Fracture Width Research Articles

Experiment on proppant transport in near-well area of hydraulic fractures based on PIV/PTV

Particle image velocimetry and laser testing technology are used to test the flow field near the well and the migration mechanism of proppant, and PIV / PTV algorithm is used to calculate the two-phase velocity distribution respectively. The results indicated that the jet from the perforation into the fracture produced a strong swirl, and the large-scale vortex structure dominated the two-phase flow. At a high injection rate, the proppant had a good follow-up to the fluid, whereas it settled and accumulated in the jet area at a low injection rate. As the flow rate, fracture width, and viscosity increased, the area affected by the vortex increased and the proppant was removed. As the pumping time increased, the moving directions of the proppant were concentrated in 0° to 45° and 315° to 360°, and the vorticity in the near-well area was enhanced. • Established a PIV/PTV experiment device to test the proppant and fracturing fluid velocity field. • Characterized by streamline and vorticity, the flow law of fracturing fluid near the wellbore is analyzed. • Revealed the mechanism of proppant migration near the wellbore via the combination of macro and micro.

Compression of Particulate Materials in Wellbore Fractures and Enhancement in the Wellbore Breakdown Limit

Abstract Fluid loss during subterranean drilling often occurs through fractures that develop or preexist around the wellbore. Particulate additives, known as lost circulation material (LCM), are commonly added to the drilling fluid to mitigate lost circulation. The LCM forms an impermeable agglomerate within the fractures while preventing further tensile failure of the wellbore wall. The outcome is enhancement in the wellbore breakdown limit. A semi-analytical elastic solution is developed to estimate the width of near-wellbore fractures that partially close on the LCM agglomerate. The solution uses stress–strain data from confined compression testing on LCMs. The compression test results are modeled through a modified form of Kawakita’s (1971) powder compaction equation. The developed constitutive model is embedded within the described semi-analytical solution for the wellbore fractures. The solution adopts an incremental loading approach to treat the nonlinearities arising from the characterized LCM constitutive behavior, as well as large deformation of the LCM agglomerate within the partially closed fractures. At each incremental load, the nonlocal stress equilibrium along the fracture length is described via an integral equation. Successive solutions to these integral equations determine the unknown fracture width of partially closed fractures. A competition between the fractures tendency for propagation and the wellbore wall tendency for secondary tensile failure determines the overall stability of the fractured wellbore. Mechanical behavior of the LCM agglomerate under compression is identified as a key parameter that controls both mechanisms, thereby, the gain in breakdown limit of a fractured and LCM-treated wellbore.

Coreflooding Evaluation of Fiber-Assisted Recrosslinkable Preformed Particle Gel Using an Open Fracture Model

Summary Recrosslinkable preformed particle gels (RPPGs) have been used to treat the problem of void space conduits (VSC) and repair the “short-circuited” waterflood in Alaska’s West Sak field. Field results showed a 23% increase in success rates over typical preformed particle gel (PPG) treatments. In this paper, we evaluated whether adding fiber into RPPGs can increase the RPPG plugging efficiency and thus further improve the success rate. We designed open fracture models to represent VSC and investigated the effect of swelling ratio (SR), fracture size, and fiber concentration on gel injection pressure, water breakthrough pressure, and permeability reduction. Results show that fiber can increase RPPG strength and delay its initial swelling rate, but an optimized fiber concentration exists. Beyond that, the fiber entangling problem can result in the recrosslinked bulk gel inhomogeneously and impact gel quality. The injection pressure of fiber-assisted RPPGs increased with the SR and fracture width. During post-injection water process, the breakthrough pressure and residual resistance factor increased when the RPPG SR and fracture width decreased. Fiber-assisted RPPGs can dramatically reduce the permeability of the fractured core up to 1.8×106 times. It is observed that the fiber-assisted RPPGs used in the experiment remain in a bulk form in the fracture when we open the fracture after water injection. Not only does the addition of fiber improve the plugging efficiency, but it also prevents particle precipitation along vertical fractures or conduits.

Experimental Study on Particle-Based Temporary Plugging Material Selection and Diversion Law of Shale Gas Reservoirs in WY Area, Sichuan, China

A temporary plugging agent is an effective tool for increasing production in old wells. By considering the temporary plugging materials used in the remote WY area, three concentrations and five ratios under different fracture widths were designed and optimized. Thus, the fracture diversion under true triaxial stress was studied. The results showed that when the fracture widths were 2.0, 4.0, and 6.0 mm, the corresponding optimal plugging scheme was that the concentrations of the temporary plugging agent were 12.0, 18.0, and 18.0 kg/m3 and the ratios of 20–70 mesh to 200–300 mesh temporary plugging agent were 4:1, 2:1 and 4:1, respectively. When maintaining the same horizontal stress, an increase in the axial stress was accompanied by an increase in the fracture pressure; the initial fractures almost propagated along the direction of the horizontal maximum principal stress, but the shapes of the turning fractures were different. When the axial stress was the same, an increase in the horizontal stress difference was accompanied by a decrease in the corresponding fracture pressure and a gradual decrease in the degree of fracture turning. This study provides a basis for numerical simulation and field application of temporary plugging fracturing at fracture ends.

Mechanism and Numerical Simulation of Vertical Fracture Propagation in Composite Coal Rock

Vertical fracture propagation mechanism is important to understand the effect of hydraulic fracturing on the roof of outburst coal seams. In this paper, the differences in physical parameters and in situ stress between an outburst coal seam and its roof strata were compared, and influencing factors of roof-fracturing fractures connecting coal seams were vertically analyzed. The impact of different fracturing strata and injection rates on fracture propagation was studied by numerical models. Results show that the horizontal principal stress of an outburst coal seam is less than that of roof strata, and the fracture length of roof fracturing is larger than that of an outburst coal seam. Roof-fracturing fracture of an outburst coal seam has the material conditions to communicate downward with the coal seam. The downward propagation height of roof-fracturing fracture is positively correlated with the minimum horizontal stress difference between an outburst coal seam and its roof strata. Soft coal fracturing cannot form a long fracture dominated by tensile failure, so the coal seam can be communicated by transforming the roof strata of soft coal to form vertical fractures. The injection rate affects the failure location, fracture width, and fracture-propagation path of the numerical model. Construction parameters should be reasonably designed in accordance with the physical parameters of coal and rock, construction displacement, and in situ stress. These research results can provide a theoretical basis and data support for the design, and optimization of construction parameters of roof fracturing in outburst coal seams.

The Seepage Tensor of the Multiparameter Model of Pipe Element in Fractured Rock Mass

Based on the measured fracture production of the rock body in the field, the disc fracture hypothesis is used to generate three groups of fractures to form a fracture network by the Monte-Carlo method. The three-dimensional fracture network is simplified into a spatial one-dimensional pipe element model based on the hypothesis of water channel flow in the fractures, and the equivalent pipe diameter of the pipe element is considered to be linearly related to the fracture width. The equivalent permeability tensor is obtained by using a genetic algorithm to obtain the ratio of the equivalent pipe diameter to aperture size for each group of fissures, and compared with the equivalent permeability tensor obtained by the overall single-parameter model and direct algorithm. In comparison with the measured permeability tensor, it is concluded that the multiparameter model can better characterize the permeability tensor than the single-parameter model.

The Effect of Bedding Plane Angle on Hydraulic Fracture Propagation in Mineral Heterogeneity Model

The bedding planes of unconventional oil and gas reservoirs are relatively well developed. Bedding planes directly interfere with hydraulic fracture expansion. Determining how bedding planes influence hydraulic fractures is key for understanding the formation and evolution of hydraulic fracturing networks. After conducting X-ray diffraction analysis of shale, we used Python programming to establish a numerical model of mineral heterogeneity with a 0-thickness cohesive element and a bedding plane that was globally embedded. The influence of the bedding-plane angle on hydraulic fracture propagation was studied. Acoustic emission (AE) data were simulated using MATLAB programming to study fracture propagation in detail. The numerical simulation and AE data showed that the propagation paths of hydraulic fractures were determined by the maximum principal stress and bedding plane. Clearer bedding effects were observed with smaller angles between the bedding surface and the maximum principal stress. However, the bedding effect led to continuous bedding slip fractures, which is not conducive to forming a complex fracture network. At moderate bedding plane angles, cross-layer and bedding fractures alternately appeared, characteristic of intermittent dislocation fracture and a complex fracture network. During hydraulic fracturing, tensile fractures represented the dominant fracture type and manifested in cross-layer fractures. We observed large fracture widths, which are conducive to proppant migration and filling. However, the shear fractures mostly manifested as bedding slip fractures with small fracture widths. Combining the fracture-network, AE, and fractal dimension data showed that a complex fracture network was most readily generated when the angle between the bedding plane and the maximum principal stress was 30°. The numerical simulation results provide important technical information for fracturing construction, which should support the efficient extraction of unconventional tight oil and gas.

Intelligent calculation method of relative sonic attenuation and its application to fracture evaluation in tight sandstone reservoir

Fractured tight reservoirs have widespread exploration and development prospects. For these types of reservoirs, fractures provide pathways for fluid flow and storage spaces for tight oil and gas, which play a significant role in increasing production. In order to explore a fine fracture evaluation scheme for tight reservoirs, we firstly proposed an intelligent calculation method for the relative sonic attenuation; and then developed a novel semi-quantitative evaluation approach for the equivalent fracture width based on relative sonic attenuation and physical experimental results of the effect of fracture on sonic attenuation. The acoustic experimental results of the models with fractures show that the S-wave relative attenuation coefficients have a good correlation with the fracture attribute parameters. This lays a foundation for the fine fracture evaluation based on attenuation information. Field application results of the intelligent calculation method for relative attenuation and the inversion method for fracture width have been validated by comparing them with results from image logging, S-wave anisotropy estimation, and production test data, which demonstrates the feasibility and correctness of the proposed methods. The investigation depth of the proposed fracture evaluation scheme based on acoustic attenuation is significantly larger than that of the image logging, which provides a new optional scheme for fine fracture evaluation, especially for effective fracture evaluation; and it makes up for the deficiencies of the image logging fracture evaluation method.

Experimental Study on the Hydraulic Fracture Propagation in Inter-Salt Shale Oil Reservoirs

In response to the difficulty of fracture modification in inter-salt shale reservoirs and the unknown pattern of hydraulic fracture expansion, corresponding physical model experiments were conducted to systematically study the effects of fracturing fluid viscosity, ground stress and pumping displacement on hydraulic fracture expansion, and the latest supercritical CO2 fracturing fluid was introduced. The test results show the following. (1) The hydraulic fractures turn and expand when they encounter the weak surface of the laminae. The fracture pressure gradually increases with the increase in fracturing fluid viscosity, while the fracture pressure of supercritical CO2 is the largest and the fracture width is significantly lower than the other two fracturing fluids due to the high permeability and poor sand-carrying property. (2) Compared with the other two conventional fracturing fluids, under the condition of supercritical CO2 fracturing fluid, the increase in ground stress leads to the increase in inter-salt. (3) Compared with the other two conventional fracturing fluids, under the conditions of supercritical CO2 fracturing fluid, the fracture toughness of shale increases, the fracture pressure increases, and the fracture network complexity decreases as well. (4) With the increase in pumping displacement, the fracture network complexity increases, while the increase in the displacement of supercritical CO2 due to high permeability leads to the rapid penetration of inter-salt shale hydraulic fractures to the surface of the specimen to form a pressure relief zone; it is difficult to create more fractures with the continued injection of the fracturing fluid, and the fracture network complexity decreases instead.

Numerical Study on Proppant Transport in Supercritical Carbon Dioxide under Different Fracture Shapes: Flat, Wedge-Shaped, and Bifurcated

As a new type of waterless technology, supercritical carbon dioxide fracturing has been widely studied by scholars in recent years, and the migration characteristics of the corresponding proppant in supercritical carbon dioxide still need further research. In this paper, the Eulerian–Eulerian computational fluid dynamics method was used to study the transport capacity of supercritical carbon dioxide, and the UDF method was used to simulate the physical parameters of supercritical carbon dioxide. In view of the deficiencies of previous studies, the special cases of wedge-shaped fractures and bypass fractures are considered, and the influence of large-span pressure and temperature on migration is first analyzed in plane fractures, which makes this study more complete. The results show that: (1) compared with slickwater, the proppant transport channel in supercritical carbon dioxide is 30% smaller at 305 K and 10 MPa. (2) The transport capacity of supercritical carbon dioxide increases with the increase of pressure and decreases with the increase of temperature. But when the pressure or temperature is too high, they have little effect on it. (3) In wedge-shaped fractures, the proppant stack height and length increase initially as the shrinkage rate of fracture width (the ratio of the fracture reduced width to the fracture length) increases. However, as the fracture width ratio increases, the maximum proppant stack height decreases in the later stage. (4) In bifurcated fractures, with the increase of bypass angle, the area of proppant in the bypass zone tends to decrease. The width of the bypass inlet has little effect on the proppant settlement in the bypass. This study further understands the migration law of proppant in supercritical carbon dioxide in fractures.

Laminar and turbulent groundwater flows in confined two- and three-dimensional discrete fracture networks

Using laminar or turbulent flow equations indiscriminately to describe groundwater flows in fracture networks may result in large errors. We propose a new method for simulating steady-state groundwater flows in two- and three-dimensional fracture networks by separating laminar flows and turbulent flows in individual fractures. Poiseuille's law is employed when the flow is laminar, while Swamee and Jain formula is utilized when the flow is turbulent. The model results are first compared to recently measured field groundwater flow data in a mining tunnel network. The effect of hydraulic gradient, aperture, fracture width in the third dimension, and fracture density is then examined. Using the laminar flow equation indiscriminately in all fractures overestimates groundwater flowrates, whereas using the turbulent flow equation underestimates them. The aperture contrast of large and small fractures has a significant impact on the potential errors of indiscriminately applying the laminar or turbulent flow equation and the flowrate difference between the three-dimensional and two-dimensional fracture networks. Total groundwater flowrates increase with fracture density in both three-dimensional and two-dimensional fracture networks, with the largest increase occurring when additional fractures are introduced parallel to the hydraulic gradient. The new approach may be utilized to estimate hydraulic head distribution and groundwater flowrate according to the crack patterns and geometric properties of the fractured rock.

Study on the failure mechanism in shale-sand formation based on hybrid finite-discrete element method

During the hydraulic fracturing in shale formation, the mechanical properties and stress field caused by sand and shale interbedding were the major factors affecting the hydraulic fracture propagation. In this paper, a hydraulic fracturing simulation model was proposed based on the hybrid finite-discrete element method, and the factors affecting the fracture propagation were analyzed. The simulation results indicated that the fracture width experienced a sudden decrease when the hydraulic fracture interacted with a bedding plane. The reservoir with high stress difference and Young’s modulus was favorable for the opening of bedding plane, and high injection rate was favorable for the longitudinal expansion of hydraulic fracture. This was mainly because the lower stress difference and Young’s modulus was, the opening degree of the bedding plane was much smaller, and the less the energy consumption of opening the bedding surface was.

Analytical model for fracture conductivity considering rod proppant in pulse fracturing

In recent years, the combination of rod proppants and pulse-fracturing technology has been successfully applied to many reservoirs. It can not only solve the issue of proppant backflow, but also improve the productivity of oil and gas wells. However, fracture conductivity under a sparse distribution of rod proppants is rarely investigated theoretically, and the existing spherical model cannot be used owing to the different shapes of proppants.Based on the contact mechanisms between cylinders, deformation and embedment models of rod proppants are developed to calculate the fracture width. To solve the problem of sparse distribution, the axial and radial distance coefficients between rod proppants are defined, and a dimensionless permeability model is derived. Finally, a model for fracture conductivity under a rod proppant is developed based on the fracture width and permeability models. The model can predict the fracture conductivity when a rod proppant is used during pulse fracturing.The results show that in both the radial and axial flow directions, the fracture conductivity under radial proppant spacing is higher than that under axial proppant spacing, and the radial optimal proppant spacing is smaller than that the axial optimal proppant spacing. A critical proppant spacing exists that reverses the fracture conductivity. A larger radial proppant spacing renders it more difficult to obtain an axial optimal proppant spacing. This phenomenon is particularly evident when the closure pressure and proppant size are increased. Increasing the fracture width and improving the radial distribution of the rod proppant can effectively improve the fracture conductivity. The results of this study provide theoretical support for the combined use of rod proppants and pulse fracturing for improving productivity.

Effect of sandstone and mudstone thickness on artificial fracturing for hydrocarbon extraction from low-permeability reservoirs

Hydraulic fracturing of low-permeability continental reservoirs that possess argillaceous interlayers between single sand bodies is poorly understood. In this study, the delta-front-facies, low-permeability sand–mudstone interbedded reservoir of the Ansai district, Ordos Basin, is used as a case study. The reservoir characteristics of different sedimentary microfacies were identified using information from outcrops, drill cores and well logging. Six reservoir physical models of sand–mudstone assemblages were established on the basis of these data. The fracture growth patterns and parameters of the six models were obtained by numerical simulation. Numerical simulation with different fracturing parameters was conducted, to obtain the best parameters for each model to achieve different fracturing effects. The results show that crack size is influenced by the thickness of sandstone and mudstone units, the sandstone to mudstone ratio, and fracturing operation parameters. Sandstone thickness is extremely important in crack propagation. For medium and thick sandstone (3–5 m thick) interbedded with thin mudstone (<0.3 m thick), fracture width and length are large, and longitudinal fractures can pierce mudstone layers. In contrast, for thin sandstone (<1.5 m thick) interbedded with thick mudstone (>0.8 m thick), fractures are small and often restricted to a single sand body, and the mudstone interlayers limit the longitudinal extent of cracks. The six models represent three sedimentary microfacies with different distributions of sandstone and mudstone. Oil well artificial fracture shapes and parameters in different microfacies were visualized through simulation with different models, and match well with data from actual fields We also conducted fracture simulation by changing the fracturing construction parameters to obtain the optimal parameters for different fracturing effects in the models, providing a new understanding of the mudstone interlayers between single sand bodies (>0.3 m thick) and an important basis for oil field construction.

Thermo-hydro-mechanical optimization of the enhanced geothermal system for commercial utilization

Enhanced geothermal system (EGS) has been commercialized worldwide, yet the complex thermal-hydraulic-mechanical coupling processes were not well illuminated. With the reservoir regarded as the fractured porous media of rock matrix and discrete fractures, this work establishes a three-dimensional EGS model based on the thermal non-equilibrium theory to study the heat extraction in the EGS. After model validations, the evolution of three fields (i.e., temperature field, seepage field, and stress field) and the effects of several crucial operating parameters (e.g., injection flow rate, depth, and length) on heat extraction performance are discussed. The results show that the change of pressure and temperature in the reservoir alters the fracture displacement and the flow preferential paths and rock matrix permeability. For the given EGS reservoir, the total heat extraction rate reaches 60% at 50 years and approaches 86% at 100 years. Increasing the elastic modulus of the rock matrix promotes the overall recovery and then decreases the average temperature of the rock matrix. Decreasing injection flow rate, increasing length, increasing depth, and decreasing the elastic modulus of rock matrix give rise to (i) increasing the period for maintaining stable average outlet temperature; (ii) elevating the average outlet temperature after specific years. Running for 100 years, the final injection pressure of the EGS is 130 MPa, 48 MPa, and 45 MPa for the three fracture widths, 26%, 14%, and 10% lower than the initial injection pressure. Changing the fracture width from 0.005 m to 0.05 m is beneficial for the EGS operation on economic efficiency. Based on the commercial standards, the optimal operating conditions are proposed for the EGS.

A fracture conductivity model for channel fracturing based on lattice-Boltzmann-method and computational-fluid-dynamics

This paper introduces a new method to predict fracture conductivity for channel fracturing by lattice-Boltzmann-method (LBM) and computational-fluid-dynamics (CFD). Firstly, the deformation of the proppant pillar is tested using uniaxial compression experiments. A non-uniform fracture width model considering the nonlinear deformation of fracture and the embedment of proppant pillars is established. Then, an improved model based on LBM-CFD is proposed to simulate the flow field within the fracture and calculate the fracture conductivity. Finally, parametric analysis is carried out to understand the effects of closure stress, elastic modulus of the reservoir rock, proppant pillar's shape and proppant pillar's spacing on fracture width and conductivity. The results showed that the conductivity decreases gradually with closure stress and increases with elastic modulus. The proppant pillar with the smallest shape ratio can provide the highest conductivity. When the ratio of the proppant pillar's diameter to spacing is about 0.5, the conductivity for channel fracturing is best. The time of proppant-laden fluid (PLF) pulse and proppant-free fluid (PFF) pulse are the keys to the successful implementation of channel fracturing. The simulation results have been applied to the optimization of the pulse time in Shengli Oilfield. The field application proves that channel fracturing design based on our method could result in a large increase in well production. This paper gives critical insights for predicting the conductivity for channel fracturing, which could serve as guidelines for the optimization of proppant pillar's parameters and pulse time in channel fracturing design.

Mechanistic Study of Micro-bubble Fluid Infiltration through the Fractured Medium.

Drilling in depleted reservoirs has many challenges due to the overbalance pressure. Another trouble associated with overbalance drilling is differential sticking and formation damage. Low-density drilling fluid is an advanced method for drilling these depleted reservoirs and pay zones with different pressures to balance the formation pore pressure and hydrostatic drilling fluid pressure. This study investigated the infiltration of a micro-bubble fluid as an underbalanced drilling method in fractured reservoirs. A novel method has been presented for drilling permeable formations and depleted reservoirs, leading to an impressive reduction in costs, high-tech facilities, and drilling mud invasion. It also reduces mud loss, formation damages, and skin effects during the drilling operation. This paper studied micro-bubble fluid infiltration in a single fracture, and a synthetic metal plug investigated the bridging phenomenon through the fractured medium. Moreover, the effects of fracture size, bubble size, and a pressure differential of fracture ends have been thoroughly analyzed, considering the polymer and surfactant concentrations at reservoir conditions, including the temperature and overburden pressure. In this study, nine experimental tests were designed using the design of experiment, Taguchi method. The results indicated that higher micro-bubble fluid mixing speed values make smaller bubbles with lower blocking ability in fracture (decrease the chance of blocking more than two times). On the other hand, a smaller fracture width increases the probability of bubble bridges in the fracture but is not as crucial as bubble size. As a result, drilling fluid infiltration in fractures and formation damages decreases in the condition of overbalanced drilling pressure differences of about 200 psi.

XFEM modeling of the effect of in-situ stresses on hydraulic fracture characteristics and comparison with KGD and PKN models

Increasing the permeability of hydrocarbon reservoirs by creating artificial cracks that are induced by injection of fluids under high pressure is called hydraulic fracturing (HF). This method is widely used in petroleum reservoir engineering. For design of Hydraulic Fracture operations, several analytical models have been developed. KGD and PKN are the first and most used analytical models in this area. Although number of advanced softwares are developed in recent years, KGD and PKN models are still popular and have even been used in a number of softwares. In both models the characteristics of the fracture namely: fracture length (L), fracture width (w), and fluid pressure at the crack mouth (p) are determined based on closed form relations using the reservoir rock shear stiffness, Poisson’s ratio, fluid injection rate, and injection time. Despite their ease of use, KGD and PKN models do not consider some important geo-mechanical and hydro-mechanical parameters and this shortcoming makes their results to be approximate. The aim of this study is evaluating the effects of in-situ stress on the fracture length, width, and fluid pressure employing XFEM method. In this study, tensile fracture mode and cohesive zone model are used for creation and propagation of cracks. In this paper, by conducting a series of numerical simulations using XFEM and after verification of the results, the accuracy of the analytical formulas of KGD and PKN models are examined. The results show that due to some simplifying assumptions used in KGD and PKN analytical models and neglecting some hydraulic and geomechanical parameters such as in-situ stresses, the length, width, and fluid pressure of the crack obtained from analytical formulas differ from the results of the numerical simulations. In this paper, the effects of in-situ stresses on hydraulic fracture characteristics (width, length, and crack mouth fluid pressure) are investigated and presented in the form of a number of correction (modification) factors that can be used for improvement of the results of KGD and PKN models. The findings of this study can help for more accurate design of hydraulic fracture process in oil industry for increasing the production of hydrocarbon reservoirs.

Optimization of Fracturing Fluid and Retarded Acid for Stimulating Tight Naturally Fractured Bedrock Reservoirs.

In tight naturally fractured bedrock reservoirs, hydrocarbons are typically stored in fractures, where hydraulic fracturing is needed to connect these fractures to the wellbore. The cross-linked gel is used as the fracturing fluid to reduce the fluid leak-off through natural fractures; however, it can cause formation damage due to its high content of residues after breaking. A synthetic polymer is introduced and evaluated that can maintain a high viscosity to minimize the leak-off , while having a low residue content after breaking. To further enhance the conductivity of the created fracture network, acid is applied to etch and roughen the created fracture faces. Because the target reservoir has a complex mineral composition, a three-step coreflood sequence using reservoir rock samples with controlled fracture widths is established to quantify the enhancement of different retarded acids and to reveal the mechanism behind it. The results indicate the synergy effect of reducing the acid concentration and surfactant adsorption on rock surfaces can lead to an obvious enhancement of the fracture permeability after acidizing, while the mud acid or hydrofluoric acid is not suitable for the target reservoir where concentrations of silicates and clays are relatively high.

Factors Controlling the Hydraulic Fracture Trajectory in Unconventional Reservoirs

The morphology of hydraulic fracture is affected by many factors. In previous studies, due to the heterogeneity of rock samples and the limitations of sample size, influence degree of various factors on fracture deflection angle has not been well distinguished in laboratory experiments. Based on the boundary element method, we established a mathematical model to study the factors controlling the morphology of hydraulic fracture. Simulation results show that with increasing injection pressure, the radius of the fracture curvature increases. When the difference between the injection pressure and the maximum principal stress is 5 times the ground stress difference, the influence of in situ stress on hydraulic fracture deflection can be ignored. Hydraulic fracture deflection angle was relatively larger when considering the viscosity of the fracturing fluid. When stress difference is too small or the injection pressure is too big, the deflection angle of fracture is easy to fluctuate during initial propagation. Too large Young’s modulus and too small Poisson’s ratio will inhibit the fracture deflection and cause a narrower width of fracture. The effect of Poisson’s ratio on fracture aperture is less than 1 mm. When perforation angle is perpendicular to maximum horizontal principal stress, the fracture width first increases rapidly and then gradually decreases from heel to tip. The influence degree of each factor on fracture deflection is ranked: stress difference of in-situ stress is the biggest, followed by injection pressure and perforation angle. This study is of great significance for the control of hydraulic fracture morphology and the further improvement of fracturing effect.