Major factors controlling fracture development in the Middle Permian Lucaogou Formation tight oil reservoir, Junggar Basin, NW China

Zhang, Chen; Zhu, Dongya; Luo, Qun; Liu, Luofu; Liu, Dongdong; Lin, Yan-Bo; Zhang, Yunzhao

doi:10.1016/j.jseaes.2017.04.032

Cited by 69 publications

(34 citation statements)

References 64 publications

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“…Well D2 obtained low oil production flow (0.7 m³/d), and accumulated oil production of 8.36 m³ in Paleogene oil test [21]. Based on the analysis of the measure of the gas-liquid inclusion homogenization and the composition of biomarkers in and out of the inclusions in the Paleogene sandstone reservoir of well D2, it is considered that this is a secondary reservoir formed in the Paleogene after the destruction of the primary reservoir in Late Triassic [47]. This secondary reservoir can be regarded as a realistic and economic exploration target series.…”

Section: Fractures Evolution and Hydrocarbon Accumulationmentioning

confidence: 99%

Fracture characteristics from outcrops and its meaning to gas accumulation in the Jiyuan Basin, Henan Province, China

Sun

Yang

et al. 2020

Open Geosciences

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The target Oil-Shale Member (TOSM) in the Upper Triassic Tanzhuang Formation in the Jiyuan Basin is about 140 m thick and its burial depth is generally between 3,000 and 7,000 m. This paper presents a study of fractures in outcrop analogs for the TOSM based on outcrop observations and experimental measurements. The role of fractures in gas accumulation in the Jiyuan Basin was also analyzed. Also, a workflow used in building discrete fracture models based on the outcrop observed data is described. Results show that the average total organic carbon content and vitrinite reflectance of the oil shale are 4.13 and 1.33%, respectively, with the organic matter type dominated by sapropel-humics (II1), indicating high potential for shale gas generation. Fracture characteristics showing mostly vertical or intersect the bedding at high angles, and partially unfilled. The fracture lengths and widths range from a few centimeters to several hundred meters, and 0.05 to 0.5 cm, respectively, and the average linear fracture density is 6.3 m. In addition, the average brittle-mineral content of the oil shale is 53.7%, indicating that the oil shale in the TOSM has strong fracability. The hydrocarbon generation occurred twice in the TOSM. The primary reservoir formed by the first hydrocarbon generation was destroyed by fractures and tectonic uplift, and partial hydrocarbon migrated to the Paleogene along the second-phase fractures to form a secondary reservoir. The gas formed by the second hydrocarbon generation was mainly migrated into the fracture network of the TOSM.

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Section: Fractures Evolution and Hydrocarbon Accumulationmentioning

confidence: 99%

Fracture characteristics from outcrops and its meaning to gas accumulation in the Jiyuan Basin, Henan Province, China

Sun

Yang

et al. 2020

Open Geosciences

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“…Diagenesis controls the evolution direction of pores in the process of burial diagenesis and is of great significance to reservoir evaluation and prediction [27,28]. e diagenetic type of the target layer in the study area is very complicated.…”

Section: Major Controlling Factorsmentioning

confidence: 99%

Microscale Mineral and Pore Structure Characterization of the Low‐Permeability Sandstone in the Ordos Basin, China

Gao¹,

Sun

Liu

et al. 2021

Advances in Civil Engineering

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Given the insufficient understanding of the characteristics and controlling factors of the low-permeability sandstone reservoir in the Heshui area, the Ordos Basin, the present study examined the microscale mineral and pore structure of Chang 2 reservoir. It analyzed its major controlling factors using a series of methods, including imaging and indirect methods. The results show that the rocks of Chang 2 reservoir in the study area are dominated by lithic arkose and feldspathic detritus quartz sandstone. The reservoir space develops intragranular pores, feldspar dissolved pores, lithic dissolved pores, and intercrystallite pores. Microcracks can occasionally be found. The average porosity is 10.5%, and the average permeability is 2.2 mD, featuring a low-porosity-ultralow-permeability reservoir. During the reservoir development, traps formed by small-scale nose-shaped uplifts resulting from the tectonic effects provide opportunities for good reservoir space. Sedimentation and diagenetic processes control the degree of development and direction of the evolution of reservoir porosity to a certain degree. Multisegment capillary pressure curve and long missing zone were corresponding to relatively good pore-throat structures. Illite was the predominant diagenetic clay minerals that determine the reservoir quality. These three effects all contribute to the overall development of the reservoir.

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“…F I G U R E 9 The evolution sequence of the Lucaogou Formation. The tectonic fractures formation times are derived from (C. Zhang, Zhu, et al, 2017), and the hydrocarbon charging times are derived from (Z. Cao, Liu, et al, 2017) (I phase oil charging / I phase tectonic fracture filling)feldspar disso- Compaction was the major reason for the reduction of porosity in tight reservoirs (Agersborg, Johansen, Mavko, & Vanorio, 2011;Ehrenberg, Nadeau, & Steen, 2009;Gier, Worden, Johns, & Kurzweil, 2008).…”

Section: Characteristics Of Calcite Fillings In Natural Fracturesmentioning

confidence: 99%

“…Relationship between diagenetic sequence and natural fracture evolutionAccording to the sequence of the mineral particles determined after observation under the microscope combined with the formation time of the tectonic fracture, as well as the diagenesis fracture formation time judged by the diagenesis intensity, the diagenesis and fracture formation, and their evolution sequences were determined to be as follows(Figures 9 and 10): bedding fracturecompaction (intragranular fractures and stylolite) -I phase tectonic fractures F I G U R E 8 Plot of the value of δ 13 C and δ 18 O (modified fromRahman & Worden, 2016). The data of calcite fillings in fractures are derived from (C Zhang, Zhu, et al, 2017)…”

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Effects of diagenesis on natural fractures in tight oil reservoirs: A case study of the Permian Lucaogou Formation in Jimusar Sag, Junggar Basin, NW China

et al. 2020

Self Cite

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Compared with conventional reservoirs, tight reservoirs experience more intense diagenesis; thus, their properties are extremely poor. Nevertheless, natural fractures with high‐strength can appear in these reservoirs and could play an essential role in the accumulation and production of tight oil. In this study, we focused on the effects of different diagenetic processes in the formation and transformation of natural fractures to determine the effects of natural fractures on tight reservoirs. Various observation techniques and analysis methods were applied (i.e., observations of cores, cast thin sections, scanning electron microscopy; field emission scanning electron microscopy; and X‐ray diffraction analysis). We clarified characteristics of the fractures and distribution patterns based on core descriptions and microscopic observations and explained the diagenetic stage and evolution sequence of reservoirs. Past studies regarding carbon and oxygen isotope analysis and basin simulation were considered. This study also reviewed the fracture formation time, source of fracture fillings, and oil charging time. We obtained insight into the coupling relationship of fracture states, diagenetic sequences, hydrocarbon charging, and, in particular, the controlling effect of diagenesis on natural fractures. The results revealed that formation, preservation, and destruction of natural fractures in tight reservoirs were closely related to diagenesis. Compaction and cementation in the reservoirs decreased the porosity and altered the petrophysical properties of the reservoir. They also provided favorable conditions for the development of tectonic fractures, while dissolution did not. The influences of dissolution and cementation on natural fractures depended on the duration for which these processes were active. Compaction and cementation formed related types of diagenetic fractures, while dissolution increased the effectiveness of natural fractures. The purpose of this study was to evaluate the influence of diagenesis on the formation, controlling effects, and effectiveness of natural fractures, as well as the effects of natural fractures on tight reservoirs through geological history. This study is expected to provide guidance for future exploration and development of tight oil and gas with similar geological origins.

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Major factors controlling fracture development in the Middle Permian Lucaogou Formation tight oil reservoir, Junggar Basin, NW China

Cited by 69 publications

References 64 publications

Fracture characteristics from outcrops and its meaning to gas accumulation in the Jiyuan Basin, Henan Province, China

Fracture characteristics from outcrops and its meaning to gas accumulation in the Jiyuan Basin, Henan Province, China

Microscale Mineral and Pore Structure Characterization of the Low‐Permeability Sandstone in the Ordos Basin, China

Effects of diagenesis on natural fractures in tight oil reservoirs: A case study of the Permian Lucaogou Formation in Jimusar Sag, Junggar Basin, NW China

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