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Article

Integrated Lithofacies, Diagenesis, and Fracture Control on Reservoir Quality in Ultra-Deep Tight Sandstones: A Case from the Bashijiqike Formation, Kuqa Depression

by
Wendan Song
1,2,
Zhaohui Xu
1,2,*,
Huaimin Xu
1,2,
Lidong Wang
3 and
Yanli Wang
4
1
State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing), Beijing 102249, China
2
College of Geosciences, China University of Petroleum (Beijing), Beijing 102249, China
3
Dina Oil & Gas Production Management Area, PetroChina Tarim Oilfield Company, Korla 841000, China
4
Kela Oil & Gas Production Management Area, PetroChina Tarim Oilfield Company, Korla 841000, China
*
Author to whom correspondence should be addressed.
Energies 2025, 18(19), 5067; https://doi.org/10.3390/en18195067
Submission received: 6 August 2025 / Revised: 17 September 2025 / Accepted: 19 September 2025 / Published: 23 September 2025
(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)
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Abstract

Fractured tight sandstone reservoirs pose challenges for gas development due to low matrix porosity and permeability, complex pore structures, and pervasive fractures. This study focuses on the Bashijiqike Formation in the Keshen Gas Field, Kuqa Depression, aiming to clarify the geological controls on reservoir quality. Lithofacies, diagenetic facies, and fracture facies were systematically classified by core analyses, thin sections, scanning electron microscopy (SEM), cathodoluminescence (CL), X-ray diffraction (XRD), grain size analyses, mercury intrusion capillary pressure (MICP), well logs and resistivity imaging logging (FMI). Their impacts on porosity, permeability and gas productivity were quantitatively assessed. A ternary reservoir quality assessment model was established by coupling these three factors. Results show that five lithofacies, four diagenetic facies, and four fracture facies jointly control reservoir performance. The high-energy gravelly sandstone facies exhibit an average porosity of 6.0% and average permeability of 0.066 mD, while the fine-grained sandstone shows poor properties due to compaction and clay content. Unstable component dissolution facies enhance secondary porosity to 6.0% and permeability to 0.093 mD. Reticulate and conjugate fracture patterns correspond to gas production rates two to five times higher than those with single fractures. These findings support targeted reservoir classification and improved development strategies for ultra-deep tight gas reservoirs.

1. Introduction

With the progressive depletion of conventional hydrocarbon resources and increasing global energy demand, ultra-deep tight sandstone reservoirs have emerged as significant targets for petroleum exploration and development. Their widespread occurrence and substantial resource potential render them crucial for future energy supply security [1,2,3,4]. The definitions of “ultra-deep” reservoirs vary among countries and research institutions. Russian scholars typically classify reservoirs deeper than 4000 m as deep reservoirs [5]. According to the United States Geological Survey, reservoirs located below 4500 m are classified as deep, whereas those exceeding 7620 m are considered ultra-deep [6]. In China, reservoir classifications vary according to geographic region. In western basins, depths between 4500 m and 6000 m are categorized as deep, whereas depths beyond 6000 m are defined as ultra-deep. Conversely, in eastern basins, reservoirs deeper than 4500 m are classified as ultra-deep [7,8]. Tight sandstone reservoirs are typically characterized by matrix permeability below 0.1 mD [9]. Although these reservoirs exhibit low porosity and permeability, natural fracture networks can significantly enhance fluid flow efficiency. Consequently, fractured tight sandstone reservoirs have emerged as critical targets for the exploitation of unconventional hydrocarbon resources [10,11].
Ultra-deep fractured tight sandstone reservoirs are often characterized by substantial heterogeneity, complex fracture systems, and multi-stage diagenesis. These features lead to considerable variation in reservoir quality and pose significant challenges for effective exploration and development [12,13,14]. Previous research has investigated the controls on reservoir quality from three main perspectives: sedimentary processes, diagenetic evolution, and structural deformation. Sedimentary controls are commonly assessed through lithofacies and microfacies analysis [15,16]. Diagenetic influences are evaluated by reconstructing diagenetic sequences, identifying authigenic mineral assemblages, and analyzing the effects of cementation, dissolution, and compaction [17,18]. Structural controls are typically studied using fracture system characterization and burial history analysis [19,20]. Recent studies have begun to explore multi-factor coupling mechanisms [21,22]. For example, lithofacies–diagenesis coupling has shown that lithofacies strongly influence early diagenetic pathways and porosity evolution [23,24]. Similarly, structural–diagenetic interactions emphasize the role of tectonic activity in guiding fluid migration and cementation during burial and uplift [25,26]. Despite these efforts, a systematic understanding of the combined effects of lithofacies, diagenesis, and structural deformation remains limited. Further research is needed to clarify how these interacting geological processes collectively influence the petrophysical characteristics of tight sandstone reservoirs.
The Keshen gas field, situated in the Kuqa Depression, serves as a representative example of an ultra-deep fractured tight sandstone reservoir system. The field comprises thick, extensive sandstone successions. Nevertheless, exploration efficiency remains low due to insufficient characterization of lithofacies associations and poorly understood relationships among lithofacies, fracture networks, and diagenetic alterations. Therefore, to address the challenges of reservoir quality prediction and reduce exploration risks, this study aims to establish a comprehensive and quantitative classification framework for reservoir quality, providing theoretical support for subsequent analysis of reservoir spatial distribution. This scheme is developed by integrating a comprehensive array of geological and petrophysical datasets. These datasets include core descriptions, thin-section petrography, fracture characterization, conventional well logs, and FMI. Lithofacies were classified based on sedimentary textures and inferred depositional hydrodynamic conditions. Diagenetic facies were identified based on petrographic characteristics, including cement types, compaction fabrics, and dissolution features. Fracture assemblages were interpreted from image logs, focusing on fracture orientation, density, and connectivity. Subsequently, a multi-scale analysis was conducted to examine both the individual and combined effects of sedimentary architecture, diagenetic alterations, and fracture systems on reservoir quality. These insights were integrated to establish a comprehensive classification framework for the Bashijiqike Formation. The proposed framework provides a geologically robust basis for evaluating reservoir heterogeneity and predicting favorable reservoir intervals in ultra-deep tight sandstone reservoirs.

2. Geological Setting

The Kuqa Depression is located along the northern margin of the Tarim Basin in northwestern China. It has been significantly affected by both Yanshanian and Himalayan tectonic events, which have shaped a complex structural architecture comprising four major structural belts and three secondary sub-depressions (Figure 1a). The depression trends approximately NEE, extending about 550 km from east to west and spanning 40 ~ 90 km from north to south, with a total areal extent of roughly 37,000 km2 [13,27,28,29]. Among these tectonic units, the Kelasu Structural Belt occupies the northern part of the Kuche Depression and is juxtaposed against the South Tianshan Orogenic Belt. It is bounded to the north by the Monocline Belt and to the south by the Baicheng Sub-depression (Figure 1b). The Kelasu Belt exhibits a distinct NEE structural trend and is subdivided into five segments from west to east: the Awate, Bozi, Dabei, Keshen, and Kela zones [30,31,32]. This study focuses on the Keshen gas reservoir, situated in the eastern part of the Keshen Zone. The reservoir is characterized by an EW structural orientation and has undergone significant compressional deformation. This tectonic regime resulted in the development of numerous faults and fracture systems, which increased reservoir heterogeneity and facilitated the formation of effective structural traps. Consequently, the Keshen reservoir represents one of the most productive gas-bearing zones within the Tarim Basin [33,34].
Drilling data from the Keshen gas reservoir in the Kuche Depression reveal a stratigraphic succession that includes Cretaceous, Paleogene, Neogene, and Quaternary strata [35] (Figure 2). The Cretaceous Bashijiqike Formation is the principal gas-bearing unit in the study area. It occurs at burial depths of approximately 6500–7000 m. Due to tectonic uplift and erosion during the Late Cretaceous, it is unconformably overlain by younger strata [36]. The Bashijiqike Formation is mainly composed of laterally continuous sandstones with relatively uniform thickness. Based on lithological features and sedimentary cyclicity, the formation is subdivided into three members: K1bs1, K1bs2, and K1bs3 [37]. K1bs1 and K1bs2 were deposited under relatively stable tectonic conditions. During this period, basement uplift and subsidence were gentle and continuous, forming a low-relief terrain that allowed slow sediment transport. These conditions favored the development of a braided river delta system [38]. Vertically, the K1bs1 and K1bs2 intervals exhibit more rhythmic, stacked fining-upward successions. Individual layers commonly initiate at a scoured base typical of channelized sand bodies, grading upward from medium- to fine-grained sandstone into siltstone and mudstone. This vertical stacking pattern indicates deposition dominated by sustained and stable traction currents, occasionally interrupted by pebbly and conglomeratic sandstone layers. In contrast, the K1bs3 unit was deposited during a period of intense tectonic activity and rapid basin subsidence. These processes created significant topographic relief between the source area and the sedimentary basin, leading to the development of a lacustrine fan delta system. This succession is characterized by an overall coarsening-upward sequence with poorly defined internal cyclicity. It consists of frequent interbeds of sandy conglomerate, pebbly sandstone, and brown mudstone, accompanied by common soft-sediment deformation structures and debris flow deposits, collectively indicating rapid sediment accumulation near the source under highly unstable hydrodynamic conditions. Laterally, the sand bodies within the K1bs3 lacustrine fan delta front show poor continuity and rapid thickness variation. They are largely restricted to areas near sediment point sources and exhibit prominent lateral pinch-outs. Conversely, the K1bs1 and K1bs2 braided delta front sand bodies demonstrate well-developed lateral continuity and sheet-like geometry. Their thickness remains relatively consistent over large areas, and the sand units can be confidently correlated between wells, providing the foundational framework for high-quality reservoir development across the region [39,40] (Figure 2).

3. Samples and Experiments

This section describes the materials and experimental methodologies used to characterize the tight sandstone reservoirs of the Bashijiqike Formation. It consists of two subsections: the first introduces the core samples and the multi-scale dataset integrated for analysis, and the second details the laboratory techniques employed to evaluate the petrophysical, mineralogical, and geomechanical properties of the reservoirs.

3.1. Samples and Data

A comprehensive dataset was assembled to evaluate the tight sandstone reservoirs of the Bashijiqike Formation, integrating core observations, petrophysical analyses, conventional wireline logs, image logs, and well test results. The types and volumes of acquired data are summarized in Table 1.

3.2. Experiments and Methods

A series of advanced experimental techniques were employed to characterize the reservoir properties. All analyses were conducted at the Tarim Oilfield Exploration and Development Research Institute and associated laboratories (Figure 3). Thin sections were examined using a LABORLUX-12POL polarizing microscope, following the SY/T 5368-2000 standard [41]. To differentiate carbonate minerals such as calcite and dolomite, Alizarin Red S staining was applied under transmitted light. SEM was carried out using a Quanta200 microscope following SY/T 5162-1997 [42]. This method enabled high-resolution imaging of pore structures, fractures, and mineral morphologies, aiding in the interpretation of diagenetic processes. CL analysis was performed using a LABORLUX-12POL microscope equipped with an ELM-3RX cold cathode CL system, following SY/T 5916-1994 and SY/T 5368-2000 standards [41,43]. This technique provided insights into cement types, distribution patterns, and diagenetic sequences. Mineralogical compositions were determined using a D/max-2500PC XRD following SY/T 5163-2010 [44]. Both bulk-rock and clay-sized fractions (<2 μm) were analyzed, with pre-treatment involving glycerol saturation and heating to facilitate clay mineral identification. Porosity and permeability were measured using the Core Lab UltraPoreTM-300 helium porosimeter and UltraPermTM-400 air permeameter, following SY/T 5336-2006 [45]. Selected samples were further analyzed using a 9505 mercury intrusion apparatus following the SY/T 5346-2005 standard to characterize pore throat size distributions [46]. Core analysis involved detailed lithological descriptions and depth correction. Grain size distribution and sediment sorting were evaluated using a MasterSizer 2000 laser diffraction analyzer, following the SY/T 5434-2009 standard [47]. In addition, FMI was conducted using Schlumberger’s Fullbore Formation MicroImager. Data were corrected for temperature effects and interpreted using the Techlog platform to identify fracture orientations, assemblages, and their implications for reservoir quality. All experimental procedures adhered to Chinese petroleum industry standards and collectively provided a comprehensive dataset for evaluating the mineralogical, structural, petrophysical, and fracture characteristics of the reservoir.

4. Results

This section outlines the key findings of the study, which are organized into three subsections: lithofacies and lithofacies assemblage characteristics, diagenetic features, and fracture characteristics. The analysis begins with lithofacies classification to establish the depositional context and initial reservoir architecture. This is followed by an evaluation of diagenetic processes and the classification of diagenetic facies, providing a framework for assessing the impact of diagenesis on reservoir quality. The final subsection addresses structural fractures, which constitute essential conduits for fluid flow in deeply buried reservoirs. Together, these analyses offer an integrated understanding of the multi-scale factors governing reservoir heterogeneity and productivity in the Bashijiqike Formation.

4.1. Lithofacies and Lithofacies Assemblage Characteristics

This subsection systematically characterizes the sedimentary architecture and depositional processes of the Bashijiqike Formation through the analysis of lithofacies and their assemblages. It begins with a detailed classification and description of individual lithofacies units, which serve as the fundamental building blocks for characterizing reservoir heterogeneity across macro to micro scales. Subsequently, lithofacies assemblages are categorized based on the vertical stacking patterns of sand bodies to represent complete depositional environment units.

4.1.1. Lithofacies Classification

Lithofacies classification is essential for understanding sedimentary processes and depositional environments. Although various classification schemes have been employed across different geological settings, they are often adapted to local sedimentological characteristics [48,49]. In this study, lithofacies within the fractured tight sandstone reservoir of the Bashijiqike Formation were defined by integrating sedimentary microfacies analysis, hydrodynamic conditions, rock types, pore types, and grain size characteristics (Table 2). It is important to emphasize that the absence of sedimentary structures in the lithofacies identification is due to poor core preservation, which has made bedding structures nearly indistinguishable. Furthermore, the classification of sedimentary microfacies did not include mouth bars, as frequent channel migration in the study area has made them difficult to preserve. Five distinct lithofacies were identified: gravelly sandstone of an underwater distributary channel (LF1), muddy conglomeratic sandstone of an underwater distributary channel (LF2), medium-grained sandstone of an underwater distributary channel (LF3), fine-grained sandstone of an underwater distributary channel (LF4), and mudstone of an interdistributary bay (LF5).
LF1 occurs at the base of channels and reflects intense erosion and rapid sediment accumulation associated with flood events or high-energy braided flows. The lithology comprises gravelly fine-grained sandstone and gravelly medium-grained sandstone. Gravel clasts generally range from 0.2 to 1 cm in diameter, with maximum sizes up to 6 cm. These clasts are randomly distributed and occasionally exhibit elongate morphologies. Reservoir pores are well developed, dominated by primary intergranular and intragranular dissolution pores. Detrital grains display moderate to good sorting, angular to subangular shapes, and predominantly point-to-line contacts. LF1 is primarily transported by rolling and saltation. Grain-size distribution curves for conglomeratic sandstone display steep slopes in the gravel-size fraction, indicating a rapid increase in cumulative frequency. This suggests rapid gravel accumulation under high-energy depositional conditions.
LF2 represents intermittent high-energy depositional environments characterized by unstable hydrodynamic conditions and rapid facies transitions. It typically develops near scour surfaces at channel bases. Lithologies consist of muddy conglomeratic fine- and medium-grained sandstone. The muddy conglomeratic sandstone contains a small amount of argillaceous clasts, unevenly dispersed within a matrix-supported texture. Mud clasts exhibit moderate sorting and subangular to angular shapes. Some clasts show evidence of plastic deformation, including torn and bent morphologies. Effective porosity is absent. Detrital grains display good to moderate sorting, angular to subangular shapes, and primarily point-to-line contacts. LF2 is deposited through a combination of rolling, saltation, and suspension. Fluctuating hydraulic energy enables the co-transport and deposition of gravels and sands. Periodic disturbances introduce fine-grained muddy sediments into the depositional system, forming muddy conglomeratic sandstones. Gravels and sands are deposited under high-energy conditions by rolling and saltation, while muddy components are transported in suspension and settle in relatively low-energy environments.
LF3 is predominantly developed in the central parts of underwater distributary channels, representing steady sediment transport and continuous deposition under normal flow conditions. The lithology is characterized by relatively high quartz and feldspar contents. Reservoir pores are moderately developed and include minor amounts of primary intergranular pores, intergranular and intragranular dissolution pores, micropores, and locally enlarged intergranular pores. Detrital grains show moderate sorting, subangular shapes, and predominantly point-to-line contacts. LF3 is primarily transported by saltation. The gentle slope observed in the grain-size curve for the saltation fraction indicates stable hydraulic conditions during deposition and well-sorted sandstone grains.
LF4 is the most widespread lithofacies in the study area. It typically occurs at the distal ends and margins of underwater distributary channels, indicating suspended-load deposition under diminished hydrodynamic energy. Quartz and feldspar contents are moderate. Reservoir pores are well developed and consist of primary intergranular pores, intergranular dissolution pores, intragranular dissolution pores, and locally enlarged intergranular pores. Detrital grains exhibit moderate to poor sorting, subangular shapes, and mainly point-to-line contacts. LF4 contains a relatively higher proportion of saltation-sized particles compared to typical medium-grained sandstone, suggesting enhanced transport by saltation under moderately energetic conditions.
LF5 corresponds to the interdistributary bay mudstone lithofacies, which reflects a low-energy, quiescent depositional environment. Lithologies are primarily composed of mudstone, argillaceous sandstone, and silty mudstone. Microscopic observations reveal a high content of iron-stained matrix material. Reservoir pores are poorly developed, and no effective porosity is observed. Grains are angular to subangular and predominantly exhibit point contacts.

4.1.2. Lithofacies Assemblage Classification

Based on lithofacies classification and corresponding hydrodynamic conditions, the vertical stacking patterns of underwater distributary channel microfacies in the Bashijiqike Formation of the Keshen gas reservoir were systematically identified. Three distinct lithofacies associations were recognized: gravelly sandstone representing high-energy braided underwater distributary channels (FA1), muddy conglomeratic sandstone indicative of high-energy braided underwater distributary channels (FA2), and medium- to fine-grained sandstone associated with low-energy braided underwater distributary channels (FA3).
FA1 is interpreted as high-energy channel-lag and channel-fill deposits. It occurs at the base of channels and reflects intense erosion and rapid sediment accumulation associated with flood events or peak flow conditions. The association is characterized by a basal layer of brownish, moderately to well-sorted and rounded gravelly sandstone. The base is marked by a distinct erosional surface scoured into the underlying strata. GR logs generally display serrated box-shaped patterns or low-amplitude box- to bell-shaped composite motifs. Correspondingly, resistivity logs typically exhibit high-resistivity box-shaped or bell-shaped signatures (Figure 4a). The lithological characteristics and log patterns are consistent with deposition in the highest-energy zones of distributary channels.
FA2 is interpreted as episodic cohesive flow deposits. This interpretation is supported by the presence of abundant, randomly distributed mud clasts within a sandy matrix, which exhibit evidence of plastic deformation (bending and tearing). These features suggest the co-transport and deposition of cohesive muddy sediments and non-cohesive sands as a single, poorly sorted mass, a process characteristic of debris flows or hyperconcentrated flows. These event-driven flows were likely triggered by bank collapse during periods of intense channel scour or flash floods, which incorporated mud clasts from semi-consolidated bank materials. Gamma-ray and resistivity logs display highly serrated box- or bell-shaped profiles, which reflect the drastic grain-size variations resulting from these short-lived, high-energy events (Figure 4b). FA3 was developed under relatively weak hydrodynamic conditions and is typically located in the distal parts of underwater distributary channels. The lithology is dominated by well-sorted medium- to fine-grained sandstone. Vertically, the deposits consist of multiple stacked single-channel sand bodies, suggesting frequent lateral channel migration with limited erosional activity. GR logs generally exhibit smooth box-shaped or bell-shaped patterns. Correspondingly, resistivity logs commonly display moderate-resistivity bell-shaped or funnel-shaped responses (Figure 4c).

4.1.3. Lateral and Vertical Distribution of Lithofacies

Based on the statistical analysis of lithofacies from cored wells, the target layer in the KS2 block is predominantly composed of FA3 and FA4, with average proportions of 36.3% and 36.1%, respectively, followed by FA2 at 18.4%. Spatially, FA1 is primarily developed near wells W8 and W1 in the anticlinal core, while the frequencies of FA4 and FA5 increase from north to south. Notably, the frequency of FA5 reaches 67% in well W14. This distribution pattern is attributed to the provenance direction of the Keshen 2 gas field, which is mainly from the Tianshan orogenic belt to the north. Toward the basin center to the south, the grain size of sedimentary particles gradually fines (Figure 5a).
Vertically, the overall proportion of lithofacies in K1bs3 is lower than that in K1bs2 and K1bs1. Specifically, the frequencies of FA1 and FA2 in K1bs1 are significantly higher than those in K1bs2 and K1bs3, reaching 6.0% and 19.1%, respectively. In contrast, FA3 shows a relatively uniform distribution throughout the vertical profile. The proportions of FA4 in K1bs1 and K1bs2 are notably higher than in K1bs3, reaching 33.1% and 44.8%, respectively. Within the same stratigraphic unit, FA3 and FA4 consistently exhibit the highest proportions, whereas FA1 shows the lowest frequency (Figure 5b).
It is important to note that the spatial distribution of facies associations is difficult to constrain, primarily due to the limited number of wells and their wide spacing, which hinders reliable correlation between boreholes. As a result, interpreting depositional environments and their vertical evolution remains challenging.

4.2. Diagenetic Features

4.2.1. Diagenesis Types

Thin section and SEM analyses demonstrate that the Bashijiqike Formation has undergone substantial compaction, cementation, and dissolution during its diagenetic evolution. At burial depths exceeding 6000 m, and under intense tectonic compression associated with the late Himalayan orogeny, detrital grains exhibit preferred orientations indicative of both vertical and lateral compaction. Intragranular fractures are commonly observed within rigid mineral grains such as quartz and feldspar, attributed to compaction-induced stress (Figure 6a). Despite deep burial, the overall compaction intensity remains relatively low. This is primarily due to an extended period of shallow burial followed by a brief episode of rapid deep burial. Moreover, early-stage carbonate cementation and the development of overpressure conditions effectively mitigated compaction effects, aiding in the preservation of primary intergranular porosity. Grain contacts are mainly of point-line and line types, with point contacts occurring infrequently (Figure 6b).
Three main cement types are identified: carbonate, clay minerals, and siliceous cement. Due to deposition under arid and alkaline conditions, carbonate and clay mineral cements are abundant, whereas quartz overgrowths are rare. Petrographic observations indicate that carbonate cements are composed of calcite, dolomite, quartz, feldspar, anhydrite, and clay minerals, with pore-filling textures being dominant. Locally, film-like and film–pore composite cementation patterns are also observed. Calcite and dolomite are the principal carbonate cements. Thin-section and CL images show that calcite primarily occurs as pore-filling cement in both intergranular and intragranular dissolution pores. Dolomite appears in two modes: basal and pore-filling. In basal cementation, dolomite occupies intergranular spaces between quartz, feldspar, and lithic grains, providing structural support against late-stage compaction. In pore-filling mode, dolomite partially fills residual pore space but is less abundant (Figure 6c–e).
XRD analyses reveal that clay minerals are dominated by illite and illite–smectite mixed layers(I/S), with average contents of 34.1% and 41.6%, respectively. Minor quantities of chlorite and kaolinite are also present (Figure 7). The I/S represent transitional products of smectite alteration during progressive burial. Illite typically occurs as interlayered forms and occasionally as discrete crystals, often manifesting as lamellar aggregates within pore spaces (Figure 6f). Chlorite forms leaf-like and honeycomb-shaped aggregates, usually found on grain surfaces or between grains (Figure 6g,h). Kaolinite, though less common, appears in platy or tabular morphologies within intergranular pores (Figure 6i). Two distinct generations of clay minerals are recognized. Early-formed chlorite rims and illite coatings act as protective clay layers that preserve primary intergranular porosity and inhibit quartz and feldspar overgrowth. These coatings are frequently associated with the dissolution of potassium feldspar and are considered favorable for reservoir quality. In contrast, late diagenetic illite and chlorite are characterized by pore-filling and pore-lining habits. These phases occupy substantial pore volume, reduce porosity and permeability, restrict pore throat connectivity, and ultimately degrade reservoir quality.
Siliceous cementation mainly consists of quartz and authigenic quartz overgrowths (Figure 6j). SEM images reveal that quartz fills intergranular pores. Although quartz overgrowths decrease the size of primary pores and throats, which negatively affects permeability, they strengthen the rock matrix’s mechanical properties, thus enhancing resistance to compaction.
Dissolution is a key constructive diagenetic process that significantly enhances reservoir quality. Microscopic observations indicate that unstable components such as feldspar, lithic fragments, and albite are prone to dissolution. Dissolution typically initiates along grain boundaries and cleavage planes, producing various secondary pore types, including enlarged dissolution pores, intragranular pores, and moldic pores. Some of these pores are subsequently filled by calcite, dolomite, or anhydrite (Figure 6k).
Compaction-induced fracturing of rigid grains results in the development of diagenetic microfractures. These features improve fluid migration and promote subsequent dissolution and cementation. Quartz, feldspar, and lithic grains are particularly susceptible to such fracturing. Microfracture zones often contain minor secondary dissolution pores (Figure 6l). However, since reservoir permeability in the Keshen gas field is predominantly governed by tectonic fractures, the contribution of diagenetic microfractures to overall reservoir performance is limited and thus not discussed further.

4.2.2. Diagenetic Facies Types

Based on diagenetic processes and associated mineral assemblages, four distinct diagenetic facies have been identified in the Bashijiqike Formation. These include the unstable component dissolution facies (DF1), carbonate cementation facies (DF2), illite–smectite interlayer filling facies (DF3), and compaction-densified facies (DF4).
DF1 is characterized by the intense dissolution of chemically unstable grains, primarily feldspar and lithic fragments. The dissolution process generates abundant secondary porosity, including both intergranular and intragranular dissolution pores. These pores are commonly partially filled by clay minerals or carbonate cements, indicating subsequent diagenetic precipitation. In ultra-deep reservoirs of the Bashijiqike Formation, DF1 significantly enhances reservoir quality and thus represents a key interval for high-quality reservoir identification. Petrographically, DF1 is marked by relatively coarse grain size, good sorting, and low matrix content. Well log responses typically exhibit moderate to low values in GR, DEN, and CNL logs (Figure 8a).
DF2 is widespread across the study area and is defined by extensive carbonate cementation. During early diagenesis, weak compaction permitted the early precipitation of carbonate cement within primary intergranular pores, often giving grains a “floating” appearance. At the middle diagenetic stage, late-stage carbonate cement occupies secondary dissolution pores in the form of authigenic minerals [12]. While early cementation helps preserve porosity by resisting mechanical compaction, the facies typically contain limited and poorly connected secondary pores. Consequently, DF2 rarely evolves into an effective reservoir. Logging responses are characterized by moderate GR, moderate CNL, and moderate to high DEN values (Figure 8b).
DF3 is associated with high concentrations of illite and I/S mixed-layer minerals. DF3 represents a transitional phase in the smectite-to-illite transformation and is commonly observed filling pore spaces. These clay minerals exhibit strong water sensitivity, which severely reduces effective permeability. Illite often forms through feldspar alteration and is typically associated with quartz overgrowths. Hence, features such as feldspar dissolution and quartz cementation are commonly observed. The well log signature of DF3 includes moderate to high GR, moderate DEN, and moderate to high CNL values (Figure 8c).
Under microscopic observation, DF4 is composed mainly of fine sand, with subordinate silt. The facies contain a high content of muddy matrix, which lowers the rock’s resistance to compaction. During late-stage diagenesis, it undergoes intense mechanical compaction, resulting in the near-total loss of intergranular porosity. Grain contacts are predominantly linear, reflecting strong compaction. Well log responses are typically marked by moderate to high GR, high DEN, and high CNL values (Figure 8d).

4.3. Fracture Characteristics

This section systematically analyzes the fracture characteristics of the Bashijiqike Formation. It begins with a classification of genetic fracture types and their morphological features. Subsequently, the spatial arrangement and connectivity of the fractures are investigated through the identification of characteristic fracture combination patterns. Together, these analyses provide key insights into the controls on productivity in the Keshen gas reservoir. The fractures analyzed in this study are all natural structural fractures identified based on core samples and FMI images, excluding artificial fractures induced by drilling or mechanical damage.

4.3.1. Genetic Types and Characteristics of Structural Fractures

In the Keshen gas reservoir, 80.2% of the fractures observed in 15 cored wells are shear fractures. These fractures typically display planar, smooth surfaces with consistent orientations and regular spatial distribution. In contrast, extensional fractures are less frequent. They are generally shorter, exhibit more irregular orientations, and have comparatively rougher surfaces (Figure 9). Based on dip angle, fractures in the Keshen reservoir can be classified into four categories: vertical, high-angle, low-angle, and horizontal fractures. Vertical fractures are the most prevalent, comprising 54.7% of the total, followed by high-angle fractures at 25.4%. Most structural fractures are well-cemented, with a mineral infilling rate of 77.2%. The predominant cementing minerals include calcite, anhydrite, and dolomite. The formation of fracture cements in the Keshen Gas Field primarily occurs during the early to middle diagenetic stage. In contrast, late-stage fractures coincide with hydrocarbon charging, and fluid activity inhibits cementation or leads to dissolution. Fracture apertures typically range from 0.4 mm to 0.6 mm, with a maximum observed aperture of 4 mm (Figure 10).

4.3.2. Fracture Combination Patterns

Core and image log interpretations further identify four principal fracture combination patterns in the study area: isolated fractures (FF1), parallel fractures (FF2), conjugate fractures (FF3), and networked fractures (FF4). FF1 consists of single, independently developed fractures. These are characterized by relatively uniform spacing and significant separation from adjacent fractures, indicating limited connectivity (Figure 11a). FF2 includes multiple similarly shaped or sinusoidal fractures that are arranged approximately parallel to one another. These are generally aligned with the bedding strike and are widely distributed in the Keshen gas field (Figure 11b). FF3 is defined by a primary fracture set accompanied by several sub-parallel subsidiary fractures. This pattern commonly forms X- or V-shaped geometries and is predominantly associated with shear deformation (Figure 11c). FF4 comprises irregularly distributed fractures that intersect to form mesh-like networks. These are also mainly of shear origin; however, their overall development in the study area is relatively limited (Figure 11d).

5. Discussion

This section provides a comprehensive analysis of the factors influencing the reservoir quality of the Bashijiqike Formation, integrating various aspects such as sedimentation, diagenesis, and fractures. The discussion begins by separately examining the impacts of lithofacies, diagenetic processes, and fracture systems on reservoir characteristics. Subsequently, these factors are consolidated into a unified “reservoir-controlling ternary diagram” model, establishing a practical classification scheme for reservoir evaluation and prediction.

5.1. Controlling Factors of Reservoir Quality

This section presents a comprehensive analysis of the factors governing reservoir quality in the Bashijiqike Formation, with an emphasis on the controlling effects of depositional, diagenetic, and structural elements. By integrating lithofacies, diagenetic facies, and fracture characteristics, this study aims to elucidate the mechanisms controlling porosity, permeability, and hydrocarbon productivity within this ultra-deep tight sandstone reservoir.

5.1.1. Lithofacies Control on Reservoir Quality

Lithofacies represent a primary control on reservoir quality, as their influence governed mainly by the prevailing depositional hydrodynamic conditions. Variations in grain size, matrix content, and sorting characteristics across different lithofacies exert a direct impact on porosity and permeability [50,51,52]. In the Bashijiqike Formation of the Keshen gas field, petrophysical analysis reveals that LF1 exhibits the most favorable reservoir properties, with average porosity and permeability values of 6.0% and 0.066 mD, respectively. LF2 and LF3 follow, with an average porosity of 4.7% and 4.5%, and an average permeability of 0.042 mD and 0.035 mD, respectively. LF4 displays the poorest reservoir characteristics, with an average porosity of 3.3% and permeability of 0.029 mD (Figure 12a,b).
Crossplots of porosity versus median grain size and clay–matrix content show a clear positive correlation. Coarser grain sizes and lower matrix content are linked to higher porosity, indicating that deposition under stronger hydrodynamic conditions promotes the development of more effective reservoir properties (Figure 12c,d). Conversely, the sorting coefficient displays no consistent relationship with porosity or permeability, likely because of the limited range of sorting variation among the studied lithofacies, which are generally moderately to well sorted.
Reservoir quality can be significantly influenced by unstable depositional energy. Well-sorted conglomerates, for instance, often contain intergranular pores filled with finer particles, leading to decreased pore connectivity and lower overall reservoir quality compared to poorly medium-grained sandstones and fine-grained sandstones (Figure 12e,f).
Lithofacies assemblage also exerts a moderate control on reservoir quality. Sand bodies formed in high-energy, underwater distributary channel environments tend to have higher porosity and permeability than those deposited under lower-energy conditions. Among all identified associations, FA1 is the most favorable depositional setting for developing high-quality reservoirs (Figure 13).

5.1.2. Diagenetic Facies Control on Reservoir Quality

Petrographic and petrophysical data from the Bashijiqike Formation in the Keshen Gas Field indicate that diagenetic facies exert a significant control on reservoir quality. Distinct differences in average porosity and permeability are observed among the different facies (Figure 14a). Among them, DF1 exhibits the most favorable reservoir properties, with an average porosity of 6.0% and an average permeability of 0.093 mD. DF2 shows moderately lower values, with an average porosity of 4.2% and an average permeability of 0.041 mD. DF3 reflects further degradation in reservoir quality, with an average porosity of 3.3% and an average permeability of 0.027 mD. DF4 demonstrates the poorest performance, with an average porosity of 2.7% and an average permeability of 0.018 mD.
These variations are primarily governed by differences in porosity, clay content, and the distribution of diagenetic minerals. The presence of dissolution-related secondary pores enhances porosity, whereas high clay content tends to diminish it. A comparison of facies shows that DF1 contains the highest porosity and the lowest clay content, while fine-grained sandstone facies display the opposite trend, with low porosity and high clay content (Figure 14b,c).
A notable observation is the positive correlation between I/S contents and porosity. This suggests that, under the influence of organic acid-rich fluids, the I/S in DF3 partially dissolve to create secondary intergranular and intragranular pores, thereby increasing porosity. Additionally, these clays often appear as flaky aggregates within pore spaces (Figure 6f), providing mechanical support and helping to preserve pore structure and volume (Figure 14d).
Diagenesis plays a fundamental role in the evolution of reservoir porosity, with the pore structure characteristics of different diagenetic facies serving as key controls on matrix-dominated reservoir quality [53,54,55]. Variations in pore structure across diagenetic facies offer valuable insights into the mechanisms that govern differences in reservoir performance. To better understand the influence of diagenetic facies on pore structure, MICP was conducted on core samples representing different facies. The average pore structure parameters for each facies are summarized in Table 3, revealing marked differences among the four types. Figure 13 illustrates the pore–throat structure characteristics of four representative samples, each corresponding to a distinct diagenetic facies. Sample K45, associated with the most favorable facies, exhibits a porosity of 7.33% and a permeability of 0.256 mD. Sample K9 shows moderate-quality reservoir characteristics, with a porosity of 4.16% and a permeability of 0.051 mD. Sample K23 displays slightly lower values, with a porosity of 3.92% and a permeability of 0.036 mD. In contrast, sample K15 represents the least favorable facies, characterized by a porosity of 1.66% and a permeability of 0.009 mD.
Figure 15a shows the capillary pressure curves and basic petrophysical trends across the four diagenetic facies. From DF1 to DF4, both porosity and permeability decrease progressively, while the capillary pressure curves shift systematically toward the upper right. This shift reflects an increase in entry capillary pressure, a reduction in mercury injection saturation, and an enhancement in mercury withdrawal efficiency. Together, these changes indicate a gradual deterioration in pore throat structure. The length of the low-slope segment within the capillary pressure curve serves as an indicator of pore throat sorting and connectivity. A longer segment is typically associated with a narrower distribution of throat sizes and a better-connected pore network. For instance, the mercury intrusion curve of DF1 sample K45 displays a distinctly extended low-slope segment, suggesting high pore–throat uniformity. In contrast, the curves of the other three samples are characterized by shorter horizontal segments, particularly DF4 sample K15, which reflects greater variability in throat size and poorer connectivity.
Figure 15b further illustrates differences in pore throat size distribution among the four representative samples. The results reveal that the dominant pore–throat radius range narrows progressively from DF1 to DF4, consistent with a loss of pore system quality. Samples K45 and K23 both exhibit bimodal distributions, in which the right-side peak represents the primary mode. For K45, the dominant peak occurs at 1.60 μm, indicating the presence of relatively large and well-connected throats. In contrast, the dominant peak for K23 appears at 0.06 μm, reflecting the development of finer, less connected pore–throat networks under stronger diagenetic modification.
Figure 15c presents the relationship between mercury saturation and the capillary pressure ratio (SHg/Pc), following the definition by Swanson [56]. The maximum value of this ratio is known as the Swanson parameter, and the corresponding pore radius is referred to as rapex. This parameter identifies the transition from wide, well-connected throats to narrow, poorly connected ones [56,57,58]. As shown in the figure, rapex values decline progressively from DF1 to DF4, indicating that the pore–throat radius most responsible for fluid flow becomes smaller across the facies. This trend suggests a systematic reduction in flow-effective pore structures and highlights the progressive deterioration of reservoir quality under increasing diagenetic influence.

5.1.3. Fracture Facies Control on Reservoir Productivity

Intense regional tectonic compression has resulted in the widespread development of structural fractures within the Bashijiqike Formation reservoirs in the study area. These fractures function not only as effective pathways for hydrocarbon migration but also as favorable sites for hydrocarbon accumulation. By enhancing both reservoir storage capacity and fluid flow efficiency, structural fractures play a critical role in improving the reservoir quality and seepage characteristics of tight sandstones. Their presence is therefore essential to the formation and preservation of high-quality reservoirs in this tectonically active setting [59,60,61].
Analysis of the relationship between fracture facies and reservoir productivity in the study area reveals that different fracture combination patterns exert a significant influence on production performance. These variations primarily result from the extent to which fractures modify the reservoir’s seepage system. For example, Well 6, which is dominated by FF1, exhibits relatively low daily gas production. This is attributed to the limited number of seepage channels and poor connectivity associated with isolated fractures, which restrict large-scale hydrocarbon migration and accumulation toward the wellbore. As a result, overall reservoir permeability remains low, and hydrocarbon extraction efficiency is significantly reduced. In addition, FF1 is more susceptible to in situ stress variations during production, increasing the likelihood of fracture closure or blockage. This further impairs seepage capacity and contributes to unstable productivity. In contrast, wells such as Well 11, Well 12, Well 13, Well 14, and Well 15 are primarily associated with FF2 and demonstrate considerably higher productivity. The presence of multiple parallel fractures creates several seepage pathways simultaneously, thereby expanding the effective contact area between the reservoir and the wellbore. This configuration facilitates hydrocarbon flow from various directions and enhances both reservoir permeability and flow efficiency. Furthermore, production data indicate that an increasing proportion of FF3 tends to correspond with higher daily gas output, reflecting improved fracture connectivity. Notably, Well 8 and Well 2, which are associated with FF4, contain a complex, multidirectional fracture network. This network substantially increases both the number and spatial extent of hydrocarbon flow channels, enabling more efficient and rapid fluid migration toward the wellbore and supporting sustained production over time (Figure 16).

5.2. Reservoir Classification and Evaluation Based on “Ternary Reservoir Control”

In the subaqueous distributary channels of the braided river delta front, LF1 and LF2, which were developed under high-energy hydrodynamic conditions, are characterized by coarse grains with good sorting and rounding. These favorable textural features enhance resistance to compaction and contribute to the preservation of primary pores. Moreover, during late-stage diagenesis, unstable mineral components are readily dissolved by pore fluids, resulting in the formation of intragranular dissolution pores. The combined effects of compaction resistance and secondary porosity generation significantly improve reservoir quality and facilitate the development of high-performance reservoir zones. By contrast, LF3 and LF4, which formed under relatively lower-energy depositional environments, exhibit finer grain sizes, poorer sorting, higher clay content, and lower compaction resistance. These characteristics contribute to the destruction of primary pores during burial diagenesis. However, when LF3 or LF4 is associated with well-developed fracture systems, these fractures can enhance pore connectivity and permeability, thereby improving fluid flow and supporting favorable reservoir development. In addition, some LF4 samples with elevated contents of carbonate cement and I/S mixed-layer clays demonstrate enhanced mechanical stability. The structural support provided by these diagenetic components increases resistance to compaction and helps preserve pore geometry. As a result, high-quality reservoirs can still form even in fine-grained facies under favorable diagenetic conditions (Figure 17).
Based on the preceding analysis, lithofacies, diagenetic facies, and fracture facies were integrated, and four key reservoir characterization parameters were selected to establish a classification scheme for reservoir quality in the Bashijiqike Formation of the Keshen Gas Field (Table 4). This scheme enables a comprehensive and quantitative evaluation of reservoir quality across the study area. The results indicate that high-quality reservoirs are primarily associated with conglomeratic sandstone and muddy conglomeratic sandstone facies, which are deposited under strong hydrodynamic conditions. Favorable diagenetic facies are those characterized by the dissolution of unstable components, which enhances pore development. In terms of structural control, the most effective fracture facies are reticulate and conjugate systems, typically formed under intense tectonic activity, which significantly improve seepage capacity. In contrast, as hydrodynamic energy decreases, compaction and cementation become more pronounced, and fracture systems transition toward single or parallel patterns. These changes collectively lead to reduced porosity and permeability, resulting in a decline in overall reservoir quality.
The classification scheme proposed here aligns with global reservoir models developed in other ultra-deep environments, such as the Norphlet Formation in the Gulf of Mexico and the Nubian Sandstone in Libya [5,61]. In both cases, secondary dissolution, early carbonate cementation, and structural fracturing are crucial in improving tight reservoir performance. These similarities strengthen the broader applicability of our ternary control model in assessing tight sandstone plays worldwide.

6. Conclusions

Previous studies on ultra-deep tight sandstone reservoirs often only separately examined the influences of factors such as sedimentation, diagenesis, and structure. This research aims to systematically integrate these three factors to analyze their combined impact on reservoir heterogeneity and productivity in the ultra-deep Bashijiqike Formation, with the goal of establishing a comprehensive quantitative “ternary control” model for reservoir classification. To achieve this, core data, conventional and borehole image log data from 16 wells, along with detailed petrophysical analysis data, were combined to classify lithofacies, diagenetic facies, and fracture facies types, forming a ternary classification scheme.
Key outcomes of this research are outlined below:
(1) Lithofacies serve as the primary control on reservoir quality. Among these, LF1 is formed in high-energy subaqueous distributary channels, constitutes the most favorable reservoir foundation, with average porosity and permeability values reaching 6.0% and 0.066 mD, respectively.
(2) Diagenetic modification further differentiates reservoir properties. DF1 notably improves pore space, yielding an average porosity of 6.0% and permeability of 0.093 mD. In contrast, DF2 and DF3 tend to reduce permeability despite providing some resistance to compaction.
(3) Fracture spatial arrangement proves essential for productivity. Wells containing FF4 or FF3 fracture systems show gas production rates 2–5 times higher than those with only FF1.
(4) The integration of these three facets demonstrates that Type I reservoirs arise from a synergistic combination of LF1, DF1, and FF3 or FF4.
Nevertheless, this study is constrained by the spatial limitation of well coverage and the absence of dynamic experimental validation for diagenetic processes. Future work should incorporate basin-scale diagenetic modeling and high-resolution three dimensional seismic fracture analysis to refine the spatial prediction of high-quality reservoirs. Experimental studies on fluid–rock interaction under ultra-deep burial conditions would further enhance the mechanistic understanding of reservoir evolution. In summary, this research establishes a robust, multi-facies-based evaluation framework that advances current reservoir classification theory and provides a valuable reference for the exploration and development of similar ultra-deep tight sand-stone reservoirs worldwide.

Author Contributions

Methodology, writing—original draft, validation, visualization, W.S.; Conceptualization, investigation, writing—review and editing, Z.X.; Analyzed data, visualization, H.X.; Validation, resources, L.W.; Validation, resources, Y.W. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the National Natural Science Foundation of China grant number U24B2015.

Data Availability Statement

The datasets in this study can be obtained by contacting the corresponding author.

Acknowledgments

The authors would like to thank the Tarim Oilfield for providing experimental data and access to specialized equipment essential for this study.

Conflicts of Interest

Authors Lidong Wang and Yanli Wang were employed by the company PetroChina Tarim Oilfield Company. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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Figure 1. Location and structural characteristics of the study area: (a) Structural map of the Kuqa Depression; (b) Structural map of the Kelasu area and location of the study area.
Figure 1. Location and structural characteristics of the study area: (a) Structural map of the Kuqa Depression; (b) Structural map of the Kelasu area and location of the study area.
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Energies 18 05067 g002
Figure 2. Stratigraphic column of the Keshen gas field and lithologic column of the Bashijiqike Formation.
Figure 2. Stratigraphic column of the Keshen gas field and lithologic column of the Bashijiqike Formation.
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Energies 18 05067 g003
Figure 3. Schematic Diagram of the Integrated Lithofacies, Diagenetic Facies, and Fracture Facies Classification Workflow for the Bashijiqike Formation Reservoir in the Keshen Gas Field. Note: The photographic image of the actual equipment is not presented due to confidentiality agreements. Arrows show the sequential order of the process.
Figure 3. Schematic Diagram of the Integrated Lithofacies, Diagenetic Facies, and Fracture Facies Classification Workflow for the Bashijiqike Formation Reservoir in the Keshen Gas Field. Note: The photographic image of the actual equipment is not presented due to confidentiality agreements. Arrows show the sequential order of the process.
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Energies 18 05067 g004
Figure 4. Lithofacies assemblage types. (a) FA1 well log response characteristics; (b) FA2 well log response characteristics; (c) FA3 well log response characteristics.
Figure 4. Lithofacies assemblage types. (a) FA1 well log response characteristics; (b) FA2 well log response characteristics; (c) FA3 well log response characteristics.
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Energies 18 05067 g005
Figure 5. Lateral and vertical development frequency of lithofacies. (a) Lateral distribution frequency of lithofacies; (b) Vertical distribution frequency of lithofacies.
Figure 5. Lateral and vertical development frequency of lithofacies. (a) Lateral distribution frequency of lithofacies; (b) Vertical distribution frequency of lithofacies.
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Energies 18 05067 g006
Figure 6. The micropore images obtained from the thin sections show the characteristics of compaction, cementation, and dissolution diagenesis. (a) Particle preferred orientation with grain fracturing under compaction, W7, 6941.88m; (b) Point-line grain contacts with primary intergranular pores, W3, 6714.17m; (c) Calcite exhibits an orange-yellow hue, while dolomite displays an orange-red tint, W2, 6512.33m; (d) Dolomite basal cementation, W2, 6706.73m; (e) Pore-filling cementation by calcite and dolomite, W5, 7091.38m; (f) Authigenic illite and illite-smectite mixed-layer in filamentous forms, W8, 6709.12m; (g) Authigenic leaf-shaped chlorite. W3, 6714.53m; (h) Authigenic honeycomb-shaped chlorite; W3, 6717.59m; (i) Authigenic platy kaolinite, W9, 6700.09m; (j) Quartz overgrowth; W5, 7092.06m; (k) Feldspar dissolution generating moldic pores, calcite-filled, W6, 6728.5m; (l) Diagenetic microfractures with associated dissolution pores, W10, 6995m. I/S = Illite-smectite mixed-layer; Ch = Chlorite; K = Kaolinite.
Figure 6. The micropore images obtained from the thin sections show the characteristics of compaction, cementation, and dissolution diagenesis. (a) Particle preferred orientation with grain fracturing under compaction, W7, 6941.88m; (b) Point-line grain contacts with primary intergranular pores, W3, 6714.17m; (c) Calcite exhibits an orange-yellow hue, while dolomite displays an orange-red tint, W2, 6512.33m; (d) Dolomite basal cementation, W2, 6706.73m; (e) Pore-filling cementation by calcite and dolomite, W5, 7091.38m; (f) Authigenic illite and illite-smectite mixed-layer in filamentous forms, W8, 6709.12m; (g) Authigenic leaf-shaped chlorite. W3, 6714.53m; (h) Authigenic honeycomb-shaped chlorite; W3, 6717.59m; (i) Authigenic platy kaolinite, W9, 6700.09m; (j) Quartz overgrowth; W5, 7092.06m; (k) Feldspar dissolution generating moldic pores, calcite-filled, W6, 6728.5m; (l) Diagenetic microfractures with associated dissolution pores, W10, 6995m. I/S = Illite-smectite mixed-layer; Ch = Chlorite; K = Kaolinite.
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Energies 18 05067 g007
Figure 7. The content of clay minerals in the Bashijiqike Formation.
Figure 7. The content of clay minerals in the Bashijiqike Formation.
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Figure 8. Well log response characteristics of diagenetic facies: (a) DF1 well log response characteristics; (b) DF2 well log response characteristics; (c) DF3 well log response characteristics; (d) DF4 well log response characteristics.
Figure 8. Well log response characteristics of diagenetic facies: (a) DF1 well log response characteristics; (b) DF2 well log response characteristics; (c) DF3 well log response characteristics; (d) DF4 well log response characteristics.
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Energies 18 05067 g009
Figure 9. Core photographs showing representative fracture types: (a) Vertical shear fracture, unfilled, W11, 6473.8 m; (b) Low-angle extensional fracture, completely filled with calcite, W10, 6878.04 m; (c) High-angle extensional fracture, partially to completely filled with dolomite, W7, 6804.19 m; (d) Horizontal extensional fracture, unfilled, W6, 6816.92 m.
Figure 9. Core photographs showing representative fracture types: (a) Vertical shear fracture, unfilled, W11, 6473.8 m; (b) Low-angle extensional fracture, completely filled with calcite, W10, 6878.04 m; (c) High-angle extensional fracture, partially to completely filled with dolomite, W7, 6804.19 m; (d) Horizontal extensional fracture, unfilled, W6, 6816.92 m.
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Energies 18 05067 g010
Figure 10. Fracture characteristic parameters: (a) Fracture orientation distribution; (b) Degree of fracture filling; (c) Distribution of fracture filling minerals; (d) Fracture aperture distribution.
Figure 10. Fracture characteristic parameters: (a) Fracture orientation distribution; (b) Degree of fracture filling; (c) Distribution of fracture filling minerals; (d) Fracture aperture distribution.
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Energies 18 05067 g011
Figure 11. Imaging Logging and Core Calibration Diagrams of Four Types of Fracture Facies: (a) Isolated fractures. (b) Parallel fractures. (c) Conjugate fractures. (d) Networked fractures.
Figure 11. Imaging Logging and Core Calibration Diagrams of Four Types of Fracture Facies: (a) Isolated fractures. (b) Parallel fractures. (c) Conjugate fractures. (d) Networked fractures.
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Energies 18 05067 g012
Figure 12. Reservoir petrophysical characteristics of the Bashijiqike Formation in the Keshen gas field: (a) Boxplot of porosity for different lithofacies; (b) Boxplot of permeability for different lithofacies; (c) Crossplot of median grain size versus porosity; (d) Crossplot of clay–matrix content versus porosity for different lithofacies; (e) Crossplot of sorting coefficient versus porosity for different lithofacies; (f) Crossplot of sorting coefficient versus permeability for different lithofacies.
Figure 12. Reservoir petrophysical characteristics of the Bashijiqike Formation in the Keshen gas field: (a) Boxplot of porosity for different lithofacies; (b) Boxplot of permeability for different lithofacies; (c) Crossplot of median grain size versus porosity; (d) Crossplot of clay–matrix content versus porosity for different lithofacies; (e) Crossplot of sorting coefficient versus porosity for different lithofacies; (f) Crossplot of sorting coefficient versus permeability for different lithofacies.
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Energies 18 05067 g013
Figure 13. Relationship between lithofacies, lithofacies associations, porosity, and permeability in Well 10 of the Keshen gas field. The red arrow indicates an upward-increasing trend.
Figure 13. Relationship between lithofacies, lithofacies associations, porosity, and permeability in Well 10 of the Keshen gas field. The red arrow indicates an upward-increasing trend.
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Energies 18 05067 g014
Figure 14. Diagenetic facies characteristics of the Bashijiqike Formation in the Keshen Gas Field: (a) Crossplot of c versus permeability for different diagenetic facies; (b) Crossplot of dissolution pores porosity versus porosity for different diagenetic facies; (c) Crossplot of mud content versus porosity for different diagenetic facies; (d) Crossplot of I/S content versus porosity.
Figure 14. Diagenetic facies characteristics of the Bashijiqike Formation in the Keshen Gas Field: (a) Crossplot of c versus permeability for different diagenetic facies; (b) Crossplot of dissolution pores porosity versus porosity for different diagenetic facies; (c) Crossplot of mud content versus porosity for different diagenetic facies; (d) Crossplot of I/S content versus porosity.
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Energies 18 05067 g015
Figure 15. Pore structure characteristics of representative samples from four diagenetic facies. (a) Capillary pressure curves from high-pressure mercury intrusion; (b) Pore–throat size distribution curves; (c) Plot of the mercury saturation/capillary pressure versus mercury saturation.
Figure 15. Pore structure characteristics of representative samples from four diagenetic facies. (a) Capillary pressure curves from high-pressure mercury intrusion; (b) Pore–throat size distribution curves; (c) Plot of the mercury saturation/capillary pressure versus mercury saturation.
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Figure 16. Histogram of single well fracture facies frequency and corresponding daily gas production.
Figure 16. Histogram of single well fracture facies frequency and corresponding daily gas production.
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Energies 18 05067 g017
Figure 17. Diagram of “three-element controlling reservoir” based on lithofacies, diagenetic facies and fracture facies.
Figure 17. Diagram of “three-element controlling reservoir” based on lithofacies, diagenetic facies and fracture facies.
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Table 1. Summary of the dataset used in this study.
Table 1. Summary of the dataset used in this study.
Data TypesSpecific Measurement/AnalysisQuantity
Core dataDrilling meterage364.18 m (from 16 wells)
Coring meterage339.47 m
Petrophysical dataPorosity and permeability580 samples
Thin sections analysis300 samples
SEM186 samples
XRD299 samples
CL120 samples
Granulometry analysis114 samples
MICP201 samples
Conventional logsCAL, SP, GR, M2R3, M2R6, M2RX, DEN, CNL, DT16 vertical wells
Image logsFMI7 vertical wells
Well testsDaily gas production rates11 vertical wells
Fluid interpretation outcomes31 vertical wells
Table 2. Lithofacies types, depositional interpretation, core features, and thin section characteristics in the Bashijiqike Formation.
Table 2. Lithofacies types, depositional interpretation, core features, and thin section characteristics in the Bashijiqike Formation.
LithofaciesDepositional
Interpretation		Core
Photographs		Thin Section
Photographs		Grain Size
Probability Plots
LF1Intense erosion and rapid deposition occur during flood events or high-energy braided flow stages.Energies 18 05067 i001
W1, 6602.58 m		Energies 18 05067 i002
W6, 6800.23 m		Energies 18 05067 i003
LF2Turbulent flow and rapid facies transitions near scour surfaces at channel bases.Energies 18 05067 i004
W2, 6623.64 m		Energies 18 05067 i005
W1, 6602.38 m		Energies 18 05067 i006
LF3Stable, continuous deposition under normal flow conditions.Energies 18 05067 i007
W3, 6511.32 m		Energies 18 05067 i008
W7, 6941.92 m		Energies 18 05067 i009
LF4Suspended-load deposition under reduced hydrodynamic energy.Energies 18 05067 i010
W4, 6714.68 m		Energies 18 05067 i011
W3, 6739.17 m		Energies 18 05067 i012
LF5Low-energy, distal depositional setting beyond channel influence.Energies 18 05067 i013
W5, 7086.86 m		Energies 18 05067 i014
W1, 6611.84 m		Undetected
Table 3. Average pore structure parameters of different diagenetic facies in the Bashijiqike Formation, Keshen Gas Field.
Table 3. Average pore structure parameters of different diagenetic facies in the Bashijiqike Formation, Keshen Gas Field.
Diagenetic Facies
Types		φ (%)k
(mD)		P50
(Mpa)		Pd
(Mpa)		SHg
(%)		WE
(%)		Rmax
(μm)		R50
(μm)		D
DF160.09317.333.1379.6229.801.530.240.92
DF24.20.04118.133.1778.7230.280.630.070.95
DF33.30.02731.144.8977.7333.390.210.031.23
DF42.70.01854.859.2567.9134.440.150.021.09
φ = porosity; k = permeability; P50 = median saturation pressure; Pd = threshold pressure; SHg = total mercury saturation; WE = mercury withdrawal efficiency; Rmax = maximum throat radius; R50 = throat radius at median saturation pressure; D = relative sorting coefficient.
Table 4. Reservoir classification criteria for the Bashijiqike Formation in the Keshen Gas Field.
Table 4. Reservoir classification criteria for the Bashijiqike Formation in the Keshen Gas Field.
Reservoir TypesIIIIIIIV
Porosity (%)6.06.0~4.24.2~3.3<3.3
Permeability (mD)>0.0930.093~0.0410.041~0.027<0.027
Controlling
factors of
reservoir
quality		LithofaciesPredominantly LF1; subordinate LF2 and LF3Predominantly LF2 and LF3; subordinate LF4Predominantly LF4; subordinate LF3LF5
Diagenetic
facies		Predominantly DF1; subordinate DF2Predominantly DF2Predominantly DF3; subordinate DF4DF4
Fracture faciesFF3, FF4FF2, FF3FF1Poorly developed fractures
Thin section characteristicsMud
content (%)		0~52~65~8>8%
Disslution pores
porosity(%)		>10.4~20.1~1.3<0.1
Pore typesPrimary intergranular pores with abundant secondary dissolution poresMinor residual primary intergranular pores, intergranular dissolution pores, and intragranular dissolution poresMicropores
between clay minerals		Very poorly
developed
porosity
Pore throat characteristicsP50 (MPa)<17.3317.33~31.1418.13~54.85>54.85
R50 (μm)>0.240.03~0.240.02~0.07<0.02
WE (%)<29.829.8~33.3930.28~34.44>34.44
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Song, W.; Xu, Z.; Xu, H.; Wang, L.; Wang, Y. Integrated Lithofacies, Diagenesis, and Fracture Control on Reservoir Quality in Ultra-Deep Tight Sandstones: A Case from the Bashijiqike Formation, Kuqa Depression. Energies 2025, 18, 5067. https://doi.org/10.3390/en18195067

AMA Style

Song W, Xu Z, Xu H, Wang L, Wang Y. Integrated Lithofacies, Diagenesis, and Fracture Control on Reservoir Quality in Ultra-Deep Tight Sandstones: A Case from the Bashijiqike Formation, Kuqa Depression. Energies. 2025; 18(19):5067. https://doi.org/10.3390/en18195067

Chicago/Turabian Style

Song, Wendan, Zhaohui Xu, Huaimin Xu, Lidong Wang, and Yanli Wang. 2025. "Integrated Lithofacies, Diagenesis, and Fracture Control on Reservoir Quality in Ultra-Deep Tight Sandstones: A Case from the Bashijiqike Formation, Kuqa Depression" Energies 18, no. 19: 5067. https://doi.org/10.3390/en18195067

APA Style

Song, W., Xu, Z., Xu, H., Wang, L., & Wang, Y. (2025). Integrated Lithofacies, Diagenesis, and Fracture Control on Reservoir Quality in Ultra-Deep Tight Sandstones: A Case from the Bashijiqike Formation, Kuqa Depression. Energies, 18(19), 5067. https://doi.org/10.3390/en18195067

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