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Abstract The SRV fracturing is the core of commercial exploitation of shale gas, and the design philosophy of the SRV fracturing is gradually introduced into the stimulation of conventional low permeability reservoir and unconventional reservoir. However, in reservoirs with poorly developed natural fractures or high horizontal principal stress difference, it is difficult to achieve the multi-fracture or fracture network by conventional hydraulic fracturing, and effectively stimulating reservoir needs other assisting methods. This paper aims to present a method of guiding the multi-directional hydraulic fractures by multiple radial slim holes drilled in spatial positions, and creating multi-fractures and even complex fracture network. In this paper, a 3D hydraulic fracturing extended finite element numerical model in the vertical well assisted by planar multi-radial slim holes was established, and the effect of radial slim hole number, diameter, length, vertical density, azimuth and phase angle, Poisson's ratio, horizontal principal stress difference and rock Young's modulus, fracturing fluid viscosity and injection rate, reservoir permeability, etc. on guidance of radial slim holes were investigated. Then, we conducted the true tri-axial hydraulic fracturing test with the artificial core, and the feasibility of the technology was verified. The results show that decreasing azimuth and phase angle and increasing hole diameter, length and vertical density strengthen the guiding effect of planar multi-radial slim holes, and increasing Poisson's ratio, reservoir permeability, and fracturing fluid injection rate and viscosity enhance the guidance effect of radial slim holes. Increasing horizontal principal stress difference and reservoir Young's modulus weaken the radial slim holes guiding effect. The physical modeling experiment proves that controlling generation of complex multi-fractures is feasible by rationally arranging the spatial positions of radial slim holes. The spatial arrangement of four planar radial slim holes with phase angle of 90°, azimuth of 45° and vertical density not less than 2 holes/m in the vertical well is a scientific scheme. With the reasonable treatment scheme, creating 6 main fractures is possible. The research results provide theoretical support for multi-fractured stimulation assisted by planar multi-radial slim holes, and help the design of well completion parameters and fracturing treatment parameters of the technology. Highlights • The new multi-fractured stimulation technique for hydraulic fracturing was put forward. • Stimulation experiments of radial slim holes-assisted hydraulic fracturing were carried out. • The effects of multiple factors on the guiding strength of radial slim holes were studied. • The best technical solution for radial slim holes-assisted hydraulic fracturing was proposed. [ABSTRACT FROM AUTHOR]

The conventional hydraulic fracturing fails in the target oil/gas zone (remaining oil, closed reservoir, etc.) which is not located in the azimuth of maximum horizontal stress of available wellbores. The technology of directional propagation of hydraulic fracture guided by vertical multi-radial slim holes is innovatively developed. In order to verify this technology, lots of true triaxial hydraulic fracturing simulation experiments were carried out with artificial cores, aiming at investigating the influence of in-situ stress, fracturing fluid displacement, and azimuth, diameter, number, and spacing of radial slim holes on fracture propagation. The results show that directional propagation of hydraulic fractures guided by vertical multi-radial slim holes is feasible. Regardless of varied radial slim hole and in-situ stress parameters, hydraulic fracture always initiates in the heel of radial slim hole. For hydraulic fracturing assisted by single radial slim hole, smaller horizontal stress difference (3 MPa, σ H /σ h  = 1.25) and smaller radial slim hole azimuth (15°) may guide propagation of hydraulic fractures along radial slim hole, and larger horizontal stress difference (6 MPa, σ H /σ h  = 1.67) can sharply reduce guidance of radial slim hole. Affected by mutual interference from guidance of radial slim holes and controlling of horizontal in-situ stress, fractures tend to distort along fracture length and fracture height. For hydraulic fracturing assisted by vertical multi-radial slim holes, horizontal stress difference is one of key factors influencing the directional propagation effect of hydraulic fracture. Larger horizontal in-situ stress difference (>6 MPa, σ H /σ h  > 1.67) hardly results in directional propagation of hydraulic fracture along radial slim hole row, and creates bigger diversion angle of fracture, and larger azimuth (>45°) of radial slim hole row reduces the guidance strength, resulting small fracture diversion radius. In conditions of larger angle between target zone and maximum horizontal stress, and requirement of large azimuth of radial slim hole row, the effective hydraulic fracture propagation along radial slim holes and ideal fracture height will be achieved through human intervention, e.g. increment of the number and diameter of radial slim holes, reduction of radial slim holes spacing, increment of fracturing fluid displacement, etc. The simulation results provide methods for designing directional propagation of hydraulic fractures guided by vertical multi-radial slim holes. [ABSTRACT FROM AUTHOR]

The clear mechanism of hydraulic fracture propagation in glutenite reservoirs with high heterogeneity is still not obtained, thus it is difficult to carry out the design of fracturing plan effectively. Based on the characteristics of the glutenite reservoirs, a coupled flow-stress-damage (FSD) model of hydraulic fracture propagation with gravels is established. This model is experimentally verified and the research on the influence of rock physical parameters and gravel property on the hydraulic fracture propagation is conducted. It is shown that as the gravel tensile strength increases, the hydraulic fracture is prone to propagate around the gravel, where the fracture deflection always occurs; as the gravel Young's modulus increases, there is high probability that hydraulic fracture propagates around the gravel, with more obvious fracture deflection; the matrix permeability influences fracture propagating morphology when encountering gravel and total fracture length; the horizontal geostress difference seriously impacts the fracture deflection; as the fracturing fluids injection displacement increases, the fracture is prone to deflect when encountering gravel; the low viscosity fracturing fluids result in the shorter fracture; the larger gravel increases the possibility of fracture deflection; in case of smaller gravel sizes, the increasing gravel content has a big influence on fracture deflection, and the increasing content of large gravel complicates the fracture morphology, resulting in the fine branched fractures; for the well rounded gravel, the fracture propagation around the gravel is prone to occur, and the fracture is not prone to deflect. Compared with the conventional sandstone reservoir, the glutenite reservoirs have higher breakdown and extension pressures, which fluctuate due to the gravel; the larger gravel size results in higher extension pressure. In this paper, a simulation method of hydraulic fracture propagation in the glutenite reservoirs is introduced, and the result provides the theoretical support for prediction of fracture propagation morphology and plan design of hydraulic fracturing in the glutenite reservoirs. [ABSTRACT FROM AUTHOR]

In order to study the effects of different parameters in hydraulic fracturing on formation temperature after low-temperature fracturing fluid is injected into high-temperature reservoir, in this paper, considering (1) osmotic pressure and capillary pressure (2) microthermal effect (heat conduction, heat convection, heat expansion, viscous dissipation) (3) the coupling processes of temperature (T), hydraulic, (H) mechanical (M) and chemical (C) in hydraulic fracturing process, and the coupled temperature prediction model of oil-water two-phase THMC based on discrete fractures is established. The effects of fracturing fluid temperature, reservoir temperature, dimensionless conductivity, Young's modulus, injection rate, cluster spacing, and proportion of branch fracture area on reservoir and fracture temperature during the pumping and shut-in stages of shale oil reservoir were studied. The results show (1) For formations with different reservoir temperatures, the temperature drop at the fracture was approximately 97% from the start of the operation to the end of the 30-day shut-in. The saturation change caused by fracturing fluid filtration is much larger than the temperature change caused by heat transfer, and it is found that the temperature and saturation change mainly occur in the early shut-in period (2) Imbibition accelerates the filtration loss of fracturing fluid. During pumping, the bottom hole temperature with imbibition considered is lower than that without imbibition considered. The temperature curve with imbibition considered begins to deviate about 10 min after pumping, but the final temperature tends to be the same, (3) When the fracturing fluid is pumped at high pressure, the fracture and matrix will be deformed, which will improve the porosity and permeability of the near well zone, thus speeding up the heat transfer rate. The high Young's modulus inhibits the increase of permeability. Compared with the young's modulus of 40 GPa and 20 GPa, the increase of permeability decreases by 9% (4) When the well was shut in for 30 days, the cluster spacing was greater than 20 m, and the temperature change around the fracture did not affect the clusters on both sides. The spacing between the clusters was 5 m, and the perforation clusters on both sides had a significant effect on the temperature. The temperature of the reservoir between the two adjacent clusters dropped from 393 K to 385 K. When there is a branch fracture, the small cluster spacing is equivalent to increasing the complexity of the fracture and accelerating the initial heat transfer rate. (5) High injection temperature, high dimensionless conductivity, low Young's modulus and low pumping rate are conducive to the heat transfer of fracturing fluid in the formation. • Based on the discrete fracture model, the temperature prediction model of oil-water two-phase flow was established. Considering the capillary force and osmotic pressure, the temperature (T) -hydraulic (H) -mechanical (M) -chemical (C) was realized. The finite element method is used to solve the model. • The effects of multiple factors on reservoir and fracture temperature during fracturing pumping and shut-in stages are analyzed. [ABSTRACT FROM AUTHOR]

There is a wealth of experimental evidence that fracture initiation and breakdown pressures differ depending on in-situ stress status, rock properties, and injection conditions. However, the mechanism is not fully understood from a theoretical modeling perspective. In this study, a fully coupled plain-strain fracture model is proposed to interpret the mechanism of fracture initiation and breakdown pressures. The fracture model consists of fracture initiation and propagation governed by linear elastic fracture mechanics. The effects of wellbore compliance (or compressibility), solid-fluid coupling, and fracture multiscale propagation behavior are fully considered. The solid-fluid coupling equations are solved using the Newton–Raphson iterative method. The explicit time marching method is used to capture the fracture initiation process. An implicit time-stepping with the fracture tip asymptotic solution is used to capture fracture propagation fronts. The model is validated against the analytical solutions of the plane-strain model. Sensitivity analysis demonstrates that the initiation pressure mainly depends on rock properties, especially the fracture toughness. The peak pressure (breakdown pressure) is related to rock properties and injection conditions and usually occurs before the peak of the pressurization rate is reached. It increases with the injection rate, fluid viscosity, Young's modulus, and fracture toughness. The dimensionless inlet flux into the fracture can be used to determine the fracture initiation pressure. The pressurization rate during the fracture initiation stage is constant and can be used to assess wellbore compliance. Using a low injection rate and a low-viscosity fluid is beneficial to capturing the fracture initiation pressure. This study can help understand fracture initiation and propagation and interpret hydraulic fracture initiation and breakdown pressures. • The wellbore compressibility, solid-fluid coupling, and multiscale propagation behavior are considered. • Breakdown pressure is dependent on injection conditions and rock properties. • Fracture initiation pressure and wellbore compliance can be determined by inlet flux and pressurization rate. • Low-viscosity fluid and low injection rate favor investigating fracture initiation process. [ABSTRACT FROM AUTHOR]

Compared with conventional hydrofracturing fluid, SC-CO 2 has the merits of no water sensitivity and effective carbon dioxide storage. At present, the research on the fracture initiation mechanism of SC-CO 2 fracturing is still at the exploring phase. This paper conducts a detailed study on the fracture initiation mechanism of SC-CO 2 fracturing, and establishes a fracture initiation and propagation model of flow-stress-damage coupling according to damage mechanics. A series of numerical simulation studies have been carried out on the rock physical parameters, fracturing construction parameters, natural fracture distribution and other factors that affect the fracture propagation of the reservoir to provide a reference for the SC-CO 2 fracturing construction design. The findings suggest: the lower formation permeability, the less SC-CO 2 filtration loss, and the larger total fracture length and width; SC-CO 2 is easier to improve the reservoir continuity and result in a complex fracture network; The lower the viscosity of SC-CO 2 , the larger total length of fractures, and the more complex the fracture network; As the delivery of pump increases, the width of fracture continues to increase, and the total fracture length decreases; SC-CO 2 has a better effect on communicating natural fractures and porous media, and the fracture network is more complex. • Fracture propagation model with flow-stress-damage (FSD) coupling is developed. • A simulation method of hydraulic fracture propagation in the glutenite reservoirs is introduced. • The model accuracy is validated through comparison between results of physical experiment and numerical simulation. • The effects of multiple factors on fracture propagating in the glutenite reservoirs are analyzed. [ABSTRACT FROM AUTHOR]

As an important part in the process of hydraulic fracturing, fracturing fluid flowback after fracturing will directly affect the productivity of the fractured wells. It is of great significance to carry out optimization research on the flowback working system of fracturing fluid (the time of flowback beginning and the size of flowback nozzles) to enhance the efficiency of fracturing. At present, researches on optimization model of fracturing fluid flowback have taken into account the effects of fracturing fluid loss and proppant reflux, while ignoring the effects of proppant sedimentation. A new calculation model of proppant regurgitation velocity has been established in recent years, but it is rarely used in the research of flowback working system. This study innovatively integrated the calculation model of modified proppant sedimentation velocity obtained through experiments, the new calculation model of critical proppant regurgitation velocity, and the wellhead pressure calculation model to form a comprehensive flowback model of fracturing fluid. Then coupled with the flowback criteria of quickly flowback, reducing proppant reflux, and maintaining proppant settlement degree (ratio of proppant settlement distance to crack height) less than 60%, an optimization model of fracturing fluid flowback is constructed and realized by MATLAB software programs. The optimization model were verified by four fractured wells in DaQing Oilfield. The effects of reservoir permeability, reservoir porosity, fracturing fluid density, and proppant particle size on wellhead pressure drop, fracturing fluid flowback rate, and proppant settlement degree were calculated and analyzed by using the above flowback model. The verification results show that the simulated wellhead pressure and flowback flowrate are in good agreement with the actual dataset, with the average errors of 11.9% and 11.6% respectively, which proves the accuracy of the flowback optimization model. Parametric analysis shows that, with the increase of reservoir permeability and reservoir porosity, the wellhead pressure drop velocity increases. When the permeability increases from 1mD to 5mD, the flowback rate of fracturing fluid and proppant settlement degree are reduced by 12.3% and 69.8% respectively. When the porosity increases from 9% to 36%, the proppant settlement degree fall by 25.2%. Moreover, the flowback rate of fracturing fluid decreases linearly and the proppant settlement degree increases linearly with the increase of fracturing fluid density; and the proppant settlement degree increases by 3.5 times when the proppant particle size increases from 0.25 mm to 1.65 mm. Therefore, choosing smaller fracturing fluid density and smaller proppant particle size can ensure higher fluid flowback efficiency and lower proppant settlement degree. • A new flowback model of fracturing fluid is constructed to optimize the flowback working system, which takes the influence of proppant settling into account. • The optimization model is realized by programming with MATLAB software and its accuracy is verified by four fracturing wells of Daqing Oilfield. • Then the influences of reservoir permeability, reservoir porosity, fracturing fluid density and proppant particle size on the wellhead pressure drop, fracturing fluid flowback rate and proppant settlement degree are clarified. [ABSTRACT FROM AUTHOR]

To understand the fracture behavior for variable density in-plane perforations on a horizontal well, true triaxial hydraulic fracturing experiments were performed with acoustic emission monitoring. The experimental results indicate that the variable density in-plane perforations can not only create transverse fractures but also arrest fracture propagation toward undesirable zones. The in situ stress and treatment parameters play significant roles in the fracture morphology and breakdown pressure. Under a large horizontal principal stress difference, there is a high possibility for simple transverse fracture creation, which results in a lower breakdown pressure. Moreover, the decrease in fracturing fluid viscosity can increase the fracture complexity and increase in pump rate can increase breakdown pressure and induce the complex fracture geomtetry. The acoustic emission (AE) characteristics and cutting fracture morphology demonstrate that not all perforations can be successfully initiated during the fracturing process. Because of the stress interaction from side perforations, fracture initiation and propagation from the middle perforation are strongly suppressed. Although the middle fracture is not fully initiated and propagated, it is still beneficial for the side hydraulic fracture connection and propagation in one plane. Secondary and axial fractures can still be observed, primarily due to the stress interaction between neighboring perforations and misalignment of the perforation tunnel orientation with the principal stress direction. In addition, the creation of complex fractures tends to occur using a high pump rate, which relates to tense fluid distribution competition from each perforation tunnel. Fracture initiation may follow an order but mostly tends to initiate from side perforations. Because of the stress interaction, hydraulic fractures from the side perforation can sometimes deviate from the perforation tunnel direction, twist and kink, and finally, generate nonplanar fractures. A large horizontal principal stress difference is recommended and beneficial for simple, straight and planar fracture creation during hydraulic fracturing stimulation with variable density in-plane completion for the horizontal well. • The application of local in-plane perforations can control the fracture path and complexity. • Tri-axial fracturing experiments were conducted on tight rock samples with local in-plane perforations. • The change in fracturing fluid viscosity and pump rate can alter the fracture path between perforations. • The connectivity of neighboring fractures can lower the breakdown pressure. [ABSTRACT FROM AUTHOR]