Seismic fracture detection of shale gas reservoir in Longmaxi formation, Sichuan Basin, China

2017 ◽  
Author(s):  
Yujia Lu ◽  
Junxing Cao ◽  
Xudong Jiang
Keyword(s):  
Shale Gas ◽  
Sichuan Basin ◽  
Fracture Detection ◽  
Gas Reservoir ◽  
Longmaxi Formation ◽  
Shale Gas Reservoir

scholarly journals Classification and Evaluation on Shale Gas Reservoir for Wufeng-Longmaxi Formation in Chuannan Area, Sichuan Basin

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Jianlin Guo ◽  
Chengye Jia ◽  
Dongbo He ◽  
Fankun Meng
Keyword(s):  
Shale Gas ◽  
Sichuan Basin ◽  
Gas Content ◽  
Brittleness Index ◽  
Type I ◽  
Gas Reservoir ◽  
Longmaxi Formation ◽  
Positive Correlation ◽  
Gas Saturation ◽  
Shale Gas Reservoir

Abstract Based on the comprehensive statistic and analysis on some representative geological and physical data, the classification criteria on net pay for shale gas reservoir of the Wufeng-Longmaxi formation in Shunan area, Sichuan Basin, are proposed, which include porosity (φ), gas saturation (Sg), density of rock (DEN), brittleness index (BI), and gas content (Vt). When the porosity, gas saturation, brittleness index, and gas content are larger than 3%, 30%, 40%, and 1 m3/t, respectively, and the density of rock is lower than 2.7 g/cm3, then this formation can be seen as the net pay. The application of two key parameters, gas content and brittleness index, could reflect the reservoir resource basis and fracability, respectively. The gas content has a positive correlation with porosity and total organic volume, and the brittleness index has a positive correlation with siliceous and carbonate content. According to the range of these two parameters, the net pay can be classified into three types. For type I, the gas content and brittleness index are larger than 4 m3/t and 50%, respectively. For type II, either the gas content or the brittleness index is lower than 4 m3/t and 50%. For type III, the gas content should be larger than 1 m3/t and lower than 4 m3/t, and the brittleness index is between 40% and 50%. The field application case indicates that the Wufeng formation and low member of the Longmaxi formation have good quality and mainly consist of type I and II formations. In addition, it is found that there is a positive correlation between the penetration ratio for type I formation and the testing production and estimate ultimate recovery (EUR). While this ratio is larger than 50%, the testing production rate and EUR will be over 15×104 m3/d and 8000×104 m3 with a probability of 92%, which meet the requirement of exploitation with reasonable economic benefits.

Characteristics of the Shale Gas Reservoir Rocks in the Lower Silurian Longmaxi Formation, East Sichuan Basin, China

2013 ◽  
Vol 31 (2) ◽  
pp. 187-219 ◽  
Author(s):  
Shugen Liu ◽  
Wenxin Ma ◽  
Lubomir Jansa ◽  
Wenming Huang ◽  
Xiangliang Zeng ◽  
...  
Keyword(s):  
Shale Gas ◽  
Sichuan Basin ◽  
Gas Reservoir ◽  
Longmaxi Formation ◽  
Reservoir Rocks ◽  
Lower Silurian ◽  
Shale Gas Reservoir

scholarly journals Total Porosity Measured for Shale Gas Reservoir Samples: A Case from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China

Minerals ◽  
2018 ◽  
Vol 9 (1) ◽  
pp. 5 ◽  
Author(s):  
Fangwen Chen ◽  
Shuangfang Lu ◽  
Xue Ding ◽  
Hongqin Zhao ◽  
Yiwen Ju
Keyword(s):  
Shale Gas ◽  
Clay Content ◽  
Total Porosity ◽  
Gas Reservoir ◽  
Longmaxi Formation ◽  
Fine Grained ◽  
Average Value ◽  
Lower Silurian ◽  
Shale Gas Reservoir ◽  
Research Institute

Measuring total porosity in shale gas reservoir samples remains a challenge because of the fine-grained texture, low porosity, ultra-low permeability, and high content of organic matter (OM) and clay mineral. The composition content porosimetry method, which is a new method for the evaluation of the porosity of shale samples, was used in this study to measure the total porosity of shale gas reservoir samples from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China, based on the bulk and grain density values. The results from the composition content porosimetry method were compared with those of the Gas Research Institute method. The results showed that the composition content porosimetry porosity values of shale gas reservoir samples range between 2.05% and 5.87% with an average value of 4.04%. The composition content porosimetry porosity generally increases with increasing OM and clay content, and decreases with increasing quartz and feldspar content. The composition content porosimetry results are similar to the gas research institute results, and the differences between the two methods range from 0.05% to 1.52% with an average value of 0.85%.

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