Origin of giant vein-type bitumen deposits in the northwestern Junggar Basin, NW China: Implications for fault-controlled hydrocarbon accumulation

Zhang, Jingkun; Cao, Jian; Wang, Yan; Hu, Guang; Zhou, Ni; Shi, Tianming

doi:10.1016/j.jseaes.2019.05.009

Cited by 16 publications

(18 citation statements)

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“…Oil sand samples were studied using plane‐polarized, cross‐polarized, and fluorescence microscopy to determine their petrography and nature of the hydrocarbon charge (Zhang et al, ). A Nikon ECLIPSE LV100N POL microscope was used, with a 100‐W mercury beam light source and Nikon DS‐Ri1 digital microscope image processing system.…”

Section: Sampling and Methodologymentioning

confidence: 99%

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Diverse oil and gas seeps in the southern Junggar Basin, NW China (piedmont Northern Tian Shan): Origins and links to tectono‐sedimentary evolution

et al. 2019

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The southern Junggar Basin in NW China is a world‐class location for the study of oil and gas seeps, with widely distributed, highly variable oil and gas seeps including gaseous mud volcanoes, liquid oil seeps, and solid bitumen deposits. However, the sources and origins of these seeps are poorly understood, as there are many potential source sequences of Permian to Paleogene age. The uncertainty surrounding the seeps means that it has not been possible to address their significance for oil and gas exploration in the area, and they are not understood in the context of the tectono‐sedimentary evolution of the basin within the piedmont region of the northern Tian Shan Mountains (in the eastern part of the Central Asian Orogenic Belt, CAOB). In the present study, these issues were addressed using combined geological and geochemical methods. Results show that there are five main types of seeps in the region from west to east. Type A seeps originate from Jurassic source rocks and are best represented by the A'erqingou mud volcano. Type B seeps originate mainly from Paleogene source rocks but also contain a Jurassic‐sourced component; they are best represented by the Dushanzi mud volcano. Type C seeps originate from a Cretaceous source and are best represented by the South Anjihai and Horgos oil sands. Type D seeps originate mainly from Jurassic source rocks but also contain a Triassic‐sourced component; they are best represented by the Qigu oil seep. Type E seeps originate from Permian source rocks and are best represented by the Dalongkou bituminous deposit. The primary controls on seep distribution are both sedimentological (deposition of source rock) and tectonic (faulting). The position and burial history of sedimentary centres controlled the distribution and maturation of source rocks. Tectonic faults provided migration pathways and traps for the oil and gas. The results of this study will help to reduce uncertainty during exploration for oil and gas in the area. The findings also have general implications for petroleum systems and exploration in the piedmont areas of foreland basins worldwide.

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Section: Sampling and Methodologymentioning

confidence: 99%

“…Gas chromatography (GC) and GC mass spectrometry (GC–MS) were used to obtain biomarker compositions (Zhang et al, ). Gas chromatography was undertaken using a HP6890 chromatograph fitted with a 30 m × 0.32 mm inner diameter (i.d.)…”

Section: Sampling and Methodologymentioning

confidence: 99%

Diverse oil and gas seeps in the southern Junggar Basin, NW China (piedmont Northern Tian Shan): Origins and links to tectono‐sedimentary evolution

et al. 2019

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“…For a vertical load F N of~1300-1500 Pa, the values of cohesion and the angle of internal friction for the quartz sand are The bulk density of a granular material was measured by sifting the granular material into the measurement container from a consistent height and weighing the known volume of material on an electronic balance. (2) The porosity of the granular material was determined by pouring a known volume of a granular material into a measuring cylinder containing a certain amount of pure water and measuring the volume of the empty space and the material particle. The porosity of the granular material is calculated from the known volume of the empty space divided by the total volume of the material.…”

Section: Experimental Materialsmentioning

confidence: 99%

“…Hydrocarbon migration from source rocks through water saturated carrier beds, faults, and unconformities to reservoir rocks is a complex subsurface process [1,2]. Although migration is important to hydrocarbon exploration, our understanding of the process has been limited by the long geological time involved and by the inability to observe it directly [3][4][5][6].…”

Section: Introductionmentioning

confidence: 99%

A Method to Simulate the Migration and Accumulation of Hydrocarbon with Analogue Modeling

et al. 2021

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Subsurface migration and accumulation of oil and gas have interested researchers for a long time, but these processes may occur over very long geological periods and are difficult to observe directly, so experimental simulations are warranted. In this study, an experimental method was developed to model hydrocarbon migration in the subsurface structure. Oil migration was simulated in a sandbox model, and industrial CT scanning was used to observe both the internal geometry of the model and the oil migration pathways. In the sandbox model, a NaI solution was used to simulate water, white oil was used to simulate hydrocarbon, and fine quartz sand, glass bead, silica powder, and brown corundum were chosen to represent brittle crust, based on suitable material parameters. A NaI-saturated layered sandbox model was constructed with an along-strike basal discontinuity, which during compression allowed a simple anticline with doubly verging reverse faults to form. Oil was then released continuously at a low rate from an orifice under one limb of the anticline. Initially, the oil migrated vertically through the fault zone until it reached the top of the fault zone; it then migrated laterally along the core of the anticline, saturating a model reservoir by buoyancy and capillary force. This experimental analog helps to explain hydrocarbon migration and accumulation within the Anjihai and Santai anticlines in northwest China.

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“…(2006) argued that oil and gas charging in the Chang-3 reservoir occurred in two stages: the first stage during the Early Cretaceous (122 Ma) and the second during the Late Cretaceous (80 Ma). With respect to the hydrocarbon accumulation model, previous studies have proposed that the Chang-7 member represents the main source rocks and that generated hydrocarbons migrated laterally and vertical to form oil reservoirs in the lower part of Yanchang Formation (Li et al., 2012; Shi et al., 2012; Watson et al., 1987; Xia et al., 2019; Zhang et al., 2019; Zou et al., 2013). Recent discoveries in several exploration wells indicate that the upper Yanchang Formation (Chang-3, 4, and 5) are also potential economic oil reservoirs (Wang et al., 2005; Xiao et al., 2011); however, hydrocarbon accumulation in this model is poorly understood.…”

Section: Introductionmentioning

confidence: 99%

Reservoir characteristics and multi-stage hydrocarbon accumulation of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, NW China

Liao

Chen

et al. 2019

Energy Exploration & Exploitation

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The Chang-8 and Chang-6 members of the Upper Triassic Yanchang Formation (lower part) are regarded as the main oil producing members of the Ordos Basin. Recently, new hydrocarbon discoveries have been made in the upper part of the Yanchang Formation (e.g., Chang-3) in the southwestern Ordos Basin, implying that this interval also has a good potential for hydrocarbon exploration. However, studies on the origin of the high-quality reservoir, hydrocarbon migration, and accumulation patterns remain insufficient. In this study, integrated petrological, mineralogical, and fluid inclusion tests are employed to evaluate reservoir characteristics, and reconstruct the history of hydrocarbon migration and accumulation during oil and gas reservoir formation. The results reveal that the Yanchang Formation is characterized by low porosity (8 − 14%), medium permeability (0.5 − 5 mD), and strong heterogeneity; the reservoir properties are controlled by secondary porosity. Two types of dissolution are recognized in the present study. Secondary pore formation in the lower part of the formation is related to organic acid activity, while dissolution in the upper part is mainly influenced by atmospheric fresh water associated with the unconformity surface. The Yanchang Formation underwent hydrocarbon charging in three phases: the early Early Cretaceous, late Early Cretaceous, and middle Late Cretaceous. A model for hydrocarbon migration and accumulation in the Yanchang reservoirs was established based on the basin evolution. We suggest that hydrocarbon accumulation occurred at the early stage, and that hydrocarbons migrated into the upper part of the Yanchang Formation by way of tectonic fractures and overpressure caused by continuous and episodic hydrocarbon expulsion during secondary migration, forming potential oil reservoirs during the later stage.

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Origin of giant vein-type bitumen deposits in the northwestern Junggar Basin, NW China: Implications for fault-controlled hydrocarbon accumulation

Cited by 16 publications

References 40 publications

Diverse oil and gas seeps in the southern Junggar Basin, NW China (piedmont Northern Tian Shan): Origins and links to tectono‐sedimentary evolution

Diverse oil and gas seeps in the southern Junggar Basin, NW China (piedmont Northern Tian Shan): Origins and links to tectono‐sedimentary evolution

A Method to Simulate the Migration and Accumulation of Hydrocarbon with Analogue Modeling

Reservoir characteristics and multi-stage hydrocarbon accumulation of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, NW China

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