Natural fractures and their contribution to tight gas conglomerate reservoirs: A case study in the northwestern Sichuan Basin, China

Zeng, Lianbo; Gong, Lei; Guan, Cong; Zhang, Benjian; Wang, Qiqi; Zeng, Q.; Lyu, Wenya

doi:10.1016/j.petrol.2021.110028

Cited by 61 publications

(28 citation statements)

References 28 publications

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“…The change in the mechanical properties of the rock reflects the difficulty degree of fracture development, so it is feasible to carry out fracture identification from the perspective of the rock mechanical properties (Zeng et al, 2022). Based on the sonic transit time logging of the compression and shear waves, the mechanical parameters of the rock can be calculated, and a stability coefficient reflecting the rock fracture characteristics can be constructed.…”

Section: Identification Methods Based On Rock Integrity Evaluationmentioning

confidence: 99%

“…It is proposed to classify the fractures in tight sandstone in terms of fracture mode, mechanical properties, and geological origin (Nelson, 2001;Laubach et al, 2009). Quantitative characterization methods of multiscale natural fractures based on outcrops, cores, thin sections, SEM, and CT were established (Fall et al, 2015;Zeng et al, 2022). Natural fractures were identified and evaluated using logging and drilling data with production performance data (Ezati et al, 2018;Fernández-Ibáez et al, 2018;Stockmeyer et al, 2018), and methods including the curvature method, geomechanical simulation, and geophysical methods have been proposed (Olson et al, 2009;Yin et al, 2016;Hooker et al, 2018;Gong et al, 2021).…”

Section: Introductionmentioning

confidence: 99%

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Natural Fractures in Low-Permeability Sandstone Reservoirs in the LD-A HPHT Gas Field, Yinggehai Basin: Implications for Hydrocarbon Exploration and Development

Fan²,

Jiang

et al. 2022

Front. Earth Sci.

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Research on the characteristics and distribution of natural fractures is of great importance for the exploration and development of low-permeability sandstone gas reservoirs. In this study, fracture identification and characterization were carried out using cores and imaging logging. Then, comprehensive fracture development indicators were constructed to predict the distribution of fractures in wells by conventional logging. The main factors that affect the development of natural fractures and the implications of fractures on hydrocarbon exploration and development were discussed. The results showed that the natural fractures were mainly low-angle tectonic fractures in sandstone reservoirs. Most of fractures are unfilled, but the distribution of the fractures in the thin sections has a discrete fracture structure, indicating that the connectivity of the fracture system is poor. The development of natural fractures is mainly influenced by rock strength, petrographic composition, and petrology, and the fractures are more developed in sandstones with a higher content of brittle minerals. The fracture densities are mainly distributed below 0.05 m/m and up to 0.1 m/m. In the present in situ stress state, all of the natural fractures in the LD-A gas field are invalid fractures. The critical pressure of the natural fracture is approximately 16.5–25.4 MP/km; when the pore pressure exceeds this value, the fractures become effective fractures. These results provide new geological knowledge and guidance for the exploration and development of LD-A gas fields and other low-permeability tight sandstone reservoirs.

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Section: Identification Methods Based On Rock Integrity Evaluationmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Natural Fractures in Low-Permeability Sandstone Reservoirs in the LD-A HPHT Gas Field, Yinggehai Basin: Implications for Hydrocarbon Exploration and Development

Fan²,

Jiang

et al. 2022

Front. Earth Sci.

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“…Relatively high-porosity and well-developed microfractures are essential to configuring permeable zones in tight gas sandstone reservoirs, functioning as one of the dominant factors for gas enrichment. Simultaneously, the development of natural microfractures facilitates the formation of pore-fracture networks during hydraulic fracturing, which is a crucial factor in gas productivity [1][2][3]. The primary types of pore space in tight sandstones include dissolved inter-granular and intra-granular pores, microcracks, microfractures, and structural fractures.…”

Section: Introductionmentioning

confidence: 99%

Pore and Microfracture Characterization in Tight Gas Sandstone Reservoirs with a New Rock-Physics-Based Seismic Attribute

Guo¹,

Qin²,

Liu³

2023

Remote Sensing

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Pores and microfractures provide storage spaces and migration pathways for gas accumulation in tight sandstones with low porosity and permeability, acting as one of the controlling factors of gas production. The development of a rational rock physics model is essential for better understanding the elastic responses of tight sandstone with complex pore structures. Accordingly, seismic characterization of pores and microfractures based on the rock physics model provides valuable information in predicting high-quality tight gas sandstone reservoirs. This paper proposes a rock-physics-based approach to compute the pore–microfracture indicator (PMI) from elastic properties for pore structure evaluation in tight sandstones. The PMI is achieved based on the axis rotation of the elastic parameter space using well-log data. The rotation angle is determined by finding the maximum correlation between the linearized combination of the elastic parameters and the introduced factor associated with total porosity and microfracture porosity. The microfracture porosity is then estimated with an inversion scheme based on the double-porosity model. Finally, the optimized rotation angle is employed to compute the PMI with seismic data. The obtained results are of great benefit in predicting the permeable zones, providing valuable information for sweet spot characterization in tight gas sandstone reservoirs.

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“…Currently, the most used methods for flow unit division include the flow zone index method (FZI) [2][3][4][5][6], interwell flow capacity index method (IFCI) [7,8], modified stratum Lorentz plot method (SMLP) [9], fuzzy clustering method [10][11][12][13][14][15][16][17][18][19][20][21], gray system theory method [22,23], and inhomogeneous comprehensive index method [24][25][26][27]. These methods are mostly based on the penetration of cores and the formation of the reservoir.…”

Section: Introductionmentioning

confidence: 99%

Dynamic Evaluation of Flow Unit Based on Reservoir Evolution: A Case Study of Neogene Guantao Ng3 Formation in M Area, Gudao, Bohai Bay Basin

et al. 2022

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To clarify the dynamic evolution characteristics of reservoir flow units during water injection development, the upper member of the Neogene Guantao formation in Block M of Gudao Oilfield is taken as a case study. Based on logging data, water injection profile test data, subwell data, and production performance data, among others, the flow zone index (FZI static) was proposed as the static evaluation parameter of the flow unit. The relationship between cumulative water injection (WT) and FZI change ( △ FZI ) was fitted. Hence, the △ FZI caused by water injection is combined with the static parameter of flow unit evaluation (FZI static) as the dynamic parameter of flow unit evaluation (FZI dynamic). The comprehensively evaluated reality of flow units in different periods is characterized by formula FZI static + △ FZI = FZI dynamic . The study shows that as the division standard of the flow unit, the FZI has a good correlation with the test results of the water absorption profile, such as water absorption intensity and relative water injection volume. Using the FZI as the static parameter of flow unit evaluation, four types of flow units were divided as follows: type I flow unit, FZI ≥ 4.1 ; type II flow unit, 4.1 > FZI ≥ 2.4 ; type III flow unit, 2.4 > FZI ≥ 1.7 ; type IV flow unit, 1.7 > FZI . The reservoir porosity and permeability characteristics of different flow units are highly correlated. Moreover, the relative permeability curve confirms that different flow units have different seepage capacities. Though, comparing characteristic reservoir parameters in different periods, the reservoir’s physical parameters became more conducive to fluid flow with the water injection development. The increase in the same water injection rate for type I and II flow units was greater than that for type III and IV flow units. Furthermore, when type I flow units were continuously distributed in a large area, high water consumption bands were formed, absorbing most of the water injection in the water injection wells. Hence, the waterflood efficiency was low. The change in different flow units was mainly controlled by the injection production well pattern and WT. Combined with the relative change characteristics of interlayer flow units, the changes can be divided into increasing type change and decreasing type changes. Finally, according to the distribution characteristics of different flow units, oil saturation, and water flooding results, strategies for tapping the potential of the remaining oil from three aspects (plane, interlayer, and inner layer) were formulated.

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Natural fractures and their contribution to tight gas conglomerate reservoirs: A case study in the northwestern Sichuan Basin, China

Cited by 61 publications

References 28 publications

Natural Fractures in Low-Permeability Sandstone Reservoirs in the LD-A HPHT Gas Field, Yinggehai Basin: Implications for Hydrocarbon Exploration and Development

Natural Fractures in Low-Permeability Sandstone Reservoirs in the LD-A HPHT Gas Field, Yinggehai Basin: Implications for Hydrocarbon Exploration and Development

Pore and Microfracture Characterization in Tight Gas Sandstone Reservoirs with a New Rock-Physics-Based Seismic Attribute

Dynamic Evaluation of Flow Unit Based on Reservoir Evolution: A Case Study of Neogene Guantao Ng3 Formation in M Area, Gudao, Bohai Bay Basin

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