Controlling Factors of Drilling-Associated Hydrocarbon Content in Shale Reservoirs with Hybrid Condensates in Terrigenous Basins

1. Introduction

Hybrid condensates require refining processes to eliminate higher-boiling-point hydrocarbon fractions (>CH4). Upon isolation, these residual hydrocarbons undergo liquefaction, yielding natural gas condensate (NGC) (Speight, 2020). Such reservoirs exhibit complex thermodynamic responses marked by sub-dew-point pressures that drive condensate precipitation and compositional alteration of reservoir gases (Ganjdanesh et al., 2019; Hassan et al., 2019). Contemporary classification frameworks categorize hybrid shale condensate resources into two distinct groups: liquid-lean and liquid-rich systems. Both classes predominantly comprise C1-C33 n-alkanes, with the C1-C7 fraction persisting in gaseous states under reservoir conditions. Volatile light hydrocarbons (VLHs, C3-C7) critically govern lean condensate formation through phase partitioning mechanisms (Clarkson et al., 2015; Sheng et al., 2016; Hassan et al., 2019; Xue-wu et al., 2020).

Recent exploration efforts in terrigenous basins have exposed critical knowledge gaps in characterizing shale condensate reservoirs. The interplay between elevated clay mineral content and heterogeneous organic inputs introduces substantial uncertainties in hydrocarbon distribution patterns (Cardott, 2012; Gherabati et al., 2016; Ganjdanesh et al., 2019; Şen & Kozlu, 2020; Strąpoć et al., 2020). Two principal analytical challenges have been identified in reservoir evaluation:

1. Hydrocarbon Phase Dynamics: Drilling-induced pressure-temperature perturbations frequently trigger phase transitions, particularly when formation pressures decline below dew-point thresholds near wellbores (Middleton et al., 2015; Clarkson et al., 2016; Zhang et al., 2020). Differential retention mechanisms further complicate analysis: C1-C2 alkanes demonstrate sluggish diffusion kinetics, while VLHs (C3-C7) and liquid-phase components (C7+) persist in metastable configurations within fracture networks and matrix porosity (Sheng, 2015; Jiang & Younis, 2016; Sheng et al., 2016). These phenomena limit the efficacy of conventional C1-C7 advanced mud-gas logging (AMGL) for quantitative hydrocarbon assessment.

2. Lacustrine Reservoir Heterogeneity: Compared to marine shale analogs, lacustrine systems exhibit amplified lithofacial variability due to laminated architectures that induce strong anisotropic hydrocarbon distribution and condensate productivity (Li et al., 2018, 2019). Additional complexity stems from dynamic phase behavior modulated by thermal maturity gradients, in situ P-T conditions, and near-wellbore condensate banking effects (Li et al., 2015, 2019). Collectively, these factors impede reliable identification of hydrocarbon sweet spots in terrigenous shale reservoirs.

The China Geological Survey (CGS) implemented a multidisciplinary investigation of the Cretaceous Shahezi Formation (K1sh Fm.) within the Songliao Basin. This study analyzed 120 meters of core samples from >3000m depths through an integrated analytical protocol:

1. High-resolution geochemical profiling via systematic 0.5-meter interval measurements (n>1000) employing rock pyrolysis, desorption gas chromatography, elemental analysis, and RoqScan mineral quantification.

2. Phase-specific hydrocarbon characterization using S1 (C7-C33) parameters and total gas content (TGC), with speciation of gaseous (C1-C2) versus volatile (C3-C7) components.

3. Lithofacies discrimination through mineralogical-TOC correlation, augmented by elemental proxies for paleoenvironmental reconstruction.

4. Nanoscale microstructural analysis utilizing dual-beam FIB-SEM (Helios Nanolab G3 UC) and FESEM (Merlin Compact) to resolve organic-inorganic interfaces, elemental migration pathways, and hydrocarbon-bitumen associations.

5. Phase behavior modeling via a novel Hybrid Shale Condensate Index (HSCI) incorporating Tmax values to map maturity-controlled phase distributions across C1-C33 hydrocarbons.

6. Multivariate statistical integration of HSCI, S1, TGC, Tmax, TOC, and compositional datasets to delineate dominant hydrocarbon distribution controls.

This approach establishes S1 and TGC as robust proxies for liquid and volatile hydrocarbon phases, respectively, while providing a systematic framework to decipher hydrocarbon occurrence mechanisms in complex shale condensate systems.

2. Geological Background

Songliao Basin of China, is situated in the eastern slope zone of the Lishu Fault Depression within the Southeast Uplift of the Songliao Basin. The Lishu Fault Depression is notable for having the longest fault depression period, the most complete stratigraphic development, the thickest sedimentary deposits, and the deepest burial in the southeast uplift area of the Songliao Basin, covering a total area of 2822 km². The basin contains two primary sets of strata: the fault depression layer and the depression layer. The fault depression layer has a thickness ranging from 0 to 8000 meters, with a maximum burial depth exceeding 10,000 meters. This layer includes the Cretaceous Huoshiling Formation (K1h), Shahezi Formation (K1sh), Yingcheng Formation (K1yc), and Denglouku Formation (K1d), with deep, semi-deep, and shore shallow lake deposits found beneath the Denglouku Formation. The depression layer consists mainly of the 1st Quantou Group (K1q), the Qingshankou Group (K2qn), the Yaojia Group (K2y), the Nenjiang Group (K2n), and Quaternary strata, with fluvial facies deposition. The Shahezi and Yingcheng Formations are the primary sections of thick shale developed during the fault subsidence period(Figure 1).

From top to bottom, the JLYY-1 well drilled through the Quaternary, Upper Cretaceous Qingshankou Formation, Lower Cretaceous Quantou Formation, Yingcheng Formation, and Shahezi Formation. The measured formation pressure of the Shahezi Formation ranges from 19.38 to 26.56 MPa, with a formation pressure coefficient between 0.84 and 1.0, averaging approximately 0.98. The formation temperature gradient in the Shahezi Formation is between 3.3°C/100m and 3.5°C/100m, indicating a normal temperature system. The formation temperature at the bottom of the JLYY-1 well is approximately 120°C.

3. Methods

3.1. Geochemical Logging of Rock Pyrolysis

To conduct a geochemical evaluation of the hybrid shale condensate reservoirs, the test procedure follows the China National Standard SY/T 5778-2008. The geochemical logging instrument operates based on the principle of heating rock samples in a special cracking furnace, allowing the hydrocarbon and kerogen within the samples to volatilize and crack at different temperatures. The carrier gas (hydrogen) is introduced to separate the hydrocarbons physically and qualitatively from the rock samples, which are then carried into the hydrogen flame for separation. This process can be used to evaluate the thermal evolution of source rocks and the oil-gas properties of reservoirs according to the following steps (El-Khadragy et al., 2018; Shalaby et al., 2019):

1. The sample is pretreated, weighed, and placed in a crucible, then purged with nitrogen and heated to 90°C. The light hydrocarbons (less than C7) in the sample are blown into the hydrogen flame ionization detector, and the S0 peak is measured.

2. The sample is automatically transferred into the pyrolysis furnace by a sampling rod, where liquid hydrocarbons (C8–C33) are pyrolyzed at a constant temperature of 300°C for 3 minutes. The hydrogen flame ionization detector measures the heavy hydrocarbons in the sample.

3. The pyrolysis furnace is programmed to increase the temperature from 300°C to 600°C. As the temperature rises, heavy hydrocarbons (greater than C33) evaporate, and the cracking of gum, asphaltene, and kerogen occurs. The S2 peak is obtained by detecting the cracked hydrocarbons in the rock sample. (If the sample is a source rock, the following steps are required.)

4. The pyrolysis sample is transferred to the oxidation furnace, where air is introduced, and the temperature is maintained at 600°C for 5 minutes. The residual carbon in the rock sample is burned into carbon dioxide, allowing the S4 peak to be measured.

In this study, the entire cored section is tested using the geochemical logging rock pyrolysis method. The measured S1 values, which are contributed by hydrocarbons from C8 to C33 n-alkanes, are used to indicate the movable liquid hydrocarbon content in the reservoir.

3.2. Geochemical Logging of Rock Elements

The test procedure follows the China National Standard SY/T 7420-2018. The fundamental principle of X-ray logging technology is based on the interaction between high-energy X-rays and the sample. When the high-energy X-rays bombard the sample, electrons are released from the outer shells of the atoms, creating electron vacancies. Subsequently, electrons from higher energy levels fall into these vacancies, emitting characteristic X-rays (X-ray fluorescence). The energy and wavelength of these emitted X-rays vary depending on the element involved. By analyzing the energy or wavelength of the X-ray fluorescence, the type and quantity of elements present in the sample can be determined (Konaté et al., 2017). Elements in the weathering zone can be classified into five categories:

1. Most easily migrated elements: Cl, Br, and S.

2. Easily migrated elements: Ca, Mg, Na, F, Sr, K, Zn, P.

3. Migrated elements: Cu, N, Co, Mo, V, Mn, P, S (in silicates).

4. Stable elements: Fe, Al, Ti, Se.

5. Hardly migrated element: Si.

In this study, elements including Na, Mg, Al, Si, P, S, Cl, K, Ca, Fe, Mn, Ti, Th, and U are analyzed across the entire shale gas condensate cores. The results are then used to investigate the influence of the paleo-sedimentary environment on the in-situ condensate hydrocarbon content.

3.3. Total Gas Content (TGC) of Desorption Gas

The Coalbed Methane Shale Gas Pulse-Type Intelligent Tester, model HTG-Pulse-6, is used to measure the Total Gas Content (TGC). The start metering conditions are determined by the differential pressure sensor (default value: 5 Pa), which triggers the pulse device to start counting at a rate of 200 pulses per minute. The gas passes through the standard pipeline when gas desorption occurs (Ma, et al., 2020). The number of pulses is directly proportional to the volume of gas passing through the standard pipeline, allowing for the accurate calculation of gas volume via pulse metering (Ahmed et al., 2016; Yoshida et al., 2018). Total gas content is calculated in accordance with GB/T 19559-2008 of the People’s Republic of China.

In this study, TGC is composed of lost gas, desorption gas, and remaining gas. It is measured across the entire cored section to assess the light hydrocarbon (C1–C7) content in the gaseous phase.

3.4. Mineral Components and Scanning Photos of the Roqscan Technology

Roqscan is a scanning electron microscope developed by CGG and Carl Zeiss, designed for use directly in the drilling field. It allows for semi-automatic analysis of elements, mineralogy, and structures in rocks, including cuttings, cores, sidewall coring, and thin sections. The original data generated by Roqscan includes elemental data (over 50 types), mineral data (over 100 types), structural data (such as mineral structure, porosity, pore size distribution, pore surface ratio, and pore throat structure), as well as high-definition digital mineral images (pseudo-color mineral images with a maximum resolution of 250 nm) based on Roqscan testing technology (Parian et al., 2015; Shiet al., 2019; Zhai et al., 2019).

Roqscan is a mineral scanning electron microscope equipped with an electronic signal detector, an X-ray detector, and various advanced analytical software. It can be used not only in the laboratory but also as a portable, durable rock cutting and core mineral analysis system at the well site for oil and gas wells. In addition to quickly and quantitatively identifying the elements, minerals, clays, types, images, and gamma radiation of cuttings or cores while drilling, Roqscan can also provide data on density, porosity, pore structure, granularity, rock brittleness, lithology, and elasticity (Johnson et al., 2015; Li et al., 2020).

In this study, Roqscan technology is used to analyze the mineral composition of the entire cored section. Additionally, laminae composed of different minerals in the terrigenous shales are observed through Roqscan electron microscope images, contributing to the study of how lithofacies and lamina-induced fractures affect condensate hydrocarbon content.

3.5. Electron Microscope Imaging Technique

We utilize the FIB (Focused Ion Beam) of the Helios Nanolab G3 UC and the FES (Field Emission Scanning Electron Microscope) of the Merlin Compact to study the micro-nanometer fine-grained rock structure, elemental composition, and reservoir characteristics. Specifically, we employ the FES of the Merlin Compact to analyze the elemental components in organic matter and inorganic minerals, while the FIB of the Helios Nanolab G3 UC is used to produce high-resolution images of the nanometer-scale shale reservoirs.

3.6. Hybrid Shale Condensate Index (HSCI)

The fluid type on the surface is typically classified based on the gas-to-oil ratio (GOR) and oil viscosity (API), as shown in Table 1 and Table 2 (Gherabati et al., 2016; Li et al., 2019). Both GOR and API are determined by the light hydrocarbon components (C1–C7) and heavy hydrocarbon components (C7+) (Arouri et al., 2010; Huang et al., 2015; Cesar et al., 2019). The hydrocarbon content in the gaseous phase ranges from mixtures of methane and ethane with very few other constituents (dry gas) to mixtures containing a range of hydrocarbons from methane to pentane, and even hexane (C6H14) and heptane (C7H16) (wet gas). In both cases, some carbon dioxide (CO2) and inert gases, including helium (He), are present along with hydrogen sulfide (H2S) and trace amounts of organic sulfur (Huang et al., 2014; Mei et al., 2018; Milkov et al., 2020).

In this study, we aim to classify the fluid type of drilling-associated hydrocarbons using the in-situ hydrocarbon components based on the surface fluid classification. While C1–C7 AMGL logging methods are employed during drilling, testing the gas hydrocarbon content of hybrid shale condensates is challenging. This difficulty arises because the liquid phase formed in the matrix typically remains below residual oil saturation. Moreover, the heavier hydrocarbon components (C7+) will be permanently trapped in the matrix unless enhanced oil recovery techniques are applied. This is especially true under drilling conditions where only small amounts of C1–C2 hydrocarbons can flow to the gas content tester due to the density of the drilling fluid. Therefore, the hybrid condensates cannot be fully evaluated without considering the accompanying oils.

As a result, we propose a new index, the Hydrocarbon Saturation Classification Index (HSCI), which uses the molar components of C1–C7 and C7+ to classify the fluid type, as described in Equation 1. Detailed ratio values are calculated according to the molar ratio of hydrocarbon components, as shown in Table 2. The HSCI, as defined in Equation 1, offers an advantage in representing the occurrence of equal and elevated maturity levels in both gaseous and liquid components of condensates, particularly for hybrid condensates. Since the C7+ fraction is the only liquid phase component available in gas condensate PVT analytical data, it is often spuriously increased by depressurization, making a reliable liquid index generally unavailable.

$$\{\begin{array}{c}Liquid Hydrocarbon if{\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}<10\\ Gas Condensate if10<{\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}<60\\ Wet Gas if60<{\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}<128\\ Dry Gas if {\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}>128\end{array}$$

(1)

Here, we made some modifications to fit the light hydrocarbon components ratio as Equation 1, where TGC is used to indicate the volume content of desorbed gas, S1 is used to indicate the mass content of movable hydrocarbon in shale.

$${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}={\displaystyle \frac{m_{C1~C7}}{M_{C1~C7}}}\cdot {\displaystyle \frac{M_{C8~C33}}{m_{C8~C33}}}={10}^3\cdot {\displaystyle \frac{\left(m_{rock}\cdot TGC\right)/{\rho }_{C1~C7}}{M_{C1~C7}}}\cdot {\displaystyle \frac{M_{C8~C33}}{m_{rock}\cdot S1}}={10}^3\cdot {\displaystyle \frac{TGC/{\rho }_{C1~C7}}{M_{C1~C7}}}\cdot {\displaystyle \frac{M_{C8~C33}}{S1}}$$

(2)

where ‘n’ indicates the molar content; ‘m’ indicates the mass for special hydrocarbon components; ‘M’ indicates the molar molecular; ‘TGC’ indicates the total gas content which is tested using the Coalbed methane shale gas pulse-type intelligent tester. Also, the fitting parameters of ${\rho }_{C1~C7}$, $M_{C1~C7}$, and $M_{C8~C33}$ are settled as 0.739g/cm3, 16g/mol, and 78g/mol, respectively.

Note the HSCI is only proposed according to the fluid type classification during production especially related to the hydrocarbon components. However, any kind of hydrocarbon components could not be used separately to illustrate the fluid phase in situ. Thus a further hydrocarbon phase work using the HSCI and the rock pyrolysis data will be discussed in the following Section 4.2.

4. Results

4.1. Influence of Lacustrine Shale Components and Lithofacies

4.1.1. Mineralogical Composition and TOC Distribution

Quantitative mineral analysis utilizing RoqScan and rock pyrolysis reveals distinct compositional zonation in lacustrine shales (Figure 3a and Figure 4). The ternary diagram in Figure 4a delineates bulk lithology into three endmembers: carbonates (orange field), clays (blue field), and siliciclastics (green field). Detailed mineral speciation maps (Figure 4b-c) employ standardized symbology: solid circles denote high-TOC samples (>2 wt%), squares represent medium-TOC (0.5-2 wt%), and triangles mark low-TOC zones (<0.5 wt%). The accompanying clay mineral classification chart identifies seven species through diagnostic XRD peaks: mixed clay (MC, 14Å), illite/muscovite (I/M, 10Å), kaolinite (K, 7Å), mixed calcareous clays (MC(C), 12-14Å composite), chlorite (Ch, 14Å+7Å), glauconite (G, 10Å+4.5Å), and biotite (Bio, 10Å+3.3Å).

4.1.2. Lithofacies Architecture and Geochemical Signatures

Core analysis identifies three vertically stacked units:

Argillaceous Dominance Zone (3080-3115m, Figure 3d-f): Clay content >75 vol% with isotropic fabric (lamination index <0.15).

Laminated Organic-Rich Unit (3115-3165m, Figure 3g): Peak TOC (5.2±0.8 wt%) coincident with pronounced bedding-parallel anisotropy (lamination index >0.65).

Calcite-Fractured Mudstone (3170-3200m, Figure 3h): 89±4% calcite content exhibiting conjugate fracture sets (density: 12±3 fractures/m) and pressure-solution crumples.

4.1.3. Hydrocarbon Phase Partitioning Mechanisms

Three genetic classes emerge from TOC thresholds:

Type I (TOC >2 wt%): S1 (C7-C33) = 1.8±0.3 mg/g, TGC (C1-C2) = 1.6±0.2 m³/t

Type II (0.5-2 wt%): S1 = 0.9±0.2 mg/g, TGC = 1.1±0.3 m³/t

Type III (<0.5 wt%): S1 = 0.3±0.1 mg/g, TGC = 0.7±0.2 m³/t

4.1.4. Mineralogical Controls on Phase Behavior

Figure 4d demonstrates S1 maxima (>1.5 mg/g) in 50-75% clay-content shales, correlating with MC(C) abundance (R²=0.82, p<0.01). Pore network modeling reveals MC(C)-rich zones develop 4.8±1.2% intergranular porosity (Figure 5a, blue clusters) versus 1.2±0.5% in I/M-dominated regions. Further，Spatial correlation analysis (Figure 5b-c) shows TGC maxima (>1.5 m³/t) overlap with high-S1 intervals but lack TOC dependence (r=0.18, p=0.32). SEM-EDS mapping confirms <2% organic porosity, with 83±7% gas stored in clay matrix intercrystals (Figure 5d, yellow highlights).

4.1.5. Reservoir Quality Indicators

Integrated analysis identifies optimal reservoirs as:

Liquid Phase: MC(C) >25%, I/M:K <1.5:1, TOC >2 wt% (Figure 5a red zones)

Gaseous Phase: Clay content 50-75%, illite crystallinity <0.35Δ°2θ (Figure 5c contour lines)

4.2. Influence of Thermal Maturity and Hydrocarbon Phases

Tmax values are used to indicate the thermal maturity valued between 450゜C to 510゜C in a mature and highly mature stage for the vertical shale section from 3080m to 3165m of JLYY-1 well. The liquid friction, as mentioned in the 2.5 section, are depicted by the HSCI of ${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$ as Equation 2, that ${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$ is valued between 0 to 140 for the vertical shale section. Generally, gas friction in gaseous and volatile phases control the shales from 3080m to 3115m, where ${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$ is valued between 60 to 140. Hydrocarbon content increase obviously with the increasing heavier components from 3115m to 3165, which are controlled by the hybrid shale condensate phases.

To illustrate the influence of thermal maturity and hydrocarbon phases on the hydrocarbon content, parameters of S1, TGC and ${\displaystyle \frac{n_{C1~C7}}{n_{C8+}}}$ are used to make a statistical scatter chart where Tmax is settled as the x-axis, black points indicate the S1 values, and blue points indicate the TGC values as Figure 6. Here, S1 and TGC are parameters tested just following the drilling process, indicating the hydrocarbon phases upon the ground, Tmax and ${\displaystyle \frac{n_{C1~C7}}{n_{C8+}}}$ are the in-situ indicators on the conditions underground for the JLYY-1 well. In detail, Tmax is valued from 460゜C to 500゜C, and associated with a liquid hydrocarbon peak (highest S1 values) around 490゜C, while no obvious hydrocarbon peak in gaseous phases correspondingly. Here, ${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$ was used to distinguish the shale hydrocarbon resources in the gas condensate, wet gas, and liquid states respectively. Moreover, a further thermal maturity system was taken into consideration, as proposed by Tissot, that hydrocarbon phases of K1sh Fm. shales reservoir could be classified into 6 types: the wet gas in mature shale (Tmax<480, ${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$>60); wet gas in highly mature shale (Tmax>480,${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}>$60); gas condensate in mature shale (Tmax<480, 10<${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$<60); gas condensate in mature shale (Tmax>480, 10<${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$<60), gas condensate in highly mature shale (Tmax>480, 10<${\displaystyle \frac{n_{C1~C7}}{n_{C8+}}}$<60); liquid in mature shale (Tmax<480, ${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$<10), liquid in highly mature shale (Tmax>480, ${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$<10). The red points indicate the ${\displaystyle \frac{n_{C1~C7}}{n_{C7+}}}$ values as shown in Figure 6., that shale gas condensate in mature and highly mature shale, acting as the major hydrocarbon phases, contribute mostly to the hydrocarbon content of the hybrid shale condensate resources in situ.

4.3. Influence of Paleo-Sedimentary Environment

Major elements (Na, K, Al, Si, Fe, Ca, Mg, Ti, Mn, S, P, Cl) and trace elements (Th, U, Ba, Sr, V, Ni, Cr, Zr) are tested to study the paleo-sedimentary environment of the K1sh Formation and its impact on hydrocarbon content in shale gas condensate layers. Al/Ti ratios indicate paleoclimate conditions (humid or dry), Ca/Fe ratios reflect paleo-salinity (freshwater or saline lacustrine), and (Al+Fe)/(Ca+Mg) ratios suggest paleo-water depth (shallow or deep water). Th/U ratios indicate volcanic tuff presence, while V/(Ni+V) ratios help assess paleo-redox conditions (oxidizing or reducing environment) (Li et al., 2019; Toyoda 1993; Hara et al., 2010; Schenk et al., 2018; Hu et al., 2020; Wu et al., 2020).

As shown in Figure 2, the paleoclimate shifts from humid to dry with increasing Al/Ti values. Shales from 3080m to 3120m were deposited in a more humid climate, resulting in higher hydrocarbon content. The paleo-lacustrine environment transitions from freshwater to saline with increasing Ca/(Ca+Fe) values, making shales from 2097m to 3102m and 3118m to 3137m better for hydrocarbon generation. These sections have higher hydrocarbon content due to the saline water environment. Similarly, increasing (Al+Fe)/(Ca+Mg) values suggest shallower water depths, enhancing hydrocarbon content in the deeper sections (2097m to 3102m and 3118m to 3137m).

Volcanic ash in the paleo-water environment, indicated by fluctuating Th/U values from 3118m to 3137m, also promotes hydrocarbon generation. As proposed by Li et al., (2019), tuffaceous shale layers are key to the hydrocarbon sweet spot during organic-inorganic diagenesis. V is enriched in an oxidizing environment, while Ni is enriched in a reducing one, with higher V/(V+Ni) values indicating stronger oxidizing conditions. For well JLYY-1, a higher reducibility environment is reflected in the shales from 3118m to 3137m, particularly 3118m to 3145m, where the best hydrocarbon content corresponds to the strongest reducing conditions.

Further, hybrid sedimentary factors contribute to organic-rich shales from 3118m to 3137m. Microscopically, organic matter is associated with volcanic activity (e.g., organic-rich clay minerals from devitrified volcanic glass, Figure 7a), terrigenous organic inputs (e.g., bitumen-covered mineral particles, Figure 7b), saline water environments with Si-rich algae (Figure 7c, d), and terrestrial plant inputs (Figure 7e,f). Additionally, bitumen migration along volcanic silica particles (Figure 7g) and bio-silicon organic matter laminae (siliceous laminae, Figure 7h) suggest a hybrid sedimentary model contributing to hybrid condensate gas in terrigenous shale reservoirs.

Overall, paleo-sedimentary factors such as a static water environment with volcanic injection, a humid climate, saline lacustrine conditions, and higher reducibility foster the formation of dominant shale, enhancing hydrocarbon content in hybrid shale condensate reservoirs.

4.4. Influence of Lamina and Lamina Induced Fractures

Lamina-induced fracture systems constitute critical hydrocarbon reservoirs and migration pathways in terrigenous shales, with four distinct lithological types identified through integrated RoqScan and BSE analyses (Figure 3 and Figure 8a-n). Siliciclastic laminae (Figure 8b,d,f), predominantly developed in 3080-3165m clay-rich intervals, feature submillimeter quartz-feldspar bands (<200μm) aligned with face cleats, accounting for 78% of total hydrocarbon storage (S1=1.8±0.4 mg/g). These laminae enhance fracture connectivity through cleat density multiplication (2.3× baseline) and anisotropic permeability development. Clayey laminae (Figure 8h), characterized by 50-150μm amplitude wrinkle structures in calcareous shales, record syn-diagenetic stress conditions (σ₁=15±3 MPa). Carbonate laminae (Figure 8j,k,m) within the same depth interval exhibit 20-80μm calcite-filled fractures with 35±7% spatial filling density, evidenced by crystalline infill textures.

Pyrite laminae (Figure 8l,n) demonstrate unique Fe-S diagenetic banding with organic pore clusters (Φ=8±3%), serving as robust sweet spot indicators through strong TOC correlation (R²=0.91). Their formation involves Fe migration along hydrocarbon flow paths and S enrichment in bitumen-rich zones (EOM=6±2%), particularly where siliceous lamina fractures intersect pre-existing clay-rich matrices. Spatial analysis confirms these lamina systems collectively create interconnected storage networks, with siliciclastic types governing bulk storage capacity while pyrite varieties mark high-TOC (>2 wt%) preservation zones. The observed lamina-fracture configurations—particularly the staggered propagation of pyrite and siliceous laminae in organic-rich intervals—provide diagnostic criteria for identifying hybrid shale condensate sweet spots.

5. Discussion

An integrated model is proposed to illustrate the hydrocarbon generation and evolution of hybrid shale condensate resources, considering the four key factors: lacustrine shale components and lithofacies, thermal maturity and hydrocarbon phases, paleo-sedimentary environment, and lamina-induced fractures, as shown in Figure 9.

5.1. Comparison. of the Hybrid Sediments Model Between Hydrocarbon-Rich Shales and Hydrocarbon-Lean Shales

Volcanism in the faulted lacustrine basin is discussed in Figure 8b and Figure 9a, where significant volcanic activity began in the early Cretaceous due to the subduction of the Indian and Pacific plates beneath the Eurasian plate. This led to the formation of graben basins, particularly in the central fault block of the Songliao Basin (Ji et al., 2019). Based on structural characteristics, volcanism, and early sedimentation, a hybrid sedimentary model is proposed (Figure 9), with Figure 9a, c and 8b, d showing the early faulted lacustrine basin, with and without volcanism, respectively. The hydrocarbon-rich shales occur between 3115m and 3165m, while the hydrocarbon-lean section lies between 3080m and 3115m.

During the early fault depression, volcanic activity raised temperatures, increased atmospheric CO2, and caused mass organism death (Zhang et al., 2018). This created a unique environment for hydrocarbon-rich shales, including a static water setting with volcanic injections, a humid climate, saline lakes, and a reducing environment in a semi-deep, closed lake. Both oxic and anoxic water layers contributed to hybrid organic deposits (Zou et al., 2019), which contained terrigenous salt-tolerant plants, organic matter, and planktonic aerobic organisms (Li et al., 2022). These organic deposits, primarily from aquatic algae, mixed with minerals and formed organic laminae, indicating a stable, reducing environment. Anaerobic bacteria helped degrade organic matter and form authigenic minerals. Organic matter and biological silica deposited along the lake bottom (Figure 9c), leading to siliceous laminae formed by diatoms, radiolarians, and sponge spicules (Brumsack 2006).

The hydrocarbon-rich shales from 3115m to 3165m, which have higher hydrocarbon content than those from 3080m to 3115m (Figure 3), are key to defining "hybrid shale condensate." The gas and liquid hydrocarbon states are influenced not only by in-situ conditions like temperature and pressure (Lerch et al., 2016; Su et al., 2016; Liu et al., 2019), but also by the input of hybrid organic matter. This includes planktonic aerobic organisms (Type-II kerogen) and salt-tolerant plants (Type-III kerogen) (Figure 9c), which contribute to the formation of gas and liquid hybrids in the early stages of hydrocarbon evolution (Rohais et al., 2019; Song et al., 2019).

As the basin evolved, volcanic activity stabilized, and secondary faults formed, leading to deeper waters, a warmer climate, and lower salinity under weak evaporation conditions. The lake environment became more stable, with an oxic layer on top and a dysoxic layer below (Figure 9b). In this stable period, algae preservation was difficult due to the weak reducing environment (Varela et al., 2011), and no hybrid organic inputs occurred. Instead, terrigenous plants and organic matter contributed to Type-III kerogen, a weak hydrocarbon generator, forming sapropelic mudstone in the deep open lake. This explains the lower hydrocarbon content in the shales from 3080m to 3115m.

5.2. The Organic-Inorganic Reactions During the Diagenesis Period for Hydrocarbon-Rich Shales.

After deposition, the hydrocarbon content of hybrid shale condensates is influenced by organic-inorganic reactions during diagenesis (Figure 9g, h, l, j). Here, we examine organic-inorganic interactions to explain hydrocarbon storage and desorption, using FIB and FES electron microscopy to describe the relationship between organic matter, inorganic minerals, and lamina pores (Figure 9k, l, m, n, o, p). The test samples are oriented vertically to the lamina surface.

Organic matter, primarily bitumen observed in SEM photos, results from kerogen evolution and often intergrows with secondary pyrite, calcareous, and siliceous minerals (Figure 9k, l, m, n, o, p). In calcareous laminae (Figure 9k), calcification occurs in the presence of prior clay deposits, where HCO3- combines with Ca and Mg ions to form calcareous diagenetic minerals in slightly alkaline, oxidizing conditions (Cao et al., 2020). Intergranular pores of calcite or dolomite contribute to bitumen storage (Figure 9k), where hydrocarbons are mainly stored in the intergranular pores of clay minerals and calcareous particles, as well as in organic pores.

Siliceous laminae (Figure 9l, m) are often associated with pyrite laminae due to the symbiotic relationship between organic matter and pyrite. Pyrite can either separate from organic matter or become embedded in asphaltene, showing flow traces (Figure 9l). Pyrite is typically surrounded by bio-silicon particles, which are amorphous feldspar products from prior clay deposits (Figure 9m). The bio-silicon particles have a high carbon content (60%-70%) and a significant amount of silicon (15%), indicating the source material is a low organism rich in Si. Pyrite forms in a reducing environment during diagenesis (Kolker 2012).

An interesting phenomenon is seen in Figure 9n, where round clay mineral assemblages are associated with carbonatite particles. These formations resemble structures found in the crystallization process of intrusive igneous rocks and likely result from the clayization of volcanic glass into chlorite and illite. Although it remains uncertain whether the clayization process directly influences organic matter evolution, it is clear that the combination of volcanic glass, organic matter, and carbonatite in a special diagenetic environment contributes to hydrocarbon-rich shales.

The most common mineral intergrowth with organic matter is authigenic quartz, followed by pyrite, illite, and carbonate minerals (Kwiecińska et al., 2019). The interlaced structures formed between organic matter and authigenic minerals are similar to those found in intrusive igneous rock crystallization processes. This suggests that organic matter and authigenic minerals may share common sources and evolved according to their diagenetic habits. The evolution of parent material into asphaltene and crystallization of minerals hints at chemical differentiation between organic and inorganic components, warranting further study.

5.3. The Hydrocarbon and Bitumen of the Hybrid Shale Condense Reservoirs

The organic matter in the cored shales of our study has evolved into condensate and wet gas stages, as discussed in Section 4.2. Hybrid shale condensate and gas in mature and highly mature shale are the dominant hydrocarbon phases and contribute significantly to the in-situ hydrocarbon content. Although the light hydrocarbons in gas or liquid states have moved away from the samples due to drilling and coring, the space left by hydrocarbon desorption, exudation, and diffusion remains detectable under specialized electron microscopy.

We use SEM images to indirectly illustrate the hydrocarbon state through FIB and FES technologies. The organic matter in the SEM photos is classified into three types: highly mature organic matter with a vesicular structure (Gas-OM), mature organic matter with liquid mold holes and vesicular structures (Condensate-OM), and bitumen with no movable hydrocarbon traces (Bitumen-OM). As shown in Figure 8p and Figure 9o, Bitumen-OM appears darker, while Gas-OM and Condensate-OM are lighter and more mobile.

Authigenic quartz and asphaltene often coexist, with asphaltene spherulites and mold pores present. In the two-dimensional images, different pore types are visible, mainly those formed by gas generation, accumulation, and escape of hydrocarbons from the parent material. These pores are typically round, with apertures ranging from tens to hundreds of nanometers, varying in size, depth, and shape. Asphaltene development is particularly noticeable in intergranular pores of authigenic minerals, which protect the organic matter and allow hydrocarbons to generate and accumulate. The light hydrocarbons around these pores, along with the asphalts formed during hydrocarbon generation, as shown in Figure 8p and Figure 9o, strongly evidence the accumulation of hybrid shale condensates.

6. Conclusions

1. Clayey shales with 50–75% clay content and elevated MC(C) levels are optimal for forming hybrid shale condensate sweet spots, as hydrocarbons are predominantly stored in organic-rich shales that have experienced only low-grade diagenesis.

2. Hybrid shale condensate reservoirs can be categorized into six types based on rock maturity and hydrocarbon phase—spanning wet gas, gas condensate, and liquid phases observed in both mature and highly mature shales. In these systems, gas condensates are the dominant contributor to the in-situ hydrocarbon inventory.

3. Paleo-sedimentary factors—such as volcanic injection, humid climatic conditions, saline lacustrine settings, and increased reducibility—promote the formation of shales with high hydrocarbon potential.

4. Siliciclastic laminae play a crucial role in enhancing hydrocarbon content, while the presence of pyrite laminae is indicative of favorable “sweet spot” conditions within organic-rich, clay-dominated shales.