Limited-entry fracturing (LEF) technology is a widely used method to realize the simultaneous propagation of multiple fractures in horizontal wells. The key of this technology is to create high perforation friction to maintain the high treatment pressure in the wellbore and realize the uniform fluid entry of multi-fractures; however, high perforation friction cannot be effectively maintained due to the serious perforation erosion effect. Considering that the current laboratory studies mostly used small fluid injection flowrate, low injection pressure, and small proppant dosage, this study has developed a field-scale flow system to investigate the effect of various factors on perforation erosion under real field conditions. The filed-scale flow system uses the real fracturing trucks, proppant, and perforated wellbore, the fluid flow rate through perforation could reach 200 m/s and the injection pressure could reach 105 MPa. The effects of different parameters, such as injection flow rates, proppant concentration, proppant type, proppant size, and carrying fluid viscosity, on the perforation erosion were investigated. The experimental results show that: (1) The perforation friction during erosion goes through two stages, i.e., the roundness erosion stage and the diameter erosion stage. The reduction of perforating friction mainly occurred in the first stage, which was completed after injecting 1 m3 proppant. (2) After erosion, the perforation changes from the original circular shape to a trumpet shape, the inner diameter is much larger than the outer diameter. (3) The more serious perforation erosion is caused by the conditions of high injection flow rate, large proppant size, using ceramic proppant, and low viscosity fluid. The findings of this study can help for a better understanding of perforation erosion during the limited-entry fracturing in the horizontal wells, and also could promote the establishment of a theoretical model of perforation erosion under the field-scale conditions.

In the past decade, significant advances in reservoir stimulation and enhanced oil recovery technologies have resulted in rapid production growth in unconventional reservoirs

To realize the effective profile control of a heavy oil reservoir, hydrolyzed polyacrylamide (HPAM) and water-soluble phenol-formaldehyde resin (PR) were chosen to prepare the profile control system, which gelled at medium or low temperatures and existed stably at high temperatures in the meantime. The effects of phenolic ratios, PR concentration, and HPAM concentration on the formation and strength of the gels were systematically studied by the gel-strength code method and rheological measurements. And the microstructure of the gels was investigated by scanning electron microscope measurements. The results showed that the gelling time of the HPAM-PR system was 13 h at 70 °C. The formed gel could stay stable for 90 days at 140 °C. In addition, the gels showed viscoelastic properties, and the viscosity reached 18,000 mPa·s under a 1.5 s⁻¹ shearing rate due to their three-dimensional cellular network structure. The formation of the gels was attributable to the hydroxyl groups of the PR crosslinking agent, which could undergo the dehydration condensation reaction with amide groups under non-acidic conditions and form intermolecular crosslinking with HPAM molecules. And the organic crosslinker gel system could maintain stability at higher temperatures because covalent bonds formed between molecules.