Qianhua Xiao

The productivity evaluation of CBM wells can yield significant insights into exploring the patterns of CBM production, predicting the effectiveness of the CBM well and reservoir stimulation, optimizing the gas reservoir development program, and developing a reasonable production system, for the purpose of facilitating efficient development of CBM. In particular, to accurately evaluate CBM productivity, we should establish the corresponding mathematical model of fluid flow through porous media and productivity evaluation model based on a clear understanding of CBM occurrence states and mechanisms of its flow through porous media. After considering the effects of slip flow, Knudsen diffusion, surface diffusion, stress sensitivity, and matrix shrinkage on fluid mass transfer, we have put forward a triple-porosity and dual-permeability mathematical model to predict CBM productivity that incorporates matrix gas desorption, complex flow in matrix pores, and gas–water two-phase flow in a cleat system. In combination with reservoir characteristic parameters, a case study of Ma-26 well in the Mabidong block in the south of the Qinshui Basin, we carried out a numerical simulation of the productivity of a fractured CBM well and analyzed the effects (on production performance) of occurrence states, cleat system permeability, complex flow regimes in the matrix, Langmuir pressure, and Langmuir volume on production are provided. The results show that 1) in the initial drainage and production stage of CBM wells, both free gas and adsorbed gas are produced simultaneously, while adsorbed gas dominates the production in later stages; 2) the peak output and cumulative output of CBM wells increase significantly with the rise in cleat system permeability; 3) the increase of Langmuir pressure, volume, and matrix porosity are conducive to the increase of CBM production. The research has considerable reference value for work on mechanisms of CBM flow in porous media and post fracturing productivity evaluation of CBM and also provides a theoretical basis for fieldwork in CBM development.

Hydrocarbon gas flooding/Huff-n-Puff (HNP) can improve the oil recovery in the unconventional reservoirs. Here, the mechanisms accounting for fluid flow in the low-permeability and ultra-low permeability reservoirs were experimentally and theoretically investigated. Core plugs collected from a typical China oilfield were utilized for the experiments. Additionally, methane was used as the injection agent to conduct natural gas HNP/displacement experiments. The results indicated that the use of natural gas as an energy supplement agent and the HNP development method can effectively improve the recovery efficiency of the aforementioned two types of reservoirs. During the HNP process, the oil recovery is effectively enhanced mainly in the first round and second round. Meanwhile, during gas injection and HNP, natural gas can evidently weaken the extraction and reduce the precipitation of heavy components. However, the natural gas injection can establish an effective driving pressure system in low-permeability core plugs, and the interaction between natural gas and oil can change the mobility ratio. Furthermore, it aids in avoiding viscous fingering and premature breakthroughs. Moreover, the oil can be sandwiched between the interface of the gas and water phases to form a slip channel in a hydrophilic core sample, which can quickly produce oil. Finally, a numerical model was developed by considering the reservoir parameters of Changqing Oilfield, China. The oil recovery after eight rounds of CH4 HNP was 80% higher than that achieved via depletion development. Additionally, the oil recovery curves are especially similar in the previous three HNP rounds. These curves show obvious differences from the fourth round onwards, which indicates that the asphaltene deposition and CH4 diffusion slightly affect the oil recovery factor during the initial production period.