Search Results (99)

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

Shale pores and throats are key factors controlling the enrichment and development efficiency of shale oil and gas. However, the characteristics and formation mechanisms of shale pores and throats remain unclear. Taking the Permian continental shales in the Mahu Sag of the Junggar Basin as an example, this paper studies the formation mechanisms of pores and throats in shales of different lithofacies through a series of experiments, such as high-pressure mercury injection and scanning electron microscopy. The results show that the Permian continental shales in the Junggar Basin are mainly composed of five lithofacies: rich siliceous shale (RSS), calcareous–siliceous shale (CSS), argillaceous–siliceous shale (ASS), siliceous–calcareous shale (SCS), and mixed-composition shale (MCS). The pores in shale are dominated by intergranular and intragranular pores. The intergranular pores are mainly primary pores and secondary dissolution pores. The primary pores are mainly slit-like and polygonal, with diameters between 40 and 1000 nm. The secondary dissolution pores formed by dissolution are irregular with serrated edges, and their diameters range from 0.1 to 10 μm. The throats are mainly pore-constriction throats and knot-like throats, with few vessel-like throats, overall exhibiting characteristics of nanometer-scale width. The mineral composition has a significant influence on the development of pores and throats. Siliceous minerals promote the development of macropores, and carbonate minerals promote the development of mesopores. Clay minerals inhibit pore development. Diagenesis regulates the development of pores and throats through mechanical compaction, cementation, and dissolution. Compaction leads to a reduction in porosity, and cementation has varying effects on the preservation of pores and throats. Dissolution is the main factor for increased pores and throats. These findings provide a lithofacies-based geological framework for evaluating effective porosity, seepage capacity, and shale oil development potential in continental shale reservoirs. Full article

The genetic mechanism of high-quality reservoirs in the tight sandstone of the Shaximiao Formation, Sichuan Basin, remains poorly understood, hindering effective exploration. This study integrates petrographic analysis and fluid inclusion homogenization temperature measurement to reconstruct the diagenetic sequence and restore porosity evolution. This approach reveals the controlling factors of reservoir densification and their interplay with hydrocarbon charging. We find that reservoir heterogeneity results from the competing effects of densifying processes (compaction and cementation) and porosity-enhancing dissolution. The critical control is identified as the timing of hydrocarbon charging relative to densification, leading to a new three-type reservoir classification. Based on the temporal relationship between hydrocarbon charging and densification, reservoirs are classified into three types: Type I (“hydrocarbon charging before densification”), Type II (“synchronous charging and densification”), and Type III (“densification before charging”). Type I (high-quality) reservoirs are primarily controlled by the synergistic effects of high-energy depositional facies and early chlorite coatings. The ‘deposition-diagenesis-hydrocarbon charging’ model elucidates high-quality reservoir mechanisms. These findings offer a genetic model and a predictive tool for pinpointing sweet spots, with significant implications for reducing exploration risk in this and similar tight gas basins worldwide. 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

The tight sandstone reservoir of the Fuyu Oil Layer in the Quantou Formation of the Cretaceous in the Bayan Chagan area displays intricate microscopic pore structures and pronounced heterogeneity, limiting hydrocarbon exploration and development efficiency. Utilizing core CT scanning digital core technology integrated with field emission scanning electron microscopy (FE–SEM) and whole-rock/clay mineral X-ray diffraction (XRD) analysis, this research performs multi-scale quantitative characterization on 15 representative rock samples from the study area, systematically elucidating reservoir pore structure diversity and its formation mechanisms. The study demonstrates that reservoirs in the study area can be categorized into three types: A, B, and C, exhibiting progressively declining reservoir performance. Type A reservoirs are characterized primarily by dissolution-formed large to medium pores, where macropores (radius > 5 μm) account for more than 92% of storage capacity, average coordination numbers reach 0.27~0.45, and connectivity is optimal. Type B reservoirs are influenced by siliceous cementation, featuring developed residual intergranular pores, macropore volume share declining to 88%, and coordination numbers decreasing to 0.11~0.20. Type C reservoirs experience intense compaction and illite cementation modification, where micropores (radius < 1 μm) constitute 5.6% numerically, yet macropore volume share is merely 76%, coordination numbers drop to 0.02–0.03, and connectivity is minimal. Mineralogical analysis reveals that quartz content exhibits a positive correlation with reservoir properties, as its rigid grain framework effectively resists compaction. Illite content rises with increasing burial depth, and plastic illite occupies pores and segment throats, resulting in Type C reservoir permeability reduction to 0.01~0.25 mD. Dissolution intensity (Type A > Type B > Type C) and cementation types (quartz cementation prevailing in Type B, illite cementation prevailing in Type C) represent crucial factors governing reservoir quality differentiation. This research confirms the reliability of digital core technology for tight reservoir classification and assessment, developing a discrimination model founded on “pore structure-mineral composition-diagenesis”. It provides a geological basis for sweet spot prediction and efficient development in the study area. 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

Determining the timing of hidden faults that terminate beneath the subsurface remains a significant challenge. For this contribution, seismic fault interpretation, fracture diagenesis analysis, and U-Pb dating of fracture cements are integrated to constrain the activity of hidden thrust faults in the southeastern Sichuan Basin. The results show that the EW- and NW-trending hidden thrust faults developed in the Permian, while the NE-trending faults have inherited later fault activity till the Cenozoic. The hidden thrust fault propagates upward from the top of the Upper Permian to the Lower Triassic strata. Fault inversion within the Permian is firstly identified by the thickness variation between the two fault walls. Core-based fracture diagenesis analysis indicates that multiple fractures and associated dissolution porosity developed within the tight matrix reservoir. In situ U-Pb dating of fracture cements yields ages of 247.4 ± 2 Ma and 234.8 ± 9.1 Ma, indicating that the hidden fault activity predates the Early Triassic. The absence of strata, evidence of structural uplift, and fault inversion collectively suggest that the first faulting in the eastern Sichuan Basin occurred at the end of the Middle Permian. The findings highlight that fracture–cave reservoir along the hidden thrust fault zone has been controlled by the coupling of the fracturing and karstification at the end of the Middle Permian, and is the key target for high gas production. Full article

In the observation of tight sandstone cores, the variations in the hydrocarbon charging usually can be observed in the same geological age reservoirs, which manifest as differential oil staining on the core surface. In order to clarify the micro total pore–throat size distribution (TPSD) characteristics and oil content differences of different oil-bearing tight reservoirs, we drilled two types of oil-bearing cores in the Chang6 formation of Xiasiwan Oilfield, conducted casting thin section (CTS), scanning electron microscopy (SEM), and X-ray diffraction (XRD) to qualitatively and quantitatively analyze petrological and pore–throat characteristics. The TPSD of different oil-bearing cores were quantitatively characterized and compared by combining high-pressure mercury injection (HPMI) and constant rate mercury injection (CRMI). Meanwhile, we quantitatively evaluated the complexity of the pore–throat structure based on fractal theory. Our results reveal significant difference in the clay mineral contents between the two types of cores, despite both being classified as arkose. Due to higher contents of illite, calcite, and chlorite, the pores of oil-smelling sandstone are obviously affected by cementation. The result of TPSD characteristics shows that the oil-appearing sandstone samples exhibit well-developed big pores and throats, displaying bimodal distribution, and three-stage fractal characteristics in the TPSD curves. Conversely, oil-smelling sandstone samples manifesting a left-skewed bimodal, pore space contribution of the samples is more dependent on pores and throats smaller than 0.12 μm. The TPSD curves exhibit three-stage and four-stage fractal characteristics. Therefore, the differences in oil-bearing properties between the two types of cores are attributed to variations in mineral composition, diagenesis, clay mineral content, pore types, pore–throat size distribution (PSD), and pore–throat complexity. Our results provide crucial guidance for subsequent reservoir quality assessment in this study area and the development of tight sandstone reservoirs with similar geological characteristics. Full article

Fluid flow prediction in clastic heterogeneous reservoirs is a universal issue, especially when diagenetic development supplants structural and depositional controls. We consider this issue in the Middle Miocene Belayim Formation of the Gulf of Suez, a principal syn-rift reservoir where extreme, diagenetically induced pore system heterogeneity thwarts production. Although fault compartmentalization is understood as creating first-order traps, sub-seismic diagenetic controls on permeability anisotropy and reservoir within these traps are not restricted. This study uses a comprehensive set of petrophysical logs (ray gamma, resistivity, density, neutrons, sonic) of four key wells in the western field of Tawila (Tw-1, Tw-3, TW-4, TN-1). We apply an integrated workflow that explicitly derives permeability from petrophysical logs and populates it within a seismically defined structural framework. This study assesses diagenetic controls over reservoir permeability and fluid flow. It has the following primary objectives: (1) to characterize complicated diagenetic assemblage utilizing sophisticated petrophysical crossplots; (2) to quantify the role of shale distribution morphologies in affecting porosity effectiveness utilizing the Thomas–Stieber model; (3) to define hydraulic flow units (HFUs) based on pore throat geometry; and (4) to synthesize these observations within a predictive 3D reservoir model. This multiparadigm methodology, involving M-N crossplotting, Thomas–Stieber modeling, and saturation analysis, deconstructs Tawila West field reservoir complexity. Diagenesis that has the potential to destroy or create reservoir quality, namely the general occlusion of pore throats by dispersed, authigenic clays (e.g., illite) and anhydrite cement filling pores, is discovered to be the dominant control of fluid flow, defining seven unique hydraulic flow units (HFUs) bisecting the individual stratigraphic units. We show that reservoir units with comparable depositional porosity display order-of-magnitude permeability variation (e.g., >100 mD versus <1 mD) because of this diagenetic alteration, primarily via pore throat clogging resulting from widespread authigenic illite and pore occupation anhydrite cement, as quantitatively exemplified by our HFU characterization. A 3D model depicts a definitive NW-SE trend towards greater shale volume and degrading reservoir quality, explaining mysterious dry holes on structurally valid highs. Critically, these diagenetic superimpressions can replace the influence of structural geometry on reservoir performance. Therefore, we determine that a paradigm shift from a highly structured control model to an integrated petrophysical and mineralogical approach is needed. Sweet spot prediction relies upon predicting diagenetic facies distribution as a control over permeability anisotropy. Full article

The Permian Xiashihezi Formation in the Ordos Basin is a typical tight sandstone gas reservoir, which is characterized by low porosity and strong heterogeneity. Diagenesis plays a crucial role in controlling reservoir quality. However, the multiple phases and types of diagenetic processes throughout geological history make the compaction mechanisms highly complex. This study employed a high-temperature and high-pressure diagenesis simulation system to conduct geological simulation experiments. Typical reservoir samples from the 2nd Member of the Permian Xiashihezi Formation were selected for these simulations. The experiments replicated the diagenetic evolution of the reservoirs under various temperature, pressure, and fluid conditions, successfully reproducing the diagenetic sequences. The diagenetic sequence included early-stage porosity reduction through compaction, early carbonate cementation, quartz overgrowth, chlorite rim formation, feldspar dissolution, and late-stage illite and quartz cementation. Mechanical compaction is the primary factor reducing reservoir porosity, exhibiting a distinct four-stage porosity reduction pattern: (1) continuous burial stage (>4000 m); (2) stagnation stage of burial (3900 m–4100 m); (3) the secondary continuous burial stage (>5000 m); (4) tectonic uplift stage (3600 m). The experiments confirmed that the formation of various authigenic minerals is strictly controlled by temperature, pressure, and fluid chemistry. Chlorite rims formed in an alkaline environment enriched with Fe²⁺ and Mg²⁺ (simulated temperatures of 280–295 °C), effectively inhibiting quartz overgrowth. Illite appeared at higher temperatures (>300 °C) in platy or fibrous forms. Feldspar dissolution was noticeable upon injection of acidic fluids (simulated organic acids), providing material for authigenic quartz and kaolinite. The key mineral composition significantly impacts reservoir diagenesis. The dissolution released Mg²⁺ and Fe²⁺ ions, crucial for forming early chlorite rims in the overlying sandstones, confirming the importance of inter-strata interactions in “source-facies coupling.” Through physical simulation methods, this study deepened the understanding of the diagenetic evolution and compaction mechanisms of tight sandstones. This provides significant experimental evidence and theoretical support for predicting “sweet spot” reservoirs in the area. Full article

The Mindong–Changchunling region is situated in the central portion of the Songliao Basin, Northeast China. The primary target stratum in this area is the Fuyu Oil Layer of the Lower Cretaceous Quantou 4 Member. This reservoir is predominantly composed of fine sandstone and siltstone, with minor interbedded medium sandstone. Variations in provenance, sedimentation, and diagenesis are identified as the main controlling factors for the distribution of high-quality reservoirs in the Mindong–Changchunling region. The sand body distribution in the Changchunling area is influenced by the eastern near-source provenance. The reservoir properties of these sand bodies are impacted by the poor sorting and high mud content typical of near-source delta sand bodies. Nonetheless, reservoir quality is enhanced by late-stage uplift and surface water dissolution-leaching. In contrast, sand body distribution in the Mindong area is governed by the southwestern far-source provenance. Far-source delta sand bodies are characterized by better sorting but high mud content, with their reservoir properties primarily impaired by carbonate cementation. During the early-middle diagenetic stage, feldspar dissolution by organic acids improves sand body reservoir quality. Due to variations in sedimentation and diagenesis, the following three favorable reservoir zones with distinct genetic types have developed in the Mindong–Changchunling area: the Chang107–Chang104–Chang52 well block, the Fu155–Fu161–Fu157 well block, and the Min103–Min31 well block. Full article

Traps are central to petroleum exploration, where hydrocarbons accumulate during migration. Reservoirs are likewise an essential petroleum system element and serve as the primary medium for hydrocarbon storage. The buried hill is a geological formation highly favorable for reservoir development. However, the factors influencing hydrocarbon accumulation in buried hill reservoirs are highly diverse, especially in areas with complex, active fault systems. Fault systems play a dual role, both in the formation of reservoirs and in the migration of hydrocarbons. Therefore, understanding the impact of complex fault systems helps enhance the exploration success rate of buried hill traps and guide drilling deployment. In the Beibuwan Basin in the South China Sea, buried hill traps are key targets for deep-buried hydrocarbon exploration in this faulted basin. The low level of exploration and research in buried hills globally limits the understanding of hydrocarbon accumulation conditions, thereby hindering large-scale hydrocarbon exploration. By using drilling data, logging data, and seismic data, stress fields and tectonic faults were restored. There are two types of buried hills developed in the Beibuwan Basin, which were formed during the Late Ordovician-Silurian period and Permian-Triassic period, respectively. The tectonic genesis of the Late Ordovician-Silurian period buried hills belongs to magma diapirism activity, while the tectonic genesis of the Permian-Triassic period buried hills belongs to reverse thrust activity. The fault systems formed by two periods of tectonic activity were respectively altered into basement buried hills and limestone buried hills. The negative structural inversion controls the distribution and interior stratigraphic framework of the deformed Carboniferous strata in the limestone buried hill. The faults and derived fractures of the Late Ordovician-Silurian period and Permian-Triassic period promoted the diagenesis and erosion of these buried hills. The faults formed after the Permian-Triassic period are not conducive to calcite cementation, thus facilitating the preservation of the reservoir space formed earlier. The control of hydrocarbon accumulation by the fault system is reflected in two aspects: on the one hand, the early to mid-Eocene extensional faulting activity directly controlled the depositional process of lacustrine source rocks; on the other hand, the Late Eocene-Oligocene, which is closest to the hydrocarbon expulsion period, is the most effective fault activity period for connecting Eocene source rocks and buried hill reservoirs. This study contributes to understanding of the role of complex fault activity in the formation of buried hill traps within hydrocarbon-bearing basins. Full article

This study focuses on the clastic reservoir in the first member of Yaojia Formation within Qijia-Gulong Sag, Songliao Basin. The results indicate that the reservoir in the study area develops within a shallow-water delta sedimentary system. The dominant sedimentary microfacies comprise underwater distributary channels, mouth bars, and sheet sands. Among these, the underwater distributary channel microfacies exhibits primary porosity ranging from 15.97% to 17.71%, showing the optimal reservoir quality, whereas the sheet sand microfacies has a porosity of only 7.45% to 12.08%, indicating inferior physical properties. During diagenesis, compaction notably decreases primary porosity via particle rearrangement and elastic deformation, while calcite cementation and quartz overgrowth further occlude pore throats. Although dissolution can generate secondary porosity (locally up to 40%), the precipitation of clay minerals tends to block pore throats, leading to “ineffective porosity” (permeability generally < 5 mD) and overall low-porosity and low-permeability characteristics. Carbon–oxygen isotope analysis reveals a deficiency in organic acid supply in the study area, restricting the intensity of dissolution alteration. Reservoir quality evolution is dominantly governed by the combined controls of sedimentary microfacies and diagenesis. This study emphasizes that, within shallow-water delta sedimentary settings, the material composition of sedimentary microfacies and the dynamic equilibrium of diagenetic processes jointly govern reservoir property variations. This insight provides critical theoretical support for understanding diagenetic evolution mechanisms in clastic reservoirs and enabling precise prediction of high-quality reservoir distribution. Full article

This study systematically analyzes reservoir formation mechanisms under deep burial conditions, integrating macroscopic observations from representative ultra-deep clastic reservoirs in four major sedimentary basins in central and western China. Developing effective clastic reservoirs in ultra-deep strata (6000–8000 m) remains a critical yet debated topic in petroleum geology. Recent advances in exploration techniques and geological understanding have challenged conventional views, confirming the presence of viable clastic reservoirs at such depths. Findings reveal that reservoir quality in ultra-deep strata is preserved and enhanced through the interplay of sedimentary, diagenetic, and tectonic processes. Key controlling factors include (1) high-energy depositional environments promoting primary porosity development, (2) proximity to hydrocarbon source rocks enabling multi-phase hydrocarbon charging, (3) overpressure and low geothermal gradients reducing cementation and compaction, and (4) late-stage tectonic fracturing that significantly improves permeability. Additionally, dissolution porosity and fracture networks formed during diagenetic and tectonic evolution collectively enhance reservoir potential. The identification of favorable reservoir zones under the sedimentation–diagenesis-tectonics model provides critical insights for future hydrocarbon exploration in ultra-deep clastic sequences. Full article

The early Paleozoic Huaiyuan Movement created a major unconformity in the Ordos Basin, significantly influencing sedimentation and early diagenesis in both the overlying and underlying strata near the unconformity. However, the origins of the associated dolomite and silica near this unconformity remain poorly understood. This study aims to reveal how this tectonic event controlled the Early–Middle Ordovician sedimentary environments and early diagenetic processes. The petrological and geochemical results indicate a progressive transition from a dolomitic tidal flat to an intra-platform depression, culminating in a mixed tidal flat during the Early-to-Middle Ordovician, driven by the Huaiyuan Movement. Furthermore, this movement, accompanied by intense weathering and erosion, increased the supply of marine dissolved silica (DSi) and terrestrial nutrients. Consequently, extensive tidal-edge biogenic silica accumulated, which later precipitated as siliceous-cemented dolomite during a shallow-burial stage. We propose a conceptual model of the sedimentary–early diagenetic processes in response to the Huaiyuan Movement, providing novel insights into the regional paleoenvironmental evolution across the Early–Middle Ordovician transition in the Ordos Basin. Full article