Evaluation of Highly Thermally Mature Shale-Gas Reservoirs in Complex Structural Parts of the Sichuan Basin

INTRODUCTION

Industry reports suggest that marine shale is the most important future shale-gas resource play in South China because of its characteristics of stable distribution, high organic content and high thermal maturity, quite similar to conditions in North America. Such shale mainly occurs in the Yangtze Platform (Hao et al., 2013; Hao and Zou, 2013; Jia et al., 2012; Lin and Wang, 2012; Li et al., 2009; Pan and Huang, 2009; Wang L S et al., 2009; Wang S J et al., 2009; Ross and Bustin, 2008; Zhang et al., 2008; Daniel et al., 2007; Jarvie et al., 2007; Liu et al., 2006) on the edges of basins exposed to air. In the centers of basins, shale is cut by faults caused by complex tectonic activity and this creates difficulties for shale-gas exploration.

Southern China has two significant marine shale formations: the Lower Silurian Longmaxi Formation (Fm) and the Upper Ordovician Wufeng Fm There have been many studies of the organic matter content, organic matter type, sedimentary setting, thermal maturity, and distribution of thickness in Longmaxi Fm shale (Chen and Guo, 2012; Huang et al., 2012; Liang C et al., 2012; Tao et al., 2012; Chen et al., 2011; Dong et al., 2009; Liang D G et al., 2009a, b, 2008), but most concentrated on single characteristics of shale and did not say much about shale-gas accumulation, which limits their value for further shale-gas exploration. The present study draws on analysis of exploration wells JY1, YY1, PY1 (Fig. 1) to identify controlling factors for shale-gas accumulation on highly thermally mature shale of the Longmaxi Fm in a complex tectonic setting. The ultimate goal is to provide a comprehensive detailed understanding of the shale in the area, and guidelines for wider exploration of potential shale-gas resources in southern China.

Figure  1.  The Sichuan Basin. (a) Tectonic subdivisions; (b) geological map of study area SW of Chongqing; (c) representative borehole logs.

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In this article, the Upper Ordovician Wufeng Fm and Longmaxi Fm is assigned as the Longmaxi Fm for simplified reason, since both of them are continuous deposition with thickness of 3–7 m and share similar sedimentary characteristics.

GEOLOGICAL SETTING

The Yangtze Craton has undergone PostCambrian Caledonian, Hercynian, Indosinian, Yanshanian, and Himalayan earth movements which have given rise to complex tectonic settings. Take eastern Sichuan Basin for example. The Chuanzhong paleouplift formed in Caledonian movement is slope in research area. And Cambrian, Ordovician and Silurian depositions are continuous while Devonian and Lower Carboniferous sediments are absent. Hercynian movements resulted in the cessation of deposition at the top of the Lower Permian Maokou Fm. Indosinian movements caused an important tectonic change because it ended marine deposition history and initiated the present tectonic framework (Zhu, 1986). A typical feature of the Yanshanian movements was gravity sliding of basement and cap rocks. For example during this period in east Sichuan, the rocks of Xuefeng Mountain slipped into the Sichuan Basin giving rise to parallel fold and fault zones in west Hunan and Hubei, drastically affecting petroleum accumulation and preservation. Himalayan movements resulted in stress field adjustments that may be driving further hydrocarbon remigration and accumulation up to the present (Liu et al., 2006).

Thus the characteristics of the first three tectonic movements were uplift and erosion that could have retarded generation of source rocks in the Silurian Basin. The last two tectonic movements not only caused uplift and erosion but also involved compressional deformation that gave rise to complex fold and fault combinations. For example, Yanshanian movements might produce tilted and horizontal strata in Silurian mudstone, and following Himalayan movements might result in the appearance of high angle fractures (Zhang et al., 2008).

SHALE-GAS ACCUMULATION CHARACTERISTICS

Thickness and Lithology of Shale

There are three depositional centers in Longmaxi Fm. Shale (TOC>0.5%): the first in the north area of Wanyuan reaching a maximum thickness of 133 m; the second the Linchuan-Fuling area, maximum thickness 120 m; the third in the Zigong- Luzhou-Yibin area, maximum thickness 120 m (Fig. 2). The depositional environment changed from deep-water continental shelf to shallow-water continental shelf between the Changning and Well YY1-Well PY1 areas, and the thickness of Longmaxi Fm in reaches 320 m at outcrop in Shizhuqiliao and gets up to 308 m in Shuanghe. The thickness is 405 m in Well PY1, 266 m in JY1 and about 148 m in DS1 (Fig. 3).

Figure  2.  Isopach map of thickness in Longmaxi Formation, Sichuan Basin.

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Figure  3.  S-E stratigraphic correlation of the Longmaxi Formation, Sichuan Basin.

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The upper part of Longmaxi Fm is mainly composed of mudstone, the middle is interbedded argillaceous siltstone and siltstone, the lower is medium-bedded shale, carbonaceous shale, mudstone, carbonaceous mudstone, siliceous shale interbedded with silty mudstone and thin argillaceous limestone, and the basal bed of the Longmaxi Fm is black shale with a high organic matter content and abundant graptolite fossils (Fig. 3).

Organic Geochemical Characteristics of Shale

The highest organic matter content is usually in the basal part of the Longmaxi Fm. The organic matter content gradually decreases as the formation sand content increases. Total organic content (TOC) and shale thickness change sharply, especially in those shales in which TOC is more than 2% (Table 1). Wang S J et al. (2009) concluded that the hydrocarbon in Ordovician rocks of the Upper Yangtze Craton is in an over-mature stage because average vitrinite reflectance (Ro) was >2.5%, in the Luzhou-Yibin-Zigong area, average Ro was 1.8%; in the Fuling-Shizhu area, it was 3.2% to 3.8%.

Table  1.  Parameters of Longmaxi shale in exploration wells

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We found organic-rich shale in the basal part of the Longmaxi Fm in wells JY1, DS1 and CX1. In JY1, the Longmaxi Fm consisted of grey argillaceous sandstone (116 m), grayish-black silty mudstone with intercalated muddy siltstone (61 m), and carbonaceous siliceous shale (89 m). Organic geochemistry shows that TOC of shale is always greater than 0.5% and the average 2.54%. The lowest 38 m of shale has especially high TOC greater than 2% average 3.5% (Fig. 3). Ro value ranges from 2.2% to 3.6%. The organic kerogen types are type I (Fig. 4).

Figure  4.  Kerogen of JY1. (a) 2 339.33 m, organic matter showing as alga body and sapropel amorphous body; (b) 2 349.23 m, organic matter showing as alga body and sapropel amorphous body; (c) 2 349.23 m, organic matter showing as alga body and sapropel amorphous body. (a), (b), (c) amorphous kerogen including algal remains and sapropel.

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In Well DS1 the Longmaxi Fm is 98 m thick consisting of grey-black lime mudstone with TOC from 0.06% to 0.90% (average 0.55%), 33 m of grayish-black mudstone with TOC from 0.64% to 1.90% (average 1.14%), and 24 m black carbonaceous mudstone whose shale component is described below. Ro ranges from 3.14% to 3.38% with organic kerogens of types I and II1 (Fu and Qing, 2008).

In Well CX1, 153 m continuous black shale core sample are recovered from lower Longmaxi Fm. The TOC of Shale is from 1% to 3% (average 2%) in the lowest 110 m. Black shale with high organic matter is concentrated near the base of the Longmaxi Fm (110–153 m) and has TOC greater than 2% (average 6.0%), (Ro) is more than 3.0% (average value 3.2%) (Wang S J et al., 2009).

Mineral Components

The mineral component has a major influence on the physical properties of mudstone and is associated with fracturing. In Well JY1, clay minerals provide the highest content ranging from 16.6% to 62.8% but mostly between 35% and 45%; the brittle mineral content is from 55% to 65% including quartz, potash feldspar, plagioclase, calcite, dolomite, and little iron pyrite and hematite. Quartz is 44.4% of the brittle minerals, feldspar 8.3%, calcite 5.9%, dolomite 3.8%, and accessory pyrite (Fig. 5). Silicified graptolites and radiolarian fossils are found in the bottom of Longmaxi Fm and may be one cause of its high organic matter content (Fig. 6).

Figure  5.  Mineral plot of shale in JY1.

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Figure  6.  Fossils photos of shale in JY1. (a) 2 389.31 m, graptolites in gray-black shale; (b) 2 389.31 m, radiolarians in carbonaceous mudstone; (c) 2 402.55 m, silica sponge spicules in carbonaceous mudstone.

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Porosity and Permeability of Shale

One hundred and fifty nine samples from Well JY1 were examined. Porosity ranged from 1.17% to 7.22%, average 4.52%. Permeability ranged from 0.001 5 to 81.35 md and average 0.32 md (Figs. 7 and 8). This data is similar to the Barnett shale in U.S. (Chalmers et al., 2012; Loucks et al., 2009) which suggests that the Longmaxi Fm shale may have comparable shale gas potential.

Figure  7.  Porosity histogram of Longmaxi Fm in Well JY1.

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Figure  8.  Permeability histogram of Longmaxi Fm in Well JY1.

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Porosity and permeability increased from the top to bottom with an obvious change at 2 377 m, where not only does TOC content become higher, but also porosity and permeability become better with numerous pores in Longmaxi Fm shale. It has been further confirmed that effective reservoir space is increased with organic carbon loss after pyrolysis (Daniel et al, 2007). SEM reveals nano pores in the size range 3.8 to 36 nm; and also some small dissolved pores and intergranular pores (Fig. 9). Some net fractures are observed in the bottom of Well JY1, which may improve the shale permeability and promote the adsorption capacity of shale. Furthermore, the in-situ test indicates that the bottom of Well JY1 has high gas content ranged from 0.89 to 5.19 m³/t and average value is 2.96 m³/t (Figs. 10 and 11).

Figure  9.  SEM images of Longmaxi Fm Shale from Well JY1. (a) 2 381.91 m, organic pores; (b) 2 335.3 m, intergranular pores; (c) 2 340.82 m, intragranular dissolution pores.

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Figure  10.  Gas content against burial depth in Well JY1.

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Figure  11.  Correlation between TOC and gas content in Well JY1.

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FACTORS CONTROLLING SHALE-GAS ACCUMULATION

As previous mentioned, a complex tectonic evolution has caused difficulties for shale-gas exploration especially by influencing tectonically controlled shale-gas accumulation that must be taken into account before exploration. This topic will be discussed in the following text.

Importance of Structure Style

All shale of the Longmaxi Fm occurs in the Yangtze Craton between the Xuefeng uplift and Qinling-Dabieshan area; including the Sichuan Basin, Jianghan Basin and Subei Basin that all have complex tectonic evolution histories of folding, faulting, uplift and erosion. Structural styles are indicated by anticlines, synclines, monoclines and fault-blocks. Some geologists consider that the Sichuan Basin may have better accumulation conditions for shale-gas than the Subei and Jianghan basins because of its stable tectonic background (SINOPEC internal information 2013). Anticlines provide better conditions for shale-gas preservation than other structures. Among anticlines, simple anticlines are better than single fault anticlines which are in turn better than double fault anticlines. Within larger synclines, double fault anticlines are better than single fault anticlines which are in turn better than simple anticlines. Among monoclines, a monocline with an overlying uniformity is better than one in a continuous stratal sequence. Among all types of structures the presence of fault blocks is bad for shale-gas preservation.

Structure style in the Sichuan Basin, from the interior basin to the edge of the basin changes from typical ejective folds to trough-like folds. Key wells YY1 and PY1 are located from ejective fold to trough like folds transition zone. The Qiyueshan fault bounded, Well JY1 of interior basin is only exposed Permian. Silurian and Cambrian have been exposed in core of anticline outer of basin. Take well YY1 for instance, it is in the core of an asymmetrical anticline dips of 35°–68° in the NW limb and 22°–45° in the SE limb. Middle and Lower Silurian strata was exposed on the core of anticline, there were lots of fracture (Zhang et al., 2010) (Fig. 12). This is classic shallow-level foreland deformation. A type area is the Zagros Mountains in Iran. The YY1 anticline appears to overlie a thrust ramp, also characteristic. For being intense reconstructed, whether the anticline or syncline in outer of basin, objective layer directly exposed on the surface or outcropped in the monoclinic form preserved conditions were apparent damage (e.g., Well PY1).

Figure  12.  A cross-well correlations of JY1, YY1, PY1.

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The good progress of shale gas exploration and development is made in JY1 well area, Yang 101 well area (Fig. 1), the common feature of these two areas are located within the basin, has anticline background.

Bedding Plane Slip within Reservoirs

Flexural slip along bedding surfaces in the Longmaxi Fm shale caused a rise in local porosity and permeability to values almost equal to that of the tight sandstone of the Xujiahe Fm. In Well JY1 it has created high angle fractures with mirror smooth fracture surfaces, slickensides and steps (Fig. 13). Bedding plane slip has occurred since Indosinian times in the Longmaxi Fm, which acted as a regional ductile layer or horizon of décollement. Strong stress transmitted from the Xuefeng Mountains also resulted in high angle fractures structure (Fig. 14) and these two movement periods have created many reticular cracks structures suitable for shale-gas accumulation.

Figure  13.  Bedding parallel polished slip surface with slickensides in Longmaxi Fm shale (after Guo and Liu, 2013; core diameter 10 cm).

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Figure  14.  Net fractures perpendicular to bedding in Longmaxi Fm shale (after Guo and Liu, 2013; core diameter 10 cm).

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Roofs and Floors of Shale-Gas Reservoirs

Favorable conditions in the roof and floor strata of shale reservoirs are very important for shale-gas accumulation because they not only prevent gas from escaping, but provide bedding parallel fracture surfaces.

The underlying stratum of the Longmaxi Fm is the Jiancaogou Fm Q₃j composed of tight carbonate 45–50 m thick. In Well DS1 this underlying stratum has porosity from 0.61% to 1.66% (average 1.01%) and permeability 0.005 8 to 0.109 2 md (average 0.020 1 md), characteristic of tight carbonate with ultra-low porosity and permeability. Regionally, It is widely distributed regionally and no water and gas have been discovered. The overlying stratum is mudstone of the Upper Longmaxi Fm S₁l which has low organic matter content, low porosity and permeability. Drilling mud escape occurred at seven levels in Well JY1 (five in the Hanjiadian Fm and two in the Xiaoheba Fm) none at all in the Longmaxi Fm (Fig. 15).

Figure  15.  Roof S₁l and floor Q₃j of the shale-gas reservoir in the Longmaxi Fm.

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CONCLUSIONS

Favorable structural and preservation conditions are the main controlling factors for shale-gas accumulation in shale with high thermal maturity in complex structural. Shale in the Longmaxi Formation of the Sichuan Basin has favorable thickness, TOC, and brittle mineral content compared with shale from stable tectonic environments in the USA, further work needs to be done in future to bring the reservoirs into production.

1. Interaction between tectonic evolution, structural style and high hydrocarbon maturity must be investigated fully to assess potential targets in this complex evolutionary setting.

2. The roof and floor layers of shale gas reservoirs must be the first focus because they are very important for shale-gas accumulation.

3. Although the thickness, TOC, and brittle mineral content are important for shale-gas exploration there are already a large number of studies have already been carried out and these be a secondary focus of research.

4. Reservoir of complex tectonic zone and high evolution degree shale strata has the characteristics of conventional gas reservoir, in addition to the hydrocarbon source rock, reservoir are same one.

Shale gas was brought into production in the US after a long tough effort. It has made a major breakthrough in shale gas in Jiaoshiba area. Because tectonic evolution, surface conditions and geographic environment are more complex in China we must not expect shale-gas exploration to be successful quickly. We should also extend fundamental research, technological development and environmental protection to ensure that commercial shale-gas exploration and development will be "green".