Abstract
Shut-in after hydraulic fracturing can make full use of fracturing fluid imbibition and improve well productivity. However, how to determine a scientific shut-in time is an important problem for reservoir engineers. Therefore, an efficient model was proposed in this paper to fill this gap and then applied in the shale oil reservoirs. An analytical model of pressure distribution and stimulation reservoir volume was first developed, which includes the process of fracturing fluid injection and well shut in. A good agreement was obtained between the calculated pressure data and field data. Afterward, the imbibition experiments of 15 core samples from shale oil reservoir were carried out and the imbibition equilibrium time was observed. Finally, we calculated the shut-in time by summation of the time of fracturing fluid volume stabilization (stimulation volume stabilization) and imbibition equilibrium time. Results show that pressure diffuses during fracturing fluid injection and the pressure balance during well shut-in both impact the time of fracturing fluid volume stabilization (stimulation volume stabilization). Furthermore, a higher permeability can increase fluid flow capacity and accelerate the time of fracturing fluid volume stabilization. A scientific shut-in time should include pressure balance time and fracturing fluid imbibition equilibrium time. This work can provide a strong basis for optimization the shut-in time and useful insights into fracturing operation in shale oil reservoirs. • A model to optimize the shut-in time is proposed considering the process of fracturing fluid injection and well shut in. • Fracturing fluid injection model is established to analyze the pressure distribution considering two-dimensional leak-off. • The shut-in time can be reasonably evaluated by summation of swept volume equilibrium time and imbibition equilibrium time. • For this specific block, the optimized shut-in time is obtained with the range from 63 to 75 days using this proposed method.
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