Hydraulic fracture is crucial for assuring well production from unconventional reservoirs. For the optimization of hydraulic fracture geometry and the ensuing production of an interlayered reservoir, vertical hydraulic fracture propagation path has been analyzed. However, an effective fluid channel cannot be formed if the proppant is unable to reach the area where the fracture propagates. This paper presents a numerical model using the lattice-based method to investigate the hydraulic fracture propagation and proppant transport mechanism in interlayered reservoirs. The hydraulic fracture propagation model was simulated under different geological and fracturing engineering factors. The results indicate that interlayer Young’s modulus and horizontal stress anisotropy are positively correlated with longitudinal propagation and proppant carrying ability in interlayered formations. The fracturing injection rate has an optimal solution for fracture propagation and proppant carrying since a too low injection rate is unfavorable for fracture penetration of the interlayer, while a too high injection rate increases fracture width instead of further fracture penetration. In conclusion, attention is drawn to fine particle size proppants used in multi-layer reservoirs for fracturing fluid to carry proppants as far as possible to obtain maximum propped area.
CO2 foam fracturing fluid is widely used in unconventional oil and gas production because of its easy flowback and low damage to the reservoir. Nowadays, the fracturing process of CO2 foam fracturing fluid injected by coiled tubing is widely used. However, the small diameter of coiled tubing will cause a large frictional pressure loss in the process of fluid flow, which is not beneficial to the development of fracturing construction. In this paper, the temperature and pressure calculation model of gas, liquid, and solid three-phase fluid flow in the wellbore under annulus injection is established. The model accuracy is verified by comparing the calculation results with the existing gas, solid, and gas and liquid two-phase model of CO2 fracturing. The calculation case of this paper shows that compared with the tubing injection method, the annulus injection of CO2 foam fracturing fluid reduces the friction by 3.06 MPa, and increases the wellbore pressure and temperature by 3.06 MPa and 5.77°C, respectively. Increasing the injection temperature, proppant volumetric concentration, and foam quality will increase the wellbore fluid temperature and make the CO2 transition to the supercritical state while increasing the mass flow rate will do the opposite. The research results verify the feasibility of the annulus injection of CO2 foam fracturing fluid and provide a reference for the improvement of CO2 foam fracturing technology in the field.
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