Next Article in Journal
Research Progress on Vaterite Mineral and Its Synthetic Analogs
Previous Article in Journal
Silica- and Sulfur-Rich Deposits Preserving Microbial Signatures at Zannone Hydrothermal Field, Western Mediterranean Sea
 
 
Search for Articles:
Title / Keyword
Author / Affiliation / Email
Journal
Article Type
 
 
Advanced Search
 
Section
Special Issue
Volume
Issue
Number
Page
 
Journals
Minerals
Volume 15
Issue 8
10.3390/min15080795
minerals-logo
Submit to this Journal Review for this Journal Propose a Special Issue
► Article Menu

Article Menu

share Share announcement Help format_quote Cite question_answer Discuss in SciProfiles
first_page
settings
Order Article Reprints
Font Type:
Arial Georgia Verdana
Font Size:
Aa Aa Aa
Line Spacing:
Column Width:
Background:
Article

Genesis of Clastic Reservoirs in the First Member of Yaojia Formation, Northern Songliao Basin

by
Junhui Li
1,
Qiang Zheng
1,
Yu Cai
1,
Huaye Liu
1,
Tianxin Hu
2 and
Haiguang Wu
2,*
1
Exploration and Development Research Institute of PetroChina Daqing Oilfield Company Limited, Daqing 163712, China
2
School of Earth Sciences, Northeast Petroleum University, Daqing 163318, China
*
Author to whom correspondence should be addressed.
Minerals 2025, 15(8), 795; https://doi.org/10.3390/min15080795
Submission received: 12 June 2025 / Revised: 25 July 2025 / Accepted: 27 July 2025 / Published: 29 July 2025
(This article belongs to the Section Mineral Exploration Methods and Applications)
Browse Figures
Versions Notes

Abstract

This study focuses on the clastic reservoir in the first member of Yaojia Formation within Qijia-Gulong Sag, Songliao Basin. The results indicate that the reservoir in the study area develops within a shallow-water delta sedimentary system. The dominant sedimentary microfacies comprise underwater distributary channels, mouth bars, and sheet sands. Among these, the underwater distributary channel microfacies exhibits primary porosity ranging from 15.97% to 17.71%, showing the optimal reservoir quality, whereas the sheet sand microfacies has a porosity of only 7.45% to 12.08%, indicating inferior physical properties. During diagenesis, compaction notably decreases primary porosity via particle rearrangement and elastic deformation, while calcite cementation and quartz overgrowth further occlude pore throats. Although dissolution can generate secondary porosity (locally up to 40%), the precipitation of clay minerals tends to block pore throats, leading to “ineffective porosity” (permeability generally < 5 mD) and overall low-porosity and low-permeability characteristics. Carbon–oxygen isotope analysis reveals a deficiency in organic acid supply in the study area, restricting the intensity of dissolution alteration. Reservoir quality evolution is dominantly governed by the combined controls of sedimentary microfacies and diagenesis. This study emphasizes that, within shallow-water delta sedimentary settings, the material composition of sedimentary microfacies and the dynamic equilibrium of diagenetic processes jointly govern reservoir property variations. This insight provides critical theoretical support for understanding diagenetic evolution mechanisms in clastic reservoirs and enabling precise prediction of high-quality reservoir distribution.

1. Introduction

The sedimentary environment plays a particularly significant role in reservoir quality. Sandbodies developed within distinct sedimentary system domains exhibit differences in mineral composition, grain size, sorting, and argillaceous matrix content, thereby influencing their resistance to compaction, pore preservation capability, and subsequent diagenetic evolution [1]. For instance, in the Wenchang Formation reservoir of Lufeng Sag, Pearl River Mouth Basin, primary porosity in lowstand systems tract underwater distributary channel sandbodies reaches 12–18%, whereas that in transgressive systems tract beach-bar and subaqueous fan sandbodies is only 5–8% [2]. Diagenesis represents a critical factor controlling clastic reservoir quality, exerting influence on reservoir pore structure and fluid-flow capacity via processes including compaction, cementation, and dissolution. Mechanical compaction causes grain rearrangement, significantly reducing primary intergranular porosity [3], and cementation further occludes pore throats, impairing reservoir connectivity [4,5]. Conversely, in domains with intense dissolution, organic acids can generate secondary porosity through dissolving unstable components like feldspar and lithic fragments, locally improving reservoir properties [6], while in cementation zones, calcite cements tend to occlude primary reservoir spaces. For instance, studies on diagenesis of the Shanxi Formation reservoir in Longdong area, Ordos Basin, demonstrate that compaction and illite cementation are dominant factors causing reservoir densification, whereas dissolution has limited capacity to enhance reservoir quality [7,8].
In recent years, with advancements in exploration technologies, multiple 100-million-ton hydrocarbon provinces (e.g., Gulong and Qijia) have been proven in the Songliao Basin [9]. The Songliao Basin hosts major hydrocarbon-producing horizons genetically and spatially linked to the study interval (K2y1) in the Qijia-Gulong Sag, including the Fuyu (K1q), Putaohua (K2y), and Nenjiang (K2n) reservoirs, which are distributed across the Central Depression Area overlapping the sag. These horizons share the Qingshankou Formation (K2qn) organic-rich mudstones as the primary source rock. The Fuyu reservoir (K1q) in the southern Sanzhao Sag develops in fluvial-deltaic sandstones with short-distance migration from K2qn sources, forming a conventional petroleum system. The Putaohua reservoir (including K2y1) occurs in delta-front sandstones of Qijia-Gulong and Daqing Placanticline, characterized by near-source tight-sandstone accumulation. Nenjiang Formation reservoirs in the western slope are associated with shoreline-shallow lake sandstones charged via lateral migration from deep sag sources. The Yaojia Formation in the Songliao Basin, serving as a core exploration interval in China’s continental petroliferous basins, hosts multiple layers of high-quality reservoir-seal assemblages. Tight sandstone reservoirs not only represent a critical hosting horizon for conventional hydrocarbon reservoirs but also exhibit significant potential in the unconventional hydrocarbon domain, with their hydrocarbon accumulation conditions holding critical importance in national energy strategic planning [10]. The clastic reservoir in the first member of Yaojia Formation within Qijia-Gulong Sag, serving as a core exploration target of the basin-centered hydrocarbon system, has attracted considerable attention regarding its reservoir characteristics and diagenetic evolution mechanisms. Current research demonstrates that the reservoir interval predominantly exhibits delta plain, delta front, and prodelta sedimentary subfacies [11]. Grain size composition, sorting, and argillaceous content of delta front sandbodies serve as the physical foundation for primary porosity development in the reservoir, whereas compaction, cementation, and dissolution processes encountered during burial represent critical diagenetic agents governing pore evolution [12,13]. Research indicates that pore evolution in this clastic reservoir is subject to multiple controls from sedimentary facies zones [14] and diagenetic sequences [15]. However, dominant controlling factors of reservoirs vary significantly across different stratigraphic sequences and structural units, with detailed studies on specific intervals remaining insufficient [16]. Furthermore, the relationship between reservoir property variations across distinct sedimentary microfacies zones and dominant controlling factors remains unclear, with the amelioration effects of mineral transformations induced by dissolution on reservoir properties particularly warranting in-depth investigation.
Using core observation, thin-section petrography, scanning electron microscopy (SEM), and physical property measurements, this study systematically investigates the petrological characteristics, pore structure types, and diagenetic sequences of clastic reservoirs in the first member of the Yaojia Formation, with the objective of unraveling how diagenesis impacts reservoir properties under varying sedimentary conditions.

2. Geological Setting

The Songliao Basin lies in northeastern China and represents the largest Mesozoic-Cenozoic continental rift-depression superimposed basin, harboring abundant oil and gas resources. The basin is divided into five major structural units: Northern Submergent Area, Central Depression Area, Western Slope Area, Southeastern Uplift Belt, and Northeastern Uplift Belt [17]. The Qijia-Gulong Sag lies in the western portion of the Songliao Basin’s Central Depression Area, bordering the Yian Sag and Keshan-Yilong Anticline Belt to the north, adjoining the Wuyuer Sag and Longhupao Terrace to the west, extending to the Daqing Placanticline and Sanzhao Sag to the south [18], and connecting to the Mingshui Terrace and Heiyupao Sag to the east, As a core subsidence unit within the NE-trending structural framework of the Songliao Basin, the southern portion of the Qijia-Gulong Sag serves as the study area for this research (Figure 1A). During the sedimentary period of the K2qn in Gulong Sag, the Songliao Basin’s structure reached a state of stability (Figure 1B).
The Qijia-Gulong Sag exhibits fully developed strata [20], with formations occurring in ascending order from the base as follows: Huoshiling Formation (K1h), Shahezi Formation (K1s), Yingcheng Formation (K1y), Denglouku Formation (K1d), Quantou Formation (K1q), Qingshankou Formation (K2qn), Yaojia Formation (K2y), Nenjiang Formation (K2n), Sifangtai Formation (K2s), and Mingshui Formation (K2m) (Figure 2). This study targets the Upper Cretaceous Yaojia Formation. During this stage, the basin is in a depression evolution phase, characterized by extensive areal coverage, low subsidence rates, and conditions favorable for organic matter enrichment and maturation, resulting in medium-to-high maturity hydrocarbons. This makes it an ideal exploration interval [21,22]. The Yaojia Formation comprises three members in ascending order: Member 1 (K2y1), Member 2 (K2y2), and Member 3 (K2y3) (Figure 2). During deposition of Yaojia Formation Member 1 (K2y1), the Qijia-Gulong Sag exhibited a delta front sedimentary environment, where interbedded sandstones and dark mudstones were widely developed. During deposition of Yaojia Formation Members 2 and 3 (K2y2-K2y3), the sedimentary environment gradually transitioned to a shoreline-shallow lake setting. A regionally stable mudstone caprock developed at the top of this interval, forming an excellent source–reservoir–seal assemblage with underlying reservoir sandbodies and providing favorable geological conditions for hydrocarbon migration, accumulation, and entrapment [23].

3. Sample and Method

A total of 28 core samples were collected from six wells (Figure 1) in the Upper Cretaceous Yaojia Formation Member 1 (K2y1) of the study area: G141, G142, G844, Y142, Y78, and Y89. Specifically, the samples include 4 from Well G141 (1973.56–2002.43 m), 6 from Well G142 (1834.39–1888.09 m), 7 from Well G844 (2035.4–2066.51 m), 4 from Well Y142 (1890.27–1900.67 m), 5 from Well Y78 (1821.76–1847.56 m), and 2 from Well Y89 (1947.65–1950.95 m); all were retrieved from middle-shallow stratigraphic intervals.
Petrographic analysis was performed using an OLYMPUSBX51-P polarizing microscope (Olympus Corporation, Tokyo, Japan), focusing on key diagenetic features including quartz overgrowths, cement distribution, and intergranular contact relationships. Multi-scale reservoir characterization was systematically conducted for 15 representative samples: ① Field emission scanning electron microscopy (FE-SEM, Hitachi High-Tech, Tokyo, Japan) was conducted using a ZEISS Gemini SEM 300 (Zeiss, Jena, Germany), with testing parameters including an accelerating voltage of 10 kV, beam current of 200 pA, and working distance of 8 mm. The instrument is equipped with an Oxford X-Max N80 energy-dispersive X-ray spectrometer (EDS, Oxford Instruments, Abingdon, UK); ② Micro-probe analysis was conducted at the Testing Center of Shandong Bureau, China Metallurgical Geology Bureau, using a JEOL JXA-8230 electron microprobe (JEOL Ltd., Tokyo, Japan). The instrument was set at an accelerating voltage of 15 kV, beam current of 20 nA, and beam spot diameter of 2 μm; ③ Mercury intrusion porosimetry (MIP) was performed following Chinese standard SY/T5346-2005 [24] using a Micromeritics AutoPore IV-9500 (Micromeritics, Norcross, GA, USA) automated mercury intrusion porosimeter. The maximum applied pressure was 228 MPa (corresponding to a throat radius of 3.6 nm), with pore size distributions calculated using the Washburn equation.
Fifteen representative samples were subjected to whole-rock X-ray diffraction (XRD) analysis using a Rigaku D/max-2500 diffractometer (Rigaku, Tokyo, Japan). For clay mineral analysis, the <2 μm clay fraction was separated from bulk samples using sedimentation method (based on Stokes’ law) after removing carbonate minerals with 10% acetic acid and organic matter with 30% H2O2. The clay fractions were then prepared as oriented mounts via vacuum filtration. The instrument was operated at a tube voltage of 40 kV and tube current of 80 mA, with the scan performed from 3 to 60° (2θ) at a step size of 0.02° and a scanning rate of 4°/min. Data processing was performed using Jade 6.0 software, with mineral phase identification conducted in accordance with Chinese standard SY/T5163-2018 [25] X-ray Diffraction Analysis Methods for Clay Minerals and Common Non-Clay Minerals in Sedimentary Rocks. Quantification of mass fractions for each mineral phase was achieved using the Rietveld whole-pattern fitting method. The detection limits were 1% for silicate minerals (e.g., quartz and feldspar) and 3% for clay minerals. Carbon and oxygen isotope analysis was performed using a GasBench II online carbonate preparation system coupled with a Thermo Scientific Delta V Advantage isotope ratio mass spectrometer (Thermo Fisher Scientific, San Diego, CA, USA). After drying the samples at 105 °C, 50 mg of 200-mesh powder was reacted with 100% phosphoric acid at 72 °C for 12 h. The released CO2 gas was purified and introduced into the mass spectrometry system. δ13C and δ18O values were reported relative to VPDB and calibrated against International Atomic Energy Agency (IAEA) standard IAEA-CO-1 (δ13C = +2.49 ± 0.01‰, δ18O = −2.39 ± 0.03‰). Analytical uncertainties were ±0.05‰ and ±0.08‰ (1σ) for δ13C and δ18O, respectively.

4. Results

4.1. Lithofacies

Member 1 of the Yaojia Formation in the study area developed within a shallow-water delta sedimentary system [26]. Well G844 shows a sedimentary microfacies sequence from top to bottom (with increasing depth; Figure 3a), including semi-deep lake facies (thick-bedded black mudstone with minor silty interlayers, indicating low-energy anoxic environments), interdistributary bay (thin silty mudstone with horizontal bedding), subaqueous distributary channel (fine sandstone with normal grading, moderate sorting, subangular grains and cross-bedding), repeated interdistributary bay and subaqueous distributary channel, and semi-deep lake facies (thick black mudstone as the basal unit, identical to the top one). In contrast, Well G142 exhibits a sedimentary microfacies sequence developing in ascending order (with increasing depth; Figure 3b), consisting of semi-deep lake facies (thick black mudstone with rare siltstone lenses), mouth bar (fine sandstone to siltstone with reverse grading, well-sorted grains and parallel bedding), sheet sand (thinly interbedded fine sandstone and siltstone with horizontal bedding), repeated subaqueous distributary channel and sheet sand, mouth bar (reverse grading fine sandstone with moderate roundness), and semi-deep lake facies (thick black mudstone as the basal unit, matching the top one).
The semi-deep lake microfacies is dominated by black mudstone, with minor silty mudstone, fine sandstone, and siltstone. Its individual beds are thick and show stable lateral distribution, extending in a sheet-like manner, and major mudstone intervals can reach a thickness of 10–15 m. The mouth bar microfacies (unique to Well G142) is characterized by a reverse rhythm of fine sandstone, silty mudstone, and mudstone, mainly composed of silty mudstone or argillaceous siltstone. The beds are thick (6–10 m in thickness) with good lateral continuity, the sediments are well sorted, and the grain roundness is moderate. The sheet sand microfacies (also unique to Well G142) features thin interbedded fine sandstone and siltstone, lacking reverse rhythm characteristics. The individual layers are thin, but the sand bodies show extensive lateral distribution in a sheet-like configuration. The subaqueous distributary channel microfacies (present in both wells) is dominated by fine sandstone, exhibiting a distinct normal rhythm (coarse-to-fine). The layers are thick with good lateral continuity; the sediments are moderately sorted, the grain roundness is low, and subangular grains are predominant. This fining-upward sequence represents a normal depositional behavior in high-energy fluvial-dominated systems, where hydrodynamic energy gradually weakens during sedimentation: coarser grains (e.g., medium to fine sand) are first deposited under stronger currents, followed by finer grains (e.g., fine sand to silt) as flow energy diminishes. The sheet sands microfacies (specific to Well G844) is mainly composed of silty mudstone with minor siltstone, forming thin and laterally discontinuous beds, which indicates low-energy depositional conditions between distributary channels.

4.2. Geochemical Characteristics

Electron microprobe analysis was performed on calcite in the samples from Well G141, Well G142, and other wells in Member 1 of the Yaojia Formation (K2y1) within the Qijia-Gulong Sag study area. Results indicate that Na2O content ranges from 0.047% to 0.169%, Al2O3 content fluctuates between 0.002% and 0.645%, MgO content varies in the range of 0.027%–0.165%, SiO2 content ranges from 0.171% to 9.049%, and CaO content ranges between 50.601% and 53.762%. The FeO content in Well G141 ranges from 1.293% to 4.092%, exhibiting an increasing trend with increasing depth. The average value rises from 2.572% to 3.439%. The MnO content varies in the range of 0.472%–1.233%, showing no distinct trend with depth. The FeO content in Well G142 ranges from 2.032% to 3.409%, exhibiting an increasing trend with increasing depth. The average value rises from 2.291% to 3.285%. The MnO content fluctuates between 0.472% and 1.233%, showing no significant correlation with depth (Table 1).
In backscattered electron microscopy (BSE) images, Cal-I to Cal-II stage calcite exhibits typical cement characteristics. Partial calcite fills mineral grain pores in a dissolved state (Figure 4a); Cal-I stage calcite is tightly interlocked among other mineral grains in a poikilotopic texture (Figure 4b). Meanwhile, siderite occurs within the calcite cement (Figure 4c). Part of the Cal-II stage calcite fills intergranular pores between rock mineral grains as cement and encloses feldspar minerals (Figure 4d).
XRD analysis unveiled pronounced disparities in mineral assemblages across three pivotal sedimentary microfacies (Figure 5), which are indicative of their distinct depositional and diagenetic trajectories. In the subaqueous distributary channel, quartz (Q) emerges as the dominant mineral, constituting 56.9% of the mineral composition. Plagioclase (Pl) accounts for 17.4%, while clay minerals and calcite (Cal) make up 16.1% and 3.7% respectively. Conversely, the mouth bar microfacies exhibits a notable surge in plagioclase content to 30% (the highest among the three microfacies), accompanied by a corresponding decline in quartz to 42.6%. Clay minerals (20.7%) and calcite (3.8%) show marginal increases compared to the subaqueous distributary channel. In the sheet sand microfacies, clay minerals reach their peak at 33.8%, accompanied by reduced abundances of quartz (42.4%) and plagioclase (20.4%). Calcite content remains relatively stable at 3.1%.

4.3. Characteristics of the Physical and Reservoir Space

4.3.1. Reservoir Physical Properties

Physical property tests on core samples indicate that with increasing depth, the porosity of different sedimentary microfacies in the study area’s clastic reservoir shows no significant decrease, deviating from the trend of the traditional compaction curve (Figure 6a). Clastic reservoir porosity in Member 1 of the Yaojia Formation (K2y1) within the study area primarily ranges from 7.45% to 17.71%. Sheet sand microfacies exhibit porosities between 7.45% and 10.96%, with an average of 9.74%. Subaqueous distributary channel microfacies show porosities in the range of 15.97%–17.71% (Figure 6b), with an average of 16.58%. Ultra-low porosity reservoirs (porosity < 10%) constitute 13%, while low porosity reservoirs (porosity 10%–15%) make up 33% (Figure 6c). Reservoir permeability primarily ranges from 0 to 5 mD, with an average of 2.24 mD. The permeability interval > 1 mD exhibits the highest frequency, followed by the 0–0.1 mD interval, and the 0.1–1 mD interval shows the lowest frequency (Figure 6d).

4.3.2. Reservoir Space Characteristics

Member 1 of the Yaojia Formation in the study area primarily exhibits residual intergranular pores, with locally developed intergranular and intragranular dissolution pores. Under microscopic observation of cast thin sections, residual intergranular pores primarily exhibit regular shapes such as triangular forms (Figure 7a,b) and are widely developed, serving as the primary pore types in the study area. Dissolution pores are predominantly locally developed (Figure 7c). Some intergranular dissolution pores form from primary intergranular pores via secondary dissolution enlargement and are frequently interconnected with fractures. Pore margins exhibit dissolution-reworked features such as embayed and serrated morphologies. Intragranular dissolution pores primarily form through the dissolution of K-feldspar grains (Figure 7d).

4.4. Diagenetic Processes

The Yaojia Formation is shallowly buried (1800–2100 m) and underwent relatively weak mechanical compaction. Grains exhibit linear contact, with occasional concave–convex contact observed (Figure 7a); clay, calcite, and quartz represent the key authigenic minerals. Clay minerals are mainly illite and chlorite. Illite occurs primarily as hair-like filaments adhering to the surfaces of dissolved feldspar, while chlorite grows as petal-like aggregates within intergranular pores. Calcite cements primarily fill pores via precipitation. Siliceous cements are predominantly manifested as quartz overgrowth. Whole-rock stable carbon and oxygen isotope comprehensive analysis was performed on representative samples from Well G141, Well G142, Well G844, Well Y142, and Well Y89. The δ13C values range from −2.03‰ to −11.31‰ (V-PDB), while the δ18O values range between −12.26‰ and −20.63‰ (V-PDB) (Table 2). For Well Y89, δ13C, values range from −9.79‰ to −11.31‰, while δ18O values cluster within −12.26‰ to −12.60‰. The relatively concentrated δ13C values suggest low organic acid content in the Yaojia Formation, with localized dissolution being the dominant process. represent the key authigenic minerals.
Diagenetic cementation is dominated by calcite cementation, quartz overgrowth, and clay mineral cementation. Quartz overgrowths exhibit secondary enlargement rims with growth zoning (Figure 8d,e). Illite commonly occurs as filamentous or lamellar coatings on particle suzrfaces (Figure 8f), whereas chlorite typically forms acicular or lining distributions within intergranular pores (Figure 8g). Calcite cements in the study area exhibit distinct generational characteristics, allowing the identification of two distinct cementation events with different genetic origins based on cement features. The first-generation calcite cements formed during the early diagenetic stage, marked by fine crystalline calcite developed in intergranular pores (Figure 8h). Second-generation calcite cements formed during the middle diagenetic stage, characterized by coarse crystalline calcite filling the residual pores after compaction (Figure 8i), causing further reduction of pore space. Dissolution is manifested as intergranular and intragranular dissolution, with some dissolution pores formed by the dissolution modification of residual intergranular pores (i.e., primary large pores). Secondary clay minerals formed during dissolution commonly occur as pore-filling or pore-bridging aggregates, and the so-called “lining-like” structures within dissolved pores may be an artifact of sample drying procedures [27]. These aggregates reduce pore throat radii, thereby completely blocking some fine pores and resulting in the phenomenon of “effective pores being rendered ineffective” (Figure 8j–l).

5. Discussion

5.1. The Influence of Sedimentation on Porosity

Significant differences exist in the distribution of porosity and permeability among different lithofacies in the Yaojia Formation. Porosity in subaqueous distributary channel microfacies primarily ranges from 15% to 20%, with an overall variation between 10.57% and 17.71% (Figure 9a). Permeability values range from 0.04 to 8.44 mD (Figure 9d). Porosity in estuarine bar microfacies tends to cluster within 15%–20%, with an overall variation between 12.33% and 15.97% (Figure 9b). Permeability values exhibit a distribution from 0.08 to 1.37 mD (Figure 9e). Porosity in sheet sand microfacies tends to be distributed within 5%–15%, with a relatively narrow variation between 7.45% and 12.08% (Figure 9c). Permeability exhibits an overall distribution from 0.01 to 0.11 mD (Figure 9f). The underwater distributary channel sedimentary microfacies exhibit the most favorable reservoir properties, followed by the estuary dam and sheet sand microfacies, demonstrating the control of sedimentary microfacies over reservoir properties [28,29].
In the Yaojia Formation, the underwater distributary channel, estuary dam, and sheet sand microfacies primarily rely on primary pores as the main reservoir space, while the proportion of secondary pores exhibits distinct differentiation among different microfacies. Specifically, in the underwater distributary channel microfacies, strong hydrodynamic forces drive the rapid accumulation of clastic particles, leading to the formation of a primary intergranular pore system with high porosity and permeability. In this microfacies, sediments exhibit a mineral composition with low mud content (<15%) and relatively high quartz particle content (40%–55%). The point-line contact support of rigid particles effectively suppresses compaction-induced destruction of primary pores, thereby preserving a high proportion of pores, with primary pores generally accounting for over 70% (Figure 10a,b). In contrast, the estuary dam and sheet sand microfacies, characterized by finer sediment grains and higher matrix content, exhibit relatively fewer total pores (Figure 10d,e,g,h). Comprehensive analysis indicates that the Yaojia Formation Member 1 is overall dominated by chlorite and illite as the major clay minerals, with illite-smectite mixed layers occurring as minor components; quartz and feldspar are ubiquitously enriched in non-clay minerals. In the subaqueous distributary channel microfacies, chlorite and illite exhibit relatively low peak intensities with broad peak shapes, indicating that authigenic clay mineralization is limited under strong hydrodynamic conditions, and clay minerals are primarily derived from post-depositional dissolution (Figure 10c). By contrast, the mouth bar microfacies, characterized by moderate hydrodynamic conditions, is distinguished by a prominent and sharp Ch (002) peak of chlorite. Clay minerals result from the combined effects of early-stage authigenesis and late-stage dissolution, leading to significant enrichment of clay minerals (Figure 10f) [30,31]. In the sheet sand microfacies, which is under the weakest hydrodynamic conditions, post-depositional dissolution further enhances the input of clay minerals, thereby forming strong and distinct peaks for chlorite and other clay minerals (Figure 10i). In the study area, shallow burial conditions (burial depth < 2000 m) result in weak compaction, thereby limiting damage to primary pores. While the lack of acidic fluid supply (Table 2) restricts the extent of dissolution, leading to overall poor development of secondary pores. Based on observations of cast thin sections using a polarizing microscope and combined with image analysis of pore types, secondary pores in the underwater distributary channel microfacies account for less than 20% of total pores on average. In contrast, local microporous environments formed during burial in the estuary dam and sheet sand microfacies facilitate weak dissolution modification, with secondary pores comprising 40% of total pores on average (Figure 11).

5.2. The Influence of Diagenesis on Porosity

In the context of different sedimentary microfacies in the Yaojia Formation, variations in compaction result in significant differences in reservoir physical properties. During compaction, the study area exhibits predominantly weak mechanical compaction due to shallow burial (1800–2100 m; Section 4.4). Grains primarily show linear contact, with occasional concave–convex contact (Figure 7a), but no deformation bands were observed in thin-section or SEM analyses. The underwater distributary channel sedimentary microfacies is predominantly composed of coarse clastic grains, featuring a stable particle-supported framework and greater resistance to compaction. During burial, particles are predominantly in linear contact (Figure 8a), with limited deformation of elastic constituents, thereby preserving a higher proportion of primary pores. The estuary dam sedimentary microfacies is dominated by fine-grained sediments like siltstone, rich in elastic grains. Under intense compaction, particles are tightly packed, forming predominantly linear-concave–convex contacts (Figure 8b). Elastic constituents such as clay minerals undergo compression and deformation, filling intergranular pores, while rigid grains develop micro-fractures due to stress, causing substantial porosity reduction. With increasing burial depth, pore structures densify further, resulting in minimal preservation of primary pores. The sheet sand sedimentary microfacies is dominated by argillaceous siltstone, due to pressure–solution processes, and precipitations of carbonate and silica cements, characterized by fine-grained and poorly sorted particles. Intense particle rearrangement occurs, with rigid grains susceptible to fracturing, resulting in predominantly concave–convex contacts between particles (Figure 8c). This disparity further underscores the control of sedimentary microfacies over reservoir properties. Coarse-grained underwater distributary channel microfacies retain better reservoir performance following compaction, whereas compaction significantly degrades reservoir properties in fine-grained sheet sand microfacies.
Calcite cementation, quartz overgrowth, and clay mineral precipitation (dominated by illite and chlorite) collectively record complex fluid–rock interactions during sediment compaction. The secondary enlargement rims with growth zoning in quartz overgrowths (Figure 8d,e) suggest multistage silica precipitation under varying and fluid chemistry. The contrasting occurrences of illite and chlorite further highlight distinct diagenetic pathways: filamentous/lamellar illite coatings on particle surfaces (Figure 8g) likely formed during early compaction from clay mineral dehydration, while acicular chlorite linings within intergranular pores (Figure 8f) may indicate later-stage precipitation from K+-rich fluids under more reducing conditions, These fluids contained concurrent Mg2+ and Fe2+, with K+ promoting chlorite nucleation through cation exchange at grain surfaces. These clay fabrics are critical for reservoir permeability, as illite coatings can enhance grain surface roughness and chlorite linings may partially preserve primary porosity by inhibiting quartz overgrowth. Calcite cements in the study area exhibit distinct generational characteristics, allowing the identification of two distinct cementation events with different genetic origins based on cement features. The first-generation calcite cements formed during the early diagenetic stage, marked by fine crystalline calcite developed in intergranular pores (Figure 8h). Their origin is attributed to carbonate-supersaturated pore fluids derived from the following: (1) evaporation–concentration of lacustrine water in the shallow burial environment post-sedimentation, which enriched Ca2+ and HCO3− ions; and (2) early dissolution of carbonate fragments within the sediment (e.g., bioclasts or detrital carbonate grains), as indicated by the moderate SiO2 content (0.171%–9.049%, Table 1) from concurrent silicate weathering; second-generation calcite cements formed during the middle diagenetic stage, characterized by coarse crystalline calcite filling the residual pores after compaction (Figure 8i). Their material source is linked to (1) thermal degradation of organic matter in the underlying Qingshankou Formation source rocks, which released CO2 and increased the carbonate alkalinity of pore fluids, and (2) dissolution of feldspar (especially plagioclase) during burial, which liberated Ca2+ ions (supported by the presence of feldspar dissolution pores in Figure 7d and 10). This stage of cementation is consistent with the relatively negative δ13C values (−2.03‰ to −11.31‰, Table 2), indicating a contribution from organic carbon-derived fluids.
There are significant variations in the correlation between different lithological components and reservoir porosity/permeability. While quartz and feldspar as rigid grains may contribute to the framework stability, their influence on poro-perm properties is limited and regulated by clay matrix, clay content, and cementation [32]. However, lithic fragment content exhibits a negative correlation with reservoir properties (as lithic fragment content increases from 0% to 60%, porosity decreases from ~18% to ~8% and permeability drops from ~1 mD to <0.1 mD). During burial, elastic lithic fragments undergo irreversible elastic deformation and particle rearrangement, leading to substantial loss of primary pore space (Figure 12e,f).

5.3. Formation Model of High-Quality Reservoirs

Stable carbon isotope compositions of organic acids exhibit diagenetic indicators, with original values typically ranging around −25‰. Isotope fractionation induced by decarboxylation can cause negative shifts in δ13C values [33]. δ13C values in the underwater distributary channel sedimentary microfacies range between −5.53‰ and −2.08‰, with porosity fluctuating within 14.87%–17.71% (Figure 13a). The limited variation indicates homogeneous diagenetic alteration, while permeability is predominantly low to ultra-low (Figure 13b); δ13C values in the sheet sand microfacies range between −5.21‰ and −2.03‰ (Figure 13c), with porosity fluctuating within 7.45%–12.33% and permeability predominantly ultra-low (Figure 13d). These isotopic signatures indicate that dissolution intensity in different microfacies is limited, while porosity variations primarily reflect the impact of sedimentary processes on reservoir quality. Comparative studies with previous research [19,34,35] reveal that conventional models categorized underwater distributary channel microfacies into moderate permeability class and sheet sands into low permeability class, whereas our data demonstrate that both microfacies are predominantly ultra-low permeability. This discrepancy stems from the dual effects of organic acid-mediated diagenesis. While organic acids enhance primary porosity by dissolving feldspar and carbonate minerals to form secondary pores, inadequate acid concentration prevents sustained dissolution, causing dissolution products (e.g., authigenic carbonates or clay minerals) to precipitate locally and partially clog pore throats. Thus, while porosity experiences a modest increase, pore connectivity improvements remain minimal at low acid concentrations.
The net porosities created by feldspar dissolution were insignificant. Reservoir permeability was reduced significantly by precipitation of dissolution by-products, especially by conversion of kaolinite to hair-like illite at higher temperatures. Secondary pores are generated while clay particles released during the process readily migrate to throats. This is also evidence in other regions [36,37,38]. Authigenic chlorite and illite/montmorillonite mixed layers collectively fill the pores, splitting originally larger pores into multiple smaller ones and thereby reducing permeability (Figure 14). The interplay between porosity enhancement from dissolution and permeability reduction due to precipitation underscores the critical role of organic acid availability in governing reservoir quality evolution.

6. Conclusions

  • Clastic reservoir quality in Member 1 of the Yaojia Formation is under synergistic control of sedimentary environment and diagenesis. Reservoir properties exhibit marked variations across different sedimentary microfacies, with underwater distributary channel microfacies showing relatively superior reservoir properties.
  • Clastic reservoir quality in Member 1 of the Yaojia Formation is significantly influenced by sedimentary environment and diagenesis. Compaction substantially reduces primary porosity through grain rearrangement, elastic grain deformation, and rigid grain crushing. Cementation, characterized by calcite cementation, quartz overgrowth, and clay mineral cementation, further exacerbates pore loss and constricts pore throats.
  • Although dissolution can form secondary pores locally to improve reservoir porosity, the generated clay minerals easily block pore throats, leading to “effective pores becoming ineffective” and reducing reservoir permeability.

Author Contributions

Conceptualization, H.W.; methodology, H.W.; software, Q.Z.; validation, Y.C.; formal analysis, J.L. and Q.Z.; investigation, T.H.; resources, J.L. and H.L.; data curation, Q.Z.; writing—original draft, J.L. and Q.Z.; writing—review and editing, J.L. and H.W.; visualization, J.L. and H.L.; supervision, H.W.; project administration, J.L., Q.Z. and Y.C.; funding acquisition, J.L., Q.Z. and Y.C.; All authors have read and agreed to the published version of the manuscript.

Funding

This work was financially supported by National Natural Science Foundation of China (Grant No. 42372150) and Provincial University Basic Scientific Research Operating Cost Projects (Grant No. 2023RCZX-02).

Data Availability Statement

The authors have permission to share data.

Conflicts of Interest

Author Junhui Li, Qiang Zheng, Yu Cai, Huaye Liu was employed by the company Exploration and Development Research Institute of PetroChina Daqing Oilfield Company Limited. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

References

  1. Bagtash, R.F.; Goll, A.B.; Omidpour, A.; Kakemem, U. Reservoir quality drivers in the Oligo-Miocene Asmari Formation, Dezful Embayment, Iran: Facies, diagenesis, and tectonic controls. Mar. Pet. Geol. 2025, 173, 107279. [Google Scholar] [CrossRef]
  2. Sun, P.K.; Jiang, S.Y.; Zhang, L.; Jia, L.B.; Rao, H.W.; Fang, H.J.; Yi, Z.; He, T.H.; Zhu, S.C.; Bao, L.Y. Impacts of Sedimentation and Diagenesis on Deeply Buried Reservoir Quality of a Rift Basin: A Case Study of Wenchang Formation in the Lufeng Depression, Pearl River Mouth Basin, China. Geofluids 2022, 2022, 8625005. [Google Scholar] [CrossRef]
  3. Bello, A.M.; Usman, M.B.; Amao, A.O.; Ramadan, K.A.; Hashem, M.A.; Kachalla, A.; Abubakar, U.; Salisu, A.M.; Mukkafa, S.; Kwami, I.A.; et al. Diagenesis and reservoir quality evolution of estuarine sandstones: Insights from the Cenomanian-Turonian Yolde Formation, northern Benue Trough, NE Nigeria. Mar. Pet. Geol. 2024, 169, 107073. [Google Scholar] [CrossRef]
  4. Walderhaug, O. Kinetic modeling of quartz cementation and porosity loss in deeply buried sandstone reservoirs. AAPG Bull. 1996, 80, 731–745. [Google Scholar] [CrossRef]
  5. Walderhaug, O. Modeling Quartz Cementation and Porosity in Middle Jurassic Brent Group Sandstones of the Kvitebjørn Field, Northern North Sea. AAPG Bull. 2000, 84, 1325–1339. [Google Scholar] [CrossRef]
  6. Yue, D.L.; Wu, S.H.; Xu, Z.Y.; Xiong, L.; Chen, D.X.; Ji, Y.L.; Zhou, Y. Reservoir quality, natural fractures, and gas productivity of upper Triassic Xujiahe tight gas sandstones in western Sichuan Basin, China. Mar. Pet. Geol. 2018, 89, 370–386. [Google Scholar] [CrossRef]
  7. Cui, G.X.; Xu, S.Y.; Wei, Q.L.; Yang, Y.M.; Hu, J.; He, T.P. The influence of diagenesis on the quality of tight sandstone reservoirs in Longdong, Ordos Basin. J. Pet. Explor. Prod. Technol. 2024, 14, 3331–3348. [Google Scholar] [CrossRef]
  8. Zhang, F.Q.; Gingras, M.; Shan, C.D.; Lu, X.S.; Zhuo, Q.G.; Zhong, H.L. The effect of coupling of tectonic compression and overpressure on porosity of deep reservoirs: A case study of southern margin of Junggar Basin, northwest China. Front. Earth Sci. 2023, 11, 1220105. [Google Scholar] [CrossRef]
  9. Yang, R.F.; Wang, Y.C.; Cao, J. Cretaceous source rocks and associated oil and gas resources in the world and China: A review. Pet. Sci. 2014, 11, 331–345. [Google Scholar] [CrossRef]
  10. Bi, H.; Li, J.Z.; Tang, Z.J.; Li, P.; Wang, L.; Shang, X.Y. High-resolution sequence stratigraphy, sedimentology and reservoir quality evaluation of the Yaojia Formation in the Longxi area of the Western Slope, Songliao Basin, China. Mar. Pet. Geol. 2017, 88, 511–530. [Google Scholar] [CrossRef]
  11. Zhang, L.; Bao, Z.D.; Lin, Y.B.; Chen, Y.M.; Lin, X.H.; Dou, L.X.; Kong, B. Genetic types and sedimentary model of sandbodies in a shallow-water delta: A case study of the first Member of Cretaceous Yaojia Formation in Qian’an area, south of Songliao Basin, NE China. Pet. Explor. Dev. 2017, 44, 770–779. [Google Scholar] [CrossRef]
  12. Worden, R.H.; Morad, S. Quartz Cementation in Oil Field Sandstones: A Review of the Key Controversies. In Quartz Cementation in Sandstones; John Wiley & Sons, Inc.: Hoboken, NJ, USA, 2000; pp. 1–20. [Google Scholar]
  13. Worden, R.H.; Burley, S.D. Sandstone Diagenesis: The Evolution of Sand to Stone. In Sandstone Diagenesis: Recent and Ancient; John Wiley & Sons, Inc.: Hoboken, NJ, USA, 2003; pp. 1–44. [Google Scholar]
  14. Zhang, L.; Bao, Z.D.; Dou, L.X.; Xu, Q.H. Diagenetic alterations related to sedimentary architecture of deltaic distributary channels in red beds of the Cretaceous Yaojia Formation, Songliao Basin. J. Pet. Sci. Eng. 2021, 203, 108564. [Google Scholar] [CrossRef]
  15. Cao, Z.; Karem, A.; Lin, C.Y.; Dong, C.M.; Ren, L.H.; Qin, M.Y.; Li, Z.J.; Tan, X.F.; Zhang, L.; Li, X.G. Diagenetic evolution of the lower Yaojia Formation of Songliao Basin, China: Impact on reservoir quality. J. Pet. Sci. Eng. 2022, 213, 110415. [Google Scholar] [CrossRef]
  16. Taylor, T.R.; Giles, M.R.; Hathon, L.A. Sandstone diagenesis and reservoir quality prediction: Models, myths, and reality. AAPG Bull. 2010, 94, 1093–1132. [Google Scholar] [CrossRef]
  17. Yang, X.B.; Wang, H.Y.; Li, Z.Y.; Guan, C.; Wang, X. Tectonic-sedimentary evolution of a continental rift basin: A case study of the Early Cretaceous Changling and Lishu fault depressions, southern Songliao Basin, China. Mar. Pet. Geol. 2021, 128, 105068. [Google Scholar] [CrossRef]
  18. Cheng, J.M.; McIntosh, J.C.; Xie, X.O.; Jiao, J.J. Hydrochemistry of formation water with implication to diagenetic reactions in Sanzhao depression and Qijia-gulong depression of Songliao Basin, China. J. Geochem. Explor. 2006, 88, 86–90. [Google Scholar] [CrossRef]
  19. Liu, P. Main Controlling Factors and Accumulation Model of Tight Oil Reservoirs in the First Member of Yaoyi Formation in Gulong Sag. Xinjiang Pet. Geol. 2023, 44, 635–645. [Google Scholar]
  20. Liu, Y.; Li, W.; Yuan, J.; Li, P.; Ge, X.; Ge, X.; Liu, P.; Wu, H.; Yu, X.; Huang, B. Lithofacies Characteristics of the Lower Cretaceous Qing 1 Member in the Heiyupao Depression, Northern Binbei Area of the Songliao Basin. Minerals 2025, 15, 125. [Google Scholar] [CrossRef]
  21. Shao, C.; Fan, T.L.; Guo, Y.J.; Cheng, P.; Sun, Y.; Wang, H.R. Discovery of Seismites in the Upper Cretaceous Yaojia Formation of the Daqing Placanticline, Songliao Basin and Their Geological Significance. J. Palaeogeogr. 2012, 14, 719–726. [Google Scholar]
  22. Deng, Q.J.; Hu, M.Y.; Su, S.; Chen, W.; Shen, J.; Kane, O.I.; Cai, Q.S.; Hu, Z.G. Factors controlling reservoir quality of a retreating delta-front in shallow-water lacustrine in the Songliao Basin, Northeast China. J. Pet. Sci. Eng. 2022, 216, 110773. [Google Scholar] [CrossRef]
  23. Li, Z.; Bao, Z.D.; Dou, L.X.; Zang, D.S.; Mao, S.W.; Song, J.; Zhao, J.H.; Wang, Z.C. Sedimentary characteristics and pattern of distributary channels in shallow water deltaic red bed succession: A case from the Late Cretaceous Yaojia formation, southern Songliao Basin, NE China. J. Pet. Sci. Eng. 2018, 171, 1171–1190. [Google Scholar] [CrossRef]
  24. SY/T 5346-2005; Rock Capillary Pressure Measurement. China National Standards: Beijing, China, 2005.
  25. SY/T 5163-2018; Analysis Method for Clay Minerals and Ordinary Non-Clay Minerals in Sedimentary Rocks by the X-ray Diffraction. China National Standards: Beijing, China, 2018.
  26. Li, Z.D.; Zhang, L.S.; Were, P.; Wang, D.J. Sedimentary characteristics of 1st member of Yaojia Formation in Zhaoyuan-Taipingchuan region of Songliao Basin. J. Pet. Sci. Eng. 2017, 148, 52–63. [Google Scholar] [CrossRef]
  27. Wilson, L.; Wilson, M.J.; Green, J.; Patey, I. The influence of clay mineralogy on formation damage in North Sea reservoir sandstones: A review with illustrative examples. Earth-Sci. Rev. 2014, 134, 70–80. [Google Scholar] [CrossRef]
  28. Xin, R.C.; Li, G.F.; Feng, Z.Q.; Liang, J.P.; Lin, C.S. Depositional Characteristics of Lake-Floor Fan of Cretaceous Lower Yaojia Formation in Western Part of Central Depression Region, Songliao Basin. J. Earth Sci. 2009, 20, 731–745. [Google Scholar] [CrossRef]
  29. Sun, S.W.; Shu, L.S.; Zeng, Y.W.; Cao, H.; Feng, Z.Q. Porosity-permeability and textural heterogeneity of reservoir sandstones from the Lower Cretaceous Putaohua Member of Yaojia Formation, Weixing Oilfield, Songliao Basin, Northeast China. Mar. Pet. Geol. 2007, 24, 109–127. [Google Scholar] [CrossRef]
  30. Worden, R.H.; Griffiths, J.; Wooldridge, L.J.; Utley, J.E.P.; Lawan, A.Y.; Muhammed, D.D.; Simon, N.; Armitage, P.J. Chlorite in sandstones. Earth-Sci. Rev. 2020, 204, 103105. [Google Scholar] [CrossRef]
  31. Dowey, P.J.; Hodgson, D.M.; Worden, R.H. Pre-requisites, processes, and prediction of chlorite grain coatings in petroleum reservoirs: A review of subsurface examples. Mar. Pet. Geol. 2012, 32, 63–75. [Google Scholar] [CrossRef]
  32. Shaldybin, M.V.; Wilson, M.J.; Wilson, L.; Muslimova, A.V.; Cherdantseva, D.A.; Molokov, P.B. Jurassic and Cretaceous clastic petroleum reservoirs of the West Siberian sedimentary basin: Mineralogy of clays and influence on poro-perm properties. J. Asian Earth Sci. 2021, 222, 104964. [Google Scholar] [CrossRef]
  33. Wang, Q.T.; Liu, W.H.; Pei, L.X.; Cai, Z.G.; Luo, H.Y.; Wang, X.F.; Zhang, D.D.; Liu, J.Z. Hydrocarbon generation from calcium stearate: Insights from closed-system pyrolysis. Mar. Pet. Geol. 2021, 126, 104923. [Google Scholar] [CrossRef]
  34. Zhu, J.W.; Jiang, L.; Guo, D.J.; Yun, H.F.; Chen, X.X. Analysis of Reservoir Characteristics and Influencing Factors of the First Member of Yaoyi Formation in the Changjiaweizi Area, Northern Songliao Basin. J. Jilin Univ. Earth Sci. Ed. 2009, 39, 205–210. [Google Scholar]
  35. He, Q.B.; Zhang, J.H. Diagenesis and Diagenetic Facies of Ultra-Low Permeability Sandstone in the First Member of Yaoyi Formation in the Da’an Area, Southern Songliao Basin. J. Chengdu Univ. Technol. Nat. Sci. Ed. 2022, 49, 674–686. [Google Scholar]
  36. Yuan, K.; Liu, K.Q.; Zhu, R.K.; Yin, G.C.; Zhang, J.Y.; Zhang, S.R. The evolution of clay mineral and its indication of hydrocarbons under overpressure: An example from the shale of the Qingshankou formation in the Gulong Sag. Pet. Sci. 2024, 21, 3867–3883. [Google Scholar] [CrossRef]
  37. Yuan, G.H.; Cao, Y.C.; Gluyas, J.; Jia, Z.Z. Reactive transport modeling of coupled feldspar dissolution and secondary mineral precipitation and its implication for diagenetic interaction in sandstones. Geochim. Cosmochim. Acta 2017, 207, 232–255. [Google Scholar] [CrossRef]
  38. Ma, B.B.; Cao, Y.C.; Jia, Y.C. Feldspar dissolution with implications for reservoir quality in tight gas sandstones: Evidence from the Eocene Es4 interval, Dongying Depression, Bohai Bay Basin, China. J. Pet. Sci. Eng. 2017, 150, 74–84. [Google Scholar] [CrossRef]
Minerals 15 00795 g001
Figure 1. (A) Geographical location map of the study area [8]. (B) Structural cross section across the Gulong Sag [19].
Figure 1. (A) Geographical location map of the study area [8]. (B) Structural cross section across the Gulong Sag [19].
Minerals 15 00795 g001
Minerals 15 00795 g002
Figure 2. Composite stratigraphic column of the Cretaceous formations in the Central Depression [20].
Figure 2. Composite stratigraphic column of the Cretaceous formations in the Central Depression [20].
Minerals 15 00795 g002
Minerals 15 00795 g003
Figure 3. Comprehensive stratigraphic column of sedimentary microfacies of the Yaojia Formation. (a) Well G844; (b) Well G142.
Figure 3. Comprehensive stratigraphic column of sedimentary microfacies of the Yaojia Formation. (a) Well G844; (b) Well G142.
Minerals 15 00795 g003
Minerals 15 00795 g004
Figure 4. Back scattered electron microscopic images. (a) Granular calcite filling intergranular pores (Well G141, 1973.56 m); (b) poikilotopic Cal-I interlocked with minerals (Well G141, 2001.37 m); (c) siderite within calcite cement (Well G142, 1835.39 m); (d) Cal-II enclosing feldspar (Well G142, 1842.19 m). Q: quartz; Pl: plagioclase.
Figure 4. Back scattered electron microscopic images. (a) Granular calcite filling intergranular pores (Well G141, 1973.56 m); (b) poikilotopic Cal-I interlocked with minerals (Well G141, 2001.37 m); (c) siderite within calcite cement (Well G142, 1835.39 m); (d) Cal-II enclosing feldspar (Well G142, 1842.19 m). Q: quartz; Pl: plagioclase.
Minerals 15 00795 g004
Minerals 15 00795 g005
Figure 5. XRD bulk rock mineral characteristics of different sedimentary microfacies. (a) Subaqueous distributary channel microfacies; (b) mouth bar microfacies; (c) sheet sand microfacies. Q: quartz; Kfs: K-feldspar; Pl: plagioclase; Ch: chlorite; I/S: mixed-layered illite-smectite; I: illite.
Figure 5. XRD bulk rock mineral characteristics of different sedimentary microfacies. (a) Subaqueous distributary channel microfacies; (b) mouth bar microfacies; (c) sheet sand microfacies. Q: quartz; Kfs: K-feldspar; Pl: plagioclase; Ch: chlorite; I/S: mixed-layered illite-smectite; I: illite.
Minerals 15 00795 g005
Minerals 15 00795 g006
Figure 6. Physical characteristics of the Yaojia Formation reservoirs in the study area. (a) Porosity vs. depth; (b) permeability vs. depth; (c) porosity frequency; (d) permeability frequency.
Figure 6. Physical characteristics of the Yaojia Formation reservoirs in the study area. (a) Porosity vs. depth; (b) permeability vs. depth; (c) porosity frequency; (d) permeability frequency.
Minerals 15 00795 g006
Minerals 15 00795 g007
Figure 7. Reservoir pore types in the Yaojia Formation. (a,b) Residual intergranular pores (Well G844, 2035.40 m; orthogonal/single polarized light, ×10); (c,d) local dissolution pores (Well G141, 2001.37 m; orthogonal/single polarized light, ×10). (Q: quartz; Int-P: intergranular pore; FD: feldspar dissolution pores).
Figure 7. Reservoir pore types in the Yaojia Formation. (a,b) Residual intergranular pores (Well G844, 2035.40 m; orthogonal/single polarized light, ×10); (c,d) local dissolution pores (Well G141, 2001.37 m; orthogonal/single polarized light, ×10). (Q: quartz; Int-P: intergranular pore; FD: feldspar dissolution pores).
Minerals 15 00795 g007
Minerals 15 00795 g008
Figure 8. Diagenetic features in Member 1 of the Yaojia Formation. (a–c) Compaction (subaqueous distributary channel: Well G141, 2002.43 m; mouth bar: Well Y89, 1947.65 m; sheet sand: Well Y78, 1826.21 m); (d,e) quartz overgrowths (Well G141, 2002.43 m); (f,g) clay cements (petal-shaped chlorite, filamentous illite; Well Y89, 1947.65 m, SEM); (h,i) calcite cementation (Cal-I: Well G142, 1842.19 m; multi-stage: Well G141, 1973.56 m); (j–l) dissolution pores (Well G142, 1878.33 m; Well G142, 1834.39 m, SEM; Well G141, 2001.37 m, BSE).
Figure 8. Diagenetic features in Member 1 of the Yaojia Formation. (a–c) Compaction (subaqueous distributary channel: Well G141, 2002.43 m; mouth bar: Well Y89, 1947.65 m; sheet sand: Well Y78, 1826.21 m); (d,e) quartz overgrowths (Well G141, 2002.43 m); (f,g) clay cements (petal-shaped chlorite, filamentous illite; Well Y89, 1947.65 m, SEM); (h,i) calcite cementation (Cal-I: Well G142, 1842.19 m; multi-stage: Well G141, 1973.56 m); (j–l) dissolution pores (Well G142, 1878.33 m; Well G142, 1834.39 m, SEM; Well G141, 2001.37 m, BSE).
Minerals 15 00795 g008
Minerals 15 00795 g009
Figure 9. Porosity distribution histogram of different sedimentary microfacies in the Yaojia Formation. (a) Subaqueous distributary channel sedimentary microfacies and porosity distribution histogram; (b) mouth bar sedimentary microfacies and porosity distribution histogram; (c) sheet sand sedimentary microfacies and porosity distribution histogram; (d) subaqueous distributary channel sedimentary microfacies and permeability distribution histogram; (e) mouth bar sedimentary microfacies and permeability distribution histogram; (f) sheet sand sedimentary microfacies and permeability distribution histogram.
Figure 9. Porosity distribution histogram of different sedimentary microfacies in the Yaojia Formation. (a) Subaqueous distributary channel sedimentary microfacies and porosity distribution histogram; (b) mouth bar sedimentary microfacies and porosity distribution histogram; (c) sheet sand sedimentary microfacies and porosity distribution histogram; (d) subaqueous distributary channel sedimentary microfacies and permeability distribution histogram; (e) mouth bar sedimentary microfacies and permeability distribution histogram; (f) sheet sand sedimentary microfacies and permeability distribution histogram.
Minerals 15 00795 g009
Minerals 15 00795 g010
Figure 10. Pore characteristics and XRD clay mineral characteristics of different sedimentary microfacies. (a,b) Subaqueous distributary channel sedimentary microfacies; (c) XRD clay mineral characteristics of the subaqueous distributary channel microfacies; (d,e) mouth bar sedimentary microfacies; (f) XRD clay mineral characteristics of the mouth bar microfacies; (g,h) sheet sand sedimentary microfacies. (i) XRD clay mineral characteristics of the sheet sand microfacies; Q-quartz, Int-P-intergranular pore, FD-secondary pores formed by feldspar. Ch: chlorite; I/S: mixed-layered illite-smectite; I: illite; Q-quartz.
Figure 10. Pore characteristics and XRD clay mineral characteristics of different sedimentary microfacies. (a,b) Subaqueous distributary channel sedimentary microfacies; (c) XRD clay mineral characteristics of the subaqueous distributary channel microfacies; (d,e) mouth bar sedimentary microfacies; (f) XRD clay mineral characteristics of the mouth bar microfacies; (g,h) sheet sand sedimentary microfacies. (i) XRD clay mineral characteristics of the sheet sand microfacies; Q-quartz, Int-P-intergranular pore, FD-secondary pores formed by feldspar. Ch: chlorite; I/S: mixed-layered illite-smectite; I: illite; Q-quartz.
Minerals 15 00795 g010
Minerals 15 00795 g011
Figure 11. Primary vs. secondary porosity proportions in sedimentary microfacies. A: Subaqueous distributary channel; B: mouth bar; C: sheet sand. Blue represents Proportion of Primary Porosity; Red represents Proportion of Secondary Porosity.
Figure 11. Primary vs. secondary porosity proportions in sedimentary microfacies. A: Subaqueous distributary channel; B: mouth bar; C: sheet sand. Blue represents Proportion of Primary Porosity; Red represents Proportion of Secondary Porosity.
Minerals 15 00795 g011
Minerals 15 00795 g012
Figure 12. Correlations between rock components and reservoir properties. (a,b) Quartz content vs. porosity/permeability; (c,d) feldspar content vs. porosity/permeability; (e,f) lithic fragment content vs. porosity/permeability.
Figure 12. Correlations between rock components and reservoir properties. (a,b) Quartz content vs. porosity/permeability; (c,d) feldspar content vs. porosity/permeability; (e,f) lithic fragment content vs. porosity/permeability.
Minerals 15 00795 g012
Minerals 15 00795 g013
Figure 13. Stable carbon isotopes vs. physical properties. (a,b) Subaqueous distributary channels (porosity/permeability); (c,d) sheet sand (porosity/permeability) [19].
Figure 13. Stable carbon isotopes vs. physical properties. (a,b) Subaqueous distributary channels (porosity/permeability); (c,d) sheet sand (porosity/permeability) [19].
Minerals 15 00795 g013
Minerals 15 00795 g014
Figure 14. Schematic diagram of reservoir evolutionary path. (a) Initial state; (b) Dissolution by organic acids; (c) Precipitation by minerals.
Figure 14. Schematic diagram of reservoir evolutionary path. (a) Initial state; (b) Dissolution by organic acids; (c) Precipitation by minerals.
Minerals 15 00795 g014
Table 1. Electron probe test data of Yaojia Formation stratigraphy in the study area (Calcite).
Table 1. Electron probe test data of Yaojia Formation stratigraphy in the study area (Calcite).
WellDepth
(m)		Elemental Composition (wt.%)Total
(%)
Na2OAl2O3MgOSiO2CaOMnOFeOSrOBaOCO2
G1411973.560.0750.030.0960.30251.760.8162.6050.0770.0243.82599.606
1973.560.0790.0070.0270.3552.371.0012.8970.0150.01543.582100.343
1973.560.07500.0820.17154.6670.4721.29300.01543.706100.481
1973.560.120.0350.0270.37552.3331.0112.65200.01243.668100.233
1973.560.1120.0060.0550.59651.6061.2333.33400.0143.536100.488
1973.560.1690.030.0550.41153.1011.0332.6530043.487100.939
2001.370.0880.0020.0760.23850.7940.7573.7440.124043.72599.548
2001.370.0470.0070.1030.24351.8450.9932.7720.139043.68999.838
2001.370.0860.0020.1170.26651.7510.9733.55700.03543.517100.304
2001.370.0610.0020.0210.26451.4180.8362.8670043.8899.349
2001.370.1160.6450.0550.27951.1770.9643.2380.0620.00743.746100.289
2001.370.0620.0060.1030.28251.5490.7943.2530.0310.02243.70199.803
2001.370.0590.0310.0340.2750.2990.9634.0920.108043.68399.539
2001.370.086000.23450.8760.7063.780.077043.74999.508
2001.370.0530.00300.22450.6411.0173.650.015043.77199.374
G1421835.390.0730.0420.0890.35853.7620.9732.0630.0770.02543.48100.942
1835.390.0480.0260.1090.29530.9222.3740.1240.00543.565100.463
1835.390.090.0280.2530.33452.7421.0212.33100.0443.599100.438
1835.390.0430.0190.0550.37451.3751.5212.3890.2780.07243.66599.791
1835.390.02900.0210.33352.0241.1922.2960043.79699.691
1842.190.1330.0250.0620.36751.9651.2313.2670.2010.02543.414100.69
1842.190.1270.0610.1650.33252.1321.2843.4090.1080.0143.338100.966
1842.190.0560.0280.0890.22951.3830.7773.1300.0343.79899.52
1842.190.04900.0690.40450.9091.223.2910043.72599.667
1842.190.120.0290.3840.35751.1541.3653.330.1550.05743.458100.409
Table 2. C-O isotope data sheet of the Yaojia Formation in the study area.
Table 2. C-O isotope data sheet of the Yaojia Formation in the study area.
Well NumberSample NumberDeepth, mStratigraphic Levelδ18OV-PDB, ‰δ13CV-PDB, ‰
G141G141-11973.7 K1y1−20.63−4.86
G141-32001.4 K1y1−20.56−4.91
G141-42002.4 K1y1−19.45−3.48
G142G142-11834.4K1y1−18.7−3.03
G142-21834.5K1y1−19.2−2.03
G142-31835.4K1y1−18.82−5.21
G142-41842.2K1y1−18.91−4.99
G844G844-22037.2K1y1−18.22−5.53
G844-32038.2K1y1−12.84−5.11
G844-52056.6K1y1−15.14−4.6
Y142Y142-131898.0K1y1−18.3−2.08
Y142-141894.6K1y1−16.78−3.52
Y142-151890.3K1y1−14.95−2.65
Y89Y89-21947.7K1y1−12.6−9.79
Y89-31950.9K1y1−12.26−11.31
Disclaimer/Publisher’s Note: The statements, opinions and data contained in all publications are solely those of the individual author(s) and contributor(s) and not of MDPI and/or the editor(s). MDPI and/or the editor(s) disclaim responsibility for any injury to people or property resulting from any ideas, methods, instructions or products referred to in the content.

Share and Cite

MDPI and ACS Style

Li, J.; Zheng, Q.; Cai, Y.; Liu, H.; Hu, T.; Wu, H. Genesis of Clastic Reservoirs in the First Member of Yaojia Formation, Northern Songliao Basin. Minerals 2025, 15, 795. https://doi.org/10.3390/min15080795

AMA Style

Li J, Zheng Q, Cai Y, Liu H, Hu T, Wu H. Genesis of Clastic Reservoirs in the First Member of Yaojia Formation, Northern Songliao Basin. Minerals. 2025; 15(8):795. https://doi.org/10.3390/min15080795

Chicago/Turabian Style

Li, Junhui, Qiang Zheng, Yu Cai, Huaye Liu, Tianxin Hu, and Haiguang Wu. 2025. "Genesis of Clastic Reservoirs in the First Member of Yaojia Formation, Northern Songliao Basin" Minerals 15, no. 8: 795. https://doi.org/10.3390/min15080795

APA Style

Li, J., Zheng, Q., Cai, Y., Liu, H., Hu, T., & Wu, H. (2025). Genesis of Clastic Reservoirs in the First Member of Yaojia Formation, Northern Songliao Basin. Minerals, 15(8), 795. https://doi.org/10.3390/min15080795

Note that from the first issue of 2016, this journal uses article numbers instead of page numbers. See further details here.

Article Metrics

Back to TopTop