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Multistage hydraulic fracturing has been proven to be an effective stimulation method to extract more oil from the depleted unconsolidated sandstone reservoirs in Bohai Bay, China. The offshore wellbores in this area were completed with a gravel pack screen that is much too difficult to be mechanically isolated in several stages. Hydra-jet fracturing technology has the advantages of multistage fracturing by one trip, waterjet perforation, and hydraulic isolation. The challenges of hydraulic-jet fracturing in offshore unconsolidated sandstone reservoir can be summarized as follows: the long jet distance, high filtration loss, and large pumping rate. This paper proposes full-scale experiments on the waterjet perforation of unconsolidated sandstone, waterjet penetration of screen liners and casing, and pumping pressure prediction. The results verified that multistage hydra-jet fracturing is a robust technology that can create multiple fractures in offshore unconsolidated sandstone. Lab experiments indicate that the abrasive water jet is capable to perforate the screen-casing in less than one minute with an over 10 mm diameter hole. The water jet perforates a deep and slim hole in unconsolidated sandstone by using less than 20 MPa pumping pressure. Recommended perforating parameters: maintain 7% sand concentration and perforate for 3.0 min. Reduce sand ratio to 5%, maintain 3.0 m3/min flow rate, and continue perforating for 7.0 min. The injection drop of the nozzle accounts for more than 62% of the tubing pump pressure. The recommended nozzle combinations for different fracturing flow rates are 8 × ø6 mm or 6 × ø7 mm for 2.5 m3/min and 3.0 m3/min, and 8 × ø7 mm for 3.5 m3/min and 4.0 m3/min. A one-trip-multistage hydra-jet fracturing process is recommended to be used for horizontal wells in offshore unconsolidated sandstone reservoirs. [ABSTRACT FROM AUTHOR]

Machine learning has been widely used for the production forecasting of oil and gas fields due to its low computational cost. This paper studies the productivity prediction of shale gas wells with hydraulic fracturing in the Changning area, Sichuan Basin. Four different methods, including multiple linear regression (MLR), support vector machine (SVM), random forest (RF) and artificial neural network (ANN) are used, and their performances are compared by the value of the mean absolute percentage error to determine the best method of all. The training and validation results show that the MLR and SVM methods exhibit poor performances with relatively high errors (> 15%), while the ANN and RF methods show obviously better results, where the RF has a median error (~12%) and the ANN has the smallest error (<10%). After the production forecasting, the particle swarm optimization is implemented as a parameter optimization approach to improve the gas production, which can be increased by around two times after optimization. This study provides a guideline for the shale gas production via hydraulic fracturing in the Changning area. Article Highlights: Machine learning algorithms are used to predict the shale gas production by hydraulic fracturing in Changning area. An integrated data set that includes geological and engineering parameters as well as recorded production rates are used. Productivity can be substantially improved by optimizing fracturing parameters using particle swarm optimization. [ABSTRACT FROM AUTHOR]

The transport and placement characteristics of proppant in rough fracture is of great significance for optimizing fracturing parameters and making proppant transport to the deep part of fracture for effective support. This paper scans the surface morphology of rock samples after fracturing, generates rough fracture based on the scanned data, and uses high-order interpolation function to generate fracture with different roughness, and establishes a numerical model of proppant transport in different roughness based on Euler-Euler two-phase flow model. The effects of different fracture roughness, fluid velocity, proppant size, proppant density and carrying fluid viscosity on the transport pattern and placement characteristics of proppant were compared and analyzed. The results show that: (1) The complex spatial structure of rough fracture hinders the transport of proppant and makes the placement of proppant in fracture uneven, with the characteristics of tortuous and variable; Compared with smooth fracture, the equilibrium height of proppant in rough fracture is higher, and more settlement at the front end of fracture is easy to cause sand plugging; (2) Higher fluid velocity, smaller density and size are conducive to the transport of proppant in rough fracture, which is not easy to cause sand plugging, and can make proppant be carried to the deep part of fracture for effective support (3) Increasing the viscosity of carrying fluid and reducing the size of proppant can significantly improve the sand carrying performance of fluid, and smaller proppant size can better pass through branch fracture. Compared with changing other process parameters, changing the viscosity of carrying fluid and proppant size has more significant effect. But in the field fracturing process, increasing the viscosity of carrying fluid is easier to achieve, so in the hydraulic fracturing process design, the viscosity of carrying fluid should be considered first, and 70% of dimensionless equilibrium height in rough fracture should be used as the critical point to evaluate sand carrying efficiency. Exceeding 70% is easy to cause sand plugging. Optimize fracturing parameters. It is recommended that fluid velocity should be greater than 0.2 m/s, proppant size should be less than 0.32 mm, proppant density should be less than 2600 kg/m3, and carrying fluid viscosity should be greater than 2 mPa s in field fracturing construction. (4) Proppant is placed in main fracture first in multi-cluster rough branch fracture, and then carried into branch fracture after reaching a certain height. It shows symmetrical distribution in branch fracture. It is suggested that smaller proppant size should be selected first in field fracturing construction process to enter branch fracture for effective support. The research results provide theoretical basis for realizing efficient filling of proppant in the deep part of fracture and optimizing fracturing parameters. [ABSTRACT FROM AUTHOR]

Improving the resolution and accuracy of the mechanical properties of organic-rich shale is very important. The results can reveal the mechanical properties of shale from micro scale and serve as a guide for the design of hydraulic fracture optimization parameters. This study introduced an advanced technique to obtain the mechanical properties of shale with high resolution (58.6 nm/pixel) by combining SEM, EDS, and Atomic Force Microscopy (AFM). To locate the target area in SEM and AFM accurately, a positioning technique that uses special distributions of pyrite was established. AFM PeakForce QNM mode was selected due to its advantages at capturing topography and mechanical properties in material. Results illustrated the ability of AFM to obtain the mechanical properties (modulus) of individual mineral components in shale, the detailed topography of crack, and mechanical properties of minerals in a specific area. In particular, the mechanical properties of minerals around crack explained the layered distribution of minerals around the fractures, and the cracks developed in the clay mineral layer was detected. This article demonstrates the great potential application of AFM in shale. [ABSTRACT FROM AUTHOR]

The aim of the present study is to help understand hydraulic fracture propagation in shale formations through numerical simulations. The hydraulic fracture propagation regime in shale is analyzed considering the anisotropic nature of the shale rock formation and slick-water fracturing fluid. It is determined that the dominant mechanism of hydraulic fracture propagation is the so-called transitional regime that is characterized by a negligibly small fluid lag region and zero fluid front pressure. For the modeling of the hydraulic fracture evolution over time, we assume orthotropic linear-elastic rock media and that the flow of the fracturing fluid is governed by the Reynold's lubrication equation. For the discretization of the coupled solid-fluid equations within the 2D plane-strain context we use the extended finite element method for the rock media and the finite volume method for the lubrication equation. The problem of the hydraulic fracture evolution over time is modeled as stable quasi-static crack growth where time is the result of upholding the mass conservation principle between the fluid inflow and the crack volume. The Picard iterative approach is used to solve the discrete non-linearly coupled solid-fluid equations. Our model is verified against several analytical solutions. Subsequently, a five-stage hydraulic fracturing problem is simulated to study the interactions between the different fractures. Results show that the on-going hydraulic fractures are attracted by the pre-existing hydraulic fractures as a result of the change of the local stress field relative to the initial in-situ stress field. For the cases considered, fracture deflections are found to be most extensive with decreasing fracture spacing and in-situ stress difference, but insensitive with the increasing the ratio of Young's moduli. [ABSTRACT FROM AUTHOR]

Understanding spontaneous imbibition of fracturing fluid in shale is critical for hydraulic fracturing design and optimization. In this paper, we present an analytical model for spontaneous imbibition including a hysteretic relative permeability-saturation-capillary pressure ( k - S - P ) relation and evaluate the relevance of hysteresis effect when modelling fracturing fluid imbibition. In the hysteretic formulations, capillary pressure and relative permeability depend not only on the current saturation but also on the history of saturation in the invaded zone. Herein, we concentrate on fracturing fluid imbibition into shale matrix during shut-in time after refracture treatment, which is driven by the strong capillary forces present in the tight matrix. We demonstrate the importance of accounting for the hysteresis in capillary pressure and relative permeability for predicting the imbibed volume of a fracturing fluid. For a problem that involves drainage and imbibition cycles, a hysteretic k - S - P relation is required to accurately assess the distribution of fluid saturation in the invaded zone. We also demonstrate that although the difference in viscosity between the fracturing fluid and gas is large, the viscosity of the gas cannot be neglected in modelling fracturing fluid imbibition in shale. The results of this investigation are expected to provide a better understanding of fracturing fluid imbibition in shale. [ABSTRACT FROM AUTHOR]

• An experimental approach of cyclic shear friction on granite fracture was proposed. • Frequency dependencies of cyclic shear friction was found. • High frequency shear friction accelerates jumping shear and fatigue failure. Cyclic hydraulic fracturing has been proved to be an effective stimulation technique to explore EGS resouces. The shear friction behaviors under cyclic normal stress are essential to understand the hydro-shearing mechanisms. This paper proposed a cyclic shear friction test to understand the friction characteristics of granite fracture during cyclic hydraulic fracturing. A cyclic normal force in sinusoidal function and a constant shear velocity were enforced on the rock specimen. The time-dependent friction behaviors were observed. Results indicate that the frictional coefficient is highly correlated with the variation of the normal force. Futhermore, the frequency dependency of cyclic shear friction was observed. High-frequency normal force motivates a lower frictional shear slip. However, the amplitude of normal force displays an irregular influence on the frictional coefficient. Microstructure analysis demonstrated that numerous scratches and a powder-lubrication layer were generated along the sheared asperity between the fracture surfaces. High-frequency shear friction accelerates jumping shear and creates finer powder to lubricate the shear slip. The present work is helpful to understand the mechanisms of cyclic hydraulic fracturing to activiate the existing natural fractures. [ABSTRACT FROM AUTHOR]

Flow-rate fluctuation cannot be avoided for high pressure pump group on surface during fracturing pumping. The hydrajet perforation string moves along wellbore axis with the flow-rate fluctuation, which causes the penetration shape is not a circle, but an ellipse with major axis in wellbore direction. In the paper, an evaluation model for hydra-jet perforation shape was built based on the linear elasticity deformation and abrasive jet cutting theory. In order to judge whether the casing is penetrated, we proposed the compute scheme of the jet coordinates at each time and cutting depth. Assuming the pumping flowrate is of uniform statistical distribution within fluctuation region, the results show that the major axis of ellipse hole is proportional to the range of pumping fluctuation in vertical wells. If pumping flow-rate fluctuation is below ±0.04 m3/min, the ratio of major axis to minor axis of the ellipse hole would be less than 2.0, which can satisfy the pin-point perforation. Therefore, the paper recommends the flow-rate fluctuation needs to be controlled in the range of ±0.04 m³/min. [ABSTRACT FROM AUTHOR]

Perforation is critical to create a flow pathway between a shale reservoir and the production casing for hydraulic fracturing. However, the damage characteristics of shales by abrasive waterjet (AWJ) remain unclear. To address this concern, AWJ experiment is conducted for three types of shale with different mineral compositions, including siliceous shale, calcareous shale, and carbonaceous shale. X-ray diffractometry measures the content of mineral components. A rock mechanics test system obtains the main physical and mechanical parameters of shale samples. Scanning electron microscope (SEM) and acoustic emission (AE) are used to analyze the damage characteristics. The results indicate that siliceous shale with more brittle minerals is beneficial for the AWJ to create a larger perforation effectively, while carbonaceous shale with more clay minerals significantly lowers AWJ performance. For the shale with more brittle minerals, abrasive erosion and matrix spallation govern shale failures. As the clay content increases, the primary rock damage is abrasive cutting leading to the transgranular fracture. AE signals induced by AWJ impact could reflect breaking mechanisms and identify the difference in shale lithology. The energy dissipation gradually reduces during the AWJ process. Also, the dissipation has a negative linear correlation with the content of brittle minerals. This study provides fundamental insight into understanding shale damage by AWJ impact to optimize the perforation scheme. • Shale impacted by abrasive waterjet is experimentally investigated. • Abrasive waterjet performance, failure characteristics, and AE response are analyzed for three types of shales. • Siliceous shale contained high brittle minerals is a rational target for AWJ. • A linear fitting models are obtained between the shale mineral components and energy dissipation of AE signal. [ABSTRACT FROM AUTHOR]

• A phase field framework is applied to investigate hydraulic fracturing in layered media. • No penetration criteria are required atmaterial interfaces. • Hydraulic fractures in the soft to stiff and stiff to soft configurations are investigated. • Different inclination angles of the layer interface are included. • The penetration, singly-deflected, and doubly-deflected scenarios can be predicted by phase field modeling. In the hydraulic fracturing of natural rocks, understanding and predicting crack penetrations into the neighboring layers is crucial and relevant in terms of cost-efficiency in engineering and environmental protection. This study constitutes a phase field framework to examine hydraulic fracture propagation in naturally-layered porous media. Biot's poroelasticity theory is used to couple the displacement and flow field, while a phase field method helps characterize fracture growth behavior. Additional fracture criteria are not required and fracture propagation is governed by the equation of phase field evolution. Thus, penetration criteria are not required when hydraulic fractures reach the material interfaces. The phase field method is implemented within a staggered scheme that sequentially solves the displacement, phase field, and fluid pressure. We consider the soft-to-stiff and the stiff-to-soft configurations, where the layer interface exhibits different inclination angles θ. Penetration, singly-deflected, and doubly-deflected fracture scenarios can be predicted by our simulations. In the soft-to-stiff configuration, θ = 0 ° exhibits penetration or symmetrical doubly-deflected scenarios, and θ = 15 ° exhibits singly-deflected or asymmetric doubly-deflected scenarios. Only the singly-deflected scenario is obtained for θ = 30 °. In the stiff-to-soft configuration, only the penetration scenario is obtained with widening fractures when hydraulic fractures penetrate into the soft layer. [ABSTRACT FROM AUTHOR]

Abstract Numerous micro-seismic and laboratorial studies show that hydraulic fracture is usually with complex geometries, such as plugged fracture, asymmetry and non-plane. It is a challenging task to recognize the complex fracture and obtain reliable fracture parameters through transient pressure analysis. In this work, we extend the semi-analytical model by Zhou et al. (2013) to analyze transient pressure behavior of a fractured vertical well with complex fracture geometries. We verified the semi-analytical model by a numerical reservoir simulator on a planar fracture. Then, based on this model, we made a systematical discussion about the transient pressure behavior of the planar fracture with varying conductivity, asymmetric fracture and non-planar fracture. Results show that when the fracture conductivity is varying along the fracture path, the influence of fracture zone conductivity on the transient pressure behavior gradually decreases with the distance from the wellbore growing. Besides, we found that the fracture asymmetry is against for the fluid flow in the fracture, and it decreases the slope of transient pressure behavior curve and enlarge pressure drop. In addition, the non-planar fracture is usually with severe fracture width restriction around the wellbore, which will induce pseudo-radial flow in the fracture at early times and large pressure drop in the fracture. Furthermore, the influences of varying conductivity, fracture asymmetry and non-plane on transient pressure behavior are obvious for fracture with average small-to-middle conductivity (average dimensionless fracture conductivity ranging from 0.1 to 50); the influences become negotiable for fracture with average high-to-infinite conductivity (average dimensionless fracture conductivity ranging from 50 to 1000). This work can provide critical insights into understanding the effect of complex fracture geometry on transient pressure behavior of fractured vertical well in tight oil reservoir. Highlights • A semi-analytical model for transient pressure behavior of fracture with complex geometries was developed. • Non-planar fracture was handled easily using the semi-analytical model. • Influences of varying fracture conductivity, fracture asymmetry and non-planar fracture were investigated. [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]

Hydraulic fracturing is widely applied to develop tight oil reservoirs, and it is significant to diagnose fracture hit to determine optimal well spacing. Pressure test is an effective method to determine fracture hit in a multi-well system. In this study, we developed a semi-analytical model to quickly identify fracture hit in multiple vertical well system in tight oil reservoir. This semi-analytical model involves several steps, i.e., prior production step of parent wells, pressure build-up step, and interference test step. The model was verified by a numerical reservoir simulator for single well and multiple wells. Then, based on the model, the well interference by fracture hit in a three-well system (two parent wells and one child well) is discussed. Results show that the developed semi-analytical model could efficiently simulate the entire production process of a multi-well system, quickly diagnose fracture hit by using pressure interference test data and determine the optimal shut-in time of parent well. The practicability of model lies in that the reservoir pressure depletion by prior production of parent wells is considered. Besides, it is found shutting down the parent well is very necessary to diagnose fracture hit when the child well is infilled. When the shut-in parent well is connected to producing child well, the pressure build-up process of parent well is terminated with the bottom hole pressure reducing continuously. What is more, the shut-in time of parent wells should be sufficient to better detect the fracture hit, especially under the condition that parent wells have produced for a long time or the connectivity among wells is weak. This work can provide critical insights into understanding the mechanism of well interference by fracture hit in a multi-well system. • A new model to identify fracture interference in a multi-well system was developed. • The model was verified by a numerical reservoir simulator. • The fracture interference in a three-well system was discussed. • Pressure test of well interference through fracture hits was analyzed. [ABSTRACT FROM AUTHOR]