Due to strong stress sensitivity resulted from unconventional tight formationsit is of practical interest to formulate a reasonable pressure drawdown plan to improve gas extraction recovery. The impact of water-shale interactions on the reservoir permeability was previously ignored in the managed pressure drawdown optimization. The controlled-pressure production dynamic analysis was mostly conducted using numerical simulation, lack of rigorous theoretical support. Hence in this paper, a theoretical production prediction model was proposed and verified with HIS RTA 2015by incorporating multiple pressure drawdown mechanisms and various non-linear gas flow process. The on-site production effects dominated by two different pressure drop methods was further compared, indicating that compared to depressurization production, the production reversion can occur in the controlled pressure production process and the EUR of single well can be increased by about 30% under the control of managed pressure drawdown approach. Finally, the pressure drawdown optimization strategy was carried out on the field test from the both production effect and economic benefits, which demonstrated that the best economic solution can generally be obtained in the early stage of production. The research results can be closely linked to the on-site production practice of shale gas wells, providing insights into designing optimized production strategy scheme.
Rate-controlled Hg injection experiments, NMR core tests and core flooding experiments are carried out to study the low permeability cores from the Daqing and Changqing oilfields. The forming and affecting factors are studied to demonstrate why the pseudo threshold pressure gradient to flow should be overcome. Because of the boundary layer caused by interaction between solid and fluid and the micro throats of low permeability reservoirs, the pseudo threshold pressure should be overcome for fluid to flow in low permeability reservoirs. Few throats are involved in the flow and the seepage cross section area is also less at lower pressures. The throats number and the seepage cross section area increase with the increasing of flooding pressure. The pore structure and movable fluid saturation of low permeability reservoirs have remarkable influence on the pseudo threshold pressure to flow, the bigger the mainstream throats and the movable fluid saturation, the less the pseudo threshold pressure to flow. The pseudo threshold pressure gradient to flow is a characteristic parameter of nonlinear flow degree and seepage ability and it is a synthetic symbol of pore structure and movable fluid saturation.
The shale gas productivity model based on shale gas nonlinear seepage mechanism is an effective way to reasonably predict productivity. The incomplete gas nonlinear effects considered in the current production prediction models can lead to inaccurate production prediction. Based on the conventional five-zone compound flow model, comprehensive gas nonlinearities were considered in the improved compound linear flow model proposed in the paper and a semianalytical solution for productivity was obtained. The reliability of the productivity model was verified by the field data, and then, the 20-year production performance analysis of the gas well was studied. Ultimately, the key influencing factors of the fracture control stage and matrix control stage have been analyzed. Research indicated the following: (1) the EUR predicted by the productivity model is higher than the EUR that the comprehensive nonlinear effects are not considered, which demonstrated that the various nonlinear effects cannot be neglected during the production prediction to ensure the greater calculation accuracy; (2) during the early production stage of shale reservoir, the adsorbed gas is basically not recovered, and the cumulative adsorption contribution rate does not exceed 10%. The final adsorption gas contribution rate is 23.28%, and the annual adsorption rate can exceed 50% in the 20th year, showing that free gas and adsorbed gas are, respectively, important sources of the early stage of production and long-term stable production; (3) the widely ranged three-dimensional fracturing reformation of shale reservoirs and reasonable bottom hole pressure in the later matrix development process should be implemented to increase the effective early production of the reservoir and ensure the earlier gas production process of the matrix development. The findings of this study can help for better ensuring the prediction accuracy of the estimated ultimate recovery and understanding the main influencing factors of the dynamic performance of gas wells so as to provide a theoretical reference for production optimization and development plan formulation of the shale gas reservoirs.
Water occurrence characteristics and water saturation are crucial for evaluating the gas-bearing property of marine shale formations and the development law of gas wells. In this work, the impacts of water saturation on the gas-bearing property and recovery ratio of marine shale are studied using 2D NMR technology and an improved adsorption gas/free gas calculation model. The results demonstrate that the main factors of shale water saturation are capillary water and free water. Water saturation and shale's capacity to saturate methane are negatively correlated. Bound water effectively inhibits the readsorption of free gas and encourages the desorption of adsorbed gas. Capillary water blocks the gas seepage channel, which lowers the reservoir's gas phase permeability. Free water saturation can be used as a marker to gauge the marine shale's ability to saturate methane. Bound water disrupts the methane adsorption–desorption equilibrium; the recovery of adsorbed gas is therefore greater than that of free gas with high water saturation. Immersion after hydraulic fracturing helps the fracturing fluid fully enter the reservoir matrix and replace the adsorbed gas, improving the recovery rate of gas wells. This study provides a solid foundation for the calculation of geological reserves and assessment of development impacts.
Diffusion plays an important role in gas production from a shale matrix. To determine the gas diffusion mechanism in micro-/nanopores and to tackle the difficult problem of the quantitative description of the gas diffusion capacity in shale reservoirs, a differential momentum equation considering fluid viscosity is derived, and an apparent diffusion coefficient model considering shale porosity, tortuosity, and Knudsen number is built. The diffusion ability testing experiment carried out to verify the reliability of the proposed model is created by our research group. The results indicate that the new apparent diffusion coefficient better captures the diffusion capacity of shale gas owing to the consideration of the aforementioned key parameters. The apparent diffusion coefficient is negatively correlated with pressure but positively correlated with the pore diameter. For the nD permeability reservoirs when the average reservoir pressure is less than 5 MPa, the contribution of diffusion to the flow rate is more than 80%. In summary, the quantitative calculation of shale gas diffusion flow under given reservoir conditions and the understanding of the contribution of diffusion to flow at different stages can be achieved with the proposed diffusion model. Scientific foundations for timely production system adjustment and single-well yield enhancement are, thereby, expected to be laid.
In shale reservoirs, pores and fractures are developed, and the seepage mechanism is complicated. The gas well estimated ultimate recovery (EUR) is difficult to be determined. The existing methods are highly dependent on production data from shale gas wells, and they cannot accurately predict the EUR of a single well with little production data and a long production time. By combining the indoor depletion development simulation experiment with in situ production data, a new power function decline model of the daily gas production and production time was established. The production process of shale gas was divided into two stages: the fracture network control stage and the matrix control stage. During the fracture network control stage, both the daily gas production and the daily water production increased rapidly and then decreased rapidly, with large fluctuations. During the matrix control stage, the daily water production gradually decreased and approached zero, and the daily gas production exhibited a power function decrease. The calculation results of the model are highly consistent with the actual production decline curve of shale gas. This demonstrates that the simulation experiment can reflect the decrease in the actual production well. The established model can eliminate the uncertainty in EUR calculations caused by insufficient actual production data. The EURs of 25 wells in the Weiyuan area have been calculated for 4 consecutive years. The overall error between the EUR calculated by the model in 2017 and 2018 and the EUR of the development plan is less than 5%. Owing to the development process, the EUR calculation results tend to increase year-by-year. It should be noted that the late production of shale gas well is worthy of attention.
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