Petroleum systems modeling on gas hydrate of the first experimental exploitation region in the Shenhu area, northern South China sea

Petroleum systems modeling on gas hydrate of the first experimental exploitation region in the Shenhu area, northern South China sea

Accepted Manuscript Petroleum Systems Modeling on gas hydrate of the first experimental exploitation region in the Shenhu area, northern South China S...

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Accepted Manuscript Petroleum Systems Modeling on gas hydrate of the first experimental exploitation region in the Shenhu area, northern South China Sea Pibo Su, Jinqiang Liang, Jun Peng, Wei Zhang, Jianhua Xu PII: DOI: Reference:

S1367-9120(18)30338-9 https://doi.org/10.1016/j.jseaes.2018.08.001 JAES 3605

To appear in:

Journal of Asian Earth Sciences

Received Date: Revised Date: Accepted Date:

30 August 2017 4 August 2018 8 August 2018

Please cite this article as: Su, P., Liang, J., Peng, J., Zhang, W., Xu, J., Petroleum Systems Modeling on gas hydrate of the first experimental exploitation region in the Shenhu area, northern South China Sea, Journal of Asian Earth Sciences (2018), doi: https://doi.org/10.1016/j.jseaes.2018.08.001

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Petroleum Systems Modeling on gas hydrate of the first experimental exploitation region in the Shenhu area, northern South China Sea Pibo Sua*, Jinqiang Lianga* , Jun Pengb, Wei Zhang a, Jianhua Xub a

MLR Key Laboratory of Marine Mineral Resources, Guangzhou Marine Geological Survey,

Guangzhou 510075, China b

Schlumberger Technology Services (Beijing) Ltd, Beijing, 10015, China

*Corresponding author. E-mail address: [email protected][email protected]

Abstract: Two-dimensional gas hydrate petroleum system modeling was conducted to understand gas hydrate accumulation mechanisms and spatial distribution related to geologic and geochemical processes in the first experimental gas hydrate exploitation region in the Shenhu area of the South China Sea. Based on the gas production in core samples, a new biogenic methane generation model was created and incorporated into a kinetic model. With the results of a rock pyrolysis experiment, a thermogenic gas kinetic model for deep formations in the study area was also developed. The entire dynamic evolution process from gas generation to migration and gas hydrate formation and accumulation in the perspective area was simulated with the petroleum system modeling method. The results showed that the gas hydrate stability zone (GHSZ) began to form after 3.88 Ma, and its thickness was greatest when the paleowater depth peaked at 3.66 Ma. The mass of thermogenic gas generation in deep formations is large, and that of biogenic gas in shallow formations is relatively small. Formations that overlap the gas hydrate bearing layers act as cap rocks that prevent the gas from migrating vertically to shallow layers. There was a geological time gap between thermogenic gas generation, migration and GHSZ formation. However, the timing of biogenic gas generation, which is typically of recent generation in the shallow layer, matched well with the formation of the GHSZ. Finally, coupling of the age and space of gas migration and GHSZ formation has allowed gas hydrate accumulation at structural highs in the Shenhu area. The evaluation technique of petroleum system modeling is of great significance for the improvement of gas hydrate exploration in frontier areas in the future, particularly where survey data are limited. Keywords: Gas hydrate; Petroleum system modeling; Gas hydrate stability zone; Gas source condition; Gas accumulation mechanisms; Shenhu area; South China Sea

1. Introduction Gas hydrates (GHs) are ice-like compounds formed in the presence of sufficient amounts of gas and water molecules (Sloan, 1998). These compounds are stable under suitable conditions of temperature and pressure (Kvenvolden, 1993; Tishchenko et al., 2005; Marquardt et al., 2010). Gas hydrate is considered as one of new energy sources in the scope of unconventional resources. An increasing number of studies on gas hydrates has been conducted in recent years (Dallimore & Collett, 1995; Boswell et al, 2012; Collett et al., 2014). Although gas hydrates have not proven to be a commercially viable energy resource, recent progresses in developing appropriate exploration/production methods have been encouraging (Boswell et al., 2014; Li et al., 2018). Guangzhou Marine Geological Survey (GMGS) has been conducting long-term feasibility studies to assess exploitable gas hydrate resources and develop offshore production methods in the South China Sea (SCS), especially in the Shenhu area (Yang et al., 2008; Zhang et al., 2013; Yang et al., 2015; Liang et al., 2017; Zhang et al., 2017). The Shenhu area of the SCS was inferred to contain major exploitable reservoirs of gas hydrate-bearing sediments(Su et al., 2010;Su et al., 2011;Su et al., 2014). The Shenhu area has been an intensive study area for gas hydrate investigation in the past decade. Early studies included 2D and 3D seismic surveys, geochemical coring, etc. Moreover, the GMGS 1, GMGS 3, and GMGS 4 gas hydrate drilling expeditions were conducted in the Shenhu area in 2007, 2015, and 2016, respectively (Yang et al., 2008; Yang et al., 2015; Liang et al., 2017; Zhang et al., 2018). The results of geophysical surveys and the GMGS 3 and 4 drilling expeditions identified at least three gas hydrate reservoirs with large amounts of gas hydrate. (Yang et al., 2015). One of reservoirs was chosen as the first offshore production test region in 2017. The depressurization method was applied in the test, and the cumulative production over sixty days was approximately 309000 m3 (under atmospheric pressure), and the average gas production was approximately 5151 m3/d (Li et al., 2018). It is important to understand the gas hydrate accumulation mechanism and the factors that control gas hydrate spatial distribution in the study area, which may apply in other areas, such as on the northern SCS slope. The concept of a gas hydrate petroleum system consisting of a gas hydrate stability zone (GHSZ) (temperature and pressure), source rocks, migration, availability of

water, and suitable host sediments or “reservoirs” as proposed by Boswell et al, 2012 has been widely applied in gas hydrate studies and exploration around the world (Collett, 2009; Rajan et al.,2013; Max & Johnson, 2014). Although some researchers have studied gas hydrate migration and accumulation characteristics in the Shenhu area using the concept of a gas hydrate petroleum system (Wu et al., 2011; Wang et al., 2014; Su et al., 2016), only accumulation conditions, such as gas source, reservoir, and migration based on interpretation of limited seismic profiles and borehole logging data have been addressed. However, seismic inversion is ambiguous in some cases, and petrophysical interpretations are only based on properties along boreholes. In addition, it is difficult to depict the dynamics of temperature and pressure which are determinants of gas hydrate stability. Furthermore, gas migration and GHSZ formation should be compatible in the geological time and space domains. Only gas that migrates to the GHSZ has the potential to form gas hydrate. Therefore, the formation process of the gas hydrate petroleum system, especially the coupling of time and space between the source rock, reservoir, migration pathways and the GHSZ in the Shenhu area should be systematically investigated. Numerical modeling is an effective way to study the dynamic process of gas migration and accumulation. The petroleum system modeling (PSM) method has been successfully adopted in gas hydrate studies and exploration throughout the world (Piñero et al.,2011; Haeckel et al., 2013; Piñero et al., 2014; Burwicz et al.,2014; Piñero et al.,2016; Kroeger et al., 2017). Based on the exploration results in the Shenhu area (Yang et al.,2015; Liang et al.,2017; Zhang et al.,2017; Zhang et al.,2018), we simulated the evolution of the gas hydrate petroleum system using the PSM method. With the proper simulation algorithm, we finally simulated the gas hydrate accumulation process. The primary aim of this study is to analyze the characteristics of the gas hydrate petroleum system and demonstrate the mechanism of gas hydrate migration and accumulation in the Shenhu area. The research results can be applied to BSR verification, GHSZ delineation for drilling risk assessments, analyses of the main controlling factors of reservoir formation, and gas hydrate favorable zones and resource prediction. This evaluation technique can be used to ultimately improve gas hydrate exploration in similar frontier areas with limited data.

2. Geological background The study area was located in the Baiyun Sag, on the southern part of the Pearl River Mouth Basin (PRMB) (Fig. 1), which is a large petroliferous basin in the northern slope of the SCS. Tectonically, the Baiyun sag has experienced rifting and post-rifting stages. The rifting stage occurred over three phases, roughly from the Late Cretaceous or Paleogene to the Early Oligocene (Fu et al., 2007). The post-rifting stage lasted roughly from the Late Oligocene to the present (Fig. 2). The latest tectonic event is the Taiwan orogeny, called the Dongsha event, which was at approximately 10.5 Ma (Gong et al., 1997). There were no any significant tectonic activities in the Pleistocene and Pliocene, which favored the accumulation and preservation of gas hydrate. Most of the faults were active at the beginning of the post-rifting stage and became inactive at 15.5 Ma and in the eastern part, where Well A is situated, were reactivated at 10.5 Ma or later (Fig. 1B). The faults are characterized by dominate NWW-trending post-rift fault groups (Wu et al., 2009; Qiao et al., 2014; Su et al., 2014). Compressive uplift and erosion in seismic profiles as well as negative tectonic subsiding rates suggest that the PRMB began to experience compression from the Philippine plate in the east at approximately 10.5 Ma to 5.5 Ma. The NWW-trending active faults might be related to this stress field (Su et al., 2017). The study area has been tectonically stable since 5.5 Ma. There are some faults crossing the GHSZ (Qiao et al., 2014; Su et al., 2014). Gravity is the main force driving fault activities during the post-rift stage later than 5.5 Ma. In general, the faults have larger normal displacement when the sedimentation rate is higher (Sun et al., 2014). Moreover, the effects of gravity are inferred by strong subsidence and sediment load discrepancies between the depocenter and wing areas. Submarine fans and gravity-flow sand bodies in the later depression phase are the main reservoirs for gas hydrate in the Shenhu area (Su et al., 2015). During the Paleocene and early Oligocene, the Shenhu Formation, Wenchang Formation and Enping Formation were deposited. Since the late Oligocene, the Baiyun sag entered the depression stage, the Zhuhai Formation, Zhujiang Formation, Hanjiang Formation, Yuehai Formation, Wanshan Formation and Qionghai Formation in Quaternary were deposited in succession (Fig. 2). The previous oil and gas discoveries have verified that the main source rocks are the Wenchang Formation and Enping Formation, which have generated large amounts of thermogenic oil and gas

(Zhu et al., 2008; Zhu et al., 2012). In addition, the source rocks developed in the Miocene and their upper formations are in the stage of immature to low maturity, and they can act as source rocks for biogenic gas and sub-biogenic gas (He et al., 2013). Both thermogenic gas and biogenic gas contribute to the migration and accumulation of gas hydrate in the Shenhu area, and the preliminary exploration results have demonstrated that the gas in the gas hydrate is predominantly biogenic gas with some thermogenic gas content (Huang et al., 2010; Zhang et al., 2017; Cong et al., 2018). Furthermore, the buried depth of the Paleogene deposits in the Baiyun sag is substantial with overlying sediment thicknesses of up to 10000 m (Zhu et al., 2008). Many mud diapirs and gas chimneys developed in the Baiyun sag due to the great thickness of sediments and overpressure (Wang et al., 2006; Shi et al., 2009; Yang et al., Su et al., 2017). Combined with the faults that have developed in the Baiyun Sag, these mud diapirs and gas chimneys play an important role in the migration and accumulation of gas hydrate in the Shenhu area (Su et al., 2014, Su et al., 2016; Zhang et al., 2018).

3. Data and Methods 3.1 Technical workflow This study mainly used the PSM method, including burial history, and temperature and pressure evolution history to simulate the gas hydrate-related processes from gas generation to accumulation. The PSM included two main parts (Fig. 3). The first part was the prediction of GHSZ based on relatively lower temperature and high external pressure conditions. The second part was the modeling of gas hydrate accumulation including gas generation, gas migration and gas hydrate formation in the GHSZ. Because gas hydrate is very sensitive to the changes of pressure and temperature which are altered frequently throughout geological time, we developed refined settings to describe the geological space and ages from which PSM simulated the generation and migration of biogenic gas and thermogenic gas, and gas hydrate accumulation and amount. Seismic interpretation of horizons and faults in the depth domain comprised the basic geological model. Then, lithology from the well logs and seismic survey were added to the model to complete the lithology model used in this paper. For the source rock, lithology and geochemistry parameters such as TOC, HI, as well as kinetic modeling were utilized to model the

process of gas generation. In sedimentary rocks, gas generation and migration are usually controlled by buoyancy and capillary force (Thomas et al., 2009). With the proper simulation algorithm, we finally simulated the gas hydrate accumulation process.

3.2 Simulation model development 3.2.1 Structural framework A 2D simulation model was developed from the seismic profile of a typical well, Well A (Fig. 4A) and interpretation based on prior research in the study area(Su et al., 2011; Liang et al., 2013a; Liang et al., 2013b). Based on seismic interpretation, we recognized and interpreted nine horizons. Then, the depth profiles were converted with the time-depth conversion equation below (Fig. 4B):

Z=26.51t3+346.03t2+690.86t……………………………….(1) where Z is the depth (m) and t is the seismic two-way travel time (s). The strata ages were set according to previous studies (Fu et al., 2007; Liang et al., 2015). In summary, the stratigraphic sequence chart of Well A, from the basement to the seafloor, is shown in Table. 1. In addition, the faults in the Well A area were interpreted based on the seismic features. Finally, the structure model of Well A was constructed as shown in Fig. 4B.

3.2.2 Lithology assignment The strata age information was based on the dating data collected from wells drilled during the GMGS3 expedition(Liang et al., 2015), the formation depths acquired from the strata framework model, and the strata division of typical logging wells (Qu et al., 2015). In addition, the lithology of the shallow strata was based on a typical well, Well A, and that of deep formations was based on regional lithological data collected from previous studies, including a comprehensive stratigraphic column of the PRMB as well as other investigations and survey data (Liang et al., 2013; Liang et al., 2015). It must be pointed out that the lithology of formations in the lateral plane was not considered in our simulation model due to the lack of sufficient information from drilled wells. The lithology of the typical wells in the Shenhu area, such as Well A, includes layers

consisting of porous mud, mud and sand, gas hydrate and free gas, from top to bottom. The resistivity is relatively low in the upper mud layers and increases in the middle gas hydrate layer and the lower free gas layer. The density of the gas hydrate layer is higher than that of the free gas layer. The neutron porosity of the gas hydrate layer is slightly higher than that of the mud layers. The permeability of the mud layers, gas hydrate layer and free gas layer increases successively with depth. The sediments of Tertiary and Quaternary occur in the upper layers with a very high mud content (> 90% in Well A). The porosity reaches 86% in the shallow Quaternary sediments and decreases to 70%~80% at the bottom of the Quaternary. The porosity of the lower Tertiary sediments further decreases with depth at a lower rate. The sand content greatly increases to 40%~60% in the Wanshan Formation. The gas hydrate bearing section of Well A is in Wanshan Formation, beginning at the depth of 255 m bsf (meters below the seafloor), with a thickness of approximately 50 m. The lithology of the formations is characterized by silt and mudstone, which accounts for 40% and 60%, respectively. The porosity is approximately 40%, and the permeability is relatively stable at 1~2 mD. The lithology of the stratum that overlaps the Wanshan Formation is similar to the gas hydrate bearing layers in the Wanshan Formation, however, the average porosity is 47%, which is higher than gas hydrate bearing layers because of low formation compaction; moreover, the permeability of the stratum that overlaps the Wanshan Formation is low, with an average of 0.5 mD. The upper mud deposits transition to the mud and sand mixed deposits. However, the thickness of the Tertiary and Quaternary mud deposits is distinctly different. The thickness of the shallow mud deposits in Well A is less because this well is at a ridge between the bathyal to abyssal zones with deposits of canyon channels at both sides. The gas hydrate layer and lower free gas layer both occur in the Wanshan Formation stratum. The thickness of the gas hydrate layer in Well A is approximately 50 m, and the average gas hydrate saturation is approximately 20%. The lithology of the deeper layers (below the Wanshan Formation), based on regional lithological data, ranges from the Shenhu to the deepest layer, the Yuehai Formation, in the order that follows. As the basement in the working area, the Shenhu Formation belongs to the piedmont fluvial facies which contains granite, sandstone and conglomerate. The Wenchang Formation was deposited as a lacustrine facies in which the main lithology is black shale with minimal sand and

mud. The Enping Formation, on the other hand, was deposited in a lake-swamp environment. The main lithology is black mudstone interbedded with gray sandstone. In the upper layer of the Zhuhai Formation, the environment changed to a coastal delta, which deposited as sandstone with interbedded sand-shale. With fluctuation of sea level after deposition of the Zhuhai Formation, the sedimentary environment in the upper layers also varies from coastal delta to shallow sea shelf. The Zhujiang Formation contains marine sand-shale interbedding, with some limestone at the bottom of the layer. The Hanjiang Formation is constituted mainly of light gray shale with a small amount of sand which is similar to the lowest layer, the Yuehai Formation, due to similar sedimentary environments.

3.2.3 Source rock parameters For the source rock, the source lithology and geochemistry parameters of TOC and HI as well as a kinetic model were utilized for simulation of the gas generation process.

3.2.3.1 The kinetics of gas generation selection The kinetics of gas generation is the engine that determines the generated components and the quantity of gas at different temperatures or depth. Wells for gas hydrate in the Shenhu area have validated that biogenic gas generally exists in the shallow deposit (Huang et al., 2010; He et al., 2013). According to the geochemistry data (Su, 2016), we matched a gas generation rate curve to the temperatures (Fig. 11). This curve revealed that the maximum generation of biogenic gas occurs at 34°C. In addition, as revealed by oil and gas exploration in the Baiyun Sag, the source rock for conventional thermogenic gas in the Shenhu area includes both the Enping and Wenchang strata (Zhu et al., 2008; Zhu et al., 2012). Using the results of a rock pyrolysis experiment (Su, 2016), we also built a thermogenic gas kinetic model for the working area (Fig. 12).

3.2.3.2 Original TOC recovery and HI The present TOC is remaining TOC that cannot be directly used in petroleum system modeling. The relevant TOC for gas generation can be estimated based on when the source rock was deposited and the original TOC content. In this study, original TOC of deeper deposits was estimated from an organic carbon recovery coefficient vs. vitrinite reflectance (Ro) chart that was

previously developed for an adjacent region—the Zhu I depression (Fig. 13). For the shallow layers, we considered the current TOC content as approximately equal to the original TOC content because of its lower evolutionary stage. The original TOC can be calculated from measurements of Ro, TOC and Kc values (Table 3). Based on this calculation, the original TOC of the Enping and Wenchang layers was 2.52% and 4.38%, respectively. The organic hydrogen index of the Wenchang layer displays a high value, with an average of 483 mg/g TOC which corresponds with sapropel-mixed kerogen (Su et al., 2010). In contrast, the organic hydrogen index of the Enping layer is lower, with an average of only 146 mg/g TOC (Su et al., 2010). In general, mixed and humus kerogen are the main organic hydrogen types.

3.2.4 Boundary conditions The boundary conditions mainly include the paleowater depth (PWD), temperatures at the sea surface and the sediment-water interface (SWIT), and heat flow (HF) (Table 4; Table 5). At the earliest stage, the study area was in a terrestrial sedimentary environment with shallow water depth. After 23.8 Ma, the sedimentary environment transitioned to transitional facies and marine facies with increasing water depth. Since 16 Ma, the water depth has oscillated greatly and frequently and is the deepest at present (Gao et al., 2006). The study area is located at approximately 19°N. The sea surface temperature (SST) of the study area can be determined according to the atlas of global SST. Moreover, the seafloor temperature depends on the water depth and salinity. For a specific salinity (35‰ in the Shenhu area), the seafloor temperature decreases with increasing water depth. Based on these relationships, the seafloor temperature at the typical well, Well A, can be calculated. According to the relationship between global mean temperature at sea level and the sediment-water interface temperature (Wygrala, 1989; Beardsmore et al., 2001), the seafloor temperature was relatively varied, oscillated greatly since 10 Ma, and is ~4°C at present. Heat flow from the basement is the main source of heat in the upper strata and dominates the thermal history parameters. This study used previous results to preliminarily reconstruct the basal thermal history(Lei et al., 2009; Zhao, 2012).

3.2.5 Simulation and calibration parameters 3.2.5.1 Simulation In sedimentary rocks, gas generation and migration are usually controlled by buoyancy and capillary force (Thomas et al., 2009). With the proper migration algorithm, gas hydrate accumulation can be simulated. The main migration algorithms are flowpath, Darcy flow, invasion percolation and hybrid (Darcy+flowpath). Each algorithm has specific application conditions, advantages and disadvantages. Flowpath is applied when the overall model is “simple”. The flowpath method considers the upward passage of hydrocarbons straight through a carrier bed until a sealing unit is encountered. HC losses or variations in rock properties between the reservoir and the source are not considered. The Darcy method, based on equations of flow through porous media, is usually used for layers with relatively lower permeable. Invasion percolation works well for multi-faulted regions. In contrast, the combined method, hybrid migration, is used to handle different strata in the petroleum system considering the advantages of both flowpath and Darcy methods (Thomas et al., 2009). For this study, we chose the hybrid method as the migration algorithm considering both the long distance (thermogenic gas) and short distance (biogenic gas) migrations, the relatively lower permeability in the deeper layers (source rock in the Wenchang and Enping Formations) and the relatively high permeability in the very shallow and unconsolidated layers.

3.2.5.2 Temperature calibration Temperature is a key parameter for control of the gas hydrate preservation environment. An accurate temperature estimate is very important for accurate modeling of the external gas hydrate preservation environment. After proper adjustment of the heat flow parameter, the simulated temperature in Well A matched very well with the calibration data (Fig. 5A).

4 Results 4.1 Gas Hydrate Stability Zone 4.1.1 Temperature and Pressure Temperature and pressure are the two key factors that control gas hydrate formation and preservation. One-dimensional simulation results reveal that the current temperature is

approximately 4°C on the seafloor and 20°C at the bottom of the Wanshan Formation (Fig. 5A). Similarly, the 2D temperature simulation profile of Well A (Fig. 5B) also shows that the seabed temperature is approximately 4°C. The water depth of the northwest section is shallow, and the sediment profile temperatures are in the range of 7~30°C. The water depth of the southeast section is relatively deeper and the sediment profile temperatures range from 7 to 40°C. Based on these simulation results, it was concluded that the layers between the seafloor and the Wanshan Formation are suitable for gas hydrate preservation based on temperature considerations. The 1D pressure simulation of Well A indicates that the relatively low hydrostatic pressure above 3200 m causes the shallow stratum to lack compaction impacts (Fig. 6A). Furthermore, the pressure evolution curve for the shallow layers indicates that the pressure in the seafloor exceeds 10 Mp, while pressure in the Wanshan Formation is nearly 15 Mp (Fig. 6B). The characteristics of the pressure simulation profile of Well A demonstrate that the pressure in the Wanshan Formation in the northwest zone of the study area is in the range of 11.26~12.83 Mpa, while in the southeast section, the pressure in the Wanshan Formation is 13.83~14.89 Mpa. The pressure in formations shallower than the Yuehai Formation in the northwest is in the range of 10-17 Mp, and the pressure in southeast in the same formations usually ranges from 14 Mpa to 20 Mpa. These higher pressures, based on the pressure simulation results, are favorable for the accumulation of gas hydrate.

4.1.2 GHSZ condition analysis In the deep-sea environment, the GHSZ normally represents a certain depth range below the seafloor. Within this depth range, temperature and pressure are relatively stable. The thickness and distribution of the GHSZ directly control gas hydrate formation and distribution. According to the actual gas hydrate range in Well A, the favorable temperature and pressure conditions above the bottom of the GHSZ can be inferred (Table 2). Based on simulated temperature and pressure of well A, the temperature in the GHSZ ranges from 4°C at the seafloor to 22.5°C at the bottom of the GHSZ. Meanwhile, the pressure in the GHSZ ranges from 12.88 MPa at the seafloor to 15.47 Mpa at the bottom. The thickness of GHSZ is up to 254 m. A temperature and pressure template for study area can be draw with the simulated temperature and pressure results based on standard template (Fig. 7). In this template, the blue

area displays the GHSZ, which has relatively low temperature and high pressure; in contrast, the white area indicates a non-GHSZ, which has relatively high temperature and low pressure. This template is a crucial base for prediction of the thickness and distribution of the GHSZ. After simulation of temperature and pressure in Well A, the gap between the predicted and actual GHSZ thickness is only 1 m (Fig. 8). The free gas reservoir (the red area) exists below the bottom of the GHSZ, in a non-GHSZ. Above the bottom of GHSZ, gas hydrate is easily formed (the blue area) and is in GHSZ zone.

4.1.3 Paleowater depth variation and its effect on the GHSZ Seafloor temperature and pressure are directly controlled by water depth assuming a constant salinity (35‰). Theoretically, the deeper the water depth, the lower the temperature and the higher pressure at the seafloor. To analyze the effect of water depth on GHSZ thickness, we simulated an evolutionary history of the GHSZ in a typical 2D cross-section of Well A (Fig. 9). The GHSZ thickness strictly conformed to the water depth. The deeper the water depth, the greater the GHSZ thickness. Based on the simulated evolutionary history of the GHSZ, the paleowater depth was less than 571 m before 3.88 Ma, during which time there was no GHSZ. After 3.88 Ma, GHSZ began to form and its thickness was greatest when the paleo water depth peaked at 3.66 Ma. Subsequently, the GHSZ thickness decreased as the paleowater depth decreased and vanished at 2.88 Ma. The GHSZ then formed again at 0.139 Ma when the paleowater depth was up to 607 m. The GHSZ thickness subsequently increased rapidly until the present day, as the water depth increased persistently and promptly.

4.1.4 Quantitative relationship between water depth and GHSZ thickness After simulating the evolutionary history of the GHSZ profile, we extracted data for paleowater depth and GHSZ thickness in the typical GHSZ profiles at different geological times (Table 6) After summarizing the paleowater depth and GHSZ sample data for a typical section, we determined the functional relationship between water depth and GHSZ thickness (Fig. 10). Finally, we drew the conclusion that paleowater depth should be greater than 550 m for the presence of a GHSZ. This functional relationship can be applied to GHSZ thickness and distribution predictions

in other similar sedimentary environments, which may guide gas hydrate exploration in other areas.

4.2 Gas source condition and gas generation 4.2.1 Source rock maturity analysis Vitrinite reflectance (Ro) and the transformation ratio (TR) are the key parameters for identifying the maturity of source rock. The simulated results of Well A show Ro in the Wenchang layer ranging from 1.7%~3.6%, which indicates wet gas in the over mature stage. In addition, Ro in the Enping layer is 0.9%~1.7%. Both the Wenchang and Enping layers are at a highly mature stage that currently generates much gas. In contrast, the shallow layers act as source rocks for biogenic gas and generally have very low maturity as expected by their shallow burial depth. The Ro value in the shallow layers generally range from 0.2% to 0.5%, which indicates an immature or lower maturity stage (Fig. 14). Further, the TR parameter in the Wenchang layer is greater than 90%, which indicates that there is no gas generation at present. Compared to Wenchang layer, the Enping layer still possess the gas generation capability with TR values ranging from 70% to 90%. The highest TR value in the shallow layers is in the Lower Wanshan Formation, which generates a large amount of biogenic gas (Fig. 15). In addition, the TR parameters in the shallow Quaternary to middle Wanshan Formations are low, while the TR parameters in the lower Wanshan Formation begin to increase dramatically with depth, generating large amounts of biogenic gas; however, Yuehai and Hanjiang Formations have no ability to generate biogenic gas.

4.2.2 Hydrocarbon generation amount and time analysis 4.2.2.1 Hydrocarbon generation amount The single-well source-rock hydrocarbon generation results (Fig. 16) show that the accumulative total gas generation in the mid-Wanshan Formation in Well A is 0.01 Mton/unit (unit=61.36 m*1 km2), which is low enough to be ignored. The accumulative total gas in the lower Wanshan Formation is 0.1 Mton/unit(unit=98.13 m*1 km2), the accumulative total gas in the Yuehai Formation is 0.26 Mton/unit(unit=99.25 m*1 km2), and the accumulative total gas in

Hanjiang Formation is 0.3 Mton/unit(unit=99.25 m*1 km2). In addition, the accumulative total of thermogenic gas in the Wenchang Formation is 1.74 Mton/unit(unit=95.65 m*1 km2) and the accumulative total of thermogenic gas in the Enping Formation is 0.44 Mton/unit(unit=86.15 m*1K m2). Comparing the biogenic gas generation of the shallow layers to the thermogenic gas generation of the deeper layers in Well A (Fig. 16), we found that the quantity of gas generation in deeper layers is much larger than that in the shallow layers, and the biogenic gas generation above the mid-Wangshan layer is small enough to be ignored.

4.2.2.2 Hydrocarbon generation time The gas generation time of shallow gas is controlled by biogenic gas generation kinetics, TOC and HI. In terms of the gas generation simulation, the accumulative amount of thermogenic gas in the deep formations is large, and the accumulative amount of biogenic gas in the shallow formations is relatively small. According to the simulation results (Fig. 16), late-stage biogenic gas generation began at 13 Ma. The Wenchang Formation generated large amounts of thermogenic gas beginning at 39 Ma and then ceased to generate gas at 23.8 Ma. The Enping Formation generated large amounts of thermogenic gas beginning at 30.5 Ma and then cease to generate gas at 5.06 Ma. The thermogenic gas is from the early stages of thermal maturity, in contrast to the late-stage biogenic gas.

4.3 Gas migration and gas hydrate formation The migration path is the effective route linking the source rock to the reservoir. In the Shenhu area, open faults, regulatory small faults and permeable sand can provide effective drainage conditions(Su et al., 2014; Zhang et al., 2018). Faults in Shenhu area are extremely activate, especially in the Cenozoic layers (Sun et al., 2014; Su et al., 2014). There are many small and short faults in the shallow layers which may be regulatory faults. These kinds of faults, together with the slump deposits in shallow layers, constitute a composite migration system both in vertical and horizontal directions. Most of the faults in Paleogene layer are larger than the faults in Cenozoic layer. Some of these faults can be considered as oil-migration faults (F1, F2, F3, F4), even the basement faults which control the rift deposits (Fig. 4B; Fig. 17). Moreover, the thermogenic gas can migrate vertically through these

large faults from the deep source rocks to the GHSZ. The oil and gas migration and gas hydrate accumulation can be divided into 4 stages (Fig. 17). In the early stage (11.9~7.82 Ma), generated thermogenic oil and gas mainly migrated within the source rocks, although some of the hydrocarbons (HC) could migrate out of the source rock. Biogenic gas generated in the shallow layers mainly migrated to and leaked from the seafloor as there were no obvious cap rocks. In the second stage (7.82~3.66 Ma), faults became active providing favorable migration conditions. A small portion of the HC migrated into the shallow layers through opened faults. Meanwhile, the shallow layers were still in their peak stage of gas generation with most of the generated gas leaking through the seafloor. In the third stage (3.66~0.01 Ma), most of the shallow layers stopped gas generation. Small activate faults, as well as permeable sands collectively allow gas migration again. In the last stage (0.01 Ma~Present), the water depth is generally deeper than 1000 m which is compatible with GHSZ formation conditions. The remaining biogenic gas in the shallow layers and the thermogenic gas from the deeper layers consistently migrates a short distance within the external GHSZ environment, and finally enters the GHSZ in a relatively higher area or in a fault block (Fig. 18). From the gas hydrate accumulation chart for the present, the gas hydrate formation area mainly collects biogenic gas originating in the shallow layers of the Shenhu area. We extracted a the typical 2D section from Well A to confirm the accuracy of simulated gas migration and gas hydrate accumulation results. The extracted 1D model displayed gas hydrate in nearly 50 m thickness with a saturation of nearly 19%, which was consistent with the drilling results (Fig. 19). Based on the above simulating process and the discussion of simulation results, we concluded that our simulation model is reliable, and the simulation results are accurate.

5. Discussion Gas hydrate formation is key in petroleum system modeling. The migration and accumulation of gas hydrate requires favorable conditions, including a rich gas source (thermogenic gas and biogenic gas), effective migration pathways (faults, permeable sands), appropriate temperature and pressure, suitable tectonic conditions (structural highs), fine reservoir physical properties and cap rocks.

5.1 Contribution of different type of gas to gas hydrate formation According to the data analysis of certain wells positions, a substantial amount of free gas exists in the shallow deposits of the working area (Liang et al., 2017). Carbon isotope test values of δ13C ranged from -49.2‰ to -74.3‰ (PDB). The value of δ13C in most of the sample was lower than -57 ‰ (PDB), which confirmed the presence of biogenic gas in the shallow deposits of the Shenhu area(Lei et al., 2009). In addition, wells drilled in deeper water also showed thermogenic gas from deeper layers(Su et al., 2014;Zhang et al., 2017). The volume of thermogenic gas generated in the deeper layers is greater than that of the biogenic gas generated in the shallower layers. The thermogenic gas, which was generated at an earlier geological age, has formed gas hydrate since the GHSZ conditions formed at 3.88 Ma and continue to exist up to the present. There was a geological time gap between the beginning of thermogenic gas migration and GHSZ formation. When the thermogenic gas initially migrated into the shallow layers, most of it was lost through the seafloor. On the other hand, the biogenic gas, which is typically generated near the present time in the shallow layer, matches well temporally with formation of the GHSZ. As such, biogenic gas generation has been much less than thermogenic gas generation, but biogenic gas contributes more to the gas in the gas hydrates in the Shenhu area than thermogenic gas (Zhang et al., 2018; Cong et al., 2018).

5.2 Influence of the reservoir and cap rock features on gas hydrate accumulation In this study, the analysis of Well A initially included physical conditions in reservoir, seal condition of the caprocks, and temperature and pressure conditions. The gas hydrate layer in Well A is located 255 m below the seafloor with a thickness of up to 50 m, which is in the Wanshan layer. Lithology in the gas hydrate layer is constituted of 40% silt and 60% shale. Porosity in this section is approximately 40% with a stable permeability ranging from 1 to 2 mD. The overlying strata have a higher porosity, up to 47%, because of the lower compaction compared to the gas hydrate bearing layer. However, the permeability of the overlying strata has an average value of only 0.5 mD, and these strata contains a lot of calcium which substantially reduces penetration capability. Therefore, the overlying strata, as well as the shale section in the Tertiary and Quaternary layers, provides a good caprock for the layer with gas hydrate by blocking gas migration upward. Below the gas hydrate layer there is a free gas section that is not in the GHSZ,

however the gas cannot transform into gas hydrate due to the low permeability of the gas hydrate layer (Fig. 20). Furthermore, integrating the migration and accumulation simulation results, the gas hydrate mainly accumulates at structural highs or at fault barrier positions. Well A was located at the structural high of a submarine ridge, which was favorable for the accumulation of gas with the cap of the overlapping layers. The gas hydrate formed with the interaction of temperature, pressure and interstitial water.

5.3 Migration and accumulation of gas hydrate After a single well analysis of prospective reservoir and cap rock conditions, we conducted simulations of dynamic gas migration and accumulation in a typical 2D section based on the GHSZ conformation and analysis of gas resource and migration conditions. Before 3.88 Ma, gas was not transformed into gas hydrate as there has no GHSZ existing in the shallow layers. Hydrocarbon migrated as free gas in open faults and permeable sands in relatively shallow layers. Deeper hydrocarbons migrated in the form of liquid (Fig. 17).

6. Conclusions Based on the petroleum system modeling method, we simulated the gas migration and accumulation of Well A in the Shenhu area, and we discussed the process of gas hydrate-petroleum system formation and controlling factors of the distribution of gas hydrate. The conclusions were as follows. (1) The paleowater depth was less than 571 m before 3.88 Ma, and the gas hydrate stability zone (GHSZ) could not form during this age. The GHSZ began to form at 3.88 Ma, and its thickness was greatest when the paleowater depth peaked at 3.66 Ma. Subsequently, the GHSZ thickness decreased as the paleowater depth decreased and vanished at 2.88 Ma. The GHSZ then formed again at 0.139 Ma when the paleowater depth reached 607 m. The GHSZ thickness increased rapidly until the present day as the water depth has increased persistently and promptly. (2) Comparing the biogenic gas generation of shallow layers and the thermogenic gas generation of the deeper layers in Well A, it was found that the quantity of gas generation in deeper layers is much larger than that in the shallow layers. The low amount of biogenic gas generation above the mid-Wanshan layer was ignored.

(3) The shale layer in the Tertiary and Quaternary acts as a good caprock for the gas hydrate layers, blocking the gas migration upward. Below the gas hydrate layer there a free gas layer which is not a suitable GHSZ. (4) There was a geological time gap between the thermogenic gas migration and GHSZ formation. When the thermogenic gas migrated into the shallow layers, most of it was lost through the seafloor. The generation of biogenic gas, which is typically generated close to the present time in the shallow layers, correlates well with the formation of the GHSZ, which explains why biogenic gas largely contributes to the gas accumulated as gas hydrate. Gas hydrate mainly accumulates at structural highs or fault barrier locations which are favorable for the accumulation of gas. Acknowledgements This study was supported by China Geological Survey project for South China Sea Gas Hydrate Resource Exploration (No. DD20160211). The authors express their gratitude to the GMGS for the permission to publish the result of this study. We thank Dr. Jiaxiong He and Dr. Zijian Zhang for providing useful suggestions and comments and also thank editors and reviewers for their comments which improved the manuscript a lot.

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Figure captions

Fig. 1 Geological settings and the position of simulation Well A in the Baiyun Sag, Pearl River

Mouth Basin (Modified from Zhang Wei et al., 2018).

Fig. 2 Major Tectonic Events, Lithology, And Sea Level Change In The Baiyun Sag, Peral River

Mouth Basin(Modified from Zhang Wei et al., 2017).

Fig.3 Work flow of gas hydrate petroleum system simulating

Fig.4 The seismic profile and interpretation across typical well A (A), 2D tectonic model of typical well A in Shenhu Area (B)

Fig.5 Temperature simulation results A: Single well simulation of current simulated temperature, B: 2D simulation of current simulated temperature

Fig.6 Pressure simulation results A: Single well simulation of current simulated pressure, B: 2D simulation of current simulated pressure

Fig.7 Temperature and Pressure Plate of GHSZ in Studying Area

Fig. 8 Comparison Diagram of Simulated GHSZ and Actual GHSZ of Well A A: Simulated GHSZ thickness, B: Actual GHSZ thickness

A 3.88Ma

B 3.66Ma

C 3.42Ma

D 0.256Ma

E 0.139Ma

F Present Day Fig. 9 Evolution History of GHSZ of Typical Section Crossing Well A

Fig. 10 Plate of Paleo Water Depth VS. Gas Hydrate Stability Zone The blue points data come from the extracted data of paleo water depth and GHSZ thickness in the typical GHSZ profiles at different geological time (Table 6).

Fig. 11 Biogenic Gas Kinetic Model in Shenhu Area

Fig. 12 Thermogenic Gas Kinetic Model in Shenhu Area

Fig. 13 The organic carbon recovery coefficient vs. Ro in the adjacent region

Fig. 14 Vitrinite Reflectance Section of Well A in Shenhu Area

Fig. 15 Transformation Ratio Section of Well A in Shenhu Area

Fig. 16 Gas generation comparison between biogenic gas and thermogenic gas in well A a :Biogenic gas abundance in well A ,b: Thermogenic gas abundance in well A

A. 11.9Ma

B. 10.95Ma

C. 7.82Ma

D. 5.30Ma

E. 3.66Ma

F. 0.01Ma

G. Present Day Fig. 17 Evolution History Chart of Gas &Oil Migration and Gas Hydrate Accumulation in Typical Section crossing Well A in Shenhu Area

Fig. 18 Gas Hydrate Accumulation Chart in Typical 2D Section in ShenHu Area (Zoom in)

Fig. 19 Extracted 1D Model Inspection

Fig. 20 Reservoir and Caprock Condition of Gas Hydrate in Well A

Table captions Table 1 Stratigraphic Sequence along the Well A Age[Ma]

Name top

Depth [m]

Thickness [m]

Event type

Layer Name

Seismic Horizon

0

Q2_Top

1252.61

5.21

Deposition

Q2

T0

0.0115

Q2_Bottom

1257.82

10.45

Deposition

Upper Q1

0.126

Upper Q1_Bottom

1268.27

10.44

Deposition

Middle Q1

0.781

Middle Q1_Bottom

1278.71

26

Deposition

Lower Q1

1.806

Lower_Q1_Bottom

1304.71

55.29

Deposition

Upper N2w

2.588

Upper_N2w_Bottom

1360

61.36

Deposition

Middle N2w

3.6

Middle_N2w_Bottom

1421.36

98.13

Deposition

Lower N2w

T2

5.332

Lower_N2w_Bottom

1519.49

496.27

Deposition

N1y

T3

10.2

N1y_Bottom

2015.76

380.86

Deposition

N1h

T4

16

N1h_Bottom

2396.62

326.89

Deposition

N1z

T5

23.8

N1z_Bottom

2723.51

769.37

Deposition

E3z

T6

30

N3z_Bottom

3492.87

904.58

Deposition

E3e

T7

39

E3e_Bottom

4397.45

1530.43

Deposition

E2w

T8

49

E2w_Bottom

5927.88

1072.12

Deposition

E1s

65

E1s_Bottom

7000

T1

Tg

Table 2 Data Sheet of PVT in GHGZ of Well A after temperature calibration. Depth (SSTVD) meter[m]

Temperature Celsius[°C]

Pressure MPa[MPa]

1253.00 1304.71 1390.81 1457.00 1476.91 1507.00

4.00 9.25 15.84 19.25 22.27 22.52

12.88 13.41 14.29 14.97 15.17 15.47

Table 3 Original TOC Recovery in Deeper Source Rock.

Source Rock Enping Wenchang

Ro(%) 1.2 2.62

Kc(v/v) 1.15 1.49

Measured TOC(%) Original TOC(%) 2.19 2.52 2.94 4.38

Table 4 Upper Boundary Condition Age (Ma)

0 0.1397 0.2561 0.4151 0.5609 0.8404 1.1873 1.521 3.6601 5.3078 8.3109 10.2 16 23.8 30.5 39 41.6 49 56.5

Paleo Water Depth (SSTVD) meter[m]

1252.61 607.14 345.24 184.94 95.45 29.83 35.71 65.62 608.52 130.95 452.38 150 197 175 25 5 50 5 2

Table 5 Lower Boundary Condition Age (Ma)

Heatflow (mW/m^2)

0 2.48 5.4 23.3 32 56.5

52 60.5 59.5 67.5 56.5 51.5

Temperature in Seafloor Celsius[°C]

4 5 14 19.12 20.12 21.13 21.13 20.13 5 19.14 10.23 19.27 19.67 20.41 23.19 24 24.26 25.33 26.02

Table 6 Extracted Data from Typical GHSZ Profiles Paleo Water Depth (M)

985.17 1018.54 1053.34 1094.37 1118.51 1180.71 1211.08 1271.84 1313.77 1237.89 1251 1334.16 607.14 582.91 608.51 570.62 985.17 1018.54 1053.34

GHGZ Thickness (M)

107.35 105.11 111.48 107.55 123.79 122.97 165.63 238.74 221.62 232.55 248.14 236.09 30.91 32.1 46.82 17.63 107.35 105.11 111.48

Age in GHSZ Profiles (Ma)

0 0 0 0 0 0 0 0 0 0 0 0 0.1397 3.4221 3.6601 3.8877 0 0 0

Graphical abstract

Highlights 

The first gas hydrate petroleum systems modeling has been conducted in the gas hydrate production region in the South China Sea;



There is a gap between main migration phase of the thermogenic gas and formation period of GHSZ in the Shenhu Area;



Generation of the biogenic gas in the recent past correlates with the formation of GHSZ;



A function relationship between water depth and GHSZ thickness built in this study can be used to guide gas hydrate exploration in other areas.