Lingshui 36-1 gas field is located on the Lingshui Low Uplift in the Qiongdongnan Basin, at water depth ranging from 1 500 m to 1 700 m. The primary target, namely the Quaternary Ledong Formation in lithological traps, is sandstone deposits in large deep-water submarine fans buried at 170 m to 300 m. Gas reservoirs are distributed northeast-southwest along the submarine fans. Each fan represents an individual gas reservoir ranging from 12 km² to 155 km². They are laterally zoned and vertically stacked, and with high gas saturation. The gas reservoirs are predominantly full of water or supported by edge water. According to well data, eight gas groups have been identified: L₂I, L₂II, L₃I, L₃II, L₃III, L₃IV, L₃V, and L₃VI on a large scale (Fig. 2).

Specifically, two reservoir intervals were found in Lingshui 36-1 gas field: L2 and L3. The reservoirs are primarily siltstone and agillaceous sandstone, and some are fine sandstone. Affected by shallow burial and weak consolidation, the reservoirs exhibit high porosity and permeability. Borehole cores and sidewall cores show porosity ranging from 26.1% to 48.0%, and 38.9% on average, and permeability of (31.4-3 636.5)×10⁻³ μm², and 983.7×10⁻³ μm² on average, indicating high-porosity, medium-to-high permeability reservoirs.

According to well data, the difference in reservoir properties is mainly controlled by the evolutionary stages of the submarine fans and the depositional microfacies. Specifically, the sandstone depositing during the prosperous stage of the submarine fans is thicker and coarser, and the reservoir quality is better. In contrast, the sandstone depositing during the waning stage of the submarine fans is thinner and finer, and contains more mud, resulting in poorer reservoir quality. For example, Well LS36-1a encountered thick and coarse sandstone with low mud content, which belongs to the third member of the Ledong Formation depositing during the prosperous stage of the submarine fans. The distributary channel sandstone is fine to silty, with average porosity of 34.27%, mud content of 12.55% and good permeability. L₂I and L₂II are sheet sand depositing during the waning stage of the submarine fans. The sand bodies are smaller and thinner, only 2 m to 3 m thick each. The lithology is primarily argillaceous siltstone. The reservoir porosity is averaged 37.8%, the mud content is as high as 25.5%, and the permeability is poorer (Fig. 3).

Two primary gas groups were tested. L₃I was perforated 13.1 m, and obtained natural gas at 23.04×10⁴ m³/d, and the open flow is expected to 1 000×10⁴ m³/d. L₃II was perforated 10.3 m, and obtained natural gas at 28.94×10⁴ m³/d, and the open flow is expected to be 96.00×10⁴ m³/d. The two gas groups have commercial production capacity, and the proven gas reserves more than 1 000×10⁸ m³ (Fig. 4).

The natural gas in Lingshui 36-1 gas field is sourced from thermogenic and biogenic processes. Thermogenic gas is the result of thermal degradation of deep source rocks, while biogenic gas is originated from bacterial degradation of organic matter in shallow strata. Gas origin can be distinguished by analyzing methane carbon isotopic composition (δ¹³C₁) and dryness coefficient (C₁/C_1-5). Biogenic gas is distributed in regions with smaller δ¹³C₁ values and higher dryness coefficients, thermogenic pyrolytic gas is distributed in regions with larger δ¹³C₁ values and lower dryness coefficients, and thermal cracking gas is between the two ^[15-16] (Fig. 5). Gas analysis indicates that methane is the primary component in different wells across Lingshui 36-1 gas field. The dryness coefficient ranges from 0.997 7 to 1.000 0, indicating dry gas. However, there are significant variations in the methane carbon isotopes, which may be caused by the differences in gas sources and migration conditions. Two wells were drilled in the western block of Lingshui 36-1 gas field. δ¹³C₁ is -66.7‰ in Well LS36-1a and -55.2‰ in Well LS36-1g, suggesting primarily biogenic gas. Multiple wells drilled in the central and eastern blocks found δ¹³C₁ ranging from -48.9‰ to -43.8‰, indicating thermogenic gas with a little biogenic gas. Furthermore, δ¹³C₁ became lighter from structural low position (LS36-1d) to structural high position (LS36-1b/c), namely, lighter δ¹³C₁ observed in structural high position (Table 2), indicating thermogenic gas migrates from structural low position to structural high position.

The ultra-deepwater and ultra-shallow strata are shallow, geologically young, and weakly consolidated, and both sandstone and mudstone have high porosity. When sandstone is saturated with water, the acoustic impedance between sandstone and mudstone is small, making it difficult to distinguish the two on seismic profiles. However, when sandstone contains gas, its P-wave velocity and density decrease rapidly, resulting in significant reduction in acoustic impedance, and a negative reflection coefficient on overlying mudstone, showing strong reflections in seismic data. When sandstone contains hydrates, its P-wave velocity increases significantly, making acoustic impedance raise, and a positive reflection coefficient on overlying mudstone, enhancing seismic reflections. Therefore, seismic reflections can qualitatively assess the gas-bearing potential of sandstone in ultra-deepwater and ultra-shallow formations. Additionally, when gas saturates sandstone, the formation often displays low V_P/V_S ratio, Class III-IV AVO anomaly and high-frequency attenuation. These properties allow for using petrophysical parameters and seismic inversion to help gas detection and prediction ^{[17⇓⇓-20]}. For instance in Well LS36-1c, the gas layers are characterized by low density, low P-wave velocity, low acoustic impedance, and low V_P/V_S ratio, while the hydrate-bearing layers show higher density, higher P-wave velocity, higher acoustic impedance, and higher V_P/V_S ratio (Fig. 6). In seismic data with positive polarity, the gas layers are reflected by low-frequency and strong-amplitude troughs, while the hydrate- bearing layers by low-frequency and strong amplitude peaks (Fig. 7a). In seismic inversion data, the gas layers exhibit low acoustic impedance and low V_P/V_S ratio, while the hydrate-bearing layers correspond to high acoustic impedance and high V_P/V_S ratio (Fig. 7b, 7c).

The gas-bearing layers generally exhibit high resistivity (greater than 2 Ω·m), similar to the gas layers in middle reservoirs. Typical ultra-deepwater and ultra-shallow gas layers display logging responses characterized by high resistivity, low density, high AC, and low CN porosity (Figs. 3 and 6). Due to the increased gas saturation, the density of the gas layers decreases, and the CN porosity significantly decreases due to the “excavation effect”. The intersection of CN porosity and density is a key indicator for identifying ultra-deepwater and ultra-shallow gas layers. There is a positive correlation between resistivity and gas saturation in the study area, showing gas layers with high saturation exhibit high resistivity. In some wells, the highest resistivity reaches 91 Ω·m, corresponding to gas saturation of 82.2%. However, some gas layers exhibit resistivity below 2 Ω·m, with weak or no intersection between CN porosity and density. Pressure sampling confirmed that the lowest resistivity is 1.5 Ω·m, and the lowest gas saturation is approximately 20%. Previous studies suggested that low resistivity may be caused by factors such as high bound water content, low structural relief, near the gas-water contact, strong cation exchange conductivity, and drilling mud invasion ^[21-22]. In the study area, the fine reservoir has a higher clay content. The clay minerals exhibit strong adsorption, resulting in higher bound water content under weak compaction, and contributing to the low-resistivity gas layers. Additionally, some gas layers are located near the gas-water contact where lower gas saturation also contributes to low resistivity. Comprehensive analysis suggests that the gas layers have high bound water content and near the gas-water contact is the first factor causing low resistivity.

Deep thermogenetic gas and shallow biogenic gas are two sources. Thermogenetic gas is the result of thermal degradation of organic matter in deep source rocks, which is primarily hydrocarbon gas. The volume of thermogenetic gas depends on the type, abundance and thermal maturity of organic matter, and the volume of source rock. Biogenic gas is mainly methane generated from the degradation of organic matter in shallow source rocks under the metabolic activities of various microbial populations. The volume of biogenic gas depends on the number of methane bacteria, the abundance of organic matter, the volume of source rock, and the temperature suitable for methane bacteria activity.

The deepwater source rocks are the Oligocene Yacheng Formation of marine-to-continental transition facies and the Miocene Lingshui Formation of marine facies. The TOC ranges from 0.4% to 2.1%, and averaged 0.86%. The organic matter is types II₂-III. The gas generation potential is up to 55×10¹² m³. The temperature suitable for methane bacteria activity is between 30 °C and 70 °C, which takes place in the marine mudstone in the Lingshui Formation, the Yinggehai Formation and the Huangliu Formation. Unfortunately, no suitable samples are available for biogenic gas simulation experiments. According to the analysis of organic carbon and pyrolytic data from shallow mudstone samples in the deepwater area of the Lingshui sag, the TOC is 0.3% to 1.8%, and averaged 0.58%, and the organic matter is of type III. Using the biogenic gas production model of the Miocene-Quaternary mudstone in the adjacent Yinggehai Basin ^[23], the simulated biogenic gas production in the deepwater area of the Qiongdongnan Basin is approximately 7×10¹² m³.

Additionally, the stable hydrate zone is favorable for long-term gas accumulation and preservation. Traditionally, it is believed that only a small portion of gas generated by source rocks accumulates in the traps on the migration path, but most gas eventually escapes into the air. This idea is only applicable for shallow-water accumulation, but not for deepwater gas which is different in migration and accumulation. The central depression of the Qiongdongnan Basin has gradually entered a deepwater environment since the Neogene, and the ultra-shallow layers have suitable conditions for hydrate development. Gas migrating into the stable layers is stabilized in the form of hydrates, especially in the ultra-deepwater area where the stable hydrate zone remains long, helping prevent gas escaping into the atmosphere.

Ultra-deepwater and ultra-shallow reservoirs are far from source rocks. The development of big gas fields depends on the presence of high-quality reservoirs. Ultra-deepwater and ultra-shallow formations are almost mudstone, but gravity flow sandstone transporting a long distance is primary reservoir, generally in gravity flow channels and submarine fans. Enclosed by mudstone, the deepwater gravity flow sandstone may form into lithologic and structural-lithological traps if effective seals are available.

In the Qiongdongnan Basin, two types of submarine fans were developed in the Quaternary Ledong Formation deepwater area: Hainan Island-sourced slope fan and Vietnam-sourced large channelized submarine fan. These are the most important reservoir types in the ultra-deepwater and ultra-shallow formations in the Qiongdongnan Basin. The Hainan Island-sourced slope fans are predominantly located in the northern continental slope, influenced by linear sources and slope geomorphology. They are scattered with NW-SE elongated, tongue-shaped, or lobe-shaped features. After the Late Miocene, source supply from the Hainan Island became insufficient, resulting in smaller, thinner slope fans with common physical properties. The large Vietnam- sourced channelized submarine fans are developed in the continental uplift, controlled by the source from the Vietnam Kontum uplift and restrictive ancient landforms. They are in a SW-NE elongated shape. Since the Late Miocene, the Qiongdongnan Basin has developed a restrictive paleogeomorphology high in the north and the south and low in the center, followed by an axial sedimentary system ^{[24⇓⇓-27]}. Since the Quaternary, as the global sea level declined rapidly, water systems such as the Thu Bon River in the Kontum Uplift sent a big volume of sediments into the basin through continental canyons, where the sediments accumulated into large channelized submarine fans on the top of the restrictive paleogeomorphology in the western deepwater area ^[14]. The Quaternary submarine fans have the longest axial length of approximately 150 km, and the largest width of up to 40 km, and cover over 3 000 km². They are high-quality reservoirs. Based on the fourth-order sequence, the submarine fans are subdivided into six phases and three stages, including initial phase (SSQ1), flourishing phases (SSQ2-SSQ4), and declining phases (SSQ5-SSQ6), and tend to migrate southeastward (Fig. 8). The gas groups in Lingshui 36-1 gas field are primarily located in the fifth and sixth phases of submarine fans, and the reservoir microfacies are almost fan center distributary channels and sheet sands.

In the ultra-deepwater and ultra-shallow formations in the Qiongdongnan Basin, traps are primarily lithologic and structural-lithologic, and some are low-relief anticlinal traps. The large Vietnam-sourced submarine fans are vertically developed into six phases, and multiple sand bodies developed every phase (Fig. 9). The sand bodies are stacked in multiple phases vertically, exhibiting complex connectivity. Laterally, they are fragmented by mudstone channels or massive turbidite deposits as lateral seals, and vertically capped by interlayer or regional cap rocks, forming extensive lithologic trap groups.

Traditional view suggests that uncemented or weakly cemented ultra-deepwater and ultra-shallow formations have limited sealing capabilities, so that natural gas is difficult to accumulate on a large scale. However, exploration practices have demonstrated that natural gas can accumulate substantially in these environments, and that uncemented or weakly cemented strata possess sealing capabilities. To evaluate these sealing capabilities, cap rocks and sealing mechanisms were investigated in ultra-deepwater and ultra-shallow formations.

Studies indicate that the ultra-deepwater and ultra-shallow formations have three types of effective cap rocks: deep-sea mudstone, mass transport deposits, and hydrate-bearing layers. Deep-sea mudstone deposits slowly and it’s pure, typically shows medium to weak amplitude, parallel and continuous reflections on seismic profiles. mass transport deposits is deposits from instable and collapsed slope sediments, generally appears as weak amplitude and chaotic reflections on seismic profiles. Hydrate layers where natural gas migrates to the hydrate stability zone and stores in reservoir pores in a solid state exhibit strong amplitude and continuous reflections on seismic profiles, often marked by Bottom Simulating Reflections (BSRs) (Fig. 10).

Furthermore, cap rocks can be categorized into interbedded and regional cap rocks according to their locations and thickness. Interbedded cap rock is mudstone between reservoirs, and thin and unstable in lateral distribution. Regional cap rock is the topmost cover on a gas field and stable in distribution. Most gas reservoirs in Lingshui 36-1 gas field are covered by regional cap rock, and a fewer are sealed by thick interbeds. The thickness and stability of cap rocks play a crucial role in gas accumulation in ultra-deepwater and ultra-shallow formations.

The sealing mechanisms of cap rocks in ultra-deepwater and ultra-shallow formations primarily involve capillary pressure and brine saturation. Capillary pressure sealing occurs when the gas buoyancy in reservoirs is less than the capillary pressure in cap rocks. Buoyancy depends mainly on hydrocarbon density and column height. Capillary pressure is influenced by hydrocarbon-water interfacial tension, wetting angle, and pore throats in cap rock. According to the borehole and sidewall cores, the deep-water mudstone is fine and pure, and more consolidated and adhesive than the sandstone (Fig. 3c). With smaller pore throats and higher capillary pressure, the mudstone is effective to seal natural gas ^[28]. Compared to shallow-water environment, ultra-deepwater environment is featured by low temperature, high pressure and high pore-water interfacial tension. As gas density increases, buoyancy reduces, resulting in higher capillary pressure in deep-water mudstone than shallow-water mudstone at the same burial depth.

Brine saturation sealing occurs when the breakthrough pressure of mudstone increases. Core physical simulation experiments show that as formation water saturation increases, the breakthrough pressure of mudstone increases exponentially ^[29-30]. Comparative studies suggest that deep-water mudstone after saturated with seawater in Lingshui 36-1 gas field has a diffusion coefficient close to that of a conventional good cap rock, which significantly improves the sealing capability.

Mass transport deposits suffering from strong shear deformation and drainage during transport ^[31] exhibit higher density, lower porosity, and greater acoustic velocity than normal sedimentary mudstone, which can enhance its sealing capacity. Hydrate-bearing strata where hydrates fill the pores in a solid state not only significantly reduce formation porosity but also greatly increase formation hardness and breakthrough pressure, effectively sealing natural gas. Several wells have discovered gas beneath hydrate-bearing strata (Fig. 2). Generally, capillary pressure is the dominant sealing mechanism, and brine saturation is a supplementary factor in the study area.

Natural gas migration in the ultra-deepwater and ultra-shallow formations is diverse. Native biogenic gas can directly enter and accumulate in traps through diffusion. Allochthonous biogenic gas or thermogenic gas migrates through vertical pathways such as faults, gas chimneys and fractures, or large sand bodies, unconformities, which form a composite migration framework.

In the Qiongdongnan Basin, two gas migration ways were identified in the ultra-deepwater and ultra-shallow formations:

(1) Vertical migration. Deep-water faults are almost developed in the Paleogene strata, but only a few faults in the Neogene connecting deep hydrocarbon source rocks. Studies indicate that relying solely on diffusion is inefficient for gas migration, so that it is difficult for natural gas to accumulate substantially in a short period. Vertical pathways such as gas chimneys and vertical fractures are essential for gas migration ^[10-11]. Influenced by recent tectonic movements, gas chimneys and vertical fractures are widely distributed in the Lingshui sag, the Linnan low bulge, and the Songnan low bulge ^[32]. Seismic reflections typically appear as irregular and columnar diffuse bands (Fig. 11). Attributes like ant body reflect dense microfractures in the diffuse bands. Seismic velocity analysis indicates low velocities at the peripheries of these features, highlighting their role as crucial migration pathways. Biogenic gas encountered in Lingshui 36-1 gas field primarily transports into traps through these gas chimneys and vertical fractures.

(2) Composite migration. Composite migration pathways are formed by combining lateral migration routes, such as large sand bodies and unconformities, with vertical migration pathways like faults, gas chimneys, and fractures. Drilling results confirm that the primary component of gas in Lingshui 36-1 gas field is deep thermogenic gas. However, there are no mature source rocks on the Linnan low bulge above the gas field, and the field is located far from the sag center. How does thermogenic gas migrate over a long distance to accumulate in the target area? A unique gas transport way in the ultra-deepwater and ultra-shallow formations has been identified based on the detailed characterization of migration paths: lateral migration through the central canyon sandstone and continuously stacked accumulation. Since the Miocene, the central canyon system along the axis of the Qiongdongnan Basin has developed successively and migrated southeastward under the control of ancient geomorphology. The canyon contains large submarine fans and turbidite channel sandstone, including the submarine fan in the Meishan Formation, canyon channel in the Huangliu Formation, restrictive submarine fan in the Yinggehai Formation, and weakly restrictive submarine fan in the Ledong Formation. These sandstones are large, laterally continuous, and stacked, forming a unique lateral relay migration channel from the mid-deep to ultra-shallow formations in the central canyon system. Deep thermogenic gas enters the central canyon through vertical migration pathways such as faults, gas chimneys, and fractures, and then migrates through the distinctive lateral relay transport channels to the ultra-shallow Ledong Formation submarine fans, and eventually accumulates into the lithologic traps on the structural ridges on the tops of the submarine fans (Figs. 1a and 11). Geochemical analysis shows that gas in Lingshui 36-1 gas field is almost thermogenic gas from deep mature source rocks, besides a small amount of biogenic gas. Moreover, Lingshui 36-1 gas field shares a gas source with the Deepsea No. 1 gas field in the Central Canyon, confirming the composite transport system.