Lower limit of thermal maturity for the carbonization of organic matter in marine shale and its exploration risk

Wang, Yuman; Li, Xinjing; Chen, Bo; Wu, Wei; Dong, Dazhong; Zhang, Jian; Han, Jianfa; Ma, Jie; Dai, Bing; Wang, Hao; Jiang, Shan

doi:10.1016/s1876-3804(18)30045-4

Cited by 49 publications

(31 citation statements)

References 20 publications

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“…The high maturity of the Lower Cambrian shales is closely related to their old age, large burial depth, and multiple thermal events [79]. According to shale gas data in the United States, shale gas reservoirs can also develop under high overmaturity conditions [80,81], but the maturity of shale with commercial potential is generally limited within the EqVRo < 3:5% [75,82].…”

Section: Geochemical and Gas-bearingmentioning

confidence: 99%

“…At the overmatured stage, original and secondary organic pores might be collapsed, shrunk, and compacted due to the escape of a large amount of hydrocarbon gas from organic pores, resulting in a large reduction of organic porosity [22,47]. Other studies suggested that such a reduction might be related to the carbonization caused from strong condensation of aromatic structure of OM [82,96,145,148,154]. For example, Wang et al [82] found that the porosity and resistivity of the Qiongzhusi and Longmaxi Formation shales in the Sichuan Basin displayed a sudden drop at the EqVRo > 3:5%, and they believed that the OM carbonization might destroy organic pore structure of shales.…”

Section: Factors Controlling Porosity and Gas Content Of The Lower Ca...mentioning

confidence: 99%

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Lower Cambrian Organic-Rich Shales in Southern China: A Review of Gas-Bearing Property, Pore Structure, and Their Controlling Factors

Gao

Xiao

et al. 2022

Geofluids

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The Lower Cambrian shales are widely developed in southern China, with greater thicknesses and higher TOC contents. Although the shale gas resource potential has been suggested to be huge, the shale gas exploration and development is not satisfactory. At present, the gas-bearing property evaluation of the Lower Cambrian shale is still a hot spot of concern. According to previous works, this paper systematically summarizes the gas-bearing characteristics and controlling factors of the Lower Cambrian shales in southern China. The buried depth of Lower Cambrian shales mainly ranges from 3000 m to 6000 m, and the thickness of organic-rich shale intervals ( TOC > 2 % ) varies from 20 m to 300 m. The TOC content and EqVRo value are generally up to 2%-10% and 2.5%-6.0%, respectively. The gas content of the Lower Cambrian shales in the Weiyuan-Qianwei block of the Sichuan Basin and the western Hubei area generally exceeds 2 m3/t, and gas composition is dominated by CH4. In southeastern Chongqing, northwestern Hunan, and northern Guizhou areas, the gas content of the Lower Cambrian shales is generally <2 m3/t, and the N2 content is generally >60%. In the Lower Yangtze region, the Lower Cambrian shale reservoirs basically contain no gas. Higher maturity, lower porosity, and less-no organic pores are suggested to be responsible for low gas contents and/or the predominate of N2 in shale gas reservoirs. Strong tectonic deformation is an important factor leading to the massive gas loss from shale reservoirs, thus resulting in no gas or only a small amount of N2 in the Lower Cambrian shales. In a word, the Lower Cambrian shale gas plays with low maturity and relatively stable tectonic condition, especially deep-ultradeep zones, may be the favorable targets for shale gas exploration.

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Section: Geochemical and Gas-bearingmentioning

confidence: 99%

Section: Factors Controlling Porosity and Gas Content Of The Lower Ca...mentioning

confidence: 99%

Lower Cambrian Organic-Rich Shales in Southern China: A Review of Gas-Bearing Property, Pore Structure, and Their Controlling Factors

Gao

Xiao

et al. 2022

Geofluids

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“…Currently, the most successful shale gas development is mainly in marine facies shales, such as the Longmaxi formation shale in South China [8,21,30,34], the Marcellus shale [8,21,30,34,36,37], and the Barnett shale in the US [38]. The organic matter type of marine shales is type I or type II [39][40][41]. Additionally, research on shale gas reservoirs has mainly focused on organic shale with type I or type II kerogen [42][43][44].…”

Section: Introductionmentioning

confidence: 99%

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

et al. 2020

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This study focuses on the nanostructure of shale samples with type III kerogen and its effect on methane adsorption capacity. The composition, pore size distribution, and methane adsorption capacities of 12 shale samples were analyzed by using the high-pressure mercury injection experiment, low-temperature N2/CO2 adsorption experiments, and the isothermal methane adsorption experiment. The results show that the total organic carbon (TOC) content of the 12 shale samples ranges from 0.70% to ~35.84%. In shales with type III kerogen, clay minerals and organic matter tend to be deposited simultaneously. When the TOC content is higher than 10%, the clay minerals in these shale samples contribute more than 70% of the total inorganic matter. The CO2 adsorption experimental results show that micropores in shales with type III kerogen are mainly formed in organic matter. However, mesopores and macropores are significantly affected by the contents of clay minerals and quartz. The methane isothermal capacity experimental results show that the Langmuir volume, indicating the maximum methane adsorption capacity, of all the shale samples is between 0.78 cm3/g and 9.26 cm3/g. Moreover, methane is mainly adsorbed in micropores and developed in organic matter, whereas the influence of mesopores and macropores on the methane adsorption capacity of shale with type III kerogen is small. At different stages, the influencing factors of methane adsorption capacity are different. When the TOC content is <1.4% or >4.5%, the methane adsorption capacity is positively correlated with the TOC content. When the TOC content is in the range of 1.4–4.5%, clay minerals have obviously positive effects on the methane adsorption capacity.

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“…In view of this phenomenon, two main controlling factors were proposed. One is that the low resistance is caused by the high conductivity mineral graphite produced by high evolution (Wang et al, 2018;Zhao et al, 2018), and the other is that the low resistance is mainly caused by inlaid close contact between particles due to diagenesis, resulting in lower gas saturation, increased water saturation, and increased mineralization within the shale to enhance conductivity (Gao et al, 2016;Liang et al, 2021).…”

Section: Impact Of Fluid Activity On Resistivitymentioning

confidence: 99%

“…However, the influencing factors vary in different regions and reservoirs. Most researchers believe that the "carbonization" of organic matter is the main cause of the phenomenon of low resistivity in the Changning region (Wang et al, 2014;Wang et al, 2018;Hou et al, 2021), but some researchers still hold different views and believe that the mosaic of rock particles in close contact with each other is the main cause (Gao et al, 2016). The above studies are mostly based on the properties of the reservoir rock itself.…”

Section: Introductionmentioning

confidence: 99%

Multi-Phases Fluid Activity Characteristics of Longmaxi Formation and Its Impact on Resistivity in the Changning Area, Southern Sichuan Basin, Southwest China

Cui

Li²,

Han³

et al. 2022

Front. Earth Sci.

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Wells with low gas content and low resistivity in the Changning area, southern Sichuan Basin were selected for this study. The burial-thermal history was reconstructed and the characteristics of multi-phase fluid activity were clarified using microscopic observation and testing of fluid inclusions in the Longmaxi shale fracture veins. Compared with wells with a high gas content and high resistivity, the influence of fluid activity on resistivity was analyzed. The results showed that the thermal evolution of the bituminous inclusions trapped in the veins has reached the stage of carbonaceous-metamorphic bitumen, and the organic matter is fully cracked for gas generation, with some organic matter exhibiting the phenomenon of “graphitization.” The synchronous fluid with bitumen was existed due to shallow burial with a middle-low maturity stage of about 280 and 292 Ma. Two phases of fluids existed in the deep burial stage, thus maturing for about 103 Ma, and the uplift stage at about 28 and 32 Ma, with high homogenization temperatures (Th) (varying from 185 to 195°C and 165–180°C). The corresponding pressure coefficients varied between 1.67 and 2.09, 1.56 and 1.92 in a moderate-strong high-pressure state. The last two phases of fluid formation in the late uplift stage for about 4 to 19 Ma and 6 to 10 Ma were characterized by low salinity at medium-low Th (varied from 140 to 155°C and 120–135°C), with pressures of 57.47–74.50 MPa and 51.44–59.41 MPa (pressure coefficients of 1.09–1.41 and 1.18–1.37), in an atmospheric-weak overpressure state. In the initial uplift stage after deep burial, the fluid closure in the Changning area was good. In contrast, the wells are filled with low gas content because of the strong tectonic forces causing the shale gas to be released and the multi-phase fluid activity that happens during the late uplift stage. New evidence indicates that the emergence of low resistance in the localized Changning area is not only related to the high degree of evolution of organic matter but is also affected by the multi-phase fluid modification in the late uplift stage.

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Lower limit of thermal maturity for the carbonization of organic matter in marine shale and its exploration risk

Cited by 49 publications

References 20 publications

Lower Cambrian Organic-Rich Shales in Southern China: A Review of Gas-Bearing Property, Pore Structure, and Their Controlling Factors

Lower Cambrian Organic-Rich Shales in Southern China: A Review of Gas-Bearing Property, Pore Structure, and Their Controlling Factors

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

Multi-Phases Fluid Activity Characteristics of Longmaxi Formation and Its Impact on Resistivity in the Changning Area, Southern Sichuan Basin, Southwest China

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