Reservoir recovery study with stability analysis model constructed by flat sand filling experiment-Example of well area X in Tankou oilfield

Abstract Injecting and recovering fluids in mature oil fields is a challenging task that can have significant impact on overall recovery rates. Conventionally, the approach taken has been a combination of laboratory experiments and numerical simulations, which lack field-scale verification and prediction accuracy. To address this limitation, we propose a new methodological approach—from experimentation to data simulation to developing a solution proposal to mathematically proving the validity of the approach. The novelty of this approach lies in its ability to fast-track verification of the solution and to predict, within limitations, the expected performance under real-field conditions. In the case study detailed in this paper, we establish the relationship between permeability, crude oil viscosity, and fluid recovery rate—all key parameters—on recovery performance, assuming a fixed wellbore network configuration. The results are validated through numerical simulations. Based on these findings, we recommend a development adjustment scheme, which is then rapidly validated using a reliability analysis model for a period of one year. The scheme implementation results in exponential distribution percentiles of 0.258375 and 0.276978, indicating its effectiveness. Additionally, the DGM (1,1) model projects recovery rates of 8.93 and 12.08 for the next two time points. Based on these projections, engineering guidelines are developed recommending crude oil viscosity adjustment through blending and dosing, and adoption of a 5 mL/min water injection rate for optimal recovery performance.