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In unconventional reservoir hydraulic fracturing, using a pump schedule with proppant concentration constant (PCC) instead of the proppant concentration stepwise increasing (PCSI) is considered an innovative approach to reduce operation costs and risks. However, the large-scale application of PCC lacks sufficient theoretical support. This study investigates the impact of two pump schedules on proppant transport behavior through visualized proppant transport experiments and the model that couples fracture propagation with proppant transport. The experiments demonstrate that PCC facilitates proppant transport and reduces flow fluctuations in complex fractures, while PCSI enhances the filling of near-well fractures. The proppant concentration (the ratio of proppant volume to fracturing fluid volume) reaches 20 % or when a combination of 40/70-mesh and 20/40-mesh quartz sands is used for injection, the pump schedule influence becomes negligible. An increase in fracture complexity, proppant size, and proppant concentration all lead to a reduced influence of the pump schedule on the dune shape. Numerical simulation reveal that the fracture area and average fracture conductivity is similar for different pump schedules, but PCC yields a slightly larger propped fracture area (ranging from 1 % to 4 %) and results in a more uniform conductivity. PCC could achieve similar fracture filling when the proppant concentration is more than 15 % or there is no significant demand for near-well conductivity. Overall, both two pump schedules have a relatively insignificant impact on the transport process of proppants and the final sand dune shape. By comparing pressure curves during hydraulic fracturing, it was evident that PCC resulted in fewer fluctuations. Analyzing production data from 93 wells with PCSI and 59 wells with PCC, it was observed that PCC enhances production and reduces proppant flowback post-fracturing. This research provides a theoretical foundation for the application of PCC pump schedule in hydraulic fracturing. • Compared the effects of different pump schedule on proppant transport. • Proppant concentration constant and stepwise injection have little difference. • Demonstrated the feasibility of proppant concentration constant injection. • Field tests show proppant concentration constant injection performs equally or better. [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]

Natural gas hydrate is an attractive potential as alternative energy source. The initial studies of natural gas hydrate production test have shown that the hydrate productivity via conventional depressurization is still far to reach the commercial level, hence, hydraulic fracturing has been proposed to stimulate the hydrated formation to enhance production. However, the buried depth of hydrate-bearing sediments is generally shallow, and the cementation of sediments is weak. Whether the hydrate-bearing sediments has adequate and commercially viable fracability is a question yet to be answered. In this study, a novel feasibility evaluation model of hydraulic fracturing in hydrate-bearing sediments is developed based on analytic hierarchy process-entropy method. The fracability index is proposed to evaluate the fracability of hydrate-bearing sediments. Representative samples were built based on the physical and mechanical characteristics of Alaska permafrost, and hydraulic fracturing experiments were carried out to evaluate the feasibility of hydraulic fracturing as a stimulation technique. The results showed that the hydrate-bearing sediments with fracability index >0.72 can form fractures under different fracturing fluid viscosity ratio. For hydrate-bearing sediments with fracability index <0.39, when the fracturing fluid viscosity ratio is 1, no fracture network is formed during hydraulic fracturing. However, when the fracturing fluid viscosity ratio is increased to more than 120, fractures may develop. For the hydrate-bearing sediments with fracability index between 0.39 and 0.72, the results are not promising when fracturing fluid viscosity ratio is 1, however, when fracturing fluid viscosity ratio is more than 120, fractures observed to grow. In general, the results indicate that the samples with high fracability index are sweet spots in hydrate sediments in terms of fracability. At low fracability index values, the viscosity of fracturing fluid has a key role in fracability, where increasing the viscosity will result in higher fracability index. • Fracability of hydrate was analyzed based on theory analysis and experiments. • Hydrate with high fracability index is favorable for hydraulic fracturing. • Increasing fracturing fluid viscosity improves fracability of hydrate. [ABSTRACT FROM AUTHOR]

The Stokes diameter is commonly used to characterize the size of non-spherical particles, but its application is limited to Newtonian fluids. In view of this case, an equivalent hydrodynamic diameter, defined as the effective settlement diameter, has been proposed from force balance for particles settling in non-Newtonian fluids, and an iterative calculation procedure was presented. In the present work, proppant effective settlement diameters falling in non-Newtonian fracturing fluids were studied. Settling velocities of three kinds of proppants falling in glycerol solutions, uncross-linked guar solutions and slick-waters were measured, numerous random repeated experiments were conducted, the corresponding proppant effective settlement diameters were calculated and the relationships between proppant effective settlement diameter and their sieve diameter falling in different fluids were studied. Results indicate that the proppant effective settlement diameter falling in uncross-linked guar solutions is bigger than that in glycerol, while it is smaller for slick-waters. When proppants settle in glycerol solutions, the proppants effective settling diameters are constantly 1.24 times bigger than their corresponding sieve diameter. For proppants settling in uncross-linked guar solutions and slick-waters respectively, two sigmoid curves of diameter ratio are obtained followed by reaching an asymptotic value, 1. This work presented a new calculation procedure of equivalent hydrodynamic diameter for non-spherical particles settling in non-Newtonian fluids. The effective settlement diameter extends the application conditions of Stokes diameter to non-Newtonian fluids and can be used in wider engineering applications. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing (HF) has been proved to be a promising technology to achieve economic production of hydrate. However, the research on HF of hydrate reservoirs is at its initial stage with limited information being available. In particular, the mechanism of fracture propagation in hydrate reservoirs is not well understood and requires further investigations. In this study, a new coupled thermo-hydrologic-mechanical-damage (THMD) model for HF simulations in hydrate reservoirs is proposed. Damage mechanics theory is used as the criterion of hydraulic fracture initiation and propagation, and the variation of hydrate properties due to hydrate phase transformation is considered in this THMD coupled model. The influence of hydrate saturation, reservoir permeability, fracturing fluid viscosity and fluid injection rate on HF were analyzed, and the mechanism of fracture initiation and propagation during HF in hydrate reservoir was revealed for the first time. The results showed that fracturing fluid destroys phase equilibria and causes hydrate dissociation, which in turn, releases the pore spaces occupied by hydrate, resulting in the increase of reservoir permeability near fracture surface. Besides, the hydrate dissociation reduces its cementation on sediment particles, causing the decrease of cohesion near the fracture surface. The fracture initiates and propagates perpendicularly to the direction of minimum principle field stress. Hydrate dissociation leads to heterogeneity of reservoir physico-mechanical properties, resulting in a irregular fracture surface morphology. Enhancing the fracturing fluid viscosity and injection rate promotes to improve the reservoir pore pressure and inhibit methane hydrate dissociation, which is beneficial to increase the fracture length. The hydrate reservoir with high methane hydrate saturation and low permeability is conductive to form long fractures during HF. • A new thermo-hydrologic-mechanical-damage (THMD) coupling model is proposed. • The dynamic property of reservoir caused by hydrate decomposition and damage is considered. • The mechanism of fracture initiation and propagation during hydraulic fracturing is revealed. [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 realize the effective extraction of high-temperature thermal energy in enhanced geothermal system (EGS), it is necessary to explore how to efficiently construct fracture network in hot dry rock (HDR). Considering the cryogenic induced thermal stress, we investigate the cracking mechanism when using supercritical CO 2 (SCCO 2) and hydraulic fracturing to stimulate HDR. Firstly, the established three-dimensional THMD coupling model is verified by conducting high temperature granite fracturing experiments. Then, characteristics of the heat and mass transfer and fracture propagation when using SCCO 2 and H 2 O in HDR fracturing are explored. Finally, the cracking mechanism of hydraulic and SCCO 2 fracturing in HDR under thermal stress is revealed. The results indicate that the cryogenic induced thermal stress can reduce the cracking pressure and tend to form branch fractures under the cooperation of injection pressure. Adopting SCCO 2 in HDR fracturing more micro fractures can be generated in near-well zone. Hydraulic fracturing has better cooling efficiency and preferably capability of extending fractures. For HDR fracturing, the scope of fracture network tends to increase first and then decrease with the raise of injection mass flux. The lower viscosity and higher specific heat capacity of fracturing fluid can promote the formation of fracture network. • True-triaxial fracturing tests on granites are conducted under different temperature. • Three-dimensional THMD coupling model is established to simulate hot rock fracturing. • Damage evolution of hydraulic and SCCO 2 fracturing in HDR stimulation is investigated. • Effect of injection mass flux on fracture morphology in HDR fracturing is researched. • Lower viscosity and higher heat capacity of fracturing fluid can promote the formation of EGS. [ABSTRACT FROM AUTHOR]

• In fluence of stress shadow on multi-clusters fracturing was analyzed. • The proppant transport and placement were considered in the model. • Multiple cluster hydraulic fracturing in multiple horizontal wells was simulated. Multiple cluster hydraulic fracturing is widely used in the development of shale reservoir. The morphology of multiple fractures propagating from multiple cluster is complex due to the stress shadow effect. The design and operation of multiple cluster hydraulic fracturing in horizontal wells require adequate knowledge of the effect of different factors, including rock properties, in-situ stresses and fluid properties on the fracture morphology. In this paper, lattice simulation, a new particle based computational method was used to investigate the multiple cluster hydraulic fracturing in shale. The results showed that stress anisotropy and cluster spacing play an important role on geometry of the propagating fracture. The middle hydraulic fracture is restricted to propagate when cluster spacing is decreased. Simultaneous, two-step and sequential fracturing scenarios in a single horizontal well were simulated. The simultaneous and sequential fracturing showed to mainly affect the fracture propagation morphology with little effect on fracture length, while the middle fracture is shorter than its two side fractures in two-step fracturing. In two horizontal models, the simultaneous and sequential fractures showed similar morphology during multiple cluster hydraulic fracturing. In term of stimulated reservoir volume (SRV), zipper fracturing showed the largest SRV during multiple cluster hydraulic fracturing in two horizontal wells. [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]