Competitive adsorption of methane and ethane on organic-rich shale at pressure up to 30 MPa: Experimental results and geological implications

Li, Jing; Li, Pengpeng; Zhou, Shixin; Sun, Zexiang; Meng, Bingkun; Li, Yaoyu

doi:10.1016/j.cej.2022.136617

Cited by 12 publications

(12 citation statements)

References 62 publications

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“…They also report that excess isotherms for methane show little or no increase at pressure above about 15 MPa, CO 2 sorption shows significant decline above about 13 MPa, and ethane shows large declines in excess sorption at pressures above about 8 MPa, this behavior is very much alike the results for our three LBS samples (Figure 1). Similar excess isotherm behaviors for methane and ethane at 60 °C were also reported for a Yanchang Shale by Li et al 33 Two studies have reported isotherms using CO 2 , methane, ethane, and propane for an organic-rich (53 wt % TOC) Kimmeridge Blackstone and a relatively low organic shale (3.65 wt % TOC) from the Vaca Muerta Formation in Argentina at temperatures of 60, 90, and 120 °C, though only at pressures much below those present in the BPS (15 MPa for CO 2 , methane, and ethane, but only up to 3 MPa for propane). 30,31 Similar to the results from the multi-laboratory study 28 and our results shown in Figure 1 for the BPS LBS rocks, both studies reported little or no drop in the excess sorption for methane at higher pressures, while CO 2 begins to show declines between 10 and 15 MPa, and ethane generally shows significant declines in excess sorption at pressures above about 8 MPa.…”

Section: Resultssupporting

confidence: 85%

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Measured Sorption Isotherms for Bakken Petroleum System Shales Using Carbon Dioxide and Produced Gas Hydrocarbons at 110 °C and Pressures up to 34.5 MPa

et al. 2023

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Sorption isotherms were measured for organic-rich Lower Bakken Shale (LBS) samples from low-, mid-, and high-thermal maturity zones of the Bakken Petroleum System (BPS) using hydrocarbon gases and CO2 at reservoir temperature and pressures. Molar sorption was strongest for CO2 and propane (averaging 0.28 mmol/g gross rock for both gases at 34.5 MPa), followed by ethane (0.24 mmol/g), produced gas (0.20 mmol/g), and methane (0.17 mmol/g). Propane and ethane had the strongest sorption at low pressures (lowest Langmuir pressure, P L), followed by produced gas, CO2, and methane. All of the hydrocarbon gases showed good conformance with the Langmuir isotherm, but CO2 showed significantly lower sorption than the Langmuir isotherm at pressures above 15–20 MPa. Contrary to the expectations that the organic content would control sorption, all five gases showed the highest sorption on a total organic carbon (TOC) basis (mg or mmol gas/g TOC) for the LBS sample with the lowest TOC (4.5 wt %) and the lowest sorption on a TOC basis for the sample with the highest TOC (20.4 wt %). Sorption from a laboratory gas mixture representing field produced gas highly favored ethane and (especially) propane over methane and an average of 48.1 mol % of the sorbed gas was propane, 39.1 mol % was ethane, and only 12.8 mol % was methane, in contrast to the average molar composition of the produced gas mixture of 69.6 mol % (methane), 20.7 mol % (ethane), and only 9.7 mol % (propane). A comparison of previous reports of the five gases’ potential effectiveness for enhanced oil recovery based on minimum miscibility pressure, ability to swell and dissolve crude oil, and ability to recover oil hydrocarbons from rock samples against the isotherm results showed a trend that propane was usually the most effective gas, followed by ethane, CO2, and produced gas, with methane being the least effective gas at mobilizing crude oil as well as having the lowest molar sorption.

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Section: Resultssupporting

confidence: 85%

“…The extended Langmuir calculation for mixed gases was used to determine the concentrations of sorbed methane, ethane, and propane for the produced gas isotherms, as described by Li et al 33 = +…”

Section: Sorbed Gas Composition For the Produced Gas Isothermsmentioning

confidence: 99%

Measured Sorption Isotherms for Bakken Petroleum System Shales Using Carbon Dioxide and Produced Gas Hydrocarbons at 110 °C and Pressures up to 34.5 MPa

et al. 2023

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“…Given that it is directly related to gas storage and flow in shale, the nanopore feature is crucial for determining the potential and recovery of shale gas. − Plentiful papers have been published referring to the nanoporosity of shales globally and its affecting factors (e.g., refs − ). Organic matter (OM) and clay minerals are reported to be the two main carriers of nanopores in shale. − OM type and thermal maturity significantly affect OM-hosted nanopores in shale.…”

Section: Introductionmentioning

confidence: 99%

Comparative Study on the Primary Control Factors of Nanopores in Transitional and Deep Marine Shale in the Southeastern Sichuan Basin, China

Liu

Meng

et al. 2023

Energy Fuels

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The deep marine shale from the Silurian Longmaxi Formation and transitional shale from the Permian Longtan Formation in the Sichuan Basin are two promising targets for shale gas exploration in China. In this study, nanopore characteristics for deep marine and transitional shale samples collected from the same well in the southeastern Sichuan Basin are investigated and compared via field emission scanning electron microscopy imaging, low-pressure gas adsorption, total organic carbon measurement, and X-ray diffraction. Results show that clay-related pores are well developed, pores within organic matter (OM) are rare, and shrinkage cracks along the OM-edge are widely prevalent in transitional shales. The deep marine shale is rich in bubble-like OM pores. The transitional shale has a larger pore volume but a lower specific surface area compared to the deep marine shale. The nanoporosity of the transitional shales is primarily controlled by clay and OM content. In deep marine shale, OM is the primary contributor to nanoporosity. Higher nanoporosity in the deep marine shales than in the middle-shallow ones was observed in this study. This occurrence is attributed to the high fluid pressure and the resulting superior preservation conditions for nanopores in deep marine shale formations.

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“…On the one hand, organic matters in shales are an important material condition for the formation of natural gases [14][15][16][17][18]. At the same time, in the process of hydrocarbon generation and evolution, organic matter will also form nanopores, providing a large number of adsorption sites for gas.…”

Section: Introductionmentioning

confidence: 99%

Influence of Organic-Inorganic Composition on the Adsorption of Niutitang Formation Shale in Huijunba Syncline

Xing

Fu²,

Wang

et al. 2022

Geofluids

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To study the influence of different organic-inorganic composition on the adsorption in shale, taking the Niutitang Formation shale in the Huijunba syncline in southern Hanzhong as the research object, based on acid treatment to extract kerogen and wet chemicals. Extracting mineral components by oxidation method, a series of isothermal adsorption experiments were carried out on the original rock, kerogen, and mineral components of the samples. Through the three-dimensional Langmuir model fitting and adsorption thermodynamic calculation method, the adsorption thermodynamic parameters such as the isometric heat of adsorption and the standard adsorption entropy are obtained. The research results show that organic matter is the primary factor affecting the methane adsorption of shale and clay minerals also affect the adsorption to a certain extent. When the burial depth is relatively shallow, diagenesis has a promoting effect on the total amount of adsorption. As the depth increases, the diagenesis will turn into an inhibitory effect on the total amount of adsorption. Through the component weighting method, the lower limit ratio of the adsorbed amount of organic matter to the total amount in the shale is 29.3%~46.7% when the depth reaches to 3000 m, while the upper limit ratio of the adsorption of mineral components is 66.4%~73.6%.

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Competitive adsorption of methane and ethane on organic-rich shale at pressure up to 30 MPa: Experimental results and geological implications

Cited by 12 publications

References 62 publications

Measured Sorption Isotherms for Bakken Petroleum System Shales Using Carbon Dioxide and Produced Gas Hydrocarbons at 110 °C and Pressures up to 34.5 MPa

Measured Sorption Isotherms for Bakken Petroleum System Shales Using Carbon Dioxide and Produced Gas Hydrocarbons at 110 °C and Pressures up to 34.5 MPa

Comparative Study on the Primary Control Factors of Nanopores in Transitional and Deep Marine Shale in the Southeastern Sichuan Basin, China

Influence of Organic-Inorganic Composition on the Adsorption of Niutitang Formation Shale in Huijunba Syncline

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