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Strong overpressure conditions are widely distributed in the deep Longmaxi Formation (Fm) shale reservoirs in the Southern Sichuan Basin, with pressure coefficients ranging from 1.75 to 2.45. Overpressure plays a positive role in the high yield of shale gas, but a detailed study of its generation mechanism, evolution history, and potential impact on pore development is still lacking. This study's evidence from theoretical analysis and the logging response method indicates that hydrocarbon generation expansion is the main generation mechanism for strong overpressure. Through the combined analysis of basin modeling, inclusions analysis, and numerical simulation, pressure evolution at different stages is quantitatively characterized. The results show that, during the shale's long-term subsidence process, the shale reservoir's pressure coefficient increased to 1.40 because of oil generated by kerogen pyrolysis. Then it increased to 1.92 due to gas generated by residual oil cracking. During the late strong uplift process of the shale, temperature decrease, gas escape, and stratum denudation caused the pressure coefficient to first decrease to 1.84 and then increased to 2.04. Comparing pore characteristics under different pressure coefficients indicates that higher pressure coefficients within shale reservoirs contribute to the maintenance of total porosity and the development of organic macropores, but the influence on the morphology of organic pores is negligible. These results will provide the scientific basis for optimizing sweet spots and guiding shale gas exploration in the study area. [ABSTRACT FROM AUTHOR]

To evaluate the production performance of shale gas wells accurately, a quadruple-porosity medium model based on kerogen, the inorganic matrix, and natural-fracture–hydraulic-fracture network is proposed to simulate shale gas production. This model includes an apparent-kerogen permeability model to characterize the combined effects of gas slippage, Knudsen diffusion, surface diffusion, stress sensitivity, and matrix shrinkage. The fractal theory is used to characterize the non-equidistant distribution of secondary fractures in the hydraulic fracture network quantitatively. In addition, the effect of the stress sensitivity of the hydraulic fracture network on the production is considered, and a numerical method for the quadruple-porosity model is presented. After the validation of the model with field production data, the sensitivity parameters were analyzed to study the effects of the apparent kerogen permeability, Langmuir volume, fractal dimension, primary and secondary fracture conductivities, geomechanical effect, stimulated reservoir volume (SRV), and inorganic-matrix permeability on the gas production. This study provides a theoretical model for a more accurate evaluation of the shale gas production and improves the shale gas seepage theory. [ABSTRACT FROM AUTHOR]

The pore structure characterization and its controlling factors in overmature shales are keys to understand the shale gas accumulation mechanism. Organic matter in source rocks is a mixture of various macerals that have their own specific evolutionary pathways during thermal maturation. Pores within macerals also evolve following their own path. This study focused on petrographic characterization and maceral controls on porosity in overmature marine shales in China and the United States. Shale from Ordos Basin in China was also selected as an example of overmature transitional shale for maceral comparison. Organic petrology techniques were used to identify maceral types and describe morphological features in detail; scanning electron microscopy techniques were then used to document the abundance and development of pores within macerals. Helium measurement, mercury intrusion capillary pressure, and CO2 adsorption were especially applied to quantify the pore structure of Wufeng-Longmaxi shale from Sichuan Basin in China. The vitrinite reflectance equivalent of the studied overmature samples is ~2.4%. The macerals within the studied marine shales are composed mainly of pyrobitumen and zooclasts. At this maturity, pyrobitumen develops abundant gas-related pores, and their volume positively correlates to gas content. Three types of pyrobitumen and its related pore structure are characterized in Wufeng-Longmaxi shales. Zooclasts contribute to total organic carbon (TOC) content but little to porosity. When the TOC content is above 1.51% in Wufeng-Longmaxi samples, the TOC content positively correlates to quartz content. Organic matter strongly controls micropore development. Pores of diameter ~ 0.5 nm provide a significant amount of micropore volume. Clay mineral and quartz contents control micro- and macropore increments in organic-lean shales. MICP results indicate that pores within 3-12 nm and 900-2500 nm account for a major contribution to pore volume obtained. Determining the proportions of pyrobitumen to zooclasts within the total organic matter in pre-Devonian organic-rich marine shales is important in predicting porosity and gas storage capacity in high-maturity shales. [ABSTRACT FROM AUTHOR]

[Display omitted] • Taiyang, Jiaoshiba and Weirong shale gases show 12‰ variation in δ2H of methane. • Carbon isotopic reversal occurs in Taiyang, Jiaoshiba and Weirong shale gases. • Hydrogen isotopic reversal only occurs in Taiyang and Jiaoshiba shale gases. • Gas δ2H is greatly affected by water salinity, causing delay of isotope change. Sichuan Basin is important commercial shale gas producing basin in China, where shale gas explorations were mainly targeted at the Upper Ordovician Wufeng-Lower Silurian Longmaxi formations with burial depth mostly of 2000 ∼ 3500 m. This study performed a detailed investigation about the δ2H features of shale gases from the Wufeng-Longmaxi shale with burial depth of <2250 m (Taiyang), 2250 ∼ 3500 m (Jiaoshiba) and >3500 m (Weirong). The average δ2H 1 and δ2H 2 values are of −135‰ and −146‰, −137‰ and −157‰, −137‰ and −124‰, respectively in Taiyang, Jiaoshiba and Weirong shale gas fields. The average δ2H 1 values are nearly the same in the three gas fields, while average δ13C 1 values increase from −35.2‰ to −28.5‰ as from Weirong to Taiyang. When wetness >8%, δ2H 1 values increase with decreasing wetness rapidly implying dominant influences from maturity, when wetness <8%, the δ2H 1 variation is small and mainly in the range of (−140 ± 15)‰, indicating a strong influence from cogenetic water. All gases are characterized by a trend of δ13C 1 > δ13C 2 > δ13C 3 , and gases in Taiyang and Jiaoshiba are characterized by δ2H 1 > δ2H 2 , while gases in Weirong are dominated by δ2H 1 < δ2H 2. Generally, with decreasing gas wetness, ethane first become more enriched in D and 13C, then become more depleted in D and 13C, and finally become more enriched in D and 13C again. The turning point of wetness from rollover to post-rollover zones is 1.2% for the δ13C 2 while 0.8% for the δ2H 2. Such delay in δ2H 2 also indicates the strong influences from the cogenetic water medium. [ABSTRACT FROM AUTHOR]

Based on field work, organic geochemical analyses and experimental testing, a six-property assessment method for shale gas is proposed. These six properties include organic matter properies, lithofacies, petrophysical properties, gas content, brittleness and local stress field. Due to the features of continuous distribution over a large area and low resource abundance in shale plays, a sweet spot should have these following properties: (a) TOC>2%; (b) brittle minerals content (>40%) and clay minerals (<30%); (c) Ro (>1.1%); (d) porosity (>2%) and permeability (>0.000 1 mD), and (e) effective thickness (30-50 m). Applying these criteria in the Sichuan Basin, the Silurian Longmaxi shale consists of four prospecting sweet spots, including blocks of Changning, Weiyuan, Zhaotong and Fushun-Yongchuan. Although these four blocks have some similarities, different features were usually observed. After comprehensive analyses using the six-property assessment method, the Fushun-Yongan Block ranks the most favorable sweet spot, followed by the Weiyuan Block. For the other two blocks, the Changning Block is better than the Zhaotong Block. By comparing with the Mississippian Barnett shale, characteristics that are crucial for a high-yielding in the Sichuan Basin include a high content of organic matter (TOC>2.5%), a moderate thermal maturity ( Ro=0.4%-2%), a high content of brittle minerals (quartz: 30%-45%), a high gas content (>2.5 m·t), and types I and II kerogen. [ABSTRACT FROM AUTHOR]

Although the annual production of shale gas in China was 13 × 10 8 m 3 in 2014, a systematic study on geochemical and isotopic characteristics of these unconventional gases has not been well addressed. In the present study, almost all shale gas samples available in China, including marine shale gas from the Wufeng-Longmaxi Formation in the Sichuan Basin (O 3 w–S 1 l) and terrestrial shale gas from Chang 7 Member (T 3 y 7 ) in the Ordos Basin, were collected and analyzed for their geochemical and isotopic compositions. The shale gas from the Wufeng-Longmaxi Shale is dry gas with an average methane content of 98.38% and records a highest content of CH 4 in the world (99.59%), which is consistent with the very high thermal maturity levels of the gas shales that have equivalent vitrinite reflectance (EqVRo) values between 2.4 and 3.6%. The δ 13 C 1 values are correspondingly heavy and record a heaviest δ 13 C 1 values (−26.7‰) for the shale gases found in the world as well. The average values of δ 13 C 1 , δ 13 C 2 and δ 13 C 3 for the Wufeng-Longmaxi shale gas are −31.3‰, −35.6‰, and −47.2‰, respectively, displaying a complete carbon isotopic reversal (i.e., δ 13 C 1 > δ 13 C 2 > δ 13 C 3 ). δ 2 H CH4 and δ 2 H C2H6 has an average value of −148‰ and −173‰, respectively, also yielding a hydrogen isotopic reversal (i.e., δ 2 H CH4 > δ 2 H C2H6 ). The Chang 7 shale has an average TOC content of 13.81% with vitrinite reflectance (VRo) values between 0.7 and 1.2%. The Chang 7 shale gas is wet gas with an average methane content of 84.90% and is rich in heavy gaseous hydrocarbons (C 2 –C 5 ). The respective values of δ 13 C 1 , δ 13 C 2 and δ 13 C 3 are −48.7‰, −36.4‰ and −31.3‰, displaying a positive carbon isotopic distribution pattern (i.e., δ 13 C 1 < δ 13 C 2 < δ 13 C 3 ). The average δ 2 H CH4 , δ 2 H C2H6 and δ 2 H C3H8 values are −256‰, −244‰ and −188‰, respectively, and are characterized by a positive distribution pattern (i.e., δ 2 H CH4 < δ 2 H C2H6 < δ 2 H C3H8 ). The differences in gas wetness and carbon and hydrogen isotopic distribution patterns between the shale gases from the Wufeng-Longmaxi and Chang 7 shale are attributed to variations in thermal maturity levels. CO 2 is present in low content in both the Wufeng-Longmaxi and Chang 7 shale gases, mostly less than 1%. δ 13 C values for the CO 2 in the Wufeng-Longmaxi Formation are between 8.9 and −9.2‰, indicating an inorganic origin from the cracking of carbonate mineral in the shales under high temperatures. In contrast, δ 13 C values of the CO 2 in the Chang 7 shale gas range from −8.2 to −22.7‰, indicating an organic origin from the thermal degradation of organic matter. Helium in both the Wufeng-Longmaxi and Chang 7 shale gases is dominantly of curst origin in terms of their R/Ra ratios that vary from 0.01 to 0.08. Positive carbon isotopic distribution pattern is typical of primitive thermogenic gas. However, it can be converted into complete or partial carbon isotopic reversal patterns due to secondary alteration. The causes that yield carbon isotopic reversal include (1) mixing of gases with the same source but different thermal maturity levels; (2) secondary cracking of oil or wet gas; (3) formation water-involved reactions; (4) gas diffusion; and (5) carbon isotope exchange between alkane gases at high temperature. Among them, carbon isotopic exchange between alkane gases at high temperature is a key factor. Nine plots have been drawn based on the shale gases from China, USA and Canada. Among them, the plot of δ 13 C 2 versus wetness demonstrates a “lying-S” shape with two inflection points on the gas wetness axis. The wetness value of 1.4% represents a critical point from pyrolytic gas (primary cracking gas) to cracking gas (secondary cracking gas) and whereas the wetness value of 6% marks the end of oil generation. On the diagram of wetness versus δ 13 C, shale gases with wetness values greater than 1.6% are characterized by positive carbon isotopic distribution pattern, whereas a complete or partial carbon isotopic reversals are observed for shale gases with wetness values less than 1.6%. [ABSTRACT FROM AUTHOR]

The unique self-generation and self-storage characteristics of shale gas allow for its geochemical characteristics to better reflect the gas generation process inside the original rock under geological conditions. Based on a systematic analysis of 541 typical shale gas components and stable isotope compositions worldwide, this review provides an in-depth elucidation of the geochemical characteristics of Silurian shale gas in the Sichuan Basin, including an explanation of its special isotope anomalies. The over-mature Longmaxi Formation shale gas is dominated by alkane gas components (> 99%), which almost entirely (98.7%) consist of methane (CH 4). The distinctive characteristics of high CH 4 and low C 2+ contents result in extremely low wetness of <0.6%, which is typical of dry gas. In view of the sapropelic kerogen origin, the Longmaxi shale gas belongs to late-mature thermogenic gases (LMT). Geochemical anomalies of Longmaxi shale gas mainly refer to abnormally enriched δ13C 1 values and full reversal, resulting in deviations in carbon isotope composition and light hydrocarbon data for shale gas in the Changning-Zhaotong and Fuling areas, unlike the slightly less thermally evolved Weiyuan area. Noble gases of the Longmaxi shale gas exhibit characteristics of crustal origin and marine carbonate, and the light hydrocarbons in Longmaxi shale gas have been seriously cracked and destroyed, and the residual fraction is more reflective of its chemical stability. At extremely high maturity, the Rayleigh fractionation effect of ethane and the involvement of inorganic material in redox reactions are important causes of isotopic anomalies in Longmaxi shale gas. The variation of δ13C 1 and δ13C 2 values of shale gas in the producing area suggests that fluid-rock interactions related to CO 2 may have occurred, but not to a significant degree, and the cumulative effects of diffusion are similarly observed. The δ13C 2 values and magnitude (δ13C 1 − δ13C 2) of Weiyuan shale gas are negatively and positively correlated with daily production, respectively, which proves that the methane in shale gas mainly comes from ethane cracking during the over-maturation stage. By comparing with typical coal-derived gas, new discriminative trend lines in the reversal zone (δ13C 1 > δ13C 2) have a certain degree of credibility and applicability. Unraveling the geological processes that led to the formation of geochemical anomalies in the Longmaxi shale gas can provide valuable insights for in-depth analysis of the late-stage gas generation. • Geochemical characteristics of Longmaxi shale gas were compared and analyzed. • Potential pathways for rational explanation of geochemical anomalies were proposed. • New discriminative trend lines were drawn in the reversal zone (δ13C 1 > δ13C 2) to improve the genesis identification. [ABSTRACT FROM AUTHOR]