Sage Journals: Discover world-class research

Abstract

The Chagan depression has the greatest oil and gas exploration potential in the Yingen-Ejinaqi Basin, Inner Mongolia, northern China. In this paper, source rocks are evaluated and the thermal maturity evolution of typical wells and the primary source rocks is modeled using BasinMod 1D and Basinview software provided by Platte River Associates, Inc. The results show that the Chagan depression developed three sets of source rocks, including the Baiyingebi 1 and 2 Formations and Suhongtu 1 Formation. The Baiyingebi 2 Formation has been the most important source rock in the Chagan depression, dominated by the medium to high maturity source rocks with type II kerogen. This study also reveals that the thermal maturity evolution of source rocks is controlled by the paleogeothermal fields during the Yingen Formation depositional periods when the maximum maturity was reached. The Bayingebi 1 and 2 Formations both experienced the hydrocarbon generation peak and reached the medium to over mature stage. While the Suhongtu 1 Formation has only reached the low to medium mature stage with lower hydrocarbon generation potential. In addition, the source rocks thermal maturity evolution in the West sag is superior to that in the East sag. Therefore, the Bayingebi 2 Formation should be investigated for the oil exploration, and the Wuliji fault nose structural zone and central structural zone will remain the primary targets for the next exploration.

Keywords

Chagan depression basin simulation maturity source rocks Lower Cretaceous

Introduction

China is one of the largest consumers of petroleum. The annual petroleum consumption was over 500 million ton in China in 2015, approximately 60% of which was imported. The energy issues have affected the economic development as the oil consumption has soared in recent years. Worse still, the traditionally large Chinese oilfields, including the Daqing Oilfield, Shengli Oilfield, Zhongyuan Oilfield, are facing a crisis of production reduction. Therefore, resource reassessment is carried out in sedimentary basins previously little explored. The Yingen-Ejinaqi Basin, in which Mesozoic sedimentary rock covers 10.4 × 10⁴ km², the Chagan depression is the first target of resource assessment and hydrocarbon exploration because of its thicker Mesozoic sediments and greater exploration potential. More than 60 million tons of petroleum reserves and the Jixiang and Ruyi Oilfields have been discovered in the Chagan depression. More remarkable, the highest yield of well Y9 reached 7.9 tons per day (flowing) in the central structural zone; the highest yield of the wells X6 and X6-1 reached 8.4 and 21.9 tons per day (flowing) in the Wuliji structural zone since October 2012. These discoveries indicate that the Chagan depression is a promising exploration area.

In recent years, with the development of oil and gas exploration, more than 200 wells have been drilled, and the amount of geochemical data from the source rocks has increased. Therefore, it is necessary to evaluate systematically the characteristics of source rocks and their thermal maturity evolution in the Chagan depression. This work can provide the basis for the resource evaluation within the Chagan depression.

The characteristics of source rock evaluation include the organic matter abundance, kerogen type, and source rock maturity. For this research, source rock maturity primarily includes indexes of vitrinite reflectance and biomarker (Akande et al., 2015; ElAtfy et al., 2014; González et al., 2013; Guo et al., 2015; Hu et al., 2015; Martínez et al., 2014; Tian et al., 2016). However, drilling wells and samples are short in the hydrocarbon-generation center and depression, because these areas have not been conventional oil and gas exploration targets. Therefore, it is impossible to do geochemical experimental test and difficult to study using conventional experimental test methods. Moreover, only information on the current maturity of source rocks can be obtained, while the source rock thermal maturity evolution history over the geologic time cannot be obtained. Hydrocarbon generation, expulsion, migration, and accumulation histories are research topics for understanding the whole process from oil and gas generation to accumulation. These are closely related to the source rock thermal evolution history. Therefore, researching the source rock thermal maturity evolution is of increasing interest. Along with the development of petroleum geology theory and the wide application of computing technology, quantitative research on the thermal maturity evolution of source rocks in the geological period is of great significance. Basin simulation method has become an important method in the thermal maturity evolution and spatial distribution characteristics of source rocks in sedimentary basin (Belaid et al., 2010; Berthonneau et al., 2016; El-Shahat et al., 2009; Hakimi and Ahmed, 2016; Hudson and Hanson, 2010; Kosakowski et al., 2013; Pang et al., 2004, 2012; Qiu et al., 2010, 2012; Resak et al., 2010; Zhu et al., 2016; Zuo et al., 2011, 2013a, 2014, 2015a, 2015b, 2016a, 2016b).

Consequently, in the paper, based on the results of source rock evaluation, source rock thermal maturity evolution was modeled using advanced basin simulation software from typical wells and source rock strata. Moreover, favorable oil and gas exploration targets are identified.

Geological setting

Geological setting of the Yingen-Ejinaqi Basin

The Chagan depression has the greatest oil and gas exploration potential compared to other sags in the Yingen-Ejinaqi Basin of Inner Mongolia, northern China (Figure 1). The Yingen-Ejinaqi Basin is a Mesozoic rift basin, developing on the Precambrian crystalline block and the Paleozoic fold basement (Lu et al., 2010; Wei et al., 2006). It is surrounded by the Lang Hill to the east, the North Hill to the west, the North Great Hill and the Yabrai Hill to the south, the China-Mongolian border, the Honggeerji Hill and the Mongan Wula Hill to the North. The Yingen-Ejinaqi basin, approximately 600 km long in its east-west direction, 75–255 km wide in its south-north direction, has an area of 12.3 × 10⁴ km², and is located from 39°N to the Mongolian border, from 99°E to 108°E. The effective Mesozoic sedimentary strata cover an area of 10.4 × 10⁴ km². The Yingen-Ejinaqi Basin consists of eight subbasins and five uplifts and has experienced four tectonic episodes since the Triassic, among which, the tectonic movements at the end of the Late Jurassic and the Early Cretaceous had a significant impact on the formation and evolution of the basin (Chen et al., 2006; Liu et al., 2006; Wei et al., 2006). The tectonic episodes included: (1) an initial rifting phase from the Late Triassic to the Jurassic, including a post-orogenic relaxation stage in the Late Triassic; uplift and erosion stage at the end of the Late Triassic due to the late Indosinian tectonic movement; an initial rifting stage due to subduction effects of the East Pacific Plate and southward effect of the Siberia Plate in the Early Jurassic; and rifting enhancement stage due to the second episode of Yanshan intense movement at the end of the Middle Jurassic and renewed uplift and erosion stage due to the third episode of Yanshan movement in the Late Jurassic; (2) an intense rifting phase in the Early Cretaceous due to the Altun fault and its branch faults tectonic movements, accompanied by strong volcanic eruption; (3) a thermal subsidence phase in the Late Cretaceous due to the fourth episode of Yanshan movement; and (4) an extrusion and uplift phase in the Cenozoic due to the northward subduction of the Indian Plate and collision with the Eurasian Plate.

Figure 1.

(a) Structural unit division of the Chagan depression; (b) Structural profile map; (c) Stratigraphic column map. Jun: Junnggar; QD: Qaidam; YE: Yingen-Ejinaqi; EL: Erlian; HL: Hailaer; SL: Songliao; BH: Bohai Bay; SNC: Southern part of North China; SC: Sichuan; HN: Hainan; TW: Taiwan.

Geological setting of the Chagan depression

The Chagan depression is located in the central Chagandelesu subbasin in the East Yingen-Ejinaqi. It is surrounded by the Xi’ni uplift to the west, the Chagan uplift to the east, the Mubatu uplift to the southwest, the Lang Hill to the southeast. The Chagan depression, 60 km long in the north-east direction, 40 km wide in the north-west direction, with an exploration area of 2000 km², is a Mesozoic rift basin with the a fault structure to the northwest and overlapping to the southeast (Wei et al., 2006). The Chagan depression consists of the West sag, the Maotun uplift, and the East sag. Each structural unit also includes a plurality of secondary units (Figure 1(a)). The strata in this area contain the Bayingebi, Suhongtu, Yingen, Wulansuhai Formations and the Cenozoic (Figure 1(b) and (c)). The sedimentary cover thickness of the West sag is significantly greater than that of the East sag. The Chagan depression has experienced three tectonic stages since the Early Cretaceous because of the Yanshan and Himalayan movements (Zuo et al., 2015a): (1) a rifting stage from the Early Cretaceous Bayingebi Formation to the Early Cretaceous Yingen Formation, during which the fault is characterized by strong activities with multi-phase volcanic activity and deposition of mafic volcanic rocks and clastic rocks; (2) a thermal subsidence stage during the Late Cretaceous Wulansuhai Formation developed in a fluvial environment; and (3) an extrusion and uplift stage in the Cenozoic, during which squeeze thrusting occurred in locally, with development of thrust faults and inversion structures, and local deposition of the Cenozoic sediments (Figure 1(b)).

Present geothermal fields and thermal history of the Chagan depression

The present geothermal gradient of the Chagan depression ranges from 30.5 to 38.0℃/km, with an average value of 33.6℃/km; and its heat flow ranges from 65.9 to 85.5 mW/m², with an average value of 74.5 mW/m² (Zuo et al., 2013b). The medium geothermal fields between the structurally stable and active regions characterize the Chagan depression. Both the geothermal gradient and heat flow are related to the basement burial depth, as well as the thickness of sedimentary cover, and thermo-refraction between the uplift surrounding the sag.

The Chagan depression has experienced four thermal evolution stages since the Mesozoic (Figure 2): (1) a geothermal gradient rapid increase stage from the Bayingebi Formation depositional period to the Suhongtu Formation depositional period, during which the geothermal gradient increased to 46–52℃/km at the end of the Suhongtu Formation depositional period; (2) a peak geothermal gradient stage during the Yingen Formation depositional period, when the maximum geothermal gradient ranged from 50 to 58℃/km; (3) a high geothermal gradient continuation stage during the Wulansuhai Formation depositional period, when the maximum geothermal gradient ranged from 39 to 48℃/km; and (4) a thermal subsidence stage during the Cenozoic, during which the Chagan depression is in the uplift and erosion stage due to the Himalayan movement and the geothermal gradient gradually decreased to 31–34℃/km at the present day (Zuo et al., 2015a).

Figure 2.

Thermal gradient evolution history of the studied wells in the Chagan depression.

Method and principle of source rock thermal maturity evolution

The method for determining source rock thermal maturity evolution is based on the present geothermal fields and thermal history. First, the 3D geological model is established using each stratum thickness, amount of erosion for the key geological periods, lithological data, thermal physical parameters, and geochemical parameters. When all these data are put together, source rock maturity of the key geological periods is modeled using basin simulation software. If the modeled results of present maturity fit with the measured vitrinite reflectance data, the modeled results represent source rock thermal maturity evolution.

During modeling, the parameters include the each stratum thickness, amount of erosion for the key geological periods, lithological data, thermal physical parameters and geochemical parameters, surface temperature, present geothermal gradient, heat flow, and thermal history. Stratum thickness, lithological data, and geochemical parameters are obtained from the Zhongyuan Oilfields, China Petrochemical Corporation. Rock thermophysical properties include heat productivity and thermal conductivity (Table 1). Present geothermal field and thermal history are important for simulation (Zuo et al., 2013, 2015a). The bottom age of each stratigraphic boundary is as follows, the Cenozoic (Cz) is 65 Ma, the Upper Cretaceous Wulansuhai Formation (K₂w) 95 Ma, the Lower Cretaceous Yingen Formation (K₁y) 100 Ma, the Lower Cretaceous Suhongtu 2 Formation (K₁s²) 105 Ma, the Lower Cretaceous Suhongtu 1 Formation (K₁s¹) 110 Ma, the Lower Cretaceous Bayingebi 2 Formation (K₁b²) 128 Ma, and the Lower Cretaceous Bayingebi 1 Formation (K₁b¹) 135 Ma (Figure 1(c)). The value of R_o used to indicate the maturation of source rocks and the stage of maturity history was classified as follows, Immature: R_o < 0.5%; Early mature: 0.5% ≤ R_o < 0.7%; Middle mature: 0.7% ≤ R_o < 1.0%; Late mature: 1.0% ≤R_o < 1.3%; Main gas stage: 1.3% ≤ R_o < 2.0%; and Dry-gas stage: R_o ≥ 2.0%. Here, source rock thermal maturity evolution in the Chagan depression, the Bayingebi 1 and 2 Formations and the Suhongtu 1 Formation, were modeled using the kinetic model of Sweeney and Burnham (1990) with the BasinMod software provided by Platte River Associates, Inc.

Table 1.

Thermal conductivity and heat production rate column in the Chagan depression.

Strata	Thermal conductivity (mW/m²)	Heat production rate (μW/m³)
K₁y	2.09	2.70
K₁s²	1.97	2.40
K₁s¹	2.21	2.47
K₁b²	2.31	2.89
K₁b¹	2.44	2.46

Results

Source rock evaluation

In this work, source rocks of the Chagan depression were evaluated from organic matter abundance, organic matter type, maturity, and dark mudstone distribution.

Organic matter abundance

Organic matter abundance is assessed according to the Chinese continental source rock standard (Table 2). In the paper, the method of TOC determination is the Rock-Eval pyrolysis method. In the Bayingebi 2 Formation, TOC (Total organic carbon) ranges from 0.06% to 4.13%, with an average value of 0.75%; chloroform bitumen “A” ranges from 0.0003% to 2.4066%, with an average value of 0.1111%; HC (total hydrocarbon content) ranges from 18.38 to 15178.43 ppm, with an average value of 867.52 ppm; and potential hydrocarbon generation amount (S₁ + S₂) ranges from 0.01 to 30.13 mg/g, with an average value of 2.47 mg/g. These values suggest that the Bayingebi 2 Formation is a medium—good source rock. The Bayingebi 1 Formation is a medium source rock, because its TOC ranges from 0.12% to 1.70%, with an average value of 0.72%; its chloroform bitumen “A” ranges from 0.0007% to 0.0935%, with an average value of 0.0355%; its HC ranges from 29.52 to 827.38 ppm, with an average value of 379.44 ppm; and its S₁ + S₂ ranges from 0.08 to 3.25 mg/g, with an average value of 1.26 mg/g. The Suhongtu 1 Formation is a poor source rock, because its TOC ranges from 0.02% to 2.66%, with an average value of 0.44%; its chloroform bitumen “A” ranges from 0.0004% to 0.2757%, with an average value of 0.0371%; its HC ranges from 7.87 to 2130.06 ppm, with an average value of 305.95 ppm; and its S₁ + S₂ ranges from 0.01 to 8.95 mg/g, with an average value of 0.73 mg/g (Table 3).

Table 2.

Evaluation criteria of terrestrial source rocks (Huang et al., 1984).

Source rock grade	Good source rock	Medium source rock	Poor source rock	Nonsource rock
Sedimentary facies	Half-deep lacustrine–deep lacustrine facies	Shallow lacustrine–half-deep lacustrine facies	Shore shallow lacustrine facies	Fluvial facies
Lithology	Black mudstone	Gray mudstone	Gray green mudstone	Red mudstone
TOC (%)	>1.0	1.0–0.6	0.6-0.4	<0.4
Chloroform asphalt “A” (%)	>0.1	0.1-0.05	0.05–0.01	<0.01
HC (10⁻⁶)	>500	500–200	200–100	<100
S₁ + S₂ (mg/g)	>6.0	6.0–2.0	2.0–0.5	<0.5
HC/TOC (%)	>6.0	6.0–2.0	2.0–1.0	<1.0

Table 3.

Organic matter abundance of different source rocks in the Chagan depression.

Source rocks	TOC (%)	“A” (%)	HC (ppm)	S₁ + S₂ (mg/g)	Evaluation
K₁s¹	$\frac{0.02 - 2.66}{0.44 (240)}$	$\frac{0.0004 - 0.2757}{0.0371 (76)}$	$\frac{7.87 - 2130.06}{305.95 (58)}$	$\frac{0.01 - 8.95}{0.73 (87)}$	Poor source rock
K₁b²	$\frac{0.06 - 4.13}{0.79 (333)}$	$\frac{0.0003 - 2.4066}{0.1111 (81)}$	$\frac{18.38 - 15178.43}{867.52 (70)}$	$\frac{0.01 - 30.13}{2.47 (176)}$	Medium-good source rock
K₁b¹	$\frac{0.12 - 1.70}{0.72 (95)}$	$\frac{0.0007 - 0.0935}{0.0355 (21)}$	$\frac{29.52 - 827.38}{379.44 (15)}$	$\frac{0.08 - 3.25}{1.26 (35)}$	Medium source rock

Organic matter type

The organic matter type of the Chagan depression is evaluated primarily using pyrolysis experiment parameters. Under the influence of relatively high maturity of source rocks, most data points distribute along the curve tail and most T_max values are more than 440℃. The organic matter types within the Chagan depression are mainly types III and II kerogen. Combining the pyrolysis ratio and hydrogen index (HI), the Suhongtu 1 Formation is dominated by type III kerogen. The organic matter type of the Bayingebi 2 Formation is better quality, and can be judged as type II kerogen, including partly type I kerogen, because its average HI is 219 mg/g, and average pyrolysis ratio reaches 20.1%. The Bayingebi 1 Formation is dominated by types II and III kerogen (Figure 3).

Figure 3.

The types of organic matter for different source rocks in the Chagan depression.

Chloroform bitumen “A” group component

Chloroform bitumen “A” group component analysis of the Chagan depression reveals that saturated hydrocarbon is the primary component with the highest content. While aromatic hydrocarbon, nonhydrocarbon and asphaltene is relatively lower content (Table 4). Source rocks of the Bayingebi 1 and 2 Formations are highest in the saturated hydrocarbon contents, and most are more than 55% (Figure 4), revealing that they are more mature and have better quality organic matter compared to the source rock of the Suhongtu 1 Formation.

Table 4.

Group component analysis of the sample extract in the Chagan depression.

Well name	Strata	Saturated hydrocarbon (%)	Aromatic hydrocarbon (%)	Nonhydrocarbon (%)	Asphaltene (%)
CC1	K₁s¹	$\frac{12.93 - 54.55}{32.65 (16)}$	$\frac{11.36 - 43.53}{25.04 (16)}$	$\frac{2.83 - 37.79}{22.82 (16)}$	$\frac{2.39 - 37.80}{16.23 (16)}$
M5		$\frac{29.69 - 54.32}{44.17 (4)}$	$\frac{13.56 - 25.34}{19.20 (4)}$	$\frac{27.09 - 39.01}{31.93 (4)}$	$\frac{4.05 - 6.05}{4.69 (4)}$
L1		$\frac{48.28 - 61.61}{54.67 (3)}$	$\frac{15.65 - 19.57}{17.86 (3)}$	$\frac{22.04 - 27.05}{24.93 (3)}$	$\frac{0.70 - 5.10}{2.54 (3)}$
CC1	K₁b²	$\frac{33.00 - 76.89}{60.79 (14)}$	$\frac{6.64 - 18.38}{12.31 (14)}$	$\frac{12.13 - 22.66}{19.15 (14)}$	$\frac{0.47 - 22.16}{3.71 (14)}$
M5		$\frac{38.90 - 63.64}{54.32 (4)}$	$\frac{11.61 - 18.99}{14.96 (4)}$	$\frac{18.08 - 32.49}{23.17 (4)}$	$\frac{4.62 - 10.04}{7.55 (4)}$
L1		$\frac{59.60 - 66.77}{62.01 (3)}$	$\frac{14.15 - 18.98}{17.11 (3)}$	$\frac{17.23 - 20.20}{18.80 (3)}$	$\frac{1.85 - 2.38}{2.07 (3)}$
CC1	K₁b¹	$\frac{51.77 - 77.95}{66.44 (5)}$	$\frac{5.53 - 13.07}{9.00 (5)}$	$\frac{12.60 - 21.68}{15.77 (5)}$	$\frac{1.19 - 10.40}{3.67 (5)}$
L1	K₁b¹	$\frac{73.90 - 78.88}{76.15 (4)}$	$\frac{10.43 - 14.83}{12.55 (4)}$	$\frac{9.16 - 10.69}{9.91 (4)}$	$\frac{1.28 - 1.53}{1.40 (4)}$

Figure 4.

Source rock chloroform bitumen “A” group composition in the Chagan depression.

Organic matter maturity

Organic matter maturity of the Chagan depression is studied by vitrinite reflectance (R_o) and biomarker in this work.

Vitrinite reflectance

One hundred nineteen R_o data from 15 wells were measured, and they range from 0.56% to 2.21%. The three sets of source rocks have all been in the mature stage with an oil threshold at 1100 m and generation peak at 2700 m. There is a positive relationship between burial depth and maturity of source rocks, suggesting that source rocks in the Chagan depression are controlled by the same geothermal field (Figure 5).

Biomarker

Figure 5.

Vitrinite reflectance (Ro) data versus depth in the Chagan depression.

Biomarkers to assess organic matter maturity include even-odd predom index (OEP), carbon predominance index (CPI), diasterane to regular sterane ratio, Ts/Ts + Tm, C₂₉ααα-20S/(20S + 20R), C₂₉ββ/(αα + ββ), and C₃₁22S/22(S + R) (Huang et al., 1984).

Chromatographic analysis of saturated hydrocarbon of samples from well CC1 samples shows that n-alkanes odd even predominance almost disappears and OEP and CPI are both less than 1.2 for source rocks in the bottom of the Suhongtu 1 Formation. GC-MC analysis of saturated hydrocarbon indicates that S/(S + R) and ββ/(αα + ββ) of C29 are 0.3 and 0.35 in the Suhongtu 1 Formation, respectively, and 0.4 and 0.45 in the Bayingebi Formation, respectively, which suggests these source rocks have gone through their mature stage. Crude oil and oil sand from 2820 to 2850 m of the Suhongtu 1 Formation of the well CC1 shows that S/(S + R) and ββ/(αα + ββ) of C29 sterane are over 0.45 and 0.6, respectively, suggesting source rocks of this depression has been already mature (Table 5). Also, the source rocks of the other two wells have reached maturity on basis of the S/(S + R) and ββ/(αα + ββ) of C29 sterane (Table 5).

Table 5.

Parameters of biomarkers for source rocks in the Chagan depression.

Well name	Strata	C₂₉S/(S + R)	C₂₉ββ/(αα + ββ)	Mature stage
M5	K₁s¹	0.48–0.49	0.41–0.44	Mature
M5	K₁b²	0.53	0.51	Mature
L1	K₁s¹	0.53	0.42	Mature
	K₁b²	0.46	0.52	Mature
	K₁b¹	0.46	0.50	Mature
CC1	K₁s¹	>0.3	>0.35	Low mature–mature
CC1	K₁b	>0.4	>0.45	Mature

Source rock distribution

Dark mudstone distribution of the three sets of source rocks in the Chagan depression was studied on the basis of logging and seismic data. The dark mudstone distribution center is located in the southwest Ehen subsag and Hule subsag for the Bayingebi 1 and 2 Formations, and in the Central Ehen subsag and Hule subsag for the Suhongtu 1 Formation. Dark mudstone is the thickest in the Bayingebi 2 Formation with the maximum of 1100 m in the southwest Ehen subsag. However, dark mudstone in the East sag is not only narrow, but also thin with slight exploration significance (Figures 6 –8).

Figure 6.

Mudstone thickness map for the Bayingebi 1 Formation in the Chagan depression.

Figure 7.

Mudstone thickness map for the Baiyingebi 2 Formation in the Chagan depression.

Figure 8.

Mudstone thickness map for the Suhongtu 1 Formation in the Chagan depression.

In short, the most promising source rocks of the Chagan depression developed in the Bayingebi 2 Formation, which are characterized by high maturity, type II kerogen, medium to good organic matter abundance, and thick dark mudstone with the peak thickness of 1100 m in the southwest Ehen subsag.

Source rock thermal maturity evolution of typical wells

Considering previous research on the present geothermal fields and thermal history of the Chagan depression, thermal maturity evolution of typical wells is modeled. The modeled result of the well Y11 is in good agreement with measured R_o data, which indicates the simulations are reliable (Figure 9). There are two thermal maturity evolution stages for the source rocks of well Y11. The thermal maturity of the Bayingebi 1 Formation is nearly 1% in the first stage during the Suhongtu Formation depositional periods. The Bayingebi 1 Formation and lower part of the Bayingebi 2 Formation reached hydrocarbon generation peak, and the middle-upper part of the Bayingebi 2 Formation reached medium mature stage, and the Suhongtu 1 Formation was still at the low mature stage in the second phase during the Yingen Formation depositional periods.

Figure 9.

The burial and thermal histories of the Y11. “+” means measured vitrinite reflectance (Ro) datum, and the solid line means modeled result in the right chart.

Most wells are drilled at tectonic uplift zones and we lack samples in the depression, so it is impossible to directly study the source rock maturity. However, the artificial wells can be established according to the seismic interpretation and sedimentary facies. This research focuses on the source rock thermal maturity evolution of the Hule subsag, Ehen subsag, and center of the Kantamiao subsag, among which artificial well R1 is used for the latter (Figure 10).

Figure 10.

Maturation history of the typical wells in the Chagan depression. (a) Well Y11, (b) Well Y1 and (c) Well R1.

The modeled results reveal that thermal maturity for the three sets of source rocks all reached the maximum during the Yingen Formation depositional periods, indicating paleogeothermal fields control the thermal maturity evolution during the Yingen Formation depositional periods.

Comparing the degree of source rock thermal maturity evolution of the three subsags, well Y1 in the center of the Ehen subsag is the most mature among the three subsags, followed by well R1 in the center of the Hantamiao subsag zone, and well Y11 in the center of the Hule subsag is least mature (Figure 10). The Suhongtu 1 Formation is mainly at the low to medium mature stage with poor hydrocarbon generation potential. The Bayingebi 2 Formation is highly mature in the Hantamiao subsag zone and some parts of the Hule subsag and highly to overly mature in the Ehen subsag. While the Bayingebi 1 Formation is highly mature in the Hule subsag and overly mature in the other two subsags.

Thermal maturity evolution of the main source rocks

Thermal maturity evolution of the Suhongtu 1 Formation

The top of source rocks of the Suhongtu 1 Formation in the West sag generally entered into the hydrocarbon generation threshold with medium maturity at well zone CC1-Y2-Y3, but they entered into the threshold only in the north of the Hantamiao subsag zone in the East sag (Figure 11(a)). Present maturity is consistent with the maturity at the end of the Yingen Formation (Figure 11(b)).

Figure 11.

Maturation level of the top of the Suhongtu 1 Formation. The contour interval is 0.1%.

Thermal maturity evolution of the Bayingebi 2 Formation

At the end of Suhongtu Formation, the top of source rocks of the Bayingebi 2 Formation in the central and south West sag entered into the hydrocarbon generation threshold with medium maturity at well zone Y2-Y3, while they entered into the hydrocarbon generation threshold only in the north subsag of the Hantamiao subsag zone in the East sag (Figure 12(a)). During the Yingen Formation depositional periods, source rocks reached medium maturity in the West sag but highly to overly mature at well zone CC1-Y2-Y3. In contrast, the East sag is characterized by low maturity. The source rocks of the Hantamiao subsag generally have entered into the hydrocarbon generation threshold at the medium to high maturity stage in the north subsag center (Figure 12(b)) at present (Figure 12(c)).

Figure 12.

Maturation level of the top of the Bayingebi 2 Formation. The contour interval is 0.1%.

Thermal maturity evolution of the Bayingebi 1 Formation

At the end of the Suhongtu 1 Formation depositional periods, the top source rocks of the Bayingebi 1 Formation entered into the hydrocarbon generation threshold only in the central and south West sag (Figure 13(a)). At the end of the Suhongtu 2 Formation depositional periods, the source rocks entered into the hydrocarbon generation threshold mostly in the West sag at the medium to over mature stage in the central-south area and only in central-north of the Hantamiao subsag zone in the East sag at a medium mature stage (Figure 13(b)). At the end of the Yingen Formation depositional periods, the source rocks were generally in the medium mature stage when the maturity was more than 2.5% at the well zone Y2-CC1 in the West sag. Well zone Y2-CC1 and the sedimentary center in the East sag reached the dry gas generation stage (Figure 13(c)). The maturity no longer changed from the Late Cretaceous to the present day (Figure 13(d)).

Figure 13.

Maturation level of the top of the Bayingebi 1 Formation. The contour interval is 0.1% in (a) and (b) and 0.2% in (c) and (d).

At the end of the Suhongtu Formation depositional periods, the bottom source rocks of the Bayingebi 1 Formation entered into the hydrocarbon generation threshold in the central West sag and some part of East sag. While some source rocks in the West sag reached medium to high maturity (Figure 14(a)). At the end of the Suhongtu 2 Formation depositional periods, the source rocks generally entered into the hydrocarbon generation threshold in the Chagan depression, and the source rocks were the highest maturity at well zone Y1-Y2 and reached the dry gas generation stage (Figure 14(b)). At the end of Yingen Formation depositional periods, the main sedimentary centers all reached the dry gas generation stage (Figure 14(c)). The maturity no longer has changed from the Late Cretaceous to the present day (Figure 14(d)).

Figure 14.

Maturation level of the bottom of the Bayingebi 1 Formation. The contour interval is 0.1% in (a) and 0.2% in (b), (c), and (d).

There are differences among these three sets of source rocks. In the West sag, both the Bayingebi 1 and 2 Formations reached the medium to overly mature stage and generally experienced a hydrocarbon generation peak with great hydrocarbon generation potential, while the Suhongtu 1 Formation only reached a low to medium mature stage, did not reach a hydrocarbon generation peak and has a low hydrocarbon generation potential. Moreover, the West sag is obviously superior to the East sag in source rock thermal maturity evolution.

Discussions

Relationship between thermal maturity evolution of source rocks and hydrocarbon distribution

The thermal maturity evolution of the three sets of source rocks in the Chagan depression was modeled according to their burial and thermal histories. The modeled results show that these source rocks all reached a maximum thermal maturity at the end of Yingen Formation depositional periods in the Early Cretaceous. This suggests that source rock thermal maturity evolution of the Chagan depression is controlled by the paleogeothermal fields of the Yingen Formation depositional periods, and the paleogeothermal fields further controlled the main hydrocarbon generation, expulsion, and accumulation periods. On the basis of these results, it is possible to determine favorable hydrocarbon accumulation areas by combining the research on the formation periods of the reservoir, cap rock, and trap. Moreover, the degree of thermal maturity evolution for these three sets of source rocks has important differences. The source rocks in the Bayingebi 1 and 2 Formations in the West sag reached the medium to overly mature stages and generally experienced a hydrocarbon generation peak with great hydrocarbon generation potential, while those in the Suhongtu 1 Formation only reached the low to medium mature stage, did not reach their hydrocarbon generation peak and have slight hydrocarbon generation potential. The West sag is superior to the East sag in source rock thermal maturity evolution.

Favorable exploration area in the Chagan depression

The Chagan depression is a rift basin developed in the Cretaceous. During the Bayingebi 1 Formation depositional periods, at beginning rift stage with shallow water, the sag accepted shore to shallow lacustrine sediments dominated by proximal sediments, and source rocks were not only thin but also inferior verified by exploration. During the Bayingebi 2 Formation depositional periods, the rift became more intense than the Bayingebi Formation depositional periods, while the sag accepted semi-deep and deep lake sediments. Source rocks are characterized by great thickness with 1200 m at the sedimentary center, with good organic matter abundance, type I and II kerogen, high maturity and great hydrocarbon generation potential. Thus, it can be inferred that the Bayingebi 2 Formation will be the main oil source for the Chagan depression.

In addition, the Chagan depression is a small continental rift basin and the hydrocarbon generation capacity is limited. Many open normal faults connect with the earth’s surface, caused by the intense faulted sag in the Early Cretaceous, which has been verified by basalt developing in vertical fractures. These faults provided migration pathways for oil and gas lost to the surface, so effective structure traps are few in the Chagan depression. Exploration should target lithologic traps and discover self-generating and self-preserving reservoirs around the hydrocarbon generation center of the Bayingebi 2 Formation, which is consistent with the present main reservoirs (e.g., tight sandstone reservoirs of well LP1, X3, and X6 in the Wuliji structural belt and block Y6 in the central structural belt). In addition to the oil and gas reserves and production have been discovered in the central structural zone and the central Wuliji structural zone, the southern area of the Wuliji structural zone is a favorable exploration target for future production.

Conclusions

The Chagan depression developed the Baiyingebi 1 and 2 Formations and Suhongtu 1 Formation source rocks. The Baiyingebi 2 Formation is the most important medium to good source rock in the Chagan depression. It is dominated by medium to high maturity source rocks with type II kerogen.

The source rock thermal maturity evolution in the Chagan depression is controlled by the paleogeothermal fields during the Yingen Formation depositional periods. The maturity of three sets of source rocks all reached a maximum at the end of Yingen Formation depositional periods.

There are important differences among these three sets of source rocks. In the West sag, both the Bayingebi 1 and 2 Formations reached the medium to overly mature stage and experienced the hydrocarbon generation peak with great hydrocarbon generation potential. In contrast, the Suhongtu 1 Formation only reached the low to medium mature stage, did not experience a hydrocarbon generation peak and has small hydrocarbon generation potential. In summary, the West sag is superior to the East sag in the degree of source rock thermal maturity evolution.

Footnotes

Acknowledgements

Two anonymous reviewers are thanked for their reviews that greatly improved this paper.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research,authorship,and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research,authorship,and/or publication of this article: This work was funded by the National Natural Science Foundation of China (grant no. 41402219) and the Sichuan Science & Technology Foundation (grant no. 2016JQ0043).

References

Akande

Lewan

Egenhoff

(2015) Source rock potential of lignite and interbedded coaly shale of the Ogwashi–Asaba Formation, Anambra basin as determined by sequential hydrous pyrolysis. International Journal of Coal Geology 150: 224–237.

Belaid

Krooss

Littke

(2010) Thermal history and source rock characterization of a Paleozoic section in the Awbari Trough Basin, SW Libya. Marine and Petroleum Geology 27: 612–632.

Berthonneau

Grauby

Abuhaikal

(2016) Evolution of organo-clay composites with respect to thermal maturity in type II organic-rich source rocks. Geochimica et Cosmochimica Acta 195: 68–83.

Chen

Wei

Yang

(2006) Tectonic evolution and petroleum prospection in the Yin’gen-Ejina basin. Petroleum Geology, Experiment 28: 311–315. (in Chinese with English abstract).

ElAtfy

Brocke

Uhl

(2014) Source rock potential and paleoenvironment of the Miocene Rudeis and Kareem formations, Gulf of Suez, Egypt: An integrated palynofacies and organic geochemical approach. International Journal of Coal Geology 131: 326–343.

El-Shahat

Villinshi

El-Bakry

(2009) Hydrocarbon potentiality, burial history and thermal evolution for some source rocks in October oil field, northern Gulf of Suez, Egypt. Journal of Petroleum Science and Engineering 68: 245–267.

González

Peralba

MDC

Barrionuevo

Kalkreuth

(2013) Geochemical characterization of Jurassic source rock from Cuba: 1. Cifuentes Formation in onshore via Blanca-Boca De Jaruco oils fields. Energy Exploration & Exploitation 31(6): 797–819.

Guo

Chai

(2015) Oil-source correlation and relative contribution of source rock from Enping Formation in Zhu I depression. Earth Science 40(7): 1177–1186. (in Chinese with English abstract).

Hakimi

Ahmed

(2016) Petroleum source rock characterisation and hydrocarbon generation modeling of the Cretaceous sediments in the Jiza sub-basin, eastern Yemen. Marine and Petroleum Geology 75: 356–373.

10.

Wang

Chen

(2015) Geochemical characteristics and origin patterns of oils in periphery of southwestern Traim Basin. Acta Petrolei Sinica 36(10): 1221–1233. (in Chinese with English abstract).

11.

Huang

Zhou

(1984) Evolution and Hydrocarbon Generation Mechanism of Terrestrial Organic Matter, Beijing: Petroleum Industry Press (in Chinese).

12.

Hudson

Hanson

(2010) Thermal maturation and hydrocarbon migration within La Popa Basin, northeastern Mexico, with implications for other salt structures. AAPG Bulletin 94: 273–291.

13.

Kosakowski

Wróbel

Krzywiec

(2013) Modelling hydrocarbon generation in the Palaeozoic and Mesozoic successions in SE Poland and West Ukraine. Journal of Petroleum Geology 36: 139–162.

14.

Liu

Lin

(2006) Tectonic evolution and petroleum prospects of the Mesozoic Inggen-Ejinaqi basin, Inner Mongolia. Geology in China 33: 1328–1355.

15.

Wei

(2010) Petroleum geological conditions of Carboniferous-Permian in Ejina Banner and its vicinities, western Inner Mongolia, China. Geological Bulletin of China 29(2/3): 330–340. (in Chinese with English abstract).

16.

Martínez

Márquez

Gutiérrez

(2014) Is there a pre-Cretaceous source rock in the Colombia Putumayo Basin? Clues from a study of crude oils by conventional and high resolution geochemical methods. Geologica Acta 12(4): 345–350.

17.

Pang

Jin

(2004) Quantitative assessment of hydrocarbon expulsion of petroleum systems in the Niuzhuang sag, Bohai Bay Basin, East China. Acta Geologica Sinica 78: 615–625.

18.

Pang

Liu

(2012) Dynamic field division of hydrocarbon migration, accumulation and hydrocarbon enrichment rules in sedimentary basins. Acta Geologica Sinica 86: 1559–1592.

19.

Qiu

Chang

Zuo

(2012) Thermal evolution and maturation of lower Paleozoic source rocks in the Tarim Basin, northwest China. AAPG Bulletin 96: 789–821.

20.

Qiu

Zuo

Zhou

(2010) Geothermal regime of the Bohai offshore area, Bohia Bay Basin, North China. Energy Exploration & Exploitation 28: 327–350.

21.

Resak

Glasmacher

Narkiewicz

(2010) Maturity modeling integrated with apatite fission-track dating: Implications for the thermal history of the Mid-Polish Trough (Poland). Marine and Petroleum Geology 27: 108–115.

22.

Sweeney

Burnham

(1990) Evaluation of a simple model of vitrinite reflectance based on chemical kinetics. AAPG Bulletin 74: 1559–1570.

23.

Tian

Lei

(2016) Development controlling factors and forming model for source rock of Yueguifeng Formation in Lishui-Jiaojiang sag, the East China Sea Continental Shelf Basin. Earth Science 41(9): 1561–1571. (in Chinese with English abstract).

24.

Wei

Zhang

Chen

(2006) Petroleum Geological Characteristics and Exploration Prospects in the Yingen–Ejinaqi Basin, Beijing: Petroleum Industry Press (in Chinese).

25.

Zhu

Qiu

Cao

(2016) Paleogeothermal reconstruction and thermal evolution modeling of source rocks in the Puguang Gas field, Northeastern Sichuan Basin. Journal of Earth Science 27(5): 796–806.

26.

Zuo YH, Ma WM, Deng YX, et al. (2013a) Mesozoic and Cenozoic thermal history and source rock thermal evolution history in the Chagan sag, Inner Mongolia. Earth Science-Journal of China University of Geosciences 38(3): 553–560 (in Chinese with English abstract).

27.

Zuo YH, Qiu NS, Deng YX, et al. (2013b) Terrestrial heat flow in the Qagan sag, Inner Mongolia. Chinese Journal of Geophysics 56(9): 3038–3050 (in Chinese with English abstract).

28.

Zuo

Qiu

Hao

(2014) Present geothermal fields of the Dongpu sag in the Bohai Bay Basin. Acta Geologica Sinica (English Edition) 88(3): 915–930.

29.

Zuo

Qiu

Hao

(2015a) Geothermal regime and source rock thermal evolution history in the Chagan sag, Inner Mongolia. Marine and Petroleum Geology 59: 245–267.

30.

Zuo

Qiu

Pang

(2015b) Meso-Cenozoic tectono-thermal evolution history in Bohai Bay Basin, North China. Journal of Earth Science 26(3): 352–360.

31.

Zuo

Qiu

Zhang

(2011) Geothermal regime and hydrocarbon kitchen evolution of the offshore Bohai Bay Basin, North China. AAPG Bulletin 95(5): 749–769.

32.

Zuo

Wang

(2016a) Tectono-thermal evolution and gas source potential for natural gas hydrate in the Qilian Mountain Permaforst, China. Journal of Natural Gas Science and Engineering 36A: 32–41.

33.

Zuo

Wang

Tang

(2016b) Mesozoic and Cenozoic thermal history and source rock thermal evolution of the Baiyinchagan sag, Erlian Basin, Northern China. Journal of Petroleum Science and Engineering 139: 171–184.

Lower Cretaceous source rock evaluation and thermal maturity evolution of the Chagan depression,Inner Mongolia,Northern China

Abstract

Keywords

Introduction

Geological setting

Geological setting of the Yingen-Ejinaqi Basin

Geological setting of the Chagan depression

Present geothermal fields and thermal history of the Chagan depression

Method and principle of source rock thermal maturity evolution

Results

Source rock evaluation

Organic matter abundance

Organic matter type

Chloroform bitumen “A” group component

Organic matter maturity

Source rock distribution

Source rock thermal maturity evolution of typical wells

Thermal maturity evolution of the main source rocks

Thermal maturity evolution of the Suhongtu 1 Formation

Thermal maturity evolution of the Bayingebi 2 Formation

Thermal maturity evolution of the Bayingebi 1 Formation

Discussions

Relationship between thermal maturity evolution of source rocks and hydrocarbon distribution

Favorable exploration area in the Chagan depression

Conclusions

Footnotes

Acknowledgements

Declaration of conflicting interests

Funding

References