Determination of the critical flow pore diameter of shale caprock

Cunfei Ma, Chengyan Lin, Chunmei Dong, Derek Elsworth, Songtao Wu, Xiaoqi Wang, Xiaolong Sun

Research output: Contribution to journalArticle

Abstract

The breakthrough pressure and pore permeability characteristics of shale caprock are the physical response of the microscopic pore throat structure. Whether oil and gas can break through shale caprock under the action of migration force is closely related to the critical flow pore diameter (pore throat diameter) of the rock. Therefore, the critical flow pore diameter is a key parameter for the division of the reservoir and caprock and evaluation of the physical seal abilities of caprock, affecting the oil and gas migration and accumulation, which are controlled by the critical lithology. In this study, the shale caprock of the N gas reservoir of the Huagang Formation in the Xihu sag, East China Sea Basin was comprehensively studied using particle size analysis, systematic environmental scanning electron microscopy, nano-CT, digital core reconstruction, low-temperature gas adsorption, high-pressure mercury intrusion, and nuclear magnetic resonance test for unconventional reservoir. In addition, the critical flow pore diameter of the shale caprock was determined. Based on the intersection point of the trendline of the breakthrough pressure data between the caprock and reservoir and the lower breakthrough pressure limit of the caprock of the gas–water reservoir, the breakthrough pressure limit of the caprock and reservoir is 2 MPa. Based on the correlation between the breakthrough pressure and shale lithology, the critical lithology for the division of the caprock and reservoir is argillaceous siltstone with a low breakthrough pressure limit of 2 MPa. Based on the identification of lithology boundary between caprock and reservoir, the critical lithology of the argillaceous siltstone selected as the research object, above-mentioned unconventional reservoir test technologies were carried out. The pore size statistics obtained from environmental scanning electron microscopy and the digital core model show that the critical flow pore diameter is between 100 and 300 nm. The high-pressure mercury injection test shows that the critical flow pore diameter ≥155 nm. The full pore diameter distribution curve is obtained by combined low-temperature carbon dioxide adsorption, low-temperature nitrogen adsorption and high-pressure mercury injection measurements. Compared the full pore diameter distribution curve with the nuclear magnetic resonance T2 spectrometry before and after centrifugation, the critical flow pore diameter is greater than 84 nm, ranging between 148 and 339 nm. Finally, based on the lithology, breakthrough pressure, and pore diameter relationships, the critical flow pore diameter of the shale caprock is 200 nm.

Original languageEnglish (US)
Article number104042
JournalMarine and Petroleum Geology
DOIs
StateAccepted/In press - Jan 1 2019

Fingerprint

critical flow
shale
porosity
lithology
siltstone
adsorption
throats
nuclear magnetic resonance
gases
scanning electron microscopy
gas
division
low pressure
oils
oil
injection
spectrometry
curves
intrusion
carbon dioxide

All Science Journal Classification (ASJC) codes

  • Oceanography
  • Geophysics
  • Geology
  • Economic Geology
  • Stratigraphy

Cite this

Ma, Cunfei ; Lin, Chengyan ; Dong, Chunmei ; Elsworth, Derek ; Wu, Songtao ; Wang, Xiaoqi ; Sun, Xiaolong. / Determination of the critical flow pore diameter of shale caprock. In: Marine and Petroleum Geology. 2019.
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abstract = "The breakthrough pressure and pore permeability characteristics of shale caprock are the physical response of the microscopic pore throat structure. Whether oil and gas can break through shale caprock under the action of migration force is closely related to the critical flow pore diameter (pore throat diameter) of the rock. Therefore, the critical flow pore diameter is a key parameter for the division of the reservoir and caprock and evaluation of the physical seal abilities of caprock, affecting the oil and gas migration and accumulation, which are controlled by the critical lithology. In this study, the shale caprock of the N gas reservoir of the Huagang Formation in the Xihu sag, East China Sea Basin was comprehensively studied using particle size analysis, systematic environmental scanning electron microscopy, nano-CT, digital core reconstruction, low-temperature gas adsorption, high-pressure mercury intrusion, and nuclear magnetic resonance test for unconventional reservoir. In addition, the critical flow pore diameter of the shale caprock was determined. Based on the intersection point of the trendline of the breakthrough pressure data between the caprock and reservoir and the lower breakthrough pressure limit of the caprock of the gas–water reservoir, the breakthrough pressure limit of the caprock and reservoir is 2 MPa. Based on the correlation between the breakthrough pressure and shale lithology, the critical lithology for the division of the caprock and reservoir is argillaceous siltstone with a low breakthrough pressure limit of 2 MPa. Based on the identification of lithology boundary between caprock and reservoir, the critical lithology of the argillaceous siltstone selected as the research object, above-mentioned unconventional reservoir test technologies were carried out. The pore size statistics obtained from environmental scanning electron microscopy and the digital core model show that the critical flow pore diameter is between 100 and 300 nm. The high-pressure mercury injection test shows that the critical flow pore diameter ≥155 nm. The full pore diameter distribution curve is obtained by combined low-temperature carbon dioxide adsorption, low-temperature nitrogen adsorption and high-pressure mercury injection measurements. Compared the full pore diameter distribution curve with the nuclear magnetic resonance T2 spectrometry before and after centrifugation, the critical flow pore diameter is greater than 84 nm, ranging between 148 and 339 nm. Finally, based on the lithology, breakthrough pressure, and pore diameter relationships, the critical flow pore diameter of the shale caprock is 200 nm.",
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Determination of the critical flow pore diameter of shale caprock. / Ma, Cunfei; Lin, Chengyan; Dong, Chunmei; Elsworth, Derek; Wu, Songtao; Wang, Xiaoqi; Sun, Xiaolong.

In: Marine and Petroleum Geology, 01.01.2019.

Research output: Contribution to journalArticle

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AU - Ma, Cunfei

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AU - Dong, Chunmei

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AU - Sun, Xiaolong

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N2 - The breakthrough pressure and pore permeability characteristics of shale caprock are the physical response of the microscopic pore throat structure. Whether oil and gas can break through shale caprock under the action of migration force is closely related to the critical flow pore diameter (pore throat diameter) of the rock. Therefore, the critical flow pore diameter is a key parameter for the division of the reservoir and caprock and evaluation of the physical seal abilities of caprock, affecting the oil and gas migration and accumulation, which are controlled by the critical lithology. In this study, the shale caprock of the N gas reservoir of the Huagang Formation in the Xihu sag, East China Sea Basin was comprehensively studied using particle size analysis, systematic environmental scanning electron microscopy, nano-CT, digital core reconstruction, low-temperature gas adsorption, high-pressure mercury intrusion, and nuclear magnetic resonance test for unconventional reservoir. In addition, the critical flow pore diameter of the shale caprock was determined. Based on the intersection point of the trendline of the breakthrough pressure data between the caprock and reservoir and the lower breakthrough pressure limit of the caprock of the gas–water reservoir, the breakthrough pressure limit of the caprock and reservoir is 2 MPa. Based on the correlation between the breakthrough pressure and shale lithology, the critical lithology for the division of the caprock and reservoir is argillaceous siltstone with a low breakthrough pressure limit of 2 MPa. Based on the identification of lithology boundary between caprock and reservoir, the critical lithology of the argillaceous siltstone selected as the research object, above-mentioned unconventional reservoir test technologies were carried out. The pore size statistics obtained from environmental scanning electron microscopy and the digital core model show that the critical flow pore diameter is between 100 and 300 nm. The high-pressure mercury injection test shows that the critical flow pore diameter ≥155 nm. The full pore diameter distribution curve is obtained by combined low-temperature carbon dioxide adsorption, low-temperature nitrogen adsorption and high-pressure mercury injection measurements. Compared the full pore diameter distribution curve with the nuclear magnetic resonance T2 spectrometry before and after centrifugation, the critical flow pore diameter is greater than 84 nm, ranging between 148 and 339 nm. Finally, based on the lithology, breakthrough pressure, and pore diameter relationships, the critical flow pore diameter of the shale caprock is 200 nm.

AB - The breakthrough pressure and pore permeability characteristics of shale caprock are the physical response of the microscopic pore throat structure. Whether oil and gas can break through shale caprock under the action of migration force is closely related to the critical flow pore diameter (pore throat diameter) of the rock. Therefore, the critical flow pore diameter is a key parameter for the division of the reservoir and caprock and evaluation of the physical seal abilities of caprock, affecting the oil and gas migration and accumulation, which are controlled by the critical lithology. In this study, the shale caprock of the N gas reservoir of the Huagang Formation in the Xihu sag, East China Sea Basin was comprehensively studied using particle size analysis, systematic environmental scanning electron microscopy, nano-CT, digital core reconstruction, low-temperature gas adsorption, high-pressure mercury intrusion, and nuclear magnetic resonance test for unconventional reservoir. In addition, the critical flow pore diameter of the shale caprock was determined. Based on the intersection point of the trendline of the breakthrough pressure data between the caprock and reservoir and the lower breakthrough pressure limit of the caprock of the gas–water reservoir, the breakthrough pressure limit of the caprock and reservoir is 2 MPa. Based on the correlation between the breakthrough pressure and shale lithology, the critical lithology for the division of the caprock and reservoir is argillaceous siltstone with a low breakthrough pressure limit of 2 MPa. Based on the identification of lithology boundary between caprock and reservoir, the critical lithology of the argillaceous siltstone selected as the research object, above-mentioned unconventional reservoir test technologies were carried out. The pore size statistics obtained from environmental scanning electron microscopy and the digital core model show that the critical flow pore diameter is between 100 and 300 nm. The high-pressure mercury injection test shows that the critical flow pore diameter ≥155 nm. The full pore diameter distribution curve is obtained by combined low-temperature carbon dioxide adsorption, low-temperature nitrogen adsorption and high-pressure mercury injection measurements. Compared the full pore diameter distribution curve with the nuclear magnetic resonance T2 spectrometry before and after centrifugation, the critical flow pore diameter is greater than 84 nm, ranging between 148 and 339 nm. Finally, based on the lithology, breakthrough pressure, and pore diameter relationships, the critical flow pore diameter of the shale caprock is 200 nm.

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