Controls of paleo-overpressure, faults and sedimentary facies on the distribution of the high pressure and high production oil pools in the lower Triassic Baikouquan Formation of the Mahu Sag, Junggar Basin, China

Journal of Petroleum Science and Engineering 176 (2019) 232–248

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Controls of paleo-overpressure, faults and sedimentary facies on the distribution of the high pressure and high production oil pools in the lower Triassic Baikouquan Formation of the Mahu Sag, Junggar Basin, China

T

Chong Fenga,b,∗, Dewen Leic, Jianhua Quc, Junzhou Huod a

Faculty of Petroleum, China University of Petroleum-Beijing at Karamay, Karamay, 834000, Xinjiang Province, PR China State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum-Beijing, Beijing, 102249, PR China c Xinjiang Oilfield Company, PetroChina, Karamay, 843000, Xinjiang Province, PR China d Changqing Oilfield Company, PetroChina, Xian, 710000, Shanxi Province, PR China b

A R T I C LE I N FO

A B S T R A C T

Keywords: Oil accumulation mechanisms Glutenite reservoirs Overpressure conduction The lower triassic Mahu sag

Large quantities of high-pressure oil pools have been discovered in the glutenite reservoirs with low porosity and low permeability in the Lower Triassic Baikouquan Formation of Mahu sag, Junggar Basin. Overpressure has a close relationship with the generation of high-production oil pools in the Baikouquan Formation. In areas with abnormally high overpressure, the daily oil and gas production of single wells is high. Geological and geophysical analysis, and two-dimensional (2D) basin models have been used to explain the mechanisms of overpressure in the Baikouquan Formation and to establish a hydrocarbon accumulation model of high pressure and high production oil pools. Based on the hydrocarbon accumulation model, the main controlling factors of high pressure and high production oil pools generation have been summarized, and the favorable accumulation zones have been predicted. The results show that the chief reasons for overpressure are disequilibrium compaction and the pressure conducted through faults. In the hydrocarbon accumulation model of high pressure and high production oil pools, the overpressure compels faults that connect source rocks with reservoirs to open and become the valid conductive systems, and the oil-bearing overpressure fluid charges into the Baikouquan Formation along faults and forms high pressure oil pools in the frontier facies glutenite reservoirs near the faults. The main controlling factors of oil accumulation are the paleo-overpressure of Fengcheng Formation source rock during the main hydrocarbon migration stage (the Early Cretaceous, before 146 Ma), the faults on the ancient nose-like belts of structural uplifts and the fan-delta frontier facies glutenite reservoirs in the Baikouquan Formation. According to the accumulation model, the fan-delta frontier facies glutenite reservoirs of the Baikouquan Formation can be divided into three sections based on the favorability of oil accumulation I, II and III, from good to bad.

1. Introduction The Mahu sag, which is located in the Junggar Basin, has the richest oil and gas resources (Zhao et al., 1999; Lei et al., 2014; 2017). In recent years, many important discoveries have been made in the Lower Triassic Baikouquan Formation glutenite reservoirs in the slope of the sag. The oil and gas exploration in the Mahu sag has a long history. In 1995, the first oil field of the People's Republic of China, the Karamay field, was found in the fault belts of the sag margin (Wang et al., 2002). Later, and for a long time, the oil exploration around the fault belts in the sag margin succeeded continually, many oil fields were found on the Kebai-fault zone and Wuxia-fault zone, and the proven oil and gas

∗

reserves reached 111 × 108 barrels (Lei et al., 2014). The hydrocarbon generation ability of source rocks inside the sag is better than that on the sag margin. The glutenite reservoirs deposited in alluvial fan and fan delta environments are closer to high-quality source rocks. Faults connect source rocks with reservoirs. Most faults have not broken through the regional cap rocks of Jurassic and Cretaceous. The vertical migration and preservation conditions of hydrocarbon are good, and fault-lithology traps are developed. So the hydrocarbon exploration potential may be larger inside the sag (Wang et al., 2005). In the 1980s, Chinese geologists had pointed to the slope of the Mahu sag as the direction of oil and gas exploration. However, the slope still was not appreciated sufficiently because of the deep burial depth and the poor

Corresponding author. China University of Petroleum-Beijing at Karamay, Anding Road 18, Karamay, 834000, Xinjiang Province, PR China. E-mail address: [email protected] (C. Feng).

https://doi.org/10.1016/j.petrol.2019.01.012 Received 30 May 2018; Received in revised form 13 November 2018; Accepted 3 January 2019 Available online 11 January 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.

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Fig. 1. Location map of the Mahu sag in the Junggar basin, northwestern China. (a) Map showing the location of the Junggar basin in China. (b) Map showing the location of the study area in the Junggar basin. The large structural units are based on Tao et al. (2016). (c) Map showing the tectonic units around the Mahu sag. The limits of the structural units are based on Imin et al. (2016). The displayed oil pools are the proven oil pools, and not all the wells are displayed. The black solid line curves show the 2D basin modeling sections.

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Fig. 2. Generalized stratigraphy and representative geochemistry of source rocks in the Mahu sag region. TOC = total organic carbon; PG = pyrolysis-derived generation. potential S1 + S2, which are the amounts of free hydrocarbons and cracking hydrocarbons of organic matter in the rock (mg HC/g rock) based on RockEval pyrograms; HI = hydrogen index [(S2 × 100)/TOC]; Ro = vitrinite reflectance.

of overpressure (Barker, 1972; Bishop, 1979; Bethke, 1985; Spencer, 1987; Luo and Vasseur, 1992; Xiomara and Eric, 1996; Hao et al., 1996; Mark and Richard, 1997a,b; Bitzer, 1999; Magnus, 2001; Wangen, 2001; Waples, 2001; Zeng and Liu, 2006; Tingay et al., 2009; Zeng et al., 2010; Bjorlykke et al., 2010; Tingay et al., 2013; Zhang, 2013): ① reducing pore spaces, including tectonic compression and disequilibrium compaction; ② increasing pore-fluid volume through hydrocarbon generation, thermal cracking of crush oil to gas, diagenesis and the increase of formation temperature; and ③ other mechanisms that include pressure conduction, buoyancy, and so on. Among those mechanisms, tectonic compression, disequilibrium compaction and hydrocarbon generation are the most typical reasons for overpressure generation in sedimentary basins around the world. Overpressure plays an important role in the generation, migration, accumulation and preservation of oil and gas (Law and Dickinson, 1985; Hunt, 1990; Law, 2002; Putnam and Ward, 2001). Hao et al. (1996, 2007) suggested that overpressure can suppress the thermal evolution of organic matter and expand the depth range and time window for hydrocarbon generation. Bethke (1989) and Xiomara and Eric (1996) believed that overpressure contributes to the reopening of the previously sealed faults, which improves hydrocarbon migration efficiency. Hunt (1990), Neuzil (1995), Yu and Lan (1996), Lee and Williams (2000) and Osborne and Swarbrick (1997) suggest that using the dynamic combination of overpressure and buoyancy, oil and gas can overcome capillary resistance and migrate from the overpressure zones to the low-pressure

physical properties of reservoirs (Tang et al., 2014; Yu et al., 2014). In recent years, the hydrocarbon exploration has become increasingly difficult at the fault belts of the sag margin, the exploration in the slope was then taken seriously, and a significant breakthrough was made at the glutenite reservoirs in the Lower Triassic Baikouquan Formation (Kuang et al., 2014; Lei et al., 2014; 2017; Imin et al., 2016; Zhi, 2016). In 2012, the M131 well was drilled in the oil reservoir in the western slope. In 2014, the M19 well in the western slope and the M21 and M22 wells in the northern slope were all drilled in the oil reservoir, which further extended the oil and gas range in the western and northern slope. In the same year, the Mh4 well was drilled in the oil reservoir in the southern slope, and the D10 and M21 wells both had good oil and gas displays in the eastern slope. In 2016, the D13 well was drilled in the oil reservoir in the eastern slope. Up to now, wells have been drilled in the Lower Triassic Baikouquan Formation oil reservoirs in all directions of the slopes of the Mahu sag, the favorable exploration zones are approximately 2800 km2, and the total oil and gas resources are more than 74 × 108 barrels. The wells reveal a new big oil (gas) field in the Junggar basin. The Mahu sag has overpressure, and the overpressure plays an important role in the generation of high production oil pools in the Lower Triassic Baikouquan Formation in the slopes. When the formation pore fluid pressure is higher than the hydrostatic column pressure of the same depth, overpressure occurs, which can commonly be found in sedimentary basins (Hunt, 1990, 1996). There are three types of origins 234

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rock almost covers all areas of the sag, and the thickness is between 50 and 300 m, with a characteristic of thinning from north to south of the sag (Tao et al., 2016; Lei et al., 2017). The Fengcheng Formation source rock is lacustrine mudstone, and alkaline minerals are widely distributed in the source rock formations (Lei et al., 2017). The Fengcheng Formation source rocks are possibly high-quality source rocks generated in the alkali lake environment (Cao et al., 2015; Chen et al., 2016). The main source materials are bacteria and algae, and their hydrocarbon generating potential is large (Wang et al., 2002). The average total organic carbon (TOC) is 1.3%, the average pyrolysis-derived generation potential (PG) S1 + S2 is 4.9 mg HC/g rock (which is the amount of free hydrocarbons and cracking hydrocarbons of organic matter in the rock based on Rock-Eval pyrograms), and the primary organic matter type is Type II kerogen (150 < HI < 160 mg HC/g TOC, where HI is the hydrogen index [(S2 × 100)/TOC]) (Tao et al., 2016). The evolution of the Lower Permian Fengcheng Formation source rocks is currently in the mature-highly mature generation stage (Ro is 0.6%∼2.1%), with oil generation (Wang and Kang, 1999; Cao et al., 2005). The source rocks in the Carboniferous and the Lower Permian Jiamuhe Formation are widely distributed in the research area. The Carboniferous source rocks are tuffs with an average TOC of 1.2%, an average PG of 0.75 mg HC/g rock, and with predominantly Type III kerogen (HI < 150 mg HC/g TOC) (Tao et al., 2016). The evolution of the Carboniferous source rocks is currently in the highly mature stage with gas generation (Wang and Kang, 1999; Cao et al., 2005). The Lower Permian Jiamuhe Formation source rocks are tuffs that have an average TOC of 1.5%, average PG of 1.3 mg HC/g rock, and a primary organic matter type of Type III kerogen (HI < 150 mg HC/g TOC) (Tao et al., 2016). The evolution of the Lower Permian Jiamuhe Formation source rocks is currently in the highly mature stage, with gas generation (Wang and Kang, 1999; Cao et al., 2005). The stratigraphy is based on Tao et al. (2016), Carroll et al. (1990), Cao et al. (2005) and Wu et al. (2014). The formation thickness obtained by drilling is based on Lei et al. (2017). The deposystem is based on Liu et al. (2016). The source rocks and geochemical data are based on Tao et al. (2016). The Middle Permian Lower Wuerhe Formation source rocks are lacustrine mudstones with an average TOC of 1.5%, a PG of less than 0.6 mg HC/g rock, and a main organic matter type of Type III kerogen (HI < 150 mg HC/g TOC) (Tao et al., 2016). The evolution of the Middle Permian Lower-Wuerhe Formation source rocks is currently in the highly mature stage, with gas generation (Wang and Kang, 1999; Cao et al., 2005). The oil and gas in the Lower Triassic Baikouquan Formation of the Mahu sag mainly originate from the Fengcheng Formation source rock. The carbon isotopes of crude oil in the Baikouquan Formation are all less than −28‰ (Fig. 3a) and are generated from typical oil-type kerogen. The Pr/Ph values of crude oil are all less than 1.3 (Fig. 3a), reflecting that the source rocks were generated in the reducing environment. The carbon isotopes of natural gas (Fig. 3b) show that it is a sapropel-type natural gas. In addition, Wang and Kang (1999), Cao et al. (2005) and Imin et al. (2016) researched that the gammacerane indexes of crude oil in the Baikouquan Formation all exceed 0.2. These characteristics manifest as crude oil generated in the alkali lake environment. The distribution of tricyclic terpanes C20, C21, C22 have an increasing tendency. These characteristics are the same as those of the source rocks in the Fengcheng Formation, which illustrates that the oil and gas in the Lower Triassic Baikouquan Formation mainly originated in the Fengcheng Formation source rocks.

zone. Overpressure in reservoirs can support more vertical stress and delay diagenetic evolution, which enables reservoirs to keep more primary pores and increases porosity and permeability. Overpressure can also improve the sealing capacity of the cap rocks (Mann and Mackenzie, 1990). Overpressure has an important impact on the generation of high production oil pools in the Lower Triassic Baikouquan Formation in the Mahu sag slopes. Overpressure oil pools with high daily production of single well have priority for exploration. For example, the pressure coefficient in the Baikouquan Formation of the M18 well is 1.74, its daily oil production is 246 barrels and natural gas production is 0.69 × 104 m3 (24.4 × 104 ft3). The pressure coefficient in the Baikouquan Formation of the Mh1 well is 1.45, its daily oil production is 292 barrels, and natural gas production is 0.25 × 104 m3 (8.8 × 104 ft3). What are the overpressure origins in these high pressure and high production oil pools? How does the overpressure control the generation and distribution of oil pools? This article states the accumulation mechanisms of high pressure and high production oil pools in the Lower Triassic Baikouquan Formation through a discussion of the overpressure origins and the overpressure oil-bearing fluid migrated upward and accumulation. 2. Geological setting 2.1. Tectonic setting Junggar basin, which is located in the northern XinJiang Uygur Autonomous Region of China, is a large petroliferous basin. The Mahu Sag research region is located in the northwest of the Junggar Basin, is distributed from northeast to southwest, and has an area of up to approximately 5000 km2 (Lei et al., 2014). The northwestern slope of the sag from north to south is adjacent to the Wu-Xia fault zone, Ke-Bai fault zone and Zhongguai uplift. The southeastern slope of the sag from north to south is adjacent to the Shiying uplift, Yingxi sag, Sangequan uplift, Xiayan uplift and Dabasong uplift (Fig. 1). At present, the Mahu Sag is a gently sloping structure, with a monocline tilting towards the southeast. The average dip angle in the Triassic Baikouquan Formation in the sag is 2°∼4°(Lei et al., 2014). 2.2. The characteristics of petroleum geology The vertical strata are obtained according to the drilling data (Fig. 2). Carboniferous, Mahu sag was the marine-continental transitional environment, and the sedimentary rocks were tuff. In the early Permian, the sedimentary environment changed into lakes with volcanoes, and the rock types of this stage were tuff, mudstone, siltstone, sandstone and dolomite. During the Middle and Late Permian, the lake area was shrinking, and many large and small alluvial fans appeared around the Mahu sag. The sedimentary rocks were of various types, including mudstone, siltstone, sandstone and glutenite. From the beginning of Triassic, the lake area gradually increased. The Lower Triassic was mudstone and glutenite deposited in fan delta environment. The Middle Triassic was mudstone, argillaceous siltstone and conglomerate deposited in delta and shallow lake environment, and the Upper Triassic was mudstone and argillaceous siltstone deposited in lacustrine environment. By Jurassic, Mahu sag was gradually arid. The Jurassic and Cretaceous were conglomerate, sandstone, siltstone, mudstone and coal deposited in braided river and fan delta environments. 2.2.1. Sources rocks and origins of oil and gas There are several hydrocarbon source rocks in the Mahu Sag (Fig. 2), including the Carboniferous through Lower Permian Jiamuhe Formation and the Fengcheng Formation, and the Middle Permian Wuerhe Formation (Wang and Kang, 2001; Cao et al., 2005; Tao et al., 2016; Chen et al., 2016). Among them, the Lower Permian Fengcheng Formation is the primary source rock. The Fengcheng Formation source

2.2.2. Reservoirs and trap type The reservoir lithology in the Triassic Baikouquan Formation of the Mahu sag is glutenite, and its depositional environment is fan-delta. There are six fans developing in the margin of the Mahu sag (Lei et al., 2017). Lacustrine mudstones were deposited between those fans. Single 235

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Fig. 3. Hydrocarbon geochemistry of the Lower Triassic Baikouquan formation, Mahu sag. (a) Carbon isotopes and Pr/Ph of crude oils. (b) Carbon isotopes of gas.

Formation pressure coefficient in the Mh1 well is 1.45 and that in the B24 well is 1.05. It illustrates that the faults are closed and can be used as the lateral occlusion conditions. Fault-lithology traps were formed by the closed faults and the lenticular glutenite reservoirs (Fig. 1c).

2.2.3. High pressure and high production wells in the Baikouquan Formation Formation pressure data were obtained from drill stem tests (DSTs), and the formation pressure coefficient was calculated by this equation:

pc =

P ρw gh

Where pc is formation pressure coefficient; P is formation pressure, Pa; ρw is density of water, 1 × 103 kg/m3; g is acceleration of gravity, N/kg; h is burial depth, m. Most of the wells in the Jurassic and Upper-Middle Triassic have not found obvious overpressure (Fig. 5, the pressure coefficient greater than 1.2 is defined as the obvious overpressure). In the Baikouquan Formation, obvious overpressure has been found, the maximal pressure coefficient could reach 1.8, and the formation pressure was between 20 and 80 MPa. Obvious overpressures were also found in the Permian and Carboniferous strata, and their maximal pressure coefficient was close to 1.8. The daily oil and gas productions of wells in the Lower Triassic Baikouquan Formation with overpressure are large. Statistics of the daily production and formation pressure coefficient of the Baikouquan Formation in the single well are reported (Table 1), the daily oil-gas production was converted into daily oil production (1000 m3 natural gas ≈ 7.4 barrels oil), and the relationship between pressure coefficient and daily production was obtained. The daily production of single wells in the Baikouquan Formation is positively correlated with the reservoir overpressure (Fig. 6). The physical properties of the Baikouquan Formation reservoirs are poor, and the daily production of single wells is low. The oil pool in the Baikouquan Formation, from which single well daily production is more than 150 BOE (barrel of oil equivalent), is considered to be the high-efficiency oil pool. The pressure coefficient of the high-efficiency oil pool is commonly greater than 1.4. It can be seen that overpressure zones are favorable for finding high-efficiency oil pools. It is necessary to analyze the origins of overpressure and its relationship with the high pressure and high production oil pools in order to generate a hydrocarbon accumulation model.

Fig. 4. Mud content - permeability plots in different sedimentary subfacies of the Lower Triassic Baikouquan formation, Mahu sag.

fans can be divided into the fan-delta plain facies glutenite and the fandelta frontier facies glutenite. The sorting of the fan-delta frontier facies glutenite is better with lower mud content than the fan-delta plain facies glutenite. The porosities of the fan-delta frontier facies glutenite are between 5%∼12%(Lei et al., 2014), the average value is approximately 10%, and the permeabilities are between 0.1 and 10 × 10−3 μm2 (Fig. 4) and primarily exceed 1 × 10−3 μm2. It is a low porosity and low permeability glutenite reservoir. Compared to the fan-delta frontier facies glutenite, the physical properties of the fan-delta plain facies glutenite are poor, with poor sorting and higher mud content. The porosity is less than 5% (Imin et al., 2016). The permeability is less than 0.1 × 10−3 μm2 (Fig. 4). The fan-delta plain facies glutenite correlates well with the mudstone between the fans, which has a sealing effect for the recent hydrocarbon reservoirs. The preserving conditions of oil pools in the Lower Triassic Baikouquan Formation of the Mahu sag is good, and the main trap type is fault-lithology trap. Above the Baikouquan Formation, the main lithology in the Middle ∼ Upper Triassic Karamay ∼ Baijiantai Formations is lacustrine mudstone, the thickness of which is approximately 500–900 m, and it can be considered as a regional caprock (Lei et al., 2017). The internal architecture of the Baikouquan Formation with tight mudstone between the fans and the fan-delta plain facies glutenite constitute the lateral occlusion conditions. With the migration of sedimentary fans, the reservoirs were surrounded by these tight rocks, and forming lenticular glutenite reservoirs. At present, faults cut through these lenticular glutenite reservoirs, but the pressure coefficients of reservoirs on both sides of the faults are different. For example, on both sides of the Dazhuluogou Fault (Fig. 1c), the Baikouquan 236

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Fig. 5. Pressure coefficient-depth and pressure-depth plots in the Mahu sag. Measured pressure. data were obtained from DSTs, and the pressure coefficients were calculated using the pressure data.

3. Discussion of the accumulation mechanisms of high pressure and high production oil pools

all basins are equipped with such conditions-hydrothermal pressurization and diagenesis pressurization-but overpressure does not exist in all of these basins. Through experiments and numerical simulations, Luo and Vasseur (1992) considered that hydrothermal pressurization contributes little to overpressure generation in the sedimentary basins. Swarbrick and Osborne (1998) and Swarbrick et al. (2004) believed that overpressure would hinder the process of diagenesis, and the diagenesis mechanism on the generation of overpressure remains unclear. Excluding these factors, we discuss disequilibrium compaction, oil

3.1. Overpressure generation mechanisms of the lower Triassic Baikouquan Formation The Lower Triassic Baikouquan Formation of the Mahu Sag is a nonhydrocarbon source rock formation. Therefore, the hydrocarbon generation is not the main reason for overpressure generation. Almost

Table 1 Oil test results of some of the wells in the Mahu sag. Well

Depth (m)

Pressure coefficient

Pressure (Mpa)

Temperature (°C)

Daily oil production (barrels)

Daily gasproduction ( × 103m3/ × 103ft3)

Oil equivalent (BOE)

Oil test conclusion

Distance from faults (km)

Ah011 Ah013 Ah1 Ah2 Ah6 Ah7

3848 3798 3848 3310 3878 3624.5

1.63 1.51 1.67 1.19 1.68 1.09

61.49 56.35 62.86 38.60 63.95 38.57

88.50 87.35 88.50 76.13 89.19 83.36

319 114 221 39 98 2

7/247.2 0.97/34.26 2.08/73.45 0/0 0/0 0/0

371 121 236 39 98 2

0.62 2.08 1.38 5.00 0.46 6.54

Ah8 D13

3276 4229.5

0.99 1.76

31.87 72.87

75.35 97.28

38 111

0/0 3.07/108.42

38 134

D15 Fn15 Fn40l M13

4247 2744 2561 3106

1.70 1.11 1.10 0.83

70.80 29.82 27.61 25.16

97.68 63.11 58.90 71.44

198 64 74 17

2.12/74.87 0.51/18.01 0/0 5.21/183.99

214 68 74 56

M1 34 M136

3169 3297

1.07 1.13

33.29 36.63

72.89 75.83

58 17

6.18/218.24 1.68/59.33

104 30

M15 M18 M19 Mh012 Mh1 X54 X89 X93 X94 Yb1

3048 3898 3522 3453 3284 2294 2452 2727 2792 3784

1.17 1.74 1.24 1.57 1.45 0.90 0.87 0.78 0.91 1.29

35.06 66.47 42.66 53.13 46.57 20.24 20.98 20.90 24.89 48.01

70.10 89.65 81.01 79.42 75.53 52.76 56.40 62.72 64.22 87.03

60 246 73 103 292 20 52 26 25 38

14.65/517.36 6.9/243.67 3.43/121.13 0/0 2.5/88.29 0.37/13.07 0/0 6.75/238.37 0/0 0/0

168 297 99 103 310 22 52 75 25 38

Yb4

3691

1.36

49.07

84.89

42

0.18/6.36

43

Oil layer Oil layer Oil layer Oil layer Oil layer Oily water layer Oil layer Oil-water layer Oil layer Oil layer Oil layer Oil bearing layer Oil layer Oil bearing layer Oil layer Oil layer Oil layer Oil layer Oil layer Oil layer Oil layer Oil layer Oil layer Oil-water layer Oil layer

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7.54 0.77 0.92 3.85 5.38 1.69 2.31 1.54 4.15 0.92 5.69 3.23 1.31 4.62 6.15 4.62 2.31 1.54 1.69

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the shallow burial depth, the overpressure is weak. The basin modeling simulation result shows that the overpressure origin in the Lower Triassic Baikouquan Formation is closely related to burial depth. According to the evolutions of the excessive pressure, burial depth, porosity and temperature of the Mh18 well near the sag center and D9 well in the edge of sag in the eastern Baikouquan Formation (Fig. 7), the overpressure in the Baikouquan Formation first started to appear in the Jurassic and peaked in the late Cretaceous. Since the Paleogene, the overpressure seemed to be lower. The evolution of overpressure is most closely connected with burial history, and the increasing overpressure followed the increasing burial depth. As the porosity of rock continues to decrease, it is more difficult to discharge the pore water, and the effect of burial depth on overpressure is even more distinct. Geophysical data confirms the presence of disequilibrium compaction in the Lower Triassic Baikouquan Formation. The disequilibrium compaction manifests itself such that the acoustic logging value of rock is bigger, the density logging and seismic velocity are lower, and the resistivity logging are lower. According to the acoustic, density and resistivity loggings data, the rock differences may cause the differences in geophysical data, and in order to rule out such differences, we extracted the acoustic, density and resistivity loggings data corresponding to mudstone and analyzed the characteristics of the logging curves. The acoustic travel-time values in most wells in the Baikouquan Formation are abnormally larger, the density values are abnormally lower, and the resistivity values are abnormally lower. For example, the wells B22, Mh1 and Mh3 (Fig. 8). This suggests that disequilibrium compaction truly exists in the Lower Triassic Baikouquan Formation of the Mahu Sag and is the main reason for overpressure generation.

Fig. 6. Pressure coefficient-day produced plots of the Lower Triassic Baikouquan formation, Mahu sag.

cracking to gas, tectonic compression and pressure conduction. 3.1.1. The main factors of overpressure generation 3.1.1.1. Disequilibrium compaction. The mechanism of disequilibrium compaction generating overpressure relates directly to the deposition and compaction process; the pore water of rapidly deposited tight sediments does not discharge in time. It supports part of the overlying skeleton's gravity, which hinders the normal decrease of the porosity and permeability and generates overpressure. Thus, the conditions of overpressure generation are tight sediment and rapid deposition rate. The Mahu Sag is located near the center of the basin's subsidence and has conditions of disequilibrium compaction. According to research undertaken by Wang et al. (2005), in the Permian, the Mahu sag was located in the subsidence center. In the Triassic, it was close to the subsidence center because the subsidence center had moved south. The glutenite in the Lower Triassic Baikouquan Formation of the Mahu sag has poor physical properties. The sediment deposited with multiple layers of gluten and lacustrine mudstone is totally tight, which provided the conditions for disequilibrium compaction and overpressure generation. From the Middle Triassic to the Upper Triassic, the lacustrine mudstone is the main rock. It has conditions for generating disequilibrium compaction and preserve overpressure. However, due to

3.1.1.2. Pressure conduction. If the origin of overpressure in the Lower Triassic Baikouquan Formation only results from disequilibrium compaction, the overpressure should increase through the increasing burial depth and lithology changes from the northwest margin to the southeast margin of the sag. However, in some zones, the changes in overpressure do not conform to the rule. For example, from the B22 well at the margin of the sag to the Mh1 well at the slope area of the sag and then to well Mh3 near the center of the sag (the locations of the wells are shown in Fig. 1c), DSTs formation pressure data show that the formation pressure coefficient in the Mh3 well in the Lower Triassic

Fig. 7. Evolutions of the excessive pressure, burial depth, porosity and temperature in the Lower Triassic Baikouquan formation, Mahu sag. The red solid line curve represents the excessive pressure. The black segmented curve represents the burial depth. The black point curve represents the porosity. The yellow solid line curve represents the temperature. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) 238

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Fig. 8. Depth profiles of well logging parameters of mudstone to overpressure, including sonic, density and resistivity from wells B22, Mh1 and Mh3 in the Mahu sag. The locations of these wells are shown in Fig. 1c. The solid red lines are normal trend lines that were calculated from the Cretaceous and Upper Jurassic. The blue dashed lines represent the deviations from the normal values of the Lower Triassic Baikouquan formation. Sonic is the traveling time of sound per unit distance. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.)

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Fig. 9. Relationships between pressure coefficient, daily production of a single well and the distance from fault transmission systems of the Baikouquan formation in the Mahu sag.

the geophysical data, such that the degree that the acoustic travel-time curve deviated from the normal trend line is approximate. The acoustic travel-time in the Mh1 well is divided clearly into upper and low two segments through the depth curve and are nearly parallel (Fig. 10). Using the equilibrium depth method to calculate the formation pressure of the Mh1 well and the actual measured formation pressure is similar to predicting formation pressure at a depth of 3284 m. The predicted overpressure in different depth strata less than 3284 m is equal to approximately 17 MPa (Fig. 10). This shows that the Mh1 well conforms to the characteristics of overpressure conduction. The AK1 well, M15 well and others have similar characteristics.

Baikouquan Formation is 1.19, which is far less than 1.45 of the Mh1 well and 1.25 of the B22 well. This illustrates that disequilibrium compaction is not the only cause of overpressure. Overpressure is more obvious near the faults. The abnormal overpressure is clear in the Mh1 well and B22 well, which are near the Dazhuluogou Fault, while the overpressure is not obvious in the Mh3 well, which is far from the Dazhuluogou Fault (the locations of the wells and the Dazhuluogou Fault are shown in Fig. 1c). Based on the relationship between pressure coefficient and the distance from fault transmission systems, the farther away from the fault, the smaller the upper limit value of pressure coefficient is in the reservoir (Fig. 9a, data shown in Table 1). It can be seen that overpressure thus seems to be spatially related to the distributions of faults. Near the faults, pressure conduction may be the main factor for overpressure generation in shallow strata. From a comparison of oil production, it was found that the Mh1 well in the Baikouquan formation obtained a high production of oil and gas, which suggested that it had been discharged with oil-bearing fluid, and the poor oil and gas showing in Mh3 well indicated that it has not been discharged with the large-scale oil-bearing fluid. Based on the relationship between the daily production of a single well and the distance from fault transmission systems, the farther away from the fault, the smaller the upper limit of the daily production of a single well is in the reservoir (Fig. 9b, data shown in Table 1). The process of oil-bearing fluid charging must cause overpressure to conduct from deep strata to shallow strata, thus leading to the overpressure in shallow strata being rather large. Overpressure conduction can be reflected by well geophysical data. After overpressure is conducted along faults and reaches a balance, the overpressure values are same at the different depth strata near the faults. Luo (2004) suggested that this characteristic can be reflected in

3.1.2. The secondary factors of overpressure generation 3.1.2.1. Tectonic compression. Wang (2015) believed that northwest margin of Junggar Basin has been compressed from northwest to southeast over a long time. Feng et al. (2008), Lei et al. (2005), Zhang (2013) and Wang (2015) subdivided the tectonic evolution stages of the northeast margin of the Junggar Basin into a Late Carboniferous collision stage, Early Permian extension-compression stage, Middle-Late Permian intensively compression stage, Triassic compression stage and Jurassic and Cretaceous weak extrusion uplift stage (Fig. 2). The inherited compression tectonic environment in the Permian and the Triassic is beneficial to overpressure generation in the Mahu Sag. Overpressure vertically appears in the Permian and the Lower Triassic (Fig. 5), which is consistent with a tectonic compression background (Fig. 2). However, the strongest compressed zones in the northwest margin of Junggar Basin are the Ke-bai fault zone and Wu-xia fault zone. Theoretically, these two zones should have the highest overpressure. However, the characteristics of overpressure distribution in the Lower

Fig. 10. Shale sonic transit time-depth plots and calculated pressures by the equivalent depth method for wells Mh1, Ak1 and M15 in the Mahu sag. The locations of the wells are shown in Fig. 1c. The solid red lines represent the normal pressure. The red segmented lines represent the predictive pressure. The red stars represent the pressure values from the DSTs. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) 240

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Triassic Baikouquan Formation gradually increase from northwest to southeast of the sag, which disagrees with the generation of overpressure by tectonic compression. From the research of Osborne and Swarbrick (1997), the mechanism of generating overpressure is the same as disequilibrium compaction when the reduction in the sediment pore volume is caused by horizontal tectonic compaction; that is, tectonic compaction can also lead to mudstone's disequilibrium compaction. The acoustic travel-time of mudstone is abnormally large. However, from the acoustic travel-time curves of the B22 well, Mh1 well and Mh3 well in the southern part of the Mahu sag (Fig. 8), the B22 well acoustic travel-time near the compressed fracture zone deviates little from the normal range. However, the Mh1 well at the slope zone of the sag and the Mh3 well near the center of the sag have large deviations from the normal range. This illustrates that in comparison with disequilibrium compaction, tectonic compassion is not the main factor for overpressure generation.

Fig. 12. Hydrocarbon expulsion history of the Fengcheng resource formation, Mahu sag.

crude oil, and the cracking temperature is higher. The oil test results (Table 1) show that the PetroChina Xinjiang Oil Field Company defines most of the oil and gas reservoirs in the Lower Triassic Baikouquan Formation as oil reservoirs. The natural gas origin of oil reservoirs is speculated as migrating along crude oil after deep hydrocarbon source rocks were generated. Thus, oil cracking to gas is not the chief factor of overpressure generation.

3.1.2.2. Crude oil cracking to natural gas. A large amount of crude oil cracks and become natural gas in the rock pores, which causes the volume of fluid increase and generates overpressure. Many scholars (Horsfield et al., 1992; Schenk et al., 1997; Geng and Geng, 2008; Zhao et al., 2006) thought that the crude oil from approximately 160 °C (Ro ≈ 1.6%) begins to crack large amounts of natural gas. It can be seen in Table 1 that the formation temperature of the Baikouquan Formation is between 52 °C and 97 °C, which is far from the oil cracking temperature. From the evolution history of formation temperature simulation results (Fig. 7), the southeast margin of sag is the deepest, and the maximum formation temperature at the D9 well in the Baikouquan Formation is just 120 °C. Therefore, it cannot produce much cracking gas. In the overpressure environment, the process of oil cracking into natural gas will be suppressed (Dominé, 1991; Dominé and Enguehard, 1992; Jackson et al., 1995; Hill et al., 1996; Wangen, 2001; Tan, 2002; Yang and Wang, 1987), and the temperature at which it begins to crack may be higher. Most reservoirs in the Lower Triassic Baikouquan Formation develop overpressure, overpressure will suppress the cracking of

3.2. The accumulation model of high pressure and high production oil pools The homogenization temperature of inclusions bearing hydrocarbon represents the formation temperature during the key periods of hydrocarbon accumulation. The homogenization temperatures of hydrocarbon bearing inclusions in the Baikouquan Formation in well M18 are divided into two parts: 50–60 °C and 85–95 °C (Fig. 11b). Corresponding to the burial and thermal histories (Fig. 11a), the M18 well experienced two periods of oil charging in the Early Jurassic and the Early-Middle Cretaceous. According to the hydrocarbon expulsion history of the Fengcheng Formation source rock (it originates from the fourth resource evolution results of the PetroChina Xinjiang oilfield company), there were two important periods of hydrocarbon expulsion

Fig. 11. (a) Burial and thermal histories of well M18. (b) Fluid inclusions' homogenization temperatures in the Lower Triassic Baikouquan formation of well M18. 241

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Fig. 13. Oil accumulation process of the Lower Triassic Baikouquan formation, Mahu sag. For the location of A-A′, see Fig. 1c. The pressure coefficient and source rock thermal evolution are from the 2D basin simulation. Not all the faults have been displayed. All the faults are reverse faults.

reservoirs in the Lower Triassic Baikouquan Formation possessed great differences. According to the basin simulation (Fig. 7), in the Early Jurassic, the porosity of reservoirs was approximately 20%, the physical properties were good, crude oil could migrate laterally, and it was difficult for reservoirs to generate strong overpressure. In the Early

stages, which were from the Middle Triassic to Early-Middle Jurassic and the Early Cretaceous (Fig. 12). The hydrocarbon expulsion stages and the homogenization temperature of hydrocarbon bearing inclusions basically match. At the two important periods of oil charge, the physical properties of 242

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Table 2 Errors in the calculated pressures. Well

Ak1 D9 M15 M18 Mh1 Xy2

Depth (m)

4652 4706 3048 3S9S 3284 5318

Actual pressure (MPa)

60 89 35 66 47 91

Acoustic logging calculation

2D simulation

Pressure (MPa)

Absolute error (MPa)

Relative error (%)

Pressure (MPa)

Absolute error (MPa)

Relative error (%)

61 85 38 64 50 89

1 4 3 2 3 2

1.67 4.49 8.57 3.03 6.38 2.20

57 82 38 62 44 94

3 7 3 4 3 3

5.00 7.87 8.57 6.06 6.38 3.30

Fig. 14. Relationship of the Baikouquan formation's oil pools and the Fengcheng formation's paleopressure coefficients (Early Cretaceous, 146 Ma), Mahu sag.

established an accumulation model of the high pressure and high production oil pools in the Lower Triassic Baikouquan Formation (Fig. 13). In the Early Jurassic (approximately 208 Ma), the Fengcheng Formation source rocks were in the maturity stage, and the porosity of the reservoirs in the Baikouquan Formation were high (Fig. 7). The faults located in the areas of strong overpressure of the Fengcheng Formation source rocks were opening, crude oil was driven by overpressure charging into the Baikouquna Formation reservoirs through faults, laterally migrated to high positions through the high porosity reservoirs, and then formed the ancient oil pools. The favorable zones of the generation of the ancient oil pools were the paleoanticlines (such as for wells M2 and M15) and the margin of the sag (Fig. 13c). In the Early Cretaceous (approximately 146 Ma), the Fengcheng Formation source rocks were in the maturity-high maturity evolutionary stage, and the porosity of the reservoirs in the Baikouquan Formation were low (Fig. 7). The faults located in the areas of strong overpressure of the

Cretaceous, the porosity of the reservoirs was close to 10%, the lateral migration of crude oil was limited in these tight reservoirs, and it was easy for reservoirs to generate strong overpressure. Accumulation model of the high pressure and high production oil pools in the Lower Triassic Baikouquan Formation have been established through three steps. Firstly, the logging data was used as synthetic records. Seismic reflection interfaces were calibrated by stratified data of wells. Fine structural interpretation of seismic section was carried out, and the present structural section map (Fig. 13a) was obtained by time-depth conversion. Secondly, by using the present structural section map and the technique of 2D basin modeling simulation, the structural sections, the paleopressure of the two oil charged periods and the evolutionary characteristics of the Fengcheng Formation source rocks were obtained (Fig. 13). Thirdly, by combining the history of tectonic evolution, the porosity evolutionary history of reservoirs and the distribution characteristics of recent oil pools, we 243

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Fig. 15. Two points, a and b, with the same excess pressure, the pressure coefficient of the shallow point a is larger than for b, and the faults near point a are more easily opened.

Fig. 16. Relationship of oil pools and paleostructure (Early Cretaceous, 146 Ma) in the Lower Triassic Baikouquan formation, Mahu sag.

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Fig. 17. Relationship of rock physical properties and oil-bearing in the Lower Triassic Baikouquan formation, Mahu sag.

It can be judged from the oil accumulation model that the Early Cretaceous was the formation stage of high pressure and high production oil pools in the Lower Triassic Baikouquan Formation of the Mahu sag. The foundation is the fan-delta frontier glutenite reservoirs, and the distribution is related to the opening of faults in the overpressure environment. The main controlling factors of oil pools generation are the Fengcheng Formation paleo-overpressure, faults on the ancient noselike structural belts and the fan-delta frontier glutenite reservoirs in the Baikouquan Formation.

mainly produced by the established model. Due to the extremely complicated geological body, the established model cannot match the actual geological body. All the wells selected are located on the 2D sections with DSTs data and complete sonic logging data. A composite of the currently found oil pools with the Fengcheng Formation paleopressure coefficient in the Early Cretaceous (146 Ma, the formation stage of high pressure and high production oil pools in the Lower Triassic Baikouquan Formation) is presented in Fig. 14. The currently found high pressure and high production oil pools in the Baikouquan Formation include the oil pool nearby wells Ah1 (the pressure coefficient is 1.67, and the daily oil and gas production is 236 barrels), Ah011 (the pressure coefficient is 1.63, and the daily oil and gas production is 371 barrels) and M18 (the pressure coefficient is 1.74, the daily oil and gas production is 297 barrels). Oil pools are found nearby well D15 (the pressure coefficient is 1.70, and the daily oil and gas production is 214 barrels) and well Mh1 (the pressure coefficient is 1.45, and the daily oil and gas production is 310 barrels). These high pressure and high production oil pools are mostly distributed within the scope of the Fengcheng Formation source rocks with paleopressure coefficients exceeding 1.4 (Fig. 14). It can be inferred that for paleopressure coefficients exceeding 1.4, some faults could be open and became effective transmission systems. Thus, this pressure scale can act as the favorable scale of oil accumulation.

4.1. The Fengcheng Formation paleo-overpressure

4.2. Faults on the ancient nose-like structural belts

The evolutions of overpressure were obtained from the 2D basin model simulation results (the 2D sections can be seen in Fig. 1c). The planar distribution of paleo-overpressures was obtained by the interpolation of the 2D basin model simulation results. The evolution results of overpressure have been verified by DSTs and overpressure values calculated through acoustic logging. Table 2 presents the errors of the calculated pressures compared with DSTs and the present overpressures predicted by acoustic logging, the absolute errors of which are between 1 and 4 MPa, and the relative errors are between 1.67%–8.57%. The present overpressures were predicted by the 2D basin model simulation, its absolute errors are between 3 and 7 MPa, and the relative errors are between 3.30%–8.57%. The 2D basin model simulation errors are

Faults are the important vertical transmission systems of oil and gas in the Mahu sag and serve as the main factor of hydrocarbon accumulation in the Lower Triassic Baikouquan Formation. In the Mahu sag, faults cut downward through source rocks in the Lower Permian Fengcheng Formation and are connected upward with the reservoirs in the Lower Triassic Baikouquan Formation, and most faults were sealed by the huge thickness of mudstone at the top of the Triassic (Lei et al., 2017) (Fig. 13). Overpressure is the dynamic condition for faults to open. Under similar pressure conditions, it was easier for faults to open and become oil migration channels, the nearby areas of which served as the favorable areas for oil to accumulate into high pressure and high production oil pools in the Lower Triassic Baikouquan Formation. Hao

Fengcheng Formation source rocks were opening, and crude oil driven by overpressure was charging the reservoirs in the Baikouquan Formation reservoirs through faults. Due to the low porosity of the reservoirs, the lateral migration of crude oil was limited, crude oil accumulated in the reservoirs nearby these opening faults (such as for wells M6, M2 and M15) and developed the paleo-overpressure in the ancient oil pools. At that moment, the fan-delta frontier glutenite reservoirs nearby those opening faults were the favorable zones for the generation of ancient high-pressure oil pools (Fig. 13b). From the Early Cretaceous to the present, the tectonic activities were weak, the reservoirs were denser, and therefore the ancient high-pressure oil pools formed in the Early Cretaceous have no obvious adjustment (Fig. 13a). 4. Main controlling factors of oil enrichment

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Fig. 18. Predicted oil enrichment areas of the Lower Triassic Baikouquan formation, Mahu sag.

nose-like uplifts should have larger paleopressure coefficients and might easily reach the pressure coefficient lower limit for opening faults. Faults nearby these structure ridges could have been opened and became the channels for releasing overpressure and oil-bearing fluid charging. Most of the oil pools currently found are related to the ancient nose-like uplifts, including the oil pools found nearby wells M18, M15 and X89, D13-D15, and Mh1 (Fig. 16).

(2005) suggested that for two points, a and b, with the same overpressure, the pressure coefficient of point a, which is at a shallow burial depth, is larger, and the rock fracture pressure and the lower limit condition of pressure coefficient for opening faults are more easily reached there (Fig. 15). Within the scope of the Fengcheng Formation's paleo-overpressure, faults on the ancient nose-like structural belts were easily opened and became the effective transmission systems. Because of the faults and the paleo-overpressure results from the basin modeling simulation were got without considering the horizontal deformation of the geological body,and there is no syn-tectonic growth from Lower Triassic to base of Cretaceous. In order to make the paleo-overpressure, fault and paleostructure match each other in the horizontal position, the paleostructure restoration method proposed by Low (1957) is adopted. The present structure contour maps of the top of the Lower Triassic Baikouquan Formation and the bottom of the Cretaceous have been made respectively. The former is used to subtract the latter, and the denudation thickness of early Cretaceous is taken into account. Finally, the paleostructure maps of the top of the Lower Triassic Baikouquan Formation in the Early Cretaceous were obtained (Fig. 16). According to this paleostructure map (Fig. 16, Early Cretaceous, 146 Ma, the formation stage of high pressure and high production oil pools in the Lower Triassic Baikouquan Formation), there were many ancient nose-like uplifts extending from the margin of the Mahu sag to the center. Under the same overpressure conditions, these structure ridges of ancient

4.3. The fan-delta frontier facies glutenite reservoirs in the lower Triassic Baikouquan Formation The oil discovered in the Lower Triassic Baikouquan Formation is mainly preserved in the fan-delta frontier facies glutenite reservoirs. According to the relationship between rocks’ physical properties and abilities to bear oil (Fig. 17), oil was preserved in rocks with porosities above 7.4% and permeabilities above 0.1 × 10−3 μm2. The porosities of the fan-delta frontier facies glutenite reservoirs are between 5%–12% (Lei et al., 2014), the average value is approximately 10%, and the permeabilities are between 0.1 and 10 × 10−3 μm2 and mostly above 1 × 10−3 μm2. However, the porosities of most fan-delta plain facies glutenites are less than 5% (Imin et al., 2016), and the permeabilities are basically less than 0.1 × 10−3 μm2 (Fig. 4). It can be seen that the fan-delta frontier facies glutenites are the favorable reservoir condition.

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5. Favorable accumulation areas for oil

Appendix A. Supplementary data

Imin et al. (2016) divided the Lower Triassic Baikouquan Formation into three sections according to lithology, electrical properties and sedimentary cycles. From bottom to top, they are the Bai 1 section (T1b1), Bai 2 section (T1b2) and Bai 3 section (T1b3). According to the main controlling factors of oil accumulation, it can divide the fan-delta frontier facies glutenite reservoirs in each section of the Lower Triassic Baikouquan Formation into three favorable accumulation areas: class I favorable areas, class II favorable areas and class III favorable areas. For the class I favorable areas, the paleopressure coefficients of the Fengcheng Formation source rocks were more than 1.4, and they are located near the faults on the ancient nose-like uplifts. For the class II favorable areas, the paleopressure coefficients of the Fengcheng Formation source rocks were more than 1.4, and they are located near the faults, but the faults are not on the ancient nose-like uplifts. The rest are class III favorable areas. In these three favorable areas, the class I favorable areas are the best places for the formation of high pressure and high production oil pools. The class III favorable areas are the worst. Each of the classes of the favorable areas seen in Fig. 18.

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6. Conclusions This research has used geological, geophysical and 2D basin model simulation methods to explain the origins of overpressure in the Lower Triassic Baikouquan Formation and to establish an accumulation model of high pressure and high production oil pools. Based on the accumulation model, we summarized the main controlling factors of the high pressure and high production oil pools and predicted the favorable accumulation areas. The results show that the main origin of overpressure in the Lower Triassic Baikouqun Formation of the Mahu Sag is disequilibrium compaction, the abnormal high overpressure is related to the pressure conducted through faults, and tectonic compression and oil cracking to gas are the secondary factors of overpressure generation. Among them, pressure conduction is the key to the high pressure and high production oil pools' accumulation. In the hydrocarbon accumulation model of high pressure and high production oil pools, the overpressure compels faults that connect source rocks with reservoirs to open and become the valid conductive systems, and the oil-bearing overpressure fluid charges into the Baikouquan Formation along faults and forms high pressure oil pools in the frontier facies glutenite reservoirs near the faults. The main controlling factors of oil accumulation are the paleo-overpressure of Fengcheng Formation source rock during the main hydrocarbon migration stage (the Early Cretaceous, before 146 Ma), the faults on the ancient nose-like belts of structural uplifts and the frontier facies glutenite reservoirs in the Baikouquan Formation. According to the accumulation model, the frontier facies glutenite reservoirs of the Baikouquan Formation's three sections can be divided into classes I, II and III, in which favorable oil accumulation areas range from good to bad: the class I favorable areas, class II favorable areas and class III favorable areas. Most of the high pressure and high production oil pools currently found in the Lower Triassic Baikouquan Formation are distributed in the class I favorable areas. Acknowledgements This work was supported by the Natural Science Foundation of Xinjiang Uygur Autonomous Region, China (2016D01B013). And we also thanks to the supports from the Scientific Research Program in Colleges and Universities of Xinjiang Uygur Autonomous Region, China (XJEDU2017I011) and the China University of Petroleum -Beijing at the Karamay Scientific Research Program (RCYJ2016B-01-009). We appreciate the Research Institute of Exploration and Development, PetroChina Xinjiang Oilfield Company, for providing background geologic data and permission to publish the results. 247

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