Search Results (89)

The Tianfu Gas Field in the Sichuan Basin is a core block for the large-scale, economic development of Jurassic tight gas in China. The first sub-member of the first member of the Shaximiao Formation in the Zhongjiang Block hosts typical low-porosity and low-permeability tight sandstone reservoirs. Based on detailed field geological surveys and core observations, this study employed multiple technical methods, including cast thin sections, scanning electron microscopy, computed tomography (CT) scanning, and nuclear magnetic resonance (NMR) to investigate sedimentary microfacies’ characteristics, analyze key reservoir properties (e.g., reservoir space types and pore structure), and clarify the main controlling factors of reservoir development. The results indicate the following: (1) The sedimentary period of the first sub-member of the first member of the Shaximiao formation (Es₁¹) was controlled by a subtropical humid climate, with widespread gray mudstones and bedding-parallel plant fossil fragments. The main sedimentary environment was a shallow-water delta front, where the underwater distributary channel microfacies was the dominant facies belt. (2) Reservoir lithology is dominated by lithic arkose and feldspathic litharenite, with low compositional and structural maturity. Residual primary intergranular pores are the dominant reservoir space type, followed by intragranular dissolved pores in feldspar and lithic fragments. (3) The pore structure is characterized by a small pore-throat radius, poor sorting, and strong heterogeneity. Reservoirs can be subdivided into three categories, with Types II and III being the main types developed in this block. (4) Underwater distributary channels of the shallow-water delta are the main occurrence of reservoir sand bodies. During the burial diagenetic stage, calcite and laumontite cementation and filling led to reservoir densification. Meanwhile, early-formed chlorite rim cement effectively protected primary pores by inhibiting grain compaction and quartz overgrowth. Superimposed with the dissolution and alteration of feldspar, lithic fragments, and other components by late acidic fluids, effective pores were further expanded. The synergistic coupling of these sand-controlling factors and the “densification–protection–alteration” diagenetic process jointly constitutes the formation mechanism of high-quality reservoirs. This mechanism can provide a reliable theoretical basis for the accurate prediction of reservoir “sweet spots” and the optimal selection of horizontal well targets in the Zhongjiang Block of the Tianfu Gas Field. Full article

Alluvial plains in the marginal zone of the monsoon system are sensitive to the climate–hydrology interaction. However, long term, high-resolution sedimentary records remain scarce in the Songnen Plain of Northeast China. This limited our understanding of the paleoclimate–paleohydrology coupling evolution over glacial–interglacial cycles. A 50.6 m continuous core was retrieved from the western Songnen Plain. The age–depth model and wavelet transform spectrum showed sedimentary continuity from ~885 ka B.P. (the late Early Pleistocene) to ~6 ka B.P. (the early Holocene), with no major hiatuses exceeding orbital resolution. Grain size analyses revealed 18 microfacies, which were synthesized into two major evolutionary cycles: a fan-delta front cycle (dominated by subaqueous mouth bars and distributary channels) and a fan-delta plain cycle (characterized by intertributary bays, floodplain lakes/swamps, and crevasse splays). The absence of pro-delta facies and the sediment succession record the oscillatory shrinkage of the Songnen paleolake. The pulsed enhancements of hydrodynamic energy, marked by grain size coarsening, coincide with major glacial–interglacial transitions (MIS 20/19, 18/17, 16/15, 14/13, 8/7, 6/5, 4/3, and 2/1), whereas fining grain sizes dominate warm interglacial periods (MIS 11, 9, 7, 5, 3, 1). These patterns are sensitive response of the alluvial plain to orbital-scale climate change. Cold–arid glacial background promoted vegetation loss and hydrological instability, and warm–humid interglacial background favored low-energy hydrological condition. This study demonstrates that the regional alluvial evolution was primarily controlled by global ice-volume fluctuations through variability of the East Asian summer monsoon. This study provides a reference for the muti-scale climate–hydrology coupling mechanism study in the northern marginal zone of EASM and highlights the importance of alluvial sediment succession in paleo-research. Full article

The application of multi-cycle steam stimulation in heavy oil reservoirs frequently alters reservoir properties, influencing the effectiveness of the stimulation and subsequent development strategies. The inherent heterogeneity of strata, characterized by distinct sedimentary facies rhythms, leads to differential patterns of property evolution. Therefore, understanding facies-controlled property variations during steam stimulation is essential for optimizing recovery strategies. This study integrates 1D core experiments with 3D geological modeling to dynamically simulate the stimulation process, enabling a comprehensive multi-scale analysis. The results show the following: (1) Both sedimentary rhythms exhibit progressive increases in porosity and permeability with successive cycles until reaching stabilization plateaus, with the uniform rhythm stabilizing earlier than the coarsening-upward rhythm. (2) 3D simulations reveal a predominant increasing trend in porosity and permeability after multi-cycle stimulation, albeit with localized reduction zones. (3) Multi-scale analysis indicates that, during the early stage (cycles 1–9), the underwater distributary channel microfacies undergoes more rapid property changes and achieves a greater cumulative increase in porosity and permeability. Conversely, during the later stage (cycles 10–30), the mouth bar microfacies demonstrates faster property alterations and a larger cumulative enhancement. This facies-specific, time-dependent understanding provides critical insights for tailoring steam stimulation strategies in heterogeneous heavy oil reservoirs. Full article

Despite the promising exploration potential of the tight bioclastic limestone in the Carboniferous Shiqiantan Formation (Shiqiantan Sag, Junggar Basin), its reservoir characteristics remain poorly constrained. In particular, the macro and microscopic features and the key factors controlling reservoir development are still not well understood. We combined core observation, cast thin-section analysis, scanning electron microscopy (SEM), X-ray diffraction (XRD), high-pressure mercury intrusion, nitrogen adsorption, and nuclear magnetic resonance (NMR) to systematically characterize the Carboniferous bioclastic limestone reservoirs and identify the factors controlling their development in the Shiqiantan Sag. This study develops a multi-scale quantitative framework that integrates mercury intrusion–withdrawal behavior, nitrogen adsorption, and NMR T₂ spectra to constrain pore connectivity and the contribution of microfractures in tight carbonate reservoirs, providing a transferable approach for reservoir evaluation beyond the study area. The results categorize three rock microfacies in the study area: Bioclastic micrite, Micritic bioclastic limestone, and Sparry Bioclastic Limestone. The reservoir space is predominantly composed of secondary pores, including intragranular dissolution pores, intercrystalline clay pores, and microfractures. The pore structures exhibit a marked contrast across the lithofacies: the sparry bioclastic limestone develops the most optimal pore-fracture composite system, The pore structures exhibit a marked contrast across the lithofacies, directly correlating with hydrocarbon accumulation. Specifically, the sparry bioclastic limestone develops a pore-fracture composite system characterized by 25–100 nm pore throats, corresponding to the primary oil-bearing intervals observed in drilling. In contrast, the bioclastic micrite limestone and micritic bioclastic limestone, despite exhibiting localized nanoscale pores, lack effective connectivity (pore throats < 25 nm) and predominantly act as tight, dry layers with poor or no oil and gas shows, which endow them with the anomalous characteristic of relatively low porosity yet high permeability. This study reveals an integrated control on the development of tight bioclastic limestone reservoirs, in which sedimentary microenvironment and paleogeomorphology jointly determine the initial reservoir framework, while subsequent structural fractures and associated diagenetic dissolution play a critical role in modifying pore structures and enhancing reservoir quality. Sedimentary microfacies distribution, controlled by paleogeomorphologic variations, dictated the initial reservoir fabric. Subsequently, fracture systems generated by tectonic uplift, coupled with dissolution from meteoric freshwater leaching and organic acids, facilitated the development of secondary pores. Ultimately, the resulting optimization of the pore structure governs the final reservoir quality. The sparry bioclastic limestone is identified as the most promising exploration target in the study area. Its favorable reservoir quality is mainly attributed to its development on palaeogeomorphic and structural highs, where enhanced hydrodynamic energy and subsequent fracture-related dissolution significantly improved pore connectivity. These high-quality reservoirs are widely developed on gentle slope profiles and similar high-quality reservoirs may also locally occur at isolated palaeogeomorphic highs within steep-slope settings, as demonstrated by individual wells. Full article

The marine carbonate reef–shoal reservoirs in the gentle slope platform margin of the M block, eastern Sichuan Basin, were well developed during the Changxing Period in late Permian and represent a favorable carbonate reservoir play for petroleum exploration. The lack of effective research methods has hindered the analysis of their unique sedimentary characteristics and controlling factors. Based on cores, thin sections, well logs, testing analyses, and high-resolution 3D seismic data, this study analyzes the lithological associations, microfacies types, reservoir physical properties, and seismic reflection characteristics of reef–shoal reservoirs. On this basis, the reef–shoal sedimentary characteristics and controlling factors were analyzed. The main conclusions are as follows: (1) Two major categories and eight subcategories of petrography were identified in marine carbonate reef–shoals, and five microfacies were identified: reef base, reef core, reef flank, reef-top–shoal, and inter-reef sea. Among these, the reef-top–shoal constitutes the optimal reservoir, while the reef flank develops secondary reservoirs. (2) The reef–shoals exhibit an external mound or wedge-shaped reflection, with internally discontinuous or chaotic reflections. Discontinuous reflections are observed at the top, while onlap terminations are present on its flanks. (3) The vertical accretion of the marine reef–shoals is small, but the platform margin belt is wide in planar, multiple rows reef–shoal bodies are identified, reflecting their small scale, discrete planar distribution, rapid lateral migration, and diverse stacking patterns. (4) The regional gentle slope marine platform margin geological setting, tectonic paleogeomorphology, and high-frequency sea level fluctuation collectively control the sedimentary structure and the formation of high-quality reservoirs of the marine reef–shoal complex. This research provides guidance for petroleum exploration and favorable reservoir prediction in the marine carbonate reservoirs of the Sichuan Basin. Full article

This study systematically investigates the lithofacies, sedimentary microfacies, vertical evolution, and spatial distribution of the braided river delta–shallow lacustrine carbonate mixed sedimentary rocks of the Upper Ganchaigou Formation in the Huatugou Oilfield of the Qaidam Basin, China. This study integrates data from field outcrops, core observations, thin section petrography, laboratory analyses, and well-logging interpretations. Based on these datasets, the sedimentary characteristics are identified, and a comprehensive sedimentary model is constructed. The results reveal that the study area contains five clastic facies, three types of mixed sedimentary facies, and ten sedimentary microfacies. Two distinct modes of mixed sedimentation are recognized: component mixing and stratigraphic mixing. A full lacustrine transgression–regression cycle is formed by the two types of mixed sedimentation characteristics, which exhibit noticeable differences in vertical evolution. Component mixing, which occurs in a mixed environment of continuous clastic supply and carbonate precipitation during the transgression, is the primary characteristic of the VIII–X oil formation. The mixed strata that make up the VI–VII oil formation show rhythmic interbedding of carbonate and clastic rocks. During the lacustrine regression, it shows the alternating sedimentary environment regulated by frequent variations in lacustrine levels. The planar distribution is affected by both intensity of sediment from the west and the changes in lacustrine level. During the lacustrine transgression, it is dominated by littoral-shallow lacustrine mixed beach bar and mixed sedimentary delta. On the other hand, during the lacustrine regression, it is dominated by laterally amalgamated sand bodies in the braided-river delta front. Based on this, a mixed sedimentary evolution model controlled by the coupling of “source–lacustrine level” is established. It offers a guide for reconstructing the sedimentary environment in basins that are similar to it and reveals the evolution path of mixed sedimentation in the short-axis source area of arid saline lacustrine basins. Full article

To identify the principal controls on gas-bearing property heterogeneity in tight reservoirs of the Shaximiao Formation in the southwestern Sichuan Basin, this study systematically examines pore structure characteristics and their influence on reservoir quality through an integrated approach incorporating cast thin sections, X-ray diffraction (XRD), high-pressure mercury injection (HPMI), and parameters such as homogeneity and variation coefficients. The research has indicated that the following findings: (1) The reservoir lithology in the study area is predominantly lithic arkose, with pore types dominated by residual intergranular pores and intragranular dissolution pores, and pore-throat radii ranging from 5 nm to 1 μm. (2) The disparity in reservoir quality is attributed to two primary factors. Firstly, diverse sediment provenance directions and varying mineral compositions directly influence the internal pore structure of the reservoirs. Secondly, differences in diagenetic minerals lead to heterogeneity in pore space development. Specifically, early carbonate cementation in the Pingluoba reservoir occluded porosity, resulting in poor physical properties. In the Yanjinggou reservoir, clay mineral cementation and pore-filling activities significantly reduced reservoir quality. In contrast, the presence of chlorite coatings in the Baimamiao and Guanyinsi reservoirs helped preserve primary porosity, contributing to superior reservoir properties. (3) The variation in gas content between different gas reservoirs is primarily attributed to differences in reservoir heterogeneity on a planar scale, whereas the gas content variation within different intervals of the same gas reservoir is controlled by differences in pore structure among various sand units. Furthermore, gas content heterogeneity within the same interval of a single reservoir results from variations in sand body thickness and connectivity. Full article

The Linxing area on the eastern margin of the Ordos Basin is a key area for tight-gas exploration. Here, the He 8 Member is the principal target for reserve growth and gas production. However, accurate prediction of sweet spots remains challenging due to poorly constrained primary controlling factors affecting high-quality reservoirs and their diagenetic densification mechanisms. To address these issues, we integrated data from cores, petrographic thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), and log-facies analysis to conduct refined sedimentary microfacies identification, diagenetic analysis, and quantitative porosity evolution analysis. Results indicate that high-quality reservoirs in the He 8 Member are predominantly controlled by distributary-channel microfacies of a braided-river delta plain. Reservoir densification resulted from destructive diagenesis, primarily intense compaction and multi-phase cementation. Compaction reduced porosity by 18.7% on average (accounting for 60% of the total loss), whereas cementation led to a 11.4% loss (36.5%). Dissolution locally enhanced reservoir quality but was insufficient to reverse the pre-existing tight background, providing a limited porosity increase of approximately 5.6%. This study reveals a depositional-diagenetic coupling control on reservoir quality and establishes a genetic model for tight sandstones, thereby providing a critical theoretical framework for sweet-spot prediction in the Linxing area and analogous geological settings. Full article

Understanding the influence of strike–slip faulting on deep carbonate reservoirs remains challenging. This study integrates core observations, well logging, and seismic interpretation to investigate fracture diagenesis and evaluate the impact of strike–slip faulting on Upper Permian reef–shoal reservoirs in the northern Sichuan Basin. Within the platform margin reef–shoal microfacies, transtensional faulting during the Late Permian was later overprinted by transpressional deformation in the Early–Middle Triassic. Although individual fault displacements are generally less than 200 m, the associated damage zones may extend over 1000 m in width. Strong compaction and cementation eliminated most primary porosity in the reef–shoal carbonates, whereas dissolution enhanced porosity preferentially developed along fault damage zones. The most productive of fracture–vug reservoirs (“sweet spots”) are mainly distributed adjacent to strike–slip fault zones within the reef–shoal bodies. Reservoir quality is controlled by syn-sedimentary faults, moldic vugs, karstic argillaceous fills, and U-Pb ages of fracture cements that indicate multi-stage diagenesis. Contemporaneous fracturing and dissolution during the Late Permian played a dominant role in enhancing reservoir porosity, while burial-stage cementation had a detrimental effect. This case study demonstrates that even small-scale strike–slip faulting can significantly improve reservoir quality in deep tight reef–shoal carbonates. Full article

This study focuses on the tight reservoirs of the Jingzigou Formation in the Satan 1 block of the Jinan Sag, Junggar Basin. By integrating analyses of sedimentary microfacies, reservoir characteristics, and fracture distribution, it innovatively applies machine learning algorithms for the quantitative identification and prediction of “sweet spots”. The results indicate that subaqueous distributary channels within the braided river delta front are the dominant sedimentary microfacies. The reservoir exhibits typical tight oil characteristics, with porosity primarily below 10% and permeability generally less than 0.01 mD. Sedimentary microfacies significantly control reservoir quality, with the subaqueous distributary channels exhibiting the best physical properties. Mid- to high-angle structural fractures effectively enhance reservoir permeability and show a strong positive correlation with oil saturation. This research employs machine learning techniques—including Decision Trees, Random Forest, and Support Vector Machines—to establish a comprehensive sweet spot classification model by integrating pore-throat structure, petrophysical parameters, reservoir thickness, and fracture development intensity. Among these, the Random Forest algorithm demonstrated optimal performance across all evaluation metrics. Prediction results reveal that Class I and Class II sweet spots are predominantly distributed in the northern slope area, while Class III sweet spots are located in the central trough and southern nose-like structural zone. These classification results show a high consistency with actual production data, confirming the effectiveness and applicability of machine learning for sweet spot prediction in this study area. The research outcomes provide reliable geological guidance for well placement optimization and reserve development in the Satan 1 block, offering significant reference value for the prediction and development of sweet spots in similar heterogeneous tight oil reservoirs. Full article

The He 1 Member of the Xiashihezi Formation (Upper Paleozoic) in the Ordos Basin represents typical tight sandstones (Φ < 10%, k < 0.5 mD). However, against the extensive tight sandstone background of the He 1 Member in the southern basin, conventional reservoirs (Φ > 12%, K > 1 mD) occur locally. Elucidating the genetic mechanism of these conventional reservoirs is critical for evaluating gas reservoirs in this region. Based on core descriptions and systematic sampling from cored wells, reservoir types are classified according to pore types and porosity in sandstones. Depositional microfacies, petrology, and diagenesis of each reservoir type are then investigated to ultimately elucidate the genetic mechanism of conventional reservoirs. Results demonstrate that intense compaction and quartz overgrowths are the primary controls on the development of the He 1 Member tight sandstones. Alteration of volcanic lithic fragments and volcanic ash matrix generated abundant intragranular dissolution pores and micropores within the matrix, while simultaneously producing substantial illite–smectite mixed-layer clays and chlorite clays. Additionally, this process supplied silica for quartz overgrowths. Moderate amounts of chlorite coatings can inhibit quartz overgrowths, thereby preserving residual intergranular porosity. Conventional reservoirs exhibit low lithic fragment content (<20 vol.%) and are characterized by a porosity assemblage of both intergranular (avg. 2.3%) and intragranular dissolution pores (avg. 6.5%). Their formation requires weak compaction, intense dissolution, and weak quartz overgrowths. These reservoirs develop within high-energy transverse bars that are sealed by overlying and underlying mudstones. Such transverse bars constitute closed intrastratal-diagenetic systems with restricted mass transfer during burial. This study provides a compelling example of diagenetic heterogeneity induced by variations in sandstone architecture within fluvial successions. Full article

This study aims to investigate the sedimentary facies characteristics of the coal seam roof in the Qinglong and Longfeng coal mines and their control over water abundance. By collecting core samples and well logging data from both mining areas, multiple methods were employed, including core observation, thin-section analysis, sedimentary microfacies distribution mapping, nitrogen adsorption tests, and nuclear magnetic resonance analysis, to systematically analyze the depositional environments, types of sedimentary microfacies, and their distribution patterns. Results indicate that the roof of Qinglong Coal Mine is predominantly composed of sandy microfacies with well-developed faults, which not only increase fracture porosity but also provide water-conducting pathways between surface water and aquifers, significantly enhancing water abundance. In contrast, Longfeng Coal Mine is characterized mainly by muddy microfacies, with small-scale faults exhibiting weak water-conducting capacity and relatively low water abundance. Hydrochemical analysis indicates that consistent water quality between Qinglong’s working face, karst water, and goaf water confirms fault-induced aquifer–surface water connectivity, whereas Longfeng’s water quality suggests weak aquifer–coal seam hydraulic connectivity. The difference in water hazard threats between the two mining areas primarily stems from variations in sedimentary microfacies and fault structures. Full article

The complexity of tight sandstone reservoirs challenges effective oil and gas exploration. The Chang 8 Member of the Yanchang Formation in the Longdong area of the Ordos Basin has significant exploration potential. However, its reservoir characteristics are controlled by two distinct provenance systems and diverse sedimentary microfacies. The specific impacts of these factors on reservoir quality and their relative importance have remained unclear. This study employs an integrated analytical approach combining casting thin sections, conventional porosity-permeability measurements, and Nuclear Magnetic Resonance (NMR) to systematically investigate the petrological characteristics, pore structure, and physical properties of the Chang 8 reservoirs. Our findings reveal that the entire section of Chang 8 is a delta front subfacies, with sub sections of Chang 8¹ and 8² developing microfacies such as underwater distributary channels, underwater natural levees, sheet sand and mouth bars. The tight sandstone reservoir is mainly composed of lithic arkose and feldspathic litharenite, with its porosity dominated by dissolution and intergranular types. These secondary pores, particularly those resulting from feldspar dissolution, are of great importance. The underwater distributary channels have the best pores, followed by sheet sands, and underwater natural levees the worst. Compaction in Chang 8² is stronger than in Chang 8¹, leading to smaller pores. The northwest provenance is characterized by high clay content and small pores, while the southwest provenance has coarser grain size and better-preserved intergranular pores. Reservoir properties improve toward the lake but deteriorate at the lake-proximal end due to more small pores. This study reveals the control laws of sedimentary microfacies, provenance, and diagenesis on the pore development of tight sandstone in the Longdong area, providing theoretical guidance for the exploration and development of tight sandstone oil and gas in the region. Full article

The prediction of thin-bedded, favorable sand bodies within the Triassic Baikouquan Formation fan delta on the western slope of the Mahu Sag is challenging due to their strong spatial heterogeneity. To address this, we propose an integrated workflow that synergizes seismic sedimentology with geologically constrained seismic inversion. This study leverages well logging, core data, and 3D seismic surveys. Initially, seismic attribute analysis and stratal slicing were employed to delineate sedimentary microfacies, revealing that the fan delta front subfacies comprises subaqueous distributary channels, interdistributary bays, and distal bars. Subsequently, the planform distribution of these microfacies served as a critical constraint for the Seismic Waveform Indicative Inversion (SWII), effectively enhancing the resolution for thin sand body identification. The results demonstrate the following: (1). Two NW-SE trending subaqueous distributary channel systems, converging near the BAI65 well, form the primary reservoirs. (2). The SWII, optimized by our workflow, successfully predicts high-quality sand bodies with a cumulative area of 159.2 km², primarily located in the MAXI1, AIHU10, and AICAN1 well areas, as well as west of the MA18 well. This study highlights the value of integrating sedimentary facies boundaries as a geological constraint in seismic inversion, providing a more reliable method for predicting heterogeneous thin sand bodies and delineating future exploration targets in the Mahu Sag. Full article

The Lower Cretaceous Jiufotang Formation in the Fuxin Basin contains a proven petroleum system. However, its southern part remains underexplored due to limited drilling and fragmentary sedimentary studies. To address this issue, we conducted detailed sedimentological logging of the two typical outcrop sections, Pijiagou and Tanjiagou. Field observations, petrographic data, and grain-size analysis were integrated to decipher hydrodynamic conditions, calibrate microfacies associations, and reconstruct the sedimentary evolution through facies stacking pattern analysis. The results show that the Jiufotang Formation predominantly consists of calcareous fine-grained clastic rocks, with poorly sorted sandstones indicative of low-energy conditions. Sediment transport mechanisms include both traction and turbidity currents, with suspension being predominant. The succession records a depositional transition from fan-delta to lacustrine environments. Two subfacies, fan-delta front and shore-shallow lacustrine, were identified and subdivided into seven microfacies: subaqueous distributary channels, interdistributary bays, subaqueous levees, mouth bars, muddy shoals, sandy shoals, and carbonate shoals. The sedimentary evolution reflects an initial lacustrine transgression followed by regression, interrupted by multiple lacustrine-level fluctuations. The alternating depositional pattern of lacustrine and deltaic facies has formed complete source-reservoir-seal assemblages in the Jiufotang Formation in the study area, making it a potential favorable target for hydrocarbon accumulation. Full article