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Volume 31 Issue 1
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Hydrocarbon Generation, Migration, and Accumulation in the Eocene Niubao Formation in the Lunpola Basin, Tibet, China: Insights from Basin Modeling and Fluid Inclusion Analysis

  • The Eocene Niubao Formation is the primary research target of oil exploration in the Lunpola Basin. Crude oil was extracted from Well Z1 on the northern margin of the basin in 1993. In this study, an integrated evaluation of the source rock, geothermal, and maturity histories and the fluid inclusion and fluid potential distributions was performed to aid in predicting areas of hydrocarbon accumulation. Due to the abundance of organic matter, the kerogen types, maturity, and oil-sources correlate with the geochemical data. The middle submember of the second member of the Niubao Formation (E2n2-2) is the most favorable source rock based on the amount of oil produced from the E2n2-3and E2n3-1reservoirs. One- and two-dimensional basin modeling, using BasinMod software, shows that the E2n2-2source rock started to generate hydrocarbon at 35-30 Ma, reached a maturity of Ro=0.7% at 25-20 Ma, and at present, it has reached the peak oil generation stage with a thermal maturity of Ro=0.8% to less than Ro=1.0%. By using fiuid inclusion petrography, fiuorescence spectroscopy, and microthermometry, two major periods of oil charging have been revealed at 26.1-17.5 and 32.4-24.6 Ma. The oil accumulation modeling results, conducted by using the Trinity software, show a good fit of the oil shows in the wells and predict that the structural highs and lithologic transitions within the Jiangriaco and Paco sags are potential oil traps. KEY WORDS:Niubao Formation, Lunpola Basin, source rocks, basin modeling, fluid inclusions, hydrocarbon migration and accumulation, petroleum geology.
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Hydrocarbon Generation, Migration, and Accumulation in the Eocene Niubao Formation in the Lunpola Basin, Tibet, China: Insights from Basin Modeling and Fluid Inclusion Analysis

    Corresponding author: Jiaren Ye, jrye@cug.edu.cn
  • 1. Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China University of Geosciences, Wuhan 430074, China
  • 2. Branch of Exploration Company, SINOPEC, Chengdu 610041, China

Abstract: The Eocene Niubao Formation is the primary research target of oil exploration in the Lunpola Basin. Crude oil was extracted from Well Z1 on the northern margin of the basin in 1993. In this study, an integrated evaluation of the source rock, geothermal, and maturity histories and the fluid inclusion and fluid potential distributions was performed to aid in predicting areas of hydrocarbon accumulation. Due to the abundance of organic matter, the kerogen types, maturity, and oil-sources correlate with the geochemical data. The middle submember of the second member of the Niubao Formation (E2n2-2) is the most favorable source rock based on the amount of oil produced from the E2n2-3and E2n3-1reservoirs. One- and two-dimensional basin modeling, using BasinMod software, shows that the E2n2-2source rock started to generate hydrocarbon at 35-30 Ma, reached a maturity of Ro=0.7% at 25-20 Ma, and at present, it has reached the peak oil generation stage with a thermal maturity of Ro=0.8% to less than Ro=1.0%. By using fiuid inclusion petrography, fiuorescence spectroscopy, and microthermometry, two major periods of oil charging have been revealed at 26.1-17.5 and 32.4-24.6 Ma. The oil accumulation modeling results, conducted by using the Trinity software, show a good fit of the oil shows in the wells and predict that the structural highs and lithologic transitions within the Jiangriaco and Paco sags are potential oil traps. KEY WORDS:Niubao Formation, Lunpola Basin, source rocks, basin modeling, fluid inclusions, hydrocarbon migration and accumulation, petroleum geology.

0.   INTRODUCTION
  • The Lunpola Basin covers an area of approximately 3 600 km2 in northeastern Tibet, southwestern China. Petroleum exploration in the Lunpola Basin commenced in the early 1950s (Li, 1954); however, exploration activities were limited until 2015 (Fan et al., 2015) because of the harsh working conditions in Tibet. Prior to 2018, over 67 exploratory wells had been drilled in the Lunpola Basin and 8 oil fields had been discovered, but only a small number of wells had sufficient production for economic exploitation (Jiang et al., 2018; Zhang, 2011; Wang et al., 2006; Chen and Du, 1996).

    Though the Lunpola Basin is in the low-exploration stage, several studies have shown that the Lunpola Basin is one of the most valuable references for understanding the dynamics of hydrocarbon accumulation in the inner basin and in the adjacent basins on the Qinghai-Tibet Plateau (Fu et al., 2016; Ma et al., 2015a; Sun et al., 2013; Wang et al., 2011a; Rowley and Currie, 2006). Petroleum surveys reveal that the source rocks are mainly located in the second and third members of the Eocene Niubao Formation (Liu et al., 2017; Li et al., 2016; Yuan and Xu, 2000). The source rocks of the > 900-m-thick Niubao Formation mainly consist of dark gray mudstone and silty mudstone (Lei et al., 1996). Based on geochemical and logging data, Liu et al. (2017) determined that the high quality source rocks (TOC > 1.0%) are more than 400 m thick. Previous studies of hydrocarbon generation in the Lunpola Basin have mostly been one-dimensional (Pan et al., 2016; Liu et al., 2001; Xu et al., 1996), so only a few of these studies were able to accurately determine the accumulation period. Thus, the hydrocarbon accumulation and migration characteristics of the Niubao Formation have not been quantitatively characterized.

    In this paper, new geochemical data for oil and rock samples are compared with the data collected by the Branch of Exploration Company, SINOPEC and previous studies (Wei et al., 2017; Ma et al., 2015b; Wang et al., 2011b). The results of this analysis are then used to identify the major source rock in the Lunpola Basin. In addition, to better predict favorable areas for hydrocarbon accumulation in the Lunpola Basin, we reconstructed the petroleum generation, migration, and accumulation processes using basin modeling and the petroleum charging history determined from fluid inclusion studies. The purposes of this paper are as follows: to evaluate the Niubao Formation source rock and identify the main source rock interval in the Lunpola Basin; to reconstruct the burial, thermal, and maturation histories of the source rocks; to determine the petroleum charging history using an integrated fluid inclusion investigation; and to predict petroleum migration pathways and favorable accumulation areas based on the source rock evaluation, fluid inclusion investigation, and basin modeling. The results of this study will provide an important reference for reducing the risks of petroleum exploration in this region.

1.   GEOLOGIC SETTING
  • The Lunpola Basin is located in Bange County, the Tibet Autonomous Region, China. It is bounded by the Bangonghu-Nujiang suture zone to the north and by the Malajiong-Pengco suture zone to the south (Ai et al., 1998). The basin is about 220 km from east to west and 15-20 km from north to south (Fig. 1a). From north to south, the tectonic units include the northern thrust nappe belt, the central depression belt, and the southern thrust and uplift belt (Fig. 1b). The main study area is the central depression belt, which comprises three sags from west to east, the Jiangriaco, Jiangjiaco, and Paco sags.

    Figure 1.  (a) The location of Lunpola Basin in the Tibet Autonomous Region, modified from Fu et al. (2012), (b) simplified geologic map of the Lunpola Basin, showing the tectonic units, the locations of boreholes, and the sections used in the modeling in this study, and (c) the tectonic evolution from the Eocene to present along section AA', modified from Fan et al. (2015). YTS. Yarlung-Tsangpo suture zone; MPS. Malajiong-Pengco suture zone; BNS. Bangonghu-Nujiang suture zone; Ⅰ. northern thrust nappe belt; Ⅱ1. Jiangriaco sag; Ⅱ2. Jiangjiaco sag; Ⅱ3. Paco sag; Ⅲ. southern thrust and uplift belt.

    The tectonic evolution of the Lunpola Basin was mainly controlled by the Bangonghu-Nujiang suture zone (Wei et al., 2017). Based on fault activity, individual tectonic characteristics, and previous studies (Wu et al., 2018; Zhao, 2011; Gonsalves et al., 2000; Luo, 1993; Xu et al., 1983), the tectonic evolution of the Lunpola Basin can be divided into three stages from the Eocene to the present (Fig. 1c). The first stage is characterized by faulting during the Eocene (50.0-35.4 Ma). The second stage is characterized by depression during the Oligocene (35.4-23.3 Ma). The third stage is characterized by uplift reconstruction from the Late Oligocene to the present (23.3-0 Ma).

    Figure 2 shows the generalized stratigraphic column from the Eocene to the Oligocene in the central part of the Lunpola Basin. The basin's basement is composed of Cretaceous marine carbonates, clastics, basal volcanics, and volcanic clastic rocks (Deng et al., 2012; Lei et al., 1996). The overlying ~3 000-m-thick Cenozoic sediments of the Lunpola Basin mainly include the Eocene Niubao Formation and the Oligocene Dingqing Formation (Sun et al., 2014; Du et al., 2004; Xu, 1980).

    Figure 2.  Generalized Eocene-Oligocene stratigraphic column for the Lunpola Basin, illustrating the tectonic evolution stages, the paleoclimate (Ma et al., 2015a), lake level fluctuations (Sun et al., 2014), and the petroleum system. Dotted lines indicate unconformities, and the red line indicates the studied interval.

    The Niubao Formation, which can be seen in a 2 000 m rock outcrop, is widespread and frequently exposed in the western and northern parts of the basin (Fig. 1b). From the bottom of the formation to the top, the Niubao Formation can be subdivided into three members (E2n1, E2n2, and E2n3) and mainly consists of purple siltstone and mud shale sandwiched between glutenite and tuff. The sedimentary facies fluctuate between fluvial to lacustrine several times, indicating multiple transgression and regression events. The Niubao Formation was deposited in a subtropical, temperate environment (DeCelles et al., 2007; Xia, 1982).

    The Dingqinghu Formation is mainly distributed in the central and eastern parts of the basin (Fig. 1b). The Dingqing Formation is about 1 000 m thick and is composed of oil shale and gray mudstone alternating with sandstone (Fu et al., 2012). Like the Niubao Formation, the Dingqinghu Formation can be subdivided into three members (E3d1, E3d2, and E3d3), which were deposited in a warm, humid, and temperate lacustrine environment.

    Previous studies of petroleum source rocks have shown that the oil source rocks of the Niubao Formation are superior to the source rocks of the Dingqinghu Formation, which are mainly oil shale (Xie et al., 2018; Ma et al., 2017; Du et al., 2016). In the Lunpola Basin, three regional lacustrine mudstones within the middle and upper submembers of the second member of the Niubao Formation (E2n2-2 and E2n2-3) and the lower submember of the third member of the Niubao Formation (E2n3-1) were identified as potential oil-generating source rocks (Liu et al., 2017; Yuan and Xu, 2000; Gu et al., 1999; Xu et al., 1996). The reservoir units in the study area, which are located in the Niubao Formation, are clastics and dolomites (Ai et al., 1999; Luo et al., 1999). The seal rocks are located in the Dingqinghu Formation and in the second and third members of the Niubao Formation (E2n2 and E2n3) (Du et al., 2004) (Fig. 2).

2.   MATERIALS AND MODELS
  • The main data used for source rock evaluation and to determine the oil-source rock correlation include the TOC, chloroform bitumen "A, " total n-alkanes analysis of the oil and source rocks, and elemental analysis of the kerogen. The analyses were conducted by the Exploration Branch of SINOPEC. Additional data were collected from the literature (Ma et al., 2015b; Sun et al., 2014) and were originally obtained by the Wuxi Experimental Research Center of SINOPEC and the Institute of Exploration and Development of the Jianghan Oilfield Company. To further understand the oil charging history of this area, a total of 38 sandstone samples from the second and third members of the Niubao Formation (E2n2 and E2n3) were collected from wells XL4, XL5, XL8, Z1, W1, and W2 in the central depression belt of the Lunpola Basin (Fig. 1b). The depth of the samples ranged from 1 578.9 to 1 987.8 m. These core samples were analyzed at the Key Laboratory of Tectonics and Petroleum Resources, China University of Geosciences (Wuhan).

    The BasinMod software and Trinity modeling software were used in this paper. BasinMod was used to help evaluate the hydrocarbon generation potential (Zhang et al., 2017; Guo et al., 2012; Cao et al., 2011), including burial history, geothermal history, and organic matter maturity history reconstructions. Due to the small amount of exploration in the Lunpola Basin (lack of 3D seismic survey and rare drilling), the Trinity software, the basic principle of which is the fluid potential (England et al., 1987; Dahlberg, 1982; Hubbert, 1953), was used to model the hydrocarbon secondary migration paths in the study area.

    Burial history reconstruction is a basic element in hydrocarbon generation analysis. The measured thicknesses of the formations and the amount of erosion used in the paper were based on the results of previous studies (Jia et al., 2015; Ma et al., 2013). The absolute ages of the depositional and erosional events were determined from the chronostratigraphic framework of the basin (Fig. 2). Due to the complicated genetic dynamics of the Lunpola Basin (Ma et al., 2013; Zhao, 2011; Ai et al., 1998), the porosity-depth model of Falvey and Middleton (1981) used for the compaction correction was adopted. This model can be expressed as follows

    where φ is the porosity, φ0 is the initial porosity, k is the compaction factor, and z is the burial depth.

    The 1D BasinMod software defaults to the initial porosity and compaction factor of a pure lithology, e.g., shale/mudstone, siltstone, sandstone, dolomite, and limestone. In the two-dimensional model, the lithologies are modified based on the sedimentary facies. The mixed lithology and sealing ability (non-dimensional) of the sedimentary facies measured in the two-dimensional simulation are summarized in Table 1.

    Facies Sandstone (%) Siltstone (%) Shale (%) Limestone (%) Dolomite (%) Thermal conductivity (W/m·℃) Sealing ability
    Alluvial plain 40 30 20 0 10 2.72 50
    Delta plain 25 30 35 0 10 2.39 80
    Alluvial 35 20 45 0 0 2.32 100
    Delta front 8 5 75 2 10 1.96 160
    Shallow lake 20 12 57 4 7 1.79 800
    Lake 5 11 84 0 0 1.38 800
    Fault 5 5 90 0 0 1.25 1 000

    Table 1.  Main lithotypes and their matrix thermal conductivity for different sedimentary facies used in the modeling

    The burial history and heat-flow significantly influence the geothermal history of sedimentary basins. The current-heat flow was calculated from the underground geothermal gradient, which was determined from the thermal conductivity of the rock (Table 1) and the corrected bottom hole temperature (BHT). The paleo-heat flow, which is difficult to determine, was determined from the tectonic evolution of the region. The Transient Heat Flow model of Jarvis and Mckenzie (1980), which considers the vertical transmission of heat and the tectonic activity caused by sudden thermal events, has been widely used to calculate the current and paleo heat flows.

    The Easy%Ro model of Sweeney and Burnham (1990), which is considered to be the most accurate and effective method for calculating the organic matter maturity history, is incorporated in the BasinMod 1D software. The good agreement between the measured and calculated Ro values implies that the thermal maturity model can be used in the study area.

    The basic principle of the Trinity software is based on fluid potential (England et al., 1987; Dahlberg, 1982; Hubbert, 1953). Hubbert (1953) first proposed the formula, which can be used to determine oil migration pathways and accumulation in sedimentary basins, for calculating the mechanical energy per unit mass. With the following system of equations

    where Ф is the fluid potential (J/kg), g is the acceleration caused by gravity (9.81 m/s2); z is the altitude (m); p is the reservoir pressure (Pa); ρ is the fluid density (kg/m3); and q is the fluid velocity (m/s).

    In this study, the locations of the structures and lithologic traps were determined based on the sedimentary facies, faults, and sandstone distribution. The sealing ability of these parameters is presented in Table 1, in which the higher number is the higher sealing ability.

3.   RESULTS AND DISCUSSION
  • In this study, the source rocks were evaluated based on geochemical indicators such as the abundance, type, and thermal maturity of the organic matter (OM). TOC is the most common index used to determine the OM abundance of source rocks (He et al., 2010). Based on the statistical data for 117 samples from 7 wells, the TOC contents of the three potential source rock intervals (E2n2-2, E2n2-3, and E2n3-1) in the Lunpola Basin range from 0.14 wt.% to 6.02 wt.%. The highest TOC ranges from 0.6 wt.% to 1.0 wt.% with an average of 0.79 wt.% (Fig. 3a), which indicates that the source rock has a fair petroleum-generation potential (Cao et al., 2009; Fu and Zhang, 2005).

    The kerogen type within the Lunpola Basin was determined using elemental analysis (Tissot and Welte, 1984). The kerogen in the basin has a relatively high H/C atomic ratio, ranging from 0.74 to 1.56, and a relatively low O/C atomic ratio, ranging from 0.05 to 0.30 (Fig. 3b), indicating the predominance of Type Ⅰ-Ⅱ1 oil-prone kerogen. These results are consistent with the results of previous studies (Ma et al., 2015b; Han et al., 2014; Wang et al., 2011a, b).

    Figure 3.  (a) Histogram of the total organic carbon (TOC) distribution in the Niubao Formation; (b) Discrimination diagram of the organic matter types in the Niubao Formation, i.e., the H/C atomic ratio versus the O/C atomic ratio. E2n2-2: the middle submember of the second member of the Niubao Formation; E2n2-3: the upper submember of the second member of the Niubao Formation; E2n3-1: the lower submember of the third member of the Niubao Formation.

    The distribution of the total carbon number of n-alkanes of the oil and source rocks in the Niubao Formation may reflect the oil-source rock correlation (Li et al., 2016; Lu et al., 1997). The oil produced from unit E2n2-3 in Well XL4 and unit E2n3-1 in Well Z1 is similar to the source rocks of unit E2n2-2 in Well Z1 (Fig. 4a), while the oil produced from unit E2n3-2 in Well XL5 and unit E2n3-1 in Well XL4 has a similar carbon number distribution of n-alkanes to that of the E2n3-1 source rocks in Well XL4 (Fig. 4b). These results indicate that there are two complete oil-reservoir models, the self-generation model and the self-reservoir model with a lower generation zone and an upper reservoir. Due to the strong influence of tectonic activity, the shallower oil reservoirs, e.g., E2n3, were damaged by fault activity, whereas the preservation conditions of oil reservoir E2n2 are better due to its greater burial depth and minimum fault activity. In conclusion, these features indicate that unit E2n2-2 is a good source rock, and units E2n2-3 and E2n3-1 are good oil reservoirs.

    Figure 4.  (a) Relative abundance versus carbon number of n-alkanes for the crude oils extracted from wells Z1 and XL1 and the E2n2 source rock from Well Z1. (b) Relative abundance versus carbon number of n-alkanes from the crude oils extracted from wells XL5 and XL4 and the E2n2 source rock extracted from Well XL4.

    Based on the above analysis, E2n2-2 is a good potential source rock interval in the Lunpola Basin due to its higher OM abundance and Type Ⅰ-Ⅱ1 oil-prone kerogen. Additionally, an oil-source comparison study suggests that the crude oils in the Lunpola Basin are mainly derived from the E2n2-2 source rock, while prediction of the favorable source rock distribution (Liu et al., 2017) indicates that E2n2-2 has an average thickness of 223 m, making it the thickest and most widely distributed source rock in the Lunpola Basin. Thus, the most favorable source rocks are in unit E2n2-2 rather than units E2n2-3 and E2n3-1.

  • To better understand the hydrocarbon generation history of the source rocks within units E2n2-2, E2n2-3, and E2n3-1, three representative seismic lines (BB', CC', and DD') and three typical wells (XL1, W1, and W2), which are located on these seismic lines in the central depression belt, were selected to reconstruct the burial, thermal, and maturity histories. Line BB' and Well XL1 are located in the northeastern part of the Jiangriaco sag; line CC' and Well W1 are located in the southeastern part of the Jiangjiaco sag; and line DD' and Well W2 are located in the thick center of the Paco sag (Fig. 1b). The database used to model the geothermal and maturity histories includes vitrinite reflectance (Ro) and the BHT data.

    The source rock maturity is the commonly used as an indicator of vitrinite reflectance (Ro) (Hunt, 1996; Tissot and Welte, 1984). The model used in this study calculates the vitrinite reflectance using the Easy%Ro method of Sweeney and Burnham (1990), which can be used to reconstruct the organic matter maturity history. In this modeling, the good connection between the measured data and the calculated Ro and temperature curves implies that the models are suitable for use in the study area (Fig. 5).

    Figure 5.  Calibration of the thermal and maturity modeling of wells XL1, W1, and W2, showing a good correlation between the measured data and the calculated temperature and vitrinite reflectance curves.

    The current heat flow can be calculated from the thermal conductivity and subsurface geothermal gradients, which are confirmed by the BHT. The calculated current heat flow values of wells XL1, W1, and W2 are 77.00, 70.27, and 66.75 mW/m2, respectively. In addition, the results of the paleo-heat flow modeling are affected by the tectonic evolution of the Lunpola Basin. The modified Jarvis and Mckenzie (1980) algorithm, which was used with typical values for the evolution of the basin, was used to calculate the paleo-heat flows.

    Based on the differences in the thermal history and the burial history of the tectonic sag, the maturity of the source rocks in wells XL1, W1, and W2 is different (Fig. 6). In Well XL1, which is located in the Jiangriaco sag, the oil generation (Ro=0.5%) of the E2n2-2 source rock began at a depth of 1 350 m at 31 Ma, while that of the E2n2-3 source rock began at a depth of about 1 500 m at 21 Ma. Currently, both the E2n2-2 and E2n2-3 source rocks are in the low maturity stage (Ro=0.5%-0.7%), whereas the E2n3-1 source rock has not yet reached the maturity level required for oil generation (Ro=0.5%).

    Figure 6.  The burial, thermal, and maturity histories of wells XL1, W1, and W2 and the current maturity distribution characteristics of Section BB', Well W1 in CC', and Well W2 in Section DD' in the Lunpola Basin. The locations of the section lines and wells are shown in Fig. 1b.

    Compared with the other two wells, Well W1 is the deepest with a depth of 2 410 m. The E2n2-2 source rocks entered the oil window (Ro=0.5%) at 34.2 Ma at a depth of 1 800 m, reached a maturity of Ro=0.7% at 27 Ma at a depth of 1 800 m, and reached their peak maturity (Ro=1.0%) at 19 Ma at a depth of 2 700 m; the lower part of the source rock is currently in the late oil generation stage (Ro=1.0%-1.3%), while the upper part of the source rock is in the main oil generation stage (Ro=0.7%-1.0%). The E2n2-3 source rock entered the low maturity stage (Ro=0.5%) at approximately 30 Ma at a depth of 1 680 m; entered the main oil generation stage (Ro=0.7%-1.0%) at 24 Ma at depth of 2 160 m; and at present, it is still in this stage. The E2n3-1 source rocks reached the oil generation threshold (Ro=0.5%) at 29.5 Ma at a depth of 1 620 m, entered the main oil generation stage (Ro=0.7%-1.0%) at 22 Ma at a depth of 2 100 m, and it is presently still in this stage.

    The newest drilled Well W2, which is located in the Paco sag, reveals that the E2n2-2 source rock entered the oil window (Ro=0.5%) at 35.5 Ma at a depth of 1 420 m; reached a maturity of (Ro=0.7%) at 21 Ma at a depth of 2 390 m; and at present, it is still in the main oil generation stage (Ro=0.7%-1.0%). The E2n2-3 source rock entered the oil generation stage (Ro=0.5%) at 38.5 Ma at a depth of 1 450 m; reached a maturity of Ro=0.7% at 19.8 Ma at a depth of 2 300 m; and it is presently in the main oil generation stage (Ro=0.7%-1.0%). The E2n3-1 source rock entered the oil window (Ro=0.5%) at 38 Ma at a depth of 1 470 m; and at present, it is in the early oil generation stage (Ro=0.5%-0.7%). Therefore, the E2n2-2 and E2n2-3 source rocks have a higher thermal maturation and hydrocarbon generation process than those of the E2n3-1 source rock.

    Figure 6 shows the model of the present maturity of two-dimensional geologic sections BB', CC', and DD'. The two-dimensional maturity model is built on top of the precise one-dimensional maturity results. At present, in Section BB', most of the E2n2-2 source rock has reached a maturity of Ro=0.5%-1.0%, only the bottom of the E2n2-2 source rock has reached the late oil generation stage (Ro=1.0%-1.3%), and most of the E2n2-3 and E2n3-1 source rocks have reached a maturity of Ro=0.5%-1.0%. At present, in Section CC', most of the E2n2-2 source rock has reached a maturity of Ro=0.5%-1.0%, only the bottom of the E2n2-2 source has reached the late oil generation stage (Ro=1.0%-1.3%), and most of the E2n2-3 and E2n3-1 source rocks have reached a maturity of Ro=0.5%-1.0%. In Section DD', all of the E2n2-2, E2n2-3, and E2n3-1 source rocks have a similar thermal maturation of Ro=0.5%-1.0%.

    In conclusion, the three main source rocks have a similar thermal maturation and hydrocarbon generation process, except for E2n2-2 source rock, which has a higher maturity than the other two source rocks in the central part of the Lunpola Basin.

  • In field of petroleum research, fluid inclusion technology has been widely used to recreate the hydrocarbon migration and entrapment process (Liu et al., 2016; Wu et al., 2016; Feng et al., 2010; Ping et al., 2010; Oxtoby, 2002; George et al., 2001; Stasiuk and Snowdon, 1997). In this study, 38 core samples (Fig. 7) collected from 6 wells in the Niubao Formation sandstone reservoir in the Jiangjiaco and Paco sags were analyzed in order to measure the fluid inclusion petrography, fluorescence, and microthermometry.

    Figure 7.  Petrography, fluorescence, fluorescence spectra, and λmax versus QF535 of the fluid inclusions from Well W1.

  • The micropetrographic observations indicate that the fluid inclusions in the samples from the Lunpola Basin are mainly located in the micro-fractures and overgrowths of quartz grains and rarely within the calcite cement (Fig. 7). Based on our microscopic observations, the fluid inclusions are mainly elliptical, rectangular, and circular in shape. The fluid inclusions are 5-15 μm long and 8 μm wide. In order of most to least abundant, the three principal types of fluid inclusions identified are as follows: (1) the abundant aqueous inclusions appear black or dark grey under transmitted light (Figs. 7a, 7b); (2) the less abundant hydrocarbon-bearing inclusions appear dark grey or grey under transmitted light (Fig. 7c); and (3) the rare pure hydrocarbon inclusions appear as single brown inclusions under transmitted light (Fig. 7e).

  • The oil inclusions have a variety of fluorescent colors under UV-light. The two main colors (Figs. 7d, 7f) are yellow and white-blue (visual study). However, visual identification of the fluorescence colors can differ based on the person observing (George et al., 2002; Oxtoby, 2002). A total of 45 oil inclusions from 16 samples from Well W1 were analyzed to determine the fluorescence spectral parameters of the main peak wavelength (λmax) and the modified red-green quotient (QF535). The fluorescence spectroscopy results indicate a significant difference between the blue and yellow oil inclusions, which have λmax of 495 and 540 nm, respectively (Fig. 7). The QF535 value can be used as an indicator of the organic matter maturity (Si et al., 2013; Ping et al., 2012; Caja et al., 2009). It is defined as the ratio of the confining area between spectral wavelengths 720-535 and 535-420 nm (Eq. 3). The larger the QF535 value, the lower the maturity of the crude oil inclusions

    As can be seen from the plot of λmax versus QF535 (Fig. 7), two oil charging events occurred, which correspond to λmax of 490-525 and 535-551 nm, originating from organic matter of nearly the same maturity.

  • Analysis of the modified red green quotient indicates that there are two crude oils with different maturities in the region. During hydrocarbon migration, the coexisting oil and aqueous inclusions can simultaneously be captured (Liu et al., 2016; Guo et al., 2012; Feng et al., 2010; Chen et al., 2009). So, homogenization temperature of the fluid inclusions from Well W1 along with the burial history and isotherm curves (Fig. 8) in order to determine an accurate hydrocarbon charging time.

    Figure 8.  Hydrocarbon charging history of the Niubao Formation reservoir based on data from the Lunpola Basin fluid inclusions.

    The homogenization temperatures of the coexisting oil and aqueous inclusions in the study area range from 90 to 150 ℃. The homogenization temperatures of the hydrocarbon inclusions range from 90-100 and 120-140 ℃, while those of the aqueous inclusions and coeval oil inclusions range from 90-110 and 110-140 ℃, respectively.

    By projecting the average homogenization temperature ranges onto the burial history and isotherm curves of the other five wells, the timing of the hydrocarbon charging events can be determined (Fig. 8). The results show that the two main oil charging event occurred at 26.1-17.5 and 32.4-24.6 Ma. This information is helpful in determining the main oil accumulation phases.

  • Secondary petroleum migration was modeled in the E2n2-2 interval, which is the major source rock and has a good match for the reservoirs and sealing beds (Fig. 2). As mentioned above, the hydrocarbon charging event in the Lunpola Basin occurred at 32.4-17.5 Ma. The tectonic reversal, which occurred after the Late Oligocene, changed the direction of hydrocarbon migration and caused redistribution of the hydrocarbon accumulation (Zhao, 2011; Ai et al., 1998). Therefore, secondary petroleum migration pathways in the E2n2-2 carrier bed were modeled at 30 and 25 Ma using the Trinity software.

    The modeling results (Fig. 9) illustrate that many factors, e.g., the sedimentary facies, faults, structures, and source rock properties, significantly influence the secondary migration directions. The modeling results show that at 30 and 25 Ma, most of the predicted favorable oil and gas areas are located in confirmed oil and gas wells, while most of the dry wells, which are far from the hydrocarbon-generative location, are not located on the oil and gas migration pathway, except for Well XL4. Well XL4 most likely has oil and gas because the well is located on the edge of the central depression belt, which makes it easy for the oil and gas to spread, and thus, the oil and gas are more obvious in this well.

    Figure 9.  Modeling results showing the hydrocarbon migration pathways and accumulation at the bottom of E2n2-2 at (a) 25 Ma and (b) 30 Ma in the Lunpola Basin.

    Figure 9 shows the petroleum migration pathways and accumulation of the E2n2-2 reservoir in the central depression belt from 30 to 25 Ma. As can be seen, the petroleum migration and accumulation characteristics at 30 and 25 Ma are quite similar. The secondary hydrocarbon migration directions in the E2n2-2 carrier at 30 and 25 Ma are both away from the central depression belt in the Lunpola Basin through the southern parts of the Jiangriaco sag and the western and eastern parts of the Paco sag. The three favorable hydrocarbon generation zones in the northern thrust nappe, which has poor preservation conditions, are not discussed in this paper.

    In the southern part of the Jiangriaco sag, oil migrated from the southern depocenter to the northern favorable reservoir area, which is dominated by delta plains. However, the petroleum migration pathways and oil and gas accumulation are not concentrated in the southern part of the Jiangriaco sag due to the faults in this area. In the western and eastern parts of the Paco sag, there are numerous petroleum migration pathways because in this area, two hydrocarbon generation areas converge into various oil accumulation areas. The migration simulation results also show that at 30 and 25 Ma, there were more than five favorable oil and gas accumulation zones in the southern and southeastern parts of the Paco sag. Due to closing of the hydrocarbon-generation zones the and favorable sedimentary areas, the oil accumulation zones in the southern and southeastern parts of the Paco sag are much better charged than other high-risk oil and gas exploration areas. In the southeastern part of the Jiangjiaco sag, the area around Well W1 is the best hydrocarbon migration belt due to the hydrocarbon generation zone in the center of the Paco sag.

    When all of the above factors are taken into consideration, it can be concluded that the center of the Jiangriaco sag and the southern and southeastern parts of the Paco sag are the main exploration targets, which is in agreement with the results of previous studies (Fan et al., 2015; Zhang, 2011).

  • The hydrocarbon generation and migration modeling results of this study reveal that three main factors control the distribution of oil accumulation zones, including source rocks, faults, and traps (Fig. 10).

    Figure 10.  Hydrocarbon migration and accumulation model for unit E2n2-2 in the Lunpola Basin.

    There are three sets of potential Eocene source rock intervals in the Lunpola Basin, E2n2-2, E2n2-3, and E2n3-1. However, the E2n2-3 and E2n3-1 source rocks have shallow burial depths, low TOC values, and low maturities (Ro=0.5%-0.7%). Therefore, due to its higher thermal maturity and more prolific and volumetrically important source rocks, unit E2n2-2 is the primary oil source and has major hydrocarbon generation.

    Previous studies (Ai et al., 1999; Lei et al., 1996) found that many faults formed in the central and eastern parts of the basin due to intense tectonic activity. Thus, the faults in the central and eastern parts of the central depression belt are more active than those in the west; therefore, the preservation conditions of the Jiangriaco sag are better than those of the Jiangjiaco and Paco sags. Additionally, based on the oil shows and oil reservoirs observed in the vertical layers, the faults played an important role in vertical hydrocarbon migration.

    Both structural and lithologic reservoirs were discovered in this region. In addition to the structural traps, numerous small sand bodies were also found in this area, indicating a relatively low hydrocarbon exploration potential and limited economic value. Both the structural traps and lithologic traps were mostly pierced by a series of nearly vertical tensional-shear faults, which formed in the Jiangjiaco and Paco sags after the Late Oligocene, destroying the reservoirs (Fig. 10). Therefore, most of the oil reservoirs discovered in these areas have abundant heavy oil and bitumen resources. In contrast, there are few faults in the center of the Jiangriaco sag, which contains favorable sedimentary facies (delta plain, delta front, and fan delta). Therefore, due to their better generation, accumulation, and preservation of oil, the structural and lithologic traps in the center of the Jiangriaco sag are favorable oil prospecting targets.

4.   CONCLUSIONS
  • In this study, we assessed the hydrocarbon generation, migration, and accumulation in the Lunpola Basin using basin modeling and fluid inclusion analysis. Currently, there is no commercially valuable crude oil exploitation in the basin; however, this study provides an important quantitative evaluation for use in oil exploration. Based on the results of our analysis, we draw the following conclusions.

    (1) Based on the geochemical data, the organic matter abundances, types, and maturities of the source rocks in the Lunpola Basin were evaluated. The results of this analysis indicate that the E2n2-2 source rocks have a high organic matter abundance, Type Ⅰ-Ⅱ1 kerogen, and a high maturity, and it is the largest contributor to oil accumulation in the study area. The oil-source correlation illustrates that the E2n2-3 and E2n3-1 oils were generated from the E2n2-2 source rocks, and the E2n2-2 source rocks are the thickest and most widely distributed. In summary, unit E2n2-2 is the major source rock in the central depression belt of the Lunpola Basin.

    (2) Hydrocarbon geothermal and maturity modeling indicates that the E2n2-2 source rocks began to generate hydrocarbon at about 35-30 Ma; reached a maturity of Ro=0.7% at around 25-20 Ma; and at present, they are in the peak oil generation stage with a thermal maturity of Ro=0.8% to less than Ro=1.0%.

    (3) Based on the petrography, fluorescence, and microthermometry analyses of fluid inclusions, two major oil charging events occurred at 26.1-17.5 and 32.4-24.6 Ma.

    (4) The secondary petroleum migration pathways at 30 and 25 Ma accurately predicted the petroleum occurrences in the self-generating and self-preserving E2n2-2 system. The migration modeling results and the goodness of fit with the oil shows in the wells indicate that there are three favorable oil accumulation zones, which are primarily located in the structural and lithologic traps within the Jiangriaco and Paco sags.

ACKNOWLEDGMENTS
  • This study is financially supported by the National Science and the Technology Major Project (Nos. 2016ZX05024002-003, 2017ZX05032-001-004, 2016ZX05027-001-005), the National Science Foundation of China (No. 41672136) and the Branch of Exploration Project, SINOPEC (No. G0800-14-KK-169). We would like to thank the Branch of Exploration Company, SINOPEC which provides background geological data and permission to publish results. The final publication is available at Springer via https://doi.org/10.1007/s12583-019-1211-3.

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