Search Results (43)

Tight oil horizontal wells in the Mahu block of the Junggar Basin commonly show rapid production decline and limited target-domain samples. These characteristics make accurate production prediction difficult. This work aims to address the small-sample overfitting problem of tight oil horizontal well production prediction in Mahu Sag with rapid production decline and limited measured well data. The concept of transfer learning is introduced to address the issue of insufficient target domain samples, and the Pearson correlation coefficient is utilized to select the main controlling factors for production from the production data. Next, based on the features extracted by the temporal convolutional network at different data scales, a multi-head attention mechanism is introduced to capture the dependencies across different time steps. Subsequently, an improved sparrow search algorithm is employed to optimize the hyperparameters of the bidirectional long short-term memory network. Finally, the bidirectional long short-term memory network is integrated to further extract the nonlinear features learned by the temporal convolutional network to conduct production prediction. Tailored to the exploitation conditions of tight oil horizontal wells in this block, a tight oil production prediction model based on transfer learning and the multi-head attention mechanism is proposed. Experimental results demonstrate that, compared with the standard bidirectional long short-term memory network, the proposed model’s evaluation metrics show a 60.93% decrease in root mean square error, a 78.53% decrease in mean absolute percentage error, and a 43.68% increase in coefficient of determination. This verifies the effectiveness of transfer learning in solving small-sample modeling challenges, providing precise technical support for the optimization of tight oil fracturing parameters and stimulation treatments in the Mahu block. The novelty of this work lies in the integration of multi-head attention temporal convolution network, quantum sparrow optimized bidirectional long short-term memory network and cross-block transfer learning for small-sample tight oil forecasting. Full article

The Fengcheng Formation in the Mahu Sag of the Junggar Basin represents one of the oldest and most significant alkaline lacustrine systems, hosting abundant dolomite that serves as a key unconventional reservoir. However, the formation mechanism of dolomite remains unclear. This study integrates detailed petrography, geochemistry and cyclostratigraphy to elucidate the origin and distribution of dolomite. Petrographic characteristics indicate a penecontemporaneous origin for the dolomite, with no apparent hydrothermal influence. Mineralogical features exhibit a multi-zonation structure of dolomite, aligning with in situ Fe content, jointly indicating that a multi-stage formation process of dolomite from core to rim. Microbial methanogenesis likely played an important role in the dolomite formation. Spatially, dolomite is enriched in the transition zone but scarce in the depocenter zone, where sodium carbonate prevails. This distribution is primarily controlled by pH differentiation between the transition zone and the depocenter zone of the Mahu Sag. In the transition zone, orbitally driven wet–dry cycles regulated the lake-level change, which, in turn, controlled pH fluctuation, as revealed by the silica precipitation during humid phases and dissolution during arid intervals. In the depocenter zone, lake water remained at a high-pH state, which was unfavorable for dolomite formation. These findings highlight that pH dynamics, linked to orbital climate cycles, played a critical role in governing dolomite formation and distribution in this ancient alkaline lake, providing new insights for the formation of dolomite in alkaline lacustrine environments. Full article

The Lower Permian Fengcheng Formation (P₁f) in the Mahu Sag, Junggar Basin, records an uncommon alkaline–lacustrine hybrid system where siliciclastic, volcaniclastic inputs, and endogenous carbonates jointly build strong reservoir heterogeneity. This study clarifies how depositional framework architecture and diagenetic evolution jointly control effective pore–throat connectivity and reservoir effectiveness. We examined 55 core samples from nine wells using X-ray diffraction (XRD), scanning electron microscopy (SEM), low-pressure N₂ adsorption (LPNA), high-pressure mercury intrusion (HPMI), and nuclear magnetic resonance (NMR) T₂ spectra, and identified five lithofacies: siliciclastic-dominated (SDF), volcaniclastic (VTF), mixed siliciclastic–carbonate (MSCF), carbonate-dominated (CDF), and alkaline mineral-rich (AMF). Reservoir quality is strongly lithofacies-dependent and cannot be inferred from pore volume alone. The SDF and CDF are both dominated by the >200 nm domain, but only the SDF preserves a coarse pore–throat framework that sustains effective flow; the MSCF is characterized by a stronger 10–50 nm contribution and a more tortuous network, and the VTF by enrichment of the 50–200 nm domain. In the SDF, quartz is preferentially associated with the >200 nm domain and dolomite with the 50–200 nm domain, consistent with coarse residual pores preserved by rigid grains and intercrystalline or dissolution-related pores, respectively. The AMF should be treated as two subtypes: the Na-borosilicate subtype shows high >200 nm volume but very high tortuosity, whereas the Na-carbonate subtype shows co-development of the 10–50 nm and >200 nm domains with lower threshold pressure and tortuosity, indicating better pore-body–throat matching and more favorable reservoir behavior. These findings provide a lithofacies-based framework for screening effective reservoir intervals in alkaline lacustrine hybrid systems. Full article

The Mahu Sag, a hydrocarbon-rich depression within the Junggar Basin, hosts significant petroleum resources. Here, the Permian Fengcheng Formation shale oil reservoirs have emerged as a primary exploration target. This study investigates fracture development within these alkaline lacustrine shales, a critical factor governing hydrocarbon migration and accumulation. Through integrated petrographic and geochemical analyses, we elucidate a multifactorial fracture formation mechanism driven by the interplay of alkaline minerals, stress, and fluids. Two distinct fracture types were identified: bedding-complex fracture veins (BCFVs) and Y-shaped high-angle fracture veins (Y-HFVs). Both fracture types result from alkaline fluid–rock interactions, which induce fracture opening along specific orientations, alter fracture angles, and control aperture width and final morphology. Alkaline mineral assemblages further influence fracture evolution via dissolution–precipitation cycles. Concurrently, these assemblages preserve hydrocarbons by inhibiting the thermal maturation of organic matter, as evidenced by variations in fluid inclusion fluorescence. The fracture networks act as crucial migration pathways, with the BCFV containing higher-maturity hydrocarbons (indicated by blue-green fluorescence) and the Y-HFV retaining less mature fluids (indicated by yellow-green fluorescence). This study presents the first systematic characterization of the multifactorial controls on fractures in alkaline lake environments, proposing a cooperative “alkaline minerals–stress–fluids” mechanism. These findings provide a new framework for understanding fracture development in alkaline lacustrine shales and offer valuable insights for shale oil exploration in analogous depositional settings. Full article

Highly deviated wells commonly exhibit large errors in horizon calibration because the logging path follows an inclined borehole trajectory, whereas post-stack seismic processing effectively treats wave propagation as vertical. This mismatch has received limited attention. Here, we performed horizon calibration and velocity-model building for highly deviated wells drilled in the Mahu Sag, Junggar Basin, and obtained three key findings. First, the assumed vertical travel path in post-stack data is the primary cause of the initial mis-tie for highly deviated wells. Second, calibration in the deviated interval requires a strategy distinct from that of vertical wells and may involve substantial stretching or squeezing of the original logs to achieve a consistent time-depth relationship. Third, the map-view projection of a highly deviated well is essentially linear; relative to vertical wells, it provides denser in situ velocity constraints and, with pseudo-well control, supplies 2D velocity information along the well-trajectory plane, thereby improving velocity-field modeling. Validation against drilling data showed that this workflow improved well ties and refined the velocity model, providing practical guidance for geological well planning and reducing drilling risk. Full article

Multi-stage multi-cluster hydraulic fracturing in conglomerate reservoirs is often characterized by strong cluster-to-cluster variability in fluid distribution, which can reduce stimulation efficiency. However, field-scale observations that constrain how injected fluid is partitioned among clusters remain limited, especially in strongly heterogeneous formations. In this study, wide-field electromagnetic (WFEM) monitoring was applied to a horizontal well completed in the Baikouquan Formation sandstone–conglomerate reservoir of the Mahu Sag, Junggar Basin. The monitored treatment consisted of 13 fracturing stages, each containing six perforation clusters. Time-lapse electromagnetic data acquired during pumping were inverted to reconstruct the spatiotemporal evolution of the effective conductive fluid-swept region. Based on the inversion results, we introduce a set of quantitative proxy indicators (swept area, swept length, cluster-specific sweep, and an asymmetric index) to support relative comparison of fluid distribution patterns at both stage and cluster scales. Results show pronounced non-uniformity within and between stages, even under similar pumping conditions. A limited number of clusters exhibit stronger and farther-reaching WFEM-inferred conductive-fluid responses, whereas other clusters show weaker or more localized responses. Asymmetric sweep patterns on opposite sides of the wellbore are also commonly observed. These patterns are consistent with the combined influences of reservoir heterogeneity, local structural/stress disturbances, and operational factors, although WFEM alone does not uniquely validate causal mechanisms of fracture growth. Overall, this study demonstrates that WFEM monitoring provides a field-scale proxy tool for delineating effective conductive fluid-swept regions and for evaluating cluster-to-cluster variability under consistent acquisition and inversion settings. The findings offer practical guidance for interpreting fluid distribution and optimizing multi-cluster fracturing in strongly heterogeneous unconventional 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

This study investigates the mechanisms behind strong water sensitivity in some low-clay-mineral-content tight conglomerate reservoirs in China’s Mahu Sag. Using core-scale water sensitivity tests, mineral analysis, in situ micro-CT scanning, and digital core techniques, we analyzed how water sensitivity alters pore structures across cores of varying permeability. Key findings include the following: (1) Water sensitivity damage increases as initial gas permeability decreases. (2) Despite low clay content, significant water sensitivity arises from the combined effect of water and velocity sensitivity, driven mainly by illite and kaolinite concentrated in gravel-edge fractures and key flow channels. (3) Water sensitivity causes non-uniform pore structure changes—some macropores and throats enlarge locally, reflecting heterogeneity. (4) Structural responses differ by permeability: medium–low permeability cores suffer from clay mineral swelling and particle migration, whereas high-permeability cores resist overall damage and may even have main flow paths enhanced by flushing. (5) Water sensitivity mainly degrades smaller pores but can improve larger ones, with the critical pore-size threshold between macro- and micro-pores inversely related to permeability. This work clarifies the pore-scale mechanisms of water sensitivity in some low-clay-mineral-content tight conglomerates, and can provide guidance for the optimization of water types injected into similar conglomerate reservoirs. Full article

Ultra-deep shale in the Mahu Sag, characterized by difficult-to-drill formations, exhibits high resistivity. This study uses XRD and petrophysical testing on 12 dry core samples (depths 4600–5000 m) to characterize mineral composition and evaluate resistivity-influencing factors. Mineralogical analysis reveals that brittle minerals, dominated by quartz and feldspar (>50%), constitute the primary components of the ultra-deep shale in the Mahu Sag, with quartz, feldspar, and carbonates collectively accounting for ~80%. Clay (~6%) and pyrite (<5%) contents are notably low, resulting in elevated resistivities of 10⁵–10⁷ Ω·m. Resistivity correlates negatively with pyrite (r = −0.588) and feldspar (r = −0.319) but positively with dolomite (r = 0.209), quartz (r = 0.017), and porosity (r = 0.749). At elevated temperatures (100 °C), resistivity declines owing to enhanced ionic conduction. These findings clarify high-resistivity mechanisms, supporting resistivity-based drilling parameter optimization. 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

Due to the complex mineral composition, low clay content, and strong heterogeneity of the mixed sedimentary shale in the Xinjiang Salt Lake Basin, the wettability characteristics of the reservoir and their influencing factors are not yet clear, which restricts the evaluation of oil-bearing properties and the identification of sweet spots. This paper analyzed mixed sedimentary shale samples from the Lucaogou Formation of the Jimsar Sag and the Fengcheng Formation of the Mahu Sag. Methods such as petrographic thin sections, X-ray diffraction, organic matter content analysis, and argon ion polishing scanning electron microscopy were used to examine the lithological and mineralogical characteristics, geochemical characteristics, and pore space characteristics of the mixed sedimentary shale reservoir. Alternating imbibition and nuclear magnetic resonance were employed to quantitatively characterize the wettability of the reservoir and to discuss the effects of compositional factors, lamina types, and pore structure on wettability. Research findings indicate that the total porosity, measured by the alternate imbibition method, reached 72% of the core porosity volume, confirming the effectiveness of alternate imbibition in filling open pores. The Lucaogou Formation exhibits moderate to strong oil-wet wettability, with oil-wet pores predominating and well-developed storage spaces; the Fengcheng Formation has a wide range of wettability, with a higher proportion of mixed-wet pores, strong heterogeneity, and weaker oil-wet properties compared to the Lucaogou Formation. TOC content has a two-segment relationship with wettability, where oil-wet properties increase with TOC content at low TOC levels, while at high TOC levels, the influence of minerals such as carbonates dominates; carbonate content shows an “L” type response to wettability, enhancing oil-wet properties at low levels (<20%), but reducing it due to the continuous weakening effect of minerals when excessive. Lamina types in the Fengcheng Formation significantly affect wettability differentiation, with carbonate-shale laminae dominating oil pores, siliceous laminae contributing to water pores, and carbonate–feldspathic laminae forming mixed pores; the Lucaogou Formation lacks significant laminae, and wettability is controlled by the synergistic effects of minerals, organic matter, and pore structure. Increased porosity strengthens oil-wet properties, with micropores promoting oil adsorption through their high specific surface area, while macropores dominate in terms of storage capacity. Wettability is the result of the synergistic effects of multiple factors, including TOC, minerals, lamina types, and pore structure. Based on the characteristic that oil-wet pores account for up to 74% in shale reservoirs (mixed-wet 12%, water-wet 14%), a wettability-targeted regulation strategy is implemented during actual shale development. Surfactants are used to modify oil-wet pores, while the natural state of water-wet and mixed-wet pores is maintained to avoid interference and preserve spontaneous imbibition advantages. The soaking period is thus compressed from 30 days to 3–5 days, thereby enhancing matrix displacement efficiency. Full article

Unconformity stratigraphic traps are widely developed in the Mahu Sag, on the northwestern margin of the Junggar Basin. It is of great significance for subsequent oil and gas exploration to explore the role of conglomerate accumulation mode and unconformity inner structure in the formation of oil and gas reservoirs. Therefore, this study uses oil and gas geophysical technology combined with geological theory to identify the P/T unconformity structure in the study area, determine the development characteristics and accumulation control of the unconformity structure, and explore the accumulation mode of stratigraphic oil and gas reservoirs. The results show the following: (1) Based on the different logging response characteristics of the upper, middle, and lower layers of the unconformity structure, five types of unconformity structure are divided according to different lithologic combinations. (2) Through experimental and numerical simulation analysis, it was verified that fracture pressure and thickness are important indicators for evaluating the sealing property of unconformity structure. P/T unconformity structure provides good floor conditions for the Baikouquan Formation reservoir, further confirming its key role in the process of oil and gas accumulation and storage. (3) Based on the analysis of actual cases, the accumulation model of stratigraphic oil and gas reservoirs under the control of unconformity structure is summarized as cross-layer accumulation above the source, fault communication source reservoir, unconformity lateral transmission and distribution, and mudstone lateral docking. The research results provide technical support and important reference values for the exploration and development of unconformity-related oil and gas reservoirs in the Junggar Basin. Full article

The exploration of the Fengcheng Formation has revealed the characteristic orderly coexistence of conventional reservoirs, tight reservoirs, and shale reservoirs, constituting a full spectrum of reservoir types, and is important for unconventional oil and gas exploration and development. Affected by frequent volcanic tectonic movement, hot and dry paleoclimate, and the close provenance supply distance, unique saline–alkaline lacustrine deposits formed during the depositional period of the Fengcheng Formation. The lithologies of the Fengcheng Formation are highly diverse, with endogenous rocks, volcanic rocks, terrigenous debris, and mixed rocks overlapping and forming vertical reservoir changes ranging from meters to centimeters. Owing to the complexity of rock types and scarcity of rock samples, the evaluation of reservoirs in mixed-rock has progressed slowly. Hence, we aimed to evaluate the characteristics of Fengcheng Formation shale oil reservoirs. Centimeter-level core characteristics were analyzed based on the lithological change and structural characteristics. To investigate the lithofacies of the Fengcheng Formation in the Mahu Sag and factors affecting reservoir development, high-frequency sedimentary structures were analyzed using sub-bio-buffering electron microscopy, energy spectrum testing, and fluorescence analysis. The results showed that the shale oil reservoirs in the study area can be divided into four categories: glutenite, volcanic rock, mixed rock, and endogenous rock. The reservoir capacity has improved and can be divided into eight subcategories. Mixed-rock reservoirs can be further divided into four subcategories based on differences in structure and composition. Differences in the bedding and dolomite content are the main factors controlling the differences in the physical properties of this type of reservoir. This study provides a reference for the classification and characteristic study of shale oil reservoirs in saline–alkali lake basins. Full article

The Mahu Sag, where the Mahu 1 well block is located, is one of the most important hydrocarbon-rich depressions in the Junggar Basin, NW China. The Permian Upper Wuerhe Formation (UWF) constitutes the primary layer of the unconventional tight oil reservoir in the Mahu Oilfield. To explore the provenance and sedimentary environment during the deposition of the UWF in the study area, we determined the clay mineralogy and whole-rock geochemical composition of argillaceous rocks. The results show that the primary minerals in argillaceous rock are feldspar, clay minerals, quartz, and a minor amount of hematite. The clay minerals identified included illite, smectite, kaolinite, chlorite, and illite/smectite mixed layers. The tectonic setting of the provenance area for the UWF is a continental island arc, associated with a cutting magmatic arc. The main provenance area is related to the Baogutu tectonic belt (the Zhayier Mountain and the Hala’alate Mountain). The bedrock primarily consists of acidic igneous rocks, with minor occurrences of intermediate–basic igneous and sedimentary rock. The chemical index of alteration (CIA) shows that the parent rocks of the argillaceous rocks have experienced moderate–strong chemical weathering. Combining the Sr/Cu and ΣLREE/ΣHREE ratios, δEu values, and clay mineral characteristics, we determined that the paleoclimate during the deposition of the UWF was generally warm and humid, with occasional short-term dry and cold periods. The UWF gradually changes, according to the relative humidity and enhanced chemical weathering from the bottom to the top. An analysis of trace elements, paleosalinity, and paleowater depth indicate that the studied argillaceous rocks were deposited in a shallow-water oxidation environment of continental fresh water with weak hydrodynamic conditions. Full article

Unconformities are of significant interest to petroleum geologists because of their crucial roles in influencing reservoir quality and controlling oil and gas migration. This study investigates the impact of unconformities on a reservoir within a prolific oil–gas-bearing zone between the Middle Permian and Lower Triassic strata in the northwestern Junggar Basin, utilizing thin sections, well logging data, seismic profiles, and geochemical analyses. The results reveal a well-developed three-layer unconformity structure characterized by a thick weathered clay layer, which acts as an effective caprock for hydrocarbons. The diagenetic evolution of the Lower Wuerhe Formation in the northwestern Junggar Basin consists of an initial stage of compaction followed by a subsequent stage of dissolution and cementation. Four key factors, including low argillaceous content in sandstone and conglomerate, diagenetic compaction, zeolite dissolution and cementation, and clay mineral infill, have played a crucial role in influencing the reservoir characteristics of the Lower Wuerhe Formation. In addition, the development of unconformities promotes atmospheric freshwater leaching, which enhances the dissolution of the underlying reservoir while developing an extensive network of strike-slip faults that improve connectivity within hydrocarbon reservoirs. This process facilitates both vertical and lateral migration of hydrocarbons along hard rock layers, which allows the unconformity to breach into the overlying conglomerate reservoirs. The results of this study suggest that the reservoir in proximity to the unconformity surface often exhibits high porosity and rich hydrocarbon content, offering valuable insights for future oil and gas exploration and development. Full article