Hydraulic fracturing fracture propagation is the main factor affecting the fracturing effect. In view of the more diversified selection of fracturing fluid, the problem of fracture propagation in non-Newtonian fluid fracturing is often encountered in fracturing. In this paper, the influencing factors of fracture propagation of non-Newtonian fluid fracturing fluid are analyzed. Based on PKN model, a threedimensional fracture propagation model considering the rheology and filtration of fracturing fluid is established, the better fracture shape simulation results are given, and the effects of fluid properties, rock physical properties, and injection parameters on fracture propagation are analyzed in detail. The research shows that (1) in the process of fracture propagation, the fracture length and width gradually increase, and the corresponding pressure in the fracture also increases. The overall increase trend is that the growth is rapid in the initial stage of fracturing and gradually slows down in the later stage.(2) The greater the consistency coefficient and rheological index, the greater the fracture width and pressure in the fracture, and the easier it is to form wide fracture. The larger the filtration coefficient is, the weaker the fracture forming ability is, and the fracture width, length, and pressure in the fracture are reduced. (3) Rock physical properties have a certain influence on fracture propagation, Young's modulus has a great influence on fracture propagation, while Poisson's ratio has little influence on it. However, the larger the Young's modulus, the more difficult the fracture is to expand, and the smaller the corresponding fracture width. (4) The larger the pump injection rate, the larger the fracture size and the higher the pressure in the fracture. The model can provide a theoretical basis for fracturing design and fracture shape prediction.
Horizontal well gravel packing is the most commonly used sand control technology in offshore oil and gas fields. For extreme conditions such as deepwater, low fracture pressure formations, and long horizontal well bore length, targeted and cost-effective measures are required. According to the friction models in different stages of gravel packing process of horizontal well, the corresponding friction is calculated and compared. According to the calculation, during the entire packing process, the washpipe/screen annular friction is the largest in β wave packing stage, which reflects that higher packing pressure is required in this stage, and the formation fracture pressure is easily broken at this stage. According to the equilibrium flow velocity, the calculation method and flow chart of α -wave sand bed height were put forward. The criterion and calculation method of packing length were designed. The influencing factors of viscosity, density and leakage rate of carrier fluid on α-wave packing length were discussed. The quantitative analysis was carried out. The design and calculation method of α-β wave packing length considering the successful completion of α wave packing and the successful completion of β wave reverse packing was put forward. The corresponding software was compiled to discuss and calculate the quantitative analysis of the factors affecting the α-β wave packing length, such as the density of carrier fluid, gravel density and washpipe/screen ratio. For specific conditions, certain criteria and methods can be used to design and optimize horizontal well gravel packing length.
Sand production is a critical issue during the development of offshore oil and gas fields. Certain gas fields (e.g. the AB gas field) have high porosity and high permeability, and with water at the bottom of the reservoir, the risk of sand production greatly increases at high differential pressures. Based on reservoir properties, geological conditions, production requirements, and well logging data, in this study an ultrasonic time difference method, a B index method, and a S index method are used together with a model of rock mass failure (accounting for water influx and pressure depletion) to qualitatively predict sand production. The results show that considered sample gas field has an overall high risk of sand production. The critical differential pressure (CDP) without water influx is in the range of 1.40 to 2.35 MPa, the CDP after water influx is from 0.60 to 1.41MPa. The CDP under pressure depletion is in the range of 1.20 to 1.92 MPa. The differential pressure charts of sand production are plotted, and the safe differential pressure windows with or without water influx are obtained. The model calculation results and the experimental results are consistent with the field production data, which indicates that the implemented prediction method could be taken as a reference for sand production prediction in similar deep water gas fields.
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