Lower limits of petrophysical parameters for effective reservoirs in ultradeep carbonate gas reservoirs: A case study from the Deng IV Member, Gaoshiti-Moxi Area, Sichuan Basin, SW China

Wang, Lu; Zhang, Yifan; Luo, Ruilan; Zou, R.; Deng, Hui; Zou, Run; Huang, Liang; Liu, Yi‐Sheng

doi:10.1016/j.jhydrol.2023.129657

Cited by 6 publications

(1 citation statement)

References 39 publications

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“…By inserting the pressure sensor probes into the rubber sleeve of the core holder, real-time pressure data from the interior of the core was collected. Given that the lower limits of petrophysical parameters for effective carbonate gas reservoirs are 2.68%, 0.042mD, 35 three groups of long core plugs, each measuring 50 cm in length, were selected with permeability ranges of 1–10 mD (type I), 0.1–1 mD (type II), and 0.01–0.1 mD (type III), resulting in average permeabilities of 2.300 mD, 0.486 mD, and 0.046 mD, respectively. Under varying initial water saturations (Swi) of 0%, 20%, 40%, and 55%, depletion tests with constant gas production rates were conducted to simulate physical scenarios.…”

Section: Methodsmentioning

confidence: 99%

A New Evaluation Method of Recoverable Reserves and Its Application in Carbonate Gas Reservoirs

Zhou,

Li,

et al. 2024

ACS Omega

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The propagation pattern of pressure drawdown effectively reflects the recoverable reserves range around the gas well and serves as a crucial basis for development strategies. However, it is not easy to detect the pressure propagation boundary near the producing well, especially in low-permeability reservoirs where the drainage radius is small. Physical simulation experiments can serve as a crucial method as the whole pressure profile and gas rate can be obtained in real time. Using long core plugs with permeabilities of 2.300 mD, 0.486 mD, and 0.046 mD, physical simulation experiments were carried out under varying initial water saturation (Swi) conditions of 0%, 20%, 40%, and 55% to observe the dynamic variations in pressure profiles of the core plugs during pressure depletion. Based on the material balance equation and pressure profile characteristics of the core plugs, a method for evaluating recoverable reserves within a well-spacing radius through laboratory experiments was proposed and performed. Mechanism analysis was conducted based on mercury injection tests, and suggestions for enhancing gas recovery were presented. Research findings indicate that lower permeability, higher initial water saturation, and higher abandonment gas rates result in reduced reserve utilization range and degree. Under abandoned gas rate conditions, for type I and II rocks, the pore radius is primarily distributed between 0.1 and 1 μm, the pressure drawdown can reach the well-spacing radius of 600 m, and the ultimate recovery efficiencies are more than 70.6%. For type III rocks, the pore radius mainly falls below 0.1 μm, the drainage radius is smaller than 10 m with Swi greater than 40%, and the ultimate recovery is below 10%. This paper provides an experimental method for recoverable reserves evaluation while formulating gas reservoir development strategies before well testing.

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Section: Methodsmentioning

confidence: 99%

A New Evaluation Method of Recoverable Reserves and Its Application in Carbonate Gas Reservoirs

Zhou,

Li,

et al. 2024

ACS Omega

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Investigation of the confinement effect on fluid-phase behavior in shale oil reservoirs during CO2 injection process

Dou,

Zhang,

Guo

et al. 2023

J Petrol Explor Prod Technol

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Due to the confinement effect of nanopores, the fluid-phase behavior of shale oil reservoirs is much different from that of conventional reservoirs. The accurate description of the phase change characteristics of fluid in nanopores is the basis to design development plan, production system, and EOR methods of shale oil reservoirs. In this study, molecular dynamics simulation was employed to analyze the phase behavior of single-component system and hydrocarbon–CO2 mixture system in organic nanopores. The results show that the confinement effect on the phase change pressure of the single-component system is influenced by the distribution of the electron cloud. The phase change pressure of hydrocarbons with even distribution of the electron cloud would be increased, while that of CO2 would be decreased due to the instantaneous dipole moment. In addition, as the length of carbon chains increases, the confinement effect on hydrocarbons becomes stronger. When the temperature increases, the confinement effect becomes weaker. In the hydrocarbon–CO2 mixture system, when the occurrence condition changes from bulk to the nanopore of 5 nm, the bubble point pressure decreases by 39.21–68.85%, and the critical temperature and pressure decrease by 75.98% and 7.13%, respectively. On the whole, the P–T phase envelope is shrunken under the confinement effect. CO2 is much easier to be miscible with shale oil in nanopores. Moreover, full mixing and keeping in single liquid phase of CO2–hydrocarbons mixture system can reduce the adsorption of hydrocarbons on organic pore walls. Therefore, CO2 injection could be a feasible method to enhance oil recovery in the matrix of shale oil reservoirs.

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Quantitative characterization of crude oil mobilization in microscopic pores during forward and reverse flooding in tight sandstone reservoirs using various fracturing fluid systems

2024

Chemical Engineering Research and Design

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Lower limits of petrophysical parameters for effective reservoirs in ultradeep carbonate gas reservoirs: A case study from the Deng IV Member, Gaoshiti-Moxi Area, Sichuan Basin, SW China

Cited by 6 publications

References 39 publications

A New Evaluation Method of Recoverable Reserves and Its Application in Carbonate Gas Reservoirs

A New Evaluation Method of Recoverable Reserves and Its Application in Carbonate Gas Reservoirs

Investigation of the confinement effect on fluid-phase behavior in shale oil reservoirs during CO2 injection process

Quantitative characterization of crude oil mobilization in microscopic pores during forward and reverse flooding in tight sandstone reservoirs using various fracturing fluid systems

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