Abstract: Deep coalbed methane (also known as coalrock gas) has become a crucial growth driver for increasing natural gas production in China. Practical experience has proven that high-yield production of deep coalbed methane requires large-scale hydraulic fracturing, and its extraction dynamics and development characteristics differ significantly from those of shallow coalbed methane. However, the key gas generation mechanisms and quantitative extraction threshold indicators remain unclear. Compared to shallow and intermediate coalbed methane, the research proposed that deep coalbed methane wells highlights three key differences in development geology—fracturing stimulation intensity and resource utilization scope, imbibition and displacement effects, and production methods—due to the geological uniqueness of deep coalbed methane wells. Through physical modeling experiments, numerical simulations, mechanistic analysis, and field trials, it is the first to reveal the intrinsic mechanisms of post-fracturing soaking and controlled pressure production in deep coalbed methane. The research establishes critical quantitative indicators and optimization strategies for scientifically determining soaking duration, flowback, and post-commissioning control measures. A “five steps-six stages” regulatory system and development model for deep coalbed methane wells were developed and validated with significant field results.The research results indicate: ① The scientific development concept of deep coalbed methane is to fully utilize the “permeation displacement displacement” effect of fracturing fluid through “reasonable well soaking, pressure control production, maintaining gas-liquid two-phase flow, and extending the self injection period”, ensuring efficient use of resources within the SRV transformation range, maximizing the synergistic and efficient production of gas-liquid two-phase within the drainage volume (DRV), and ultimately achieving the highest estimated ultimate recovery (EUR). ② During the fracturing and soaking process of deep coal seams, a significant gas-water displacement effect occurs. Based on imbibition-displacement NMR experiments, long-core pressure transmission experiments, and field-scale numerical simulations, the lower and upper limits of fracturing fluid soaking time were estimated to be 2.5 days and 15 days, respectively. Combining Daji field practice, the reasonable soaking time for deep coalbed methane wells was comprehensively determined to be 3 to 11 days. ③ Both microfluidic experiments and online NMR experiments demonstrate that during the flowback phase, the gas phase readily channels through dominant large pathways (gas channeling), leading to significant water phase retention in secondary fractures. Higher effective stress increases water retention and reduces drainage efficiency, subsequently blocking gas flow pathways from matrix pores connected to these secondary fractures. Compared to rapid depressurization, stepwise pressure reduction establishes a virtuous cycle of “desorption replenishment from the adsorbed state−continuous supply and production from the free state”, nearly doubling the CBM recovery factor (from 41.6% to 80.7%). ④ The conductivity of both self-propped and propped fractures decreases exponentially (by over 94%) within the effective stress range of 5−20 MPa. Furthermore, once flow velocity exceeds a critical threshold, the conductivity of propped fractures suffers severe damage due to coal fines migration, proppant embedment, or flowback. This underscores the necessity of controlled-pressure drainage to prevent damage to seepage pathway conductivity. Through a comprehensive analysis of multiple methods, it was determined that the single-layer backflow liquid production for vertical wells during the backflow phase ranges from 20 to 23 m³/d. Extending this to horizontal wells (taking 10 fractured sections as an example), the maximum daily liquid production should not exceed 230 m³/d. ⑤ Through comprehensive numerical simulation and dynamic monitoring, the reasonable production system for different production stages has been clarified, and the daily gas production per kilometer (daily allocation production) in Daji field has been quantitatively determined to be 40 000 to 50 000 m³/d. It is recommended to control the pressure drop rate during the backflow stage, production stage, stable production stage, and decline stage within the threshold values of 0.6, 0.7, 0.04, and 0.07 MPa/d, respectively. ⑥ Based on the experimental and simulation results of deep coal rock gas soaking and pressure control extraction, a new “five steps-six stages” full life cycle extraction system with “soaking diffusion to promote desorption, pressure control to stabilize flow and prevent closure, regulation to promote extraction and production, fine control to extend self jetting, lifting and unblocking to ensure stable production, and energy replenishment to control decline” as the core was constructed. Application of this system to 31 wells in the Daning Block confirmed that key production indicators—such as liquid production, gas production, and wellhead pressure—in the test wells were significantly superior to those in wells with almost no active soaking and produced under conventional aggressive methods at similar stages. After soaking time in the well 7−10 days and control method, the wellhead pressure increased from 6.45 MPa to 11.64 MPa, flowback efficiency improved from 20% to 30.1%, the predicted stable self-flow production period extended to 400−500 days, and the EUR per well increased by over 30%. The research results can provide important scientific theoretical basis for optimizing the extraction system of deep coalbed methane wells, improving single well production, and enhancing recovery efficiency.