Influence of Natural Fractures on Tight Oil Migration and Production: A Case Study of Permian Lucaogou Formation in Jimsar Sag, Junggar Basin, NW China

Zhang, Yunzhao; Zeng, Lianbo; Luo, Qun; Zhu, Rixiang; Lyu, Wenya; Liu, Dongdong; Dai, Quanqi; Pan, Shouxu

doi:10.1007/s12583-021-1442-y

Cited by 18 publications

(7 citation statements)

References 90 publications

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“…In addition, the permeability calculation results based on eq 9 are compared in Figure 11b. S4 has the worst predicted permeability with an actual value of 0.52 μm 2 compared to the predicted value of 0.36 μm 2 , but the overall prediction is reasonable with an average absolute error of 0.06 2 . The relationship between the porosity and permeability shows a positive correlation in both actual and predicted values with corresponding correlation coefficients of 0.88 and 0.86, respectively, and the linear relationships between the two basically coincide.…”

Section: 4mentioning

confidence: 85%

“…The pore structure inside underground reservoir rock is the main space for hydrocarbon storage and migration. , In addition, microscopic petrophysical properties such as the pore morphology, pore size distribution (PSD), and permeability can provide an important basis for reservoir evaluation, development, and enhanced hydrocarbon recovery. , However, the microscopic pore structure of underground rock is complex, and the pore shapes and types are diverse, leading to an unclear fluid flow mechanism. − This limits the exploration and development of underground energy resources. Therefore, it is of great significance to characterize the pore shape and topology and in turn analyze their influence on permeability.…”

Section: Introductionmentioning

confidence: 99%

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Influence of Pore Morphology on Permeability through Digital Rock Modeling: New Insights from the Euler Number and Shape Factor

Qin

Xia

et al. 2022

Energy Fuels

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The microscopic pore shape and topology significantly affect fluid transport and occurrence in porous permeable rock. A quantitive characterization of the impact of pore morphology on permeability is currently lacking, which limits the efficient development of underground hydrocarbon resources. This work introduces the Euler number and shape factor to characterize the pore topology and shape of heterogeneous sandstone based on CT imaging. The pore morphology under different pore sizes and the correlation of the Euler number, shape factor, fractal dimension, and surface area are analyzed. Furthermore, a modified Kozeny–Carman equation is established to explain the influence of the Euler number and shape factor on permeability. The results show that with the increase of pore diameter, the Euler number decreases while the shape factor increases. In a connected pore system, the smaller Euler number corresponds to the complex pore network, which leads to the increase in the surface area, shape factor, and fractal dimension. At constant porosity, the shape factor is negatively correlated with permeability, and with increasing Euler number, the heterogeneity of the pore structure increases, resulting in an increase of flow resistance and a decrease of permeability. The results provide a new pore morphology characterization method for digital rock and help to understand the flow mechanism of hydrocarbons in complex pore networks.

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Section: 4mentioning

confidence: 85%

Section: Introductionmentioning

confidence: 99%

Influence of Pore Morphology on Permeability through Digital Rock Modeling: New Insights from the Euler Number and Shape Factor

Qin

Xia

et al. 2022

Energy Fuels

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“…Since 2011, concerns have been increasingly raised about the exploration and development of tight oil (Guoxin Li et al, 2020;Zhang et al, 2021). The Lucaogou Formation in the Jimsar Sag of the Junggar Basin is the priority to explore and develop tight oil in the Jimsar Sag (Kuang et al, 2015;Wang 2021;Zhi et al, 2019).…”

Section: Introductionmentioning

confidence: 99%

The Influence of Continental Mixosedimentite Sedimentation on Shale Oil Sweet Spot: A Case Study on the Permian Lucaogou Formation in the Jimsar Sag of the Junggar Basin, NW China

Liang¹,

Zhang²,

Zhu³

et al. 2023

Front. Earth Sci.

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Over the years, shale oil has been at the leading edge of oil exploration and also become the hotspot of reserve increases for various oil fields. The Permian Lucaogou Formation in the Jimsar Sag has been less extensively researched in terms of, among others, lithologic interpretation of fine-grained mixosedimentite, identification and classification of sedimentary microfacies, and sweet spot evaluation. The present study identifies the classification of sedimentary microfacies, characteristic distribution of sedimentary reservoir, and spatial configuration distribution of facies-controlled sweet spot body based on core logging, cutting logging, and data while drilling, combined with logging information, experimental analysis data, and production data with respect to formation test and production test and through the lithology identification based on element logging. This study indicated the following: 1) Microfacies of the reservoir body include a shallow lacustrine sand bar, mixing beach, and dolomitic flat. Different microfacies are adapted to different lithologies or lithological associations. 2) The lower sweet spots P2l12−3, P2l12−2, and P2l12−1 evolved into the dolomitic flat from mixing beach from NE to W. Also, the dolomitic flat is mostly developed in the west of the work area, and the mixing beach is better developed in the east. The shallow lacustrine sand bar is highly developed in the middle location, and the mixing beach and shallow lacustrine sand bar are highly developed on the northern and southern sides. 3) Sedimentary microfacies have evident controls over sweet spots. The upper sweet spots P2l22−3 and P2l22−2 are dominated by Class I sweet spots followed by Class II and IV sweet spots, which are major sweet spot reservoirs. The upper sweet spot P2l22−1 is mainly suffused with Class IV sweet spots, and the Class I reservoir is feldspathic litharenite (shallow lacustrine sand bar microfacies accordingly).

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“…Traditionally, fractures have been jointly identified by conventional logs of acoustic slowness(AC), compensated neutron(CNL), compensated density(DEN), dual lateral resistivity 19 – 22 . FMI as an unconventional log is the most intuitive and useful to identify fracture 23 , 24 , 25 , 26 , 27 , 28 . For the Da'anzhai member of the central Sichuan, with a history of more than 50 years’ oil exploration and development, the majority of wells in this area are old wells with conventional logs.…”

Section: Introductionmentioning

confidence: 99%

Identification of fractures in tight-oil reservoirs: a case study of the Da'anzhai member in the central Sichuan Basin, SW China

Tian

Liu

Wang

et al. 2021

Sci Rep

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The Da'anzhai Member of the Jurassic Ziliujing formation in central Sichuan is a typical tight-oil reservoir with porosity and permeability less than 2% and 0.1 × 10–3 μm2, respectively. Fractures in this formation are well developed in micro- and nano-scale. However, the factors that control the fracture distribution are unclear. Additionally, the uncomprehensive and ineffective identification and evaluation of fractures in the early stage of tight-oil development makes it difficult to meet the requirements of tight-oil development. In our work, we used cores, thin sections, and a scanning electron microscope (SEM) to study the influence of the microscopic rock composition, including the shelly grains, calcite grains, and clastic grains, on the fracture development. We found that the microscopic composition of shelly grains and calcite grains separately control the development of inter-shelly fractures and shelly fractures, and intergranular fractures, and tectonic fractures. Except for a small number of dissolution fractures found in mudstone, the fractures are not well developed in the formations with clastic grains. According to the characteristics of the development degree of fracture and the resolution of the well-logs, the fractures are divided into large scale, small scale, and micro-scale. By a newly established level-by-level constraints method, we systematically identified the scale, occurrence, filling characteristics, and development degree of fractures in the Da'anzhai member by well-logs. Moreover, a quantitative model is also proposed for identifying the angles and development degree of fractures. The results show that the scale of fractures can be effectively identified by the shapes and values of resistivity logs; the occurrence, development, and filling characteristics of fractures can be semi-quantitatively evaluated by the relative amplitude difference between the matrix resistivity (Rb) and formation resistivity (RT). The results are consistent with the interpretation results by formation micro-resistivity imaging (FMI) log, which further demonstrates that the level-by-level constraint method by conventional well-logs can be used to systematically and effectively predict the fracture characteristics in tight-oil reservoirs.

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Influence of Natural Fractures on Tight Oil Migration and Production: A Case Study of Permian Lucaogou Formation in Jimsar Sag, Junggar Basin, NW China

Cited by 18 publications

References 90 publications

Influence of Pore Morphology on Permeability through Digital Rock Modeling: New Insights from the Euler Number and Shape Factor

Influence of Pore Morphology on Permeability through Digital Rock Modeling: New Insights from the Euler Number and Shape Factor

The Influence of Continental Mixosedimentite Sedimentation on Shale Oil Sweet Spot: A Case Study on the Permian Lucaogou Formation in the Jimsar Sag of the Junggar Basin, NW China

Identification of fractures in tight-oil reservoirs: a case study of the Da'anzhai member in the central Sichuan Basin, SW China

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