The Yinggehai Basin is an important Cenozoic petroliferous basin in the western area of the northern continental shelf, South China Sea. In the basin there are two exploration plays, the shallow strata (Pliocene Yinggehai Formation-Quaternary) and the mid-deep strata (Middle Miocene Meishan Formation - Upper Miocene Huangliu Formation). Over the past 30 years, major discoveries have been made in gas exploration in the basin, especially in the central diapir structural belt, two large gas fields (i.e. DF1-1 and DF13 with gas reserves of over 100 billion m³ in the shallow and mid-deep strata of Dongfang diapir) and several medium-small gas fields (such as LD22-1 gas field) were discovered^[1,2,3,4,5], making this area the largest offshore gas production base of China. Meanwhile, the understanding of petroleum system, the related exploration theory and techniques have improved significantly. It is confirmed that the Miocene is the main gas source rock in the central diapir belt, whereas Oligocene Yacheng source rocks are potential source rocks for the Lingao low uplift and the slope of Yinggehai Sag; the inorganic CO₂ in natural gas in the central diapir belt is originated from crustal lithification; the episodic and rapid charge model of gas pool accumulation has been proposed^{[2,3,4,5,6,7]}; in particular, the discovery of DF13 field has overthrown the traditional view that there are mainly water-soluble gas in the high temperature and high pressure (HTHP) reservoirs^{[6, 8]}. In recent years, some adventurous exploration activities have been conducted targeting at HTHP mid-deep strata in the eastern slope of Yinggehai Sag (transition zone between central diapir belt and Yingdong slope) based on the newly collected 3D seismic data and geological research results^[9,10], leading to the discovery of the L lithologic gas field with a preliminarily estimated reserves of over 100 billion m³. Most previous studies believed that it was difficult for the gases generated from the source kitchen in the central Yiggehai Sag to laterally migrate toward the eastern slope of Yinggehai Sag due to the lack of interconnected sand bodies and that the vertical migration of gas from deeply- buried source rock is also limited owing to the lack of fault networks^{[1-2, 4]}. Therefore, the discovery of the L gas field has drawn great attention to the genetic origin and migration of gas in this area. In this study, the genetic type of natural gases, sources of hydrocarbon gas and CO₂ and their relationships with the gas fields in the diapiric zone are investigated, based on which a migration model of gas in the L field is proposed. This work will help better define the future drilling targets and promote the exploration of the mid-deep lithologic gas reservoirs in the non-diapir area in the basin.

The Yinggehai Basin is a NW-SE trending Cenozoic strike- slip basin in the passive continental margin of the northern continental shelf in South China Sea with an area of 11.3×10⁴ km². It includes three main tectonic units, i.e., the Yingdong slope, the Yingxi slope and the central depression (Fig. 1a). The basin underwent two stages of tectonic evolution, the Paleogene rifting stage and the Neogene-Quaternary post-rifting thermal subsiding stage^[11]. In the rifting stage, the eastern slope of Yinggehai Sag and the north part of Dongfang area in the central depression were mainly controlled by Yingdong Fault, and half-garben structure developed, receiving Paleogene deposits. The Yacheng Formation coal-bearing strata of neritic and coastal plain facies deposited in the adjacent Qiongdongnan Basin in Early Oligocene, which are regarded as one of main source rocks in the basin^[3]. The same sequence is assumed to be present in the central Yinggehai Sag, but it has not been revealed by drilling due to deep burial depth. Nevertheless the Yacheng Formation revealed in the margin of the basin and the Lingao low uplift is still believed to be potential source rock. In particular, the eastern slope (near Yingdong slope) of Yinggehai Sag sits in the transitional zone of Yinggehai and Qiongdongnan Basin, so its sedimentary evolution has some similar characteristics with Qiongdongnan Basin. Considering that the No.1 Fault controlled deposition in the rifting stage and the Yacheng Formation deposited during the early Oligocene, there are likely neritic and coastal plain coal-bearing sediments in the small half graben trending northwest-southeast in the downthrown wall of No. 1 Fault.

In Neocene age, the eastern slope of Yinggehai Sag, together with Yinggehai Basin, entered into the depression stage. In the central part of Yinggehai Sag, rows of nearly north- south trending diapirs (with a series of high-angle faults) in echelon formation developed^[1,2]. Since the Late Miocene, the southern basin underwent rapid subsidence and the subsiding center gradually migrated to the Ledong area, and the basin appeared high in the north and low in the south so the strata were buried deeper from the Lingao Low Bulge to Dongfang area and Ledong area from north to south^[11]. The Miocene Meishan and Sanya Formations are dominated by neritic- bathyal thick mudstone (Fig. 1b) that is regarded as the main source rock of the gas fields in the central diapir belt^[1,2,3]. The distribution and characteristics of the Miocene source rocks in the eastern slope of Yinggehai Sag are similar to those in the central diapir belt, except slightly thinner. Influenced by provenance supply from Hainan Island, submarine fan, channel sand, neritic shelf sandstone and marine mudstone developed in Meishan, Huangliu, Yinggehai Formations, forming good reservoir-cap assemblage^{[9-10, 12]}.

The Yinggehai Sag are characterized by late rapid subsiding, Neogene - Quaternary thick deposits (thickness up to 8 000- 10 000 m), high temperature & high pressure and many diapir structures. The geothermal gradient in Neogene is 4.04 °C/100 m on average and up to 5.56 °C/100 m, and the heatflow value is 77.8±7.2 mW/m² on average and 95 mW/m² at maximum. Although the overall subsidence of the basin occurred and main faults were inactive at the end of Lingshui Formation period (T60), the diapiric fault activities were strong and the hidden faults in the eastern slope of Yinggehai Sag were still active slightly. The unique geological conditions have an important influence on hydrocarbon generation, migration and accumulation.

The L gas field is located in the south part of the eastern slope of Yinggehai Sag, including LD01, LD02, LD03 lithologic gas reservoirs (Fig. 1a), and the LD01 Huangliu Formation channel sand reservoir is the main body. Huangliu Formation sandstone reservoir in LD01 gas pool is the gravity flow sedimentary system in the upper Miocene canyon channel, and the planar distribution of channel is obviously controlled by the provenance supply from Hainan Uplift, with two branch channels in the north and south wings^[9]. There are LST, TST and HST inside the channel. The LST sandstone is controlled by flexure slope break near the sag and, which is overlain by transgressive and HST mudstones, forming effective traps^[13]. The main production layers of the gas pool are submarine fan - axial channel sandstone of Upper and Middle Miocene Huangliu Formation at the burial depth of 3 800-4 300 m (Fig. 2). The reservoirs are dominated by siltstone and fine-medium sandstone, with a logging porosity of 8.5%- 12.3% and core permeability (0.04-10.00)×10^-3 μm², mostly in the range of (0.1-2.0) ×10^-3 μm². High-yield commercial gas flow was obtained by DST test^[13]. The LD02 gas pool is a lithologic trap of axial gravity flow channel in Miocene Meishan Formation, with fans extending along slope break and distinct incised feature in the main channel and lobes. The LD03 gas pool is a lithologic trap on a big nose-structure and has vertically overlapped sand bodies. Its roof and floor are shallow marine mudstone of Meishan Formation and Sanya Fortmation respectively, and its higher part is transgressive mudstone, which forms an effective sealing layer. The main gas pays in LD02 and LD03 gas pools are Meishan Formation sandstone, at burial depths of 3 710-4 200 m, dominated by fine sandstone and some siltstone. The sidewall coring samples have a porosity of 9.5%-13.2% and permeability of mainly (0.1-1.0) 10^-3 μm², indicating the reservoir is low-porosity and ultra-low permeability. Compaction and carbonate cementation are important factors turn the physical properties of the reservoirs poorer in the L gas field. Huangliu and Meishan Formation are mainly in the A2 period of middle diagenetic stage, with obvious pore reduction caused by compaction^[13].

Drilling and testing results show that the Miocene gas pays in the L gas field are characterized by not only low porosity and low-ultralow permeability, but also abnormally high tem-perature and pressure. According to DST data, the formation temperature is 180-190 °C with a geothermal gradient of 4.35 °C/100 m, and the pressure coefficient is as high as 2.19- 2.29^[13].

The natural gas in the L gas field is complex in composition, showing stratification vertically. The gas samples from the Huangliu Formation of LD01 and LD02 gas pools have 34.35%- 85.37% of methane and low content of ethane and propane (1.3%-5.8%). Non hydrocarbon gas in it mainly includes CO₂ and N₂, and the CO₂ varies widely in content (0.52%- 62.17%). The gas dryness coefficient (C₁/C_1-5) is 0.94-0.98. In comparison, the gas samples from the Meishan Formation of LD02 and LD03 gas pools have a methane content of 33.08%-58.88%, higher CO₂ content (33.3%-58.98%), N₂ content of 5.3%-7.5%, and ratios of C₁/C_1-5 from 0.96 to 0.99, indicating dry gas (Table 1).

2.2.1. Carbon isotope composition and genetic type of hydrocarbon gas

Carbon isotope composition of hydrocarbon gas component is one of the important parameters to identify its genetic type and source^[14]. Carbon isotopic composition of methane is related not only to organic matter types, but also to the maturity closely, namely δ¹³C₁ values become heavier with the increase of thermal maturity. Carbon isotopic composition of ethane, although also affected by maturity, has a closer relationship with its parent materials. So, it is often used as an important indicator of genetic type of hydrocarbon gas. The carbon isotope value of ethane of gas from humic organic matter is heavier, usually heavier than -28‰^[14,15], whereas ethane from sapropel organic matter is usually depleted in ¹³C.

Results of carbon isotope composition analysis show the gas samples from the Huangliu Formation of LD01 and LD02 gas pools have a δ¹³C₁ of -40.71 to -29.44‰ (mainly between -34.04‰ and -29.44‰) and δ¹³C₂ of -27.27‰ to -23.28‰ (mainly between -25.88‰ and -23.13‰). The δ¹³C₁ and δ¹³C₂ values of gas samples from Meishan Formation are heavier, ranging from -29.24‰ to -27.40‰ and from -23.78‰ to -20.26‰ respectively. In general, δ¹³C₂ values of these gases are greater than -28‰, similar to gases from humic and coal- bearing source rocks in Australia’s Cooper basin^[16] and China’s petroliferous basins^[14,15]. The δ¹³C₁-δ¹³C₂ diagram shows that all gas samples from the L gas field fall into the coal-type gas area (Fig. 3). Based on the δ¹³C₁values of methane carbon isotope and by using δ¹³C₁-R_o relationship equation of gas generated by Type II₂ - III kerogens in Yinggehai Basin, the maturity (R_C1) of hydrocarbon gas samples from the L gas field were calculated at 0.69% to 1.97% (Table 1). Referring to the δ¹³C₁-R_o relationship curve of coal type gas of Cooper basin reported by Berner^[16], the maturity (R_C2) of gas samples from the L gas field were estimated between 0.75% and 2.01%. The R_o values determined by the two different methods are very close, indicating that the gas of the L gas field is the product of thermal evolution of organic matter during mature and high mature stages.

2.2.2. Isotopic compositions and origin of carbon dioxide

The content and carbon isotope value of CO₂ in the L gas field vary widely (Table 1). When the CO₂ content in natural gas is less than 10% (0.5%-7.5%), the δ¹³C_CO2 value is lighter (-11.83‰--18.08‰), indicating organic origin. When the CO₂ content in natural gas is more than 10%, the δ¹³C_CO2 value is heavier (-9.04‰--0.85‰). The natural gas samples of Meishan Formation in LD02 and LD03 gas pools have a CO₂ content between 33.3% and 58.98% and δ¹³C_CO2 value from -1.10‰ to -3.63‰, indicating inorganic origin (Fig. 4). The helium associated with natural gas of high CO₂ content has a ³He/⁴He ratio of 7.78×10^-8, much lower than that of air (1.4×10^-6), indicating the helium is crustal origin. These features are similar to those of most inorganic CO₂ from the gas fields in the central diapir belt^[1,2,3], so it’s inferred that they have the same origin, mainly from thermal decomposition of calcareous shale in deep strata, with a small contribution of CO₂ from thermal decomposition of basal carbonates^[7]. Fig. 5 shows that inorganic CO₂ in the L gas field has a good isotopic correspondence with the carbonate minerals and cement in Miocene-Oligocene calcareous rock; some gas samples have heavier δ¹³C_CO2 values, also similar to that of carbonates. Drilling results reveal that the Meishan and Sanya Formations in the Yinggehai Basin contain calcareous mudstone and calcareous siltstone, and pre-Paleogene limestone or dolomite was drilled in two wells in the Yingdong slope (Fig. 1b), suggesting there are carbonates in local parts of the basement which can provide potential material base for inorganic CO₂. The Neogene-Quaternary sediments in the Yghehai Sag are hugely thick, and the geothermal gradients there are up to 4.5-4.7 °C/100 m, representing a typical "deep - hot basin". Since 5.5 Ma, the thermal fluids formed by rapid thermal subsidence of the basin and diapir activity invaded upward along the diapiric faults (in diapiric belt) and hidden faults (in eastern slope of Yinggehai Sag), providing important heat source^[11] for the generation of a large amount of CO₂ from fast thermal decomposition of deep Meishan and Sanya calcareous mudstones (or carbonates)^{[7, 17-18]}. The CO₂-rich gas then moved upward through faults/permeable sandbodies into reservoirs, ultimately forming CO₂-rich gas reservoirs.

The natural gas generated by sapropel organic matter usually contain relatively high content of normal alkanes in total C₅-C₇ light hydrocarbons, while the natural gas from humic organic matter has more isoparaffin and aromatic hydrocarbons^[15]. Statistic data of 209 gas samples from the Ordos, Sichuan, Qaidam and Tarim basins show that the natural gas with alkane content of C₅-C₇ light hydrocarbons of greater than 30% is oil-type gas, while that with smaller than 30% is coal-type gas^[19]. The isoparaffin contents (55%-73%) of total C₅-C₇ light hydrocarbons in gas samples from the L gas field (Fig. 6) are much greater than normal alkanes (18%-30%) and cycloparaffin contents (5%-15%), similar to those of coal-type gases in the Ordos, Tarim, Sichuan basins^[19].

The relatively high content of aromatic hydrocarbons (benzene and toluene) is also regarded as an important indicator of coal-type gas^[3]. The benzene contents of total C₆ light hydrocarbons in gases from the L gas field range from 19% to 30%, and the toluene content of the C₇ hydrocarbons is even up to 45.4%, reflecting that parent material of the gases is mainly terrigenous organic matter. The humic organic matter is relatively poor in hydrogen and could produce more condensed aromatic compounds, so the corresponding monocyclic aromatic abundance (benzene and toluene) is relatively high in the gases.

Available data shows that there are two sets of source rocks in Yinggehai Basin, i.e., the Oligocene Yacheng Formation and the Miocene (including the lower Huangliu and Meishan- Sanya Formations).

The Yacheng source rocks are mainly distributed in the slope of Yinggehai Sag (the downthrown side of No. 1 Fault) and the Lingao low uplift. It is dominated by swamp, littoral and neritic facies. According to drilling and geochemical data, Well YC19-2-1 located in the downthrown wall of No.1 Fault near Qiongdongnan basin, encountered the coal-bearing source rock of delta facies at the burial depth of 3 900-4 300 m, with R_o value of 1.1%-1.4% and TOC value of 1.50%-5.39% (Fig. 7b). It has been confirmed that the Oligocene Yacheng Formation source rock is the major source rock of the adjacent YC13-1 (in shallow water area) and Lingshui 17-2 gas fields (in deep-water area) in Qiongdongnan Basin^{[3, 20-21]}. The seismic data interpretation shows that the Yacheng Formation near the L gas field is more deeply buried, most of which has entered the mature-high mature stage, so it is inferred as a potential source rock with high gas generation capacity.

Miocene source rocks mainly develop in Yinggehai Sag, with a big thickness and extensive distribution, and are composed mainly of delta, neritic, bathyal facies, and are considered as the main source rocks in the central diapiric gas fields^{[1-3, 22]}. So far, the Miocene source rocks revealed by most wells drilled on the basin margin, have relatively low TOC content; however, several deep wells in the eastern slope of Yinggehai Sag encountered good Miocene source rocks with higher TOC values^[22]. For example, the sidewall coring mudstone samples of the Huangliu and Meishan Formations in Well LD22-1-7 have TOC values of up to 1.52%-3.03% with an average of 2.1%. The Upper Meishan Formation mudstones encountered by the newly drilled well LD03-1 also display relatively high TOC value ranging from 0.6% to 2.1% with an average of 1.2%. The Huangliu and Meishan (not penetrated) Formations revealed by Well LD30-1-1A are about 700 m thick, the Lower Huangliu and Meishan mudstones have TOC values of 0.40%-3.17% with an average of 1.29%, largely ranked as good source rocks (Fig. 7a). Hydrogen indexes (HI) mainly range from 120 to 300 mg/g with an average of 145 mg/g, indicating gas-prone type II₂-III kerogens^[22].

Seismic data and drilling results reveal that Miocene source rock in the eastern slope of Yinggehai Sag is buried at depths of 3 500-6 300 m. The source rock reaches R_o of 0.6%, the hydrocarbon generation threshold, at the burial depth of about 2 600 m; oil window is between 2 600-4 500 m; condensate and wet gas window between 4 500-5 400 m; dry gas window deeper than 5 400 m (Fig. 8). The gas generation peak of Sanya Formation source rock occurred in the Late Pliocene, while the Meishan and Huangliu Formations source rocks are still in the massive gas generation stage. Miocene source rock layers in the west part of the L gas field are buried between 4000 m and 7 000 m deep, with a higher maturity. Basin modeling results show that the central depression in Yinggehai Basin has a large gas generation volume and a gas generation intensity of greater than 50×10⁸ m³/km^2[22], providing sufficient gas source for the formation of gas fields in central diapir belt and lithologic gas reservoirs in the eastern slope of Yinggehai Sag.

Carbon isotope composition (δ¹³C₂) of ethane in nature gas is an important indicator of gas-source correlation^[14,15]. The δ¹³C₂ values of gas samples from the L gas field are heavier, 70% samples heavier than -24‰, which is obviously different from that YC13-1 gas derived from Oligocene Yacheng coal-bearing source rock. The plot of δ¹³C₁-δ¹³C₂-δ¹³C₃ shows that the majority of gas samples from the L gas field fall the same area with gas samples from adjacent LD22-1 gas field (sourced from Miocene source rock), indicating that both of them can be derived from the similar source^[3] (Fig. 3). From the stable carbon isotope of methane, the δ¹³C₁ value of gas samples from LD22-1 gas field mostly vary between -32‰ and -40‰, lighter than those from the L gas field (Fig. 3), suggesting that the latter contains higher proportion of high maturity gas. According to the hydrocarbon distribution rule, the traps near kitchen usually capture oil and gas with higher maturity, while traps far from kitchen collect hydrocarbons with lower maturity. The reservoirs in the L gas field are deeper Miocene Huangliu and Meishan Formations, closer to the Miocene kitchen. In contrast, Pliocene reservoirs in LD22-1 gas field are far away from the Miocene source kitchen^[2], so they may trap more gas generated during the early period of mature to high mature stages (Table 1 and Fig. 1).

Correlation of ¹³C₂ in gas with the δ¹³C of kerogen also indicates most of the gas samples of the L gas field are sourced from the Miocene source rock (Fig. 9). Available data show that the Miocene and Lower Oligocene source rocks have obvious differences in kerogen: the former has heavier δ¹³C value of koregen, mainly from -21‰ to -25‰ (average of -23.8‰); while the latter has δ¹³C value from -26‰ to -30‰ (on average -27.2‰) (Fig. 9). Previous studies showed that the organic matter in Yacheng coal-bearing strata is sourced mainly from terrigenous plants, while the Miocene source rock contain organic matters derived from both terrigenous and marine plants^[3]. Photosynthetically, marine plants (with relatively heavy δ¹³C) utilize CO₂ from the water-soluble bicarbonates, whereas terrestrial plants utilize CO₂ from the atmosphere, consequently the δ¹³C value difference of them in ancient sediments could be up to 3‰-5‰^[23]. Comparison of δ¹³C₂ with δ¹³C_kerogen shows most of gas samples from the L gas field are closer to the Miocene source rock, only individual gas samples have lighter δ¹³C₂ value similar to the δ¹³C_kerogen value of Yacheng source rock, so a small amount of gas may be derived from Yacheng source rock (Fig. 9).

The gases in the L gas field mainly consist of CH₄ and CO₂ with a small amount of N₂. The contents of CH₄ and CO₂ vary widely from 14% to 85% and from 0.5% to 62.2% respectively. The gas of Meishan Formation has higher CO₂ content than that of the overlying Huagliu Formation (Table 1 and Fig. 2). Such changes are probably caused by the reformation of inorganic CO₂ charged later to the composition of early- charged hydrocarbon-rich gas, which is mainly related to the timing of the generation and charging of hydrocarbon gas and inorganic CO₂.

Previous studies show that the Miocene humic source rock in the Yinggehai Sag (including diapir belt and eastern slope of Yinggehai Sag) produced hydrocarbon gas and minor N₂ and organic CO₂ during mature to high mature stages, but massive inorganic CO₂ by thermal decomposition of calcareous mudstone in overmature stage^[24]. Therefore, the gas accumulated early has a high proportion of hydrocarbon gas and minor N₂ and organic CO₂. For example, LD01_11 and LD02_12 samples from upper Huangliu Formation have a high hydrocarbon-gas content of 81.77%-85.37%, low CO₂ content of 0.52%-7.45%, and lighter δ¹³Cco₂ values of -18.08‰--11.83‰, indicating typical organic origin^[7,17]. With continuous subsidence of the basin, the Meishan and Sanya strata evolved into late gas generation stage. In particular, since the end of Pliocene, strong thermal fluid invasion associated with diapir activity made the Middle-Lower Miocene calcium-rich strata undergo a “short period-high temperature” heat effect, and rapidly reach the threshold temperature (>300 °C)^[18] of thermal decomposition of calcareous rock to generate inorganic CO₂. These CO₂-rich fluid from the central diapir belt migrated eastward along the permeable sandbodies of the Meishan and Sanya Formations. Also, Sanya Formation calcareous rock and basal carbonate in the L gas field could generate some inorganic-CO₂ too, which could migrate upwards along concealed faults into overlying reservoirs and mixed with early-accumulated hydrocarbon gas. The early-accumulated gas reservoirs are affected at different degrees by the late CO₂ injection, leading to significant variations in gas composition of different reservoirs. Close to CO₂ kitchen, the lower Meishan gas reservoirs are more affected by CO₂; while the upper Huangliu reservoirs are less affected and richer in hydrocarbon gas, which implies shallow reservoirs would have low risk of finding CO₂.

The δ¹³C₁ values in the L gas field vary widely between -40.71‰ and -27.40‰, the δ¹³C₂ values between -27.27‰ and -20.26‰. Previous researches show that the main factors influencing methane and ethane carbon isotope composition are kerogen type and thermal maturity^[14,15,16]; in addition, oxidation would also make δ¹³C₁ and δ¹³C₂ values turn heavier. However, the gas reservoirs in the L gas field are large in burial depth (3 700-4 250 m) and have few fractures in Neogen age, making it hard for oxidation bacteria to live. Based on the geological conditions and organic matter property and thermal evolution characteristics of Miocene source rocks in the study area, as well as the gas-source correlation results, it is concluded that the maturity differences and organic facies variation of source rock are the main factors leading to the big variations of δ¹³C₁ and δ¹³C₂ values in L field.

As shown in Fig. 10, only LD02_11 sample is exceptional and obviously different from the others (main group): with lighter δ¹³C₁ (-40.71‰) and lower maturity (0.69%), suggesting that there is some gas generated by the source rock of Miocene Huangliu Formation in the early mature stage near the reservoir. In contrast, carbon isotope compositions of the main gas group have obviously similar carbon isotopic curves, indicating these gas samples are mainly derived from the same source rock, and their variations in δ¹³C₁ and δ¹³C₂ values can be attributed to the difference in their maturity levels. The δ¹³C₁ and δ¹³C₂ values of these gases are positively correlated with each other (Fig. 11), which indicates thermal maturity is also one of main factors resulting in the significant variation of δ¹³C₁ and δ¹³C₂. This is in accordance with burial thermal evolution history of the Miocene source rocks in Well L02-1 (Fig. 8). On the other hand, the δ¹³C values of kerogens from the Miocene source rocks vary between -27.7‰ and -21.8‰ (mainly ranging from -25.7‰ to -21.8‰), reflecting a composite of kerogens with wide span of δ¹³C values probably due to organic facies change. It means that the gases generated by these source rocks, even under the same maturity and accumulation condition, would have significantly different carbon isotope composition as suggested by Berner et al.^[16]. Therefore, it is believed that the accumulation of gases generated by the Miocene source rocks during late mature to high mature stages results in the significant variation in their δ¹³C₁ and δ¹³C₂ values in the L gas field.

For a long time, the issue on large-scale gas accumulation under HTHP conditions has been hotly debated. According to data from some studies published early, the discovered oil/gas reservoirs were mainly distributed around 300 m on the top of high pressure compartment^[25,26]. Law et al.^[27] thought that it was hardly possible to find industrial gas accumulation in the reservoirs with pressure coefficient of over 1.96. It is fortunate that the L gas field with the pressure coefficient of up to 2.29 has been found in Yinggehai Basin. On the basis of the aforementioned discussion, along with combination of the related geological data, a migration model has been proposed to show the formation of gas reservoirs in the L gas field, eastern slope of Yinggehai Sag (Fig. 12).

Gas-source correlation results have confirmed that the Miocene Sanya, Meishan and Lower Huangliu Formations are the main source rocks of the L gas field. Currently the source rocks near the Meishan and Lower Huangliu Formations reservoirs are already mature, and the Meishan and shanya source rocks underlying and west to the gas reservoirs have greater burial depth and higher maturity, with R_o values mainly of 1.3%-3.2% (Fig. 8). More importantly, rapid subsidence (since 5.5 Ma) and high geothermal gradient (4.5 °C/100 m) made Miocene source rocks undergo “short term, high temperature, rapid thermal maturation”, generating gas quickly and at high intensity^{[11, 22]}, providing abundant gas- source supply for the L gas field. The late gas generation peak (approximately Pliocene-Quaternary) of Miocene source rocks matches well in timing with the lithologic trap formation, which is conducive to the accumulation of gas in the eastern slope of Yinggehai Sag. Also, the potential Yacheng source rocks, currently with burial depths of 5 000-6 000 m (Fig. 12) and high maturity in the Paleogene half garden adjacent to the L gas field, may generate some gas, servicing as the secondary gas source.

The Miocene source rocks, currently with burial depths of 5000-7 500 m, locally up to 10 000 m in Yinggehai Sag, are located in a strong overpressure zone. The pressure in shallow gas reservoirs in the central diapir belt is normal^[1,2], whereas in the mid-deep gas reservoir there are overpressures with pressure coefficients (Cp) of 1.7-1.8^{[4-6, 8]}. Drilling results revealed that the top surface of regional overpressure zone in Yinggehai Basin has a depth of approximately 3 000 m and becomes gradually deeper toward the basin’s margin^{[6, 28]}. Huangliu reservoirs in the L gas field in eastern slope of Yinggehai Sag sit over the source rocks with deeper source rocks and shallower reservoirs, so that there is a relatively large pressure difference between them. According to the results of simulation experiments^[29], when the pressure difference between sources and reservoirs exceeds approximately 3-6 MPa, large-scale expulsion of hydrocarbon occurs. As illustrated in Fig. 8, the Huangliu reservoir in the L gas field was buried at 2 500-2 800 m at 2 Ma, with pressures of about 25-28 MPa, while the burial depth of Meishan-Sanya source rocks underlying the reservoirs in the west of the L gas field was 4 000-5 000 m, with estimated formation pressures in the range of 80-100 MPa, corresponding to Cp value of 2.2 as encountered by Well LD03-1 at 4 000 m. Therefore, the pressure difference then between the source and reservoir reached about 50-75 MPa. With increase of burial depth, the diagenesis of the Huangliu and Meishan reservoirs became more and more intense, gradually leading to the present low-porosity and low-permeability reservoirs. According to drilling data, the Huangliu and Meishan reservoirs with present burial depths of 3 700-4 200 m, have a formation pressure of 81.4- 92.4 MPa, with a Cp values of 2.20-2.29. In such a high temperature and high pressure condition, the buoyancy effect on gas migration is very small in the low permeability reservoirs^[30]. The Meishan and Sanya source rocks underlying reservoirs, especially to the west of the L gas field, are buried at depths of 4 500-6 500 m, and the corresponding formation pressure may be 99-143 MPa at the assumed Cp value of 2.20. So there are still considerable pressure difference of 17.6- 50.6 MPa between sources and reservoirs, which could provide an important driving force for gas migration into the res ervoirs of the L gas field, further accelerating the charging efficiency.

Different from the central diapir belt, there lacks of migration channels like the diapiric faults in the eastern slope of Yinggehai Sag^[1-2,4-6], so if the gas derived from the deeply burial Miocene source rocks could migrate to the lithological traps is a key factor for formation of gas reservoir. As shown in Figs. 8 and 12, the Huangliu and Meishan reservoirs in the L gas field are surrounded by mature source rocks, and the Meishan-Sanya source rocks underlying the reservoirs near the west of the L gas field have evolved into gas generation peak, so the gas from them could migrate a short distance into the reservoirs. The gas may migrate in three ways, i.e., migration of gas from the Miocene source rock to the reservoirs nearby; vertical migration of highly mature gas (from deeper Meishan and Sanya Formations source rock) through concealed faults; and lateral migration along permeable sandbodies (Fig. 12). It can be seen from the coherence attribute slice of seismic data^[9] that there are hidden faults connecting the reservoirs and source rocks in the eastern slope of Yinggehai Sag (Fig. 12), which thus provide migration pathways for the gases derived from the deep highly mature source rocks. Moreover, Huangliu-Meishan reservoirs are located in a SW structural ridge^[9], conducive to lateral gas migration through sand bodies or unconformities under the joint driving of “source-reservoir” pressure difference and buoyancy. Therefore, although the Miocene reservoirs in the L gas field are low in porosity and extremely low in permeability, the abundant gas supply and good migration conditions could improve hydrocarbon charging efficiency, making it possible for the gas to accumulate to large scale at very short time duration (about 2 Ma)^[13].

The gases from the L litholgic gas field in the eastern slope of the Yinggehai Sag are dominated by CH₄ and CO₂, with a dryness coefficient of up to 0.94-0.99, and classified as coal-type gas based on δ¹³C₁ and δ¹³C₂ values and isoparaffin contents of total C_5-7 light hydrocarbons. When the CO₂ content is greater than 10%, the ¹³C_CO2 value of gas samples are -9.04‰ to -0.95‰, and the associated helium has a ³He/⁴He value of 7.78×10^-8, suggesting that the CO₂ here is crustal origin and is mainly sourced from the thermal decomposition of calcareous mudstone and carbonate in deep strata.

The correlation of δ¹³C₂ values in gases and δ¹³C values of kerogens shows that the gases in the L gas field are derived from Miocene source rocks, the products of late mature-high mature stage; the majority of which are similar to the gases in LD22-1 gas field. Additionally, it’s possible that less gas comes from Oligocene Yacheng source rocks.

The reservoirs in the Huangliu and Meishan Formations in the L gas field are characterized by low porosity and ultra-low permeability, as well as high temperature and over pressure. There are three kinds of migration ways, i.e., migration of gas from the Miocene source rock to the reservoirs nearby, vertical migration of highly mature gas (from deeper Meishan and Sanya source rocks) through concealed faults, and lateral migration along permeable sandbodies. The large pressure difference between the “source” and “reservoir” is the key driving force for the vertical and lateral migration of gas. This migration model will better guide the geological understanding of mid-deep lithologic gas reservoir in the non-diapir area of Yinggehai Basin.