Shale characteristics and shale-gas potentials in the Lower Devonian Tangding Formation in the Tian'e area of the Nanpanjiang Basin, SW China

The Upper Permian Linghao Formation shale is the most potential shale gas exploration target in Nanpanjiang Basin. In this study, X-ray diffraction, field emission scanning electron microscopy, CH4 isothermal adsorption, and nuclear magnetic resonance cryoporometry are intergrated to reveal comprehensive characterization of Linghao Formation shale collected from a well in Nanpanjiang Basin. Results indicate that organic-rich shales developed in the Ling 1 member and the lower part of Ling 3 member. The organic-rich shales are predominantly characterized by kerogen type I, with a relatively highly mature to overmature status. The Ling 1 organic-rich shale mainly consists of mixed shale lithofacies, and the organic-rich shale in the lower part of Ling 3 is mainly composed of argillaceous shale. The pore volume in Ling 1 organic-rich shale is mainly contributed by 3- to 6-nm and 8- to 11-nm organic pores. The pore volume of Ling 3 organic-rich shale is mainly contributed by 2- to 3-nm and 4- to 11-nm organic pores. The organic pores between 3 and 10 nm also have a small contribution to the pore volume. The absolute adsorption gas content of Ling 1 and Ling 3 organic-rich shale is 1.21 m3/t and 1.64 m3/t, respectively. The absolute adsorption gas content of Ling 1 and Ling 3 organic-rich shale exceeds the minimum standard for commercial shale gas development in China (1.0 m3/t). According to the adsorption gas ratio of 50%, the total gas content of Ling 1 and Ling 3 organic-rich shale can reach 3.28 m3/t and 2.28 m3/t, respectively. It is suggested that the Upper Permian Linghao Formation shale in the Nanpanjiang Basin has a significant potential for shale gas exploration.

Key geological issues and main controls on accumulation and enrichment of Chinese shale gas

Great progress has been made in marine shale gas of Wufeng–Longmaxi formations in the Sichuan Basin. However, shale gas exploration in the complex structural belt around the Sichuan Basin still faces great challenges. In this study, shales of Wufeng–Longmaxi formations collected from the northern Guizhou were taken as the studied target, organic matter (OM) characteristics, mineral composition, pore structure, methane adsorption capacity and in situ desorption gas content were measured, and the controlling factors of shale gas content were further discussed. The results indicated that the sedimentary facies of Wufeng–Longmaxi formations in north Guizhou varies from shallow‐water shelf facies to deep‐water shelf facies from south to north, and organic‐rich shales are primarily distributed in Daozhen‐Xishui areas, with a maximum thickness of about 80–100 m. Organic‐rich shales are characterized by high total organic carbon (TOC) content, high thermal maturation and type I–II1 kerogens, which can be comparable with those in commercially produced shale gas field in Sichuan Basin. High‐quality shale gas reservoirs generally have a high content of brittle minerals, making them easier to be fractured. OM pores are the dominanted pore type in the studied shales, followed by intergranular pores associated with brittle minerals, dissolution pores within carbonate grains and microcracks, while clay mineral‐related pores are poorly developed. The Wufeng–Longmaxi Formation shales generally have strong methane adsorption capacities, but these vary greatly across different areas. Shale gas adsorption capacity is primarily controlled by TOC content and thermal maturation level. Similarly, total gas content, including desorption gas and lost gas, varies greatly in different areas, and it is obviously lower than that in Fuling and Luzhou shale gas field, due to the loss of shale gas and low‐pressure coefficient in the complex structural zone. It is worth explaining that shale gas is not always low in northern Guizhou, which is determined by burial depth and the distance of great fractures. Shale gas content is relatively high in LY1 well and DY1 well in Xishui‐Daozhen area, and it is extremely low in TY1 well and AY1 well in Tongzi‐Zheng'an area. Shale gas content in the same structural unit is primarily influenced by TOC content, OM pore development degree and water saturation. However, different structural units have different shale gas contents, due to the differences in preservation conditions. Shale reservoirs with good preservation conditions, that is, wide and gentle structure, far from a large fault and great burial depth, generally have high shale gas contents.

Gas content is one of the most important parameters of shale reservoir evaluation and productivity evaluation. In order to obtain gas content accurately, based on the first law of Fick and material balance equation, mathematical model of gas dispersion flow in shale reservoir is established, analytical solution is obtained, and evaluation method of gas dispersion in shale reservoir is formed. On the basis of this study, the onsite desorption gas measuring device and testing process for coring shale gas wells are designed, the time-varying shale desorption gas is obtained, and the residual gas of shale is measured by the crushing method. The calculation formula of shale gas content is obtained by fitting the test data, the shale gas loss, and total gas content are calculated, and then analyzed the influences of the shale gas-bearing properties and gas content on single well production and geological reserves by combining the data of shale absorbed gas. The results show that the gas content calculated by the new method is about 6.54% more than that of log interpretation, and about 7.57% on average more than that obtained by traditional empirical method. The gas content proportion of long Yi1 subsegmental small layers 1 and 2 is smaller than that of long Yi1 subsegmental small layers 3 and 4 and long Yi2 subsegmental. It is considered that the amount of shale gas lost is large, because of the pressure release during the coring, and the comparative error of gas content obtained by several methods is within the acceptable range. So the new method can be used as an important mean to obtain shale gas content. The most direct factors affecting gas content are complex: Buried depth, porosity, total organic carbon content, water saturation, and formation temperature. Shale gas content is the material basis of single well production and geological reserves of shale gas, and it is also the decisive factor. Therefore, the accurate evaluation of shale gas content is one of the key techniques to evaluate shale gas well productivity and shale gas resources, which is of great significance.

Mechanisms of shale gas generation and accumulation in the Ordovician Wufeng-Longmaxi Formation, Sichuan Basin, SW China

Source and seal coupling mechanism for shale gas enrichment in upper Ordovician Wufeng Formation - Lower Silurian Longmaxi Formation in Sichuan Basin and its periphery

There has been great success of marine shale gas exploration and production from Lower Silurian Longmaxi Formation (called Longmaxi shale) in Sichuan Basin, China, while whether commercial gas production could be obtained from lacustrine shales is still a question. The 7th Member of Triassic Yanchang Formation (called Chang 7 shale), which is the exploration target for the only national lacustrine shales gas pilot, was investigated to identify the key issues on the accumulation and development of terrestrial shale gas accumulation. It is considered that there are many differences in terrestrial and marine shales including depositional environment and provenance, distribution characteristics, organic matter types, mineral composition, and pore types. So evaluation standards of the two shales should not be the same. The Longmaxi shale was deposited in deep shelf, widely distributed, stable, mature–overmature (in gas window), presence of plenty micro-pores, brittle, and overpressured, which make it a good condition for shale gas accumulation. The key factors that affect the production of the Longmaxi shale concluded that the shale is rich in organic matter, high thermal evolution, brittle, and overpressured. The Chang 7 shale in Ordos Basin was deposited in deep lake, relative limited distribution, in low stage of thermal evolution (in oil window), high clay mineral content, and conducive to shale gas adsorption. On the basis of comparing the geological features of the two shales, it is found that the shale is richer in the organic matter content than in the Longmaxi shale, while the shale is not mature enough to produce more gas, and the strata pressure is relatively lower which means the shale gas was not preserved very well either. So through this study, it is believed that the shale gas formation condition in the Chang 7 shale may not be as good as in the Longmaxi shale, the absorbed gas may be the future of this shale, and the shale oil should be the focus of petroleum exploration and development in this region.

Shale gas enrichment model and exploration implications in the mountainous complex structural area along the southwestern margin of the Sichuan Basin: A new shale gas area

Breakthrough of shallow shale gas exploration in Taiyang anticline area and its significance for resource development in Zhaotong, Yunnan Province, China

Deep marine shale is the primary carrier of shale gas resources in Southwestern China. Because the occurrence and gas content of methane vary with burial conditions, understanding the microscopic mechanism of methane occurrence in deep marine shale is critical for effective shale gas exploitation. The temperature and pressure conditions in deep shale exceed the operating limits of experimental equipment; thus, few studies have discussed the microscopic occurrence mechanism of shale gas in deep marine shale. This study applies molecular simulation technology to reveal the methane’s microscopic occurrence mechanism, particularly the main controlling factor of adsorbed methane in deep marine shale. Two types of simulation models are also proposed. The Grand Canonical Monte Carlo (GCMC) method is used to simulate the adsorption behavior of methane molecules in these two models. The results indicate that the isosteric adsorption heat of methane in both models is below 42 kJ/mol, suggesting that methane adsorption in deep shale is physical adsorption. Adsorbed methane concentrates on the pore wall surface and forms a double-layer adsorption. Furthermore, adsorbed methane can transition to single-layer adsorption if the pore size is less than 1.6 nm. The total adsorption capacity increases with rising pressure, although the growth rate decreases. Excess adsorption capacity is highly sensitive to pressure and can become negative at high pressures. Methane adsorption capacity is determined by pore size and adsorption potential, while accommodation space and adsorption potential are influenced by pore size and mineral type. Under deep marine shale reservoir burial conditions, with burial depth deepening, the effect of temperature on shale gas occurrence is weaker than pressure. Higher temperatures inhibit shale gas occurrence, and high pressure enhances shale gas preservation. Smaller pores facilitate the occurrence of adsorbed methane, and larger pores have larger total methane adsorption capacity. Deep marine shale with high formation pressure and high clay mineral content is conducive to the microscopic accumulation of shale gas in deep marine shale reservoirs. This study discusses the microscopic occurrence state of deep marine shale gas and provides a reference for the exploration and development of deep shale gas.

Shale gas accumulates in reservoirs that have favorable characteristics and associated organic geochemistry. The Wufeng-Longmaxi formation of Well Yucan-6 in Southeast Chongqing, SW China was used as a representative example to analyze the organic geochemical and reservoir characteristics of various shale intervals. Total organic carbon (TOC), vitrinite reflectance (Ro), rock pyrolysis, scanning electron microscopy (SEM), and nitrogen adsorption analyses were conducted, and a vertical coupling variation law was established. Results showed the following: the Wufeng-Longmaxi formation shale contains kerogen types I and II2; the average TOC value at the bottom of the formation is 3.04% (and the average value overall is 0.78%); the average Ro value is 1.94%; the organic matter is in a post mature thermal evolutionary stage; the shale minerals are mainly quartz and clay; and the pores are mainly intergranular, intragranular dissolved pores, organic matter pores and micro fractures. In addition, the average specific surface area (BET) of the shale is 5.171 m2/g; micropores account for 4.46% of the total volume; the specific surface area reaches 14.6%; and mesopores and macropores are the main pore spaces. There is a positive correlation between TOC and the quartz content of Wufeng-Longmaxi shale, and porosity is positively correlated with the clay mineral content. It is known that organic pores and the specific area develop more favorably when the clay mineral content is higher because the adsorption capacity is enhanced. In addition, as shale with a high clay mineral content and high TOC content promotes the formation of a large number of nanopores, it has a strong adsorption capacity. Therefore, the most favorable interval for shale gas exploration and development in this well is the shale that has a high TOC content, high clay mineral content, and a suitable quartz content. The findings of this study can help to better identify shale reservoirs and predict the sweet point in shale gas exploration and development.

The molecular and isotopic compositions of shale gases exhibit substantial differences under different storage conditions. Gas geochemistry is widely used when evaluating gas accumulation and expulsion in petroleum systems. Gas geochemical characteristics can provide important references for determining the enrichment mechanism of shale gas reservoirs and predicting shale gas production capacity in different regions. In tectonically stable regions with similar reservoir formation and evolution histories, shale gas reservoirs are expected to exhibit favorable storage conditions with only relatively small variations in gas geochemical characteristics. In tectonically active regions, shale gas preservation conditions are expected to be more variable. In this study, we systematically analyzed the stable isotope signatures (δ13C and δD) of alkane gases (CH4, C2H6, and C3H8), along with noble gas compositions and isotopic signatures, of normally pressured Wufeng‒Longmaxi marine shale gas samples comprising a continuous pressure coefficient series from a structurally active region at the transition between an orogenic belt and the southeastern (SE) Sichuan Basin, China. The relationships between noble gas contents, isotopic signatures, and shale gas yields were evaluated, and a mechanism for normally pressured shale gas accumulation and expulsion was presented. The δ13C and δD data suggest that the normally pressured shale gas originated from late-mature thermogenic generation, equivalent to shale gas from other production areas in the inner Sichuan Basin. Gas dryness ratios [C1/(C2 + C3)] exhibit negative relationships with δ13C1 and δ13C2. Normally pressured shale gas yields exhibit a negative correlation with δ13C and a positive correlation with [C1/(C2 + C3)], suggesting differences in shale gas accumulation and expulsion across the studied region related to changes in the pressure coefficient. Noble gas isotope data suggest that the normally pressured Longmaxi shale gas received a substantial contribution of crust-derived He. Coupling noble gas and stable C/H isotope data reveals that the abundance of He and Ar, along with the δ13C signatures of alkane gases, is affected by the abundance of shale gas during the accumulation and expulsion process. The noble gas and stable isotope distribution trends presented herein can be used to evaluate Wufeng‒Longmaxi’s normally pressured shale gas accumulation and expulsion in complex structural areas of the southeastern Sichuan Basin. Better preservation conditions accompanying lower tectonic activity will normally result in higher shale gas production and a lower concentration of noble gases. The above findings show that gas geochemical characteristics could be used as effective evaluation indicators for determining shale gas accumulation mechanisms in tectonically active regions.

Shale gas accumulation patterns in China

Gas-bearing property of the Lower Cambrian Niutitang Formation shale and its influencing factors: A case study from the Cengong block, northern Guizhou Province, South China

Analysis of Lower Cambrian shale gas composition, source and accumulation pattern in different tectonic backgrounds: A case study of Weiyuan Block in the Upper Yangtze region and Xiuwu Basin in the Lower Yangtze region