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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)).

Abstract

Through the field emission scanning electronic microscope (FESEM) and the nitrogen adsorption test, pore type and structure of shale reservoir in the Longmaxi Formation in the Sichuan Basin were well studied. Result showed that the pore type includes organic pore, intercrystalline pore, dissolution intracrystalline pore and interparticle pore, and the organic pore was one of major pore types; among the organic pore, the micropore had large pore volume and specific surface area, and was the main storage space of shale gas.

Authors
Wenping Liua,b, Jun Liua, Molun Caic, Chao Luoa, Xuewen Shia, Jian Zhanga,b

aShale Gas Research Institute, PetroChina Southwest Oil & Gas Field Company, Sichuan 610051, China. bShale Gas Evaluation and Exploitation Key Laboratory of Sichuan Province, Sichuan 610213, China. cCCDC Geological Exploration & Development Research Institute, Sichuan 610051, China

Received 10 October 2016 Accepted 31 March 2017

Through study on effect of total organic carbon (TOC), organic matter maturity (Ro), diagenesis and tectonism on shale porosity, influence of TOC on porosity could be divided into four stages: the rapid increasing stage (TOC from 0 to 2%), the slow decreasing stage (TOC from 2 to 3%), the rapid increasing stage (TOC from 3 to 4% or 6%) and the rapid decreasing stage (TOC > 4% or 6%); influence of the maturity on porosity of shale could be divided into three stages: the rapid decreasing stage (Ro from 1.5 to 2.2%), the rapid increasing stage (Ro from 2.2 to 2.7%) and the rapid decreasing stage (Ro > 2.7%); during the high thermal evolution stage, the organic diagenesis was stronger than the inorganic diagenesis; the tectonism had a great impact on porosity, and the more intense the tectonism was, the smaller the porosity would be.

The evolution of shale porosity of the Longmaxi Formation underwent five stages: the immature rapid compaction stage (Ro<0.7%), the mature hydrocarbon generation and dissolution stage (Ro from 0.7 to 1.3%), the high mature pore closed stage (Ro from 1.3 to 2.2%), the overmature secondary pyrolysis stage (Ro from 2.2 to 2.7%) and the overmature slow compaction stage (Ro>2.7%); among which the mature hydrocarbon generation and dissolution stage and the overmature secondary pyrolysis stage were the most favorable shale pore development stages.

Introduction

Organic matter-rich mudstone-shale intervals are always regarded as source rocks and caprocks in the conventional petroleum exploration, but this understanding now is changed with major breakthroughs in recent shale gas exploration and development, the thick-bedded organic matter-rich shale as a new reservoir interval have carried out a large number of studies (Loucks et al., 2009, Curtis et al., 2012, Tian et al., 2013, Niu et al., 2015).

Due to self generation and self reservoir, storage spaces of shale gas reservoirs distinctly are different from that of other reservoirs; besides inorganic pores supported by mineral particle and diagenetic fractures in normal reservoirs, organic pores within kerogens and contractional fractures by hydrocarbon generation are also developed in the shale. This paper mainly focus on the shale pore, i.e., inorganic pores and organic pores, and analysis of the organic pore need to be studied through the field emission scanning electronic microscope (FESEM) (Loucks et al., 2009, Milliken et al., 2013).

Inorganic pores are generally supported by frameworks which were composed of minerals or detrital particles, it primarily stored free gas in shale gas reservoirs; organic pores are distributed within kerogens and normally remained after organic matters generating hydrocarbons, surfaces of organic matters can adsorb part of hydrocarbons which called the adsorbed gas (Curtis et al., 2012, Milliken et al., 2013, Löhr et al., 2015), while the remaining pores can store free gas which are not yet expelled.

By now, a large number of studies are carried out on factors controlling shale porosity, mainly including total organic carbon (TOC), thermal evolution maturity, diagenesis and tectonism (Holford et al., 1974, Del et al., 2003, Tian et al., 2012, Cheng and Xiao, 2013, Mastalerz et al., 2013, Pommer and Milliken, 2015, Xiao et al., 2015, Yu et al., 2015, Löhr et al., 2015, Tian et al., 2016, Wang and Cao, 2016). A major view holds that TOC has a good positive correlation with porosity (Curtis et al., 2012, Tian et al., 2012, Tian et al., 2013, Milliken et al., 2013, Cao et al., 2015, Wu et al., 2015, Zhang et al., 2015, Cao et al., 2016, Li et al., 2016, Lu et al., 2016, Wei et al., 2016), and thermal evolution degree has a negative correlation with porosity (Xiao et al., 2015).

The stronger the diagenesis is, the lower the porosity will be (Kong et al., 2015, Wang et al., 2015b), and the stronger the tectonism is, the lower the porosity will be (Li et al., 2015, Ji et al., 2016). For the shale pore evolution model, foreign scholars think that the shale pore evolution can be divided in four stages, and when Ro is 1.2%, the porosity is smallest (Mastalerz et al., 2013), while China scholars believe that the organic pore evolution can be divided into three stages, and when Ro is 2.0%, the porosity is largest (Wang et al., 2013, Xiao et al., 2015).

Through study of shale reservoir in Longmaxi Formation in Sichuan Basin and abroad typical shale reservoirs, from aspects of TOC, thermal evolution maturity, diagenesis and tectonism, factors controlling shale porosity were well discussed, and the shale pore evolution model in Longmaxi Formation was summarized.

Geological setting

The Sichuan Basin is located at the northwest side of Yangtze Paraplatform, it is a secondary tectonic unit of Yangtze Paraplatform (Fig. 1) (Luo et al., 1994, Guo et al., 1996, Liu et al., 2016).

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

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

During the depositional period of Longmaxian in the Early Silurian, the sedimentary environment of this basin was a clastic rock of continental shelf facies, the sedimentary environment of south Sichuan and northeast Sichuan were generally deepwater continental shelf subfacies, and the main sediments were black carbonaceous shale, siliceous shale or silty shale, which were intercalated with lamellose siliceous rock and carbonaceous mud shale (Guo et al., 2004, Mou et al., 2014, Wang et al., 2015a); this black shale was distributed stably with large thickness and high TOC, it was considered as the primary target interval for exploration and production of shale gas in Sichuan Basin (Fig. 2).

Fig. 2. Stratigraphic comprehensive histogram of Silurian in Sichuan Basin showing that the lower part of the Longmaxi Formation is dominated by black shale which was intercalated with silty shale, and is the primary target interval for exploration and production of shale gas.

Samples of Longmaxi Formation were collected from 14 shale gas appraisal wells at five different structures, namely, Changning structure, Weiyuan structure, Jiaoshiba structure, Fengdu structure and Wuxi structure.

Shale pore types and structures

Shale pore types

Storage space of the shale reservoir in Longmaxi Formation can be divided into fractures and pores, of which pore types include organic pore and inorganic pore (including intercrystalline pore, dissolution intraparticle pore, interparticle pore, etc.). Shale pores are normally divided into micropore (<2 nm), mesopore (2–50 nm) and macropore (>50 nm) (Tian et al., 2012, Wei et al., 2016). Through FESEM, both organic pore and inorganic pore are dispersed in the shale reservoir, but the organic pores are relatively concentrated; the organic pores are either enclosed by clay or mixed with clay minerals and pyrites. Diameters of organic pores are relatively small, and they are dominated by micropores and mesopores; Diameters of inorganic pores are large, and they are dominated by macropores (Fig. 3).

Fig. 3. SEM characteristics of pores in shale sample of Longmaxi Formation from Well N3. The sample depth is from 2338.22 to 2338.25 m, TOC is 0.95%, the equivalent vitrinite reflectance (Roeq) is 2.75%, and the overall porosity is 3.79%. (a) and (b) Organic pores; (c) microfractures; (d) dissolution intraparticle pores in the calcite; (e) dissolution intraparticle pores in the pyrite; (f) interleaved pores.

Fig. 3. SEM characteristics of pores in shale sample of Longmaxi Formation from Well N3. The sample depth is from 2338.22 to 2338.25 m, TOC is 0.95%, the equivalent vitrinite reflectance (Roeq) is 2.75%, and the overall porosity is 3.79%. (a) and (b) Organic pores; (c) microfractures; (d) dissolution intraparticle pores in the calcite; (e) dissolution intraparticle pores in the pyrite; (f) interleaved pores.

Pore structures

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Based on characteristics of micropores, mesopores and macropores, the pore structure was analyzed using the carbon dioxide adsorption method, nitrogen absorption method and high pressure mercury intrusion porosimetry respectively (Tian et al., 2013, Cao et al., 2015, Cao et al., 2016, Wu et al., 2015, Zhang et al., 2015, Li et al., 2016, Lu et al., 2016, Wang and Cao, 2016, Wei et al., 2016). Pore structures of shale reservoir in Longmaxi Formation differ greatly from shale reservoirs in other strata of Sichuan Basin and other basins.

According to analysis of a nitrogen absorption–mercury intrusion porosimetry, the shale reservoir in Permian shale in the southern Anhui in China is dominated by pore above macropore (Cao et al., 2016); according to specific surface area and pore structural characteristics in different shales, with the increase of maturity, number of macropore and mesopore decrease, but number of micropore increases due to hydrocarbon generation and pyrolysis of organic matter (Tian et al., 2012, Cao et al., 2015) (Fig. 4).

Fig. 4. Change of the pore volume with pore diameter in the shale of Longmaxi Formation, Sichuan Basin (Tian et al., 2012, Cao et al., 2015).

Fig. 4. Change of the pore volume with pore diameter in the shale of Longmaxi Formation, Sichuan Basin (Tian et al., 2012, Cao et al., 2015).

A result of the nitrogen absorption test of organic matter-rich shale samples in Longmaxi Formation from Well N3 in Changning area indicates that the cumulative specific surface area of micropore is large, ranging from 0 m2/g to 13 m2/g; the cumulative specific surface area of mesopore varies from 2 m2/g to 7 m2/g; the cumulative specific surface area of macropore is about 1 m2/g (Fig. 5a); micropores account for a large proportion of pore volume, two prominent peaks at 1.2 nm and 1.5 nm of diameter correspond to 0.049 mL/g and 0.031 mL/g of maximal pore volumes respectively; mesopores with diameter from 2 to 50 nm account for a second large proportion of pore volume, it correspond to pore volume from 0.002 to 0.003 mL/g; macropores account for a relative small proportion of pore volume (Fig. 5b).

 Fig. 5. Pore diameter distribution of shale samples from Well N3 (nitrogen absorption method, sample Roeq: about 2.7%). (a) Distribution of the cumulative specific surface area with pore diameter showing that the cumulative specific surface area of micropore ranges from 0 m2/g to 13 m2/g, the cumulative specific surface area of mesopore varies from 2 m2/g to 7 m2/g, the cumulative specific surface area of macropore is about 1 m2/g; (b) distribution of pore volume with pore diameter showing that micropores account for a large proportion of pore volume, followed by mesopores, macropores account for a relative small proportion of pore volume.

Fig. 5. Pore diameter distribution of shale samples from Well N3 (nitrogen absorption method, sample Roeq: about 2.7%). (a) Distribution of the cumulative specific surface area with pore diameter showing that the cumulative specific surface area of micropore ranges from 0 m2/g to 13 m2/g, the cumulative specific surface area of mesopore varies from 2 m2/g to 7 m2/g, the cumulative specific surface area of macropore is about 1 m2/g; (b) distribution of pore volume with pore diameter showing that micropores account for a large proportion of pore volume, followed by mesopores, macropores account for a relative small proportion of pore volume.

Above test results indicate that in the high-mature or over-mature organic matter-rich shale (Roeq about 2.7%), micropores are the most developed, followed by mesopores, and the higher the TOC of samples are, the larger the specific surface area will be. In general, due to organic matter evolution, micropores that are dominated by organic pores account for a large percentage of pores in the high-mature organic matter-rich shale.

Controlling factors of shale porosity

TOC

Volume of organic matter in rocks has a strong relation with TOC generally (Fig. 6), and TOC mainly has a great influence on organic pores. Hydrocarbon-generation efficiency varies with type of organic matter, and organic pores generated in the same stage are also different, generally, kerogens of Type I and Type II1 generate the most hydrocarbons and organic pores (Milliken et al., 2013, Pommer and Milliken, 2015).

Fig. 6. Relationship between TOC versus organic matter volume (Niu et al., 2015) showing that TOC has a positive correlation with organic matter volume.

Studies show that in the same thermal evolution stage, the higher the same type TOC, the greater the porosity will be (Tian et al., 2012, Tian et al., 2013, Cao et al., 2015, Cao et al., 2016, Löhr et al., 2015, Wei et al., 2016), and when TOC is greater that a certain value (5%), the corresponding volume percentage of organic matter in rocks is up to 10%, and the compaction resistance of the rock becomes weak, the porosity decreases (Milliken et al., 2013).

TOC has a relation with porosity in the Longmaxi shale. In Changning and Weiyuan blocks, the porosity increases quickly with increase of TOC in the area with TOC less than 2%, that is closely related to increase of organic pore number (Fig. 7, Fig. 8). In the area with high TOC, changing trend of porosity with TOC are consistent, but inflection points are different; porosity of Changning block starts to decline at the TOC of about 6%, while porosity of Weiyuan block begins to decline at the TOC of about 4%; in the area with medium TOC, both Changning block (TOC from 2 to 5%) and Weiyuan block (TOC from 2 to 4%) show a changing trend which are different from previous studies, i.e., the porosity decreases first and then increases with increase of TOC (Fig. 7, Fig. 8).

Fig. 7. Relationship between TOC and porosity in shale of Longmaxi Formation in Changning block showing that the porosity increases quickly with increase of TOC in the area with TOC less than 2%; in the area with high TOC, the porosity starts to decline at the TOC of about 6%; in the area with medium TOC (TOC from 2 to 5%), the porosity decreases first and then increases with increase of TOC.

Analysis of TOC and organic matter volume of typical shale in North America shows that organic matter volume has a strong negative correlation with TOC when TOC is between 2.5 and 3.5% (Fig. 9), that agrees with the above trend, but cause of such the trend needs to be further investigated. Generally, TOC of variable intervals controls development of organic pores and thus influences porosity.

Fig. 8. Relationship between TOC and porosity in the shale of Longmaxi Formation in Weiyuan block showing that the porosity increases quickly with increase of TOC in the area with TOC less than 2%; in the area with high TOC, the porosity begins to decline at the TOC of about 4%; in the area with medium TOC (TOC from 2 to 4%), the porosity decreases first and then increases with increase of TOC. 

Fig. 9. Relationship between TOC and organic matter volume showing that organic matter volume has a strong negative correlation with TOC when TOC is between 2.5 and 3.5%.

Organic matter maturity

The organic matter maturity mainly reflects the maximal burial depth of strata during the geological time, it influences shale organic porosity greatly; generally, the porosity reduces with increase of maturity (Xiao et al., 2015) (Fig. 10a). In the immature stage (Ro<0.5%), organic pores are not regularly distributed within organic matter, some shales have more organic pores within organic matter (Löhr et al., 2015) while other shales have almost no organic pores in the immature stage (Curtis et al., 2012), and pores are dominated by mesopores and macropores.

When entering in the oil window (Ro from 0.5 to 1.2%), organic pores begin to be generated, porosity of samples with same type and TOC generally increases gradually with increase of maturity, and pores are dominated by micropores and mesopores. In the condensate oil and wet gas generation stage (Ro from 1.2 to 2.0%), organic pores formed by hydrocarbon generation in the early mature stage are filled by bituminous matter, thus the porosity reduces, and pores are dominated by mesopores.

In the dry gas generation stage (Ro from 2.0 to 3.5%), secondary pyrolysis of long-chain hydrocarbons or bitumen in organic pores enables original pores to reappear, and meanwhile, organic matter generates new micropores (Curtis et al., 2012, Löhr et al., 2015, Xiao et al., 2015), leading to increase of pore specific surface area and pore volume simultaneously, and accordingly the porosity increases, pores are dominated by micropores.

Fig. 10. Relationship between organic matter maturity and shale porosity. (a) Relationship between organic matter maturity and shale porosity in the shale of South China and North America showing that the porosity reduces with increase of maturity; (b) relationship between organic matter maturity and shale porosity in the shale of Longmaxi Formation in Changning and Weiyuan blocks.

Based on bitumen reflectance (Rb) of shale samples from Changning and Weiyuan blocks, the equivalent Ro (Roeq) were converted using an empirical formula of Feng and Chen (1988), and in order to eliminate influence of factors like TOC on porosity, samples with TOC of 1%, 2%, 3%, 4% and more than 4% were collected from Changning and Weiyuan as well as Jiaoshiba blocks with weak tectonism for analysis (Fig. 10b).

As indicated by analysis results, in the stage of Roeq from 1.5 to 2.2%, bitumen and other products of this stage are filled in pores, and consequently, the porosity decreases quickly with increase of maturity; in the stage of Roeq from 2.2 to 2.7%, secondary pyrolysis of crude oil and bitumen makes porosity increase with increase of maturity; in the stage of Roeq greater than 2.7%, organic pore volumes formed by secondary pyrolysis reach the maximum, and the porosity of shale is mainly influenced by diagenesis, leading to decrease of the porosity with increase of the maturity.

Diagenesis

Diagenesis is very crucial to research of shale reservoir porosity (Löhr et al., 2015), it influences development of inorganic pores and organic pores to variable extents (Guo et al., 2014, Yang et al., 2015, Jiang et al., 2016). According to petrographic thin-section analysis, FESEM and X-ray diffraction analyses, seven diagenesis processes in shale reservoir of Longmaxi Formation, Sichuan Basin are developed, i.e., compaction, cementation, clay mineral conversion, metasomatism, dissolution, organic thermal maturation and tectonic fracturing, and the diagenetic evolution is in the middle diagenetic stage B to the late diagenetic stage (Kong et al., 2015, Wang et al., 2015b).

As the shale in Longmaxi Formation of Sichuan Basin is characterized by self generation and self reservoir, its diagenesis consists of organic diagenesis and inorganic diagenesis, among which organic diagenesis is just hydrocarbon evolution process.

To further investigate controlling effect of inorganic diagenesis on shale reservoir, it is necessary to quantify organic pores and inorganic pores. A normal practice is to take the porosity intercept as inorganic porosity in the cross plot of porosity versus TOC in a same interval of shale reservoir. Samples with TOC of 0–2% of Longmaxi shale were collected form Wells N1 and N3 in Changning block and Well W1 in Weiyuan block for analysis of diagenesis (in the same well, sample locations were concentrated and basically organic matter maturity values were the same).

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

Through the field emission scanning electronic microscope (FESEM) and the nitrogen adsorption test, pore type and structure of shale reservoir in the Longmaxi Formation in the Sichuan Basin were well studied. Result showed that the pore type includes organic pore, intercrystalline pore, dissolution intracrystalline pore and interparticle pore, and the organic pore was one of major pore types; among the organic pore, the micropore had large pore volume and specific surface area, and was the main storage space of shale gas.
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.
http://www.allaboutshale.com

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