You are here
Home > BLOG > China Shale > Pore evolution characteristic of shale in the Longmaxi Formation, Sichuan Basin

Pore evolution characteristic of shale in the Longmaxi Formation, Sichuan Basin

Fig. 1. Structural characteristics of Sichuan Basin and sampling locations (modified from Liu et al. (2016)).

Result shows that the higher the maturity is (the stronger the inorganic diagenesis is), the lower the inorganic porosity will be (Fig. 11). Meanwhile, the entire shale reservoir is in the late diagenetic stage which is dominated by weak cementation and metasomatism (Wang et al., 2015b), and very few primary inorganic pores are preserved and no more secondary dissolution pores are formed; this stage has weak impacts on inorganic pores, and the maturity increases from 2.41% to 2.55%, whereas the inorganic porosity just decreases from 1.0% to 0.5%. Therefore, the effect of organic diagenesis on porosity in the shale of Longmaxi Formation is stronger than that of inorganic diagenesis.

Fig. 11. Effects of inorganic diagenesis on inorganic porosity in Changning and Weiyuan blocks showing that the higher the maturity is (the stronger the inorganic diagenesis is), the lower the inorganic porosity will be.


The effect of tectonism on shale porosity has been studied to some extent in the world (Li et al., 2015, Ji et al., 2016). Compared with the shale in intense tectonic modification sites with development of faults, the shale in stable tectonic sites have significantly higher porosity and larger pore volume, whereas the tectonism has insignificant impacts on specific surface area. The influence on porosity varies with tectonic site and compression strength.

The tectonism is weak in Weiyuan and Jiaoshiba areas, while the Changning area is compressed to form an anticline under the NE-direction stress, but the effect of this compression is weak; the Fengdu area is adjacent to the Jiaoshiba area, where reverse faults are developed; the Wuxi area is in the Dabashan fault belt, and is subjected to intense compressive deformation (Fig. 1).

According to analysis of porosity characteristics of Fengdu, Wuxi, Changning, Weiyuan and Jiaoshiba areas with the same TOC, the Weiyuan and Jiaoshiba areas have the weakest tectonism but the highest porosity, whereas the Fengdu and Wuxi areas have the strongest tectonism but the lowest porosity (Table 1).

In particular, a linear distance from Well JY1 in Jiaoshiba block to Well B1 in Fengdu block is about 7 km, and faults of Fengdu block are mainly formed in Himalayan Period (He et al., 2016); shale of Longmaxi Formation in these two wells have same sedimentary environment, maturity and diagenesis, but different tectonism; thus, porosity characteristics of the shale in these two wells are completely different: When TOC increases from 2% to 4%, the porosity of Well B1 increases from 1.8% to 3.0%, the porosity of Well JY1 decreases from 7.0% to 4.5%, Well X2 and Well JY1 have a same changing trend of porosity while Well N3 and Well B1 have a opposite changing trend of porosity.

Table 1. Porosity distribution of samples with same TOC from Longmaxi Formation under different tectonism in Sichuan Basin.

Since hydrocarbons in pores well protect pore spaces, effect of tectonism on shale porosity should be studied in combination with hydrocarbon generation history. If major tectonic activities occur prior to the peak hydrocarbon generation period, then the tectonic compression will have a significant disruptive effect on shale pores, and the fault activities during this period will have little impact on shale pores. If major tectonic activities occur after the peak hydrocarbon generation period, then the tectonic compression will have a weak disruptive impact on pores, but in the fault-developed areas, the massive hydrocarbon loss will lead to decrease of pressure to support pore spaces, then if the pores experience the compression again, the shale pores will be damaged seriously.

Evolution of shale pores

Through simulation of porosity change of carbonaceous mudstone under different temperatures, Ji et al. (2016) considered that the micropore type in the organic matter-rich shale was relatively simple and the micropores mainly were distributed in the organic matter of kerogens, and a large number of secondary pores of clay mineral occurred in samples under the relative high simulation temperature, pore abundance and size in the scanning images increased with rise of the simulation temperature.

Wang et al. (2013) proposed that organic porosity of the shale did not increase monotonically with increase of organic matter maturity, in the gas-generation stage (Ro from 1.3 to 2.0%), the organic porosity of shale generally increased with increase of organic matter maturity, but when Ro was greater than 2.0%, the organic porosity generally decreased with increase of depth. Xiao et al. (2015) thought that organic porosity reached the maximum value when Ro or Roeq was from 2.0 to 3.0%.

According to the porosity test data of samples in different thermal evolution stages (Curtis et al., 2012, Wang et al., 2013, Xiao et al., 2015), and in combination with relation between maturity and porosity in Changning and Weiyuan blocks, the value of 2.7% is approximately believed to be the maximum porosity of organic pores, and combined with previous researches on matrix porosity, a dual porosity evolution conceptual model is proposed for shale in Longmaxi Formation, Sichuan Basin (Fig. 12), and the porosity evolution can be divided into five stages. (1) The immature quick compaction stage (Ro<0.7%).

Fig. 12. The dual porosity evolution conceptual model for shale in Longmaxi Formation, Sichuan Basin (modified from Wang et al., 2013, Xiao et al., 2015 and Tian et al. (2016)) showing that the porosity evolution process can be divided into five stages: the immature quick compaction stage, the mature hydrocarbon generation and dissolution stage, the high mature pore closing stage, the overmature secondary pyrolysis stage and the overmature slow compaction stage.

This stage mainly is influenced by compaction, the porosity of inorganic pores decreases quickly and the porosity of organic pores basically does not change (Fig. 13a–b). (2) The mature hydrocarbon generation and dissolution stage (Ro from 0.7 to 1.3%). In this stage, due to temperature and clay minerals catalysis, when a large amount of carboxylic acid is released from kerogens to form a large number of water soluble monobasic–dibasic short-chain organic acids, making diagenetic fluid become weak acidic (Wang et al., 2015b); inorganic pores are influenced by dissolution of carbonate mineral and feldspar, resulting in increase of porosity of secondary pores, while a large number of organic pores are developed due to hydrocarbons generated from kerogens, resulting in increase of porosity of organic pores (Fig. 13c–e).

(3) The high mature pore closing stage (Ro from 1.3 to 2.2%). In this stage, the condensate gas begin to be substantially generated, and inorganic pores slowly become smaller due to compaction, resulting in bituminous matter filled in organic pores within kerogen and leading to decline of porosity (Fig. 13f–h). (4) The overmature secondary pyrolysis stage (Ro from 2.2 to 2.7%). In this stage, inorganic pores reduce slowly due to compaction, while porosity of organic pores increase because bituminous matter remained in pores in the high mature stage begin to dissolve and original kerogens continue to generate dry gas (Fig. 13i–k). (5) The overmature slow compaction stage (Ro>2.7%). In this stage, both organic pores and inorganic pores are influenced by compaction, the porosity declined slowly (Fig. 13l).

Fig. 13. Characteristics of pores with different maturity in typical shale in North America and Longmaxi Formation of Sichuan Basin. (a), (d), (f), (h) and (l) The Woodford shale (Curtis et al., 2012); (b) and (e) The Eagle Ford shale (Mastalerz et al., 2013); (c) and (g) The Marcellus shale (Niu et al., 2015); (i) the shale of Longmaxi Formation from Well W3 in the Weiyuan block; (j) the shale of Longmaxi Formation from Well N3 in the Changning block; (k) the shale of Longmaxi Formation from Well XW1 in the Changning block.


(1)   Shale of Longmaxi Formation in Sichuan Basin has a high TOC and thermal evolution degree, the pore is mainly dominated by organic pore, among which the proportion of pore volume and specific surface area of micropore is large, and the micropore is as one of main storage spaces for shale gas.

(2)   The porosity of shale reservoir is jointly controlled by TOC, organic matter maturity, diagenesis and tectonism. When TOC is from 4% to 5%, the porosity is highest; organic pores are the most developed in the oil window and secondary pyrolysis stages; the organic diagenesis is stronger than the inorganic diagenesis in the high thermal evolution stage; the stronger the tectonism is, the smaller the porosity will be.

(3)   Organic pores and inorganic pores have different changing trends during the evolution process, and the evolution of shale porosity in Longmaxi Formation undergo five stages: the immature quick compaction stage, the mature hydrocarbon generation and dissolution stage, the high mature pore closing stage, the overmature secondary pyrolysis stage and the overmature slow compaction stage. Among which, the mature hydrocarbon generation and dissolution stage and the overmature secondary pyrolysis stage are the most favorable stages for development of shale pores.


The work was supported by the National Natural Science Foundation of China (No. 41502150), Major science and technology special projects of PetroChina Co. Ltd (No. 2016E-0611) and Strategic Priority Research Program of the Chinese Academy of Sciences (No. XDB10010504).


Cao et al., 2015   T.T. Cao, Z.G. Song, S.B. Wang, J. Xia   A comparative study of the specific surface area and pore structure of different shales and their kerogens   Sci. China Earth Sci., 58 (4) (2015), pp. 510-522

Cao et al., 2016   T.T. Cao, Z.G. Song, G.X. Liu, Q. Yi, H.Y. Luo   Characteristics of shale pores, fractal dimension and their controlling factors determined by nitrogen adsorption and mercury injection methods   Petrol. Geol. Recovery Effic., 23 (2) (2016), pp. 1-8   (in Chinese)

Cheng and Xiao, 2013   P. Cheng, X.M. Xiao   Gas content of organic-rich shales with very high maturities   J. China Coal Soc., 8 (5) (2013), pp. 737-741   (in Chinese)

Curtis et al., 2012   M.E. Curtis, B.J. Cardott, C.H. Sondergeld, C.S. Rai   Development of organic porosity in the Woodford Shale with increasing thermal maturity   Int. J. Coal Geol., 103 (2012), pp. 26-31

Del et al., 2003   B.M. Del, C.A. Arias, H. Brix   Phosphorus adsorption maximum of sands for use as media in subsurface flow constructed reed beds as measured by the Langmuir isotherm   Water Res., 37 (14) (2003), pp. 3390-3400

Feng and Chen, 1988   G.X. Feng, S.J. Chen   Relationship between the reflectance of bitumen and vitrinite in rock   Nat. Gas. Ind., 8 (3) (1988), pp. 20-25   (in Chinese)

Guo et al., 1996   Z.W. Guo, K.L. Deng, Y.H. Han   The Formation and Development of Sichuan Basin   Geological Publishing House, Beijing (1996)   (in Chinese)

Guo et al., 2004   Y.H. Guo, Z.F. Li, D.H. Li, T.M. Zhang, Z.C. Wang, J.F. Yu, Y.T. Xi   Lithofacies palaeogeography of the early silurian in sichuan area   J. Palaeogeogr., 6 (1) (2004), pp. 20-29   (in Chinese)

Guo et al., 2014   X.S. Guo, Y.P. Li, R.B. Liu, Q.B. Wang   Characteristics and controlling factors of micro-pore structures of Longmaxi shale play in the Jiaoshiba area, Sichuan Basin   Nat. Gas. Ind., 34 (6) (2014), pp. 9-16   (in Chinese)

He et al., 2016   Z.L. He, H.K. Nie, Y.Y. Zhang   The main factors of shale gas enrichment of Ordovician Wufeng Formation-Silurian Longmaxi Formation in the Sichuan Basin and its adjacent areas   Earth Sci. Front., 23 (2) (2016), pp. 8-17   (in Chinese)

Holford et al., 1974   I.C.R. Holford, R.W.W. Wedderburn, G.E.G. Mattingly   A Langmuir two-surface equation as a model for phosphate adsorption by soils   Eur. J. Soil Sci., 25 (2) (1974), pp. 242-255

Ji et al., 2016   L.M. Ji, Y.D. Wu, C. He, L. Su   High-pressure hydrocarbon-generation simulation and pore evolution characteristics of organic-rich mudstone and shale   Acta Pet. Sin., 37 (2) (2016), pp. 172-181   (in Chinese)

Jiang et al., 2016   Z.X. Jiang, X.L. Tang, Z. Li, H.X. Huang, P.P. Yang, X. Yang, W.B. Li, J. Hao   The whole-aperture pore structure characteristics and its effect on gas content of the Longmaxi Formation shale in the southeastern Sichuan Basin   Earth Sci. Front., 23 (2) (2016), pp. 126-134   (in Chinese)

Kong et al., 2015   L.M. Kong, M.X. Wan, Y.X. Yan, C.Y. Zou, W.P. Liu, C. Tian, L. Yi, J. Zhang   Reservior diagenesis research of silurian Longmaxi Formation in Sichuan Basin   Natural Gas Geosci., 26 (8) (2015), pp. 1547-1555   (in Chinese)

Li et al., 2015   H.C. Li, D.Y. Liu, P.A. Peng, Q.T. Wang   Tectonic impact on reservoir character of Chongqing and its neighbor area   Natural Gas Geosci., 26 (9) (2015), pp. 1705-1711   (in Chinese)

Li et al., 2016   W.Z. Li, B. Zhong, H.Z. Yang, X.F. Yang, Z.M. Hu, M. Chen   A new method for gas diffusivity evaluation in matrix rocks of shale reservoir   Acta Pet. Sin., 37 (1) (2016), pp. 88-96   (in Chinese)

Liu et al., 2016   S.G. Liu, B. Deng, Y. Zhong, B. Ran, Z.Q. Yong, W. Sun, D. Yang, L. Jiang, Y.H. Ye   Unique geological features of burial and superimposition of the Lower Paleozoic shale gas across the Sichuan Basin and its periphery   Earth Sci. Front., 23 (1) (2016), pp. 11-28   (in Chinese)

Löhr et al., 2015   S.C. Löhr, E.T. Baruch, P.A. Hall, M.J. Kennedy   Is organic pore development in gas shales influenced by the primary porosity and structure of thermally immature organic matter?   Org. Geochem., 87 (2015), pp. 119-132

Loucks et al., 2009   R.G. Loucks, R.M. Reed, S.C. Ruppel, D.M. Jarvie   Morphology, genesis, and distribution of nanometer-scale pores in siliceous mudstones of the Mississippian Barnett shale   J. Sediment. Res., 79 (12) (2009), pp. 848-861

Lu et al., 2016   S.F. Lu, H.T. Xue, M. Wang, D.S. Xiao, W.B. Huang, C.Q. Li, L.J. Xie, S.S. Tian, S. Wang, J.J. Li, W.M. Wang, F.W. Chen, W.H. Li, Q.Z. Xue, X.F. Liu   Several key issues and research trends in evaluation of shale oil   Acta Pet. Sin., 37 (10) (2016), pp. 1309-1322   (in Chinese)

Luo et al., 1994   Z.L. Luo, X.K. Zhao, S.G. Liu, H.B. Song   Uplift of Longmen Mountain Orogenic Belt and the Formation and Evolution of Sichuan Basin   Chengdu University of Science and Technology Press, Chengdu (1994)

Mastalerz et al., 2013   M. Mastalerz, A. Schimmelmann, A. Drobniak, Y. Chen   Porosity of Devonian and Mississippian new Albany shale across a maturation gradient: insights from organic petrology, gas adsorption, and mercury intrusion   AAPG Bull., 97 (10) (2013), pp. 1621-1643

Milliken et al., 2013   K.L. Milliken, M.D. Rudnicki, D.N. Awwiller, T. Zhang   Organic matter-hosted pore system, Marcellus formation (devonian), Pennsylvania   AAPG Bull., 97 (2) (2013), pp. 177-200

Mou et al., 2014   C.L. Mou, X.Y. Ge, X.S. Xu, K.K. Zhou, W. Liang, X.P. Wang   Lithofacies palaeogeography of the late ordovician and its petroleum geological significance in middle-upper Yangtze region   J. Palaeogeogr., 16 (4) (2014), pp. 427-440   (in Chinese)

Niu et al., 2015   L. Niu, R.K. Zhu, L.S. Wang, B. Bai, T. Wang, J.G. Cui   Characteristics and evaluation of the Meso-Neoproterozoic shale gas reservoir in the northern North China   Acta Pet. Sin., 36 (6) (2015), pp. 664-672   (in Chinese)

Pommer and Milliken, 2015   M. Pommer, K. Milliken   Pore types and pore-size distributions across thermal maturity, Eagle Ford Formation, southern Texas   AAPG Bull., 99 (9) (2015), pp. 1713-1744

Tian et al., 2012   H. Tian, S.C. Zhang, S.B. Liu, H. Zhang   Determination of organic-rich shale pore features by mercury injection and gas adsorption methods   Acta Pet. Sin., 33 (3) (2012), pp. 419-427   (in Chinese)

Tian et al., 2013   H. Tian, L. Pan, X. Xiao, R.W.T. Wilkins, Z.P. Meng, B.J. Huang   A preliminary study on the pore characterization of Lower Silurian black shales in the Chuandong Thrust Fold Belt, southwestern China using low pressure N2 adsorption and FE-SEM methods   Mar. Petrol. Geol., 48 (2013), pp. 8-19

Tian et al., 2016   H. Tian, S.C. Zhang, S.B. Liu, M.Z. Wang, H. Zhang, J.Q. Hao, Y.P. Zheng, Y. Gao   The dual influence of shale composition and pore size on adsorption gas storage mechanism of organic-rich shale   Natural Gas Geosci., 27 (3) (2016), pp. 494-502   (in Chinese)

Wang and Cao, 2016   L. Wang, H.H. Cao   A possible mechanism of organic pores evolution in shale: a case from Dalong Formation, lower Yangtze area   Natural Gas Geosci., 27 (3) (2016), pp. 520-523   (in Chinese)

Wang et al., 2013   F.Y. Wang, J. Guan, W.P. Feng, L.Y. Bao   Evolution of overmature marine shale porosity and implication to the free gas volume   Petrol. Explor. Dev., 40 (6) (2013), pp. 764-768   (in Chinese)

Wang et al., 2015a   T. Wang, K.M. Yang, L. Xiong, H.L. Shi, Q.L. Zhang, L.M. Wei, X.L. He   Shale sequence stratigraphy of Wufeng-Longmaxi Formation in southern Sichuan and their control on reservoirs   Acta Pet. Sin., 36 (8) (2015), pp. 915-925   (in Chinese)

Wang et al., 2015b   X.P. Wang, C.L. Mou, Q.Y. Wang, X.Y. Ge, X.W. Chen, K.K. Zhou, W. Liang   Diagenesis of black shale in Longmaxi Formation, southern Sichuan Basin and its periphery   Acta Pet. Sin., 36 (9) (2015), pp. 1035-1047   (in Chinese)

Wei et al., 2016   M. Wei, L. Zhang, Y. Xiong, J. Li, P. Peng   Nanopore structure characterization for organic-rich shale using the non-local-density functional theory by a combination of N2, and CO2 adsorption   Microporous Mesoporous Mater., 227 (2016), pp. 88-94

Wu et al., 2015   W. Wu, C.C. Fang, D.Z. Dong, D. Liu   Shale gas geochemical anomalies and gas source identification   Acta Pet. Sin., 36 (11) (2015), pp. 1332-1340   (in Chinese)

Xiao et al., 2015   X.M. Xiao, Q. Wei, H.F. Gai, T.F. Li, M.L. Wang, L. Pan, J. Chen, H. Tian   Main controlling factors and enrichment area evaluation of shale gas of the Lower Paleozoic marine strata in south China   Petrol. Sci., 12 (4) (2015), pp. 573-586

Yang et al., 2015   R. Yang, S. He, D.F. Hu, H.R. Zhang, J.K. Zhang   Characteristics and the main controlling factors of micro-pore structure of the shale in Wufeng Formation-Longmaxi Formation in Jiaoshiba area   Geol. Sci. Technol. Inf., 34 (5) (2015), pp. 105-113   (in Chinese)

Yu et al., 2015   L.J. Yu, M. Fan, H.Y. Chen, W.X. Liu, W.T. Zhang, E.S. Xu   Isothermal adsorption experiment of organic-rich shale under high temperature and pressure using gravimetric method   Acta Pet. Sin., 36 (5) (2015), pp. 557-563   (in Chinese)

Zhang et al., 2015   X.M. Zhang, W.Z. Shi, Q.H. Xu, R. Wang, Z. Xu, J. Wang, C. Wang, Q. Yuan   Reservoir characteristics and controlling factors of shale gas in Jiaoshiba area, Sichuan Basin   Acta Pet. Sin., 36 (8) (2015), pp. 926-939   (in Chinese)


Corresponding author.

Shale Gas Research Institute, PetroChina Southwest Oil & Gas Field Company, Sichuan 610051, China.

E-mail address: [email protected] (W. Liu).

2096-2495/© 2017 Chinese Petroleum Society. This is an open access article under the CC BY-NC-ND license (

Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.

Leave a Reply

2 × 3 =