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).
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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 (http://creativecommons.org/licenses/by-nc-nd/4.0/).