore range. The most pronounced improvement was observed in the micropore range. Initial oil saturation serves as another primary controlling factor for imbibition efficiency. As oil saturation increases, imbibition efficiency improves markedly. The optimized slickwater system developed in this study has been successfully applied in Well NC002. It achieved a tested oil production rate of 32 tonnes per day. This field application validates the effectiveness of the proposed approach. It also provides practical technical support for the efficient development of tight oil resources in the Sichuan Basin. Full article

The quantitative characterization of microscopic pore structure has long been a challenge in reservoir evaluation for igneous reservoirs, owing to their pronounced heterogeneity and complex pore geometry. In this study, thin-section casting, X-ray diffraction, high-pressure mercury intrusion, nuclear magnetic resonance, and fractal theory were employed to investigate the reservoir-space types, pore-structure characteristics, and fractal features of the igneous rocks both quantitatively and qualitatively. The relationships among reservoir petrophysical properties, pore structure, movable-fluid saturation, and fractal dimension were examined. The results indicate that the reservoirs in the study area are characterized by medium-to-low porosity and medium-to-low permeability, with mean values of 6.57% and 2.06 mD, respectively; the storage performance of andesite was found to exceed that of tuff. Based on the morphology of the mercury intrusion curves and the petrophysical parameters, the reservoirs were classified into three categories. From Class I to Class III, the displacement pressure increased progressively, the movable-fluid saturation declined from 9.65% to 8.54%, and the heterogeneity was markedly enhanced. The fractal analysis revealed that the reservoirs exhibit distinct piecewise fractal behavior with a well-defined inflection point, allowing two fractal intervals to be distinguished: large pore-throats (D₁) and small pore-throats (D₂). The mean total fractal dimension was 2.8996, and the large pore-throat fractal dimension (mean = 2.9607) exceeded that of the small pore-throats (mean = 2.3863), indicating that large pore-throats serve not only as the principal contributor to reservoir space but also as the dominant control on heterogeneity. Correlation analysis demonstrated that D₁ is significantly negatively correlated with both porosity and permeability, making it a key indicator for evaluating reservoir flow capacity, whereas D₂ is positively correlated with petrophysical properties, reflecting the role of fine throats in improving the connectivity of isolated pores. Notably, the large-pore-throat fractal dimension (D₁) of these igneous reservoirs generally exceeds that of tight sandstone, whereas the small-pore-throat fractal dimension (D₂) is positively correlated with petrophysical properties rather than negatively, in contrast to sandstone reservoirs; this indicates that the pore-structure behavior of igneous reservoirs is distinct from that of conventional clastic reservoirs. This study offers a new perspective on the quantitative characterization of pore structure in igneous reservoirs and provides a scientific basis for reservoir evaluation and exploration-and-development efforts in the study area. Full article

The Shaximiao Formation in the Sichuan Basin possesses favorable exploration potential for unconventional oil and gas, whereas systematic studies on the genetic mechanism of its tight sandstone reservoirs remain insufficient. In this study, tight sandstones of the study area were comprehensively investigated through multiple analytical methods, including thin section observation, scanning electron microscopy, cathodoluminescence, electron probe microanalysis, fluid inclusion testing, and reservoir physical property measurement. The Shaximiao Formation belongs to typical low-permeability tight reservoirs, which are predominantly composed of lithic arkose, followed by feldspathic litharenite and arkose. A variety of authigenic minerals are widely developed in the reservoirs, including laumontite, calcite, quartz overgrowth, feldspar overgrowth, and clay minerals. The main reservoir spaces consist of primary pores, feldspar dissolution pores, and laumontite dissolution pores. The reservoirs have reached middle diagenetic stage A. A full set of diagenetic events can be identified in the study interval. These processes consist of gypsum cementation, chlorite cementation, feldspar dissolution, quartz overgrowth, kaolinite precipitation, laumontite cementation and dissolution, carbonate cementation, and pyrite cementation. Synthetic analysis of microscopic inclusion occurrences, homogenization temperature, and salinity data reveals that the Shaximiao Formation experienced three successive charging episodes of three different fluid endmembers, namely indigenous formation brine, organic acid fluid, and low-salinity surface-derived fluid. These multiphase mixed fluids sequentially altered authigenic minerals and pore spaces under variable open–closed diagenetic systems. The diagenetic system evolved progressively from an early closed environment dominated by laumontite precipitation to a middle–late semi-open-to-open environment dominated by calcite and siliceous cementation. Differential fluid migration controls diagenetic processes and the spatial distribution of cements, which fundamentally accounts for the strong heterogeneity of the reservoirs. Three types of diagenetic environments are classified in the study area, namely compaction-dominated, cementation-dominated, and dissolution-dominated environments, which jointly control the diagenetic assemblages and physical property evolution of the reservoirs. Compaction acts as the primary pore-reducing factor, causing a total porosity loss of 23.34%. Dissolution of feldspar and laumontite serves as the major pore-enhancing process, increasing the porosity by 5.26% and 4.32%, respectively. The mudstone and carbonate rock fragments in western Sichuan provide essential materials for calcite cementation, while intermediate-acid pyroclastics and plagioclase albitization collectively promote laumontite enrichment. The infiltration of meteoric freshwater and the upward migration of organic acids along faults induce feldspar dissolution, further resulting in the formation of kaolinite and quartz overgrowths. The brackish diagenetic environment under arid climatic conditions facilitates the development of early gypsum, which is finally transformed into anhydrite through burial dehydration. Full article