Evaluation of Marine Shale Gas Reservoir in Wufeng–Longmaxi Formation, Jiaoshiba Area, Eastern Sichuan Basin

Abstract

The Jiaoshiba area, as an important production capacity contribution block for the Fuling shale gas field, is of great significance for its long-term stable production. This study is based on continuous coring, and uses methods such as whole-rock mineral analysis, porosity and permeability analysis, gas content analysis, and organic geochemistry to systematically analyze the influencing factors of reservoir properties and gas content in the studied interval. Combined with the variation law of TOC and other parameters with depth, the target reservoir is comprehensively evaluated, and the evaluation results are verified based on actual production data. The results show that the influence of minerals on permeability is very weak, and cracks can greatly improve permeability, but their contribution to porosity is not significant. Porosity has a certain impact on gas content, but it is not the main controlling factor. The pores related to quartz (organic silicon) are mostly organic pores, which host a large amount of shale gas, while clay minerals are not conducive to the occurrence of shale gas. Organic matter (OM) maturity contributes more to porosity than OM abundance, but OM abundance has a stronger impact on gas content than its maturity. The research intervals can be divided into four categories: Class I (①–③) is the best, followed by Class II (⑦–⑨); Class III (④–⑥) is poor, and Class IV (top, non-gas-bearing layer) is the worst.

1. Introduction

The Fuling shale gas field (FLSGF), as the first commercial shale gas field in China, has important strategic significance for national energy security. Jiaoshiba, as the main gas-producing area, strongly supports the growth of shale gas production in China. Compared to the United States, the exploration and development of shale gas in China started later, with complex surface and stratigraphic structures, making exploration and development difficult. However, in recent years, China has experienced rapid development. In 2023, China’s shale gas production reached 25 billion cubic meters, and national shale gas demonstration zones have been established, such as Fuling, Changning–Weiyuan, and Zhaotong [1,2,3,4,5,6,7].

Although there are various methods for evaluating shale gas reservoirs, most of them use the “point to face” method to study. Specifically, limited samples are selected for relevant experimental analysis, including but not limited to thin section analysis, X-ray analysis, SEM (scanning electron microscopy) analysis, low-temperature nitrogen adsorption, high-pressure mercury intrusion, total organic carbon, chromatography–mass spectrometry, and so on [8,9,10,11,12]. This study selected a typical coring well in the Jiaoshiba area, and conducted continuous coring on the target layer (2330.46–2415.1 m) with intervals mostly less than 1 m. Various experimental methods were used to finely evaluate the Wufeng–Longmaxi Formation, providing reference for shale gas development in the Jiaoshiba area.

2. Geological Background

Most of China’s shale gas resources are concentrated in the Paleozoic marine shale reservoirs in the south, which have strong tectonic activity, complex geostress, deep burial, and harsh surface environments [13]. Jiaoshiba is located in Jiaoshi Town, Fuling District, Chongqing, in the eastern part of the Sichuan Basin. Its structural location spans two secondary structural units, with the main area being the Jiaoshiba fault anticline, including four local structures such as the Yanjiang saddle and the Wujiang No. 2 fault anticline. The faults mainly develop in the east and west wings of the structure and its southwest, while the faults in the main structural area are not developed [14,15,16]. The burial depth gradually increases from northeast to southwest, with a burial depth of less than 3000 m in the central and northern parts and a burial depth of more than 3000 m in some southern areas. The strata of the Wufeng–Longmaxi Formation, the subject of this study, can be vertically divided into sub-layers ①–⑨. Among them, sub-layers ①–③ represent the lower gas layer, sub-layers ④–⑥ represent the middle gas layer, and sub-layers ⑥–⑨ represent the upper gas layer. The three-dimensional development of the three layers has been comprehensively realized (Figure 1).

3. Samples and Experiments

This study focuses on the core well, and conducts continuous experimental analysis on sub-layers ①–⑨ of the target interval Wufeng–Longmaxi Formation, including total organic carbon analysis, whole-rock mineral analysis, gas content analysis, and physical property analysis.

The TOC analyzer used was the TA-1000 offline total organic carbon analyzer, with the specific experimental procedures as follows: solid cores were ground to 200 mesh, treated with 1 mol/L hydrochloric acid to remove inorganic carbon, washed to neutrality, dried, and then tested.

For whole-rock mineral analysis, a D8 Advance A25 X-ray diffractometer was used. The specific experimental steps were as follows: whole-rock samples are ground to 200 mesh and pressed into tablets; for clay mineral analysis, oriented slices (subjected to ethylene glycol saturation treatment) need to be prepared, followed by scanning and testing.

The porosity testing instrument is a modified helium porosimeter. Cores were processed into cylinders of 25 × 25 × 80 mm, their volume was calculated, then nitrogen was pressurized to equilibrium, and finally the porosity was calculated. The porosity measured in this study was effective porosity, and organic porosity was measured through low-temperature nitrogen adsorption in the experiment.

All experiments were completed at the Experimental Center of the Jianghan Oilfield Exploration and Development Research Institute, Sinopec (Wuhan, China).

4. Results

The TOC test results of 173 shale samples (2330.46–2415.1 m) show that the TOC ranges from 0.55% to 5.89%, mainly concentrated between 1% and 5%. The whole-rock mineral analysis of 87 shale samples shows that they contain quartz, clay minerals, potassium feldspar, plagioclase, calcite, dolomite, pyrite, and hematite, among which quartz and clay minerals have the highest content, ranging from 18.4 to 70.6% and from 16.6 to 62.8%, respectively. Plagioclase ranges from 1.9% to 11.9%, potassium feldspar ranges from 1% to 4.8%, dolomite ranges from 2.3% to 31.5%, calcite ranges from 2% to 11.8%, hematite ranges from 1.4 to 7.5%, and a small amount of samples also detected pyrite, with a content ranging from 1.4% to 7.5%. The physical property (porosity, permeability) tests of 159 samples show that the porosity ranges from 1.17% to 7.22%, and the permeability changes greatly, especially when microcracks and fractures exist, greatly improving the permeability. The overall permeability ranges from 0.0015 mD to 335.81 mD, with an average value of 24.81 mD. The permeability of the samples without cracks ranges from 0.0015 mD to 0.78 mD, with an average value of 0.094 mD; the permeability of samples containing microcracks ranges from 0.40 mD to 9.75 mD, with an average value of 3.56 mD; and the permeability of samples containing fractures ranges from 10.32 mD to 335.21 mD, with an average value of 107.10 mD. A total of 31 shale samples were subjected to on-site gas content experiments, and the results showed that the analytical temperature ranged from 62.3 °C to 64 °C, and the measured gas content ranged from 0.44 to 5.19 m³/t (Figure 2).

5. Discussion

5.1. Factors Affecting Reservoir Physical Properties

Shale reservoir physical properties include porosity and permeability; porosity is the ratio of pore volume to total volume, expressed as a fraction or percentage [16]. Ambrose et al. (2010) obtained reconstructed three-dimensional images using scanning electron microscopy and field emission ion microscopy and found that most of the pores were related to the kerogen network, indicating a close correlation between the pore development degree and the organic matter content [17]. In layers with better sorting (Wufeng Formation and the bottom of the Longmaxi Formation), there are small differences in particle size, uniform distribution of intergranular pores, and a high proportion of effective pore volume (porosity 4~6% [18]). In layers with poor sorting (the middle–upper part of the Longmaxi Formation), there is a mixture of coarse and fine particles, where fine particles fill the gaps between coarse particles, resulting in the blockage of intergranular pores and a decrease in porosity to 2~3% [18]. The permeability refers to the conductivity of the entire pore system (including fractures), especially the development of fractures, which can greatly enhance the permeability [18].

5.1.1. Mineral Composition

According to the properties of the minerals contained in the studied interval, they can be divided into two categories: brittle minerals and ductile minerals. Brittle minerals include quartz, feldspar, calcite, and dolomite, while ductile minerals are mainly clay minerals (with an average content of 37.78%). To eliminate the influence of crack development, all 35 samples selected did not contain cracks. The results show that the permeability ranges from 0.0016 to 0.75 mD, the porosity ranges from 2.63 to 6.43%, and the content of brittle minerals ranges from 33.9 to 80.3%, with an average value of 59.44%. According to Figure 3, it can be seen that neither brittle minerals nor clay minerals have an obvious correlation with each other. Overall, quartz has a relatively weak positive correlation with porosity, while clay minerals have a relatively weak negative correlation with porosity. This can be explained by the fact that brittle minerals such as quartz are more likely to form secondary pores, whereas clay minerals, with strong plasticity, tend to collapse and block pores. Additionally, porosity is more influenced by late diagenesis, thus resulting in such relatively weak correlations.

Feldspar and calcite show a positive correlation with permeability, indicating that feldspar and calcite are prone to forming microfractures, which in turn contribute to permeability but not to porosity (Figure 4). In contrast, clay minerals exhibit a weak positive correlation with permeability, which is a spurious correlation caused by the influence of feldspar and calcite. This phenomenon occurs when there is a strong positive correlation between clay content and feldspar content. This is consistent with previous studies, namely that permeability changes with variations in lithology [19]. Overall, the weak correlations suggest that the influence of mineral content on physical properties (porosity and permeability) is relatively weak.

5.1.2. Development of Cracks

The cracks on the core can be divided into microcracks and small cracks; microcracks are invisible to the naked eye but visible under the microscope, and small cracks are visible to the naked eye. The degree of crack development has little effect on porosity, but greatly increases the permeability. According to Figure 5, the permeability of samples with only developed pores ranges from 0.0015 to 0.7794 mD, and the porosity ranges from 1.17 to 7.22%; the permeability of samples with developed microcracks ranges from 0.3998 to 9.7485 mD, and the porosity ranges from 3.17 to 7.13%; and the permeability of samples with developed small cracks ranges from 10.32 mD to 355.20 mD, and the porosity ranges from 2.49% to 6.24%. Compared to cracks, the contribution of pores to permeability is basically negligible; similarly, compared to pores, the contribution of cracks to porosity can be largely ignored.

5.1.3. Organic Matter Abundance and Maturity

OM abundance refers to the OM content in shale, including various organic compounds such as hydrocarbons. This study characterizes the relative OM content based on total organic carbon (TOC), and uses vitrinite reflectance (Ro) to characterize the OM thermal evolution degree. By analyzing the correlation between TOC, Ro, and porosity separately (Figure 6), it can be seen that there is a certain positive correlation (R² = 1.95) between TOC and porosity, which fully demonstrates that the OM abundance is beneficial for shale pore development. Shale reservoirs are relatively dense with a large number of nanoscale pores (including organic and inorganic pores) developed. As the content of TOC increases, the development degree of organic pores increases, and their contribution to porosity increases, thus showing a positive correlation. Figure 6b shows a good positive correlation (R² = 0.49) between Ro and porosity, with a better correlation than the correlation between TOC and porosity, indicating that OM maturity contributes more to porosity than OM abundance. This can be explained by the fact that as maturity increases, the kerogen degradation not only generates organic pores, but also generates byproducts such as organic acids, which react with shale reservoirs and greatly increase porosity.

5.2. Factors Affecting Gas Content

There are many factors that affect the shale gas content, which can be divided into internal and external factors. The internal factors mainly include porosity, mineral composition, and organic geochemical characteristics (OM abundance and maturity), while the external factors mainly include tectonic movement, preservation conditions, etc. The sample quality for gas content testing ranges from 5.612 to 6.315 Kg, and the test results (including measured gas content, loss gas content, and residual gas content) range from 0.44 to 5.19 m³/t. This study explores the effects of porosity, mineral composition, and organic geochemical characteristics on its gas content, laying a foundation for the next reservoir evaluation.

5.2.1. Porosity

Pores are the main storage sites for shale gas, and porosity refers to the proportion of all pore volume, which is the basis for the shale gas occurrence and thus affects the gas content. Through the correlation analysis between porosity and gas content (Figure 7), it can be seen that gas content has an upward trend with the increase in porosity, and the correlation is relatively poor, indicating that porosity has a certain impact on gas content, but it is not the main controlling factor.

5.2.2. Mineral Composition

To investigate the influence of minerals on the gas content, this study conducted correlation analysis between various minerals (quartz, plagioclase, potassium feldspar, calcite, dolomite, and clay minerals) and gas content (Figure 8), and then obtained the relationship between each mineral and gas content. Among numerous minerals, only quartz and clay minerals show a good correlation, with quartz showing a significant positive correlation with gas content, while clay minerals show a significant negative correlation with gas content, and other minerals have no significant correlation. The so-called quartz in the Jiaoshiba area is actually organosilicon. In geology, organosilicon refers to naturally occurring organic compounds (or their derivatives) with silicon–carbon (Si-C) covalent bonds in their molecular structure. They are widely distributed in rocks, sediments, soils, oil and gas reservoir fluids, and pore water of geological bodies. A large number of organic pores developed in organosilicon can host a large amount of shale gas. The organosilicon in the shales of the Wufeng–Longmaxi Formation is mainly derived from siliceous biological remains, including siliceous shells of radiolarians, sponge spicules, diatoms, etc. [20,21]. During the sedimentary process, this biogenic silica exists in the form of opal-A (amorphous silica) and is later transformed into quartz through diagenesis [22]. Under the microscope, quartz with biological structures (such as radiolarian skeletal crystals) and cryptocrystalline–microcrystalline quartz aggregates without biological structures can be observed [20,21]. However, the adsorption capacity of clay minerals for shale gas is far inferior to that of organic matter, and it is easy to block the formed pores. Therefore, this correlation is presented, which also proves the widespread development of organic pores.

5.2.3. Organic Matter Abundance and Maturity

This study used correlation analysis to determine the impact of OM abundance and maturity on gas content (Figure 9). It can be seen that the OM maturity has a weak positive correlation with gas content, while the OM abundance has a strong positive correlation with gas content, indicating that the influence of OM abundance on gas content is stronger than its maturity. This can be explained by the fact that the studied interval maturity does not change significantly and are all in the mature stage, so their positive correlation is not particularly obvious. However, the OM abundance changes greatly, so there is a more obvious positive correlation.

5.3. Reservoir Comprehensive Evaluation

This study comprehensively evaluated the studied interval based on various factors such as TOC, porosity, permeability, brittle minerals, clay minerals, and gas content varying with depth (Figure 4), and established reservoir classification standards for the studied interval. The results showed that TOC, porosity, brittle minerals, and gas content showed a stepwise upward trend with depth, while vitrinite reflectance and permeability showed no significant changes. Overall, the lower (①–③) reservoir is superior to the upper (⑦–⑨) reservoir. Based on their changing trends, the studied interval can be divided into four categories: I, II, III, and IV. In Category I, TOC, porosity, and brittle mineral content are at high values, while clay mineral content shows a low value, with the highest gas content. In Category II, TOC and porosity are also at high values, but the brittle mineral content varies back and forth in the low-value range, the clay mineral content varies back and forth in the high-value range, and the gas content shows low values. In Category III, TOC and porosity are at lower values, while the brittle minerals and clay minerals are stable at higher values, and the gas content is at a lower value (only one point has abnormally high gas content). In Category IV, TOC, porosity and brittle mineral are at low values, while clay mineral content is at high values, and gas content is at low values. Category I can be further divided into two sub-classes, Ia and Ib. Ia is the highest-quality reservoir, followed by Ib. Overall, the lower (①–③) gas layer in the studied interval is the best, followed by the upper (⑦–⑨) gas layer, and the middle (④–⑥) gas layer is the worst.

To further verify the rationality of the reservoir classification evaluation criteria proposed in this article, the accumulated gas production from a large number of development wells in the studied area was systematically analyzed. The studied interval can be divided into ①–⑨ small layers from top to bottom, with the small layers ①, ②, and ③ being the lower gas layer, the small layers ④ and ⑤ the middle gas layer, and the small layers ⑦, ⑧, and ⑨ the upper gas layer. This study analyzed a large number of adjustment wells in the studied area, including the upper gas reservoir wells, the middle gas reservoir wells, and in the lower gas reservoir wells, all of which have been in operation for the past 5 years. The results show that the accumulated gas production of the upper gas layer is 0.03–131 million cubic meters, with an average value of 45 million cubic meters; the accumulated gas production of the middle gas layer is 0.15–18 million cubic meters, with an average of 14 million cubic meters; and the accumulated gas production of the lower gas layer is 0.41–171 million cubic meters, with an average of 66 million cubic meters (

Table 1. The accumulated gas production analysis.

	Accumulated Gas Production (Million Cubic Meters)
	Maximum	Minimum	Average
Upper gas layer (⑦–⑨)	131	0.03	45
Middle gas layer (④–⑥)	86	0.15	14
Lower gas layer (①–③)	171	0.41	66

).

This result indicates that the lower gas layer is the best, followed by the upper gas layer, and the middle gas layer is the worst, further verifying the reservoir classification and evaluation criteria proposed in this article. This further demonstrates the applicability of the reservoir classification and evaluation method, providing reference for the shale gas development in new areas and even the Sichuan Basin in the next step.

6. Conclusions

The influence of minerals on permeability is very weak, and cracks can greatly increase permeability, but their contribution to porosity is not significant. As the maturity increases, the kerogen degradation produces organic pores, and the byproducts of hydrocarbon generation (organic acids, etc.) that react with shale reservoirs, greatly increasing porosity. OM maturity contributes more to porosity than its abundance. Porosity has a certain influence on gas content, but it is not the main controlling factor. The mineral pores that host shale gas are mostly related to quartz, while clay minerals are not conducive to shale gas occurrence and have a negative impact on the pores formed by minerals such as quartz. OM abundance has a stronger impact on gas content than its maturity.

Overall, the lower reservoir (①–③) is superior to the upper (⑦–⑨) reservoir. Based on their changing trends, the studied interval can be divided into four categories: I, II, III, and IV. In Category I, TOC, porosity, and brittle mineral content are at high values, while clay mineral content is at low values, with the highest gas content. In Category II, TOC and porosity are also at high values, but the brittle mineral content varies back and forth in the low value range, the clay mineral content varies back and forth in the high value range, and the gas content is at low values. In Category III, TOC and porosity are at lower values, while the brittle minerals and clay minerals are stable at higher values, and the gas content is at a lower value (only one point has abnormally high gas content). In Category IV, TOC, porosity, and brittle mineral are at low values, while clay mineral content is at high values, and gas content is at low values. Category I can be further divided into two sub-classes, Ia and Ib. Ia is the highest-quality reservoir, followed by Ib. Overall, the lower (①–③) gas layer in the studied interval is the best, followed by the upper (⑦–⑨) gas layer, and the middle (④–⑥) gas layer is the worst.