Wettability Characteristics of Mixed Sedimentary Shale Reservoirs in Saline Lacustrine Basins and Their Impacts on Shale Oil Energy Replenishment: Insights from Alternating Imbibition Experiments

Abstract

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

1. Introduction

With the continuous growth of global energy demand, shale oil and gas, as an important unconventional energy source, is playing an increasingly important role in the global energy structure. Compared to conventional oil and gas resources, shale oil and gas have features such as large reserves and a widespread distribution, difficulties in their extraction are also relatively increased. Shale oil represents a crucial energy resource for the exploration and development of 21st-century oil and gas. With China’s substantial potential in shale oil resources, expediting the development of unconventional oil and gas holds significant importance for alleviating the nation’s petroleum energy demands [1,2]. The national standard defines it as oil stored in organic-rich shale formations [3]. Shale oil mainly exists in an adsorbed and free state in formations dominated by mudstone [4]. Wettability is a key factor controlling the accumulation and flow of hydrocarbons, and reservoir wettability has a significant impact on the microscopic distribution of oil, gas, and water in rock pores and the reservoir formation process [5,6]. Currently, methods for characterizing reservoir wettability are mainly divided into experimental and simulation categories [7]. Experiments include the contact angle method, Amott method, USBM method, nuclear magnetic resonance relaxation measurement method, and relative permeability measurement method [8,9,10,11], and simulations include lattice Boltzmann method and molecular dynamics method [12,13]. Environmental scanning electron microscopy was used to conduct a comprehensive investigation of the micrometer (µm) scale wetting property variations of carbonate rocks covered with an organic layer. Energy-dispersive X-ray mapping confirmed the presence of an organic layer on the samples. The application of microscopy techniques revealed the reason for the hydrophobic wetting behavior of real carbonate rocks [14]. In carbonate-dominated lithologies, samples from the Wolfcamp-A and Niobrara A-Chalk formations exhibit high contact angles, indicating a certain degree of hydrophobicity, even when cleaned and not aged. In contrast, samples from the Eagle Ford, Niobrara B-Chalk, C-Chalk, Codell, Bakken, and Three Forks formations show strong hydrophilicity when not aged, which is the expected behavior under environmental conditions [15]. The study evaluated the original wettability of the Bakken, Eagle Ford, Wolfcamp, and Barnett formations using siliceous and carbonate core samples. The results showed that all shale layers exhibit moderate wettability. TOC and oil type affect wettability, while mineralogical composition does not [16]. A methodology for measuring shales’ wettability that uses X-Ray Photoelectron Spectroscopy (XPS) is presented. The results are compared with conventional imbibition tests. XPS is being used as a faster way to infer the wetting condition of sandstone rocks [17]. In unconventional shale oil reservoirs, the initial wettability of the rock surface is crucial for fluid behavior. Oil samples from multiple shale formations in the United States (including light and heavy Eagle Ford, Wolfcamp, Middle Bakken, and Three Forks) were analyzed using SARA to investigate the effect of oil composition on rock surface wettability, and to examine the influence of rock mineralogy and brine salinity. These factors collectively determine the wettability characteristics of the shale oil/brine/rock system [18]. The data indicates that the total organic carbon (TOC) content is positively correlated with the effective porosity, pressure decline permeability, and oil saturation of the samples. Additionally, as the TOC content increases, the bulk density and matrix density of the core samples decrease. Notably, a significant portion of the porosity in the samples exists within the organic matter, and these organic pores have a high affinity for oil [19]. These methods have different principles and application effects, and their evaluation of wettability focuses on different aspects. Evaluating the water-wet or oil-wet nature of a reservoir can be achieved using qualitative methods, such as observing the size, shape, and whether a capillary rise phenomenon occurs in water droplets; or using quantitative methods, through measuring contact angle values, spontaneous capillary rise rates, nuclear magnetic resonance relaxation times, etc., to precisely quantify the wettability of the sample [20]. Factors affecting the wettability of shale reservoirs mainly include mineral composition, organic matter characteristics, and pore structure, and external factors such as the properties of formation water, temperature, and pressure conditions also have a certain impact on wettability [21,22,23,24,25]. Studies on the wettability characteristics of different shale formations have shown that scholars have established a correlation between material composition and fluid behavior. Zheng Guowei [26] et al.’s research in the Fengcheng Formation of the Ordos Basin in the Majiawo depression revealed that shale oil-wetness is positively correlated with TOC and dolomite content, negatively correlated with quartz content, and has a segmented evolution relationship with calcite content, with macropore volume showing a significant positive correlation with oil-wetness; Zeng Juan [27] et al. discovered, based on sample analysis of five wells in the southeastern Chongqing region, that TOC significantly enhances shale oil-wetness while having little effect on water-wetness; Liu Xuan [28] found, in his study of marine shale in the Longmaxi Formation of the Silurian, that TOC has a nonlinear parabolic relationship with water contact angle, and quartz, as the dominant factor of brittle minerals, has the most significant impact on wettability, while illite/smectite mixed layers play a key role among clay minerals, and also confirmed that an increase in gas content leads to a decrease in water contact angle. The complex pore wettability of shale governs the initial distribution and displacement flow of oil and water within the pores. While spontaneous imbibition reflects fluid flow within the internal pore network of a sample, the imbibition of a single fluid is insufficient to characterize the mixed-wet pores within the sample. Therefore, alternate imbibition is employed to physically simulate the flow processes of both oil and water phases within the shale pore network, mimicking the oil–water exchange occurring during hydraulic fracturing and production. Alternate spontaneous imbibition reveals the distribution and flow capacity of oil and water within shale pores. Combined with two-dimensional NMR (Nuclear Magnetic Resonance), which monitors real-time changes in oil and water content within the sample’s pores during imbibition, T2 relaxation spectra (corresponding to fluid distribution states in pores of different scales) are acquired in real-time throughout the cyclic process to characterize the wettability of the shale samples. The samples studied originate from the saline lacustrine basin of the Junggar Basin. Given the significant variation in the properties of reservoir rocks, it is impossible to select a single universal wettability measurement method applicable to any reservoir. To obtain accurate data on the rock’s wettability characteristics, the alternate imbibition method and NMR are rationally combined [29]. In general, the study of shale wettability is a complex process involving multiple factors and methods. Different shale reservoir features vary significantly, and a comprehensive use of various characterization methods and consideration of multiple influencing factors are needed to understand the wettability characteristics of shale reservoirs more comprehensively [30]. This study uses the method of combined oil–water alternate spontaneous imbibition experiments and two-dimensional nuclear magnetic resonance technology to study the dynamic evolution characteristics and control mechanisms of reservoir wettability. On the one hand, oil–water alternate imbibition experiments simulate the real reservoir fluid dynamic behavior through non-steady-state fluid replacement processes, obtaining the dynamic response relationship between wettability and displacement efficiency and imbibition rate; on the other hand, two-dimensional nuclear magnetic resonance technology overcomes the single-scale detection limit of traditional methods through the joint interpretation of T1–T2 relaxation spectra, precisely identifying the wettability differences in oil and water distribution in different pore structures, with a particularly unique advantage in characterizing the non-uniform characteristics of pore wettability. Although the combined use of NMR and the alternate wettability method provides dynamic wettability quantification capability, spontaneous imbibition primarily relies on capillary forces, leaving some pores inaccessible. After oil–water state exchange, wettability hysteresis occurs. The interfacial interactions within nano-scale pores (<50 nm) require further resolution through molecular simulation. As a special class of shale reservoirs, salt lake basin turbidite deposition shale reservoirs have unique reservoir characteristics and hydrocarbon storage patterns. A higher number of carbonate rock layers may lead to low reservoir coverage, low displacement efficiency, rapid water flooding, gas cap breakthrough, and ultimately a decline in oil and gas production. However, research on the wettability characteristics of brine-driven basin turbidite deposition shale reservoirs is relatively limited, which restricts our understanding of the hydrocarbon migration and production patterns of this type of reservoir. Wettability reduction, as an important factor affecting shale hydrocarbon production, directly affects the capillary pressure, relative permeability, and hydrocarbon flow energy of shale reservoirs [31,32]. Therefore, in-depth research on the wettability characteristics of saline lacustrine basin mixed sedimentary shale reservoirs is of great significance for optimizing production schemes and improving recovery rates. The Lucaogou Formation in the Jimsar Sag and the Fengcheng Formation in the Mahu Sag in the Junggar Basin belong to typical deep marine saline lacustrine basin shale oil reservoirs and are one of the important areas and formations for land-based shale oil exploration in China [33]. As shale oil exploration and development continue and the understanding of reservoir evaluations deepens, strengthening the study of shale wettability is particularly important for a deeper understanding of the shale oil accumulation mechanism and flow rules [34]. This study takes mixed-type shale in the Lucaogou Formation of the Jimsar depression and the Fengcheng Formation of the Mahu depression in the Junggar Basin as the research object, conducting alternate imbibition experiments to quantitatively characterize the wettability of shale reservoirs, combining the organic matter and pore characteristics, lithofacies and mineral composition, physical properties, and oil saturation characteristics of shale to explore the distribution characteristics and influencing factors of shale reservoir wettability. The aim is to reveal the wettability characteristics of mixed-type shale reservoirs in saline lake basins and explore their impact on the efficiency of shale oil and gas energy extraction, as well as to provide references for subsequent exploration and development studies. Improving the recovery rate of shale oil and gas is of great significance for ensuring national energy security and reducing dependence on foreign energy.

2. Materials and Methods

2.1. Geological Features

The Junggar Basin is located in the northern part of the Xinjiang Uyghur Autonomous Region of China, and it is one of the large composite oil and gas basins in western China’s land area [35,36]. The total area of this basin exceeds 13 × 10⁴ square kilometers. The geological structure is characterized by multi-level differentiation features, mainly composed of six first-level structural units including the western uplift belt, central depression belt, and land bridge uplift belt. It is further divided into 44 s-level structural units, such as the Mahu Depression, Xiayan Uplift, Dabasong Uplift, Zhongguai Uplift, Shawan Depression, Pen1 Well West Depression, Shixi Uplift, Mobei Uplift, Dongdaohaizi Depression, and Fukang Depression. The regional structural layout shows significant spatial differentiation laws, with first-level uplift belts and depression belts alternating in distribution, and secondary uplift structures and depression units showing adjacent coexistence, forming a complex structural landform combination system (Figure 1). Since the Carboniferous period, the deep structure of the basin has undergone multiple stages of evolution under the effect of four tectonic movements in the Hercynian, Indosinian, Yanshan, and Himalayan periods: during the early Permian, a rift basin structural system developed; in the middle Permian, it transformed into a foreland basin structural background; and from the late Permian to the Triassic, it entered the stage of depression basin evolution. From the Carboniferous to the middle Permian, the internal structure of the basin was controlled by the uplift–depression structural pattern, and each secondary unit formed independent sedimentary systems; starting from the late Permian structural transformation period, a unified subsidence center gradually developed in the central and southern parts of the basin, ultimately achieving the integration of the lake system across the entire basin, marking a major transformation from differentiated to integrated sedimentary patterns [37,38]. The basin developed from Carboniferous to Quaternary, including Carboniferous, Permian, Triassic, and Quaternary strata, with relatively complete strata, and sediment thickness can exceed 7000 to 9000 m, with differences in the distribution range of different strata [39,40,41]. It has significant zonality in plain view, with the Jiamuhe Formation (P1j), Fengcheng Formation (P1f), Xiazijie Formation (P2x), and Xiawuerhe Formation (P2w) developing in the western and central parts, and the Lucaogou Formation (P2l) being characteristic of the eastern part, while the Shangwuerhe Formation (P3w) exhibits a distribution pattern covering the entire basin. Significant differences in burial depth are observed vertically, with deep to ultra-deep reservoir systems dominating below 4500 m, accounting for more than 60% of the total reservoir thickness. The source rock system developed multi-layer source rock systems vertically from Carboniferous to Triassic, with six effective source rock formations being identified. Among these, the Permian source rocks have the best quality and the widest distribution, represented by the Fengcheng Formation, Xiawuerhe Formation, and Lucaogou Formation, with high organic richness and large hydrocarbon generation potential, forming the core material foundation for the basin’s oil and gas reservoir formation [42]. There was a large amount of hydrocarbon generation and expulsion over multiple evolutionary stages through successive multiple-reservoir formation periods, including the Middle to Late Permian, Late Triassic, and Middle Jurassic to Early Cretaceous [43], providing sufficient sources for reservoir formation. The Jiamuhe Formation of the Permian mainly consists of volcanic rocks and volcaniclastic rocks, while the reservoir rocks of the Xiazijie Formation, Xiawuerhe Formation, Shangwuerhe Formation, Fengcheng Formation, and Lucaogou Valley Formation are mainly composed of fluvial–deltaic clastic rocks. Mixed rocks and carbonates developed in local areas, such as the Fengcheng Formation in the Mahu Depression and the eastern part of the Lucaogou Valley Formation in the Fukang Depression.

Jimsar Sag is located at the southwestern edge of the eastern uplift belt in the Junggar Basin. It has undergone multiple cycles of tectono-sedimentary evolution from the Carboniferous to the Himalayan period, forming a monoclinal sag structure with relatively weak tectonic activity and continuous strata, generally showing a low west and high east morphology (with the western part being a lowland and the eastern part being a slope belt). The main lithofacies of the Lucaogou Formation within the sag is a halite deep-lake sedimentary system, with local development of deltaic and shallow-half-deep lake subfacies. The thickness of the strata is 90–350 m, with a burial depth of 2500–4500 m. Its lithology is characterized by the high-frequency interbedding of terrestrial clastic, carbonate, and volcaniclastic multi-source materials, forming a complex mixed sedimentary sequence. The oil-rich areas of shale oil are mainly distributed in the transitional zone from the sag to the slope belt. Based on rock-electric properties and oil productivity differences, two major high-quality reservoir units, the “upper sweet spot body” (Lucaogou Formation, Member II, Submember II) and the “lower sweet spot body” (Lucaogou Formation, Member I, Submember II), are identified, separated by thick mudstone layers. The sweet spots are primarily composed of mixed-type tight reservoirs, characterized by high oil saturation and good mobility.

The Fengcheng Formation in the Mahu Sag is mainly controlled by frequent changes in paleoclimate and volcanic activity, forming a fan delta-shallow lake-half deep lake halite basin sedimentary system. In the early stage of Feng I Formation deposition, influenced by frequent volcanic activity, volcaniclastic rocks developed at the bottom; in the later stage, as volcanic activity weakened and the climate became wetter, the basin expanded, developing dolomitic mudstone. During the Feng II Formation deposition period, evaporation intensified, the basin shrank, and the salinity of the lake water increased. At the same time, the supply of terrestrial clastic minerals increased, presenting an alternating combination of dolomitic mudstone and feldspathic mudstone, and developing alkaline minerals such as nahcolite and kernite. During the Feng III Formation deposition period, the basin expanded again, the climate became wetter, and the large-scale input of terrestrial clastic materials occurred, resulting in the development of interbedded mudstone and siltstone in the study area.

2.2. Sample Collection and Characteristics

The samples in this study were taken from the mixed turbidite shale sections of the Lucaogou Formation in the Jimsar Sag and the Fengcheng Formation in the Mahu Sag. The core focus is on the evolution of sedimentary environments and material input, with the selection of mixed sections characterized by the interaction of lacustrine, volcanic, and terrigenous clastic features (

Table 1. Characteristics of mixed sedimentary-type shale experimental samples in the Junggar Basin.

Sample Number	Depth	TOC/%	Mineral Content/%
			Quartz	Potassium Feldspar	Plagioclase	Calcite	Dolomite	Pyrite	Ulexite	Clay Minerals
L1	4137.93	0.46	21.4	1.7	42.4	/	32.6	/	/	0.9
L2	4241.40	1.57	29.8	3.7	25.8	0.4	37.9	/	/	2.4
L3	4234.30	2.29	30.5	11.0	29.7	0.7	24.7	/	/	3.4
L4	4248.15	0.95	52.7	32.6	2.7	8.7	2.9	/	/	0.4
L5	4375.98	0.34	18.7	3.7	17.2	49.2	2.4	/	/	8.0
L6	4123.79	0.19	43.2	2.2	40.0	2.0	4.7	/	/	2.6
L7	4270.54	1.09	21.7	5.0	16.1	0.4	45.9	/	/	10.9
F1	4920.80	0.84	17.1	6.3	14.3	2.0	8.9	4.2	42.5	4.7
F2	4943.68	1.31	14.0	2.0	24.9	48.6	3.7	2.8	/	4.0
F3	4880.85	0.56	41.4	5.4	17.3	1.3	26.1	3.4	/	5.1
F4	4886.16	1.64	48.7	3.6	28.2	4.5	5.1	6.2	/	3.7
F5	4932.74	0.60	18.0	4.5	24.8	21.4	18.6	2.9	5.7	4.1
F6	4950.36	0.56	0.8	6.1	11.8	60.2	7.1	3.0	9.3	1.7
F7	4958.97	0.49	11.8	10.1	45.3	4.2	14.6	5.3	6.9	1.8
F8	4970.34	0.98	35.7	6.7	36.0	1.0	11.5	6.0	/	3.1
F9	4907.85	1.16	57.9	3.6	20.8	1.7	6.1	4.1	/	5.8
F10	4938.45	1.27	58.4	0.8	4.2	24.6	8.3	1.4	/	2.3
F11	4961.19	0.98	61.0	5.7	12.2	6.5	6.2	4.1	/	4.3

). In terms of sample characteristics, the Lucaogou Formation exhibits a typical mixed sedimentary structure with high-frequency alternations in calcareous laminae, and shows a locally striped interbedding of volcanic clastic chunks and fine-grained lacustrine muddy layers, with clastic components ranging from clay-sized to silt-sized. The Fengcheng Formation is mainly characterized by the thick interbedding of grayish-white tuffaceous shale and dark gray calcitic laminae, with the widespread development of microcrystalline calcite clusters formed by volcanic ash alterations, as well as the mixed accumulation of terrigenous feldspathic clastics and chemically precipitated siliceous nodules, indicating a periodic, alternating response of volcanic eruptions, chemical precipitation, and terrigenous transport.

2.3. Experimental Method and Procedure

The rock X-ray diffraction experiment was conducted using a Bruker D8 Advance X-ray diffractometer for mineral analysis. The rock samples were crushed and ground to less than 200 mesh, dried, and then prepared via low-speed centrifugation to minimize preferred orientation effects. The instrument was configured with a Cu Kα radiation source (wavelength 1.5406 Å), operating at 40 kV and 40 mA. Diffraction patterns were automatically collected using DIFFRAC.EVA V2.0 software, and mineral phases were identified using the ICDD-PDF4+ mineral database, with a focus on characterizing the diffraction peaks of quartz, feldspar, and clay minerals. Thin sections were prepared by injecting blue epoxy resin into the pores of 2.5 cm diameter cylinders after washing with oil and drying, using vacuum pressure ranging from 20 to 30 MPa to avoid crack interference. After curing, the sections were cut to a thickness of 0.3 cm, finely polished at low speed to reduce cracking, and further ground to a thickness of 30 μm. Mineral composition, cement types, and pore structures were examined using a polarizing microscope. The experiment followed the SY/T 6103-2019 standard [44]. Rock samples were subjected to vacuum-drying and surface sputter-coating with a 5–10 nm gold layer using an argon ion beam polishing scanning electron microscope (SEM) to eliminate charging effects. Morphology was observed using a field emission SEM in low-vacuum mode at 0.5–1.0 kV, with an accelerating voltage of 10–20 kV and probe current of 1–5 nA, utilizing secondary electron (SE) and backscattered electron (BSE) signals for imaging. Elemental qualitative and quantitative analyses and mineral composition were performed simultaneously using an energy-dispersive spectrometer (EDS). The experiment was conducted in a controlled environment at approximately 25 °C and less than 30% humidity.

Alternating imbibition was combined with 2D nuclear magnetic resonance (NMR) experiments: oil–water–oil alternating imbibition was performed on selected samples and quantitatively characterized using 2D NMR to assess the wettability of mixed-type shale. The specific steps are as follows: (1) The selected rock samples were cleaned with dichloromethane for 7 days, then dried at 100 °C for 24 h to ensure consistent initial wettability. Initial sample mass and NMR signals were then measured. (2) During the dynamic alternating wetting process, the environment was maintained at 70 °C. The samples were first fully immersed in an oil phase fluid (dodecane, viscosity 1.34 mPa·s) for continuous imbibition, with mass changes monitored using a high-precision balance, and NMR signals were measured at mass monitoring points, with a mass fluctuation threshold of less than 0.01 g within 24 h indicating imbibition stability. Subsequently, the fluid was quickly changed to a water phase fluid (8306 ppm sodium bicarbonate solution simulating formation water) for reverse imbibition, with mass monitoring and NMR signal measurement used to determine equilibrium based on mass stability thresholds; this process was repeated by switching back to the oil phase fluid, recording sample mass and NMR signals, and terminating the experiment when the total mass of the alternating imbibition process stabilized, indicating that the oil–water distribution in the sample pores had reached dynamic equilibrium. (3) Two-dimensional NMR spectra were used to distinguish oil-wet and water-wet pore signals. Measurements were conducted using a MicroMR12-025V NMR come from Suzhou, China, Suzhou Niumag Analytical Instrument Corporation analyzer, with a wait time (TW) of 1.5 s, an echo spacing (TE) of 0.06 ms, and 3000 echo repetitions. The principle is based on the difference in hydrogen proton resonance signals in oil and water under a magnetic field, with the longitudinal relaxation time (T1) reflecting the strength of the fluid–pore surface interaction. Water molecules in water-wet pores exhibit shorter T1 values due to surface binding effects, while oil molecules in oil-wet pores show longer transverse relaxation times (T2) due to weak surface binding. NMR provides in situ observation evidence for the dynamic evolution of wettability. (4) Oil and water-wet pore imbibition mass was calibrated through preparing gradient standards of the imbibition fluids (oil and water) at 20%, 40%, 60%, 80%, and 100% of the total imbibition volume, with NMR parameters set as in Step (3). Measurements were repeated three times, recording the integral areas of oil and water, with fluid content as the X-axis and NMR integral signals as the Y-axis, fitting the linear equation (R² > 0.98) to establish a standard curve and determine the calibration parameters for NMR signals and imbibition fluid mass.

Contact angle measurement experiment: Using a contact angle meter, the rock surface was sanded and polished, then fixed on the sample holder. A microliter syringe was used to draw oil and expel air bubbles. A needle was suspended about 0.5 mm above the sample surface, slowly dispensing 2–5 μL of oil droplets so that they gently touched the surface, before quickly moving vertically away. The droplet was left to stabilize for 1–3 min, and a clear image was captured. The automatic fitting software analyzed the wetting angles on both sides and recorded the average. The surface was cleaned and the measurement was repeated at different positions ≥3 times.

3. Results

3.1. Layer Characteristics and Lithologic Division

The Lucaogou Formation is dominated by terrigenous clastics, with high contents of quartz, feldspar, and rock fragments, and contains carbonate nodules, reflecting the characteristics of rapid deposition from a nearby source (Figure 2(a1–d2)). The grain size is relatively coarse, mainly consisting of fine to medium sand, with moderate sorting, intercalated with gravel and muddy turbidite lamination, indicating the high-energy environment of a delta front or shallow lake, with strong water dynamics leading to poor material sorting. In contrast, the Fengcheng Formation conglomerate is characterized by a complex combination of volcanic and terrigenous clastics, primarily composed of quartz and feldspar, with average contents of 33% and 27%, respectively, followed by calcite and dolomite, with average contents of 16% and 11%, respectively, and low contents of pyrite and clay minerals, with average contents of 3.9% and 3.7%, respectively. The volcanic material ratio is high, with common ash, feldspathic minerals, and authigenic silica, and local dolomite and pyrite contents are observed, reflecting frequent volcanic activity and a reducing environment in semi-deep to deep lake settings. Its grain size is mainly silt to fine sand, with good sorting, indicating a low-energy, still-water deposition background, with periodic volcanic eruptions and terrigenous input forming multiple types of alternating thin layers (Figure 3(a1–d2)).

In terms of sedimentary structure characteristics, the Lucaogou Formation has poorly developed laminae, mainly blocky or discontinuous undulatory lamination, with locally observed lens-shaped cross-bedding composed of coarse sand to fine gravel, reflecting intermittent flash flood events (Figure 2(b2,d2)). Its vertical lithological sequence shows a rapid cycle of conglomerate–gravel sandstone–shale, intercalated with thin layers of carbonaceous shale, with low mineral maturity, obvious feldspar alteration, and dispersed organic matter, with terrigenous input being dominant. The Fengcheng Formation is characterized by the development of multiple types of laminae, including millimeter-scale ash–clay rhythmic laminae, silica–organic matter horizontal lamination (Figure 2(c2,d2)), and volcanic ash event laminae, with good continuity of thin layers. Ash layers contain angular volcanic glass, clay layers are rich in organic matter, and silica laminae are mostly formed by chemical precipitation, possibly related to hydrothermal activity.

In terms of lithological development, the Lucaogou Formation is characterized by thick layers of conglomerate intercalated with thin layers of mud shale, locally containing oil shale and calcareous cement zones, with high proportions of coarse clastics, and conglomeratic structures, often volcanic rock fragments mixed with terrigenous gravels, reflecting a rapid filling process near the source under an active tectonic background, with sample lithologies including calcareous siltstone (Figure 2(a1–b2)), siltstone (Figure 2(c1,c2)), and silty dolomite (Figure 2(d1,d2)). The Fengcheng Formation conglomerate series is thin and stable, with frequent interlayering of ash layers with mudstone, siliciclastic rock, and volcanic event layers coupled with chemical deposition, reflecting the dynamic equilibrium of volcanic–hydrothermal–sedimentary processes during the lake basin expansion period, with sample lithologies including clayey shale (Figure 3(a1,a2)), clayey feldspathic shale (Figure 3(b1,b2)), feldspathic shale (Figure 3(c1,c2)), and silica shale (Figure 3(d1,d2)). The fundamental difference between the two is rooted in the ancient geographical setting; the Fengcheng Formation was formed in a semi-deep water basin, away from the main source, with active volcanic activity, while the Lucaogou Formation is located in the steep slope belt at the basin’s edge, controlled by strong tectonic uplift and coarse clastic alluvial systems, leading to differences in its conglomerate types and preservation conditions compared to the Fengcheng Formation.

3.2. Storage Space Type

In terms of pore types, the Lucaogou Formation is dominated by intergranular pores and intergranular dissolution pores (Figure 4(a1,b1)). Its conglomerate contains up to 60–70% terrigenous clastic material, primarily consisting of fine sandstone and siltstone. Primary intergranular pores are well-developed between clastic grains (quartz, feldspar, rock fragments), with pore sizes ranging from 10 to 50 μm. Due to the weak diagenetic compaction and low clay content (<10%), the pore morphology is irregular but has moderate connectivity. Secondary pores are mainly intergranular dissolution pores (50–100 μm) formed by the dissolution of feldspar, volcanic rock fragments, and early calcite cement by acidic fluids, creating a honeycomb-like structure. This significantly improves pore connectivity, with porosity reaching 5–12%, classifying it as a medium-porosity reservoir. In contrast, the Fengcheng Formation, deposited in a hypersaline lake environment, is primarily composed of arkose shale and calcareous shale, with a high carbonate cement content. Most primary intergranular pores are filled with calcite and dolomite (Figure 4(c1,d1)), leaving residual pores mostly isolated (<20 μm). The main pore types are intercrystalline pores (1–10 μm) and dissolution pores (<10 μm) (Figure 4(d1,c1)), with the former originating from micropores between dolomite crystals, and the latter being concentrated within feldspar. However, due to the strong resistance of carbonate minerals to dissolution, their dissolution activity is weak and pore connectivity is poor, resulting in porosity of only 1–5%, and making the reservoir tighter overall.

The differences in lithology and diagenetic processes are key to pore heterogeneity. The Lucaogou Formation was formed in a semideep lake–delta depositional system, with abundant terrigenous clastic input. The early weak compaction–weak cementation conditions favored the preservation of primary pores, while the later organic acid dissolution of feldspar, rock fragments, and early cements formed a secondary pore network. In contrast, the Fengcheng Formation is a hypersaline lake basin deposit, where high water salinity leads to the rapid precipitation of carbonate minerals (dolomite, calcite), resulting in the strong early cementation and carbonate cementation of clastic grains, inhibiting the development of primary pores; neither formation has organic pores or microfractures.

3.3. Alternating Saturation

In the alternate imbibition experiment, two-dimensional nuclear magnetic resonance (NMR) technology was used to characterize the dynamic distribution features of oil and water in different wetting pores (Figure 5). During the first oil imbibition stage, oil-wet pores were preferentially occupied by the oil phase, while the oil phase infiltrated into mixed-wet pores through capillary forces. The NMR T₁–T₂ spectrum showed that signals were concentrated in the medium to large pore size range (Figure 5e), with a small extension into the small pore region, indicating that the oil phase formed a continuous phase in pores dominated by oil wetting, while the small pores were not completely filled. During the water imbibition stage, water-wet pores were rapidly occupied by the water phase, and some of the oil phase in mixed-wet pores was displaced by the water phase due to water imbibition, causing a significant shift in the NMR signal response towards shorter relaxation times, an increase in the signal intensity of the water recognition zone, and a decrease in the T₁/T₂ ratio, forming a distinct “bimodal distribution” feature—coexistence of the left peak (water phase) and the right peak (oil phase) (Figure 5j). In the second oil imbibition stage, mixed-wetting pores were re-invaded by the oil phase due to dynamic changes in wettability, and the NMR signal migrated back to the meso–macro pore regions, with signal intensity approaching that of the first oil imbibition stage, indicating that oil–water alternate imbibition reached its maximum under the experimental conditions. The experiment further revealed that oil and water alternation was predominantly occupied by single-phase wetting pores, with the NMR signal migration path exhibiting a “circular” feature, reflecting the dynamic wettability process. This result indicates that wettability differentiation at the pore scale directly controls the selectivity of imbibition pathways, with oil-wet pores forming an advantageous channel for the oil phase, while mixed-wet pores serve as a “buffer zone” for dynamic oil–water exchange [45].

Nitrogen adsorption experiments show that the study area is dominated by slit-shaped pores (Figure 6), and ink-bottle shaped pores are not developed. Therefore, theoretically, the wettability hysteresis effect has little influence on the study area. To further confirm this understanding, we compared the nuclear magnetic resonance (NMR) signals of direct oil absorption (state A) and the state after oil imbibition–water imbibition–oil imbibition (state C). If wettability hysteresis occurred, state B would exhibit more water signals than the normal wetting state [46]. However, we found that the NMR signals of most samples in state C were not significantly different from those in state A, allowing for the wettability study in this work to ignore the influence of wettability hysteresis (Figure 7).

Figure 8 shows the dynamic changes in oil and water phase fluids entering the pore spaces of the samples from the Lucaogou Formation and Fengcheng Formation during the alternate imbibition process. The x-axis represents the cumulative time of alternate imbibition, and the y-axis represents porosity, indicating the volume ratio of the imbibed fluids to the volume of the core. Among these, a represents the oil phase imbibition porosity, b represents the water phase imbibition porosity, and c represents the total imbibition porosity. The oil–water–oil alternating imbibition of the Lucaogou Formation samples stabilized at 276 h, 528 h, and 780 h, respectively, while the Fengcheng Formation samples were relatively delayed, stabilizing at 480 h, 960 h, and 1104 h, respectively. The oil phase imbibition porosity increased rapidly in the initial 48 h but then slowed down and tended to stabilize. When it switched to the water imbibition phase, it significantly decreased, indicating that oil was displaced in the mixed-wet pores. The peak in oil imbibition porosity during the second oil imbibition was lower than the first (Figure 8(a2–a4)), suggesting that some mixed-wet pores were occupied by water. However, the peak in oil imbibition porosity during the second oil imbibition exceeded the first peak for some samples (Figure 8(a1,a5,a6)), indicating that some pores were transformed by the water phase fluids and experienced a wettability reversal. The water phase imbibition porosity increased sharply and quickly stabilized after the transition from oil to water (Figure 8(a2,a4,a6)). However, when the water imbibition porosity was <1%, it only increased (Figure 8(a1,a3,a5)). In terms of total imbibition porosity, both areas showed stepwise increases with a leap after each phase change. The growth of the Fengcheng Formation was slower but more stable, with a lower overall increase than that of the Lucaogou Formation.

3.4. Contact Angle Result

The contact angle measurement results indicate (Figure 9) that the contact angle between the original core sample and crude oil is within a very narrow, low-angle range, between 3.72° and 11.92°. This range has significant wetting indicative properties; at the rock–oil interface, a contact angle less than 90° indicates a wetting state (oil-wet), and an extremely small angle of below 30° or even approaching 0° clearly demonstrates the strong wetting characteristics (strong oil-wetness) of the core surface. This means that crude oil has a strong tendency to spread and adhere to the original surface of the core, forming a very thin oil film. Notably, the average contact angle of the Lucaogou formation core samples is significantly smaller than that of the Fengcheng formation. This smaller contact angle value indicates that the rock surface of the Lucaogou formation exhibits stronger oil wetness and oil affinity compared to the Fengcheng formation.

4. Discussion

4.1. Wetting Characteristics

We observed the total porosity data of each imbibition fluid after the stabilization of the “oil–water–oil” three-stage imbibition (

Table 2. Results following the alternating imbibition and wetting of pores.

Stratigraphy	Lithology	Number	Depth/m	Porosity/%				Helium Porosity/%	Wettability Index
				Mixed Porosity	Water Porosity	Oil Porosity	Total Porosity
Jimsar Depression Lucaogou Formation	Dolomitic Siltstone	L1	4137.93	0.05	0.62	3.13	3.80	7.01	−0.66
		L2	4241.40	0.64	0.31	2.61	3.57	11.44	−0.64
		L3	4234.30	0.20	0.41	1.96	2.57	5.27	−0.60
	Siltstone	L4	4248.15	0.06	0.89	6.21	7.16	12.80	−0.74
		L5	4375.98	0.18	0.46	2.21	2.85	8.49	−0.62
		L6	4123.79	0.75	1.27	5.70	7.71	8.60	−0.57
	Silty dolomite	L7	4270.54	0.16	1.36	4.93	6.45	6.62	−0.55
Mahu Depression Fengcheng Formation	Dolomitic limy Shale	F1	4920.80	0.56	0.29	1.09	1.94	2.27	−0.41
		F2	4943.68	0.04	0.18	0.97	1.19	1.78	−0.66
	Dolomitic limy felsic Shale	F3	4880.85	0.93	0.21	2.68	3.81	4.27	−0.65
		F4	4886.16	0.50	0.12	1.94	2.56	2.25	−0.71
	Felsic Shale	F5	4932.74	0.10	0.28	1.14	1.52	1.15	−0.56
		F6	4950.36	0.42	0.55	3.08	4.05	3.33	−0.63
		F7	4958.97	0.19	0.27	2.51	2.97	3.53	−0.75
		F8	4970.34	0.21	0.23	0.29	0.73	0.96	−0.07
	Siliceous shale	F9	4907.85	0.59	0.43	1.93	2.95	2.21	−0.51
		F10	4938.45	0.14	0.51	2.19	2.83	1.93	−0.59
		F11	4961.19	0.17	0.24	2.84	3.25	1.65	−0.80

). In the alternate imbibition experiment, the total fluid porosity is 3.44%, and the core gas-measured porosity is 4.75%. Through capillary action, the oil–water mixture can enter 72% of the core pore volume, indicating that the imbibition fluids can effectively fill most of the open pore systems in the sample. Gas-measured porosity represents the total pore volume, while the porosity obtained from the imbibition experiment is close to 3/4 of the total. This high imbibition efficiency ratio verifies the reliability of the alternating imbibition process, indicating that the experimental method can adequately characterize the effective pore space of the sample and has good applicability in heterogeneous reservoirs. Some samples (F4, F5, F6, F9, F10, F11) from the Fengcheng Formation have a higher total porosity upon imbibition than their gas-measured porosity, indicating that imbibition fluids can enter some closed pores and microfractures via wettability. Comparing the two areas, the total imbibition porosity of the Lucaogou Formation is higher, with larger oil-wet pores and water-wet pores and smaller mixed-wet pores, reflecting a more developed reservoir space in its formation, with larger oil-wet pores being more favorable for oil adsorption and accumulation in the pores. The reservoir capacity of the Fengcheng Formation is weaker than that of the Lucaogou Formation, with a higher mixed-wet porosity being beneficial for the flow of the two oil–water phases, leading to strong imbibition displacement effects.

According to the results of the wettability index (Table 2), the mixed-type shale of the Lucaogou Formation and the Fengcheng Formation, as a whole, exhibits an oil-wet characteristic. The method for calculating the wettability index is shown in Equation (1): its value range is between −1 and +1, with positive values indicating hydrophilicity and negative values indicating oleophilicity, allowing for a quantitative characterization of rock wettability. ϕwater is the water saturation porosity, i.e., the pore volume that water can spontaneously imbib; ϕoil is the oil saturation porosity, i.e., the pore volume that oil can spontaneously imbib; ϕtotal is the total porosity, including open pores and partially closed pores.

$$W={\displaystyle \frac{\varphi \mathrm{water}-\varphi \mathrm{oil}}{\varphi \mathrm{total}}}$$

(1)

The wettability index distribution of the Lucaogou Formation reservoirs ranges from −0.74 to −0.55, indicating moderate to strong hydrophobicity, with hydrophobic intensity varying stepwise and being controlled by lithology. Sandstone exhibits the strongest hydrophobicity, with a wider wettability index range (−0.74~−0.57), with some samples approaching strongly hydrophobic; argillaceous sandstone has moderate hydrophobicity, with indices concentrated between −0.66~ and −0.60, showing a relatively homogeneous hydrophobic trend; sandstone with ankerite has the weakest hydrophobicity, with a wettability index of −0.55. Among the three lithologies, the wettability difference between sandstone and sandstone with ankerite spans 0.19, reflecting the regulatory effect of lithological components, while argillaceous sandstone exhibits transitional characteristics. The wettability index distribution of the Fengcheng Formation ranges from −0.80 to −0.07, spanning a continuous range from strongly hydrophobic to weakly hydrophobic, with an extremely heterogeneous overall wettability. Significant differences in wettability exist among different lithologies, with argillaceous feldspathic shale showing the strongest hydrophobicity, with indices concentrated between −0.71~−0.65, exhibiting a somewhat strongly hydrophobic feature; siliceous shale is second, with an index range of −0.80~−0.51, showing a transition between strong hydrophobicity and moderate hydrophobicity; argillaceous feldspathic shale has intermediate wettability, with indices distributed between −0.66~−0.41 and hydrophobicity showing a weakening trend controlled by lithology; feldspathic shale exhibits the weakest hydrophobicity, with an index range of −0.75~−0.07, a wide span, and the strongest heterogeneity. Among the four lithologies, the wettability span between argillaceous feldspathic shale and feldspathic shale is 0.73, indicating significant differentiation, revealing the impact of lithological combinations on wettability. There are significant differences in the wettability characteristics of the Lucaogou Formation and the Fengcheng Formation shale reservoirs. The wettability index range of the Lucaogou Formation is only 0.19, indicating that its wettability distribution is more concentrated and it exhibits stronger oil-wettability overall, which is favorable for the retention of shale oil in pore spaces and may promote the effective transfer of energy to the oil phase through more favorable capillary action. In comparison, the wettability index range of the Fengcheng Formation is as high as 0.73, significantly higher than that of the Lucaogou Formation, reflecting the larger range of wettability changes due to the complexity of rock properties in this reservoir, and indicating weaker oil-wettability overall. This may suggest that the retention capacity of shale oil in the Fengcheng Formation is relatively poor, and the heterogeneity of wettability may reduce the efficiency of energy transfer, thereby affecting the final recovery rate of shale oil. This provides an important direction for wettability optimization in subsequent reservoir modification.

Cross-validation between the wetting index and contact angle measurements reveals a highly synergistic change pattern (Figure 10): a decrease in the wetting index is always accompanied by a synchronous reduction in the contact angle, which is also indicative of differences in oil-wettability. This data confirms the accuracy of the alternate imbibition experiments, where the observed oil phase imbibition volume is significantly higher than that of the water phase (wetting index = −0.57), matching the contact angle measurement results; simultaneously, this correlation further verifies the reliability of NMR continuous-measurement technology, as one feature of a significant increase in long relaxation components in oil-saturated samples is a direct reflection of oil-wettability at the pore scale. Ultimately, it is conclusively determined that the mixed-type shale of the Lucaogou Formation and Fengcheng Formation exhibits an overall oil-wet characteristic.

4.2. Analysis on Factors Influencing Wettability of Mixed Rocks

4.2.1. Material Composition

Organic matter in shale is key to producing oil-wet wettability, especially its non-polar components, which enhance the force of the interaction between rock and oil phases, making the rock surface more easily covered by oil [47]. In a saline lake basin turbidite-type shale setting, there is a linear relationship between the wettability index and TOC content (Figure 11a); the higher the TOC content, the lower the wettability index (the stronger the oil-wetness). This relationship was verified in two typical formations: the Lucaogou Formation is mainly composed of siltstone, while the Fengcheng Formation is mainly composed of felsic shale. Lithological comparisons show that samples from the Lucaogou Formation are mostly distributed in the high TOC range, with significantly higher TOC content than those from the Fengcheng Formation. Their average wettability index is lower, confirming that high organic matter abundance directly leads to stronger oil-wetness. The Fengcheng Formation has generally lower TOC content and weaker oil-wetness overall compared to the Lucaogou Formation. The Lucaogou Formation is mainly composed of calcareous siltstone and calcareous silt, while the Fengcheng Formation is mainly composed of calcareous mudstone, calcareous felsic mudstone, and siliceous mudstone, with relatively complex source material compositions. In terms of lithological comparison, samples from the Lucaogou Formation are mainly distributed in areas with a relatively higher TOC content, indicating increased organic matter abundance, and a generally lower wettability index, being more oil-wet. Samples from the Fengcheng Formation are mainly concentrated in areas with relatively lower TOC content, showing relatively weaker oil-wetness, reflecting that the overall oil-wetness of the Fengcheng Formation is not as strong as that of the Lucaogou Formation.

It should be noted that the degradation of organic matter in rocks is primarily influenced by the type of organic matter itself and environmental factors (e.g., temperature, pressure, microorganisms). Among the environmental factors, temperature is the dominant driver of organic matter degradation. Thermal simulation experiments focusing on hydrocarbon generation show that, at low temperatures (<150 °C), microbial degradation prevails, where light hydrocarbons in crude oil are decomposed under aerobic or anaerobic conditions. In contrast, at moderate to high temperatures (>150 °C), thermal cracking becomes the primary pathway, converting heavy components and kerogen into low-molecular-weight products. Under the experimental conditions of this study, the thermal degradation of organic matter is negligible. Although microbial degradation may occur slowly, it requires specific microbial communities, which are limited in laboratory settings. Consequently, the degradation rate is extremely low and can be considered negligible [48,49].

By analyzing the relationship between the wettability index and the distribution of carbonate mineral content, an “L” shape correlation diagram (Figure 11b) is observed. When carbonate content is low (below 20%), the wettability index rapidly decreases, and oil-wetness increases. However, as the carbonate content continues to increase, the wettability index rises and converges within the moderately oil-wet range. This indicates that an excess of carbonate minerals negatively affects the wettability of rocks, reducing oil-wetness [50]. Primarily influenced by mineral distribution differences caused by content variations, when carbonate content is low, it exists in the form of fine particles and xenoliths, making it easier to affect the wettability properties of rock samples. As carbonate content increases, these mineral particles form continuous or relatively continuous clusters and layers, causing the overall trend of wettability changes to slow down [51].

Comprehensive analysis indicates that the wettability of turbidite rocks is co-regulated by the total organic carbon (TOC) content and carbonate content, which in turn affects the energy replenishment efficiency of shale oil reservoirs. The TOC content has a positive effect, increasing oil-wettability, meaning that more organic matter surfaces are favorable for the adsorption and retention of oil phases, which may enhance capillary forces and promote energy transfer from the aqueous phase to the oil phase. However, this positive effect exhibits a saturation effect. Appropriate carbonate content also has a positive effect on increasing oil-wettability, possibly because it improves pore structure, increases the contact area of the oil phase, and aids in optimizing wettability. However, excessive carbonate may occupy oil phase space, reducing oil-wettability and hindering effective energy transfer. Therefore, when the TOC content is high and the carbonate content is moderate, the oil-wettability of the rock is often stronger, creating favorable conditions for shale oil storage and energy replenishment. Conversely, when the TOC content is low and the carbonate content is excessively high, the oil-wettability of the rock is weaker, leading to reduced effective energy transfer and shale oil extraction. This suggests that during the development of shale oil reservoirs, we need to fully consider the impact of TOC and carbonate content on wettability.

4.2.2. Lamination Type

The wettability of the Fengcheng Formation is mainly controlled by the type and proportion of laminae, with different laminae contributing different wetting pores and thus collectively forming the overall wettability characteristics. The Lucaogou Formation lacks a distinct lamina structure, featuring blocky conglomerates, and its wettability is influenced by factors such as mineral composition, organic matter content, and pore structure. As shown in Figure 12, regardless of whether there is a high or low proportion of oil pores, water pores, or mixed pores, the variation in the content of felsitic laminae is relatively small, indicating that felsitic laminae contribute relatively evenly to the wettability of the three types of pores. Its main function is to provide pore space, offering a place for the storage of oil and water, but it does not significantly favor any specific type of wettability. Clayey limestone laminae are closely related to the development of oil-wet pores. Figure 12a clearly shows that areas with a high proportion of oil pores have a significantly higher content of clayey limestone laminae compared to areas with a low proportion of oil pores, confirming that oil pores mainly originate from the contribution of clayey limestone laminae. Clayey limestone laminae are composed of oil-wet minerals, including dolomite and calcite, further enhancing their affinity for oil and leading to the formation of oil-wet pores. Siliceous laminae are important areas for the formation of water-wet environments. Figure 12b shows that areas with a high proportion of water pores have a significantly higher content of siliceous laminae compared to areas with a low proportion of water pores, verifying that water pores mainly originate from the contribution of siliceous laminae. Siliceous minerals typically carry a negative charge, enabling them to strongly interact with water molecules to form hydration films, thereby promoting the formation of water-wet environments [52]. Clayey felsitic laminae contribute the most to mixed-wet pores. Figure 12c indicates that areas with a high proportion of mixed pores have a significantly higher content of clayey felsitic laminae compared to areas with a low proportion of mixed pores. This lamina has characteristics of both felsitic and clayey limestone, and its complex mineral composition results in both oil-wet and water-wet sites, leading to mixed wettability. This mixed wettability state allows for oil and water to coexist in the same pore, increasing the complexity of hydrocarbon storage. In the Fengcheng Formation, felsitic laminae serve as the pore matrix, clayey limestone laminae dominate the oil-wet environment, siliceous laminae dominate the water-wet environment, and clayey felsitic laminae form a mixed wet state. Different laminae influence each other, collectively determining the pore wettability preference, and thus affecting the wettability characteristics of the reservoir. The differential contribution of different lithological layers in the Fengcheng Formation to wettability directly affects the energy replenishment mechanism of shale oil. Oil-wet argillaceous layers promote oil retention, enhance capillary forces, and facilitate the transfer of water phase energy to the oil phase; water-wet siliceous layers may impede energy transfer and reduce recovery rates. The mixed wettability of layers containing argillaceous and felsic materials increases the complexity of energy transfer pathways; therefore, clearly defining the types and proportions of lithological layers and their control on wettability is beneficial for developing more effective reservoir management schemes.

4.2.3. Pore Structure

The Lucaogou Formation and Fengcheng Formation, as mixed turbidite shale oil reservoirs, have wettability characteristics that are controlled by multiple factors. These factors not only include the wettability preference, which is determined by the combination of lamina types, but are also closely related to the micro-pore structure [53]. As shown in Figure 13b, with an increase in porosity, the proportion of oil-wet pores in the reservoir shows an increasing trend, while the proportions of water-wet pores and mixed-wet pores remain relatively stable. This confirms that higher porosity can provide a larger space for oil and gas storage, which is favorable for oil saturation. Regarding the trend in changes in the wettability index, although the specific manifestations of the Lucaogou Formation and Fengcheng Formation differ, both generally show that as porosity increases, the reservoir wettability index gradually tends towards strong oil wetting (Figure 13a). There are also differences in the relationship between porosity and wettability between the Lucaogou Formation and the Fengcheng Formation. The wettability index of the Fengcheng Formation shows a relatively obvious correlation with porosity, indicating that porosity has a more significant impact on the wettability of the Fengcheng Formation. On the other hand, although the wettability index of the Lucaogou Formation is relatively concentrated across all porosity ranges, it also shows a certain correlation, suggesting that the controlling factors for its wettability are more complex, being influenced not only by porosity but also by mineral composition, organic matter content, and other factors. Further distinguishing the roles of different pore types reveals that, although a large number of micropores have limited reservoir space, they can significantly increase the specific surface area, which is favorable for the adsorption of organic matter and thus enhances overall oil wettability and provides favorable conditions for oil phase adsorption and storage. Macropores, on the other hand, focus on providing macroscopic oil and gas storage space, more directly determining the reservoir’s storage capacity [54]. This further explains the overall oil-wet wettability characteristics of mixed turbidite shale reservoirs in salinized lake basins mentioned in Section 4.1. Additionally, there are differences in the degree of pore development between the Lucaogou Formation and the Fengcheng Formation. The porosity range of the Lucaogou Formation is relatively large (1–8%), reflecting its strong heterogeneity in terms of pore development. The porosity of the Fengcheng Formation is relatively concentrated (1–4%), indicating that its pore structure is controlled by relatively singular factors. These differences lead to significant differences in the oil and gas accumulation patterns of the two formations (Figure 13a). The wettability of the reservoirs in the Lucaogou Formation and the Fengcheng Formation is controlled by multiple factors working together, with porosity playing an important role by indirectly regulating wettability through its effects on pore space size and oil and gas storage patterns. Porosity affects the wettability of the Lucaogou Formation and the Fengcheng Formation differently, thereby impacting the efficiency of energy supplementation. High porosity generally favors oil-wettability, enhances capillary force, and promotes energy transfer. Micropores increase the specific surface area, facilitate the adsorption of organic matter, and improve oil-wettability; macropores provide storage space. The porosity of the Lucaogou Formation is strongly heterogeneous, possibly making energy supplementation more complex; the Fengcheng Formation has a simple pore structure, resulting in relatively stable energy supplementation.

4.2.4. Increase Recovery Rate

Based on the characteristic of shale reservoirs where 74% of the pores are oil-wet (12% mixed-wet, 14% water-wet), a targeted wettability control strategy is implemented during actual shale development: First, an anionic-nano composite surfactant is used to fundamentally modify oil-wet pores, reducing capillary resistance through ultra-low interfacial tension and changing the pore wall wettability from oil-wet to weakly water-wet, and thus converting capillary resistance into imbibition driving force. Second, precise control is applied to the mixed-wet region: the water-wet and mixed-wet pores are maintained in their natural state to avoid interference, while ultra-low-concentration surfactants are used to protect the spontaneous imbibition advantage. Finally, a “injection-stop-micro-drive” dynamic shut-in circulation is adopted and combined with the 90 °C reservoir temperature to compress the shut-in period from 30 days to 3–5 days, thereby improving matrix replacement efficiency and reducing shut-in energy consumption by 50%. This ultimately achieves an economically and efficiently developed goal for ultra-low-permeability shale oil.

5. Conclusions

Alternating imbibition using oil–water mixtures can reach 72% of the pore volume of the core, verifying that the experimental method can effectively simulate the process of energy replenishment in shale oil reservoirs. The total imbibition porosity of some Fengcheng Formation samples was higher than the gas-measured porosity, indicating that changes in wettability can promote fluid invasion of sealed pores and microfractures, potentially activating oil flow capacity. The total porosity of imbibition in the Lucaogou Formation was even higher, with a significant proportion of oil-wet pores, suggesting that its reservoir space is well developed and conducive to oil-phase adsorption enrichment, providing a good foundation for energy transfer from the aqueous phase to the oil phase. The wettability index shows that the Lucaogou Formation is predominantly oil-wet (−0.74~−0.55), while the wettability of the Fengcheng Formation has a large range (−0.80~−0.07), being significantly controlled by the non-homogeneity of the lithology. The difference in oil-wetness between the two types of reservoirs reveals the key role of lithological combinations in the distribution of wettability, which in turn affects the efficiency of energy replenishment.

TOC content and carbonate minerals jointly regulate the wettability of clastic rocks, indirectly affecting energy replenishment efficiency. When TOC content is below 1%, its increase enhances oil wettability, which is favorable for oil phase adsorption, enhances capillary force, and promotes energy transfer; after exceeding 1%, the influence of TOC on wettability weakens, and the dominance of the mineral composition increases. The Lucaogou formation has high TOC abundance (generally >1%), with a dominant mineral composition of siltstone and strong oil wettability, and is more conducive to efficient energy replenishment. The Fengcheng formation has a lower TOC and complex lithology, with weaker oil wettability. The relationship between carbonate content and wettability is “L”-shaped; moderate carbonate content (<20%) can significantly enhance oil wettability, while excessive amounts may reduce oil wettability, hindering effective energy transfer. The synergistic effect of TOC and carbonate indicates that a combination of high organic matter abundance and moderate carbonate content is more favorable for the development of strongly oil-wet reservoirs, promoting the transfer of water phase energy to the oil phase.

The layer types in the Fengcheng Formation dominate in terms of differentiating wettability, directly affecting the energy replenishment pathways. Gypsum-shale layers contribute oil-wet pores, increasing oil phase saturation and promoting oil phase continuity, which is beneficial for effective energy transfer; siliceous layers promote water-wet pores, which may form water locks, hindering energy transfer. Layers containing gypsum and granite form mixed-wet pores, increasing the complexity of energy transfer. The proportion of layers directly affects pore wettability preference; the proportion of gypsum-shale layers is positively correlated with oil pores, while siliceous layers are positively correlated with water pores. The Lucaogou Formation has a clastic conglomerate structure, with wettability controlled by multiple factors, including minerals, organic matter, and pore structure. Layer combinations regulate oil and water distribution through the differences in layer properties; granite layers act as pore matrices, providing space, and the complex layer combinations result in significantly higher non-homogeneity of wettability in the Fengcheng Formation compared to the Lucaogou Formation, increasing the difficulty of energy replenishment.

Increased porosity promotes enhanced oil wettability, which in turn affects energy replenishment efficiency. Micropores enhance organic matter adsorption through high specific surface area, increasing oil wettability and facilitating energy transfer from the aqueous phase to the oil phase, while macropores dominate macroscopic storage capacity, providing a space for energy storage. The porosity range in the Lucaogou formation is wide (1%~8%), and wettability is influenced by porosity, TOC, and mineral overlay; the porosity in the Fengcheng formation is concentrated (1%~4%), and wettability is more sensitive to changes in porosity. Porosity structure indirectly affects wettability intensity and heterogeneity characteristics by regulating oil and water storage space and specific surface area, thereby influencing energy replenishment efficiency and the final oil recovery rate of shale oil.

Based on the characteristic of an oil-wet pore occupancy of 74% in shale reservoirs, differentiated wetting regulation should be implemented: anionic-nano-composite surfactants should be used to fundamentally alter oil-wet pores; precise protection strategies should be executed for mixed wetting zones (to maintain the natural state of water-wet/mixed zones + enhance spontaneous imbibition with ultra-low concentration of active agents); and with optimized “dynamic shut-in” technology (injecting liquid—stopping flow—micro-drive cycle, 90 °C reservoir temperature field) should compress the shut-in period to 3–5 days to improve displacement efficiency while reducing energy consumption by 50%, improving the economic development of ultra-low-permeability shale oil.