Quantitative evaluation of free gas and adsorbed gas content of Wufeng-Longmaxi shales in the Jiaoshiba area, Sichuan Basin, China

Gou, Qiyang; Xu, Shang

doi:10.26804/ager.2019.03.04

Cited by 56 publications

(29 citation statements)

References 22 publications

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“…Both organic matter and clay minerals in shale can adsorb methane [32,33]. Therefore, before using molecular simulation technology to study methane adsorption, molecular models of methane, illite, quartz, and kerogen were constructed based on different force fields.…”

Section: Establishment Of Modelmentioning

confidence: 99%

Molecular Simulation of Adsorption in Deep Marine Shale Gas Reservoirs

Chang¹,

Zhang²,

et al. 2022

Energies

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Deep marine shale gas reservoirs are extremely rich in the Sichuan basin in China. However, due to the in situ conditions with high temperature and high pressure (HTHP), in particular reservoir pressure being usually much higher than the test pressure, it is difficult to accurately clarify the adsorption behavior, as seepage theory plays an important role in shale gas reserves evaluation. Therefore, three kinds of sorbent, including illite, quartz and kerogen, and two simulation methods, containing the grand canonical ensemble Monte Carlo method and molecular dynamics method, are synthetically used to determine the methane adsorption behavior under HTHP. The results show that both absolute adsorption and excess adsorption decrease with the increase of temperature. When the pressure increases, the absolute adsorption increases quickly and then slowly, and the excess adsorption first increases and then decreases. The superposition of wall potential energy is strongest in a circular hole, second in a square hole, and weakest in a narrow slit. The effect of pore size increases with the decrease of the pore diameter. Under HTHP, multi-layer adsorption can occur in shale, but the timing and number of layers are related to the sorbent type.

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Section: Establishment Of Modelmentioning

confidence: 99%

Molecular Simulation of Adsorption in Deep Marine Shale Gas Reservoirs

Chang¹,

Zhang²,

et al. 2022

Energies

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“…At true "time zero", the adsorbed gas content is 1.77 m 3 /t rock, accounting for 30.1% of the total gas. Usually, the adsorbed gas content in Longmaxi Shale is 20-50% [52,53]. During the first six hours, the total gas content decreases dramatically due to the expansion of free gas.…”

Section: Free Gas Vs Adsorbed Gasmentioning

confidence: 99%

Numerical Simulation Based on the Canister Test for Shale Gas Content Calculation

Kang

Lu²,

Tian

et al. 2021

Energies

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The accurate determination of the gas in place in shale reservoirs is a basic but challenging issue for shale gas evaluation. Conventional canister gas desorption tests on retrieved core samples and subsequent data analyses (via linear or polynomial regression)—originally developed for coalbed methane, where gases are mainly stored in the adsorbed phase—is unadvisable for shale gas, which is stored as an appreciable amount of free gas in shale reservoirs. In the present study, a mathematical model that simultaneously takes into account gas expansion, adsorption/desorption, and the gas flow in shale is proposed to simulate gas release from a core sample retrieved from the Lower Silurian Longmaxi Formation of the Fuling shale gas field, Sichuan Basin. The results indicate that, compared with the value of 2.11 m3/t rock estimated with the traditional United States Bureau of Mines (USBM) method, the total gas in place within the studied Longmaxi Shale estimated with our mathematical model under reservoir pressure conditions is up to 5.88 m3/t rock, which is more consistent with the result from the new volumetric approach based on Ambrose et al. According to our mathematical model, the content of free gas is 4.11 m3/t rock at true “time zero”, which accounts for 69.9% of the total gas. On the other hand, the lost gas portion is determined to be up to 4.88 m3/t rock (~85% of the total gas). These results suggest that the majority of the free shale gas is actually trapped within the pore space of the shale formation.

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“…Adsorption is one of the important mechanisms of shale gas occurrence (Rexer et al, 2013(Rexer et al, , 2014Gasparik et al, 2014;Hu H. et al, 2018;Chen et al, 2019b;Gou and Xu, 2019). At present, the method for evaluating shale gas adsorption capacity is mainly through high-pressure methane adsorption experiments under dry condition, which do not account for the effect of water (Gasparik et al, 2012;Yang et al, 2015;Tian et al, 2016;Sander et al, 2018;Song et al, 2018;Gou et al, 2020;Shang et al, 2020).…”

Section: Implications For Shale Adsorbed Gas Content Evaluationmentioning

confidence: 99%

Effect of Pre-Adsorbed Water on Methane Adsorption Capacity in Shale-Gas Systems

Chen

Jiang

et al. 2021

Front. Earth Sci.

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The presence and content of water will certainly affect the gas adsorption capacity of shale and the evaluation of shale gas content. In order to reasonably evaluate the gas adsorption capacity of shale under actual reservoir conditions, the effect of water on methane adsorption capacity needs to be investigated. Taking the Da’anzhai Member of the Lower Jurassic Ziliujing Formation in the northeastern Sichuan Basin, China as an example, this study attempts to reveal the effect of pre-adsorbed water on methane adsorption capacity in shale-gas systems by conducting methane adsorption experiments in two sequences, firstly at different temperatures under dry condition and secondly at different relative humidity levels under the same temperature. The results show that temperature and relative humidity (i.e., water saturation) are the main factors affecting the methane adsorption capacity of shale for a single sample. The key findings of this study include: 1) Methane adsorption capacity of shale first increases then decreases with depth, reaching a peak at about 1,600–2,400 m. 2) Lower relative humidity correlates to greater maximum methane adsorption capacity and greater depth to reach the maximum methane adsorption capacity. 3) 20% increase of relative humidity results in roughly 10% reduction of maximum methane adsorption capacity. As a conclusion, methane adsorption capacity of shale is predominately affected by water saturation, pore type and pore size of shale. This study could provide a theoretical basis for the establishment of a reasonable evaluation method for shale adsorbed gas content.

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Quantitative evaluation of free gas and adsorbed gas content of Wufeng-Longmaxi shales in the Jiaoshiba area, Sichuan Basin, China

Cited by 56 publications

References 22 publications

Molecular Simulation of Adsorption in Deep Marine Shale Gas Reservoirs

Molecular Simulation of Adsorption in Deep Marine Shale Gas Reservoirs

Numerical Simulation Based on the Canister Test for Shale Gas Content Calculation

Effect of Pre-Adsorbed Water on Methane Adsorption Capacity in Shale-Gas Systems

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