# Factors Controlling Shale Reservoirs and Development Potential Evaluation: A Case Study

Authors: Chao Luo; Hun Lin; Yujiao Peng; Hai Qu; Xiaojie Huang; Nanxin Yin; Wei Liu; Xuanbo Gao
Journal: Geofluids
 (2021)

---

## Abstract

The shale of the Lower Silurian Longmaxi Formation is an important gas-producing layer for shale gas development in southern China. This set of shale reservoir characteristics and shale gas development potential provide an important foundation for shale gas development. This study takes wellblock XN111 in the Sichuan Basin, China, as an example and uses X-ray diffraction (XRD), scanning electron microscopy (SEM), isothermal adsorption, and other techniques to analyze the shale reservoir characteristics of the Lower Silurian Longmaxi Formation. The results show that the Lower Silurian Longmaxi Formation was deposited in a deep-water shelf environment. During this period, carbonaceous shale and siliceous shale characterized by a high brittle mineral content (quartz>40wt.%, carbonatemineral>10wt.%) and a low clay mineral content (<30 wt.%, mainly illite) were widely deposited throughout the region. The total organic carbon (TOC) content reaches up to 6.07 wt.%, with an average of 2.66 wt.%. The vitrinite reflectance is 1.6–2.28%, with an average of 2.05%. The methane adsorption capacity is 0.84–4.69 m3/t, with an average of 2.92 m3/t. Pores and fractures are developed in the shale reservoirs. The main reservoir space is composed of connected mesopores with an average porosity of 4.78%. The characteristics and development potential of the shale reservoirs in the Lower Silurian Longmaxi Formation are controlled by the following factors: (1) the widespread deep-water shelf deposition in wellblock XN111 was a favorable environment for the development of high-quality shale reservoirs with a cumulative thickness of up to 50 m; (2) the high TOC content enabled the shale reservoir to have a high free gas content and a high adsorptive gas storage capacity; and (3) the shale’s high maturity or over maturity is conducive to the development of pores and fractures in the organic matter, which effectively improves the storage capacity of the shale reservoirs. The reservoir characteristic index was constructed using the high-quality shale’s thickness, gas content, TOC, fracture density, and clay content. Using production data from shale gas wells in adjacent blocks, a mathematical relationship was established between the Estimated Ultimate Recovery (EUR) of a single well and the Reservoir Characteristics Index (Rci). The EUR of a single well in wellblock XN111 was estimated.


---

## Body

## 1. Introduction

As an important supplement of and replacement for conventional natural gas resources, shale gas has become a hot spot in global natural gas exploration and development [1–3]. Shale gas is a type of unconventional natural gas, which occurs in shale reservoirs that are rich in organic matter [4, 5]. Such reservoirs have the characteristics of self-generated self-storage, low porosity, and low permeability [6].Several sets of organic-rich shales were developed in the Paleozoic and Mesozoic in the Upper Yangtze region of southern China [7]. The shale reservoirs of the Lower Cambrian Niutetang Formation and the Lower Silurian Longmaxi Formation are the most well developed [8, 9], and their shale gas resources have great potential. Among them, the evaluation and exploration of shale gas resources in the Sichuan Basin and its surrounding areas have achieved remarkable results and an excellent understanding [10, 11]. By the end of 2019, the cumulative proven shale gas reserves of the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation had exceeded 1.8×108m3 [12]. The commercial development of shale gas in Fuling, Changning, Weiyuan, Zhaotong, Yongchuan, and other areas indicates that China’s shale gas has entered a stage of industrial-scale exploitation [13], which is of far-reaching significance to China’s unconventional gas development and energy structure optimization. The Longmaxi Formation shale is widely distributed in the Sichuan Basin and its periphery [14], and it is the key strata of marine shale gas exploration and development in China. Shale gas reservoirs are controlled by their sedimentary environments [15], tectonic movement [16], diagenesis, and pressure evolution [17, 18]. Shale gas reservoirs’ characteristics are significantly different under different geological conditions [19], which determine the development characteristics and distribution of the high-quality shale gas reservoirs in the Longmaxi Formation. The characteristics of shale reservoirs [20] and their development potential [21] are the most critical factors limiting shale gas development. Some studies have examined nanopores of shale reservoirs by a field emission scanning microscope-focused ion beam [22–24]; some work have studied on the gas flow behavior of shale gas [25, 26]; and others have proposed criteria for identifying high-quality shale reservoirs [27, 28]. Some studies have evaluated the potential of shale reservoirs; most of them focus on static resource potential and development potential. For example, Guo et al. (2020) has proposed a method to evaluate the resource potential of shale reservoir, which takes the heterogeneity of shale reservoir into account and could correct the TOC difference [29]. Viet and Hyundon [30] analyze the production potential and economic feasibility in a shale gas reservoir by using an economic indicator. Since shale gas is mainly concentrated in micronanoscale pores [31, 32], it is of great significance to explore the factors influencing the development of shale reservoirs and to determine the resource scale that determines the development potential of shale gas in order to clarify the development mechanism of high-quality shale reservoirs and the efficient development mechanism of shale gas.Taking the wellblock XN111 in the Sichuan Basin as an example, the shale’s geochemical and mineralogical characteristics were obtained using X-ray diffraction, scanning electron microscopy, isothermal adsorption, and other techniques. The structure, reservoir space, and reservoir fluid parameters of the shale reservoir in the Longmaxi Formation in well XN111 were identified. The main factors affecting the shale gas accumulation in this area were investigated. The shale gas reserves were estimated using the volume method. In addition, the calculation of the single well shale gas development potential provides theoretical support for shale gas exploration in the Sichuan Basin and in similar basins in the future.


## 2. Regional Geologic Setting

From the Late Sinian, the Upper Yangtze Basin gradually entered a stable thermal subsidence stage, with the Upper Yangtze Platform sandwiched between the South China and Qinling oceans [33, 34]. In the Late Caledonian, the Upper Yangtze Platform area formed a craton depression basin in the Early-Middle Silurian due to the collision and compression between the Cathaysia Plate and the Yangtze Plate [35] when the South China Ocean was closed. The Late Ordovician-Early Silurian was a period of intense compression in southern China [36]. Under the continuous subduction of the Gutethys Ocean, the scope of the uplifted subcratonic basin where the Sichuan Basin was located was further reduced [37], and in the Early-Middle Ordovician, the sea area with broad sea characteristics was transformed into a sea area restricted by underwater uplift (Figure 1). With the further uplift of the paleo-uplift in the basin, marine shale with a wide distribution [38], a large thickness, and a low deposition rate were formed in an anoxic deep-water shelf environment at medium depths.Figure 1
Structural sketch map and sedimentary environment of the Sichuan Basin, southern China.The Longmaxi Formation was stable in the Sichuan Basin in the Early Silurian. In the Upper Yangtze region, the Early Silurian Longmaxi Formation inherited the scale of the transgression in the Middle-Late Ordovician [39]. Due to the continuous and stable subsidence of the crust, the transgression scale was large, the environment was stable, and the lithologic combination was relatively stable [40]. It was rich in lithology, radiolarians, and sponge containing bone spicules, which were distributed throughout the basin, representing a group of offshore continental shelf strata deposited under reducing conditions [41]. Well XN111 is located in the southwestern part of the Upper Yangtze Platform, which is on the western margin of the Sichuan Basin. The Longmaxi Formation in well XN111 consists of five types of petrofacies: ordinary shale, siliceous shale, carbonaceous shale, silty shale, and calcareous shale. The lower part of the shale of the Longmaxi Formation in well XN111 is composed of black carbonaceous mudstone, which is rich in graphitization stone, rich in organic matter, and stable in distribution. The upper lithology is mainly gray black, black thin-middle-layered carbonaceous shale, and siltstone with banded and lensed argillaceous micritic limestone.


## 3. Database and Methodology

This study is based on 168 m of cores, 108 thin sections, X-ray diffraction (XRD) data for 24 samples, source rock data for 29 samples (vitrinite reflectance, total organic carbon (TOC) content, and macerals), and scanning electron microscope (SEM) observations of 47 samples from wellblock XN111.The XRD analyses were conducted using a BRUKER D8 ADVANCE diffraction tester. The test conditions were as follows: Cu target, K radiation, 40 kV tube voltage, and 30 mA tube current. After the test, a corresponding analysis was carried out using the material standard powder diffraction data. Before the TOC analysis, the samples were dried and ground to 80 mesh. The determination was completed using a CS-344 analyzer. The vitrinite reflectance (Ro) was determined using a Zeiss MPV-SP photometer. The carbon dioxide/nitrogen isothermal adsorption experiment was performed using an Autosorb IQ3 automatic specific surface and pore size distribution analyzer produced by Kantar. The shale samples were broken into 60–80 samples and dried in an oven at 110°C for 12 h. Then, the Autosorb-IQ3 automatic specific surface and pore size distribution analyzer was placed under vacuum conditions at 110°C for 12 h before degassing. After the analyses, the carbon dioxide adsorption data and nitrogen adsorption data were interpreted using the density functional theory (DFT) model to obtain relevant information, such as the pore volume and specific surface area. The macropore volume and specific surface area were obtained by subtracting the micropore and mesopore volumes and the specific surface area from the total pore volume and specific surface area of the nitrogen adsorption data, respectively.An argon ion polishing-field emission scanning electron microscope (SEM) was used for the observation. The images were obtained using an S-4700 cold field emission scanning electron microscope (SEM), and then, the images were uniformly binarized and parameterized.


## 4. Results

### 4.1. Mineralogy

The X-ray diffraction analysis of the rock samples revealed that the minerals in the shale include quartz, feldspar, calcite, dolomite, pyrite, and clay (Figure2), among which the clay minerals are mainly illite, an I/milled layer, and chlorite. The quartz content of the high-quality shale in the Longmaxi Formation is high, accounting for 42.3% on average. This is followed by calcite and dolomite, with average contents of 13.5% and 12.9%, respectively, and small amounts of feldspar and pyrite. The clay mineral content is generally low, ranging from 5.1% to 58.2%, with an average of 23.8%. It is mainly composed of illite and does not contain montmorillonite.Figure 2
Mineral composition of the shale reservoir in the Longmaxi Formation.


### 4.2. Fractures

Tectonic fractures, bedding fractures, and diagenetic shrinkage fractures are the most common types of fractures in the Longmaxi Formation shale (Figure3). The fractures are unevenly distributed. The structural fractures are usually divided into filled and unfilled types. High-angle structural fractures can be seen in the siliceous shale of the lower Longmaxi Formation. Obvious specular and scratches are usually visible on the structural fracture surfaces. The structural fractures in the individual strata are particularly well developed. The image logging data show that there are 27 high-resistance structural fractures in the 2443 m deep section of the Longmaxi Formation in well XN111, and the strike direction is 70–80° NE. The size of the structural fractures is usually several millimeters, making them the dominant channel for natural gas migration and seepage.Figure 3
Characteristics of the shale fractures in the Longmaxi Formation. (a) High-angle fractures filled with calcite; (b) high-angle fractures filled with calcite; (c) unfilled high-angle fractures; (d) lamellation; (e) diagenetic shrinkage fractures; and (f) diagenetic shrinkage fractures.
(a)
(b)
(c)
(d)
(e)
(f)The foliation is generally horizontal and patchy, and it was observed in both outcrops and the core samples, which is a unique feature of the shale. In the quiet and stable deep-water depositional environment, due to the low deposition rate, the sediments developed laminar accumulation features. However, due to the high organic matter content, under diagenetic compaction, the organic matter and clay minerals contracted strongly and formed bedding joints between the thin bedding. They are basically several microns in size and generally formed in the carbonaceous shale. Diagenetic shrinkage cracks are microcracks formed by dehydration due to the evaporation of water during diagenesis. Mineral particles are often distributed, and some of them can be broken into fragments. The width of the fractures is small and irregular.In addition to macrofractures that can be resolved using the core samples and the image logging data, a large number of microfractures were also observed in the Longmaxi Formation. The microfractures generally include filling fractures, dissolution fractures, interlayer fractures between clay minerals, edge fractures between mineral particles, and microfractures from organic hydrocarbon generation. The causes of microcracks are varied. During diagenesis, changes in the mineral facies will cause the formation of microfractures, such as the dehydration of clay minerals. As the depth of the formation increases, the compaction leads to fracture caused by particle fracturing. Interstitial carbonate material is easily dissolved to form dissolution fractures. In the process of hydrocarbon generation, as the hydrocarbon generation increases, when the breakthrough pressure is reached, a large number of microfractures will be formed. Tectonic activity produces stress, resulting in microfractures between flaky clay minerals and clastic particles. Microfractures can also be formed within and between debris particles under the action of external forces.


### 4.3. Organic Geochemical Characteristics

#### 4.3.1. TOC

The TOC content of the Longmaxi shale reaches a maximum of 6.07 wt.%, with an average of 2.66 wt.% (Figure4). The TOC content varies with the lithology, and the siliceous shale and clay shale contents are the highest. In the lower part of the Longmaxi shale, the TOC content gradually decreases upward.Figure 4
Histogram of the TOC distribution of the Longmaxi Formation.


#### 4.3.2. Thermal Maturity

The Longmaxi shale is at a highly mature stage [42], and the equivalent vitrinite reflectance is 1.6–2.28%, with an average of 2.05%. The Ro value indicates that the source rock has reached the hot gas window.


#### 4.3.3. Gas Content

The gas-bearing property of the shale is strongly heterogeneous, and the gas-bearing properties of the different strata are significantly different. The methane adsorption capacity of the shale is usually related to the organic carbon content, the degree of thermal evolution, the reservoir temperature, the formation pressure, the water saturation, and the composition of the natural gas [43]. For well XN111, the methane gas adsorption capacities of 22 samples ranged from 0.84 to 4.69 m3/t, with an average of 2.92 m3/t. The amount of gas adsorption and the TOC are positively correlated. That is, the greater the TOC, the greater the amount of gas adsorption. Organic matter has a strong gas adsorption potential, which can explain this phenomenon. A large amount of shale gas is adsorbed onto the surfaces of the kerogen in the shale, and the high TOC content indicates the large volume and adsorption capacity of the shale gas. The field measurements of the gas content reveal that the gas content of the lower shale of the Longmaxi Formation in well XN111 is greater than 3.0 m3/t, and the overall adsorption capacity and gas content of the lower shale of the Longmaxi Formation are relatively large. For example, the isothermal adsorption data for the upper and lower shale reservoirs (samples 48409-4B and 48409-3B, respectively) in the Longmaxi Formation were compared. The methane adsorption capacity of upper sample 48409-4B was 2.55 m3/t, while that of lower sample 48409-3B was 3.2 m3/t. The methane adsorption capacity of the lower shale reservoir was 25.5% higher than that of the upper shale reservoir (Figure 5).Figure 5
Isothermal adsorption curve for the Longmaxi Formation in well XN111.


### 4.4. Reservoir Storage Space

The morphology, quantity, and distribution of the shale micropores were qualitatively observed using focused ion beam scanning electron microscope (FIB-SEM). According to the relationship between the pore development and rock particles, they can be divided into matrix pores (organic pores, clay mineral interlayer pores, berry pyrite intercrystalline pores, grain mineral edge pores, and secondary dissolution pores) and microfractures (Figure6). The interbedded pores in the organic matter and clay minerals are the most well developed and are important components of the reservoir space.Figure 6
FE-SEM images of the shale samples from wellblock XN111. (a) OM pores, pyrite, and interP pores at the edges of mineral grains; (b) large OM particle with irregular and elliptical OM pores; (c) intercrystalline interP pores in pyrite framboids; (d) microfractures; (e) intraP pores with calcite grains; (f) OM pores and interP pores at the edge of a calcite grains; (g) interP pores at the edges of mineral grains, OM pores, and intercrystalline interP pores in clay particles; (h) fluid inclusion intraP pores within brittle minerals and OM pores in OM grains; (i) cleavage-sheet intraP pores within clay particles and OM pores; (j) intercrystalline interP pores in pyrite framboids, microfractures and OM particle with irregular and elliptical OM pores; (k) OM pores and interP pores at the edges of mineral grains; (l) porous OM particles.
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)The organic matter pores are secondary pores formed inside kerogen during diagenetic evolution from solid kerogen to hydrocarbon fluid [44, 45]. They are mostly round, elliptical, and irregular polygons, and they are generally 10–150 nm in size. The dispersed organic matter is commonly associated with berry pyrite and clay minerals, and organic matter nanopores are developed in the pyrite grains and clay minerals. In the early deep-water continental shelf sedimentary environment of the Longmaxi Formation, a large amount of red algae was produced [46], and a large number of organic pores easily developed.During the diagenetic evolution, the montmorillonite transformed into illite through the Aemon mixed layer. Intrapores were generated between the filamentous or curly illite, which were arranged in parallel with each other and had good connectivity. A berry pyrite micropellet formed in an anoxic environment, consisting of many small pyrite grains. The intercrystalline interP pores are nanopores. Calcite, feldspar, and other soluble minerals easily produce secondary dissolution pores through acid etching, which have a more irregular shape, are relatively isolated, and have poor connectivity. Micropores are easily developed on the edge of quartz and other rigid granular minerals. Their morphology is controlled by the original porosity and diagenesis [47, 48], and they are mostly triangular or irregular, with poor connectivity. The microfractures are more well developed, and most of them are serrated or curvilinear. Their extension length is large, and their widths are generally 50–100 nm. They can provide storage space for free gas and can be helpful when analyzing the adsorbed gas. They are an important channel for gas seepage.


### 4.5. Reservoir Properties

The porosity of the Longmaxi shale is 0.86% to 8.44% (average 4.78%). The permeability is very low, ranging from 0.0026 D to 0.0328 D, with a mean of 0.0116 D. The analysis shows that the specific surface area ranges from 3.263 m2/g to 38.767 m2/g, with average of 18.76 m2/g. The specific surface area provided by the micropores is 2.712–21.69 m2/g, with an average of 8.57 m2/g, accounting for 45.68% of the specific surface area. The mean throat radius is 4 nm to 16.1 nm, with a mean of 7.2 nm. The total pore volume of the Longmaxi shale is 11×10−4ml/g to 321×10−4ml/g, with an average of 109×10−4ml/g. The pore volume provided by the micropores (<2 nm) is 2.5×10−4ml/g to 22.3×10−4ml/g, with an average of 10.3×10−4ml/g, accounting for an average of 9.45% of the total pore volume. The mesopore volume (2 nm to 50 nm) ranges from 31.4×10−4ml/g to 278×10−4ml/g, with an average of 86×10−4ml/g. The macropores (>50 nm) account for 11.65% of the total pore volume, indicating that the mesopores are dominant in the Longmaxi shale.


## 4.1. Mineralogy

The X-ray diffraction analysis of the rock samples revealed that the minerals in the shale include quartz, feldspar, calcite, dolomite, pyrite, and clay (Figure2), among which the clay minerals are mainly illite, an I/milled layer, and chlorite. The quartz content of the high-quality shale in the Longmaxi Formation is high, accounting for 42.3% on average. This is followed by calcite and dolomite, with average contents of 13.5% and 12.9%, respectively, and small amounts of feldspar and pyrite. The clay mineral content is generally low, ranging from 5.1% to 58.2%, with an average of 23.8%. It is mainly composed of illite and does not contain montmorillonite.Figure 2
Mineral composition of the shale reservoir in the Longmaxi Formation.


## 4.2. Fractures

Tectonic fractures, bedding fractures, and diagenetic shrinkage fractures are the most common types of fractures in the Longmaxi Formation shale (Figure3). The fractures are unevenly distributed. The structural fractures are usually divided into filled and unfilled types. High-angle structural fractures can be seen in the siliceous shale of the lower Longmaxi Formation. Obvious specular and scratches are usually visible on the structural fracture surfaces. The structural fractures in the individual strata are particularly well developed. The image logging data show that there are 27 high-resistance structural fractures in the 2443 m deep section of the Longmaxi Formation in well XN111, and the strike direction is 70–80° NE. The size of the structural fractures is usually several millimeters, making them the dominant channel for natural gas migration and seepage.Figure 3
Characteristics of the shale fractures in the Longmaxi Formation. (a) High-angle fractures filled with calcite; (b) high-angle fractures filled with calcite; (c) unfilled high-angle fractures; (d) lamellation; (e) diagenetic shrinkage fractures; and (f) diagenetic shrinkage fractures.
(a)
(b)
(c)
(d)
(e)
(f)The foliation is generally horizontal and patchy, and it was observed in both outcrops and the core samples, which is a unique feature of the shale. In the quiet and stable deep-water depositional environment, due to the low deposition rate, the sediments developed laminar accumulation features. However, due to the high organic matter content, under diagenetic compaction, the organic matter and clay minerals contracted strongly and formed bedding joints between the thin bedding. They are basically several microns in size and generally formed in the carbonaceous shale. Diagenetic shrinkage cracks are microcracks formed by dehydration due to the evaporation of water during diagenesis. Mineral particles are often distributed, and some of them can be broken into fragments. The width of the fractures is small and irregular.In addition to macrofractures that can be resolved using the core samples and the image logging data, a large number of microfractures were also observed in the Longmaxi Formation. The microfractures generally include filling fractures, dissolution fractures, interlayer fractures between clay minerals, edge fractures between mineral particles, and microfractures from organic hydrocarbon generation. The causes of microcracks are varied. During diagenesis, changes in the mineral facies will cause the formation of microfractures, such as the dehydration of clay minerals. As the depth of the formation increases, the compaction leads to fracture caused by particle fracturing. Interstitial carbonate material is easily dissolved to form dissolution fractures. In the process of hydrocarbon generation, as the hydrocarbon generation increases, when the breakthrough pressure is reached, a large number of microfractures will be formed. Tectonic activity produces stress, resulting in microfractures between flaky clay minerals and clastic particles. Microfractures can also be formed within and between debris particles under the action of external forces.


## 4.3. Organic Geochemical Characteristics

### 4.3.1. TOC

The TOC content of the Longmaxi shale reaches a maximum of 6.07 wt.%, with an average of 2.66 wt.% (Figure4). The TOC content varies with the lithology, and the siliceous shale and clay shale contents are the highest. In the lower part of the Longmaxi shale, the TOC content gradually decreases upward.Figure 4
Histogram of the TOC distribution of the Longmaxi Formation.


### 4.3.2. Thermal Maturity

The Longmaxi shale is at a highly mature stage [42], and the equivalent vitrinite reflectance is 1.6–2.28%, with an average of 2.05%. The Ro value indicates that the source rock has reached the hot gas window.


### 4.3.3. Gas Content

The gas-bearing property of the shale is strongly heterogeneous, and the gas-bearing properties of the different strata are significantly different. The methane adsorption capacity of the shale is usually related to the organic carbon content, the degree of thermal evolution, the reservoir temperature, the formation pressure, the water saturation, and the composition of the natural gas [43]. For well XN111, the methane gas adsorption capacities of 22 samples ranged from 0.84 to 4.69 m3/t, with an average of 2.92 m3/t. The amount of gas adsorption and the TOC are positively correlated. That is, the greater the TOC, the greater the amount of gas adsorption. Organic matter has a strong gas adsorption potential, which can explain this phenomenon. A large amount of shale gas is adsorbed onto the surfaces of the kerogen in the shale, and the high TOC content indicates the large volume and adsorption capacity of the shale gas. The field measurements of the gas content reveal that the gas content of the lower shale of the Longmaxi Formation in well XN111 is greater than 3.0 m3/t, and the overall adsorption capacity and gas content of the lower shale of the Longmaxi Formation are relatively large. For example, the isothermal adsorption data for the upper and lower shale reservoirs (samples 48409-4B and 48409-3B, respectively) in the Longmaxi Formation were compared. The methane adsorption capacity of upper sample 48409-4B was 2.55 m3/t, while that of lower sample 48409-3B was 3.2 m3/t. The methane adsorption capacity of the lower shale reservoir was 25.5% higher than that of the upper shale reservoir (Figure 5).Figure 5
Isothermal adsorption curve for the Longmaxi Formation in well XN111.


## 4.3.1. TOC

The TOC content of the Longmaxi shale reaches a maximum of 6.07 wt.%, with an average of 2.66 wt.% (Figure4). The TOC content varies with the lithology, and the siliceous shale and clay shale contents are the highest. In the lower part of the Longmaxi shale, the TOC content gradually decreases upward.Figure 4
Histogram of the TOC distribution of the Longmaxi Formation.


## 4.3.2. Thermal Maturity

The Longmaxi shale is at a highly mature stage [42], and the equivalent vitrinite reflectance is 1.6–2.28%, with an average of 2.05%. The Ro value indicates that the source rock has reached the hot gas window.


## 4.3.3. Gas Content

The gas-bearing property of the shale is strongly heterogeneous, and the gas-bearing properties of the different strata are significantly different. The methane adsorption capacity of the shale is usually related to the organic carbon content, the degree of thermal evolution, the reservoir temperature, the formation pressure, the water saturation, and the composition of the natural gas [43]. For well XN111, the methane gas adsorption capacities of 22 samples ranged from 0.84 to 4.69 m3/t, with an average of 2.92 m3/t. The amount of gas adsorption and the TOC are positively correlated. That is, the greater the TOC, the greater the amount of gas adsorption. Organic matter has a strong gas adsorption potential, which can explain this phenomenon. A large amount of shale gas is adsorbed onto the surfaces of the kerogen in the shale, and the high TOC content indicates the large volume and adsorption capacity of the shale gas. The field measurements of the gas content reveal that the gas content of the lower shale of the Longmaxi Formation in well XN111 is greater than 3.0 m3/t, and the overall adsorption capacity and gas content of the lower shale of the Longmaxi Formation are relatively large. For example, the isothermal adsorption data for the upper and lower shale reservoirs (samples 48409-4B and 48409-3B, respectively) in the Longmaxi Formation were compared. The methane adsorption capacity of upper sample 48409-4B was 2.55 m3/t, while that of lower sample 48409-3B was 3.2 m3/t. The methane adsorption capacity of the lower shale reservoir was 25.5% higher than that of the upper shale reservoir (Figure 5).Figure 5
Isothermal adsorption curve for the Longmaxi Formation in well XN111.


## 4.4. Reservoir Storage Space

The morphology, quantity, and distribution of the shale micropores were qualitatively observed using focused ion beam scanning electron microscope (FIB-SEM). According to the relationship between the pore development and rock particles, they can be divided into matrix pores (organic pores, clay mineral interlayer pores, berry pyrite intercrystalline pores, grain mineral edge pores, and secondary dissolution pores) and microfractures (Figure6). The interbedded pores in the organic matter and clay minerals are the most well developed and are important components of the reservoir space.Figure 6
FE-SEM images of the shale samples from wellblock XN111. (a) OM pores, pyrite, and interP pores at the edges of mineral grains; (b) large OM particle with irregular and elliptical OM pores; (c) intercrystalline interP pores in pyrite framboids; (d) microfractures; (e) intraP pores with calcite grains; (f) OM pores and interP pores at the edge of a calcite grains; (g) interP pores at the edges of mineral grains, OM pores, and intercrystalline interP pores in clay particles; (h) fluid inclusion intraP pores within brittle minerals and OM pores in OM grains; (i) cleavage-sheet intraP pores within clay particles and OM pores; (j) intercrystalline interP pores in pyrite framboids, microfractures and OM particle with irregular and elliptical OM pores; (k) OM pores and interP pores at the edges of mineral grains; (l) porous OM particles.
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)The organic matter pores are secondary pores formed inside kerogen during diagenetic evolution from solid kerogen to hydrocarbon fluid [44, 45]. They are mostly round, elliptical, and irregular polygons, and they are generally 10–150 nm in size. The dispersed organic matter is commonly associated with berry pyrite and clay minerals, and organic matter nanopores are developed in the pyrite grains and clay minerals. In the early deep-water continental shelf sedimentary environment of the Longmaxi Formation, a large amount of red algae was produced [46], and a large number of organic pores easily developed.During the diagenetic evolution, the montmorillonite transformed into illite through the Aemon mixed layer. Intrapores were generated between the filamentous or curly illite, which were arranged in parallel with each other and had good connectivity. A berry pyrite micropellet formed in an anoxic environment, consisting of many small pyrite grains. The intercrystalline interP pores are nanopores. Calcite, feldspar, and other soluble minerals easily produce secondary dissolution pores through acid etching, which have a more irregular shape, are relatively isolated, and have poor connectivity. Micropores are easily developed on the edge of quartz and other rigid granular minerals. Their morphology is controlled by the original porosity and diagenesis [47, 48], and they are mostly triangular or irregular, with poor connectivity. The microfractures are more well developed, and most of them are serrated or curvilinear. Their extension length is large, and their widths are generally 50–100 nm. They can provide storage space for free gas and can be helpful when analyzing the adsorbed gas. They are an important channel for gas seepage.


## 4.5. Reservoir Properties

The porosity of the Longmaxi shale is 0.86% to 8.44% (average 4.78%). The permeability is very low, ranging from 0.0026 D to 0.0328 D, with a mean of 0.0116 D. The analysis shows that the specific surface area ranges from 3.263 m2/g to 38.767 m2/g, with average of 18.76 m2/g. The specific surface area provided by the micropores is 2.712–21.69 m2/g, with an average of 8.57 m2/g, accounting for 45.68% of the specific surface area. The mean throat radius is 4 nm to 16.1 nm, with a mean of 7.2 nm. The total pore volume of the Longmaxi shale is 11×10−4ml/g to 321×10−4ml/g, with an average of 109×10−4ml/g. The pore volume provided by the micropores (<2 nm) is 2.5×10−4ml/g to 22.3×10−4ml/g, with an average of 10.3×10−4ml/g, accounting for an average of 9.45% of the total pore volume. The mesopore volume (2 nm to 50 nm) ranges from 31.4×10−4ml/g to 278×10−4ml/g, with an average of 86×10−4ml/g. The macropores (>50 nm) account for 11.65% of the total pore volume, indicating that the mesopores are dominant in the Longmaxi shale.


## 5. Discussion

### 5.1. Main Factors Affecting Shale Gas Enrichment

#### 5.1.1. Stable Anoxic Deep-Water Sedimentary Environment

The stable anoxic deep-water sedimentary environment resulted in the widely distributed shale reservoir in wellblock XN111.A quiet and stable deep-water reducing environment is the best environment for the formation, development, and preservation of organic rich marine sediments. The early stage of the deposition of the Longmaxi Formation in well XN111 inherited the sedimentary characteristics of the Wufeng Formation. The main body of the sediment included deep-water continental shelf and semiconfined shallow sea facies [49]. In this period, the deposition rate was low, and the deposition time was more than half that of the Longmaxi period [50]. The deposition thickness was about 100–135 m, accounting for only 30–45% of the thickness of the entire Longmaxi Formation. Black carbonaceous siliceous shale and black shale were developed. In this period, the semiconfined deep-water shelf was relatively deep, quiet, and stable [51]. The sedimentary thickness was large and the organic matter was rich (graptolite development). The organic matter type was primarily I type, which indicates a high degree of thermal evolution. This was the main period for the development of effective source rocks in the Longmaxi Formation.In the late period of the Longmaxi Formation, dark gray shale, gray mudstone, and silty mudstone assemblages were mainly deposited. The main body was deposited in a shallow water shelf environment. The deposition rate was significantly higher than that in the early period, and the deposition thickness was about 150–165 m (Figure7). During this period, the water body was relatively shallow, the organic matter was relatively undeveloped, and the graptolite content decreased significantly.Figure 7
Sedimentary characteristics of the shale reservoir in the Longmaxi Formation, well XN111, Sichuan Basin.Shale thickness is a prerequisite for commercial shale gas accumulation. Successful experiences in the United States have shown that the minimum thickness of black shale required for exploration and development of shale gas is 30 m. The effective thickness of the Longmaxi Formation in well XN111 is relatively large. The thickness of the lower shale of the Longmaxi Formation increases from northwest to southeast with a thickness of about 120 m. Over 50 m of fine black shale is present.


#### 5.1.2. High TOC Content, Appropriate Organic Matter Type, and Thermal Maturity

Organic pores are the main storage space for shale gas. The TOC is an important factor in reservoir properties and shale gas accumulation. The formation of organic pores is related to the content of transformed organic carbon, which is controlled by the type of organic matter. The organic matter in the Longmaxi shale is mainly Type I kerogen, which is conducive to shale gas accumulation. Studies have shown that the TOC content is positively correlated with the shale gas adsorption and pore volume [52]. Shale gas accumulation requires a TOC of at least 0.5%. The TOC content of the Longmaxi shale in the study area is high, with an average value of 2.66%, which is far higher than the lower TOC limit, indicating that the shale gas reserves have a great potential.Appropriate thermal maturity is very important for shale gas [53]. The vitrinite reflectance can reflect the thermal maturity and affect the shale gas concentration and the reservoir’s physical properties. The average vitrinite reflectance of the Longmaxi shale is 2.05%, which is suitable for the production and accumulation of natural gas. During the thermal evolution of organic matter, a series of physical and chemical reactions occur, including the transformation of organic carbon, the decomposition of organic matter, and the generation of hydrocarbons. Moreover, a large number of nanopores are generated in the source rocks, which can provide storage space for shale gas.


#### 5.1.3. An Assemblage of Rocks and Minerals Prone to Fracturing

The rock mechanics data show that the Young’s modulus of wellblock XN111 is 29,000 to 36,000 MPa, the Poisson’s ratio is 0.16 to 0.18, and the brittleness index can reach more than 65%. This is due to the low content of clay minerals and the high content of brittle minerals (mainly siliceous minerals and carbonate minerals) in wellblock XN111, which makes the Longmaxi Formation shale easy to fracture and produce.


#### 5.1.4. Widely Distributed Natural Fractures

Fractures provide important reservoirs for shale gas and can act as seepage channels for methane molecules. The image logging and core data show that the fracture width of the Longmaxi Formation is 0.5 to 1 mm, and the fracture density of most of the wells is 0.4/m to 4/m. These widely developed macroscopic fractures are important factors controlling the shale gas enrichment in the Longmaxi Formation. Due to the extremely low permeability of the shale system, a certain scale of structural fractures is conducive to improving the permeability of the shale reservoir and forming a dominant seepage channel, which is the key factor for high yield shale gas wells. The image logging data show that 87 high-resistance fractures are developed in the lower Longmaxi Formation in well XN111, with an azimuth of 340–350° NE, a strike of 70–80° NNE, and an inclination of 20–80° (Figure8). Similarly, shale fractures and diagenetic shrinkage fractures are also beneficial to improving the conductivity of shale reservoirs.Figure 8
Fracture statistics of well XN111. (a) rosette (azimuth); (b) rosette (strike); (c) dip (degree).
(a)
(b)
(c)Microfractures form a bridge connecting the macroscopic fractures and microscopic pores. They play an important role in shale gas seepage. The microfractures in the Longmaxi Formation are well developed because the organic particles, brittle minerals, and clay minerals can develop microfractures. These large-scale microfractures are connected with other pores, forming a fracture network-pore system, which provides effective storage and seepage space for the natural gas trapped in the shale.


### 5.2. The Development Potential of the Longmaxi Shale Gas

The area of shale gas in well XN111 is about 390 km2. Thus far, several horizontal fracturing wells have been drilled, and good results have been achieved. The total shale thickness of the Longmaxi Formation in well XN111 is 30–210 m. Among them, the lower part of the Longmaxi Formation has an effective shale thickness of 33.9 m. The total porosity is 3–6%, fractures are developed, and it is a high-quality source rock and reservoir (high TOC content, relatively high Ro content). The gas content is 3.82 m3/t, and the pressure coefficient is 1.80. According to the volume method, the Longmaxi shale gas resources in wellblock XN111 can reach 1393.7×108m3, and the reserve abundance is 3.57×108m3/km2.The maximum principal stress direction in this area is NW (300–310°), and the natural fracture direction is NNE (30°). Both the fracturing effect and the drilling safety should be considered when designing the horizontal well orientation. The horizontal trajectory orientation of the horizontal well group is selected at a certain angle with respect to the direction of the minimum principal stress and the natural fractures, comprehensively taking the natural fractures, structural morphology, and other factors into consideration. The best horizontal well trajectory directions for this area were determined to be NE20° and SW200°. Since the high-pressure dry gas shale reservoir in the Longmaxi Formation in the well XN111 area is mainly driven by elasticity, the exploitation of natural energy depletion was adopted in the early stage. When the wellhead pressure dropped to the pipeline pressure, pressurization was used for the mining. The production capacity was mainly maintained by means of interwell replacement.Sensitivity analysis of the reservoir parameters affecting the shale production in the adjacent Longmaxi Formation was carried out. Five parameters, including the shale thickness, gas content, TOC, fracture density, and clay content, were selected. Among them, the high-quality shale thickness, gas content, TOC, and fracture density are positively correlated with gas well production, while clay content is negatively correlated with gas well production. The reservoir characteristic index was constructed, which is a comprehensive mathematical index that affects the production of shale gas wells. The mathematical relationship between the Estimated Ultimate Recovery (EUR) of a single well and the Reservoir Characteristic Index (Rci) (Figure9) was established using the production data for the gas wells for which the production conditions are close to waste in the adjacent well area:
(1)EUR=3035.7e0.6032Rci.Figure 9
Plot of the reservoir characteristic index versus the EUR of wellblock XN111.Based on the relationships between the single-well EUR, the initial production, and the comprehensive classification coefficient in the adjacent block, it was predicted that the single-well index in wellblock XN111 is9666×104m3. Factors controlling shale reservoirs were analyzed to clarify geochemical and mineralogical characteristics, which also provide the structure, reservoir space, and reservoir fluid parameters. The model of Estimated Ultimate Recovery (EUR) is comprehensive when considered all the most influential parameters: high-quality shale thickness, gas content, TOC, fracture density, and clay content. The model is efficient and convenient to use for various reservoir characteristics scenarios.


## 5.1. Main Factors Affecting Shale Gas Enrichment

### 5.1.1. Stable Anoxic Deep-Water Sedimentary Environment

The stable anoxic deep-water sedimentary environment resulted in the widely distributed shale reservoir in wellblock XN111.A quiet and stable deep-water reducing environment is the best environment for the formation, development, and preservation of organic rich marine sediments. The early stage of the deposition of the Longmaxi Formation in well XN111 inherited the sedimentary characteristics of the Wufeng Formation. The main body of the sediment included deep-water continental shelf and semiconfined shallow sea facies [49]. In this period, the deposition rate was low, and the deposition time was more than half that of the Longmaxi period [50]. The deposition thickness was about 100–135 m, accounting for only 30–45% of the thickness of the entire Longmaxi Formation. Black carbonaceous siliceous shale and black shale were developed. In this period, the semiconfined deep-water shelf was relatively deep, quiet, and stable [51]. The sedimentary thickness was large and the organic matter was rich (graptolite development). The organic matter type was primarily I type, which indicates a high degree of thermal evolution. This was the main period for the development of effective source rocks in the Longmaxi Formation.In the late period of the Longmaxi Formation, dark gray shale, gray mudstone, and silty mudstone assemblages were mainly deposited. The main body was deposited in a shallow water shelf environment. The deposition rate was significantly higher than that in the early period, and the deposition thickness was about 150–165 m (Figure7). During this period, the water body was relatively shallow, the organic matter was relatively undeveloped, and the graptolite content decreased significantly.Figure 7
Sedimentary characteristics of the shale reservoir in the Longmaxi Formation, well XN111, Sichuan Basin.Shale thickness is a prerequisite for commercial shale gas accumulation. Successful experiences in the United States have shown that the minimum thickness of black shale required for exploration and development of shale gas is 30 m. The effective thickness of the Longmaxi Formation in well XN111 is relatively large. The thickness of the lower shale of the Longmaxi Formation increases from northwest to southeast with a thickness of about 120 m. Over 50 m of fine black shale is present.


### 5.1.2. High TOC Content, Appropriate Organic Matter Type, and Thermal Maturity

Organic pores are the main storage space for shale gas. The TOC is an important factor in reservoir properties and shale gas accumulation. The formation of organic pores is related to the content of transformed organic carbon, which is controlled by the type of organic matter. The organic matter in the Longmaxi shale is mainly Type I kerogen, which is conducive to shale gas accumulation. Studies have shown that the TOC content is positively correlated with the shale gas adsorption and pore volume [52]. Shale gas accumulation requires a TOC of at least 0.5%. The TOC content of the Longmaxi shale in the study area is high, with an average value of 2.66%, which is far higher than the lower TOC limit, indicating that the shale gas reserves have a great potential.Appropriate thermal maturity is very important for shale gas [53]. The vitrinite reflectance can reflect the thermal maturity and affect the shale gas concentration and the reservoir’s physical properties. The average vitrinite reflectance of the Longmaxi shale is 2.05%, which is suitable for the production and accumulation of natural gas. During the thermal evolution of organic matter, a series of physical and chemical reactions occur, including the transformation of organic carbon, the decomposition of organic matter, and the generation of hydrocarbons. Moreover, a large number of nanopores are generated in the source rocks, which can provide storage space for shale gas.


### 5.1.3. An Assemblage of Rocks and Minerals Prone to Fracturing

The rock mechanics data show that the Young’s modulus of wellblock XN111 is 29,000 to 36,000 MPa, the Poisson’s ratio is 0.16 to 0.18, and the brittleness index can reach more than 65%. This is due to the low content of clay minerals and the high content of brittle minerals (mainly siliceous minerals and carbonate minerals) in wellblock XN111, which makes the Longmaxi Formation shale easy to fracture and produce.


### 5.1.4. Widely Distributed Natural Fractures

Fractures provide important reservoirs for shale gas and can act as seepage channels for methane molecules. The image logging and core data show that the fracture width of the Longmaxi Formation is 0.5 to 1 mm, and the fracture density of most of the wells is 0.4/m to 4/m. These widely developed macroscopic fractures are important factors controlling the shale gas enrichment in the Longmaxi Formation. Due to the extremely low permeability of the shale system, a certain scale of structural fractures is conducive to improving the permeability of the shale reservoir and forming a dominant seepage channel, which is the key factor for high yield shale gas wells. The image logging data show that 87 high-resistance fractures are developed in the lower Longmaxi Formation in well XN111, with an azimuth of 340–350° NE, a strike of 70–80° NNE, and an inclination of 20–80° (Figure8). Similarly, shale fractures and diagenetic shrinkage fractures are also beneficial to improving the conductivity of shale reservoirs.Figure 8
Fracture statistics of well XN111. (a) rosette (azimuth); (b) rosette (strike); (c) dip (degree).
(a)
(b)
(c)Microfractures form a bridge connecting the macroscopic fractures and microscopic pores. They play an important role in shale gas seepage. The microfractures in the Longmaxi Formation are well developed because the organic particles, brittle minerals, and clay minerals can develop microfractures. These large-scale microfractures are connected with other pores, forming a fracture network-pore system, which provides effective storage and seepage space for the natural gas trapped in the shale.


## 5.1.1. Stable Anoxic Deep-Water Sedimentary Environment

The stable anoxic deep-water sedimentary environment resulted in the widely distributed shale reservoir in wellblock XN111.A quiet and stable deep-water reducing environment is the best environment for the formation, development, and preservation of organic rich marine sediments. The early stage of the deposition of the Longmaxi Formation in well XN111 inherited the sedimentary characteristics of the Wufeng Formation. The main body of the sediment included deep-water continental shelf and semiconfined shallow sea facies [49]. In this period, the deposition rate was low, and the deposition time was more than half that of the Longmaxi period [50]. The deposition thickness was about 100–135 m, accounting for only 30–45% of the thickness of the entire Longmaxi Formation. Black carbonaceous siliceous shale and black shale were developed. In this period, the semiconfined deep-water shelf was relatively deep, quiet, and stable [51]. The sedimentary thickness was large and the organic matter was rich (graptolite development). The organic matter type was primarily I type, which indicates a high degree of thermal evolution. This was the main period for the development of effective source rocks in the Longmaxi Formation.In the late period of the Longmaxi Formation, dark gray shale, gray mudstone, and silty mudstone assemblages were mainly deposited. The main body was deposited in a shallow water shelf environment. The deposition rate was significantly higher than that in the early period, and the deposition thickness was about 150–165 m (Figure7). During this period, the water body was relatively shallow, the organic matter was relatively undeveloped, and the graptolite content decreased significantly.Figure 7
Sedimentary characteristics of the shale reservoir in the Longmaxi Formation, well XN111, Sichuan Basin.Shale thickness is a prerequisite for commercial shale gas accumulation. Successful experiences in the United States have shown that the minimum thickness of black shale required for exploration and development of shale gas is 30 m. The effective thickness of the Longmaxi Formation in well XN111 is relatively large. The thickness of the lower shale of the Longmaxi Formation increases from northwest to southeast with a thickness of about 120 m. Over 50 m of fine black shale is present.


## 5.1.2. High TOC Content, Appropriate Organic Matter Type, and Thermal Maturity

Organic pores are the main storage space for shale gas. The TOC is an important factor in reservoir properties and shale gas accumulation. The formation of organic pores is related to the content of transformed organic carbon, which is controlled by the type of organic matter. The organic matter in the Longmaxi shale is mainly Type I kerogen, which is conducive to shale gas accumulation. Studies have shown that the TOC content is positively correlated with the shale gas adsorption and pore volume [52]. Shale gas accumulation requires a TOC of at least 0.5%. The TOC content of the Longmaxi shale in the study area is high, with an average value of 2.66%, which is far higher than the lower TOC limit, indicating that the shale gas reserves have a great potential.Appropriate thermal maturity is very important for shale gas [53]. The vitrinite reflectance can reflect the thermal maturity and affect the shale gas concentration and the reservoir’s physical properties. The average vitrinite reflectance of the Longmaxi shale is 2.05%, which is suitable for the production and accumulation of natural gas. During the thermal evolution of organic matter, a series of physical and chemical reactions occur, including the transformation of organic carbon, the decomposition of organic matter, and the generation of hydrocarbons. Moreover, a large number of nanopores are generated in the source rocks, which can provide storage space for shale gas.


## 5.1.3. An Assemblage of Rocks and Minerals Prone to Fracturing

The rock mechanics data show that the Young’s modulus of wellblock XN111 is 29,000 to 36,000 MPa, the Poisson’s ratio is 0.16 to 0.18, and the brittleness index can reach more than 65%. This is due to the low content of clay minerals and the high content of brittle minerals (mainly siliceous minerals and carbonate minerals) in wellblock XN111, which makes the Longmaxi Formation shale easy to fracture and produce.


## 5.1.4. Widely Distributed Natural Fractures

Fractures provide important reservoirs for shale gas and can act as seepage channels for methane molecules. The image logging and core data show that the fracture width of the Longmaxi Formation is 0.5 to 1 mm, and the fracture density of most of the wells is 0.4/m to 4/m. These widely developed macroscopic fractures are important factors controlling the shale gas enrichment in the Longmaxi Formation. Due to the extremely low permeability of the shale system, a certain scale of structural fractures is conducive to improving the permeability of the shale reservoir and forming a dominant seepage channel, which is the key factor for high yield shale gas wells. The image logging data show that 87 high-resistance fractures are developed in the lower Longmaxi Formation in well XN111, with an azimuth of 340–350° NE, a strike of 70–80° NNE, and an inclination of 20–80° (Figure8). Similarly, shale fractures and diagenetic shrinkage fractures are also beneficial to improving the conductivity of shale reservoirs.Figure 8
Fracture statistics of well XN111. (a) rosette (azimuth); (b) rosette (strike); (c) dip (degree).
(a)
(b)
(c)Microfractures form a bridge connecting the macroscopic fractures and microscopic pores. They play an important role in shale gas seepage. The microfractures in the Longmaxi Formation are well developed because the organic particles, brittle minerals, and clay minerals can develop microfractures. These large-scale microfractures are connected with other pores, forming a fracture network-pore system, which provides effective storage and seepage space for the natural gas trapped in the shale.


## 5.2. The Development Potential of the Longmaxi Shale Gas

The area of shale gas in well XN111 is about 390 km2. Thus far, several horizontal fracturing wells have been drilled, and good results have been achieved. The total shale thickness of the Longmaxi Formation in well XN111 is 30–210 m. Among them, the lower part of the Longmaxi Formation has an effective shale thickness of 33.9 m. The total porosity is 3–6%, fractures are developed, and it is a high-quality source rock and reservoir (high TOC content, relatively high Ro content). The gas content is 3.82 m3/t, and the pressure coefficient is 1.80. According to the volume method, the Longmaxi shale gas resources in wellblock XN111 can reach 1393.7×108m3, and the reserve abundance is 3.57×108m3/km2.The maximum principal stress direction in this area is NW (300–310°), and the natural fracture direction is NNE (30°). Both the fracturing effect and the drilling safety should be considered when designing the horizontal well orientation. The horizontal trajectory orientation of the horizontal well group is selected at a certain angle with respect to the direction of the minimum principal stress and the natural fractures, comprehensively taking the natural fractures, structural morphology, and other factors into consideration. The best horizontal well trajectory directions for this area were determined to be NE20° and SW200°. Since the high-pressure dry gas shale reservoir in the Longmaxi Formation in the well XN111 area is mainly driven by elasticity, the exploitation of natural energy depletion was adopted in the early stage. When the wellhead pressure dropped to the pipeline pressure, pressurization was used for the mining. The production capacity was mainly maintained by means of interwell replacement.Sensitivity analysis of the reservoir parameters affecting the shale production in the adjacent Longmaxi Formation was carried out. Five parameters, including the shale thickness, gas content, TOC, fracture density, and clay content, were selected. Among them, the high-quality shale thickness, gas content, TOC, and fracture density are positively correlated with gas well production, while clay content is negatively correlated with gas well production. The reservoir characteristic index was constructed, which is a comprehensive mathematical index that affects the production of shale gas wells. The mathematical relationship between the Estimated Ultimate Recovery (EUR) of a single well and the Reservoir Characteristic Index (Rci) (Figure9) was established using the production data for the gas wells for which the production conditions are close to waste in the adjacent well area:
(1)EUR=3035.7e0.6032Rci.Figure 9
Plot of the reservoir characteristic index versus the EUR of wellblock XN111.Based on the relationships between the single-well EUR, the initial production, and the comprehensive classification coefficient in the adjacent block, it was predicted that the single-well index in wellblock XN111 is9666×104m3. Factors controlling shale reservoirs were analyzed to clarify geochemical and mineralogical characteristics, which also provide the structure, reservoir space, and reservoir fluid parameters. The model of Estimated Ultimate Recovery (EUR) is comprehensive when considered all the most influential parameters: high-quality shale thickness, gas content, TOC, fracture density, and clay content. The model is efficient and convenient to use for various reservoir characteristics scenarios.


## 6. Conclusions

In this study, the characteristics and development potential of the shale reservoirs in the Lower Silurian Longmaxi Formation were analyzed by taking wellblock XN111 in the Sichuan Basin, southern China, as an example. Several important findings are summarized as follows.(1)
The widespread deep-water shelf deposition was a favorable environment for the development of high-quality shale hydrocarbon source rocks with a cumulative thickness of up to 50 m. The high TOC content results in the shale reservoir having high free gas and adsorption gas storage capacity. The high maturity to over maturity of the shale is conducive to the formation of organic pores, and the pore space is dominated by mesopores (2–50 nm). The development of fractures further effectively improves the reservoir and the seepage capacity of the shale reservoirs(2)
The reservoir characteristic index was constructed using five parameters: high-quality shale thickness, gas content, TOC, fracture density, and clay content. The mathematical relationship between the Estimated Ultimate Recovery (EUR) of a single well and the Reservoir Characteristic Index (Rci) was established. It was predicted that the EUR of a single well in the well XN111 area is9666×104m3



---

*Source: 6661119-2021-02-24.xml*