Densification Mechanism and Natural Gas Accumulation Process, Triassic Xujiahe Formation, Hechuan Area, Sichuan Basin, China

Tight sandstone gas is widely distributed in the world’s major petrol-bearing basins. During the past years, we have witnessed a skyrocketing exploration and development of tight gas in China, such as the Sulige Gas field [1]. However, with the years of development, the Sulige gas field is facing the situation of complex stable production [2]. Petroleum geologists are eager to find another sizable tight gas field. The Xujiahe Formation, Sichuan Basin, is considered a very promising area [3]. Nevertheless, the exploration and development of tight gas in the Xujiahe Formation are restricted by an insufficient understanding of the accumulation mechanism [4]. It is vital to reveal the densification mechanism and natural gas accumulation process of the Xujiahe Formation, Sichuan Basin.

For a particular sedimentary basin, the distribution of source rocks [5], migration and accumulation system [6], and charging periods [7] are the main contents of the hydrocarbon accumulation mechanism. Buoyancy plays a minimal role in hydrocarbon migration in tight lithologic gas reservoirs with gentle structures, and the pressure difference between source rock and reservoir is the main driving force for hydrocarbon accumulation [8]. At the early stage of hydrocarbon migration, the pressure difference between source rock and reservoir caused by mudstone compaction is the main driving force for hydrocarbon accumulation; in the late stage of hydrocarbon migration, the pressurization of hydrocarbon generation by source rock is the main driving force of hydrocarbon accumulation [9, 10]. Because of the difference in dynamic mechanisms, conventional petroleum geology theory and methods cannot be directly applied to unconventional resources.

Unlike the tight gas reservoirs in South Texas (North America), South America, or the Middle East, most of the tight gas reservoirs in China are deposited in continental facies or transitional facies [1]). The continental tight gas accumulation mechanism is closely related to reservoir diagenetic evolution. As for gas exploration and development, the relationship between the densification process of the reservoir and the hydrocarbon accumulation process is of vital importance. The sequence of gas charging and reservoir compaction will affect the prediction of sweet spots. The accumulation mode of tight gas can be divided into preformation mode and postformation mode [11]. The preforming mode means reservoir densification first and natural gas accumulation later, and the postforming mode means natural gas accumulation first and reservoir densification later. The preforming mode mainly includes sag center symmetrical distribution mode [12], foreland lateral slope distribution mode [13], and structural slope distribution mode [14]; The postforming mode can be divided into three stages: natural gas accumulation stage of a primary conventional reservoir, reservoir densification stage, and multiple accumulation stage [15]. The relationship between reservoir densification and gas accumulation process determines the accumulation mode and mechanism of tight sandstone gas. It is necessary to combine the study of the formation cause and process of reservoir densification with the analysis of oil and gas accumulation periods.

Determining the hydrocarbon accumulation period and time is one of the critical parts of revealing the hydrocarbon migration accumulation history and establishing the hydrocarbon accumulation model [16, 17]. The analysis method of hydrocarbon accumulation period is to analyze the hydrocarbon accumulation period by studying the tectonic development history [18], trap formation history [19], and hydrocarbon generation and expulsion history [20] of source rock and to determine the hydrocarbon accumulation period indirectly according to the main hydrocarbon generation period of source rock, trap formation period, and reservoir saturation pressure. The fluid inclusion analysis method is widely used to study the hydrocarbon migration and accumulation process [21, 22]. Herein, based on the essential geological characteristics of the Hechuan area in the Sichuan Basin, we will recover the burial history and thermal evolution history. Through thin section identification, mercury injection test, calcium content determination, and other experimental analysis methods, this paper will analyze the reservoir development characteristics of the second Member of the Xujiahe Formation in the Hechuan gas field. We will illustrate the diagenetic characteristics of the second member of the Xujiahe formation, revealing the formation cause of reservoir density. The process of gas accumulation in the Hechuan area of the Sichuan Basin will be expounded.

The paper structure is organized as follows. We describe reservoir characteristics through physical experiments in section 3. The densification mechanism will be discussed in section 4, and in section 5, we will describe the natural gas accumulation period and process.

Sichuan Basin is a secondary tectonic unit of the Yangtze Block. It is a large tectonic sedimentary basin formed after Mesozoic-Cenozoic. The basin can be divided into the west Sichuan depression, the north Sichuan depression, the East Sichuan depression, and the central Sichuan uplift. In the central Sichuan uplift area, the fold is gentle, the sedimentary cap is thin, the stress is weak, and the detachment layer is not developed, forming low and slow structures.

Hechuan gas field is located in the middle of the Sichuan Basin, which belongs to the paleo-uplift oblique gentle tectonic belt in the middle Sichuan basin (Figure 1). As a part of Sichuan Basin, Hechuan gas field has experienced a sedimentary and tectonic evolution history similar to that of the main body of Sichuan Basin and successively deposited Marine strata dominated by carbonate rocks below the Middle Triassic and continental strata dominated by sand and mudstone from the Upper Triassic to Neogene. It has experienced Caledonian, Hercynian, Indosinian, Yanshan, and Himalayan tectonic movements, among which Indosinian, Yanshan, and Himalayan movements have an important influence on the formation of Hechuan gas field. The second Member of the Xujiahe Formation in this area mainly belongs to delta front subfacies deposition, and delta front underwater distributary channel and mouth bar are the central reservoir sand bodies. The microfacies of the underwater distributary channel and mouth bar of the delta front in the Hechuan area are closely symbiotic in space and constitute the skeleton sand body of the delta front (Figure 1).

The outcrop layer of Hechuan gas field is dark purple mudstone of Suining Formation of Upper Jurassic. The upper Jurassic Suining Formation, Middle Shaximiao Formation, Lower Liangshan Formation and Ziliujing Formation, Upper Triassic Xujiahe Formation, and Middle Triassic Leikoupo Formation were successively debunked from top to bottom. The stratigraphic sequence was normal. The Xujiahe Formation in the Hechuan gas field can be divided into six members vertically and from top to bottom: Member 6, Member 5, Member 4, Member 3, Member 2, and Member 1. Members 1, 3, and 5 of the Xujiahe Formation are mainly black shale and mudstone with thin argillaceous siltstone, coal seam, or coal line and are the primary source rocks of the Xujiahe Formation with strong hydrocarbon generation capacity. Members 2, 4, and 6 of the Xujiahe Formation are mainly composed of gray medium-grained, medium-fine-grained lithic arkose, arkose lithic sandstone, and lithic quartz sandstone, which are the main reservoir segments of the Xujiahe Formation. The second Member of the Xujiahe Formation is the best reservoir in the Hechuan gas field.

To analyze the reservoir and diagenetic characteristics of the Xujiahe Formation in the study area, we collected 2,460 data points of porosity and permeability from 19 Wells, obtained 743 thin section analysis data (including sorting debris composition, particle size, sorting, and grinding identification), and 49 thin sections of rock, as well as scanning electron microscope (SEM) and cathode luminescence photographs.

In addition, 35 core samples were obtained from 15 key coring Wells, and the following four types of experiments were conducted on the collected rock: Eighty-four thin sections of rock were observed by optical microscope (OM), 12 typical samples were observed by SEM, 12 typical samples were tested by high-pressure mercury injection, and 35 sandstone samples were analyzed by X-ray diffraction (XRD) of whole rock and clay minerals.

Thirty-five samples were ground into thin slices. The sheets were impregnated with blue epoxy resin to highlight the sandstone pore space, and half of each sheet was stained with alizarin red S and K-ferricyan to identify carbonate cementation. The samples were observed under reflected and transmitted light (polarized light) using a ZEISS Axioskop 40 OM to determine the clastic composition and structure of the reservoir rocks, the type and content of cements, the pore type and face rate (the surface porosity of the section was calculated by a point recording method), and diagenetic characteristics [23].

SEM is a common imaging technique used to study the microstructure and clay mineral characteristics of rocks in tight sandstone reservoirs at micro- and nanoscales [24]

In this paper, 12 samples of 0.5 cm × 1 cm × 0.2 mm were prepared by argon ion polishing and gilding, and then the pore characteristics on micro- and nanoscale were observed by using Quanta-200F SEM under the conditions of an acceleration voltage of 20 kV and emission current of 50–100 Pa. In addition, the minerals, especially the clay minerals, were observed by SEM to identify the clay mineral type [25].

Based on the capillary bundle model, the mercury injection method is used to study the micropore throat structure of sandstone reservoir rock on the micron scale by replacing wetting phase air with nonwetting phase mercury. The samples are dried to constant weight at 105°C before testing and then tested with American corelab CMS300 and American AutoPore 9500 mercury injection instruments under the maximum experimental pressure of 200 MPa. To determine the pore radius, pore throat distribution, sorting coefficient, skew degree, peak state, structural coefficient, and uniformity coefficient of reservoir rock [26].

XRD analysis of whole rock and clay minerals in 35 samples of Xujiahe Formation in the study area was carried out. XRD analysis was carried out by D/max-2500 X-ray diffractometer at room temperature (25°C) to quantitatively analyze the mineral composition in rocks and clay minerals, identify the mineral composition in rocks, and determine the species and content of clay minerals [27].

The inclusion samples were collected from the second Member of the Xujiahe Formation in the Hechuan Area. The lithology is mainly medium-fine-grained sandstone. Fluid inclusion testing, including inclusion microscopy and inclusion homogenization temperature measurement, was carried out. During the experiment, the reservoir core samples are ground into two-sided light slices of inclusions, and detailed petrographic observation was carried out on a polarizing microscope to determine the phase state, type, and distribution characteristics of fluid inclusions. The homogenization temperature of fluid inclusions was measured at 20°C and 30% humidity by electric cooling and heating station.

Braided river delta sandbodies are mainly developed in the second member of Xujiahe Formation in Hechuan area, and the lithology is mainly light gray fine-grained sandstone. The content of quartz in the detrital component is 42%–79%, with an average of 61%. The quartz is mainly monocrystalline, most of which have no wave extinction (Figure 2(a)). The content of feldspar is 13%–22%, with an average of 16%, in the form of strips or long columns, mainly potassium feldspar (Figure 2(b)). The content of rock debris is 7%–29%, with an average of 21%, which is mainly metamorphic debris and sedimentary debris (Figure 2(c) and 2(d)). According to the classification method of Folk [28], the rock type of the second member of Xujiahe Formation in Hechuan area is mainly feldspar lithic sandstone with a small amount of lithic feldspar sandstone (Figure 2(e)). Quartz content is low, but feldspar, debris content is high, and composition maturity is low; The sorting of clastic particles is medium to good, and the grindability is good (Figure 2(a)–2(d)). The intergranular filling content is less than 15%, the clay content is low, and it belongs to the granular support structure with high structural maturity.

After sediment deposition, due to the static pressure of the overlying water body and sedimentary layer, as well as the effect of tectonic deformation stress, the water discharge in the sediment, resulting in the reduction of porosity and volume is called compaction [29]. Compaction generally exists in the whole process of sedimentary diagenesis until metamorphism [30]. In the study area, the compaction is mainly mechanical, and the contact between particles is mainly line-convex contact (Figure 3(a)). Some particles are compressed and bent (Figure 3(b)). Even the quartz particles are compacted and broken and then filled and cemented with silica (Figure 3(c)). Feldspar double grain bending, fracture, and dislocation (Figure 3(d)). A small amount of mica intrudes into the clastic particles to form pseudomatrix (Figure 3(e)). The lamellar and columnar minerals such as mica and feldspar are arranged in an obvious orientation (Figure 3(f)). The content of soft cuttings in Hechuan area is above 3%, and the average face rate is 5.5%. Compaction pore reduction is larger, up to 34%, and may be affected by material composition.

Silica cementation is one of the most common diagenetic phenomena in the study area. Silica cementation occurs mainly in the form of secondary accretion of quartz and a few in the form of autogenous quartz filling pores. In the early diagenetic stage, the compaction is weak, the contact between particles is insufficient, and the free space around the quartz particles is sufficient. Quartz can be enlarged and multiplied to restore its own shape. The enlarged edges are continuous and uniform. In the middle and late diagenesis, a large number of intergranular pores were destroyed by compaction and cement filling, and the remaining intergranular pores or dissolution pores were filled by quartz. The secondary increase of quartz is usually precipitated by the local increase of quartz debris particles, and the increased edge width is not uniform and grows toward the pore direction. This diagenesis phenomenon is most common in the study area (Figure 4(a)). The content of siliceous cement is 0%–11%. At the same time, the silica cements of some samples in the study area were deposited in the intergranular pores in the form of autogenous crystals (Figure 4(b)).

The carbonate content of the second member of Xujiahe Formation in Hechuan area is low, ranging from 0% to 28%, with an average of 1.03%, and the main distribution range is from 1.0% to 2.0%. There are mainly calcite and dolomite and a small amount of iron calcite. The cementation of calcite and iron calcite shows that the sparry calcite is embedded grain. The type of cementation is porous cementation. In addition, it can be seen that calcite cementation embedded crystal cementation (Figure 5(a) and 5(b)). The cementation of dolomite is semiself-shaped, and the dolomite crystals of fine grain grade are dispersed or clustered. The cementation type is mainly inlaid, often associated with calcite (Figure 5(c) and 5(d)).

The clay minerals in the second member of Xujiahe Formation in Hechuan area are mainly illite, chlorite, and kaolinite. There are three forms of existence: the first is the native clay matrix, the second is the clay film formed by the precipitation of clay minerals on the surface of the particles, and the third is the autogenous clay minerals in the intergranular pores. The autogenous illite fills the intergranular pores and feldspar dissolution pores in a fibrous form, and the crystals are large and have developed to the end of hydromuscovite. Under SEM, the granules were distributed in lamellar, fibrous, and hair-like forms (Figure 6(a) and 6(b)). The chlorite cement shows fibrous vertical grain edge growth under the thin sheet, forming the phenomenon of grain coating (Figure 6(c) and 6(d)). The content of chlorite ring-edge cementing is not high, generally 0.2%–2%, and a small number of samples in the study section can be seen. Kaolinite cements are generally filled in the intergranular pores and intragranular pores in the shape of scales, worm-like, and page-like (Figure 6(e) and 6(f)). The size of individual crystals is generally less than 5 µm, and the intergranular pores are developed but very fine.

Dissolution is an important factor of reservoir physical property in this study interval, which leads to the formation of a large number of secondary pores and plays a positive role in improving reservoir physical property. In the study formation, the main development of intragranular pores, mold pores, and intergranular pores is caused by dissolution, showing strong heterogeneity, and the face rate is generally less than 5%. The dissolution pore in the grain is mainly feldspar dissolved along the cleavage plane, and the unstable components in the cuttings (granite cuttings, silty cuttings, extruding cuttings, and argillaceous cuttings) were dissolved, forming the pores with honeycomb and patch distribution. The dissolution residue or autogenous microcrystalline quartz is common in the solution pore, and the face rate is generally 1%–5%. It is mainly developed in medium and medium-fine feldspar lithic sandstone (Figure 7(a) and 7(b)). Intergranular dissolved pores are sometimes difficult to distinguish from semifilled residual intergranular pores, which are mainly manifested in the intergranular dissolved pores formed by the dissolution boundary of partial feldspar and partial debris. The boundary of the pores is irregular and accompanied by the filling of authigenic clay minerals. Authigenic microcrystalline quartz can be seen locally. Face rate is generally 1%–2%. It is commonly found in feldspar lithic sandstone (Figure 7(c) and 7(d)). Casting hole: feldspar and cuttings are dissolved after the retention of granular pores, mostly isolated output, content is generally less than 1%. It is mainly produced in medium—fine feldspar lithic sandstone.

Porosity and permeability are two main parameters reflecting the reservoir performance and seepage condition of a tight sandstone reservoir. The physical properties of 322 core samples from the second Member of the Xujiahe Formation in the Hechuan area show that the porosity is mainly in the range of 4%–12%, with a minimum porosity of 1.14%, the maximum porosity of 16.54%, and the average porosity of 6.95%. The permeability is mainly in the range of 0.01–0.2 mD. The minimum permeability is 0.00432 mD, the maximum is 11.9 mD, and the average permeability is 0.194 mD, a typical low porosity and ultra-low permeability reservoir (Figure 8).

The pore space of rock can be divided into pore and throat. Generally, the larger space surrounded by rock particles is called a pore, while the narrow part connected only between two particles is called the throat. Pores reflect the reservoir capacity of rocks, while the shape and size of throats control the reservoir and permeability of pores. The pore structure of reservoir rock is the geometry, size, distribution, and interconnectivity of pores and throats, and the pore structure is the main factor affecting the permeability of reservoir rock. According to the identification and analysis of thin section, cast, and scanning data of the core well of the Member 2 of the Xujiahe Formation in the Hechuan Gas field, it is considered that the reservoir space types of the Member 2 of the Xujiahe Formation mainly include intergranular pore, intragastric pore, heterobasic pore, and microfracture (Figure 9). Among them, residual intergranular pores and intragranular dissolved pores are important pore types. Their development degree greatly influences on the physical properties of reservoir rocks, which is a crucial factor in evaluating the reservoir conditions of the Xujiahe Formation. Through the observation and analysis of cast thin section, it is concluded that the throat types of the second Member of the Xujiahe Formation in the Heshuan area are mainly sheet throat and tubular throat, and there are a few pores shrinkage or bundle throat. The tubular roar has high porosity and only low permeability. This kind of pore structure belongs to the type of large porosity and narrow throat. The throat width is 0.5–1 m, and the throat is crisscrossed and dendritic. The pore structure of lamellar growl is very narrow, and the throat is very thin. This kind of pore structure is commonly found in linear contact and concave-convex contact sandstone. It is a kind of throat commonly developed in the area and has essential significance for reservoir pore communication.

Mercury injection is a standard method to study the pore structure of the rock. Mercury injection capillary pressure analysis was carried out on 14 core samples from Well HC-1 and Well HC-103 of the Member 2 of the Xujiahe Formation in the Hechuan area. The physical experiment results show that: The threshold pressure of samples with porosity >6% averages 1.46 MPa. The median pressure is 8.26 MPa. The maximum pore throat radius ranged from 0.49 to 9.94 µm, with an average of 1.196 µm. The median radius ranged from 0.08 to 0.41 µm, generally less than 0.25 µm, with an average of 0.143 µm. The maximum mercury intake saturation averaged 90.79%–93.26%. From the core capillary pressure curve, the pore structure of the reservoir is moderately sorted, and the pore structure of the second Member of the Xujiahe Formation in the study area is very similar (Figures 10 and 11).

The spatial and temporal variation of reservoir quality is mainly controlled by the original sedimentary conditions and diagenesis.

The composition and structure of sediments control the development of primary pores. After sediment burial, complex physical and chemical processes control the densification process in the later stage of the reservoir, among which compaction and cementation have an important impact on the failure of reservoir performance, and dissolution has a certain significance for the construction of the reservoir.

Compaction is the main type of diagenesis that increases rock density and decreases primary porosity [31]. Compaction strength is mainly related to rock depth, formation temperature, and detrital mineral composition [32]. Before the late Cretaceous overthrust and napping of Longmen Mountain in western Sichuan and Daba Mountain in northern Sichuan, and the whole Sichuan Basin was uplifted and denudated, the Xujiahe Formation in central Sichuan mainly experienced deep burial in Jurassic and Early Cretaceous after deposition and continued settlement, with an average burial depth of about 4,500 m and strong compaction of sandstone reservoirs [33]. The second member of Xujiahe Formation in the study area is a coal measure clastic rock group with low content of quartz and high content of plastic clastic particles such as feldspar and clastic (Figure 2(e)). The compression resistance is weak. The clasts contain more soft phyllite and argillaceous clasts (Figure 2(c) and 2(d)), reduced compaction resistance. With the increase of burial depth, the compaction effect is significant, and the contact between the detrital particles changes from point contact to line contact and convex contact (Figure 2). Soft debris and argillaceous interstitium fill pores and fractures under the action of compaction, resulting in lower porosity and poorer physical properties of reservoirs. The main manifestations are mica and other plastic debris with bending deformation and uneven wavy extinction (Figure 3(b)); feldspar double grain bending, fracture, and dislocation (Figure 3(d)); a small amount of mica intrudes into the clastic particles to form pseudomatrix (Figure 3(e)). Stratified and columnar minerals such as mica and feldspar are arranged in an obvious directional manner (Figure 3(f)). Linear contact is common among particles, and some particles are Mosaic contact or convex contact. The relationship between sandstone cement content and negative cement porosity (negative cement porosity refers to sandstone sediment porosity before cementation) was compiled for tight sandstone in Hechuan area (Figure 12). It can be seen that the vast majority of samples are cast in the lower left area of the figure, indicating that compaction is the main factor leading to the reduction of sandstone reservoir porosity, as well as the main factor leading to reservoir densification.

Quartz is the most common autogenous siliceous cement in sandstones, usually in the form of secondary marginal extension of clastic quartz grains, or in the form of autogenous quartz crystals in intergranular pores [34, 35]. When there is sufficient free space around the quartz grains, the quartz grains tend to restore the crystal autobody through coaxial accretion, which is characteristic of quartz secondary enlargement in the early diagenetic stages [34]. In the late diagenesis, a large number of intergranular pore volumes were reduced and occupied by cementation, and the secondary increase of quartz was shown as filling residual pores [34, 35]. At this point, the quartz edge will be irregular, and even accretion particles will be inlaid contact [34]. Siliceous cementation occurs in the early diagenetic stage of the second member of Xujiahe Formation in Hechuan area, and siliceous cementation develops in the middle diagenetic stage, filling residual intergranular pores and dissolution pores in the form of quartz margin enlargement. The high content of calcite cement in early diagenetic stage hindered the migration of fluid in pores, resulting in low content of SiO2 released by feldspar dissolution and weak siliceous cement (Figure 13(a)). At the same time, authigenic quartz precipitates are found in secondary dissolution pores formed by feldspar dissolution (Figure 13(b)). This indicates that SiO2 released by feldspar dissolution is one of the sources of siliceous cements. The clay minerals in the sandstone of the second member of Xujiahe Formation in Hechuan area are mainly illite and chlorite, the content of kaolinite and smectite is low, and there is a small amount of illite/montmorillonite mixed layer, the content is generally not more than 20%, indicating that smectite has been transformed into illite in the middle diagenetic stage, so the SiO2 released by the conversion of clay minerals in the sandstone is also the source of siliceous cement. It was found that the contact points of quartz particles were sutures and convex and convex. Under certain temperature and pressure conditions, the contact points of quartz particles could be chemically dissolved and siliceous cements formed (Figure 13(c) and 13(d)). Although the existence of a small amount of early dispersed quartz secondary enlargement may have a certain role in the preservation of the reservoir primary pores [34, 35]. However, siliceous cements occupy pore space, which damages pore connectivity and reduces reservoir physical properties. Some sandstones even because of strong quartz cementation, resulting in increased quartz edge direct contact, pore hours exhausted (Figure 13(e) and 13(f)). The formation of secondary quartz is difficult to dissolve, resulting in lower porosity of the reservoir with higher content of SiO2 cements (Figure 14).

Carbonate cements are the most important types of cements in sandstones of many oil-bearing basins. They are characterized by universal distribution, multistage formation, and genetic diversity [36]. The presence of carbonate cements will have a serious negative impact on the Hechuan reservoir (Figure 15). The carbonate cements occupy the pore space of the reservoir, which reduces the porosity of the sandstone and deteriorates the reservoir quality. During the early burial process, due to the increase of geothermal pressure, the solubility of CO2 increased and the carbonate dissolved. In the middle and late diagenetic period, the temperature and pressure decreased due to stratum uplift, and calcium carbonate precipitated [37, 38]. Therefore, carbonate cements occur mainly in the late period of middle diagenesis and often appear as secondary dissolution pores filled with feldspar and feldspar-rich clasts (Figure 5(b)). According to thin section identification and microscopic determination of carbonate content, the content of carbonate cements in the sandstone of the second member of Xujie Formation in the study area is very low, ranging from 0% to 28%, and the average volume fraction is about 1.03%, mainly consisting of calcite, dolomite, and a small amount of iron calcite. When iron calcite cementation and metasomatism are strong, pseudobasement cementation can be formed, which greatly reduces the porosity (Figure 5(a) and 5(d)).

The common authigenic clay minerals in the study area include illite, chlorite, kaolinite, etc. The formation of authigenic clay minerals is influenced by many factors such as sedimentary and diagenetic environment. Authigenic clay minerals usually fill residual intergranular pores or secondary dissolution pores, resulting in tight reservoir, and have little positive effect on pore development.

Authigenic illite cements are widely seen in Hechuan area. Illite is the main diagenetic clay mineral in the middle diagenetic stage. It can be formed by the alteration of early clay minerals such as smudge and kaolinite. Temperature and pH are important factors in its formation. The smectite clay minerals of autogenetic or clastic sedimentary origin in the early diagenetic stage gradually transformed to illite through interlayer minerals with the increase of burial depth and temperature. The transformation reaction of smectite-illite roughly starts at 60°C–110°C and can even be carried out at a shallow burial depth of 500 m and at a low temperature of 20°C–30°C. This transformation process is carried out gradually from disordered to ordered mixed layer by montmorillonite-illite mixed layer → illite-montmorillonite mixed layer → illite mixed layer and requires the supply of potassium ions. Potassium ions are generally provided by the dissolution of potassium feldspar. Under the condition of a relatively alkaline (neutral) medium, when there is sufficient original content of potassium feldspar and the degree of potassium feldspar alteration to kaolinite is high in the early diagenetic stage, the reaction of kaolinite alteration to illite will also occur. The comprehensive study of clay minerals in the whole region shows that illite cement is mostly produced in the form of a bridge, which seriously blocks pores (Figure 6(a) and 6(b)). Among them, the porosity of illite specially developed strata is decreased, the highest porosity is less than 8%, and the permeability is generally less than 0.1 mD.

Chlorite is usually formed in an alkaline aqueous medium rich in iron (Fe²⁺) or magnesium (Mg²⁺). Iron (Fe2+) or magnesium (Mg2+) generally comes from the following two ways: The provenance of rich rock debris, especially rich volcanic rock debris and iron and magnesium dark minerals, provides iron (Fe²⁺), magnesium (Mg²⁺); when the content of iron and magnesium ions in the pore fluid reaches a certain degree, chlorite will be precipitated in the alkaline pore water. With the increase in temperature, montmorillonite also transforms into chlorite in the alkaline environment rich in iron and magnesium, which is similar to the principle of the transformation of montmorillonite into illite. In addition, kaolinite in the alkaline environment rich in iron and magnesium will also be transformed into chlorite.

In the study area, authigenic chlorite cements generally appear in the form of thin film and intergranular filling (Figure 6(c) and 6(d)). Padded (thin-film) chlorite, whose presence increases the particle radius, greatly reduces the permeability of the reservoir, but on the other hand, it also has the effect of protecting intergranular pores. When chlorite films of a certain thickness (3, 5 µm) are uniformly covered on the surface of the particles, quartz particles lose their nucleation ability, and quartz secondary growth is suppressed. At the same time, the increasing overburden load in the burial diagenetic process is balanced by the increased mechanical strength caused by the continuous growth of chlorite so that the mechanical strength and compaction resistance of the rock are significantly improved not only protecting the primary intergranular pores of sandstone but also preserving the secondary pores formed by the dissolution of skeleton particles (feldspar, etc.). The blades and sheets of chlorite between grains not only occupy the pore space when segmented but also cause the complexity of pore space and greatly reduce the permeability. Although the padded authentically chlorite plays an important role in the retention of intergranular pores, its existence degrades the quality of intergranular pores as an effective storage space. The lamellar chlorite filling increased the density of the reservoir.

Authigenic kaolinite is usually formed by the dissolution of volcanic debris of potassium feldspar and feldspar-rich feldspar under acidic conditions (Figure 6(e) and 6(f)). Its occurrence will lead to the filling of intergranular pores and reduce the reservoir performance. In addition, authigenic kaolinites mostly form page and vermicular aggregates with a large number of intergranular pores, which can be used as effective reservoir space for oil and gas. But such cements rarely develop.

Due to tectonic uplift after subsidence, middle and deep reservoirs were formed in Hechuan area. The diagenetic evolution sequence of tight reservoir in Hechuan area was recovered by combining the sedimentary and burial history, thermal history, and mineral cross-cutting relationship (combined with sedimentary and burial history, thermal history, mineral cross-correlation, and mineral formation temperature), and the intensity of diagenetic action on reservoir in different stages was quantitatively calculated (Figure 16).

The pore types of the sandstones in the study interval are mainly secondary pores, which are dissolved pores in feldspar and debris. At the early stage, the sediments did not break away from the water body, and nodular, berry-globular pyrite, and patchy siderite were formed. The porosity decreased, and primary intergranular pores mainly developed. By the end of the Early Jurassic, the burial depth was up to kilometers, which was A shallow burial environment. The diagenetic stage was early diagenetic stage A, with strong compaction and porosity reduced to about 20%.

At the end of the Middle Jurassic, the depth of burial was up to 3,000 m. Compaction continued and the associated quartz increased. Later, chlorite rim cementation occurred, which retained part of the primary pores. Pressure dissolution began, and early calcite cementation occurred, and the pores decreased to 10%. The pore type was primary intergranular pores.

At the end of Cretaceous, the maximum depth of burial is about 5,000 m, which is A deep burial environment. It is a submember of mesodiagenetic rock with strong pressure dissolution. In the middle Cretaceous period, Ro reached 1.0, and the source rocks generated a large number of hydrocarbons, produced organic acids, and dissolved, increasing the porosity to about 13%. Meanwhile, the second-stage siliceous cementation and the late-stage iron calcite cementation further densified the reservoir, reducing the porosity to less than 10%. Later, due to the Himalayan movement, the stratum was uplifted, resulting in a burial depth gradually less than 3,000 m, which was the B submember of mesodiagenetic rock. The compaction was still strong, and the porosity continued to decrease to about 7% due to siliceous cementation. The pore type is a mixture of dissolution pore, primary intergranular pore, and fracture.

In this study, the microscopic characteristics, types, and homogenization temperature distribution of fluid inclusions in the Xujiahe Formation reservoirs of the Hechuan Gas Field are systematically observed, and the accumulation period of natural gas in the Hechuan Gas field is studied. The natural gas accumulation process will be revealed.

As shown in Figure 17, fluid inclusions are well developed in reservoir sandstone samples of the Xujiahe Formation in the Hechuan Gas field. Most of them are saltwater inclusions and gas inclusions without fluorescence, but also gaseous hydrocarbon inclusions with very weak fluorescence. Inclusions mainly occur in quartz grain fracture and quartz overgrowth boundary to elliptic, angular shape, elongated, negative crystal shape, and irregular polygon, belt, line, isolation, sporadic, or cluster inclusions individual small, generally less than 20 µm, mainly distributed in 4–18 μm, gas-liquid ratio between 7% and 15%.

The formation of fluid inclusions is accompanied by hydrocarbon migration and accumulation, and the formation time of hydrocarbon inclusions can be determined by using the homogenization temperature of saline inclusions contemporated with hydrocarbon inclusions. Due to the fluid inclusions related to the oil and gas in sedimentary basin formation temperature is relatively low, the general inclusions homogenization temperature measurement result cannot temperature correction, so in the same period of brine inclusions, homogenization temperature can represent the capture of the hydrocarbon inclusions in reservoir temperature, combining with the sedimentary burial history and the analysis of palaeogeothermal that would become hydrocarbon accumulation period. The homogenization temperature of saline inclusions is continuous, which indicates that gas charging in Hechuan Gas field may be a continuous process (Figure 18).

Based on the measured results of homogenization temperature of fluid inclusions and combined with the data of sedimentary burial history, thermal evolution history and source rock evolution history in Hechuan Area (Figure 19), the accumulation period of tight sandstone gas in the second Member of Xujiahe Formation in Hechuan Gas Field can be calculated. The natural gas of the second member of the Xujiahe formation in Hechuan gas field may be a process of continuous charging and accumulation, and the main accumulation period is late Jurassic to late cretaceous, that is, 155–70 Ma.

According to the sedimentary and burial history, thermal evolution history, and source rock evolution history of the Hechuan gas field, the geological process of reservoir formation can be divided into two evolutionary stages according to their spatiotemporal configuration. According to the sedimentary and burial history, thermal evolution history, and source rock evolution history of Hechuan gas field, the geological process of accumulation can be divided into two evolutionary stages according to the temporal and spatial morphology.

1. Early burial hydrocarbon generation and expulsion gas charging stage. It is the stage of hydrocarbon expulsion of coal-measure source rocks, and the maturity of organic matter in source rocks increases further, and the amount of hydrocarbon generation increases gradually, and the source rocks show the characteristics of “extensive overlying” hydrocarbon generation. In the early stage of hydrocarbon expulsion, the tectonic evolution of Sichuan Basin was stable, and no fractures and fractures were developed between reservoir sand bodies and source rocks. Due to low porosity and permeability, only the sandstone reservoirs with relatively good porosity and permeability were charged with a small amount of hydrocarbons. In the later period, with the increase of burial depth, the lithology became more compact, and the sandstone reservoirs showed the characteristics of low porosity and low permeability, which was not conducive to the long-distance horizontal migration of oil and gas. The hydrocarbon gas was transported and accumulated nearby to form reservoirs, and the natural gas entered the Second Member of the Xujiahe Formation, forming the source, reservoir, and cap assemblage of lower source and upper reservoir. This period was the main gas filling and accumulation period.

2. Tectonic uplift gas expansion stage. Tectonic uplift and denudation resulted in shallow formation burial depth, lower formation temperature and pressure, a significant increase in the volume of reservoir-forming gas, a significant increase in reservoir permeability (Figure 20), and a more extensive charging range of natural gas, which should be an essential reason for the formation of “large-area, low-abundance, and continuous gas reservoir.” This stage is the finalizing stage of tight sandstone gas.

In this paper, the densification of the source and superimposed tight sandstone gas reservoir of the Upper Triassic Xujiahe Formation in the Sichuan Basin is revealed. The relationship between the densification process of the reservoir and the hydrocarbon accumulation process is clarified. We propose that the tight gas of the Upper Triassic Xujiahe Formation in Hechuan accumulates during the process of densification, which will be helpful and practical for further tight gas exploration and development.

1. The natural gas charging the tight sandstone reservoirs of the Upper Triassic Xujiahe Formation in Hechuan area is a continuous process. The gas accumulation period can be roughly divided into two stages: late Jurassic to Late Cretaceous (155–70 Ma) which is the period of hydrocarbon generation and expulsion of coal measure source rocks; from late cretaceous to present (since 70 Ma) when gas reservoirs were formed by formation uplift and denudation.

2. Compaction of deep buried strata, siliceous cementation due to weak acid conditions, and calcareous precipitation caused by the drop of temperature and pressure of uplift denudation of siliceous cement formation caused by weak acidic environment are the main geological factor for the densification of the Xujiahe Formation reservoir in the Hechuan area. Combining with the analysis of hydrocarbon accumulation period of time, we put forward the natural gas accumulation model of the Xujiahe Formation, Hechuan area: the natural gas accumulation is accompanied by formation densification.

This work is supported by CNPC Scientific Research and Technology Development Project “Whole petroleum system theory and unconventional hydrocarbon accumulation mechanism” (2021DJ0101).

The authors declare that they have no conflicts of interest.

The data that support the findings of this study are available on request from the corresponding author. The data are not publicly available due to privacy restrictions.