The P₃ w Formation contains mainly light gray and brown sandy conglomerate with interbedded brown mudstone. The clasts in the sandy conglomerate are dominated by lithic fragments (>90%; Figure 2A), with <10% quartz and feldspar grains (Figures 2C,D). The lithic fragments comprise mainly mafic–intermediate volcanic rock (Figure 2A), with low (<15%) metamorphic and sedimentary rock contents. The volcanic lithic fragments comprise mainly tuff (Figures 2A,B) with a small amount of basalt and andesite (Figure 2C). Poor sorting and subangular–subrounded clasts (Figure 2A) in the conglomerate demonstrate the low textural maturity of this formation and suggest that it was deposited close to provenance areas.

The reservoir rocks can be divided into oil-, gas-, and water-bearing and dry layers according to the fluid they host. Authigenic laumontite and calcite occur in oil-bearing layers alongside authigenic quartz and kaolinite (Figure 3B, D, E). Mixed-layer illite/smectite was observed in the intergranular pores (Figure 3C). Solid bitumen was also found in residual and secondary pores, indicating hydrocarbon emplacement (Figure 2E). Sparry laumontite and calcite with rare analcime are precipitated in the water-bearing layers (Figures 2C, 3F). Lithic clast surfaces are often coated with a mixed-layer illite/smectite. Dry layers have lower laumontite and calcite contents, and abundant mixed-layer illite/smectite coats the lithic grains and comprises the matrix in intergranular pores.

During diagenesis, the P₃ w Formation experienced mechanical compaction, mineral dissolution, cementation, and mineral replacement. Different diagenetic processes occurred in the different layers, particularly cementation and mineral dissolution. Because the studied strata have generally been buried to depths >4,000 m, all of the sandy conglomerates have undergone strong mechanical compaction. The grains have linear to concave and convex contacts (Figure 2A) and primary pores have been almost entirely destroyed (Figure 2B).

In the oil- and gas-bearing layers, laumontite and calcite occur as the primary cement (Figure 2F). Abundant secondary pores were generated by the extensive dissolution of laumontite and calcite cements and feldspar grains (Figures 2D,E, 3A). Bitumen often remains in the dissolution pores (Figure 2E). Late-stage calcite partially filled the pores formed by dissolution of laumontite and feldspar (Figure 2F, 4A, 5C). Authigenic quartz and vermicular kaolinite aggregates also occur in pores formed by dissolution of laumontite (Figures 3D,E). Leaf-like chlorite aggregates are often precipitated between grains (Figure 3C), and smectite has been gradually replaced by mixed-layer illite/smectite via illitization.

In the water-bearing layers, little dissolution has occurred and a small volume of dissolution porosity is found in only a few samples. Sparry laumontite and calcite form the primary cement (Figures 2B,C). Rare authigenic analcime occurs in several samples (Figure 3F). The dry layers have low zeolite and calcite contents and almost no dissolution has occurred. Smectite experienced extensive illitization, forming abundant mixed-layer illite/smectite (Figure 3C).

In the oil-bearing layers, three generations of calcite can be identified by their dark red, orange, and bright yellow appearance in CL images (Figure 4). The dark red early-stage calcite occurs mainly as primary cement in primary pores and around the lithic grains (Figures 4C, 5A). The orange late-stage calcite I was precipitated mostly in primary pores through the recrystallization of early-stage calcite (Figure 4). The early-stage calcite in the oil- and gas-bearing layers has been partially dissolved then replaced by mixed-layer illite/smectite (Figure 5B). The bright yellow late-stage calcite II was precipitated in unconnected residual intergranular pores and pores formed by the dissolution of laumontite (Figures 4A, 5C,D). In the water-bearing layers, early-stage and late-stage calcite I commonly occurs with a small amount of late-stage calcite II in pores formed by the dissolution of laumontite (Figure 4A).

The authigenic calcite in the P₃ w Formation has a wide range of MnO contents (Figure 6). Calcite in the oil-bearing layers yields MnO contents of 0.05%–5.06% (mean = 1.42%), the MnO contents of calcite in the water-bearing layers fall into two groups (0–1% and 2%–4%), and the MnO contents of calcite in the oil-bearing layers fall into three groups (<1.5%, 2.5%–4%, and 4%–6%; Figure 6). The FeO contents of calcite are generally <0.20%.

In situ LA–ICP–MS analyses were used to measure the REE contents of the calcite in the P₃ w Formation and yielded light REE (LREE)/heavy REE (HREE) ratios of 2.20–7.80 (mean = 5.17), showing LREE enrichment. The calcite yields Y/Ho ratios of 19.10–28.43 (mean = 21.77), negative Ce anomalies (δCe = 0.26–0.61; mean = 0.33), and positive Eu anomalies (δEu = 1.04–1.74; mean = 1.26).

The calcite in layers with different hydrocarbon charging intensities have different carbon isotopic compositions. The calcite in the oil-bearing layers is depleted in ¹³C, with δ¹³C values of −25.7‰ to −6.2‰ (mean = −14.1‰). The δ¹³C values of calcite in the water-bearing layers is higher, at −12.4‰ to +1.2‰ (mean = −7.1‰). There are no clear differences in the oxygen isotopic compositions of the calcite among the different layers. The calcite in the oil-bearing layers yields δ¹⁸O values of −20.9‰ to −13.6‰ (mean = −15.5‰), and the calcite in the water-bearing layers yields δ¹⁸O values of −18.0‰ to −11.5‰ (mean = −15.6‰; Table 2).

Previous studies have suggested that the crude oil hosted by the P₃ w Formation may have been biodegraded near the fault zone (Pan et al., 2021); therefore, we analyzed crude oil biomarkers from the sampled layers. The total ion chromatogram from the crude oil from the study area shows a relatively complete sequence of n-alkanes, and typical biodegradation markers (e.g., 25-norhopanes) were not identified in the mass spectrum (Figure 7). Limited samples possibly underwent mild biodegradation as the existence of UCM (unidentified compound materials, Figure 7).

The redox sensitive element (e.g., Mn and Fe) contents of calcite are closely related to the fluid from which it precipitated and can potentially indicate the geologic fluids present during diagenesis (Gregg and Shelton, 1989; Aggarwal et al., 2004; Liu et al., 2019). Previous studies have shown that hydrocarbon-bearing fluids in the Junggar Basin are enriched in Mn (Cao et al., 2007, 2020). In addition, in rocks containing red layers, the thermochemical oxidation of hydrocarbons by high-valence Mn^3+/4+ ions also releases Mn²⁺ ions into the pore water (Hu et al., 2018; Kang et al., 2021). Therefore, the MnO contents in calcite most likely reflect the intensity of hydrocarbon charging and subsequent hydrocarbon–water–rock interactions. Furthermore, the alteration of volcanic material may also lead to a slight increase in the Mn and Fe contents of pore water and a slight increase in its pH (Xi et al., 2015; Xie et al., 2020). In addition to elemental composition, the carbon isotopic compositions of calcite are also widely used to trace the sources of geological fluids, as calcite precipitated from meteoric water and calcite affected by ¹³C-depleted organic carbon from hydrocarbons will have different carbon isotopic compositions (e.g., Irwin et al., 1977; Surdam et al., 1993; Seewald, 2003; Hu et al., 2018). The MnO contents in the three calcite stages and the lower δ¹³C values of calcite in the hydrocarbon-bearing layers indicate that the diagenetic fluids were altered by hydrocarbon-bearing fluids during diagenesis (Irwin et al., 1977; Seewald, 2003; Cao et al., 2007; Zhi et al., 2022).

In the oil- and gas-bearing layers, some of the late-stage I calcite formed via recrystallization of early-stage calcite, and both of these generations of calcite are found mainly in the primary pores (Figures 4B,C). In contrast, the late-stage calcite II occurs mainly in secondary pores (Figure 5C), indicating that this calcite was precipitated after large-scale dissolution. As the MnO increase due to the alteration of volcanic material is limited, the higher MnO content of the late-stage calcite II reflects a change in the diagenetic fluid caused by hydrocarbon emplacement during diagenesis (Figure 6; Cao et al., 2007; Hu et al., 2018). The calcite in the oil- and gas-bearing layers yield a wide range of δ¹³C values (−25.7‰ to −6.2‰), indicating that the source of the C in the calcite changed gradually during diagenesis from inorganic CO₂ in meteoric water to organic derived CO₂ from hydrocarbons (Irwin et al., 1977; Seewald, 2003). The early-stage calcite with low MnO contents (<1.5%) and high δ¹³C and δ¹⁸O values (δ¹³C > −10.0‰; δ¹⁸O > −15.0‰) was precipitated in the oil- and gas-bearing layers (Figures 6, 8), and the higher δ¹⁸O values were inherited from meteoric water (Figure 8; Swart, 2015).

The first stage of hydrocarbon emplacement occurred during the Middle Jurassic (Wang, 2016; Pan et al., 2021); however little hydrocarbon charging occurred during this stage (Zhi et al., 2022). Organic acids and organic derived CO₂ in the hydrocarbon-bearing fluids led to a slight decrease in the pH and an increase in the Mn contents of the pore water (Cao et al., 2007; Hu et al., 2018) and provided organic carbon for the precipitation of the late-stage calcite (Seewald, 2003; Wu et al., 2017). This calcite generation is characterized by higher MnO contents (2.5%–4%) and slightly lower δ¹³C values (−15.0‰ to −10.0‰). During the Early Cretaceous, a second, large-scale hydrocarbon charge further altered the diagenetic fluids, resulting in a series of hydrocarbon–water–rock interactions (Seewald, 2003; Swart, 2015; Kang et al., 2019; Sun et al., 2021). Organic acids and organic derived CO₂ dissolved in hydrocarbon-bearing fluids further reduced the pH of the pore water, and the decarboxylation of organic acids in moderately hot rocks also produced CO₂ (Irwin et al., 1977). Intense hydrocarbon charging led to further enrichment of the pore water in Mn and organic derived ¹³C-depleted CO₂ (Cao et al., 2007; Zhi et al., 2022). Thermochemical oxidation of the hydrocarbons also likely occurred in some layers, forming organic acid intermediate, and even more ¹³C-depleted CO₂ than decarboxylation derived CO₂ (Seewald, 2003; Hu et al., 2018). The late-stage calcite that formed in this environment has high MnO contents (4%–6%) and low δ¹³C values (less than −15.0‰; Figures 6, 8).

The water-bearing layers contain mainly early-stage and late-stage I calcite (Figure 5A), with a little late-stage II calcite precipitated in the pores formed during dissolution of laumontite (Figure 4A). The late-stage calcite in the water-bearing layers has low MnO contents (<1.0%; Figure 6), and their δ¹³C values are generally lighter than −10.0‰ (Figure 8). This indicates that the diagenetic fluids in the water-bearing layers were not affected by large-scale hydrocarbon emplacement and inherited their compositions mainly from paleo-meteoric water (Zhi et al., 2022). However, in individual layers (e.g., at a depth of 3,629.5–3,642.0 m in well K206), the pore fluids might have been affected by water-soluble organic acids and CO₂ derived from hydrocarbons (Aggarwal et al., 2004; Minor et al., 2019). The late-stage calcite in these layers has high MnO contents (2.44%–3.82%) and negative δ¹³C values (−12.4‰ to −10.7‰).

In the P₃ w Formation, laumontite cement is abundant and widespread (Figure 2A) and is related to the alteration of volcanic lithic fragments in the rocks (Hay, 1966; Zhu et al., 2012). Laumontite can be observed in the water-, oil-, and gas-bearing layers (Figures 2C,E), indicating that the alteration of volcanic material was widespread. The moderately high MnO and FeO contents of early-stage calcite show that Mn²⁺ and Fe²⁺ ions were released into the pore water from the volcanic material during eodiagenesis, and the process slightly increased the pH of the pore water and promoted the precipitation of the early-stage calcite (Figure 6; Gieskes and Lawrence, 1981; Elderfield and Gieskes, 1982; Zhu et al., 2012).

Overall, the presence of calcite with low MnO contents (<1.5%) and moderately high δ¹³C values (greater than −10.0‰) shows that the early diagenetic fluids in the study area were affected by meteoric water (Irwin et al., 1977; Aggarwal et al., 2004). The wide range of MnO contents (2.5%–6%) and lower δ¹³C values (less than −10.0‰) of the authigenic calcite in the hydrocarbon-bearing layers indicate that during subsequent hydrocarbon charging the diagenetic fluid was altered by hydrocarbon-bearing fluids (Figures 6, 8). Individual water-bearing layers were also affected by water-soluble carboxylic acids and organic-matter derived CO₂. Moreover, in siliciclastic strata where oxidizing minerals occur, hydrocarbon–water–rock interactions promoted by high temperatures (>90°C) or microorganisms may cause hydrocarbon oxidation and generate organic acids and ¹³C-depleted CO₂ (Surdam et al., 1993; Seewald, 2003; Hu et al., 2018; Wan et al., 2021). CO₂ generated via this process can lead to further precipitation of authigenic calcite with δ¹³C values of less than −25‰ under alkaline conditions (Figure 8; Irwin et al., 1977; Hu et al., 2018).

Authigenic minerals are widespread in the P₃ w Formation and characterized by multiple phases of precipitation (Figure 2). Multiple generations of authigenic minerals are products of changing geological fluids and complex fluid–rock interactions (Xie et al., 2020; Sun et al., 2021; Zhi et al., 2022). In the oil- and gas-bearing layers, hydrocarbon charging changed the diagenetic sequence, leading to the dissolution and re-precipitation of various secondary minerals (Walkden and Berry, 1984; Swart, 2015; Wu et al., 2017; Kang et al., 2019). During the early diagenetic stage, the pore water was transferred from the interbedded plastic mudstone layers to the clast-supported sandy conglomerate layers. As the burial depth increased, the temperature rose gradually, and the volcanic material experienced extensive alteration leading to the precipitation of authigenic laumontite as primary cement (Zhu et al., 2012). This process led to an increase in the pH of the pore water (Elderfield and Gieskes, 1982; Sample et al., 2017) and inorganic CO₂ and terrestrial Ca²⁺ concentrated gradually in the pore water, leading to precipitation of the early-stage calcite in residual intergranular pores (Figures 2B, 4C). There was a hiatus after the deposition of the P₃ w Formation before the deposition of the overlying Early Triassic Baikouquan Formation, forming the Permian–Triassic unconformity around the sag (Figure 1B). This meant that the P₃ w formation was affected by leaching by meteoric water during diagenesis (Yuan et al., 2017). The neutral to acidic meteoric water changed the properties of the pore water and caused partial recrystallization of the early-stage calcite.

Limited hydrocarbon emplacement occurred during the Middle Jurassic (Figure 9; Pan et al., 2021). The acidic hydrocarbon-bearing fluids promoted the alteration of volcanic material and led to precipitation of the late-stage I calcite (Figure 5B). The second, large-scale hydrocarbon charging event during the Early Cretaceous introduced organic acids and organic derived CO₂ (Figure 9; Surdam et al., 1984, Surdam et al., 1989; Zhi et al., 2022), which further reduced the pH of the pore water, leading to extensive dissolution of laumontite and early-stage calcite (Figure 2E). These secondary pores became interconnected along cleavage fractures (Figure 3E) and retained small amounts of solid bitumen (Figure 2E). When the Ca²⁺, Al³⁺, and Si⁴⁺ ions released by the dissolution of laumontite and early-stage calcite reached saturation, secondary quartz and kaolinite precipitated in the pores (Figures 3D,E). Dissolution also buffered the pH of the pore water (Surdam et al., 1984, 1993), leading to the precipitation of late-stage calcite II in dissolution and residual intergranular pores (Figures 5C,D).

In the water-bearing and dry layers, alteration of volcanic lithic fragments and the pore water composition led to precipitation of laumontite and early-stage calcite during eodiagenesis. More sparry laumontite and calcite cements occur in the water-bearing layers than in the dry layers, as water aids ion transport (Figure 2C). Leaching by meteoric water also promoted recrystallization of early-stage calcite (Figures 2B, 5A). During mesodiagenesis, most minerals (including the laumontite cement) remained stable in the water-bearing layers, except for smectite, which was illitized.

The late-stage calcite in the study area was affected by organic acids dissolved in the hydrocarbon-bearing fluids (Figure 8). A small amount of organic acid is dissolved in hydrocarbon-bearing fluids when they are extracted from source rocks (Irwin et al., 1977; Franks and Forester, 1984). The δ¹³C values of the authigenic calcite in the oil- and gas-bearing layers of the P₃ w Formation are lighter than those of calcite in typical source rocks (Figure 10), suggesting that insufficient organic acid was supplied from the source rocks to generate the ¹³C-depleted late-stage calcite. Assuming that the maximum organic acid content in the in hydrocarbon-bearing fluids that migrated into the reservoirs in the P₃ w Formation from the source rock was 10,000 mg L⁻¹ (Shock, 1994), and that the porosity of the reservoir rock was 15% when the reservoir was charged by oil and gas, the organic acid in one cubic meter of rock could have generated 1,100 g of CO₂ through thermal decarboxylation. However, the calcite content of the formation is ∼6%, which would have required 71,280 g of CO₂ per cubic meter of rock. As stable carbon isotopic fractionation is mass balanced, we can assume δ¹³C values of −2‰ and −25‰ for the early-stage calcite and the calcite related to thermal decarboxylation of organic acids, respectively (Irwin et al., 1977; Hu et al., 2018). Using the carbon isotopic compositions of the calcite in the P₃ w Formation, we can estimate that CO₂ from the thermal decarboxylation of organic acids accounts for 18%–100% (mean = 53%) of the calcite in the oil- and gas-bearing layers. In the water-bearing layers, this proportion reduces to 0%–45% (mean = 23%). Using these proportions, we still estimate that the authigenic calcite in one cubic meter of rock in the hydrocarbon- and water-bearing layers would have required 37,779 and 16,395 g, respectively, of CO₂ from the decarboxylation of organic acids. Both values are far higher than the 1,100 g supplied by the source rocks, which suggests that the supply of organic acids from source rocks was insufficient, and that additional organic acids were most likely produced in the reservoir rocks via interactions between organic hydrocarbons and inorganic minerals.

It has been suggested that hydrocarbons reacting with SO₄ ²⁻ or high-valance Fe and Mn oxides, induced by microorganisms or high temperatures, to generate organic acids after hydrocarbons are emplaced in a reservoir (Surdam et al., 1993; Seewald, 2003). The low δ¹³C values (as low as −25.7‰) of the late-stage calcite confirm that hydrocarbon oxidation occurred in the P₃ w reservoirs. The oxidation consisted of a series of intermediary reactions involving alkene, alcohol, ketone, and carboxylic acid, ultimately producing short-chained saturated hydrocarbons and CO₂ (Figure 11). The mineral oxidants provided a strong driving force for the reaction to proceed by consuming H₂ that would otherwise accumulate in pore fluids (Seewald, 2001). The rapid kinetics of the reactions that consume the alkene, alcohol, and ketone intermediaries resulted in very low concentrations of these species in solution during n-alkane oxidation, whereas the sluggish kinetics of the destruction of carboxylic acids by decarboxylation and oxidation would have allowed their certain concentrations in aqueous fluids (Seewald, 2001, 2003). The carboxylic acids most likely provided the excess organic derived CO₂ required to precipitate the calcite in the P₃ w Formation.

The homogenization temperatures of fluid inclusions in the P₃ w Formation indicate that they formed at temperatures of >80°C during hydrocarbon charging (Wang, 2016); such temperatures are not conducive to the metabolism and survival of bacteria (Peters et al., 2005). Moreover, the crude oil in the P₃ w Formation contains a relatively complete n-alkane sequence, with no significant increase in typical microbial degradation biomarkers (e.g., 25-norhopanes; Figure 7), providing further evidence against the possibility that the organic acids were generated by microbial activity. In addition, no authigenic pyrite or H₂S were found in the samples, ruling out the possibility of thermochemical sulfate reduction (Krouse et al., 1988). Thus, some of the organic acids in the P₃ w Formation were generated via the oxidation of hydrocarbons by high-valence Fe and Mn oxides at temperatures of >80°C.

The REE characteristics of the calcite also support an oxidized diagenetic environment during burial of the P₃ w Formation. The calcite in this formation is enriched in LREEs relative to HREEs (Figure 12). Previous studies have shown that when crude oil or other organic matter is degraded, more LREEs than HREEs are released from hydrocarbon-bearing fluids into the pore water (Haley et al., 2004; Himmler et al., 2010). This process likely caused the LREE enrichment in the authigenic calcite. The calcite also yields negative Ce and positive Eu anomalies (Figure 12), indicating an oxidizing environment (Zhao, 1997). The calcite also yields high Y/Ho ratios (19.10–28.43). Bau and Dulski (1999) argued that Fe and Mn oxides and hydroxides preferentially adsorb Ho relative to Y in an oxidizing environment, thus increasing the Y/Ho ratios of diagenetic fluids. In addition, interbedded brown mudstone layers are found in the P₃ w Formation, and hematite also exists in some conglomerate layers. These indicate an oxidizing diagenetic environment in this formation. It implies that organic acids were generated by the oxidation of long-chain hydrocarbons by oxidizing meterials when hydrocarbons migrated into reservoirs in the P₃ w Formation.

Owing to the different volumes of meteoric water and hydrocarbon-bearing fluids, different fluid–rock interactions occurred in the hydrocarbon-bearing, water-bearing, and dry layers, which altered the diagenetic processes and affected reservoir quality. During the early stage of diagenesis, the P₃ w Formation was only shallowly buried, leading to weak compaction. Authigenic laumontite and early-stage calcite precipitated as primary cements, partially resisting compaction by the overlying strata (Figure 13A; Liu et al., 2019). As burial depth increased, increased compaction, the recrystallization of the early-stage calcite, and clay mineral precipitation reduced the residual primary porosity. During the depositional hiatus at the end of the Permian, the CO₂ supply from meteoric water caused slight dissolution of soluble components, including the laumontite cement and feldspar debris at the top of the formation, and these dissolution pores were filled mostly by recrystallized calcite. Thus, only limited secondary porosity formed close to the top of this formation owing to leaching by meteoric water (Figures 2, 13B).

During mesodiagenesis, a limited phase of hydrocarbon emplacement during the Middle Jurassic played an important role in alteration of the P₃ w reservoirs. Owing to charging by acid hydrocarbon bearing fluids derived from the source rocks, the pH of the pore water in the reservoir decreased, preventing the precipitation of laumontite and calcite or promoting their dissolution and forming a small amount of secondary porosity. This period of hydrocarbon emplacement interrupted the decline in reservoir porosity caused by mechanical compaction, providing pore space for subsequent hydrocarbon accumulation and laying the foundation for further reservoir alteration (Figure 13C). After intense hydrocarbon charging during the Early Cretaceous, the high-temperature oxidation of hydrocarbons produced organic acids that added to those initially derived from the source rocks. The decrease in the pH of the pore fluids caused extensive dissolution of laumontite and early-stage calcite and produced abundant secondary pores. Overall, the two periods of hydrocarbon emplacement considerably increased the reservoir porosity and contributed to the formation of the P₃ w reservoir beds (Figure 11D).