Effects of Friction on Hydraulic Fracture Growth Near Unbonded Interfaces in Rocks

1981 ◽  
Vol 21 (01) ◽  
pp. 21-29 ◽  
Author(s):  
Gordon D. Anderson
Keyword(s):  
Stress Field ◽  
Hydraulic Fracturing ◽  
Normal Stress ◽  
Hydraulic Fracture ◽  
Fracturing Fluid ◽  
Frictional Properties ◽  
Interface Surface ◽  
Tight Reservoirs ◽  
Fracture Growth ◽  
The U.S

Abstract Small-scale laboratory experiments were performed to study the growth of hydraulically driven fractures in the vicinity of an unbonded interface in rocks. The purpose was to evaluate under which conditions the hydraulic fractures would cross the interface. The materials used in these studies were Nugget sandstone from Utah (3 to 6% porosity) and Indiana limestone (12 to 15% porosity). The fracturing fluid was oil (viscosity appx. 300 cp) injected into the rock through high-pressure steel tubing. Prismatic blocks of the rock materials to be studied were held adjacent to one another in a hydraulic press so that a normal stress was set up across their mutual interface. Lubricants and surface roughening were used to vary the frictional properties of the interfaces. It was found that as the interface surface friction coefficient was decreased, the normal stress had to be increased for a hydraulic fracture to cross the interface. The frictional shear stress that the interface can support without slippage appears to be critical in determining fracture growth across the interface. Additional experiments were performed to evaluate the coefficient of friction for the different interface surface preparations used. These experiments demonstrated that a variation in the frictional properties along an interfacial surface in the vicinity of hydraulic fracture growth can alter the path of the fracture. The experiments also demonstrated that cracks, which intersect the interface from the side opposite the approaching hydraulic fracture, can impede fracture growth across the interface. Introduction Hydraulic fracturing and a variant - massive hydraulic fracturing (MHF) - are primary candidates for stimulating production from the tight-gas reservoirs in the U.S. Hydraulic fracturing has been used widely as a well completion technique for about 30 years. MHF is a more recent application that differs from hydraulic fracturing in that larger quantities of fluid and proppant are pumped to create more extensive fractures in the reservoirs. Application of MHF to increase production from the tight reservoirs has provided mixed and, in many cases, disappointing results, especially in lenticular reservoirs. For MHF to be successful in enhancing the production of gas from tight reservoirs, it is important that the fractures be emplaced in productive reservoir rock providing large drainage surfaces in the low-permeability material and conductive channels back to the wellbore. We then are faced with the problem of containing fractures in a given formation.Under the U.S. DOE'S Unconventional Gas Recovery program, Lawrence Livermore Natl. Laboratory is conducting a research program to study the hydraulic fracture process. The general goal of this research is to determine if and to what extent the reservoir parameters control the geometry of the created fractures. These reservoir parameters include (1) the mechanical properties of the rock (i.e., elastic moduli, mechanical strength, etc.), (2) the physical state of the rock (i.e., presence of pre-existing cracks or faults, porosity, pore fluid, etc.), (3) presence of layering or interfaces between different rock strata, and (4) stress field on the rock. In addition to reservoir parameters, the growth of a hydraulically driven crack will be influenced by (1) the manner in which the driving fluid is injected into the rock, (2) the characteristics of the fracturing fluid (i.e., viscosity, presence of proppant, etc.), and (3) any chemical reaction between the fluid and rock. Previous work has shown that crack orientation is controlled primarily by the in-situ or applied stress field, with crack growth oriented perpendicular to the least principal stress. SPEJ P. 21^

Effects of Various Parameters on Hydraulic Fracturing Geometry

1981 ◽  
Vol 21 (04) ◽  
pp. 435-443 ◽  
Author(s):  
Merle E. Hanson ◽  
Ronald J. Shaffer ◽  
Gordon D. Anderson
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Reservoir Rock ◽  
Experimental Program ◽  
Hydraulic Fractures ◽  
Model Calculations ◽  
Well Completion ◽  
Fracturing Process ◽  
Tight Reservoirs ◽  
The U.S

Abstract We are conducting a theoretical and experimental program on the hydraulic fracturing process. One primary objective of the program is to determine those reservoir properties or characteristics that can control the created fracture geometry. Theoretical models are applied to analyze some aspects of the dynamics of fracturing near material interfaces. The results of these calculations indicate that variation of material properties across a well-bonded interface can cause dynamic material response resulting from the fracturing, which could enhance propagation across the interface. Effects of friction also are analyzed theoretically; however, in the frictional calculations, the wave mechanics are ignored. These calculations show that frictional slip along the interface tends to draw a pressurized fracture toward the interface; this motion tends to reduce the chances of penetrating the material across the frictional interface.Small-scale laboratory experiments are performed to study the effects of frictional characteristics on hydraulic fracture growth across unbonded interfaces in rocks. Various lubricants and mechanical preparations of the interface surfaces are used to vary the coefficients of friction on the interface surfaces. It is found that the frictional shear stress that the interface surface can support determines whether a hydraulically driven crack will cross the interface. Experiments also are being performed to study the effects of pre-existing cracks, which perpendicularly intersect the unbonded interface, on hydraulic crack growth across the interface. It also is found that the presence of these pre-existing cracks impedes the propagation of the hydraulic fracture across the interface. The experimental results on the effects of friction on the interface and the effects of pre-existing cracks on hydraulic fracture penetration of interfaces are consistent with the predictions of the numerical model calculations. Introduction Massive hydraulic fracturing (MHF) is a primary candidate for stimulating production from the tight gas reservoirs in the U.S. Hydraulic fracturing has been widely used as a well completion technique for about 30 years. MHF is a more recent application that differs from hydraulic fracturing in that more fluid and proppant are pumped to create more extensive fractures in the reservoir. Application of MHF to increase production from the tight reservoirs has provided mixed and, in many cases, disappointing results - especially in lenticular reservoirs. For MHF to be successful in enhancing gas production from tight reservoirs, it is important that the fractures be created in productive reservoir rock with large drainage surfaces in the low-permeability material and conductive channels back to the wellbore. We are faced then with the problem of containing fractures in a given formation.Under the U.S. DOE's unconventional gas recovery program, Lawrence Livermore Natl. Laboratory is conducting a research program on the hydraulic fracture process. The general goal of this research is to determine if and to what extent reservoir parameters control the geometry of the created fractures. From theories implied and demonstrated, hydraulic fractures propagate perpendicular to the least principal stress. Hence, except for very shallow applications, the fractures will be primarily vertical, with the azimuthal orientation controlled by the in-situ stress. The vertical gradient in the horizontal stresses also could be a factor in the control of the shape or vertical extent of fractures. SPEJ P. 435^

High-Resolution 3D Structural Geomechanics Modeling for Hydraulic Fracturing

2015 ◽  
Author(s):  
T.. Bérard ◽  
J.. Desroches ◽  
Y.. Yang ◽  
X.. Weng ◽  
K.. Olson
Keyword(s):  
High Resolution ◽  
Stress Field ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Image Data ◽  
Natural Fractures ◽  
Fracture Length ◽  
3D Space ◽  
Wellbore Pressure

Abstract Three-dimensional (3D) geomechanical models built at reservoir scale lack resolution at the well sector scale (e.g., hydraulic fracture scale), at least laterally. One-dimensional (1D) geomechanical models, on the other hand, have log resolution along the wellbore but no penetration away from it—along the fracture length for instance. Combining borehole structural geology based on image data and finite elements (FE) geomechanics, we constructed and calibrated a 3D, high-resolution geomechanical model, including subseismic faults and natural fractures, over a 1,500- × 5,200- × 300-ft3 sector around a vertical pilot and a 3,700-ft lateral in the Fayetteville shale play. Compared to a 1D approach, we obtained a properly equilibrated stress field in 3D space, in which the effect of the structure, combined with that of material anisotropy and heterogeneity, are accounted for. These effects were observed to be significant on the stress field, both laterally and local to the faults and natural fractures. The model was used to derive and map in 3D space a series of geomechanically based attributes potentially indicative of hydraulic fracturing performance and risks, including stress barriers, fracture geometry attributes, near-well tortuosity, and the level of stress anisotropy. An interesting match was observed between some of the derived attributes and fracturing data—near-wellbore pressure drop and overall ease and difficulty to place a treatment—encouraging their use for perforation and stage placement or placement of the next nearby lateral. The model was also used to simulate hydraulic fracturing, taking advantage of such a 3D structural and geomechanical representation. It was shown that the structure and heterogeneity captured by the model had a significant impact on hydraulic fracture final geometry.

scholarly journals On the link between stress field and small-scale hydraulic fracture growth in anisotropic rock derived from microseismicity

2017 ◽  
Author(s):  
Valentin S. Gischig ◽  
Joseph Doetsch ◽  
Hansruedi Maurer ◽  
Hannes Krietsch ◽  
Florian Amann ◽  
...  
Keyword(s):  
Stress Field ◽  
Hydraulic Fracture ◽  
P Wave ◽  
Fracture Plane ◽  
Small Scale ◽  
Elastic Model ◽  
Stress Tests ◽  
Principal Stresses ◽  
Anisotropic Rock ◽  
Fracture Growth

Abstract. To characterize the stress field at the Grimsel Test Site (GTS) underground rock laboratory a series of hydrofracturing test and overcoring test were performed. Hydrofracturing was accompanied by seismic monitoring using a network of highly sensitive piezo sensors and accelerometers that were able to record small seismic events associated with decimeter-sized fractures. Due to potential discrepancies between the hydro-fracture orientation and stress field estimates from overcoring, it was essential to obtain high-precision hypocenter locations that reliably illuminate fracture growth. Absolute locations were improved using a transverse isotropic P-wave velocity model and by applying joint hypocenter determination that allowed computation of station corrections. We further exploited the high degree of waveform similarity of events by applying cluster analysis and relative relocation. Resulting clouds of absolute and relative located seismicity showed a consistent east-west strike and 70° dip for all hydro-fractures. The fracture growth direction from microseismicity is consistent with the principal stress orientations from the overcoring stress tests provided an anisotropic elastic model for the rock mass is used in the data inversions. σ1 is significantly larger than the other two principal stresses, and has a reasonably well-defined orientation that is subparallel to the fracture plane. σ2 and σ3 are almost equal in magnitude, and thus lie on a circle defined by the standard errors of the solutions. The poles of the microseismicity planes also lie on this circle towards the north. The trace of the hydraulic fracture imaged at the borehole wall show that they initiated within the foliation plane, which differs in orientation from the microseismicity planes. Thus, fracture initiation was most likely influenced by a foliation-related strength anisotropy. Analysis of P-wave polarizations suggested double-couple focal mechanisms with both thrust and normal faulting mechanisms present, whereas strike-slip and thrust mechanisms would be expected from the overcoring-derived stress solution. The reasons for these discrepancies are not well understood, but may involve stress field rotation around the propagating hydrofracture. Our study demonstrates that microseismicity monitoring along with high-resolution event locations provides valuable information for interpreting stress characterization measurements.

Dynamics of hydraulic fracture development according to acoustic transmission data

2021 ◽  
Author(s):  
Sergey Turuntaev ◽  
Evgeny Zenchenko ◽  
Petr Zenchenko ◽  
Maria Trimonova ◽  
Nikolai Baryshnikov
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Injection Pressure ◽  
Ultrasonic Pulse ◽  
Theoretical Research ◽  
Fracture Rate ◽  
Acoustic Transmission ◽  
Fracturing Fluid ◽  
Fracture Closure ◽  
Transmission Data

<p>Acoustic transmission data obtained in laboratory experiment were used to estimate main stages of hydraulic fracture onset, growth and filling by fracturing fluid. Laboratory setup consists of two horizontal disks with a diameter of 750 mm, and a sidewall with an internal diameter of 430 mm. The disks and the sidewall form a pressure chamber with a diameter of 430 mm at a height of 70 mm. There are a number of holes in the disks and the sidewall that are used for mounting ultrasonic transducers, pressure sensors, as well as for fluid injections. As a model material, a mixture of gypsum with cement was used, which was poured into the chamber. The sample was saturated with water gypsum solution and loaded with vertical and two horizontal stresses using special chambers. The fracture was created by viscous fluid (mineral oil with viscosity 0.1 Pa*s) injection with a constant rate 0.2 cm<sup>3</sup>/s through a cased borehole (diameter 12 mm) with a horizontal slot, which was preliminary located in the center of the sample. Hydraulic fracturing monitoring was carried out by recording of ultrasonic pulses passing through the sample during fracturing. To separate the ultrasonic pulses, the frequency of their sending was used. After that, the envelope of each record fragment was constructed using the Hilbert transformation and its maximum was found. Comparison of the ultrasonic pulse amplitude variations and injection pressure led to the following observations. Initial decrease in the pulse amplitudes began before the maximum pressure was reached, which may indicate the hydraulic fracturing onset at a pressure less than the maximum. The amplitude decline occurs smoothly, so it is difficult to identify any characteristic point on these curves and, accordingly, it is difficult to establish an accurate time of the fracturing onset and the fracture rate. The fracture rate was estimated by different methods previously as ≈130 mm/s. After the decline, the pulse amplitudes started to increase, that was related with the injection fluid front propagation in the fracture. In contrast to the decline, the beginning of the amplitude growth was clearly detected. Taking into account the spatial locations of the ultrasonic pulse source, receivers, and fracture, it is possible to estimate the propagation velocity of the fracturing fluid front as ≈35 mm/s. After the increase, the ultrasonic pulse amplitudes started to decrease significantly (up to 3 times), which is probably due to the further expansion of the fracture aperture. On the transducers located closer to the well, this decline is maximum. When the injection is stopped, the ultrasonic pulse amplitudes began to grow again, which indicates the fracture closure as the injection pressure decrease. In the experiments on the fracture re-opening under various stress applied to the sample, a linear relationship between the fracture re-opening pressure and applied vertical stress was found. This type of relationship should be expected, but values of the relation parameters declined from the values suggested in theoretical research, which was explained by taken into account back-stresses and non-linear behavior of the sample material.</p>

Tiltmeter Mapping of Measured Nonsymmetric Hydraulic-Fracture Growth in a Conglomerate/Sandstone Formation Using the Implicit Level-Set Algorithm and the Extended Kalman Filter

SPE Journal ◽  
2017 ◽  
Vol 23 (01) ◽  
pp. 172-185
Author(s):  
V.. Pandurangan ◽  
A.. Peirce ◽  
Z. R. Chen ◽  
R. G. Jeffrey
Keyword(s):  
Kalman Filter ◽  
Hydraulic Fracturing ◽  
Dynamic Model ◽  
Extended Kalman Filter ◽  
Level Set ◽  
Hydraulic Fracture ◽  
Field Data ◽  
Fracture Propagation ◽  
Physical Processes ◽  
Fracture Growth

Summary A novel method to map asymmetric hydraulic-fracture propagation using tiltmeter measurements is presented. Hydraulic fracturing is primarily used for oil-and-gas well stimulation, and is also applied to precondition rock before mining. The geometry of the developing fracture is often remotely monitored with tiltmeters—instruments that are able to remotely measure the fracture-induced deformations. However, conventional analysis of tiltmeter data is limited to determining the fracture orientation and volume. The objective of this work is to detect asymmetric fracture growth during a hydraulic-fracturing treatment, which will yield height-growth information for vertical fracture growth and horizontal asymmetry for lateral fracture growth or detect low preconditioning-treatment efficiency in mining. The technique proposed here uses the extended Kalman filter (EKF) to assimilate tilt data into a hydraulic-fracture model to track the geometry of the fracture front. The EKF uses the implicit level set algorithm (ILSA) as the dynamic model to locate the boundary of the fracture by solving the coupled fluid-flow/fracture-propagation equations, and uses the Okada half-space solution as the observation model (forward model) to relate the fracture geometry to the measured tilts. The 3D fracture model uses the Okada analytical expressions for the displacements and tilts caused by piecewise constant-displacement discontinuity elements to discretize the fracture area. The proposed technique is first validated by a numerical example in which synthetic tilt data are generated by assuming a confining-stress gradient to generate asymmetric fracture growth. The inversion is carried in a two-step process in which the fracture dip and dip direction are first obtained with an elliptical fracture-forward model, and then the ILSA-EKF model is used to obtain the fracture footprint by fixing the dip and dip direction to the values obtained in the first step. Finally, the ILSA-EKF scheme is used to predict the fracture width and geometry evolution from real field data, which are compared with intersection data obtained by temperature and pressure monitoring in offset boreholes. The results show that the procedure is able to satisfactorily capture fracture growth and asymmetry even though the field data contain significant noise, the tiltmeters are relatively far from the fracture, and the dynamic model contains significant “unmodeled dynamics” such as stress anisotropy, material heterogeneity, fluid leakoff into the formation, and other physical processes that have not been explicitly accounted for in the dynamic ILSA model. However, all the physical processes that affect the tilt signal are incorporated by the EKF when the tilt measurements are used to obtain the maximum likelihood estimates of the fracture widths and geometry.

scholarly journals Stratigraphically Controlled Stress Variations at the Hydraulic Fracture Test Site-1 in the Midland Basin, TX

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8328
Author(s):  
Arjun Kohli ◽  
Mark Zoback
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Active Faults ◽  
Horizontal Wells ◽  
Test Site ◽  
Stress Profile ◽  
Fracture Test ◽  
Orientation Data ◽  
Stress Measurements ◽  
Fracture Growth

We investigated the relationship between stratigraphy, stress, and microseismicity at the Hydraulic Fracture Test Site-1. The site comprises two sets of horizontal wells in the Wolfcamp shale and a deviated well drilled after hydraulic fracturing. Regional stresses indicate normal/strike-slip faulting with E-W compression. Stress measurements in vertical and horizontal wells show that the minimum principal stress varies with depth. Strata with high clay and organic content show high values of the least compressive stress, consistent with the theory of viscous stress relaxation. By integrating data from core, logs, and the hydraulic fracturing stages, we constructed a stress profile for the Wolfcamp sequence, which predicts how much pressure is required for hydraulic fracture growth. We applied the results to fracture orientation data from image logs to determine the population of pre-existing faults that are expected to slip during stimulation. We also determined microseismic focal plane mechanisms and found slip on steeply dipping planes striking NW, consistent with the orientations of potentially active faults predicted by the stress model. This case study represents a general approach for integrating stress measurements and rock properties to predict hydraulic fracture growth and the characteristics of injection-induced microseismicity.

Mathematical modeling heat and mass transfer in a vertical hydraulic fracture crack during inflation and cleaning*

2020 ◽  
Vol 6 (2) ◽  
pp. 41-62
Author(s):  
Guzel T. Bulgakova ◽  
Andrey R. Sharifullin ◽  
Marat R. Sitdikov
Keyword(s):  
Mathematical Modeling ◽  
Mass Transfer ◽  
Hydraulic Fracturing ◽  
Heat And Mass Transfer ◽  
Hydraulic Fracture ◽  
Temperature Fields ◽  
Maximum Temperature ◽  
Evolutionary Equation ◽  
Fracturing Fluid ◽  
Temperature Dynamics

When designing hydraulic fracturing for high-temperature formations, it is important to know the temperature change in the fracture during the injection of fracturing fluid. The temperature profile in the hydraulic fracture is necessary to calculate the optimal composition of the fracturing fluid, which necessarily includes a crosslinker (crosslinker) and a breaker (breaker), the concentration of which is calculated by the temperature at the end of the crack. Currently, this concentration is calculated based on the maximum temperature of the formation, which can lead to a decrease in the efficiency of hydraulic fracturing, since a breaker will not completely destroy the crosslinked gel. Therefore, when a well is brought into operation after the stimulation, proppant removal may occur, reducing the effectiveness of stimulation to zero. In this regard, the optimization of the decision-making process in the design of hydraulic fracturing in terrigenous and carbonate reservoirs by calculating the optimal parameters of process fluids based on predicting heat and mass transfer processes occurring during processing is a very urgent task. A tool has been developed to improve the design efficiency of hydraulic fracturing based on mathematical modeling of temperature fields in a hydraulic fracture during its development and during the period of technological sludge. A mathematical model that describes the temperature dynamics in a hydraulic fracture taking into account fluid leakage into the formation represents the evolutionary equation of convective heat transfer with a source, which is defined as the density of the heat flux from the formation. To check the adequacy of the model of temperature dynamics in a hydraulic fracture, a model of temperature recovery in a fracture is presented with the subsequent adaptation of simulation results to actual data. Developed mathematical models can be used in hydraulic fracturing simulators.

Effect of Fluid Compressibility on Toughness-Dominated Hydraulic Fractures With Leakoff

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2118-2132 ◽  
Author(s):  
Di Wang ◽  
Mian Chen ◽  
Yan Jin ◽  
Andrew. P. Bunger
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Fracturing Fluids ◽  
Fracture Shape ◽  
Carbon Dioxide Co2 ◽  
Fracture Growth ◽  
Fluid Compressibility

Summary Hydraulic fracturing using supercritical carbon dioxide (CO2) has a recognized potential to grow in importance for unconventional oil and gas reservoirs. It is characterized by higher compressibility than traditional liquid-phase hydraulic-fracturing fluids. Motivated by the larger compressibility of supercritical CO2, this paper considers the problem of a hydraulic fracture in which a compressible fluid is injected at a constant rate to drive a hydraulic fracture in a permeable and brittle rock. The two cases of a plane-strain fracture and a penny-shaped fracture are considered. It is shown that for many practical cases, the formation has a large enough fracture toughness that the propagation is in a regime for which the pressure inside the hydraulic fracture can be treated as spatially uniform (“toughness dominated”). Both numerical simulations and analytical solutions for the relevant limiting regimes show that fluid compressibility affects fracture shape only at the very beginning period, which corresponds to the storage regime, and has little effect on fracture growth in the leakoff regime. Overall, because the transition from the storage regime to the leakoff regime is expected to often take place in a short time after the fracture starts propagating, the influence of compressibility in the storage regime is very brief and can be quickly ignored. Therefore, even relatively sizable fluid compressibility has almost no effect on fracture growth in the toughness-dominated regime when leakoff is taken into account.

scholarly journals The Impact of Oriented Perforations on Fracture Propagation and Complexity in Hydraulic Fracturing

Processes ◽  
2018 ◽  
Vol 6 (11) ◽  
pp. 213 ◽  
Author(s):  
Liyuan Liu ◽  
Lianchong Li ◽  
Derek Elsworth ◽  
Sheng Zhi ◽  
Yongjun Yu
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Stress Criterion ◽  
Damage And Fracture ◽  
Fracturing Process ◽  
Heterogeneous Rock ◽  
The Impact

To better understand the interaction between hydraulic fracture and oriented perforation, a fully coupled finite element method (FEM)-based hydraulic-geomechanical fracture model accommodating gas sorption and damage has been developed. Damage conforms to a maximum stress criterion in tension and to Mohr–Coulomb limits in shear with heterogeneity represented by a Weibull distribution. Fracturing fluid flow, rock deformation and damage, and fracture propagation are collectively represented to study the complexity of hydraulic fracture initiation with perforations present in the near-wellbore region. The model is rigorously validated against experimental observations replicating failure stresses and styles during uniaxial compression and then hydraulic fracturing. The influences of perforation angle, in situ stress state, initial pore pressure, and properties of the fracturing fluid are fully explored. The numerical results show good agreement with experimental observations and the main features of the hydraulic fracturing process in heterogeneous rock are successfully captured. A larger perforation azimuth (angle) from the direction of the maximum principal stress induces a relatively larger curvature of the fracture during hydraulic fracture reorientation. Hydraulic fractures do not always initiate at the oriented perforations and the fractures induced in hydraulic fracturing are not always even and regular. Hydraulic fractures would initiate both around the wellbore and the oriented perforations when the perforation angle is >75°. For the liquid-based hydraulic fracturing, the critical perforation angle increases from 70° to 80°, with an increase in liquid viscosity from 10−3 Pa·s to 1 Pa·s. While for the gas fracturing, the critical perforation angle remains 62° to 63°. This study is of great significance in further understanding the near-wellbore impacts on hydraulic fracture propagation and complexity.

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