Diagenetic Evolution and Formation Mechanism of Middle to High-Porosity and Ultralow-Permeability Tuff Reservoirs in the Huoshiling Formation of the Dehui Fault Depression, Songliao Basin

Abstract

The fluid action mechanism and diagenetic evolution of tuff reservoirs in the Cretaceous Huoshiling Formation of the Dehui fault depression are discussed herein. The fluid properties of the diagenetic flow are defined, and the pore formation mechanism of the reservoir space is explained by means of thin sections, X-ray diffraction, electron probes, scanning electron microscopy (SEM), cathodoluminescence, and stable carbon and oxygen isotopic composition and fluid inclusion tests. The results reveal that the tuff reservoir of the Huoshiling Formation is moderately acidic, and the physical properties of the reservoir are characterized by middle to high porosity and ultralow permeability. The pore types are complex, comprising both primary porosity and secondary porosity, with dissolution pores and devitrification pores being the most dominant. Mechanical compaction and cementation are identified as key factors reducing reservoir porosity and permeability, while dissolution and devitrification processes improve pore structure and enhance pore connectivity. Diagenetic fluids encompass alkaline fluids, acidic fluids, deep-seated CO₊-rich hydrothermal fluids, and hydrocarbon-associated fluids. These fluids exhibit dual roles in reservoir evolution: acidic fluids enhance the dissolution of feldspar, tuffaceous materials, and carbonate minerals to generate secondary pores and improve reservoir quality, whereas alkaline fluids induce carbonate cementation, and clay mineral growth (e.g., illite) coupled with late-stage mineral precipitation obstructs pore throats, reducing permeability. The interplay among multiple fluid types and their varying dominance at different burial depths collectively governs reservoir evolution. This study underscores the critical role of fluid–rock interactions in controlling porosity–permeability evolution within tuff reservoirs.

1. Introduction

Tuff is formed by the compaction and consolidation of volcanic ash with particle sizes of less than 2 mm. The fine-grained pyroclastic materials produced during volcanic eruptions (>90%) are dispersed by the wind [1,2,3]. There are two main types of tuff formation: the primary airfall type, which results from the direct deposition of volcanic ash into the lake, and the water-transported type, which forms when volcanic material is eroded, transported, and redeposited by fluvial processes (streams or rivers) into the lake environment [4,5]. At present, oil and gas have been found in some tuff reservoirs, such as the green tuff reservoir in the Yoshii-Tobaisaki Gas Field in Japan [6]; the reservoirs of tuffaceous rocks in Wuerhe Oilfield of the Junggar Basin [7]; the Nantun Formation sedimentary tuff reservoir in the Sudelte Structural Belt, Buir Depression, Hailaer Basin [8]; and the tight tuff reservoir of Tiaohu Formation, Santanghu Basin [9]. The geological evolution of a specific region is discussed in the context of volcanic activity and its influence on sedimentation [10,11].

Water-rock interactions are the link between the evolution of diagenetic minerals and changes in the underlying water ions. It is one of the most crucial geological processes in the formation and evolution of oil and gas reservoirs. It runs through the whole diagenetic evolutionary history of the reservoir and is involved in the migration and accumulation of oil and gas [12]. Diagenetic fluids, including meteoric water, seawater, and hydrothermal fluids, play a crucial role in mineral dissolution, precipitation, and replacement processes. These fluids can alter the porosity and permeability of reservoirs, impacting hydrocarbon storage and migration [13]. In the context of hydrocarbon charging, the dissolution of organic acids and organic carbon sources and the subsequent decarboxylation and oxidation of organic acids lead to changes in reservoir water quality and the acidification of pore water, which cause the instability of alkaline minerals and the transformation of clay minerals [14,15,16]. When the formation water in a reservoir is acidic, Fe³⁺ and Mn^3+/4+ ions dissolve. These dissolved ions are then involved in the direct oxidation of biomethane during early diagenesis or the thermochemical oxidation of hydrocarbons in middle diagenesis. Eventually, reduced ions such as Mn²⁺ and Fe²⁺ are released and enter secondary precipitated minerals [17,18]. Therefore, the major elements in secondary minerals, such as Mn, Fe, and Mg, are effective geochemical indicators that reflect the interactions between hydrocarbons and water-rock interactions and related diagenetic fluid characteristics [19,20]. Tuff reservoirs typically differ significantly from other tight reservoirs such as tight sandstones and shales [21], generally exhibiting higher porosity than shale reservoirs, and intergranular pores contribute more to the pore system in dense tuff reservoirs than do organic pores, which provide the main reservoir space in shale [9,22,23]. The evolution of these reservoirs is influenced primarily by the abundance of tuff and the degree of development of primary pores. As the tuffaceous content increases, the pore type transitions from intergranular dissolved pores to intergranular pores [24,25]. The dissolution of tuff and the process of the formation of dissolved pores are discussed, and the pore structure of the products of this process is deteriorated by alteration products such as authigenic quartz, apatite, and illite, in which the porosity of the reservoir increases without affecting permeability [25,26,27]. In the study of reservoir genetic control factors, diagenesis, such as devitrification and dissolution, is the main factor [25,28,29]. However, systematic analyses of the effects of diagenetic fluid properties on the formation and control factors of tuff reservoirs are lacking.

In general, against the background of water-rock interactions and diagenesis, combined with the basic characteristics of petrology, reservoir space, and physical properties, the fluid action mechanism and diagenetic evolution of the Cretaceous Huoshiling Formation tuff reservoir in the Dehui fault depression are studied. The purpose of this study is to define the types, properties, and sources of diagenetic fluids in tuff reservoirs and clarify the influence of different diagenetic fluids on the formation of reservoir space. The formation mechanism of reservoir space should be explored, the genesis and physical property control factors of tuff reservoir pores should be explained, and the diagenetic evolution process of the reservoir should be clarified. Further exploration of volcanic rock reservoirs under similar geological backgrounds provides important scientific data and theoretical support.

2. Geological Setting

Located in the southeastern uplift of the Songliao Basin, the Dehui fault depression covers an area of 4053 km² and was formed in Mesozoic sedimentary strata that developed over the shallow metamorphic basement of the late Paleozoic era. The thickness of the northern stratum is greater than that of the southern stratum [30,31], which is a typical “double fault type” fault depression and contains seven secondary tectonic units. The Cretaceous was the main horizon for oil and gas exploration in the Songliao Basin. The main volcanic rocks containing oil and gas are the Yingcheng Formation, Shahezi Formation, and Huoshiling Formation, and the oil-reservoir-cap combination is relatively well developed [32,33]. The target layer in the study area is the Huoshiling Formation, which contains primarily pyroclastic rocks with lithologies dominated by tuff (Figure 1).

3. Materials and Methods

A total of 60 tuff samples from the Huoshiling Formation were collected from Wells DS16, DS20, DS81, DS94, and DS102. These samples were processed into thin sections for whole-rock X-ray diffraction (XRD) analysis, electron probe microanalysis (EPMA), cathodoluminescence (CL) imaging, carbon-oxygen isotope micro-area analysis, and fluid inclusion studies, with corresponding experimental tests systematically conducted. Electron probe, cathodoluminescence, and stable isotope analyses of carbon and oxygen were carried out at the Guangzhou Institute of Geochemistry, Chinese Academy of Sciences. Fluid inclusion temperature measurements were completed by the Shaanxi Provincial Key Laboratory of Oil and Gas Accumulation Geology and the Beijing Institute of Geology of Nuclear Industry.

3.1. X-Ray Diffraction

The instrument used was a polycrystalline X-ray diffractometer. The oil-bearing rock samples were washed and treated to a fluorescence level less than 4, dried at a temperature less than 60 °C, and cooled to room temperature before use. The crushed rock samples were ground to a total particle size of less than 40 µm or no particle feeling after finger rubbing, and the sample powder was placed in the groove of the sample slide for use. The X-ray diffraction (XRD) patterns obtained after measuring the samples were compared to determine the mineral species according to the standard X-ray diffraction (XRD) data. The integrated intensity of selected diffraction peaks of clay minerals and various nonclay minerals on the diffraction pattern was measured, and the total amount of clay minerals and nonclay mineral content were calculated according to SY/T 5163-2018 [34].

3.2. Electron Probes

Electron probe microanalysis determines the mineral composition by detecting the mass fraction of local elements and then determines the mineral composition. In this study, a Japanese electron JXA-8230 electron probe and an Oxford X-Max 20 energy spectrometer were used. The morphology, composition, and distribution analysis of the major elements of the solid sample were combined with an energy spectrometer to study the change characteristics of the composition and structure during the growth of minerals, which can be used for rapid qualitative and semiquantitative analysis.

3.3. Cathodoluminescence

The experiment was conducted in a dark room utilizing the Leica DM2700P and CLF-2 CL systems for cathodoluminescent (CL) petrologic studies. The system voltage was maintained between 13 and 15 kV, the current ranged from 240 to 260 μA, and the vacuum was controlled within the range of 50 to 60 nm. Cathodoluminescence is a physical luminescence phenomenon observed on the surface of an object, produced by bombarding the surface of a solid sample with cathode rays (fast electron beams). This process converts electrical energy into light radiation energy, commonly referred to as cathode-ray luminescence.

CL is a powerful tool for studying carbonate minerals, as it reveals information about their trace element composition and diagenetic history. The CL properties of carbonate minerals, such as calcite and dolomite, are primarily controlled by the presence of activators (e.g., Mn²⁺) and quenchers (e.g., Fe²⁺) [35,36]. CL imaging can identify growth zoning, cementation phases, and diagenetic alterations, providing insights into the formation and evolution of carbonate rocks [37,38]. In this study, CL was employed to analyze the mineralogical features and diagenetic processes of the Huoshiling Formation, with a focus on carbonate minerals.

3.4. Carbon and Oxygen Isotope Microanalysis

The primary instruments utilized for the analysis of carbon and oxygen isotopes in carbonate cement microzones include a laser micromachining sample preparation device and a gas isotope mass spectrometer (Thermo Scientific MAT253, Waltham, MA, USA). The analytical procedure is as follows: After the laser and microscope are installed coaxially, a coherent laser beam emitted by a He-Ne laser is focused (to approximately 20 μm) onto the thin slice sample within the vacuum sample chamber, under vacuum conditions. This process heats the carbonate minerals in the thin-slice sample to temperatures exceeding 1500 °C, resulting in the decomposition of the minerals and the production of CO₂ gas. The CO₂ is subsequently collected in the vacuum purification system using the cold trap principle and is then introduced into the gas isotope mass spectrometer for analysis. Finally, the carbon and oxygen isotope values of the CO₂ gas are determined, with the PDB standard employed for the same digital analysis.

3.5. Fluid Inclusions

The fluid inclusion tests and analysis experiments were conducted using the German Linkam-TH600 cold and hot platform. The thermocouple was calibrated with synthetic Fis over a temperature range of −196 to 600 °C. The temperature accuracy was ±0.1 °C for the range of −100 to 25 °C, ±1 °C for 25 to 400 °C, and ±2 °C for temperatures above 400 °C. During the analysis, the heating rate typically ranged from 0.2 to 5 °C/min; however, it decreased to 0.1 °C/min near the freezing point and to 0.2 to 0.5 °C/min close to the homogenization temperature.

4. Results

4.1. Reservoir Characteristics

4.1.1. Petrological Characteristics

The rock types of the Huoshiling Formation are diverse, and consist mainly of tuff, rhyolitic tuff, argillaceous tuff, etc. The tuff core is mainly gray and white, and a small amount of carbon debris is found in the tuff sample from Well DS20 (Figure 2a,b). Some samples exhibit strong silicification and argillization, and chlorite can be observed (Figure 2d–f). Moreover, some samples contain magnetite and muscovite minerals under a microscope (Figure 2c,g–i). At the same time, quantitative analysis via X-ray diffraction (XRD) was performed on 19 samples from the Huoshiling Formation tuff reservoir, and the characteristics of the mineral composition are shown in

Table 1. Mineral composition characteristics of whole-rock tuff from the Huoshiling Formation in the Dehui fault depression.

No.		Depth/m	Mineral Volume Fraction/%				Clay Minerals Mineral Mass Fraction/%
			Quartz	K-Feldspar	Plagioclase	Carbonate	Clay Mineral	Illite/Smectite Mixed Layer	Illite	Chlorite
A	1	2203.66	47.3	2.4	34.7	/	15.6	59	26	15
	2	2204.46	26.3	3.8	23.1	/	46.8	71	26	3
	3	2204.86	41.8	2.8	33.8	1.7	19.9	70	21	9
	4	2206.6	37.7	2.6	17.8	13.2	28.7	80	17	3
	5	2208.31	40.6	2.5	29.8	2.6	24.5	81	13	6
	6	3275.30	41.3	3.5	21.5	0.5	29.1	86	13	1
	7	3276.00	43.7	3.9	21.5	0.4	24.1	90	9	1
	8	3036.38	34.4	1.5	18.4	20.2	24.6	86	13	1
	9	2323.50	13.5	7.5	31.5	8.5	38.2	78	8	10
	10	2329.09	37.8	7.6	30.7	1.3	21.6	66	16	11
Average			36.4	3.8	26.3	6.1	27.3	76.7	16.2	6.0
B	1	1435.46	44.7	/	9.3	1.2	42.9	97	1	/
	2	1436.07	51.1	/	6.3	1.2	39.2	95	3	/
	3	1436.90	50.8	/	6.1	3.8	37.1	98	2	/
	4	1437.95	49.5	/	11.2	2.7	34.3	98	2	/
	5	1438.88	46.7	/	7.1	1.2	42.6	96	4	/
	6	1439.86	41.2	/	4.6	1.5	51.4	96	4	/
	7	1440.81	44.2	/	7.3	0.4	47.1	96	4	/
	8	1442.73	40.9	/	4.1	1.4	53.2	94	6	/
	9	1443.10	37.1	/	12.7	3	45.3	99	1	/
Average			45.1	/	7.6	1.8	43.7	96.6	3.0	/

Note: A—tuffaceous sandstone; B—tuff.

. The division of Groups A and B is based on detailed petrographic analysis of core samples and thin sections under a microscope. Group A primarily consists of tuffaceous rocks (Figure 2a,b). In contrast, Group B is characterized by tuffaceous sandstones (Figure 2i), with the figure representing a typical example of this group. This classification is supported by the distinct mineralogical and textural features observed in the samples.

The results show that the mineral composition is dominated by quartz and feldspar, with significant amounts of carbonate and clay minerals. In tuffaceous sandstone and tuff, the mass fractions of plagioclase and clay minerals are relatively high. Specifically, the illite/smectite mixed layer minerals constitute 76.7% and 96.6% of the clay minerals in tuffaceous sandstone and tuff, respectively, while the mass fractions of illite are 16.2% and 3.0%, respectively. Additionally, both rocks contain relatively low mass fractions of potassium feldspar and chlorite. In tuffaceous sandstone, the mass fraction of potassium feldspar is 3.8% and that of chlorite is 6.0%. In tuff, the mass fractions of potassium feldspar and chlorite are extremely low, nearly non-existent. Potassium feldspar readily dissolves and decomposes in acidic environments, and chlorite may undergo chemical alterations in oxidizing environments. Owing to long-term diagenesis, the geological conditions where tuff is situated may cause the potassium feldspar and chlorite within the tuff to gradually decrease and even disappear completely [39,40]. The TAS diagram (Figure 3a) shows that most of the tuff samples are located in the region of medium-felsic volcanic rocks (trachyte, phonolite, basaltic trachyandesite). Moreover, most of the data points in the K₂O and SiO₂ diagrams are located in the intermediate-felsic volcanic zones of dacite and rhyolite (Figure 3b).

In summary, the Huoshiling tuff in the study area has a lower quartz volume fraction and a higher plagioclase volume fraction, indicating that the original volcanic ash of the tuff was moderately felsic. In the diagenetic process, the optimal temperature for the conversion of feldspar to kaolinite is 120~140 °C. After this temperature is exceeded, kaolinite begins to transform into illite under sufficient K⁺ conditions [41]. In this temperature range, smectite will transform into illite, and the illite/smectite mixed layer is a transition product of this transition. However, due to the low content of potassium feldspar and the fluid retention effect, only part of smite is illitized [20], resulting in a high content of the illite/smectite mixed layer. In addition, the high content of the illite/smectite mixed layer in clay minerals at the diagenetic stage may be related to the deep diagenetic transformation of tuffaceous material [42].

Figure 3. (a) Classification of tuffs in the TAS (from LeBas, 1986) [43]; (b) K₂O-SiO₂ discrimination diagram for the tuffs (from Maitre, 2002) [44].

Figure 3. (a) Classification of tuffs in the TAS (from LeBas, 1986) [43]; (b) K₂O-SiO₂ discrimination diagram for the tuffs (from Maitre, 2002) [44].

4.1.2. Reservoir Porosity and Permeability

The physical property data of the reservoir indicate that the Huoshiling Formation tuff reservoir within the study area exhibits medium–high porosity coupled with ultralow permeability (Figure 4a). The reservoir’s porosity varies from 2.8% to 21%, with an average value of 13.85%. Notably, approximately 68.4% of the rock samples possess porosities exceeding 10% (Figure 4b). In terms of permeability, the maximum recorded value is 0.95 mD, while the minimum is 0.007 mD, resulting in an average permeability of 0.30 mD. Furthermore, around 93% of the rock samples exhibit permeabilities below 1.0 mD (Figure 4c). Overall, while the correlation between reservoir porosity and permeability is weak, there is a tendency for permeability to increase with rising porosity (Figure 4a).

4.1.3. Pore Types

Recent studies have highlighted the critical role of scanning electron microscopy (SEM) in characterizing pore structures and their influence on reservoir properties in unconventional reservoirs. For instance, Meng et al. (2023) employed an integrated approach combining scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) to analyze water occurrence and pore size distribution in marine shale reservoirs, highlighting the critical role of pore structures in controlling fluid behavior [45]. In a subsequent study, the authors investigated the rock fabric of lacustrine shale in the Upper Cretaceous Qingshankou Formation, Songliao Basin, utilizing SEM to reveal complex pore networks and their influence on residual oil distribution. Furthermore, they applied SEM and NMR techniques to examine the effects of initial water saturation and water films on imbibition behavior in tight reservoirs, underscoring the importance of pore-scale characteristics in fluid flow dynamics [46,47]. Collectively, these studies underscore the value of SEM in understanding pore structures and their implications for reservoir performance, providing a robust comparative framework for our SEM analysis of the Huoshiling Formation.

Analyses of thin sections, SEM, and cathodoluminescence (CL) images reveal that the reservoir space of the Huoshiling Formation is complex, comprising both primary and secondary pores (Figure 5a,b). Primary pores, formed through compaction or cementation, exhibit polygonal shapes with relatively straight edges (Figure 5a). Secondary pores, which dominate the reservoir space, are primarily associated with the dissolution of feldspar, tuff, carbonate, and other soluble minerals, resulting in dissolution pores, dissolution fractures, and micropores formed by devitrification (Figure 5c–f). These pore types often occur in combination rather than in isolation, with secondary dissolution pores and devitrification pores being particularly prominent in the tuff reservoirs of the study area.

Tuffaceous dissolution pores primarily arise from the complete or incomplete dissolution of tuffaceous material situated between detrital grains at the edges of cracks. Influenced by late compaction and the dissolution of minerals, the original cracks expand, leading to the formation of dissolution fractures (Figure 5c,d). Feldspar dissolution is also significant, with feldspar dissolution pores resulting from the dissolution of feldspathic minerals (Figure 5e). In addition, the devitrification of volcanic glass leads to the formation of aluminosilicate minerals, which, under acidic fluid action, dissolve to create micropores (Figure 5f). Devitrification further contributes to the development of intergranular pores filled with quartz and feldspar (Figure 5g). Whole-rock analysis (Table 1) indicates a high proportion of clay minerals in the tuff reservoir, supported by SEM observations of intergranular pores associated with illite/smectite mixed layers, chlorite, and illite (Figure 5h–l).

4.2. Diagenetic Types

The diagenesis of the tuff reservoirs within the Huoshiling Formation in the study area primarily involves mechanical compaction, cementation, metasomatism, and dissolution, all of which contribute to the transformation of the buried reservoirs.

4.2.1. Mechanical Compaction

Mechanical compaction predominantly occurs during the early stages of diagenesis. This process results in irreversible porosity loss, a destructive form of diagenesis that directly decreases both the porosity and permeability of the reservoir rock. Consequently, under the influence of compaction, the rock particles predominantly exhibit linear and convex contacts, with a limited number displaying point-like contacts in their particle-contact relationships. The detrital particles are oriented and distributed relatively densely, and as compaction progresses, local fragmentation of the detrital particles becomes evident (Figure 6a–c).

4.2.2. Cementation and Metasomatism

The Huoshiling Formation reservoir in the Dehui fault depression exhibits notable carbonate cementation, siliceous cementation, and mineral cementation of authigenic clay.

Carbonate Cementation

Carbonate cementation is prominent in the study area. To ascertain the type of carbonate cement, electron probe microanalysis indicated a volume content ranging from 5% to 40% for FeO, and from 15% to 38% for MnO, with values between 65% and 90% for the former and 55% to 91% for the latter in the elemental maps of the three terminals. The volume content of MgO primarily ranges from 1% to 15%, suggesting that the carbonate cement is predominantly composed of calcite and iron calcite, with no indications of dolomite minerals (Figure 7a). Microscopically, the carbonate exhibits interlocking characteristics with the embedded cementation (Figure 6d,e). Microscopic examination of selected thin sections reveals that the displayed calcite as a porous cementation that filled the intergranular pores, and cathodoluminescence tests revealed bright yellow to yellow colors, predominantly observed in the form of pore filling and the replacement of other minerals (Figure 8a,f).

Siliceous Cementation

Siliceous cementation primarily manifests as quartz overgrowths and authigenic quartz (Figure 6e). The quartz overgrowths display well-formed crystals characterized by hexagonal columnar shapes and more complete crystal faces (Figure 5j). The extent of quartz overgrowth development is influenced by the acidity and alkalinity of the diagenetic fluid, the source of SiO₂, as well as temperature and pressure conditions. Previous studies indicate that silica cements predominantly originate from the pressure dissolution of clastic quartz particles, the transformation of smectite to kaolinite, the dissolution of volcanic materials, and the dissolution of unstable minerals such as potassium feldspar and albite within the clastic framework in acidic environments [48,49]. Siliceous cementation reduces pore space, resulting in the close adherence of fragment particles to one another, thereby diminishing the physical properties of the reservoir.

Clay Mineral Cementation

X-ray diffraction analysis indicates that both tuffaceous sandstone and tuff exhibit a high mass fraction of clay minerals (Table 1), with a particularly elevated content of Illite/smectite mixed layers. Clay minerals can be categorized into terrigenous and indigenous types. Authigenic minerals typically possess a superior crystal structure compared to terrigenous clay minerals, and they primarily develop from the edges of grains toward the centers of pores, where they become filled [50,51].

Scanning electron microscopy (SEM) analysis indicates that the illite/smectite mixed layer primarily forms through pore bridging or filling, resulting in aggregates that are typically crumbled, flocculent, or honeycomb-like (Figure 5h). The composition of the autogenetic illite minerals is relatively straightforward, characterized by large crystals with well-defined shapes; the majority exhibit filamentous, hair-like, and honeycomb structures that occupy the reservoir pores, with a notable development of microcracks (Figure 5i,j).

Chlorite is frequently identified by its roles in pore filling and lining [52]. Notably, there is no distinct vertical or parallel alignment between chlorite crystals and detrital particles during pore filling; chlorite, exhibiting pompon-like and rosette structures, fills the pores and is often associated with authigenic quartz particles (Figure 5k). In terms of pore lining, chlorite displays needle-like structures that grow perpendicularly to the particles and extend toward the pores (Figure 5l). As the crystals approach the pores, the abundance of available growth space increases, resulting in larger crystal formations and a greater number of intercrystal pores, ultimately leading to a disordered accumulation of blade-like aggregates [53,54].

Metasomatism

The metasomatism observed in the study area encompasses the alteration of skeletal particles and the surrounding matrix by calcite and dolomite. The common calcite is characterized by interlocking cementation and carbonate-embedded cementation (Figure 6d,e). In some samples, feldspar particles underwent dissolution and were either partially or completely replaced by calcite (Figure 6f), thereby affecting the physical properties of the reservoir.

4.2.3. Dissolution

The X-ray diffraction analysis indicated that the primary volcanic ash of the tuff reservoir in the Huoshiling Formation is intermediate to acidic, characterized by elevated levels of feldspar in its mineral composition, particularly the highest concentrations of plagioclase. Consequently, feldspar particles, tuffaceous minerals, and other easily soluble minerals may dissolve during the later stages of tuff reservoir dissolution under the influence of acidic fluids. This process results in the expansion of solution pores and the formation of corrosion fractures (Figure 5c,d). Initially, the tuffaceous content of the reservoir is relatively low, facilitating the formation of numerous intergranular dissolution pores following early dissolution, which subsequently preserves migration channels for late-stage acidic fluids and hydrocarbon charging. Following late dissolution, secondary dissolution processes more readily create high-quality reservoirs [55], significantly enhancing the reservoir space and contributing to the formation of large secondary pores in this region.

4.2.4. Devitrification

The type of tuff debris in the studied region is predominantly glassy debris, with glass being the primary component and a highly unstable element. As burial depth, temperature, and pressure increase, glassy materials tend to undergo a transformation towards crystallinity, a process known as devitrification, which primarily occurs during the early stages of rock burial [53,56]. The products of devitrification mainly consist of quartz and feldspar crystals, resulting in the formation of pores [57]. Several factors influence the development of devitrification pores, including the properties of volcanic rocks, particularly acid volcanic glass, which is prone to forming devitrification pores. Additionally, the concentrations of glass fragments and organic acids play a crucial role in controlling the rate of devitrification [58].

The dissolution of the tuff has created conditions conducive to pore development. Early corrosion processes lead to the formation of authigenic kaolinite and authigenic quartz, while low-temperature quartz in the vitric tuff is produced during devitrification, resulting in a significant number of intercrystalline pores (Figure 5f,g). In the later stages, dissolution pores are formed under the influence of acidic diagenetic fluids [24]. The clastic components of tuff are predominantly vitric fragments, with the main constituent being volcanic glass, an extremely unstable material that readily undergoes devitrification and dissolution. Furthermore, in conjunction with basin simulation and the properties of carbonate cement, the tuff reservoirs of the Huoshiling Formation contain a certain amount of organic matter. The hydrocarbon generation evolution of this organic matter during burial generates organic acids, which can effectively facilitate the devitrification process.

5. Discussion

5.1. Mechanism of Diagenetic Fluid Action

This study employed the characteristics of carbon and oxygen isotopes found in carbonate cement, in conjunction with findings from fluid inclusion analyses. The effects of fluids are evident in two main forms: initially, alkaline fluids facilitate the deposition of calcite, dolomite, and various carbonate minerals that occupy fractures and block reservoir space; conversely, acidic fluids effectively dissolve soluble mineral constituents, including felsic, tuffaceous, and carbonate minerals, leading to the creation of dissolution pores that improve the reservoir’s physical attributes [24,59,60].

No dolomite mineral features were identified in the carbonate cements of the Huoshiling Formation (Figure 7a). First, carbonate rocks in marine and continental environments are divided according to the formula used to calculate paleosalinity (Z) [61], and the water environment is a marine environment when Z > 120; when Z < 120, it is a continental environment. The Z-value of all samples in the study area is less than 120, indicating that the pore fluid that forms cement is in a continental environment. Second, concerning the relationship between the δ¹⁸O_V-PDB of carbonate cement and the temperature of diagenetic fluid, previous studies [62] established a calculation formula for the palaeotemperature of the fluid. This Formula (1) is employed to derive the corresponding palaeotemperature of the diagenetic fluid, which is then used as the palaeotemperature for the formation of carbonate cementation.

T = 16.9 − 4.38(δ_c − δ_ω) +0.1(δ_c − δ_ω)²

(1)

The δ¹⁸O_V-PDB of carbonate cement is measured by δ_c, while δ_ω represents the δ¹⁸O_V-SMOW of seawater during the formation of carbonate cement, which is considered to be 0 in this study.

Consequently, the formation stage of carbonate cementation can be divided into two distinct stages (

Table 2. Carbon and oxygen isotope data of the Huoshiling Formation in the Dehui fault depression.

No.	Depth/m	δ13CV-PDB (‰)	δ18OV-PDB (‰)	δ18OV-SMOW (‰)	T/°C	Z
1	3282.1	−5.119	−20.476	9.801	148.51	106.6
2	3282.1	−4.737	−20.614	9.659	149.68	107.3
3	3282.1	−5.215	−20.371	9.910	147.62	106.5
4	3282.1	−5.479	−19.042	11.280	136.56	106.6
5	3282.1	−5.061	−18.742	11.589	134.12	107.6
6	3282.1	−7.022	−17.216	13.162	121.95	104.3
7	3282.1	−5.261	−18.231	12.116	129.99	107.4
8	3230.6	−6.404	−19.657	10.646	141.64	104.4
9	3230.6	−7.587	−19.442	10.867	139.86	102.1
10	3230.6	−5.698	−19.82	10.478	142.99	105.8
11	3230.6	−5.565	−19.926	10.368	143.88	106.0
12	3283.7	−4.407	−20.268	10.016	146.75	108.2
13	3283.7	−3.014	−19.989	10.303	144.41	111.2
14	3283.7	−3.171	−19.873	10.423	143.44	110.9
15	3501.6	−20.923	−11.021	19.548	77.32	79.0
16	3502.0	−20.748	−11.235	19.328	78.73	79.2
17	3502.0	−21.079	−10.382	20.207	73.15	79.0
18	3506.5	−19.570	−5.700	25.034	45.12	84.4
19	3922.6	−1.923	−17.514	12.855	124.29	114.6
20	3922.6	−3.311	−16.668	13.727	117.69	112.2
21	3922.6	−1.906	−16.993	13.392	120.21	114.9
22	3926.7	−2.538	−18.818	11.511	134.73	112.7
23	3926.7	−2.656	−18.215	12.132	129.86	112.8
24	3930.0	−4.978	−20.673	9.598	150.19	106.8
25	3930.0	−6.993	−17.345	13.029	122.96	104.3
26	3930.0	−5.387	−19.775	10.524	142.62	106.4
27	3930.0	−6.282	−16.801	13.590	118.72	106.1
28	3932.0	−4.361	−19.912	10.383	143.76	108.5
29	3932.0	−5.443	−15.195	15.245	106.54	108.6
30	3932.0	−5.286	−15.339	15.097	107.61	108.8
31	3932.5	−4.556	−19.147	11.171	137.42	108.4
32	3932.5	−5.016	−16.785	13.606	118.59	108.7
33	3932.5	−5.158	−16.978	13.407	120.09	108.3
34	2205.0	−20.605	−4.985	25.771	41.22	82.6
35	2205.0	−21.451	−3.619	27.179	34.06	81.6
36	2205.0	−20.178	−4.556	26.213	38.93	83.7
37	2205.0	−22.049	−8.402	22.248	60.76	78.0
38	2205.0	−18.325	−1.825	29.029	25.23	88.9
39	2205.0	−17.134	−0.838	30.046	20.64	91.8
40	2206.5	−9.939	−18.938	11.387	135.71	97.5
41	2206.5	−9.348	−18.732	11.599	134.03	98.8
42	2206.5	−9.346	−19.038	11.284	136.53	98.7
43	1435.7	−18.926	−9.358	21.263	66.65	83.9
44	2481.1	−25.076	−9.885	20.720	69.97	71.0
45	2481.1	−23.238	−8.116	22.543	59.04	75.7
46	2481.1	−26.596	−10.271	20.322	72.44	67.7
47	3506.0	−29.742	−3.280	27.529	32.34	64.8

Note: δ¹⁸O_V-SMOW = 1.03086 × δ¹⁸O_V-PDB + 30.86 [63]. Z = 2.048(δ¹³C_V-PDB + 50) + 0.498(δ¹⁸O_V-PDB + 50) [61].

, Figure 7b). The calcareous filling, indicative of alkaline fluid, is composed of calcite and develops in two phases. Early calcite exhibits orange-red cathode light, whereas late calcite emits bright orange cathode light; it fills cracks or pores and is oriented parallel to the early calcite. Conversely, the siliceous filling, which signifies acidic fluid, consists of quartz and also develops in two stages. The cathode light of early quartz is dark brown-red, while that of late quartz is bluish-purple (Figure 8). Additionally, a small amount of kaolinite is observed, characterized by indigo blue cathode light, which is typical of hydrothermal dissolution and secondary mineral precipitation.

5.2. Diagenetic Fluid Properties

5.2.1. C-O Isotope Characteristics

The carbon and oxygen isotopic compositions of carbonate cements serve as effective indicators of fluid sources. Consequently, carbonate cements formed by distinct fluids with varying carbon sources exhibit different carbon isotopic compositions [64]. The existing research identifies three sources of carbon in geological fluids: marine carbonate rock (δ¹³C_V-PDB = 0 ± 4‰) [65], a magmatic or deep source (δ¹³C_V-PDB = −5‰ to −2‰ and −9‰ to −3‰, respectively), and sedimentary organic matter (δ¹³C_V-PDB = −30‰ to −15‰) [66,67,68].

In the δ¹³C_V-PDB-δ¹⁸O_V-PDB diagram (Figure 9a), the formation of carbonate cement is associated with the decarboxylation of diagenetic carbonates and organic acids. Two distribution intervals are observed for the δ¹³C_V-PDB and δ¹⁸O_V-PDB values. Specifically, δ¹³C_V-PDB ranges from −29.742‰ to −17.134‰ and from −9.939‰ to −1.923‰, while δ¹⁸O_V-PDB spans from −20.614‰ to −16.785‰ and from −11.235‰ to −0.838‰. As depth increases, the δ¹³C value exhibits a positive shift, whereas the δ¹⁸O value shows a negative shift (Figure 9c,d). At a formation depth of 2500 m, the relatively low δ¹³C value indicates an influence from organic carbon isotopes. At a depth of 3000 m, as the thermal maturity of the organic matter increases, a greater release of carbon dioxide occurs, leading to an increase in the δ¹³C value. The δ¹⁸O value is primarily influenced by temperature; higher temperatures correlate with lower δ¹⁸O values [69]. In the δ¹³C_V-PDB-δ¹⁸O_V-SMOW diagram (Figure 9b), the data points are situated within the areas designated for sedimentary organic matter and the mantle multiphase system. In the deposited organic matter zone, the data relate to the processes of decarboxylation and oxidation of organic matter. Meanwhile, in the mantle multiphase system area, the data trend towards the sedimentary rock contamination/high-temperature effect zone and the low-temperature alteration area, exhibiting a horizontal distribution. This trend may be attributed to the degassing effect of CO₂ or the water–rock reaction between the fluid and surrounding rocks [70,71]. According to the principle of isotope fractionation, when CO₂ degassing occurs within a fluid, gaseous CO₂ escapes, leading to a relative enrichment of the heavier isotopes of carbon and oxygen in the fluid. This process predominantly influences δ¹³C, while the effect on δ¹⁸O is comparatively minor. Conversely, the water–rock reaction primarily involves the exchange of oxygen isotopes between the fluid and the surrounding rock, which significantly impacts δ¹⁸O, with a relatively smaller effect on δ¹³C [70]. By examining the variation characteristics of δ¹³C_V-PDB and δ¹⁸O_V-SMOW values of carbonate cements in the Huoshiling Formation, it is evident that at formation depths between 3000 m and 4000 m, both CO₂ degassing and water–rock interaction jointly influence the C-O isotope composition of diagenetic fluids.

At depths ranging from 2000 m to 2500 m, the formation of carbonate cement is influenced by fluid interactions resulting from the thermal evolution of organic matter. In contrast, at depths between 3000 m and 4000 m, the involvement of CO₂-rich hydrothermal fluids of deep inorganic origin may play a role in the formation of carbonate cement.

5.2.2. Fluid Related to Source Rock Thermal Evolution

Kerogen in source rocks is considered the primary source of organic acids in reservoir field water, with the decarboxylation of kerogen through heat being the principal pathway for organic acid formation. The organic acids and organic matter generated by the thermal evolution of kerogen in source rocks release CO₂, which subsequently dissolves in formation water to create an acidic fluid. Furthermore, organic acids can interact with hydrocarbon-bearing fluids to produce acidic fluids that possess enhanced dissolution capabilities and inhibitory effects, thereby influencing the hydrocarbon generation and evolution processes of source rocks [74].

The results indicate that there are two stages of hydrocarbon-associated inclusions in Well DS102. The homogenization temperature of the first stage is concentrated between 105 °C and 120 °C, with an average of 114 °C. In contrast, the homogenization temperature in the second stage ranges from 120 °C to 140 °C, with an average of 134 °C (Figure 10a–c). For the Well DS81 samples, the inclusion homogenization temperature is primarily concentrated in the range of 115 °C to 120 °C, with an average of 122 °C. The homogenization temperatures of the Well DS20 samples range from 100 °C to 125 °C, yielding an average of 113 °C (Figure 10d–f). Additionally, the inclusions in Well DS16 also exhibit two stages of secondary saline inclusions, with homogenization temperatures concentrated in the ranges of 105 °C to 110 °C and 115 °C to 125 °C, respectively, resulting in average temperatures of 105 °C and 120 °C (Figure 10j–l).

The burial history was reconstructed using Ro data, seismic profiles, and well log data. These data were integrated with regional tectonic events to constrain the timing and magnitude of subsidence and uplift. According to the burial history and thermal evolution of Wells DS102, DS81, DS20, and DS16 (Figure 11), the capture time of the higher-temperature secondary hydrocarbon-bearing saline inclusions ranges from 105 to 120 Ma. This period corresponds to the main hydrocarbon generation and expulsion phase of the Huoshiling Formation source rocks. During hydrocarbon generation, organic acids released from the source rocks react with carbonate minerals, leading to the formation of CO₃²⁺, Ca²⁺, and Mg²⁺, while also dissolving minerals to create secondary pores. However, over time, significant amounts of carbonate minerals precipitate [75,76]. Previous research has suggested that oil and gas charging can impede the compaction of overlying strata and postpone the occupation of pores by cementation, particularly during the initial stages of oil and gas charging [77]. Studies on organic acids present in the formation water of oil and gas reservoirs indicate that the thermal evolution of source rocks can release substantial quantities of short-chain organic acids. These acids exhibit a capacity to supply H⁺ that is 6- to 350-times greater than that of carbonic acid, enabling the dissolution of significant amounts of feldspar and carbonate minerals, thus facilitating the formation of extensive secondary pores within reservoirs [78]. Furthermore, early and prolonged strong hydrocarbon charging is identified as a crucial factor for the effective preservation of devitrification micropores within tuff reservoirs during deep burial [74].

5.2.3. Indicative Significance of Hydrocarbon Associated Saline Inclusions

In the Huoshiling Formation tuff reservoir, the uniformity of fluid inclusion temperature and salinity exhibits a positive correlation (Figure 12). This relationship arises from multiple factors, including diagenesis, hydrocarbon charging processes, and deep hydrothermal activity.

First, it is important to note that tuff reservoirs are characterized as tight reservoirs. As temperature increases, minerals undergo dissolution and precipitation, which subsequently impacts the uniformity of temperature and salinity within the inclusions [79]. During the early diagenetic stage, feldspar and other soluble minerals dissolve under the influence of organic acids (Figure 5e,f), while the secondary enlargement of quartz occurs (Figure 6e). The dissolution of certain carbonate minerals also takes place, releasing ions (such as Ca²⁺, Mg²⁺, etc.) into the fluid. This dissolution process can either absorb or release heat, thereby influencing the local temperature. An increase in ion concentration may result in elevated salinity of the fluid. In the middle diagenetic stage, as temperature and pressure rise, the carbonate ions in the fluid reach a supersaturated state, leading to the reprecipitation of carbonate minerals, primarily calcite (Figure 6d and Figure 8a,b,e,f). Consequently, an increase in temperature during diagenesis may result in a simultaneous rise in both the uniform temperature and salinity of fluid inclusions. Deep hydrothermal fluids originate from magma sources or other deep sources (Figure 9b). These hydrothermal activities produce high-temperature and high-salinity fluids that interact with hydrocarbon materials in the reservoir, thereby influencing fluid inclusions. The formation and evolution of hydrothermal fluids involve the mixing of fluids from various sources within the reservoir, and the degree of this mixing also affects the salinity and homogenization temperature of the fluid inclusions [80,81]. Furthermore, during the hydrocarbon charging process, the reservoir temperature and fluid pressure increase, promoting the dissolution of salts in the fluid and altering the salt concentration, which consequently affects the salinity of the fluid inclusions [80].

5.3. Diagenetic Evolution Stage Division

The formation process of tuff in the Huoshiling Formation within the Dehui fault depression is simulated using an ideal model (Figure 13a). This simulation is integrated with the burial history, thermal history (Figure 11b), and the uniform temperature characteristics of the corresponding layer inclusions (Figure 10f). A comprehensive analysis of vitrinite reflectivity and the pore characteristics of the source rock serves as the basis for establishing a diagenetic evolution sequence (Figure 13).

According to the analysis of burial and thermal histories, the period from 131 to 110 Ma ago corresponds to early rapid burial, during which the strata underwent two episodes of rapid subsidence and structural uplift, reaching depths of 2500 m. The ground temperature during this period ranged between 140 °C and 150 °C, placing the reservoir in the early diagenetic stage. From 110 to 73 Ma ago, the strata experienced normal and continuous deep burial, with ground temperatures ranging from 140 °C to 190 °C, indicating that the reservoir was in the intermediate diagenetic stage. In the late stage, the structure gradually uplifted to a deep burial stage, spanning from 73 Ma to the present, with the reservoir now in the late diagenetic stage (Figure 13b). Consequently, the diagenetic stages of the Huoshiling Formation tuff in the Songliao Basin are categorized into two primary stages: the superficial diagenetic stage and the buried diagenetic stage. The buried diagenetic stage is further subdivided into the early, middle, and late diagenetic stages (Figure 13c). The epigenetic stage refers to the weathering activity that occurs prior to lava surface flow and burial diagenesis.

During the initial stages of burial, the sediment beds are relatively shallow. Due to the leaching effect of atmospheric precipitation, unstable components such as spars and cuttings within reservoirs undergo early dissolution, leading to the formation of secondary pores. As burial depth increases, so does the surface temperature. At a burial depth of 1500 m, the organic material within the formation transitions into the immature to low maturity phase, marking the onset of early diagenesis, during which organic acids are released. The presence of these organic acids further promotes the dissolution of tuff, carbonate cement, and clastic particles (Figure 6d,e). Upon reaching a burial depth of 2000 m, diagenesis progresses into a moderate phase, characterized by low-maturity organic matter and a significant expulsion of organic acids. Consequently, the diagenetic sequence can be summarized as follows: volatile exsolution/devitrification → mechanical compaction → dissolution → carbonate cementation → replacement; based on the mechanisms of diagenetic fluid within the reservoir, the diagenetic evolution sequence of the Huoshiling Formation tuff reservoir can be outlined as follows: mechanical compaction → early carbonate cementation/feldspar dissolution/tuff dissolution → late carbonate precipitation → late carbonate mineral metasomatism.

5.4. Formation of Reservoir Pores

Tuff and feldspar particles can dissolve to create secondary pores, while organic matter releases organic acids during thermal evolution, which facilitates the dissolution of tuff, feldspar chips, and feldspar produced by early devitrification, leading to the formation of secondary dissolution pores [30,81]. Carbonate cements mitigate partial mechanical pressure during diagenesis and provide the material foundation for the development of calcite cements and partial dissolution pores [82]. Notably, significant dissolution of feldspar and carbonate cementation are observed in the tuff reservoir of the Huoshiling Formation within the Dehui fault depression (Figure 5d–f and Figure 6d,e).

Volcanic glass formed during volcanic eruptions is susceptible to transitioning from an unstable state to a stable state, which results in devitrification and the formation of new minerals such as pyrochlore, quartz, and feldspar. This process facilitates the further development of various fissures. Subsequently, feldspar group minerals dissolve under the influence of organic acid fluids, promoting the development of secondary pores [3,83]. Moreover, tuffaceous dehydration shrinkage and the expansion of particle edges are the primary factors contributing to the dissolution of intermediate-acid tuffaceous rocks (Figure 5b–d and Figure 6b), which are typically composed of autogenic quartz, kaolinite, and numerous dissolution intergranular pores. During the diagenetic evolution process, illitization occurs, leading to the obstruction of pore throat connectivity [26]. Additionally, the Huoshiling Formation tuff reservoir exhibits a high overall content of clay minerals, including illite/smectite mixed layers, illite, and chlorite. Both illite and illite/smectite mixed layers are intumescent minerals, and their destruction mechanism primarily involves hydration swelling. The filiform texture of illite is particularly prone to dislodging and blocking pore throats under fluid impact. Furthermore, carbonate cements occupy pores, obstructing reservoir spaces and reducing reservoir permeability [52,84].

Based on a comprehensive analysis of diagenetic features such as dissolution, devitrification, and cementation in tuff reservoirs, a pore evolution model at the microscopic scale was established (Figure 14). The influence of diagenesis leads to the formation of numerous dissolution pores in acidic fluids, primarily from soluble minerals such as tuffaceous and feldspar minerals. During this process, clay minerals, including authigenic quartz, illite/smectite mixed layers, and illite, are present. Subsequently, the clay minerals, particularly the illite/smectite mixed layers, obstruct the pore throats and diminish permeability due to fluid action. These phenomena can be attributed to the moderate-to-high porosity and ultralow permeability of the Huoshiling Formation tuff reservoir in the study area.

6. Conclusions

The tuff reservoirs in the Huoshiling Formation are characterized by intermediate-acidic lithology, with medium–low porosity and ultralow permeability. The pore types are complex, encompassing both primary pores and secondary pores, among which dissolution pores and devitrification pores are the most well developed.

Reservoir diagenesis includes mechanical compaction, cementation (including carbonate, siliceous, and clay–mineral cementation), metasomatism, dissolution, and devitrification. These processes have varying impacts on the reservoir physical properties. The formation of reservoir carbonate cements is related to diagenetic carbonates and the decarboxylation of organic acids. It is influenced by temperature and the fluid environment, and it is closely associated with the fluids generated from the thermal evolution of the source rocks.

The sources of diagenetic fluids are complex. At depths of 2000–2500 m, the fluids are primarily influenced by organic matter thermal evolution and decarboxylation, while at 3000–4000 m, they are jointly affected by deep inorganic CO₂-rich hydrothermal activities. Alkaline fluids promote the precipitation of carbonate minerals such as calcite, filling fractures and partially obstructing reservoir spaces. In contrast, acidic fluids significantly enhance the dissolution of feldspar, tuffaceous, and carbonate minerals, creating extensive secondary pores and improving reservoir properties.

Reservoir pore development is controlled by multiple factors like tuff/feldspar dissolution, devitrification, and clay minerals. Diagenesis and clay minerals dominate pore connectivity and permeability. Hydrocarbon-associated fluids delay compaction, promote feldspar/carbonate dissolution via organic acids for secondary pore development, and preserve devitrification micropores during burial. These fluid-driven processes shape the final pore structure and reservoir properties.