TOC contents and Rock-Eval parameters were effective to characterize hydrocarbon generation potentials of source rocks (He et al., 2018; He et al., 2022). TOC contents of the analyzed mudstones, carbonaceous mudstones, and coal samples in the Yacheng and Lingshui formations range from 0.13 wt.% to 96.51 wt.% (Figure 3A). Rock-Eval data reveal hydrocarbon generation potentials of free hydrocarbon (S₁) and generative hydrocarbon potential (S₂) of the analyzed samples ranging from 0.02 mg HC/g TOC to 154.05 mg HC/g TOC (Figure 3A), which are identified as the main source rocks forming the discovered gas fields. Most of the analyzed samples were characterized as fair to very good source rocks, with carbonaceous mudstones and coal samples being identified as excellent source rocks, indicating great hydrocarbon generation potential for the source rock formations (Figure 3A).

Maximum temperature (T_max) and hydrogen index (I_H) values show close-set distribution, with T_max values ranging from 408 to 482°C and I_H values ranging from 11 mg HC/g TOC to 462 mg HC/g TOC, respectively (Figure 3B). The average T_max reaches 444°C, and the average I_H value is 101 mg HC/g TOC, indicating that source rocks of the Yacheng and Lingshui formations are sufficiently mature to generate dry gas. In the T_max versus I_H plots (Figure 3B), most of the analyzed samples were considered to be Type II₂ and III kerogens, with a smaller number of analyzed samples being characterized as Type II₁ kerogen (Figure 3B).

Vitrinite reflectance (R_o%) was measured to assess thermal maturities of the source rocks in this research. R_o% values of the samples in the Yacheng Formation are >2.0% in the Lingshui Sag, a higher value than that of the samples in the Low Uplift (Table 1). The results indicate that the Yacheng and Lingshui formations in the QDNB are highly matured to over-matured.

Natural gas compositions in the LS25, LS17-2, LS18-1, YL8-1, and YL8-3 gas fields and the GMGS5-W08 hydrate site are dominated by hydrocarbon gas, accounting for 76.38∼99.79% of the total gas volumes (Table 2). Methane (CH₄) contents of the gas fields and the GMGS5-W08 gas hydrate site range from 75.48 to 96.14% and 79.16 to 97.69%, respectively (Table 2). Wet gas (C₂+) contents vary from 0.85 to 8.44% for the gas fields and from 2.10 to 19.55% for the gas hydrate samples (Table 2). Dryness coefficients (C₁/C_1-5 by volume) were in the range of 0.91–0.95 (Table 2). The δ¹³C₁, δ¹³C₂, and δ¹³C₃ values of all gas fields and W08 range from −59.5 to 35.97‰, −28.40 to 22.40‰, and −27.80‰ to −20.20‰, respectively. The δ¹³C values of the CO₂ samples vary from −20.70‰ to −2.70‰ in the gas fields (Table 2).

Previous studies suggested that δ¹³C₁ and δ¹³C₂ threshold values to distinguish thermogenic and microbial origins of CH₄ and C₂H₆ are −55‰ and −42‰, respectively, (Milkov, 2005). Thermogenic gas can be subdivided into coal-type and oil-type gas by δ¹³C₂ and δ¹³C₃ threshold values of −28‰ and −25‰, respectively (Xu and Shen, 1996; Huang et al., 2016; Liu Q. et al., 2019; Lai et al., 2021). A plot of the δ¹³C₁ values versus the δ¹³C₂ values of the analyzed gas samples shows that methane (CH₄) in both the gas hydrates and gas fields was composed of thermo-microbial methane (CH₄) and thermogenic methane (CH₄). Ethanes (C₂H₆) were derived solely from coal-type thermogenic gas with δ¹³C₂ values > −28‰ (Figure 4A).

A notable phenomenon is that the δ¹³C₁ values decreased from −35.97‰ to −59.5‰ along gas migration pathways (from LS25 to W08 or from the Sag Center to the Low Uplift), indicating lighter δ¹³C₁ values due to fraction effects of secondary migration and increased contents of biogenic gas. The C₂+ hydrocarbon gas in the hydrate was mainly derived from the deeply buried coal-type source rocks, and methane (CH₄) often has a mixed thermogenic and microbial origin.

Natural gas hydrate accumulation, which is similar to the conventional oil and gas reservoirs, is often associated with faults, gas chimneys, and diapirism. Faults that fail to reach the gas hydrate stability zone (GHSZ) directly are not efficient pathways for hydrate accumulation that some large-scale faults, however, are often connected with gas chimneys to form efficient fluid migration pathway systems. Normal faults are identified in the study area, which extend from the source rocks to the Quaternary strata or connected with gas chimneys at shallower burial depths (Figure 5A), a characteristic indicating intense fluid migration from deep areas to the seafloor or shallow traps through the fault-chimney pathways. In parallel, enhanced reflections (ERs) were widely developed on the top of or at the flanks of the gas chimneys, faults, and central channel (Figures 5B,C), indicating significant fluid flow in the study area (Cartwright et al., 2007; Horozal et al., 2009; Petersen et al., 2010; Karstens & Berndt, 2015; Kang et al., 2016).

Gas chimneys were developed mainly in the Low Uplift, exhibiting vertical columnar or finger shapes (Figure 5B and Figure 6). The GMGS5 W07, W08, and W09 gas hydrate sites are located directly on the top of three large gas chimneys (Figure 6). Diameters of the gas chimneys vary from 3 to 5 km, and the top of the chimneys terminates at the T1 interface, ∼150 m from the seafloor (Figure 6). Gas chimneys are characterized by mushroom-shaped acoustic blanking zones, with weak internal push-down reflections being interpreted (Figure 6). The high-amplitude reflections at the edge or within the gas chimneys were identified as high-velocity gas hydrate in the soft sediments (Figure 6). Normal faults were interpreted within the gas chimneys, with invisible faults and/or fractures beyond seismic resolution being widely developed in the interior of the gas chimneys. With widely distributed enhanced reflections (ERs) on the top of or at the flanks of the gas chimneys (Figure 6), fluid charging should occur constantly in the study area.

Pressure and temperature, especially overpressure, are important driving forces for sub-surface fluid flow, and understanding their origins and evolution is the key aspect to understand oil and gas migration and accumulation mechanisms.

In the LS25 gas field of the QDNB, two separate overpressure systems were identified (Figure 7, Gan et al., 2019). The lower overpressure system is mainly formed by hydrocarbon generation, with a maximum pressure coefficient (Pc) > 1.8, which extends up to the bottom of the Huangliu Formation. The upper overpressure system is in the second member of the Yinggehai Formation, which was subject to rapid subsidence and disequilibrium compaction of the shallow marine mudstones, with a pressure coefficient (Pc) of c. 1.4. Gas accumulation in the Huangliu Formation (from 1.8 Ma to the present) is relatively later than that in the second member of the Yinggehai overpressured interval, indicating that gas accumulation in the late Huangliu channel system occurred between the formation of the two high-pressure systems since 1.8 Ma, a timing with large-scale hydrocarbon generation and migration. Two thick gas layers in the early and late phases of channel depositions have pressure coefficients of 1.5 and 1.0, respectively. Sandstone intervals deposited early in the channel have a pressure coefficient (Pc) up to 1.8, a characteristic indicating poor gas preservation conditions of upper units of the channel due to the development of intense fractures.

Gas generated source rocks were accumulated in the distinct reservoirs of the channel system by overpressure and buoyancy, with continuous upward migration into the second member of the Yinggehai Formation being hindered by the existence of the upper overpressure system. However, the fluid can be migrated laterally along the porous sandstones in the channels which were proved by the discovery of the LS18 gas field, east of the Central Canyon.

Fluid inclusion can be applied to confirm phases of oil and gas accumulation, which record important information on fluid properties, trapping temperatures, and pressures under in situ conditions. Hydrocarbon-bearing aqueous inclusions and aqueous inclusions were widely developed in the Huangliu Formation in the LS25 and LS17-2 gas fields in the Lingshui Sag (Xu et al., 2014; Gan et al., 2018; He, 2020). Homogenization temperatures (Ths) of the hydrocarbon-bearing aqueous inclusions are >120^oC, ranging from 130 to 160^oC. The Ths of the aqueous inclusions range from 78 to 90.2^oC and from 99.7 to 101.2^oC in wells LS17-2-7 and LS25-3-1, respectively, which is significantly lower than that of the hydrocarbon-bearing aqueous inclusions (He, 2020).

At least three hydrocarbon charging stages were identified in the study area according to the Ths of the hydrocarbon-bearing aqueous inclusions in the Huangliu Formation of the LS17 gas field, corresponding to Ths of 87.2^oC, 110∼120^oC, and 140∼160^oC, respectively (Gan et al., 2019; Table 3). Timing for hydrocarbon charging is estimated to be c. 0.3 Ma at a temperature of 87.2^oC. Some of the Ths of the hydrocarbon-bearing aqueous inclusions are relatively higher than the current strata temperature (approximately 100^oC), indicating the influence of deep thermal fluids/gas in the Central Canyon gas fields in the Lingshui Sag, which were driven by the deep high-pressure/temperature fluid systems.

In addition, hydrocarbon-bearing aqueous inclusions and the coexisting aqueous inclusions were commonly developed in the target formation, indicating multi-stages of fluid migration in the QDNB. The Ths of the coexisting aqueous inclusions range from 78 to 90.2^oC and from 99.7 to 101.2^oC in wells LS17 and LS25 in the Lingshui Sag, matching a trapping time of 2∼0 Ma (Table 3).

The previous study indicates four stages of hydrocarbon and fluid migration stages in the QDNB, with charging times from 17.5 to 13 Ma (Stage I), 10 to 5.5 Ma (Stage II), 4 to 2 Ma (Stage III), and 2 to 0 Ma (Stage VI), respectively (Figure 8) (Liu and Chen, 2011; Huang et al., 2012; Xu et al., 2014; Su et al., 2016a, 2016b; Xu et al., 2017; Gan et al., 2018; Zhong et al., 2019; He, 2020).

Based on the geochemical analysis, paleotemperature/pressure and hydrocarbon charging analyses, and the structural characteristics of the QDNB, preliminary accumulation models for natural gas hydrates were proposed in the Songnan Low Uplift (Figure 9).

Prior to the accumulation processes forming gas hydrates, favorable hydrocarbon generation conditions, efficient migration pathways, and sufficient driving forces are key aspects to form gas hydrates. TOC contents and Rock-Eval results indicate good hydrocarbon generation potential of the Yacheng and Lingshui source rock formations, which are highly matured or over-matured. Effective hydrocarbon migration systems in the study area mainly comprise faults, laterally distributed extended channel sandstones, and gas chimneys. Faults that extend from the source rock intervals up to the Quaternary strata or gas chimneys provide efficient hydrocarbon migration pathways. In the LS25 gas field, late deposition in the channel of the Huangliu Formation has a Pc value of 1.0, and the early deposited intervals in the channel have Pc values of 1.5∼1.8, which are significantly higher. Some of the Pc values in the Yacheng Formation can even reach 2.1 (Zhang et al., 2016), indicating that strong overpressure at depth can provide sufficient impetus for hydrocarbon migration.

With our analysis, high-overmatured thermogenic gas was postulated to be derived from mudstone or coal-bearing strata of the Oligocene Yacheng and Lingshui formations. Gases in the Lingshui Sag could migrate upward through faults. Meanwhile, natural gas was also migrated through laterally distributed sandstone due to the sealing effect of the MTDs (Figure 9). Furthermore, migration of gas was mixed with shallow biogenic gas, thus forming the gas hydrate, such as the cases of the W09 and W08 gas hydrates (Figure 9). Biogenic gas derived from immature or low mature source rocks of the shallow Sanya and Meishan formations can also migrate through faults to form gas hydrates in the study area, such as the W07 gas hydrates (Figure 9). A mixture of biogenic gas in the study area can also be the result of diffusion through interbedded microcracks and pore networks in the shallower strata.