Speaker
Description
As a new type of unconventional resource, deep coalbed methane reservoir has demonstrated generally significant development potential. It is characterized by rapid gas breakthrough, high gas production rates, and high estimated ultimate recovery (EUR) per well. Given that gas content is a key parameter for reserve assessment and development planning, it is crucial to establish a novel gas content measurement procedure especially for situ deep coalbed methane reservoirs. However, the testing results from conventional USBM method often deviate significantly from actual well production performance and fail to do accurate evaluation. To address this limitation, a novel in situ gas content testing method was proposed in this paper for deep coalbed methane. Specifically, three parts were included in this method: Firstly freshly retrieved core samples were promptly placed into a high-pressure vessel for simulating reservoir temperature condition, and methane was injected to restore the pore pressure to the formation pressure, thereby closely replicating the downhole temperature and pressure conditions. Subsequently, an isobaric displacement experimental procedure was established, in which water is injected to displace the annular gas between the core and the high-pressure vessel. It was ensured that all measured gas originates solely from the core itself. Next, rapid valve switching is performed to achieve a slight pressure reduction, followed by pressure re-equilibration. Based on the experimental data, a mathematical model for charaterizeing gas flow within matrix-fracture system was developed to calculate the free gas pore volume under reservoir conditions. By combining the measured total gas content with the derived free gas volume, the contributions of free and adsorbed gas were accurately determined. Ultimately, we conducted gas content evaluation comparation between the proposed method and conventional approaches. Based on field pressure preserved coring data, the proposed method yields a 50 % higher total gas content, with the free gas fraction reaching nearly 50 % greater than values obtained by other conventional methods. The method presented in this study significantly enhances the accuracy of in situ gas content measurement by closely replicating original formation pressure and temperature conditions. It thereby establishes an experimental framework for precisely evaluating the proportions of adsorbed and free gas under actual reservoir conditions.
| Country | China |
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