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<p>Accurate characterization of dynamic coal reservoir properties is crucial for evaluating production performance, optimizing development strategies, and predicting productivity potential in coalbed methane (CBM) extraction processes. A mathematical model was developed by integrating key operational parameters (such as production boundaries, production strategies, and hydraulic fracturing design), with reservoir pressure serving as the core governing variable. The model quantitatively describes the spatiotemporal evolution of reservoir properties (e.g., gas content, water saturation, and permeability) and stage-specific production volumes of gas and water, along with their respective ratios. Field validation using data from three producing wells in the SZN Block confirms the model’s predictive capability. The results indicate that CBM well productivity is governed by several interacting factors, including the production boundary extent, pressure propagation range, and dynamic permeability evolution. The dynamics of the pressure drop funnel show a strong correlation with well production, indicating that production variability arises from differences in production boundaries and pressure propagation behaviors. Sustained high gas production is facilitated by a self-reinforcing mechanism: gas desorption enhances gas-phase permeability to over 1&#xa0;mD, which in turn promotes gas seepage and production. Over 70% of CBM resources are produced during the single-phase gas flow stage (SPGF), whereas less than 15% are recovered during the gas–water two-phase flow stage. The dynamic variations in water saturation and water-phase permeability explain the characteristic water production behavior of typical CBM wells: water constitutes up to 90% of total fluid production in the early phase, yet it becomes negligible during the SPGF stage, due to the combined effect of extremely low water proportion (&lt;10%) and water-phase permeability (&lt;0.1&#xa0;mD). Consequently, a key objective for production optimization is to achieve an expanded production boundary through sufficient water drainage and a gradual reduction in bottom-hole flowing pressure. Conversely, adopting an overly aggressive depressurization strategy may trigger premature gas desorption near the wellbore, which limits the outward expansion of the production boundary and leads to rapid gas production decline. Water production volume and its proportion at each stage are controlled by porosity and formation compressibility—critical geological parameters that must be considered when designing and adjusting production strategies. This study provides a robust technical framework for analyzing reservoir dynamics and optimizing development strategies in CBM fields.</p>

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A Mathematical Model for Dynamic Characterization of Reservoir Parameters in Coalbed Methane Development

  • 期刊论文

  • 发表日期：

    2026年4月6日

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  • Xinlu Yan,
  • Shuheng Tang,
  • Xiaokang Fu,
  • Lei Xu,
  • Qing Yan,
  • Zhongcheng Li,
  • Guangjing Liu

摘要

Accurate characterization of dynamic coal reservoir properties is crucial for evaluating production performance, optimizing development strategies, and predicting productivity potential in coalbed methane (CBM) extraction processes. A mathematical model was developed by integrating key operational parameters (such as production boundaries, production strategies, and hydraulic fracturing design), with reservoir pressure serving as the core governing variable. The model quantitatively describes the spatiotemporal evolution of reservoir properties (e.g., gas content, water saturation, and permeability) and stage-specific production volumes of gas and water, along with their respective ratios. Field validation using data from three producing wells in the SZN Block confirms the model’s predictive capability. The results indicate that CBM well productivity is governed by several interacting factors, including the production boundary extent, pressure propagation range, and dynamic permeability evolution. The dynamics of the pressure drop funnel show a strong correlation with well production, indicating that production variability arises from differences in production boundaries and pressure propagation behaviors. Sustained high gas production is facilitated by a self-reinforcing mechanism: gas desorption enhances gas-phase permeability to over 1 mD, which in turn promotes gas seepage and production. Over 70% of CBM resources are produced during the single-phase gas flow stage (SPGF), whereas less than 15% are recovered during the gas–water two-phase flow stage. The dynamic variations in water saturation and water-phase permeability explain the characteristic water production behavior of typical CBM wells: water constitutes up to 90% of total fluid production in the early phase, yet it becomes negligible during the SPGF stage, due to the combined effect of extremely low water proportion (<10%) and water-phase permeability (<0.1 mD). Consequently, a key objective for production optimization is to achieve an expanded production boundary through sufficient water drainage and a gradual reduction in bottom-hole flowing pressure. Conversely, adopting an overly aggressive depressurization strategy may trigger premature gas desorption near the wellbore, which limits the outward expansion of the production boundary and leads to rapid gas production decline. Water production volume and its proportion at each stage are controlled by porosity and formation compressibility—critical geological parameters that must be considered when designing and adjusting production strategies. This study provides a robust technical framework for analyzing reservoir dynamics and optimizing development strategies in CBM fields.