Reservoir dynamic evolution and drainage optimization in deep saturated coalbed methane of Shenfu Block

A production-data and reservoir-modeling study of 11 deep saturated coalbed methane wells in China’s Shenfu Block found that the initial bottomhole pressure-drawdown rate was associated with whether wells entered a stable or declining production pattern. Wells with an initial drawdown rate above 160 kPa/d were classified as decline type, while slower drawdown was associated with greater modeled permeability improvement and sustained production. The study proposed a staged regime of slow initial drawdown, moderate acceleration during the production-increase stage and slower drawdown during later decline.

The analysis used actual gas and water production records from 11 vertical wells in the Shenfu Block. All had produced continuously for more than one year, had complete geological and production data and had original reservoir pressure of approximately 20 MPa. The principal target was the No. 8 + 9 coal seam, whose reported burial depth was 1,853.5–2,526.3 m and thickness was 3.2–22.9 m. The researchers classified wells according to their gas-production curves as decline type or stable type.

Average reservoir pressure and permeability were not measured directly during production. Instead, they were estimated with a coupled material-balance and permeability-prediction framework that incorporated adsorbed and free gas, gas-water production, pressure-dependent gas slippage, effective stress and coal-matrix shrinkage. The estimates for each well were generated by combining model parameters with its production history. The authors noted that the absence of independent measured reservoir-pressure data for direct calibration means that absolute pressure estimates and permeability-enhancement ratios may contain systematic errors.

The decline-type pattern was illustrated by well S2, which had an initial pressure-drawdown rate of 197.3 kPa/d. After 473 days of production, its average daily gas production was 3,318 m³/d and average daily water production was 4.05 m³/d. Its modeled average reservoir pressure declined from 21.92 MPa to 11.71 MPa, while modeled permeability increased by only 0.9%. Gas production rose rapidly at first but declined sharply after reaching a peak, and water production fell to almost zero in the later period.

Well S11 represented the stable-type pattern. Its initial drawdown rate was 131.14 kPa/d, and it had produced for 541 days at the data cutoff. Its average daily gas production was 8,073 m³/d and average daily water production was 2.39 m³/d. The model estimated that average reservoir pressure declined from 22.06 MPa to 3.7 MPa and that permeability increased by 5.4%. The researchers associated this broader modeled pressure reduction with a larger depressurized zone and progressively greater contributions from matrix shrinkage, allowing gas production to rise and then stabilize.

A comparison of geographically adjacent wells S7 and S3, which the authors said had similar geological conditions and fracturing parameters, highlighted the relationship between initial drawdown and later production. S7 had an initial drawdown rate of 245.733 kPa/d and reached peak gas production of 6,301 m³/d after about three months, but production subsequently declined. Its modeled average reservoir pressure fell from 21.7 MPa to 15.42 MPa, and modeled permeability increased by 0.8%. S3 had a slower initial drawdown rate of 117.433 kPa/d; its daily gas production increased and stabilized above 10,000 m³/d, while modeled average pressure declined from 20.6 MPa to 11.3 MPa.

The researchers proposed controlling the initial bottomhole flowing-pressure drawdown rate within 160 kPa/d. During the later part of the gas-production increase stage, they recommended increasing the rate by 50–100 kPa/d to promote gas desorption. During the later decline stage, they proposed reducing the drawdown rate to approximately 50 kPa/d. Simulations after 200 days of continuous drainage indicated that a moderate initial rate produced a larger modeled depressurized area and more sustained production trend than an excessively rapid rate.

The staged regime was applied to one Shenfu Block well. After implementation, the well reached peak gas production of 14,651 m³/d and then entered a high, stable-production period lasting more than 200 days, with daily gas production remaining above 9,000 m³/d. The authors described this field application as validation of the proposed regime and reported advantages in stable-production duration and productivity stability compared with previous wells in the block. Because only one application was described, the result does not by itself establish performance across the field.

The findings are bounded by the study’s small sample of 11 wells and its reliance on model-calculated rather than independently measured reservoir pressure and permeability. The analysis also did not account for inter-well interference or complex fracture networks, and the authors called for production-time pressure and permeability measurements, geomechanical simulations and multi-well interference models. They also cautioned that numerical thresholds should be adapted to other blocks according to local in-situ stress, reservoir pressure and permeability, rather than applied unchanged across all deep coalbed methane reservoirs.

Subject of Research: Reservoir dynamics and drainage-rate optimization in 11 deep saturated coalbed methane wells in the Shenfu Block

Article Title: Reservoir dynamic evolution and drainage optimization in deep saturated coalbed methane of Shenfu Block

Article References: Wang, Y. J., Xu, H., Liu, Y. N., Liu, Y. C., Wu, H., Liu, D., Wu, X. Z., Dong, Y., Song, X. J., & Wang, J. W. (2026). Reservoir dynamic evolution and drainage optimization in deep saturated coalbed methane of Shenfu Block. PLOS One, 21(10), e0360289. https://doi.org/10.1371/journal.pone.0360289

Image Credits: AI Generated

DOI: 10.1371/journal.pone.0360289

Keywords: coalbed methane, Shenfu Block, reservoir pressure, permeability, drainage optimization, production decline, pressure drawdown, gas desorption, Ordos Basin, reservoir modeling, Reservoir, dynamic