1 Introduction
Shale gas is an important unconventional oil and gas resource in the world (
Curtis, 2002;
Bowker, 2007;
Hughes, 2013;
Li et al., 2019a;
Li et al., 2020;
Zheng et al., 2020). China is one of the countries with the largest shale gas reserves in the world, and the Sichuan Basin is currently the most important area for the commercial development of shale gas (
Hao et al., 2013; Guo and Zhang, 2014;
Tang et al., 2019;
Nie et al., 2020). The Niutitang Formation (Є
1n) and lower Silurian Longmaxi marine shales are two main shale gas target layers (
EIA, 2011;
Zou et al., 2014). They are generally characterized by a wide distribution, large thickness, and high content of the total organic carbon (TOC) (
Zhang et al., 2008;
Jin et al., 2018;
Yi et al., 2019). However, little research work has been carried out on shale gas accumulation and the factors influencing the gas content in the Є
1n in western Hubei compared with the Longmaxi Formation. Limited studies have shown that a shallow carbonate ramp, and shallow and deep shelves constitute the sedimentary environment of the Є
1n, and a deep shelf environment is the basic condition for shale gas accumulation (
Wang et al., 2013). Carbonaceous shale is the main lithology of the Є
1n with minor amounts of siltstone and limestone (
Huang et al., 2012); The TOC and vitrinite reflectance (
Ro) values are generally greater than 2.0% and 3.0%, respectively (
Zhao et al., 2016). The Є
1n is characterized by a high amount of brittle minerals, and low porosity and permeability (
Huang et al., 2018). The shale reservoir is dominated by nanometre pores and inter-granular pores, organic as well as some dissolution pores are the main micropore types that provide the reservoir space for shale gas (
Nie et al., 2014). Studies have showed that the gas content of the lower part is higher than that of the upper part of the Є
1n due to the high TOC value and large amount of brittle mineral (
Tan et al., 2014). Although the accumulation of shale gas is influenced by many factors, preservation condition are the most important factors for shale gas enrichment (
Ambrose et al., 2010; Roger and Neal, 2011;
Loucks et al., 2012;
Zeng et al., 2016). A good sealing capacity of roofs and floors, moderate burial depth and low development of normal faults are beneficial for the shale gas accumulation (
Nie et al., 2012).
Although the mechanism of shale gas accumulation in the Є1n2 of western Hubei has received limited study, there are still three questions that remain. First, there are few studies on the lithofacies division of the deep shelf strata considering its wide distribution. Second, the vertical heterogeneity of shale reservoirs needs to be further studied. Third, the main vertical and horizontal controlling factors of shale gas content vertically and horizontally need to be clarified. Therefore, the black shale in the Є1n of western Hubei is chosen for this paper, and several methods are conducted. The rock lithology and sedimentary facies are researched, and shale gas accumulation conditions, such as shale thickness, burial depth, geochemistry and reservoir physical properties are discussed. Moreover, the gas content and its factors that influence it are analyzed. Finally, the favorable area is determined according to the characteristic analysis of sedimentation, burial depth, shale thickness, TOC, Ro, and gas content and its impact factors.
2 Geological setting
The study area is located in the north-central Yangtze Region, adjacent to the Sichuan Basin and Hunan Province, it is bounded by the northern Xiangguang fault (F6) and eastern Tongchenghe fault (F12) with exposed strata from the Proterozoic Nanhua to the Cenozoic Neogene system; it is a marine and continental superimposed plate. The folds are mainly NE-SW-oriented (B1–B6, B8), and a few are nearly E-W-oriented (B7, B9–B11). The faults are mainly NE-SW-oriented (F1–F5, F8). However, there are also a few NW-SE-oriented (F9–F12) and E-W-oriented (F6 and F7) faults (Fig. 1). There are four sets of marine hydrocarbon source rocks in the Middle Yangtze Region: lower Sinian, lower Cambrian, upper Ordovician–lower Silurian and upper Permian source rocks. Currently, the large-scale lower Cambrian Є1n2 shale is one of the most important shale gas reservoirs, with a 0–300 m interval of black shale and a high content of TOC due to favorable sedimentary facies.
3 Data and methodology
A total of 29 shale gas wells and 18 outcrop sections were chosen in the study area. Nearly 400 samples obtained from 16 wells were tested for TOC, Ro, mineral composition, porosity, permeability, micropore structure, field canister desorption gas content (VD), residual gas content (VR) and Langmuir volume (VL). Specifically, due to the high gas content of the drilling core, the 23 samples from the ZD2 well were used to study the variations in the lithology, geochemistry, reservoir physical properies and gas-bearing properties in the longitudinal direction. The TOC content was tested by a Leco CS-230 carbon-sulfur tester. The mineral composition was tested by an X’Pert PRO DY2198 X-ray diffractometer. Porosity and permeability were tested by an AP-608 overpressure porosity permeability tester. Microscopic pores were observed by a JSM-35CF scanning electron microscope. Moreover, VL was tested by a GAI-100 high-pressure isothermal adsorption apparatus. VD was tested by a YSQ-IV Rock desorption apparatus. VR was tested by an FCG009 shale gas field testing apparatus. All the samples were tested in the State Key Laboratory of Geological Processes and Mineral Resources. Based on the test data and core observation, the geological conditions for shale gas accumulation and the enrichment mechanism of the Є1n in western Hubei were studied.
4 Results
4.1 Strata and sedimentary facies
The ZD2 well located in the southeastern Huangling anticline (B8) was chosen to study the characteristic of strata and sedimentary facies of the Є1n (Fig. 2). According to the lithological characteristics of the ZD2 well, the Є1n can be vertically divided into 3 sections: the first section (Є1n1), the second section (Є1n2), and the third section (Є1n3). The lower part of Є1n1 is argillaceous siltstone, and the upper part is mainly carbonaceous limestone mixed with a minor amount of carbonaceous shale; thus, the sedimentary environment was a shallow shelf. The lithology of the Є1n2 is mainly carbonaceous shale with a minor amount of silty mudstone; thus, the sedimentary environment was a deep shelf. The lithology of the Є1n3 is mainly limestone mixed with carbonaceous shale and argillaceous siltstone, and thus the sedimentary environment was a shallow shelf.
The lithofacies paleo-geographic map of the Є1n2 in the study area is derived from the lithology and thickness of 29 shale gas wells and 18 outcrop sections. The lithofacies paleo-geographic map shows that there is a paleo-continent in the northeast and that the Є1n is absent in this area. From east to west, the sedimentary facies of the Є1n2 are carbonate slope, shallow shelves with lithologies of limestone, dolomite and carbonaceous shale, deep shelves with carbonaceous shale, shallow shelves with the lithologies of limestone and silty mudstone. Three submarine uplifts are located north of Yichang city on the shallow shelf. Morphologically, the deep shelf is horn-shaped, wide at both ends and narrow in the middle. The deep shelf has a wide distribution, from western Lichuan city to eastern Yichang city and from northern Shengnongjia to southern Hefeng counties. The deep shelf can be divided into three parts according to lithological characteristics: the northern part is mainly carbonaceous shale mixed with argillaceous siltstone, the middle part is mainly carbonaceous shale and the south part is carbona-ceous shale mixed with silicious rock. In general, siltstone gradually decreases as silicious rock increases from north to south (Fig.3).
4.2 Thickness and burial depth of organic-rich shale
There are two main deposits centers with large thicknesses. The first deposit is distributed in southern Enshi city with a thickness of greater than 200 m, and the thickness gradually increases to the south. The other area is in north-western Shengnongjia with a thickness of greater than 250 m, and the thickness gradually increases to the north. The thickness of the shale is relatively thin to the east of Yichang and west of Lichuan, with a thickness of mainly 10–50 m, and in some areas, the thickness of the shale is less than 10 m, such as in wells XD1, YD3, YD5 and ZK9. The burial depths of the Lichuan and Huaguoping synclines (B3 and B5) mainly range from 2000 to 4000 m, and other areas, such as the Shengnongjia, Huangling, and Hefeng anticlines (B7, B8, and B11) have burial depths of mainly less than 2000 m (Fig. 4).
4.3 Shale reservoir characteristics
According to the classification criteria of shale gas evaluation parameters in the Technical Specification for the Calculation and Evaluation of Shale Gas Reserves (DZ∕T0254-2014) which was issued by the National Ministry of Natural Resources (Table 1), the shale reservoir characteristics of the Є1n2 were analyzed by TOC, Ro, mineral composition, porosity, permeability and microscopic pores and fractures.
4.3.1 Organic geochemical characteristics
The vertical variations in TOC and Ro for the ZD2 well were studied. The results showed that the TOC ranges from 0.4%–5.0%, and the average TOC values of the Є1n1, Є1n2, and Є1n3 are 1.67%, 2.61%, and 0.45%, respectively. The TOC shows a gentle growth trend until the bottom of the Є1n2 and then decreases rapidly within the Є1n1. The Є1n2 with an average TOC value of 2.61% is the main hydrocarbon source rock of the Є1n and is the most important target layer in this study. The Ro value ranges from 2.05%–2.59% and generally increases along with burial depth (Fig. 2).
Date from the 368 TOC and 89 Ro samples showed that the samples with high TOC values of 2.0%–4.0% accounted for the largest proportion, followed by the samples with very high TOC values that are higher than 4.0% and medium TOC values of 1.0%–2.0% (Fig. 5(a)). The high maturity samples with Ro between 2.0%–3.5% accounted for the larger proportion (Fig. 5(b)). According to the TOC contour map, the high TOC values are mainly distributed in 3 areas, including Enshi city to Hefeng county, Shengnongjia and Changyang county with TOC values mainly ranging from 3%–5%. In general, TOC values are higher in the middle of the study area and decrease significantly to the west of Lichuan city and to the east of Yichang city. The distribution of Ro is similar to that of TOC, with the highest value more than 4% in Hefeng county (Fig. 5(c)).
4.3.2 Mineral composition and content
Previous studies indicate that clay mineral content affects the specific surface area and adsorption capacity of shales (
Aringhieri, 2004;
Cheng and Huang, 2004;
Chalmers and Bustin, 2008). In addition, shale rich in brittle minerals more easily forms hydraulic fractures (Bowker, 2003;
Jarvie et al., 2007). Therefore, the analysis of shale mineral composition is of great significance to the exploration and development of shale gas. According to the mineral composition, the shale lithofacies classification scheme can be divided into siliceous shale, calcareous shale, clay shale and mixed shale and then subdivided into 31 subclasses (
Wang et al., 2018). The results show that siliceous shale (S) is the main lithofacies in most samples, followed by mixed shale (M), calcareous shale (C) and clay shale (CM) which rarely occur in the samples (Fig. 6(a)). Additionally, the average brittle mineral content is 52.5%, which is based on 89 samples that belong to the high level according to the classification criteria in Table 1. Clay content decreases and quartz content slightly increases with burial depth (Figs. 6(b), 6(c), and 6(d)). Moreover, the mineral composition has different characteristics in different areas. The SD1 well in the northern part of the study area contains the least clay minerals (Fig. 6(b)), the ZD2 well in the middle part of the study area contains relatively more carbonate and pyrite minerals (Fig. 6(c)), and the GC outcrop section in the south contains relatively more quartz and nearly no carbonate minerals (Fig. 6(d)).
4.3.3 Porosity and permeability
As fine-grained sedimentary rocks, shale reservoirs generally have low porosity and permeability (
Best and Katsube, 1995;
Clarkson et al., 2013;
Chalmers and Bustin, 2015;
Liu and Ostadhassan, 2019). Taking well ZD2 as an example, the changes in the porosity and permeability of the Є
1n
2 in the vertical direction are analyzed. The results show that the porosity values range from 1.95% to 3.72% with little vertical change; the permeability values range from 0.00017 to 0.00186 md with great vertical change (Fig. 2). According to the classification criteria, the porosity for most samples with low level values is distributed in the 2%–5% interval, followed by the samples with ultra-low level values of less than 2% (Fig. 6(e)). The permeabilities of all samples are less than 1 mD, which indicates an ultra-low level (Fig. 6(f)).
4.3.4 Microscopic pore structure
The pore structure of shale is an important factor affecting the gas storage capacity of shale reservoirs and the commercial exploitation of shale gas (Ross and Bustin, 2009;
Curtis et al., 2012a;
Chalmers et al., 2012;
Clarkson et al., 2013;
Li et al., 2016;
Tang et al., 2016;
Li et al., 2019b). The micropore types, structures and sizes of the rock can be precisely evaluated by argon ionizer polishing and scanning electron microscopy (SEM) (
Curtis et al., 2012b;
Zhao et al., 2014;
Li et al., 2018). Two samples in the upper and middle parts of the Є
1n
2 were observed by SEM. Sample A in the upper part of the Є
1n
2 with a TOC value of 1.02% and a brittle mineral content of 48% contains calcite dissolution pores, clay intergranular pores and a few organic pores. The calcite dissolution pores are mainly elliptical with apertures of 0.2–1 μm and some pores are long strips (Fig. 7(A1)). The pyrite intergranular pores (Fig. 7(A2)) and the quartz inter-crystal pores are poorly developed (Fig. 7(A3)). The clay intergranular pores are mainly elliptical with apertures of 0.5–2.0 μm (Fig. 7(A4)). The organic matter pores are relatively less developed with irregular and elliptical shapes, and the pore sizes range from 30–100 nm (Figs. 7(A5) and 7(A6)). Sample B in the middle of the Є
1n
2 with a TOC value of 3.16% and a brittle mineral content of 56% contains calcite and dolomite dissolution pores, clay intergranular pores, pyrite intergranular pores and organic pores. The calcite dissolution pores are mainly elliptical with apertures of 0.1–0.3 μm, and some pores are irregular (Figs. 7(B1) and 7(B2)). The dolomite dissolution pores are mainly elliptical with apertures of 0.3–1 μm (Figs. 7(B3) and 7(B4)). The clay intergranular pores are mainly elliptical and sub-rounded with apertures of 1–3 μm (Fig. 7(B5)). Pyrite intergranular pores are developed with apertures of 30–100 nm (Fig. 7(B6)), and quartz inter-crystal pores are poorly developed (Fig. 7(B7)). The intragranular pores are developed in the organic band with an aperture of 50–200 nm and the number of organic pores is obviously greater than that of sample A with a TOC of 1.02% (Figs. 7(B8) and 7(B9)). The microfractures are mainly distributed inside the calcite and at the boundary between the organic band and inorganic minerals (Figs. 7(B9) and 7(B10)). By comparing the microscopic pores in the upper and middle Є
1n
2, the calcite dissolution pores, clay minerals intergranular pores and organic pores are the three main pore types, which are both developed in the two samples. Additionally, the types of micropores are clearly related to the mineral compositions, and more dolomite dissolution pores are found in sample B in the middle Є
1n
2 because of the much higher dolomite content. Finally, TOC has a strong influence on the micropore type. The organic micropores, microfractures, and pyrite intergranular pores are more developed in sample B than in sample A due to the higher TOC value.
4.3.5 Gas content
Taking well ZD2 as an example, the vertical variation in the gas content was analyzed (Fig. 2). The VL of the three samples shows that the sample in the lower of Є1n2 has the highest gas content. The VD ranges from 0.14 to 2.52 m3/t, and the average value of the Є1n1, Є1n2 and Є1n3 are 0.80, 1.20 and 0.21 m3/t, respectively. The total gas content (VT) is consist of VD, VR, and the lost gas content. The curve of the VT is similar to that of the VD. In general, the gas content first shows a trend of slow increase with burial depth, reaches a peak value at the bottom of the Є1n2, and finally decreases rapidly at the top of the Є1n1.
Horizontally, the average value of the VD ranges from 0 to 2.05 m3/t in the study area according to the sample tests of 16 wells (Table 2). The results show that the gas content is poor in most wells with VD values less than 0.1 m3/t, and wells with VD values greater than 1.0 m3/t are distributed only southeast of the Huangling anticline (B8).
5 Discussion
5.1 Factors influencing the shale gas content vertically
Taking the ZD2 well as an example, the factors that influence the shale gas content vertically were analyzed. The results show that the gas content has a positive linear correlation with TOC and the quartz content (Fig. 8(a) and 8(c)). The clay content (Fig. 8(b)), carbonate content (Fig. 8(d)), porosity (Fig. 8(e)), and permeability (Fig. 8(f)) have no obvious correlations with the gas content. Organic matter content is an important index to evaluate shale reservoir quality. Organic matter is not only the source of shale gas but also provides storage space for shale gas (
Wang et al., 2009;
Tan et al., 2014). The good linear correlation between TOC and gas content can be explained by the correlation between TOC and the specific surface area, total pore volume and number of organic pores in shale reservoirs. TOC has a positive correlation with the specific surface area and total pore volume and with the
R2 values of 0.8504 and 0.5597, respectively (Fig. 9). Additionally, when comparing sample A with a TOC content of 1.02% and sample B with a TOC content of 3.16%, the samples with a TOC content of 3.16% had more organic pores (Figs. 7(A6) and 7(B9)).
Mineral composition in shale can directly control the development of micropores (Gasparik et al., 2012;
Gou and Xu, 2019;
Tang et al., 2019); thus, it can influence the gas content (
Lu et al., 1995;
Ji et al., 2012). In this paper, the gas content has a better correlation with quartz than clay and carbonate minerals. Previous studies have shown that the quartz content has a better relationship with the gas content because a high quartz content can provide a large part of the pore volume (
Tang et al., 2016). However, microscopic observation by SEM showed that the micropore of quartz barely develop (Figs. 7(A3) and 7(B7)). Further research shows that, on the one hand, the high quartz content is not only conducive to the formation of microfractures but also has good compaction resistance, which can prevent the pores from being destroyed and thus increase the total pore volume of shale; on the other hand, the study of 12 samples from the wells ZD1 and ZD2 shows that the quartz content has a clear positive correlation with the TOC content with an
R2 of 0.5517, and both the clay and carbonate content have no clear correlation with the TOC content (Fig. 10). Since the quartz intragranular pores are barely developed in the microscopic pores (Figs. 7(A3) and 7(B7)), the quartz content correlates well with the gas content, which maybe caused by two possible reasons. One possible reason is that quartz and organic matter are coupled symbioses, which leads to a good positive correlation of quartz with TOC (Fig. 10). The other reason is that a high quartz content is conducive to the formation of microfractures, which can improve the permeability of the Є
1n
2 in the well ZD2 (Fig. 7(B8)).
5.2 Influencing factors of shale gas content horizontally
Based on the results, the gas content has a good vertical correlation with the TOC and quartz mineral content. However, the gas content has no obvious horizontal correlation with TOC and quartz mineral content by using the data of wells ZD1, ZD2, SD1, and ND1 wells in the deep shelf (Figs. 11(a) and 11(b)). Therefore, the gas content is obviously horizontally affected by the other factors. To clarify the factors that influence the gas content horizontally, the factors that influence the gas content were studied in the following sections, such as sedimentary facies, structural style, fault and fracture characteristics, thermal evolution degree, stratigraphic unconformity and burial depth.
5.2.1 Sedimentary influences on the gas content
The sedimentary environment controls the formation of organic-rich shale and determines the quality of shale gas reservoirs (
Algeo and Tribovillard, 2009;
Liu et al., 2015;
Zhao et al., 2019). The relationship between sedimentary facies and thickness, TOC and gas content was studied based on the 36 thickness data points, 33 TOC data points and 16
VD data points (Figs. 3(a), 3(b), and 3(c)). The shale thickness is highest, with a value of 186.3 m, in the deep shelf environment with argillaceous siltstone, followed by the deep shelf environment with carbonaceous siliceous rock, the deep shelf environment with carbonaceous shale, and the carbonate shallow shelf and submarine uplift environments with the thickness of 128.8 m, 114.7 m, 42.5 m, and 7.5 m, respectively (Fig. 3(b)). The TOC is highest in the deep shelf environment with carbonaceous siliceous rock, with an average value of 4.0%, followed by the deep shelf environment with carbonaceous shale, the deep shelf with the argillaceous siltstone, and the shallow carbonate shelf and submarine uplift environments with average values of 3.8%, 2.2%, 1.5%, and 1.2%, respectively (Fig. 3(c)). The statistical results show that the deep shelves with carbonaceous shale and carbonaceous siliceous rock with higher TOC contents are much more beneficial to the accumulation of shale gas. The deep shelf with argillaceous siltstone has the largest shale thickness. However, its TOC content is much lower than that of deep shelf with carbonaceous shale and carbonaceous siliceous rock.
The sedimentary facies influences the gas content of drilling wells by controlling the thickness and TOC of the shale. The results show that the VD is 0.0 m3/t in both the XD1 and YD3 wells, which are located in the submarine uplift because of the low values of TOC and thickness. The VD is greater than 1.0 m3/t in the ZD2, YD2, YY1, and YD4 wells, which are located in the deep shelf because of the larger values of TOC and thickness (Fig. 3(a)). However, the gas content is very low in some wells located in the deep shelf with large TOC contents and thicknesses, such as EY1, SD1, HD1, CD1, WD1, X1, YD1, ND1, and ZD1. The gas content is influenced not only by sedimentary facies, but also by other factors. Therefore, the influence of structural style, fault properties and other factors on the gas content is thoroughly discussed in the following sections.
5.2.2 Structural type influencing the gas content
The degree of fold deformation and fracture development is generally different in tectonic belts, and a weak tectonic zone is favorable for the preservation of shale gas (
Wang et al., 2016). A total of 14 wells were used to analyze the impact of structural type on gas content in the study area (Fig. 12). The results show that areas with wide and gentle folds and that are also away from large normal faults are beneficial for shale gas accumulation, such as wells ZD2, YD2, YD4, YY1, and Y1 with
VD values of 1.22, 1.54, 1.55, 2.05, and 1.05 m
3/t, respectively (Figs. 12(c), 12(g), and 12(i)). In contrast, the gas content is poor in the cores of anticlines, such as in wells X1, CD1, and YD1 (Figs.12(a), 12(b), and 12(f)). However, the gas content is poor in some survey wells with wide and gentle folds, such as in wells EY1, WD1, ND1, ZD1, HD1, and SD1. Therefore, the reason for the poor gas content is analyzed in detail in the following sections.
5.2.3 The influence of faults and fractures on the gas content
Shale gas can be lost when normal faults cut through shales and their roofs and floors. When high-angle fractures develop, they are not conducive to shale gas preservation (
Wang et al., 2016). The CD1 and WD1 wells are located near the Xiannvshan normal fault (F9), and the up-dip direction of the shale formation communicates with the fault; thus, shale gas is easily escapes, resulting in very low gas contents of 0.08 and 0.02 m
3/t, respectively (Figs. 12(b) and 12(d)).
Specifically, the EY1 well is located in the core of a secondary syncline in the Zhongyang anticline belt (B4), and its structural position is relatively favorable. However, the well location is close to the hidden normal fault underground, which results in a low gas content of 0.26 m3/t (Figs. 12(a) and 13(a)). The correlation between the fracture characteristics and gas-bearing strata was studied by observing the fractures in the cores of wells X1, ZD1, and ZD2. The results show that breccia and calcite veins developed in the X1 well. The calcite vein is approximately 1 cm wide and presents an 80° angle to the shale bedding face. The development of high-angle fractures results in no gas in the well (Figs. 13(b) and 13(c)). There is some gas in wells ZD1 and ZD2 with VD values of 0.15 and 1.22 m3/t, respectively, because fractures develop poorly in the core, especially in the core of well ZD2, which is very intact (Figs. 13(d) and 13(e)). Nine wells near the normal Xiannvshan fault were chosen to analyze the correlation between the VD and the distance from the normal fault to the wells. The selected wells are all in the deep shelf and are away from the core of the anticline. The results show that the VD has an obvious positive linear correlation with the distance from the Xiannvshan fault with a correlation coefficient of 0.6204. The VD value is less than 0.5 m3/t when the distance is less than 5 km (Fig. 14).
5.2.4 Thermal evolution degree influencing on the gas content
The degree of thermal evolution of shale is the main factor controlling the micropore structure. After shale reaches the over-mature state, its specific surface area and pore volume decrease sharply with increasing
Ro. Meanwhile, the contents of smectite and illite with larger specific surface areas decreased, and the chlorite with small specific surface areas increased (
Liang et al., 2014). The correlation between the gas content and
Ro shows that when
Ro is greater than 3.0%, the
VD is less than 0.1 m
3/t. Additionally, the value of
Ro ranges from 2.0% to 2.5% in wells with high gas contents, such as in wells YD2, YY1, and ZD2 (Fig. 15(a)). Although the SD1 and HD1 wells are located in the deep shelf with large shale thicknesses and high TOC contents, the gas content is very low in the two wells. The reason is that the high
Ro value of the two wells are influenced by the Yangri Fault (F7). It is a large thrust fault fracture with strong seismic activity and a hot spring distribution along the fault, and the Є
1n shale is heated by the tectonic movement. Therefore, shale thermal evolution is relatively high, which results in a smaller specific surface area and pore volume, and thus, the gas content is very low in both SD1 and HD1 wells.
When comparing the SD1 with the ZD2 well, the Ro values of ZD2 are relatively low with higher contents of smectite and illite and lower contents of chlorite (Fig. 15(b)), which result in a larger specific surface areas and pore volume. Experimental tests show that the average porosity in well ZD2 is 2.71%, which is much higher than the value of 0.52% in the SD1. Therefore, compared with the ZD2, the low specific surface areas and porosity due to higher thermal evolution are the main reasons for the low gas content in the SD1 well.
5.2.5 Influences of the roof and floor sealing capacity on the gas content
The sealing property of organic-rich shale can be divided into macro-sealing and Micro-sealing. Macro-sealing refers to the lithology, thickness and transverse distribution stability of the target, top and bottom layers. Micro-sealing includes shale porosity, permeability and brittle mineral content (
Lou et al., 2011;
Pan et al., 2014). The analysis indicates that the Є
1n
2 shale gas target layer has good self-sealing properties and an average thickness of 133.9 m. The average thicknesses of the roofs of Є
1n
3 and Є
1sp organic-rich shales are 83.2 m and 276.4 m, respectively. The average thicknesses of the floors of the Є
1n
1 and Z
2d organic-rich shales are 17.2 m and 221.7 m, respectively (Fig. 16(a)). Additionally, the Є
1n
3 has a better sealing capacity than the Є
1n
1 due to its low brittle mineral content (Fig. 16(b)). In particular, there is an important discovery in this study according to the 21 data points of wells and stratigraphic sections. TheЄ
1n
1 is distributed only in the deep shelf of the central and northern parts of the study area (Fig. 16(c)) and is absent in the eastern and southern parts of the study area, where the Z
2d unconformably contacts the Є
1n
2 stratigraphically. For example, the Є
1n
1 is developed in the core of the ZD2 well with a thickness of 12.6 m (Fig. 16(d)), while it is absent in the core of the ND1 well (Fig. 16(e)). The unconformity boundary is very clear in Hefeng county, and the shale of the Є
1n
2 is overlain on the dolomite of the Dengying Formation (Z
2d) with weathered crust in the middle (Fig. 16(f)). The results show that, first, the unconformity boundary is the main reason for the poor gas content in the wells located in the southern part of the boundary, such as wells ND1 and WD1 wells. In addition, the existence of the unconformity boundary leads to the loss of shale gas in the southern and eastern parts of the study area, which is not conducive to the preservation of shale gas.
5.2.6 Influencing of burial depth on the gas content
The burial depth is very important for the formation of shale gas reservoirs. Shale gas reservoirs are susceptible to infiltrating atmospheric water, which results in gas loss when the burial depth is too shallow (
Si et al., 2016). The correlation was studied between the
VD and burial depth of the ZD1, ZD2, YD4, YD2, and YY1 wells. These five wells are located on the deep shelf facies in the south-eastern side of the Huangling anticline (B8), far from the large regional normal Xiannvshan Fault (F9); thus, the burial depth plays a major role in the gas content.
The results show that the average burial depths of Є1n2 in ZD1, ZD2, YD4, YD2, and YY1 are 300.8, 781.8, 1292.6, 1693.7, and 1857.5 m, respectively, with average VD value of 0.16, 1.22, 1.69, 1.9, and 1.84 m3/t, respectively. Therefore, the VD increases with burial depth, and there is an exponential correlation between gas content and burial depth with a correlation coefficient of 0.5799. Additionally, when the burial depth is less than 500 m, the average value of VD is lower than 0.5 m3/t, and when the burial depth exceeds 500 m, the influence of the burial depth on the gas content gradually decreases, especially when the burial depth is greater than 1500 m, and the influence of the burial depth on the gas content is negligible (Fig. 17(a)).
The burial depth affects not only the gas content but also the gas composition. The correlation between methane content and burial depth was studied for wells ZD1 and ZD2. The results show that the methane content increases with burial depth for both wells (Figs. 17(b) and 17(c)). In particular, the methane content of the ZD1 well increases obviously when the burial depth is greater than 300 m (Fig. 17(b)). Thus, the depth of 300 m may be the groundwater boundary between the free alteration zone and the stagnation zone.
Based on the correlation analysis between the gas content and sedimentary facies distribution, structural style, fault and fracture development characteristics, degree of thermal evolution, regional unconformity boundary and burial depth, wells with low gas contents are generally affected by the combination of two or more factors. Additionally, the combination of structural styles, fault and fracture development, and the distribution of the regional unconformity boundary are the three most important factors affecting the gas content. The areas with high gas content must meet the following conditions: deep shelf environment, Є1n1 is present, wide and gentle syncline, away from large normal faults greater than 5 km, the moderate thermal evolution and the burial depth of greater than 500 m.
5.3 Favorable block evaluation
According to these results and the Technical Specification for Calculation and Evaluation of Shale Gas Resources/Reserves issued by the Ministry of Natural Resources (DZ/T 0254-2014), the evaluation index system of favorable shale gas area in western Hubei was established, and the favorable blocks were selected.
This study shows that the selected favorable areas must meet the following nine conditions: 1) continuous distribution area≥50 km2; 2) thickness of organic-rich shale of more than 20 m; 3) TOC≥1.0%; 4) VD≥1.0 m3/t; 5) wide and gentle fold belt; 6) away from normal fault greater than 5 km, low fracture density, and high-angle fractures that are not developed in the core; 7) good sealing properties of the roof and floor, and no stratigraphic unconformity; 8) Ro distribution in the range of 1.3%–3.0%; (9) burial depth≥500 m.
According to the above nine conditions, three favorable areas of western Hubei are determined by overlapping the buried depth, shale thickness, TOC and Ro contour maps of organic-rich shale. The favorable areas are mainly distributed in the southern Huangling anticline (B8) and northern Xiannvshan fault (F9), which contain the YD2–ZD2 well block, Y1 well block and YD4 well block (Fig. 18).
6 Conclusions
Based on systematic research on the geological controls of shale gas accumulation and the enrichment mechanism of the lower Cambrian Niutitang Formation, the conclusions are as follows:
1) The Niutitang Formation can be vertically divided into three sections, and the Є1n2 is mainly a shale gas reservoir. The deep shelf facies is the main sedimentary facies and can be divided into three lithofacies: argilla-ceous siltstone, carbonaceous shale and carbonaceous siliceous rock.
2) There are two main shale deposits with shale thicknesses greater than 200 m. Vertically, the TOC shows gentle growth trends until the depth reaches the bottom of the Є1n2 and then decreases rapidly in the Є1n1. Horizontally, the TOC is mainly distributed from 2% to 4%. Siliceous shale is the main lithofacies, and the average brittle mineral content is high. The reservoir has low porosity and ultra-low permeability. Calcite dissolution and clay intergranular and organic pores are the main pore types and micropores types are clearly related to the mineral and TOC contents.
3) Vertically, the gas content is mainly affected by TOC. Since the quartz intragranular pores are barely developed in the microscopic pores, the good correlation of the quartz content with the gas content may be caused by the coupled symbioses of the quartz and organic matter, which leads to the good positive correlation of the quartz with TOC; the high quartz content is conducive to the formation of microfractures that improve the permeability.
4) Horizontally, the gas content has no obvious correlation with TOC and quartz mineral content and changes greatly in different tectonic units, with high gas contents distributed only southeast of the Huangling anticline. The combination of structural styles, fault and fracture development, and the distribution of the regional unconformity boundary between the upper Sinian Dengying Formation (Z2d) and the Є1n2 are the three most important factors affecting the gas content.
5) The favorable areas must meet the following conditions: deep shelf environment, Є1n1 is present, wide and gentle syncline, away from large normal faults greater than 5 km, moderate thermal evolution and burial depth of greater than 500 m, this includes the YD2–ZD2 well block, Y1 well block and YD4 well block, which are distributed in the southern Huangling anticline and northern Xiannvshan Fault.
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