Prediction of favorable areas for sandy conglomerate reservoirs: a case study of the middle permian lower Wu’erhe Formation in the Wu’erhe Nose Uplift, Junggar Basin

In recent years, with the advancement of unconventional oil and gas exploration, tight sandy conglomerate reservoirs have attracted considerable attention due to their unique sedimentary characteristics and substantial resource potential. This study focuses on the tight sandy conglomerate reservoirs of the Lower Permian Wu’erhe Formation in the Wu’erhe Nose Uplift of the Junggar Basin. By integrating geological, well logging, and seismic data, this work provides a systematic evaluation of sedimentary microfacies, reservoir characteristics, and hydrocarbon accumulation patterns. The research reveals that the study area developed a fan delta–lacustrine sedimentary system, influenced by a northeastern sediment source and two major channels (W42 and F26). The second (P₂w₂) and third (P₂w₃) members of the Wu’erhe Formation are predominantly composed of subaqueous distributary channel sands within the fan delta front, exhibiting a sand-to-ground ratio of 40%–55% and favorable lateral continuity, which qualifies them as high-quality reservoir units. The sandy conglomerate reservoirs are characterized by a predominance of residual intergranular pores and intragranular dissolution pores, with pore structure marked by fine skewness and narrow throats. Differential compaction and selective dissolution during diagenesis have collectively contributed to a reservoir model described as “overall tight with local enrichment.” The primary hydrocarbon accumulation type is a structural-lithologic composite reservoir, jointly controlled by nose-like structures and lithologic boundaries. Through acoustic impedance inversion and seismic attribute analysis, the spatial distribution of dolomitic sandy conglomerate—exhibiting high impedance and high resistivity—was accurately delineated, leading to the identification of five new structural-lithologic traps. A comprehensive evaluation suggests that the second and third members of the Wu’erhe Formation, given their favorable reservoir properties and abundant hydrocarbon shows (including oil-rich and oil-impregnated intervals), represent the most prospective targets for “sweet spot” identification and large-scale horizontal well development in the study area. Finally, based on the development of oil-layer identification charts, specific testing recommendations were proposed for the W356 well area, and potential exploration targets were predicted.

1 Introduction

In recent years, with the ongoing advancement of unconventional oil and gas exploration, sandy conglomerate reservoirs have drawn increasing interest due to their unique sedimentary reservoir characteristics and substantial resource potential (Xia et al., 2008; Li et al., 2019; Yin et al., 2020; Zhi et al., 2023; Li et al., 2024). Compared with conventional sandstone reservoirs, sandy conglomerates display distinct particularities in sedimentary mechanisms, structural composition, and diagenetic evolution (Wang, 2017). Sandy conglomerates typically develop in event-depositional environments such as alluvial fans and fan deltas, characterized by rapid lithofacies changes, strong structural heterogeneity, and poor preservation conditions for primary pores (Wu, 2009). Moreover, differences in mechanical and chemical properties of gravels and interstitial materials promote differential compaction and selective dissolution during diagenesis, leading to the formation of complex pore-fracture coupled systems (Xu, 2007; Niu et al., 2009). These distinctive features give sandy conglomerate reservoirs a typical “overall tight yet locally enriched” character, in which hydrocarbon distribution is jointly controlled by sedimentary microfacies, structural configuration, and high-quality reservoirs. As a result, the prediction of “sweet spots” has emerged as a key prerequisite for the efficient development of such reservoirs (Hao et al., 2012; Tang et al., 2024). The adoption of multidisciplinary, multi-parameter integrated research methods to establish sweet spot identification models not only reveals the formation mechanisms and distribution patterns of high-quality reservoirs, but also provides a scientific basis for exploration planning and development strategy formulation. This approach is of significant practical importance for promoting the efficient development of unconventional oil and gas resources (Huang et al., 2025; Li et al., 2025).

Extensive research has been conducted on the physical properties of sandy conglomerate reservoirs. For instance, Zhu et al. (2025) demonstrated that reservoir quality is primarily controlled by sedimentary facies, burial depth, fluid properties, and formation temperature. Wang et al. (2025) developed a well-log lithology identification method for these reservoirs using the XGBoost algorithm, achieving an accuracy of 91.05%. Meng (2025) implemented high-precision reservoir characterization through geostatistical stochastic pre-stack seismic inversion. Pang et al. (2026) introduced a well-log interpretation method for mineral composition and physical properties based on the Beluga Whale Optimization (BWO) algorithm, reporting errors below 3% for mineral content and 0.26% for porosity. Furthermore, Wang et al. (2026) established a non-destructive evaluation method for reservoir heterogeneity based on stratified elastic wave velocity measurements, which accurately assesses the impact of factors such as uneven fracture and gravel distribution on core heterogeneity.

Located adjacent to the Mahu source sag in the Junggar Basin, the Wu’erhe Nose Uplift is regarded as highly favorable for hydrocarbon accumulation (Wu, 2009; Wang, 2017). Previously, sandy conglomerate reservoirs within the Wu’erhe Formation (P₂w) in this area were perceived to have unfavorable petrophysical properties and low single-well productivity, and therefore were not initially considered primary exploration targets. However, in 2019, a breakthrough was achieved when wells W017 and F26 obtained industrial oil flow from the sandy conglomerates of the Wu’erhe Formation, overturning conventional perceptions and renewing interest in reservoir evaluation of this formation (Xu, 2007; Niu et al., 2009; Wu, 2009). Currently, the sandy conglomerate reservoirs developed within the Wu’erhe Formation across the Wu’erhe Nose Uplift of the Wu’erhe Oilfield demonstrate comparatively better petrophysical properties. Moreover, the overall exploration maturity in the area remains relatively low, suggesting significant potential for further evaluation.

This study focuses on the Lower Wu’erhe Formation in the Wu’erhe Nose Uplift as a representative case. By integrating the latest geological, well logging, and seismic data from the area, it systematically performs a comprehensive evaluation of the sedimentation, reservoir characteristics, and hydrocarbon accumulation within the Wu’erhe Formation. Techniques such as acoustic impedance inversion and amplitude attributes are applied to predict high-quality reservoirs in key intervals, identify favorable hydrocarbon accumulation zones, and pinpoint promising exploration targets.

2 Geological background

2.1 Sedimentary characteristics

The study area is located in the Wu’erhe Nose Uplift (Figure 1), with the Permian Wu’erhe Formation (P₂w) as the target interval. Its proximity to the Mahu source rock depression makes it a favorable setting for hydrocarbon accumulation, and it encompasses the Lower Wu’erhe Formation.

Figure 1

Figure 1. Geographic location map of Wu’erhe Nose Uplift. (a) Location of the Junggar Basin in China; (b) The study area is situated in the northwestern part of the Junggar Basin.

Structurally, the area lies within the Wuxia Fault Zone of the Western Uplift in the Junggar Basin and adjoins the Mahu Sag in the Central Depression (Wu, 2009; Wang, 2017). It is bounded by the Kexia Fault Zone to the northwest, the Ma 131 well block reservoir of the Mabei Oilfield to the northeast, the Ma 2 well block reservoir of the Mabei Oilfield to the east, and the Aihu Oilfield to the south. The southwestern part comprises farmland and villages, whereas the northwestern and northern regions are characterized by Cretaceous wind-eroded yardang landforms, which belong to the famous “Devil City” scenic area (Xu, 2007; Niu et al., 2009). The terrain is moderately undulating, with elevations varying from 310 m to 360 m and an average elevation of 330 m. The area exhibits significant annual temperature variations, ranging from −40 °C to 40 °C, along with low precipitation and high evaporation, reflecting a continental arid climate. The target layer, the Permian Wu’erhe Formation, is generally buried at depths between 700 m and 3000 m.

Structurally, the study area lies within the Wuxia Fault Zone of the Western Uplift in the Junggar Basin, adjacent to the Mahu Sag of the Central Depression. The northwestern margin of the Junggar Basin has undergone three major tectonic events. The late-Permian tectonic movement established the fundamental framework of the Kexia Major Fault Zone. Subsequently, the late-Triassic tectonic event, though less intense and extensive than the preceding one, further modified the existing structures, giving rise to various nose-like structures, anticlines, and thrust faults (Hao et al., 2012; Tang et al., 2024). It was during this phase that the Wu’erhe Fault-Nose structure was formed, which also coincided with a major period of hydrocarbon accumulation. Beginning in the late Cretaceous, tectonic movements led to uplift and erosion along the northwestern margin, accompanied by the development of numerous small-scale extensional normal faults (Huang et al., 2025; Li et al., 2025).

Based on drilling data and seismic-geological interpretation results, the study area, overlying the Carboniferous basement, developed from bottom to top the following formations: the Permian Jiamuhe Formation, Fengcheng Formation, Xiazijie Formation, Lower Wu’erhe Formation, and Upper Wu’erhe Formation; the Triassic Baikouquan Formation, Karamay Formation, and Baijiantan Formation; the Jurassic Badaowan Formation, Sangonghe Formation, Xishanyao Formation, and Toutunhe Formation; and the Cretaceous succession. Regional unconformities exist between the Carboniferous and Permian, Permian and Triassic, Triassic and Jurassic, and Jurassic and Cretaceous sequences. Locally, the Permian Xiazijie and Jiamuhe Formations pinch out towards the higher parts of the Luliang Uplift and Zhongguai Uplift (Figure 2).

Figure 2

Figure 2. Stratigraphic division and development characteristics of the study area.

The Lower Wu’erhe Formation in the study area is subdivided, in ascending order, into the First, Second, and Third Members. The First Member comprises interbedded gray and gray-green poorly sorted sandstone, coarse sandstone, and dark gray sandy mudstone. The middle-upper part of the Second Member primarily consists of green-gray sandy pebbly conglomerate, gravel-bearing poorly sorted sandstone, and sandy conglomerate, underlain by brown argillaceous poorly sorted sandstone. The Third Member is characterized by dark gray sandy conglomerate and sandy poorly sorted conglomerate interbedded with sandy mudstone.

Hydrocarbon reservoirs in the Wu’erhe Formation are predominantly distributed in the Second and Third Members, which constitute the main focus of this study. According to previous studies, the porosity of sandy conglomerate reservoirs in the Wuerhe Formation of the Junggar Basin typically ranges from 3% to 18% (Dong et al., 2025). The felsic components within sandy conglomerate possess petrophysical properties that resist compression and wear, effectively inhibiting the formation of muddy matrix and secondary cements during diagenesis while reducing porosity loss due to compaction, thus providing favorable reservoir quality (Dong et al., 2025). Xu et al. (2025) found that in sandy conglomerate samples from the Wuerhe Formation, although pores with an equivalent radius smaller than 30 μm account for a relatively high proportion, their contribution to the total pore volume is relatively low. In contrast, pores larger than 60 μm, despite being fewer in number, constitute over 50% of the total pore volume, serving as the primary storage space.

2.2 Tectonic characteristics

The northwestern margin of the Junggar Basin experienced three major tectonic events. The Late Permian tectonic movement established the fundamental framework of large-scale uplifts, depressions, and major fault zones in the basin (Xia et al., 2008; Wu, 2009; Wang, 2017). The subsequent Late Triassic tectonic movement, though of lesser intensity and scope than the previous one, built upon the earlier structures and formed several nose-shaped anticlines and reverse faults (Xu, 2007; Niu et al., 2009). Specifically, the Wu’erhe Nose Uplift structural belt was formed during this event, accompanied by the development of secondary paleo-uplifts, making it a significant period for hydrocarbon accumulation. The structural framework of the study area was essentially finalized during the Early Cretaceous (Hao et al., 2012; Tang et al., 2024). The observed stratigraphic unconformities are predominantly characterized as parallel unconformities resulting from tectonic processes and angular unconformities influenced by the foreland thrust belt along the northwestern margin. In terms of present-day structure, the Triassic Lower Karamay Formation generally exhibits a southeast-dipping monocline configuration (Figure 3).

Figure 3

Figure 3. Seismic-geological interpretation profile along Wells FN407-FN15. The specific locations of the work areas for wells FN407 and FN15 are shown in Figure 4.

3 Databases and methods

3.1 Seismic interpretation

In order to thoroughly investigate the study area, which covers approximately 300 km², and to delineate the regional distribution patterns and oil play characteristics of the target formations, this research collected and integrated six 3D seismic datasets. Subsequently, detailed seismic interpretation was conducted, involving precise tracking of key horizons and systematic interpretation of fault systems. This process clearly defined the morphology and distribution of various structural traps, thereby establishing a robust structural framework for assessing hydrocarbon accumulation potential and guiding subsequent reservoir characterization work (Chen et al., 2024; Zhi et al., 2024).

3.2 Core description

Systematic core observation and sedimentological description were conducted on 14 wells within the study area. The observations focused on lithology identification (e.g., sandstone, mudstone, sandy conglomerate) and detailed description of sedimentary structures. This fundamental core analysis provides a direct geological basis for well log calibration and seismic facies analysis (Liu et al., 2025; Zhang et al., 2025).

3.3 Experimental testing

A comprehensive suite of experimental tests was conducted to thoroughly characterize reservoir properties, including: thin-section identification, scanning electron microscopy (SEM) observation, physical property analysis, high-pressure mercury intrusion, and X-ray diffraction (XRD) whole-rock analysis. The corresponding instruments utilized for each test were as follows: (1) Thin-section identification: Nikon E600 research-grade polarizing microscope; (2) SEM observation: Helios650 scanning electron microscope; (3) Petrophysical property analysis: PoroPDP-200; (4) High-pressure mercury intrusion: AutoPore IV 9505; (5) XRD whole-rock analysis: SmartLab SE multi-function X-ray diffractometer.

Thin-section identification and SEM observation were employed to analyze rock mineral composition, diagenesis, and pore microstructure. Petrophysical property analysis was used to obtain reservoir porosity and permeability parameters. High-pressure mercury intrusion experiments.

3.4 Seismic inversion

Seismic inversion technology was employed to accurately characterize the spatial distribution of sand bodies and delineate trap boundaries within the target intervals. Using the SMI inversion software constrained by well log data and interpreted seismic horizons, seismic reflection volumes were transformed into acoustic impedance volumes. This process facilitated the quantitative prediction of both the planar distribution and vertical development characteristics of high-quality reservoirs (He et al., 2022; Ubuara et al., 2024). This inversion outcome effectively reduces the multiplicity of solutions in reservoir prediction, providing reliable basis for drilling target optimization and reserve estimation.

4 Results

4.1 Sedimentary characteristics

During the Early to Middle Permian, the Junggar Basin experienced a humid climate, which favored the deposition of thick hydrocarbon source rock formations (Xu, 2007; Niu et al., 2009). This humid condition persisted during the deposition of the Middle Permian Xiazijie Formation and the initial stage of the Lower Wu’erhe Formation. However, the climate gradually transitioned to humid-semi-arid by the end of the Lower Wu’erhe Formation depositional period (Xia et al., 2008; Wang, 2017). This climatic evolution is recorded in the stratigraphy as thick, reduced (commonly gray to dark-colored) lithologic assemblages interbedded with partially oxidized rock layers.

Through integrated analysis of core samples, single-well sedimentary sequences, facies, and cycles from existing wells, combined with seismic and log facies identifications, it has been determined that the Lower Wu’erhe Formation in the study area was influenced by western provenance systems and comprises fan delta-lacustrine deposits (Hao et al., 2012; Tang et al., 2024).

The reservoir sand bodies of the Wu’erhe Formation in the study area predominantly consist of front subaqueous distributary channels and distal sand bars deposited within a fan delta-lacustrine environment (Xia et al., 2008; Wang, 2017). Specifically, in the nose uplift area, the Lower Wu’erhe Formation lithology is predominantly gray and gray-green sandy conglomerate, interbedded with thin layers of gray-brown and dark gray argillaceous siltstone and silty mudstone. The area mainly developed subaqueous distributary channel deposits of the fan delta front subfacies, with good reservoir physical properties and widespread oil shows (Qiao, 2017; Kang et al., 2023).

The Lower Wu’erhe Formation in the study area exhibits a regressive-progradational sedimentary cycle with frequent lake-level fluctuations, resulting in an interbedded sequence of front sand bodies and lacustrine-flooding mudstones (Xu, 2007; Niu et al., 2009). Vertically, multiple reservoir-seal assemblages developed. Among these, the Second (P₂w₂) and Third (P₂w₃) Members show better sand body development and greater lateral continuity compared to the First Member (P₂w₁), making them more suitable for horizontal well development (Tang et al., 2024; Huang et al., 2025). Based on a comprehensive analysis of single-well facies characteristics, the Wu’erhe Formation in the study area is interpreted as a fan delta-lacustrine sedimentary system. The well-developed fan delta front sand bodies in the nose uplift area represent a favorable setting for the formation of substantial hydrocarbon accumulations (Xu, 2007; Niu et al., 2009).

The sediment source for the Permian Lower Wu’erhe Formation in the study area was derived from the north-northeast direction (Xu, 2007; Niu et al., 2009). Under the influence of this provenance, sand bodies are well-developed in the nose uplift area, providing favorable reservoir conditions for hydrocarbon accumulation. Toward the southern slope and sag areas, sand bodies gradually thin as a result of greater distance from the source and progressively weaker hydrodynamic conditions (Tang et al., 2022; Wang R. et al., 2024). During the Wu’erhe depositional period, a fan delta-lacustrine sedimentary system extended from the nose uplift area through the slope zone to the sag. Variations in sediment supply and hydrodynamic energy resulted in differences in front sand body development across different periods.

The Wu’erhe Formation oil play in the Wu’erhe Nose Uplift primarily develops within the braided river delta front subfacies, with high-quality reservoirs occurring in the underwater distributary channel microfacies (Xu, 2007; Niu et al., 2009). Laterally, multi-stage underwater distributary channels are extensively superimposed and interconnected. Influenced by lacustrine level changes and relative sediment supply, a fan delta sedimentary system characterized by “small plain, large front” was developed (Xu, 2007; Hao et al., 2012). The Wu’erhe Formation demonstrates obvious “channel-controlled sand” characteristics. Based on detailed structural interpretation, a fine-scale paleogeomorphology map of the Second Member in the study area was constructed, confirming two major channels in the W42 and F26 well areas within the Wu’erhe Nose Uplift, which macroscopically govern the distribution of thick front sand areas in the nose uplift zone (Figure 4).

Figure 4

Figure 4. Stratigraphic isopach map of the second Member (P₂w₂) of the Lower Wu’erhe Formation in the Wu’erhe Area.

The sand-to-ground ratio in the second member of the Wu’erhe Formation within the study area primarily ranges from 40% to 55% (Hao et al., 2012; Tang et al., 2024). The northern flank of the nose uplift area, due to its proximity to the sediment source, exhibits a relatively higher sand-to-ground ratio (exceeding 55%), which diminishes toward the slope zone to below 40%, reflecting lateral variation in sedimentary facies. Figure 5 shows the sedimentary facies map of the second member of the Wu’erhe Formation in the study area. Driven by the two major channels in the W42 and F26 well areas, the fan delta front facies belt extends along a northeast-southwest direction across the entire nose uplift area.

Figure 5

Figure 5. Sedimentary facies map of the second member of the Wu’erhe Formation (P₂w₂), Wu’erhe Area.

The deposition of the Third Member exhibits significant inheritance from the Second Member, also being controlled by the two major channels in the W42 and F26 well areas, with two fan bodies developing accordingly. The flow direction shows slight variations compared to the Second Member, transitioning primarily from the northeast-southwest orientation to a more north-northeast to south-southwest direction. Besides the similar development of front sand bodies in the nose uplift area, the frontal facies sand bodies extend further toward the slope zone (Figure 6).

Figure 6

Figure 6. Sedimentary facies map of the third member of the Wu’erhe Formation (P₂w₂), Wu’erhe Area.

Overall, compared to the depositional period of the First Member, the Second and Third Members experienced stronger sediment supply and hydrodynamic conditions, resulting in thicker individual sand bodies. Consequently, the front sand bodies in the Second and Third Members of the uplift area have a larger planar distribution, greater individual sand body and cumulative thickness, and better lateral stability. Additionally, owing to shallower burial depth and relatively better petrophysical properties, they represent the most favorable intervals for exploring large-scale oil plays and implementing horizontal well development (Tang et al., 2023a; Yin et al., 2025).

4.2 Reservoir characteristics

4.2.1 Lithological characteristics

Based on core observations from cored wells and statistical analysis of rock thin sections, the reservoir lithology of the Lower Wu’erhe Formation is predominantly composed of sandy conglomerate, sandy gravel rock, and gravel-bearing sandstone (Figure 7). The grains are primarily subrounded with poor sorting. The rock cementation is moderate, mainly of the pore-embayment compaction type. The interstitial material between rock grains is predominantly argillaceous matrix, with a content varying from 2% to 6% (averaging 4%). Zeolite minerals and calcite cement are also observed.

Figure 7

Figure 7. Typical core photos of the Wu’erhe Formation, Wu’erhe Nose Uplift.

In local areas of the nose uplift zone, dolomitic sandy conglomerate is developed in the Second and Third Members. The grains are predominantly subangular with moderate to poor sorting. The rock cementation is moderate, primarily of the compaction-embayment type. The interstitial material between rock grains is mainly argillaceous matrix, and also includes dolomite, siderite, and analcime cement.

4.2.2 Oil-bearing characteristics

According to core description data from 14 wells in the study area, the total coring footage in the Lower Wu’erhe Formation was 255.94 m, with a core length of 224.91 m, representing a recovery rate of 87.9%. Oil-bearing core length obtained was 97.48 m.

Specifically, in the Third Member, the core length was 52.38 m, including 5.06 m of oil-rich core, 3.95 m of oil-impregnated core, 10.67 m of oil-spotted core, 8.31 m of oil-traced core, and 8.53 m of fluorescent core.

In the Second Member, the core length was 52.38 m, comprising 10.35 m of oil-impregnated core, 9.07 m of oil-spotted core, and 5.23 m of fluorescent core.

In the First Member, the core length was 93.6 m, consisting of 17.25 m of oil-spotted core, 8.07 m of oil-traced core, and 10.99 m of fluorescent core (Table 1; Figure 8).

Table 1

Table 1. Statistical results of oil-bearing characteristics from Wu’erhe Formation cores, Wu’erhe area.

Figure 8

Figure 8. Histogram of core shows from the Wu’erhe Formation, Wu’erhe Nose Uplift.

The statistical results indicate that the oil-bearing characteristics of the Third and Second Members are significantly better than those of the First Member.

4.2.3 Reservoir petrophysical properties

Based on core porosity and permeability analysis data from the Wu’erhe area, the porosity of the Third Member reservoir ranges from 6.1% to 19.11%, with a mean of 13.05% and a median of 12.53% (Figure 9a). The permeability ranges from 0.54 mD to 548 mD, with a mean of 8.35 mD and a median of 4 mD (Figure 9b).

Figure 9

Figure 9. Histograms of porosity and permeability distribution for the Wu’erhe Formation in the study area. (a) Wu-3 Member, porosity; (b) Wu-3 Member, permeablity; (c) Wu-2 Member, porosity; (d) Wu-2 Member, permeablity; (e) Wu-1 Member, porosity; (f) Wu-1 Member, permeablity.

The porosity of the Second Member reservoir ranges from 3.94% to 22.38%, with a mean of 13.82% and a median of 13.43% (Figure 9c). The permeability ranges from 0.03 mD to 1043.02 mD, with a mean of 7.48 mD and a median of 7.39 mD (Figure 9d).

The porosity of the First Member reservoir ranges from 4.71% to 15.24%, with a mean of 9.41% and a median of 8.45% (Figure 9e). The permeability ranges from 0.02 mD to 282.65 mD, with a mean of 4.33 mD and a median of 3.64 mD (Figure 9f).

The Lower Wu’erhe Formation overall belongs to a medium-to low-porosity and medium-to low-permeability reservoir. The petrophysical properties of the Second and Third Members are significantly better than those of the First Member, making them the preferred intervals for reserve growth and production enhancement in this area.

4.2.4 Pore types and pore structure

The Wu’erhe Formation exhibits relatively developed porosity, with reservoir space dominated by residual intergranular pores and intragranular dissolution pores, followed by micro-fractures (Figures 10a–d). In the nose uplift area, the Wu’erhe Formation benefits from secondary pores, coupled with a high degree of micro-fracture development, which enhances reservoir properties and indicates potential for production enhancement.

Figure 10

Figure 10. Thin-section and SEM photographs of the Wu’erhe Formation in the study area. (a) Well F503, 932.06 m, P₂w₃: Primary intergranular pores are distributed between particles, with a particle size of approximately 60 μm; (b) Well W3445, 1202.27 m, P₂w₃: Dissolution mainly occurs within particles, forming intragranular dissolution pores. The internal pore connectivity of this sample is relatively good; (c) Well W42, 1221.2 m, P₂w₂: Intergranular pores, intragranular dissolution pores, and microfractures are all well developed; (d) Well W42, 1222.65 m, P₂w₂: Dissolution primarily occurs within particles, forming intragranular dissolution pores. These pores are relatively isolated; (e) Well W42, 853.73 m, P₂w₃: Honeycomb-like illite/smectite mixed-layer clays; (f) Well W357, 1772.81 m, P₂w₁: Illite is well developed.

Based on X-ray diffraction (XRD) and scanning electron microscopy (SEM) analysis of Wu’erhe Formation core samples, the clay minerals in the reservoir rocks mainly include honeycomb-like and irregularly shaped illite-smectite mixed-layer minerals coating grain surfaces, with an average relative content of 79.6%. Other clay minerals include illite, kaolinite, and chlorite, with average relative contents of 8.4%, 7.1%, and 4.9%, respectively (Figures 10e,f). The development of illite-smectite mixed-layer minerals in the reservoir, along with their additional conductivity, is the main reason for the low resistivity observed in the study area. Clay minerals dominated by illite-smectite mixed layers are primarily distributed in the delta front facies belt and gradually decrease toward the slope area. Robust hydrodynamic conditions favor the formation of illite-smectite mixed layers (Wang Q. Y. et al., 2024; Wang F. et al., 2024).

The Lower Wu’erhe Formation in the study area is a typical medium-low porosity and permeability, sandy conglomerate, pore-fracture-type reservoir. Residual intergranular pores and intragranular dissolution pores serve as the main reservoir spaces. Hydrocarbons are primarily enriched in sandy conglomerate reservoirs with low clay content and more favorable petrophysical properties.

Based on the analysis of numerous micrographs, the pore structure types of the sandy conglomerate in the Wuerhe Formation within the study area primarily include intergranular pores, dissolution pores, and microfractures (Figure 10). Intergranular and dissolution pores are predominantly characterized by isolated and sheet-like structures. Statistical analysis reveals that the areal porosity percentages of intergranular pores and dissolution pores account for 31% and 65%, respectively, while microfractures constitute only 4%. Specifically, sheet-like pores are formed by grain-boundary microfractures, residual intergranular pores, or dissolution pores, whereas isolated pores are associated with intragranular dissolution pores within the sandy conglomerate samples. Although the proportion of intergranular pores is significantly smaller than that of dissolution pores, intergranular pores mainly consist of pores with diameters larger than 60 μm, whereas dissolution pores are mostly smaller than 30 μm. Given the strong heterogeneity of sandy conglomerate, reservoirs with larger-sized intergranular pores and better-connected microfractures exhibit superior physical properties and higher oil potential. In contrast, dissolution pores, which predominantly develop within particles, show relatively poorer oil potential. Overall analysis indicates that intergranular pores and microfractures are the most dominant pore types in the sandy conglomerate of the Wuerhe Formation in the study area.

Mercury injection capillary pressure (MICP) experimental results indicate that the capillary pressure curves of the Wu’erhe Formation exhibit fine skewness, poor pore sorting, and are characterized by small pores and fine throats. The median pressure for saturation ranges from 0.12 to 17.38 MPa, with an average of 7.95 MPa. The median pore-throat radius ranges from 0.04 to 0.76 μm, with an average of 0.17 μm. The displacement pressure ranges from 0.01 to 1.33 MPa, with an average of 0.46 MPa. The average capillary radius ranges from 0.04 to 3.33 μm, with an average of 0.75 μm (Figure 11).

Figure 11

Figure 11. Capillary pressure curves from key wells in the Wu’erhe Formation of the study area. Basic information of the samples: (a) Well W27, 1412.72 m; (b) Well W42, 1222.3 m; (c) Well W27, 1413.17 m; (d) Well W42, 1222.65 m.

4.3 Oil play type

Based on comprehensive analysis of stratigraphic correlation, detailed structural interpretation, sedimentary facies distribution, reservoir characteristics, and well testing results, it is concluded that the Permian Wu’erhe Formation oil play is macroscopically controlled by the nose uplift structure. Laterally, the oil play is constrained by lithology and petrophysical properties, primarily distributed in the subaqueous distributary channels of the fan delta front, with oil layers overlapping and connecting continuously. The oil play consists of structural-lithologic and lithologic reservoirs developed in a faulted nose structural setting (Figure 12).

Figure 12

Figure 12. Reservoir profile of the third member of the Permian Wu’erhe Formation along wells W10-F26-W017-W9-F20. Logging symbols: SP stands for spontaneous potential, measured in mV; GR stands for gamma ray, measured in API; RT stands for true resistivity, measured in Ω·m; RI stands for induction resistivity, measured in Ω·m.

The oil play in the Third Member of the Wu’erhe Formation in the F26 well area, as shown in Figure 12, is a structural-lithologic reservoir jointly controlled by faults and lithologic boundaries. Its southern boundary is fault-controlled, while the other boundaries are defined by the pinch-out of oil-bearing sand bodies. Seismic attributes clearly reflect the lithologic boundaries (Shan et al., 2022; Niu et al., 2024; Yin et al., 2024). The central part of the oil play is buried at a depth of 1,598 m, with a reservoir thickness of 994 m and an oil-bearing area of 11.0 km². To date, three wells within this oil-bearing area have yielded industrial oil flow, and the horizontal well W025_H has shown good oil and gas indications. The oil-bearing area of the reservoir is well-confirmed, with an estimated reserve scale exceeding 5 million tons (Figure 12).

5 Discussion

5.1 Construction of an oil layer chart for the lower Wu’erhe Formation and recommendations for well testing

Wells W017 and F26 in the study area successively achieved breakthroughs in oil testing within the upper sand bodies of the Third Member, expanding the exploration potential of the Wu’erhe Formation and confirming its potential for large-scale exploration. Through comprehensive research on the structure, sedimentary reservoirs, and hydrocarbon accumulation in the Third Member of the northern W42 well area, it was found that the bottom sand layer of the Third Member of the Wu’erhe Formation in the W356 well area exhibits lateral stability, significant thickness, and well-developed oil layers as interpreted from well logs, meeting the geological conditions for production enhancement via horizontal wells. Additionally, the overlying mudstone caprock is well-developed and laterally stable, providing excellent sealing conditions. It is therefore recommended to conduct reperforation and testing in the interval of 1151.0–1199 m in the existing Well W356 in this area, aiming to confirm the hydrocarbon-bearing potential of this layer and to provide a geological basis for subsequent comprehensive evaluation (Table 2).

Table 2

Table 2. Well log interpretation results of the third member of the Wu’erhe Formation in well W356.

Figure 13 shows the well log interpretation results of the Third Member of the Wu’erhe Formation in Well W356. Testing is recommended for three intervals within the 1151.0–1199 m section. This recommendation is based on the following considerations.

1. The W356 well area is located in the high part of the eastern axis of the Wu’erhe Nose Uplift, which is a favorable structural position and an advantageous area for hydrocarbon migration and accumulation. The main sedimentary environment of the Permian Wu’erhe Formation in the Wu’erhe Nose Uplift is the fan delta front subfacies, characterized by interbedded sandy conglomerate and mudstone, which is conducive to reservoir formation (Huang et al., 2022; Niu et al., 2024).

2. The log curves of the proposed well testing interval in Well W356 show clear oil layer characteristics. Seismic and inversion data indicate that the reservoir sand bodies are laterally stable and exhibit vertical stacking, suggesting evaluation potential for the Third Member in this area (Figures 14, 15).

3. Cuttings analysis from the lower sand body of the Third Member in Well W356 shows 34.00 m of fluorescence. The total hydrocarbon content in gas logging increased from 1,516 ppm to 20,649 ppm, with components up to nC5, indicating good oil and gas shows (Tang et al., 2023b; Abraham-A et al., 2024). Well log interpretation identified four oil layers with a total thickness of 29.6 m, demonstrating significant oil layer thickness. The log interpretation results for the proposed testing interval fall within the oil layer range on the identification chart (Figure 16).

4. Comprehensive analysis suggests that the bottom sand body of the Third Member of the Permian Wu’erhe Formation in Well W356 exhibits clear oil layer characteristics. The probability of achieving oil flow through reperforation and testing is high, potentially opening up new evaluation prospects.

Figure 13

Figure 13. Well log interpretation results for the third member of the Wu’erhe Formation, well W356. Logging Symbols: CAL is caliper (hole diameter), measured in inches; SP is spontaneous potential, measured in mV; GR is gamma ray, measured in API; RT is true resistivity, measured in Ω·m; RI is induction resistivity, measured in Ω·m; RXO is flushed zone resistivity, measured in Ω·m; CNL is compensated neutron log; AC is acoustic interval transit time (slowness), measured in μs/ft; DEN is bulk density, measured in g/cm³; C5∼C6+ is the hydrocarbon logging series; CALO is open hole caliper, measured in inches; PERM is permeability, measured in mD; POR is porosity, measured in %.

Figure 14

Figure 14. Seismic profile along wells F21-W356-F3.

Figure 15

Figure 15. Seismic inversion profile along wells F21-W356-F3.

Figure 16

Figure 16. Identification chart for oil zones in the lower Wu’erhe Formation of the study area.

The specific recommended testing intervals for the Third Member in Well W356 are as follows: 1199.0–1195.0 m, 1184.0–1180.0 m, and 1156.0–1151.0 m, with a total perforation thickness of 13.0 m (Table 3). The basis for interval selection is as follows.

1. Fluorescence shows were observed in cuttings logging:

Table 3

Table 3. Proposed reperforation intervals for well testing in the third member of the Wu’erhe Formation, W356 well area.

Intervals 1120.00 m–1138.00 m, 1142.00 m–1158.00 m, and 1196.00 m–1200.00 m logged as gray fluorescent sandy conglomerate.

Dry UV fluorescence: 1%, pale yellow, weak luminescence.

Serial comparison: Grade 11, milky white.

2. Gas logging shows distinct anomaly amplitudes:

Interval 1120.0 m–1158.0 m: total hydrocarbons increased from 0.1517% to 2.065%, with components detected up to C1, interpreted as a dry layer.

Interval 1196.0 m–1200.0 m: total hydrocarbons increased from 0.3994% to 3.7892%, with components detected up to nC5, interpreted as an oil layer.

3. Electrical log data indicate good reservoir properties in this interval:

Interval 1142.4 m–1200.5 m: RT: 15.3 Ω·m, DEN: 2.44 g/cm³, AC: 77.8 μs/ft, interpreted as an oil layer.

5.2 Comprehensive prediction of favorable zones

Based on integrated seismic-geological interpretation studies, it is concluded that the Lower Wu’erhe Formation of the Permian in the Wu’erhe Nose Uplift developed large-scale retrogradational fan-delta deposits. The sand bodies are stacked, interconnected, and extensively distributed. Structural-lithologic target sand bodies are well developed in the Lower Wu’erhe Formation of the study area, creating favorable conditions for the formation of structural-lithologic oil plays.

Two sets of dolomitic sandy conglomerate are developed in the Third and Second Members of the Wu’erhe Formation within the study area. These exhibit good petrophysical properties and show hydrocarbon shows throughout, indicating potential for substantial reserves. Testing of both dolomitic reservoir intervals in Well W3445 achieved breakthroughs. Sand layer correlation confirms stable lateral distribution and large sand body thickness, which is conducive to production enhancement via horizontal drilling. On seismic profiles, the dolomitic sandy conglomerate exhibits low-frequency, medium-to-strong amplitude reflection characteristics (Liu et al., 2025; Zhang et al., 2025).

Statistical results indicate that the P₂w mudstone in the study area exhibits low impedance and low resistivity, the sandy conglomerate shows moderate impedance and moderate resistivity, and the dolomitic sandy conglomerate is characterized by high impedance and high resistivity. The cross-plot of acoustic impedance and resistivity can effectively distinguish mudstone, sandy conglomerate, and dolomitic sandy conglomerate (Table 4; Figure 17).

Table 4

Table 4. Statistical table of acoustic impedance and resistivity for different lithologies in the study area.

Figure 17

Figure 17. Acoustic impedance chart for P₂w in the study area. The horizontal axis represents acoustic impedance, which is the product of rock density and wave velocity. The vertical axis, RT, represents true resistivity.

This study utilized acoustic impedance inversion, combined with fault and structural interpretation results, to re-evaluate and confirm five structural-lithologic traps in the Wu’erhe Formation of the Wu’erhe Nose Uplift, with a total area of 5.0 km². The technical workflow of this study is illustrated in Figure 18. Through well-to-seismic integration, standardized well log data and petrophysical analysis are utilized to establish accurate lithology identification templates, as well as to construct the low-frequency model and wavelet for seismic inversion. Subsequently, based on geostatistical seismic inversion, seismic data are transformed into a high-resolution acoustic impedance volume, enabling the three-dimensional spatial mapping of lithology distribution. Building on this, and in combination with key seismic attribute prediction and structural interpretation, the prediction of traps and favorable reservoirs is ultimately accomplished.

Figure 18

Figure 18. Flowchart of seismic inversion technology for trap and favorable reservoir prediction.

The dolomitic sandy conglomerate exhibits characteristics of low frequency, medium-to-strong amplitude, and high impedance. Its spatial distribution can be accurately determined using acoustic impedance inversion (Figure 19). Along the well trajectories of W27-W001-W118 and W17-W001-W3416, the dolomitic sandy conglomerate in the Third Member shows greater thickness, better continuity, and a wider planar distribution. In contrast, the dolomitic sandy conglomerate in the Second Member is only locally developed, with poorer lateral continuity and relatively limited planar distribution.

Figure 19

Figure 19. Seismic inversion profile along wells W17-FN5-DW604-W001-W3445-W3416.

The trap parameters are listed in Table 5, and their planar distribution is shown in Figure 20. Among these, the P₂w₃ structural-lithologic trap has the largest area (Figure 21). It contains thick dolomitic sandy conglomerate and has demonstrated effective well testing results in surrounding wells. The trap is well-confirmed and represents the primary target for production enhancement.

Table 5

Table 5. Table of trap elements for the study area.

Figure 20

Figure 20. Planar distribution of traps in the study area.

Figure 21

Figure 21. Acoustic impedance map of the P₂w₃ trap in the study area.

5.3 Applicability and limitations of the technology

The technical approach presented in this paper is closely integrated with the geological characteristics of the study area and demonstrates significant applicability within the specific geological context of the Wu’erhe Formation. By combining detailed sedimentary microfacies characterization, seismic attribute analysis, and acoustic impedance inversion, it effectively predicted structural-lithological traps jointly controlled by nose-like structures and lithological boundaries. This proves the effectiveness of the comprehensive prediction philosophy guided by geological models and integrating well and seismic data in sandy conglomerate reservoirs characterized by multiple sediment sources and strong heterogeneity. The established workflow of “standardized well-log data processing → petrophysical analysis and lithology identification template building → geostatistical seismic inversion → 3D lithology spatial characterization → comprehensive trap evaluation” is logically clear and provides important reference value for “sweet spot” prediction in continental coarse-clastic reservoirs with similar sedimentary backgrounds (e.g., alluvial fans, proximal fan deltas). In particular, the method of identifying high-quality dolomitic sandy conglomerate reservoirs using characteristics of high impedance and high resistivity offers a clear technical pathway for locating similar high-quality diagenetically-altered reservoir bodies.

However, this technical method still faces several limitations when applied to a broader range of sandy conglomerate reservoirs. First, the method heavily relies on high-quality foundational data. The relatively abundant drilling and 3D seismic data in the study area are prerequisites for detailed inversion and prediction. In exploration frontier areas or data-scarce regions, low well control leads to inaccurate low-frequency model construction, significantly increasing the non-uniqueness of seismic inversion solutions and thus affecting reservoir prediction accuracy. Second, the technique has a strong dependence on specific reservoir type “labels.” The identification of high-quality reservoirs in the paper highly depends on the “dolomitic sandy conglomerate” lithologic end-member, which exhibits special physical property responses (high impedance, high resistivity). For more common sandy conglomerate bodies without significant diagenetic mineral differentiation or marked physical property contrasts, the predictive effectiveness of the key lithology identification and fluid detection templates within this method may be diminished. Third, a scale gap exists in the method’s ability to address the extreme heterogeneity of sandy conglomerate reservoirs. While seismic inversion can delineate the macro-scale distribution of sand bodies, the pore structure heterogeneity within sandy conglomerates—caused by gravel distribution, interstitial material variations, and microfractures (e.g., fine throats and poor pore-throat sorting as mentioned in the paper)—is a problem at the meter or even centimeter scale. Existing geophysical techniques struggle to characterize this directly and precisely, yet it is precisely this factor that is key to controlling single-well productivity.

To enhance the universality and prediction accuracy of this technical method for sandy conglomerate reservoirs, future research could develop multi-scale integrated prediction technologies. Strengthening petrophysical experiments and digital core technology to establish quantitative relationships between microscopic pore structure parameters and macroscopic geophysical responses would enable an upgrade from “sand body prediction” to “effective reservoir prediction.” Simultaneously, intensifying the application of machine learning and artificial intelligence technologies, such as training intelligent algorithms (e.g., deep learning networks) to uncover more subtle “sweet spot” patterns within seismic attributes, would enhance adaptability in areas with complex lithological assemblages.

In summary, the technical method demonstrated in this paper has clear applicability and good predictive performance in sandy conglomerate reservoirs with geological conditions similar to the Wu’erhe Formation. Its core strength lies in the close integration of geology and geophysics. However, its application effectiveness is strongly constrained by the quality of foundational data, the distinctiveness of reservoir geophysical signatures, and the degree of reservoir heterogeneity. Future development should focus on breaking through scale limitations, reducing dependence on prior models, and improving the identification capability for complex geological bodies through intelligent means, thereby achieving more precise prediction for sandy conglomerate reservoirs.

6 Conclusion

1. The Lower Permian Wu’erhe Formation in the Wu’erhe Nose Uplift of the Junggar Basin developed a fan delta–lacustrine sedimentary system. Its deposition was controlled by a northeastern sediment source and two major channels (W42 and F26). The second (P₂w₂) and third (P₂w₃) members of the formation are characterized by the extensive development of subaqueous distributary channel sands in the fan delta front. These sands exhibit a high sand-to-ground ratio (40%–55%) and good lateral continuity, forming the primary high-quality reservoir units in the region. The sandy conglomerate reservoirs are dominated by residual intergranular pores and intragranular dissolution pores, with pore structure characterized by fine skewness and narrow throats. Differential compaction and selective dissolution during diagenesis have resulted in a reservoir model of “overall tightness with local enrichment”.

2. The hydrocarbon accumulation type is primarily a structural-lithologic composite reservoir, jointly controlled by nose-like structures and lithologic boundaries. Through acoustic impedance inversion and seismic attribute analysis, the spatial distribution of dolomitic sandy conglomerate—exhibiting high impedance and high resistivity—was accurately delineated, leading to the identification of five new structural-lithologic traps.

3. Comprehensive evaluation indicates that the Second and Third Members of the Wu’erhe Formation, with their superior reservoir properties and abundant oil shows (including oil-rich and oil-impregnated levels), represent the most favorable intervals for “sweet spot” targeting and large-scale horizontal well development in the study area. Finally, based on constructed oil layer identification charts, specific testing recommendations were proposed for the W356 well area, and prospective areas were predicted.

Data availability statement

The original contributions presented in the study are included in the article/supplementary material, further inquiries can be directed to the corresponding author.

Author contributions

JL: Writing – review and editing, Methodology, Writing – original draft. YJ: Writing – review and editing, Software. TS: Writing – review and editing, Software. ZC: Software, Writing – review and editing. NZ: Writing – review and editing, Software.

Funding

The author(s) declared that financial support was not received for this work and/or its publication.

Conflict of interest

Authors JL, YJ, TS, ZC, and NZ were employed by Fengcheng Oilfield Operation Area of Xinjiang Oilfield Company.

Generative AI statement

The author(s) declared that generative AI was not used in the creation of this manuscript.

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