Hydraulic Fracturing Treatment Research Articles

Settling of Spherical Particles in High Viscosity Friction Reducer Fracture Fluids

Investigating the key factors that impact fluid rheology and proppant static settling velocity in high viscosity friction reducers (HVFRs) is a critical aspect for successful proppant transport in hydraulic fracture treatment. In this study, the rheological properties of HVFRs were tested at various temperature ranges (i.e., 25, 50, 75, and 100 °C) and different HVFR concentrations (i.e., 1, 2, 4, and 8 gpt). Three sizes of spherical particle diameters (i.e., 2, 4, and 6 mm) were selected to measure the static settling velocity. The fracture fluid was tested in two fracture models: an unconfined glass model and a confined rectangular model with two fracture widths (7 and 10 mm). The settling velocity in the confined and unconfined models was measured using an advanced video camera. HVFR results exhibited acceptable thermal stability even at higher temperatures, also the viscosity and elasticity increased considerably with increasing concentration. Increasing the temperature cut the friction reducer efficiency to suspend the spherical particles for a significant time, and that was observed clearly at temperatures that reached 75 °C. Spherical particles freely settled in the unconfined model due to the absence of the wall effect, and the settling velocity decreased significantly as the HVFR concentration increased. Additionally, the fracture angularity substantially slowed the proppant settling velocity due to both the wall effect and several types of friction. This research provides insights into the rheological parameters of a high viscosity friction reducer as a fracturing fluid and its efficiency in transporting particles in bounded and unbounded fracture networks.

Hydraulic-Fracture-Width Inversion Using Low-Frequency Distributed-Acoustic-Sensing Strain Data Part II: Extension for Multifracture and Field Application

Summary Low-frequency distributed-acoustic-sensing (LF-DAS) strain data are direct measurements of in-situ rock deformation during hydraulic-fracturing treatments. In addition to monitoring fracture propagation and identifying fracture hits, quantitative strain measurements of LF-DAS provide opportunities to quantify fracture geometries. Recently, we proposed a Green’s function–based algorithm for the inversion of LF-DAS strain data (Liu et al. 2020b) that shows an accurate estimation of fracture width near the monitor well with single-cluster completions. However, multicluster completions with tighter cluster spacings are more commonly adopted in recent completion designs. One main challenge in the inversion of LF-DAS strain data under such circumstances is that strain measurements at fracture-hit locations by LF-DAS are not reliable, which makes the individual contribution of each fracture to the measured strain data indistinguishable. In this study, we first extended the inversion algorithm to handle multiple fractures, investigated the uncertainties of the inversion results, and proposed possible mitigation to the challenges raised by completion designs and field data acquisition through a synthetic case study. Ideally, there are available data on both sides of each fracture so that the inverted width of each fracture can be obtained with a negligible error. In reality, the strain data are usually limited, providing less constraint on the width of individual fracture. Nevertheless, the inversion results provide an accurate estimation of the width summation of all fractures. To evaluate the individual fracture width, a time-dependent constraint is added to the inversion algorithm. We assume that the width at the current timestep is dependent on the width at the previous step and the width variation between the two timesteps. The width variation can be roughly estimated from LF-DAS strain-rate data at the fracture-hit location. This extra constraint helps to improve the inversion performance. Finally, a field example is presented. We show the width summation of all fractures and the width of each individual fracture as a function of treatment time. The time-dependent width profiles show consistent trends with the LF-DAS strain-rate data. The calculated strains from the inverted model match well with the LF-DAS measured strain data. The findings demonstrate the potential of LF-DAS data for quantitative hydraulic-fracture characterization and provide insights on better use of LF-DAS data. The direct information on fracture width helps to calibrate fracturing models and optimize the completion designs.

Laboratory Testing of Fracture Conductivity Damage by Foam-Based Fracturing Fluids in Low Permeability Tight Gas Formations

In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.

The Production Performance Evaluation of Hydraulically Fractured Wells in the East Sulige Field Using Machine Learning

The paper presents a comprehensive workflow to integrate the machine learning algorithm with the Monte Carlo simulation, and a field example is provided to demonstrate that the proposed workflow could reasonably capture the behaviour of well production data. The workflow helps engineers in learning valuable lessons from their historical operations to optimize the future hydraulic fracturing treatments in the Sulige gas field.

Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs

Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery.We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement.Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geo-mechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition counter-current flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.

Laboratory study on casing deformation during multistage horizontal well fracturing in shale gas development and strain based casing design

Shale gas development in the Sichuan-Chongqing region in China has experienced a high level of casing deformation or failure during hydraulic fracturing treatment, which has resulted in significant productivity decline and economic losses. This problem has motivated many studies in the literature but focusing on the shearing deformation using the finite element method. This paper categorizes the casing failure modes and mechanisms in the region and presents casing collapse laboratory results. The designed laboratory tests rendered us critical data points in casing deformation under different loading scenarios. For multiple stage hydraulic wells in the region, we propose to use a strain-based protocol for casing design instead of the current design based on maximum stress.

Analysis of Hydraulic Fracturing Efficiency Considering the Principal Stress in Brushy Canyon Formation of the Permian Basin

The purpose of this study is to investigate the effect of principal stress direction on the efficiency of hydraulic fracturing treatment. There are two different drilling scenarios: 1. Four horizontal wells drilled in four orthogonal directions regardless of in-situ stress condition (“Actual”). 2. Three horizontal wells drilled equivalent to “Actual” case by considering the direction of principal stress (“Proposed”). The hydraulic fracturing modeling was carried out based on well logging data and completion reports of Brushy Canyon formation, Permian Basin. In the results of “Actual” case, transverse fractures were generated in two horizontal wells drilled parallel to σhmin-dir (direction of σhmin), similar to “Proposed” case. Meanwhile, for two other wells drilled perpendicular to σhmin-dir, longitudinal fractures were generated. These obliquely deviated fractures significantly decreased the fracture spacing between the stages up to 26%. This induced great stress shadow, however, the fractures propagated straight due to the large stress anisotropy of 2000 psi (σHmax/σhmin = 1.4). Therefore, it was found that due to the different direction of fracture propagation in “Actual” case, “Proposed” case was 14.6% of stimulated reservoir volume (SRV) higher. In conclusion, for successful hydraulic fracturing treatment, the direction of horizontal well must be determined in consideration of the principal stress direction as well as stress anisotropy.

Pressure-Based Diagnostics for Evaluating Treatment Confinement

SummaryIn multiple-stage hydraulic fracturing treatments performed in horizontal wells, treatment confinement is the state in which fracturing fluid and proppant flow out of the wellbore only through the specific perforations targeted for the fracturing stage. The terms treatment confinement and treatment isolation are synonymous. Isolation from previously treated intervals is a necessary condition for efficient treatment along the lateral. Failure to confine fracturing stages can be a result of failure of the fracture plug to maintain a seal or the development of casing breaches (holes) in the proximity of the fracture plug. Both conditions can be strongly impacted by proppant induced erosion.This paper is a sequel to a previous publication in which casing erosion and breaches were investigated in fracture treated horizontal wells in the Montney Formation (White et al. 2020). Integrated diagnostic methods based on data from treating pressure analysis, fiber-optic measurements, and downhole imaging were applied to investigate the root cause of failure. It was determined that treatment pressure analysis was effective in diagnosing casing and associated fracture plug integrity-loss events. This was achieved by (1) identifying treating pressure trends and anomalies during the main part of the treatment that signify confinement loss, (2) calculating near-wellbore friction at the end of treatments to compare to the friction expected for a confined treatment, and (3) analyzing step-down tests conducted during the pad stage and overflush stage at the end of the treatment to determine the near-wellbore frictional components of perforation friction and near-wellbore tortuosity. This information enables comparison of previous with current treatments for determining the effects of job design and fracture plug modifications on treatment confinement.The objective of this paper is to validate that useful conclusions on the degree of treatment confinement can be made using only stand-alone pressure-based analysis. This is achieved by comparing the analysis results with fiber-optic and post-treatment wellbore imaging measurements. Also highlighted is the use of downhole gauges for accurately calculating pipe friction, which is necessary for accurately calculating bottomhole treating pressure at the active treatment interval.

HYDRAULIC FRACTURING DESIGN IMPROVEMENTS BY PROPPANT FLOWBACK MITIGATION METHOD APPLICATION DURING HYDROCARBON PRODUCTION

Proppant flowback after hydraulic fracturing treatment is quite a serious challenge that causes damage to both downhole and surface equipment, leading to unwanted workovers and production suspension, or other negative outcomes. Some special methods including preventive as well as corrective measures already exist in the industry to overcome the proppant flowback problems. However, there is no clear guidance on how to choose the method for certain conditions, particularly during the hydraulic fracturing design stages. Therefore, the authors conducted a comprehensive review of fourteen preventive technologies to systematize them and to propose an initial decision-making approach. The following methods were considered in this paper: Resin Coated Proppants (RCP), RCP with Activator, RCP with Nanoparticles, Proppant with Liquid Resin Systems (LRS), Proppant with Surface Modification Agents (SMA), Proppant with Proppant Consolidation Aid (PCA), Cylindrical Proppant, Microfibers, Thermoset Resin Fibers, Thermoset Film Strips, Deformable Isometric Particles (DIP), Expandable Proppants, Polymer Surface Modified Proppants, and In-situ Formulated Proppants. The review reveals physical, chemical, and technological properties of each method to select criteria for effective screening. So, the reader could find the appropriate proppant flowback mitigation method corresponding to a particular reservoir and the well conditions during the initial hydraulic fracturing design stages.

Research on Fracture Initiation Pressure in Deviated Well of WCH9 Block

Highly-deviated well are applied for effectively developing WCH9 gas field with deep buried and low permeability, and the payzone are candidates for hydraulic fracturing by evaluation of gas reservoir. Therefore, fracture initiation pressure is a key parameter for design of hydraulic fracturing treatment. Firstly, a series of experiments were completed by core sample from target formation, Young's modulus is about 13GPa and Poisson's ratio is 0.286 at a confining pressure of 40MPa, horizontal principal stress is 78 MPa and 63 MPa, and in-situ stress profiles were interpreted by logging data. Then, the formation rock is regarded as isotropic linear elastic material, thus total stresses distribution on the deviated wellbore wall was determined by stress superposition principle, in which in-situ stress redistribution around the deviated wellbore, fluid pressure acted on the borehole wall and filtration stress are taken into account when fracturing fluid was injected into wellbore. Further, prediction model of fracture initiation pressure was established by applying criterion of maximum tensile stress and effective stress transformation. Lastly, according to the borehole trajectory, in-situ stress and other parameters from payzone of WCH9 block, fracturing initiation pressure varied with <i>Deviation angle and azimuth angle</i> were computed by numerical simulation method, these results provide a basis for optimization design of hydraulic fracturing technology parameters.

Hydraulic Fracture Propagation and Analysis in Heterogeneous Middle Eastern Tight Gas Reservoirs: Influence of Natural Fractures and Well Placement.

Hydraulic fracturing is a stimulation process, most frequently used in tight and unconventional reservoirs for successful and economical hydrocarbon production. This study deals with the propagation behavior of induced hydraulic fractures (HFs) in naturally fractured formations within heterogeneous Middle Eastern tight gas reservoirs. Local sensitivity analysis was conducted for a Middle East candidate reservoir by varying fracture design parameters to investigate the fracture propagation behavior. After a comprehensive evaluation, a discrete fracture network-based simulator was used to introduce multiple sets of natural fractures (NFs) into the model to further analyze their interactions. Furthermore, simplistic wellbore placement analysis was also conducted. It is observed that production in tight reservoirs is governed by the presence of NFs and their distribution. This investigation analyzes HF propagation behavior and its correlated effects in the presence of NFs. Further assessment in terms of varying fracture geometry, NF sets, wellbore placement, and their effects on the conductivity are also presented. The introduced NF sets further illustrate the significance of the NF properties in this assessment. Additionally, variations in well placement demonstrate how effective the treatment can be in the presence of complex NF sets when properly located. The study is unique as it is one of its kind based on field data within the Middle East region and offers an insight into the potential concerns that may assist future fracturing operations within the region. The outcomes from this research validate the significance of NF orientation and its subsequent effects on the final HF geometry and network. Additionally, it further highlights the criticality of well placement and design strategies during hydraulic fracturing treatment design. Results describe how a minor modification with respect to the well placement can significantly affect hydraulic fracturing operations and subsequently the productivity and feasibility.

Fracture-Hit Detection Using LF-DAS Signals Measured during Multifracture Propagation in Unconventional Reservoirs

SummaryLow-frequency distributed acoustic sensing (LF-DAS) data are a powerful attribute to detect fracture hits and characterize fracture geometry during multistage hydraulic fracturing treatments in unconventional reservoirs. The DAS data in low-frequency bands linearly correlate with strain and strain rate induced by dynamic fracture propagation. Due to the complexity of multiple-fracture propagation in unconventional reservoirs, the measured signals from different wells exhibit various characteristics. Mechanisms causing the differences are not well understood, which makes the interpretation of real LF-DAS data and detection of fracture hits very challenging. Hence, it is necessary to relate the observed strain/strain-rate signatures to specific fracture patterns based on the physical model of rock deformation during fracture propagation and to quantitatively characterize signatures surrounding fracture hits. In this study, we have applied our in-house fracture propagation model to simulate simultaneous multiple-fracture propagation as well as fracture-induced strain and strain-rate responses along an offset monitor well. Then a general guideline for fracture-hit detection is proposed based on quantitative analysis of strain/strain-rate responses during multiple-fracture propagation. Finally, a set of field examples are presented to demonstrate the potential of LF-DAS data on hydraulic fracturing monitoring.During multiple-fracture propagation, a “heart-shaped” zone with positive strain rates may be identified for each fracture before the fracture hit. Immediately after the fracture encounters the monitor well, part of the fiber within the fracture path keeps being extended, while the fiber sections off the path become compressed. Three 1D features along the channel (location) axis are designed to detect fracture hits. The features are maximum strain rate, the summation of strain rates, and summation of strain-rate amplitudes. Channels with fracture hits usually exhibit significant peak values of the three features. However, the characteristic signatures can be less detectable when the gauge length is close to the cluster spacing. Connections between fracture-hit locations and cluster perforations clearly reflect the fracture propagation direction. The field examples illustrate the complexity of real LF-DAS signals and demonstrate the adequacy of the proposed guideline for fracture-hit detection with multicluster completion. The fractures propagate nearly perpendicular to the horizontal wellbore in this unconventional shale formation. In addition, four to five fractures out of eight perforation clusters can propagate 396.24 m (1,300 ft) and hit the monitor well, and the “heel-biased” fracture pattern is observed (fractures that do not hit the monitor well are usually close to the toe side). Fracturing fluid leaking off into the previous stage can also be diagnosed, which could negatively affect the completion efficiency.

The alterations of critical pore water pressure and micro-cracking morphology with near-wellbore fractures in hydraulic fracturing of shale reservoirs

The crack initiation and propagation in a laminated shale formation have been widely investigated, but the alterations of critical pore water pressure (including fracture initiation pressure and breakdown pressure) and the micro-cracking morphology with near-wellbore fracture geometry are still unclear. This paper numerically investigates the alterations of critical pore water pressure and the morphology of the hydraulic fractures in shale formation with different near-wellbore fractures. First, a hydro-fracturing model is developed for a laminated shale formation within the framework of PFC2D. Then, this model is validated with the Blanton’s criterion, pressure history and fracture geometry. Finally, the effects of length, shape, and symmetry properties of near-wellbore fractures on the critical pore water pressure and micro-cracking morphology are comparatively investigated. The critical pore water pressure, micro-cracking morphology, aperture and permeability, and the fractal dimension of hydraulic fractures are quantitatively analyzed at three initial near-wellbore fractures. Simulation results indicate that the length and the distribution of near-wellbore fracture branches play a crucial role in pore water pressure variation and micro-crack propagation during hydraulic fracturing. The critical pore water pressure is sensitive to the initial near-wellbore fracture length especially when the initial fracture length exceeds a critical fracture length. The shape of initial near-wellbore fracture could change the distribution of micro cracks and induce large pore water pressure. The symmetrical radial fracture (θ=0°) more likely causes a hydraulic fracture with high permeability while the X-shape fracture (θ=30°) contributes greatly to the complexity of the fracture network and stimulated reservoir volume. These findings on the pore water pressure variation and the micro-cracking morphology are helpful in the optimization design of hydraulic fracturing treatment.

Statistical Modeling and Characterization of Induced Seismicity Within the Western Canada Sedimentary Basin

AbstractIn western Canada, there has been an increase in seismic activity linked to anthropogenic energy‐related operations including conventional hydrocarbon production, wastewater fluid injection, and, more recently, hydraulic fracturing (HF). Statistical modeling and characterization of the space, time, and magnitude distributions of the seismicity are vital for a better understanding of induced earthquake processes and development of forecasting models. In this work, a statistical analysis of the seismicity in the Western Canada Sedimentary Basin was performed across past and present time periods by utilizing a compiled earthquake catalog for Alberta and eastern British Columbia. Specifically, the interevent space‐time distance distributions of earthquakes were studied using the nearest‐neighbor distance (NND) method. Additionally, the frequency‐magnitude statistics and aftershock parameters of several clusters were analyzed using the Gutenberg‐Richter relation and the epidemic‐type aftershock sequence model. The results suggest that recent regional changes in the NND distributions, namely, a disproportionate increase in loosely and tightly clustered seismic activity over time, are unnatural and likely due to the rise in HF operations for the development of unconventional resources. It is concluded that both these loosely and tightly clustered earthquake subpopulations differ measurably from what may be the region's tectonic seismic activity. Additionally, HF treatments have a greater probability of triggering swarm‐like sequences that sharply spike the seismicity rate and are characterized by larger Gutenberg‐Richterbvalues. In contrast, conventional production and wastewater disposal operations largely trigger loosely clustered activity with more typical magnitude occurrence distributions.

Completion Effects on Diagnosing Multistage Facture Treatments with Distributed Temperature Sensing

Summary Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut in, the clusters that take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume; however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior. This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (noncommunicating intervals), so the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The nonuniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string, such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Because the varying heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation. A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Because the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned all along the wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Because the interpreted stage interval is not perforated at that time, the thermal behavior at the noncommunicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval. This study provides a field application of the developed interpretation method. The new interpretation method provides more accurate diagnosis of fracture treatments by DTS interpretation.

Discrete element method simulation of the growth and efficiency of multiple hydraulic fractures simultaneously-induced from two horizontal wells

Multiple hydraulic fracturing treatment from horizontal wells has been widely used to enhance the productivity of unconventional hydrocarbons. Interaction among the fractures can cause the reorientation of fractures and lower the stimulation efficiency. We perform discrete element method (DEM) simulations to assess the influence of completion scheme on the trajectory and efficiency of fractures simultaneously-induced from two horizontal wells. Simulation of a single hydraulic fracture yields reasonable agreement with the theoretical solution regarding the fracture pattern and stress alteration and thus confirms the validity of the model. Stress shadowing effect caused by the opening of early fractures alters the state of local stress and thus leads to the appearance of dominant fractures and the reorientation of other fractures located in the altered stress field. Influences of the fracturing scheme including the distance between wells, the spacing between injection points, and arrangement of injection points are examined. The distribution uniformity index reveals that the effect of distance between wells on improving the efficiency of treatment is conditionally dependent on the spacing between injection points. Under the conditions considered in this study, the distance between wells enhance the efficiency only when the spacing reaches 40 m. Similarly, enlarging the spacing between injection points does not affect the distribution uniformity index when the distance between wells is 40 m, but effectively mitigate the stress shadowing effect and promotes the fracturing efficiency when the distance exceeds 60 m. Arrangement of injection point plays a negligible role on the fracturing efficiency compared with the spacing among them.

A fractal approach for surface roughness analysis of laboratory hydraulic fracture

Hydraulic fracturing treatment in rocks creates surfaces that are not smooth but rough in general. Accurate characterization of surface roughness is necessary to relate fracture deformation to fluid flow. In this study, we analyze the surface of an experimentally generated hydraulic fracture using a practical fractal approach which is capable of modeling applications. The hydraulic fracturing test is conducted using a nearly homogeneous siltstone cube in a true triaxial cell, and a fracture is created showing a perfectly radial pattern. To evaluate roughness, each surface profile is decomposed into large-scale fracture waviness and localized surface roughness considering various length scales. Despite the waviness, estimated roughness amplitudes follow a power-law relation up to a length-scale, showing a fractal nature. Unlike ideal brittle materials with an exponent of 0.5, the roughness exponent is found to vary in a narrow range of 0.1 but exceeds 0.5. The fractal dimension (box dimension) of the hydraulic fracture surface is estimated to be 1.4 showing a good match with roughness exponents. An increase in roughness exponent may indicate an increasing difficulty in fracture propagation and fluid and proppant transport along the fracture. As such, the topology of a hydraulic fracture surface is essential to hydraulic fracture growth to assess fracturing performance.

Hydraulic-Fracture-Width Inversion Using Low-Frequency Distributed-Acoustic-Sensing Strain Data—Part I: Algorithm and Sensitivity Analysis

Summary Low-frequency distributed-acoustic-sensing (LF-DAS) data, which can be treated as linear-scaled strain variations, have been used recently to monitor hydraulic-fracturing treatments. Forward geomechanical modeling has been the subject of recent research efforts to better interpret the observed signatures of field LF-DAS data. To the best of our knowledge, there is no study that attempts to quantitatively characterize fracture geometries by directly inverting the LF-DAS strain data. In this study, we propose an inversion algorithm, in which the strains monitored by LF-DAS along an offset well are related to the fracture widths through a Green function. A 3D displacement-discontinuity method is used to construct the Green function. The least-squares method is first used to solve the linear system of equations. Regularization might be needed to stabilize the underdetermined system. Then, Markov-chain Monte Carlo (MCMC) simulations are conducted to generate fracture-width samples from the target distribution of LF-DAS strain data and to quantify uncertainties associated with the inverted widths. The inversion results obtained by the least-squares method are nonunique, heavily depending on the a priori regularization information. Regardless of the additional constraints imposed on the linear system, the inverted fracture width at the monitor-well location is always consistent with the true value because the LF-DAS data show a dominant sensitivity of fracture width near the monitor well. MCMC simulation results confirm that the LF-DAS strain data can only impose constraints on fracture segments near the monitor well. Moreover, the average value of the inverted widths in the vicinity of the monitor well is usually the same as the width right at the monitor well, except for the very early time after fracture hit when there are sharp width variations near the fracture tip. Therefore, it is efficient to use a single width for each fracture during the inversion process. The presented algorithm is successfully applied to invert the width evolution near the monitor well as a function of injection time. The results of this study demonstrate how much information can be obtained with high confidence from the inversion of LF-DAS strain data, which is beneficial for future use of LF-DAS data. The accurate estimation of fracture width at the monitor well can be used to calibrate hydraulic-fracturing models, improve the design of completion parameters such as proppant size, and provide the possibility of characterizing the whole fracture geometry with additional information or assumptions.

How will treatment parameters impact the optimization of hydraulic fracturing process in unconventional reservoirs?

Hydraulic fracturing is a very complex process that has not yet been fully understood. Furthermore, the number of stages, length of fracture clusters in each stage, proppant and fracturing fluid compatibilities, optimum spacing length, proppant transport and placement, proppant and frac-fluid compatibility, and optimum spacing are some of the challenges inhibiting successful application of this technique across the world. In this study, we present the impact of fracture-cluster lengths, proppant types and sizes, proppant densities, frac fluid types, fluid viscosities, and injection rates on hydraulic fracturing process. Firstly, we developed a stress profile to determine initiation location and orientation of the hydraulic fractures, and subsequently created the geological layering in the zone of interest. We grouped our investigations into 5 case studies, followed by developing an efficient hydraulic fracturing design approach, and we determined the optimal treatment to achieve maximum recovery. Our results show that fracture clusters with optimal lengths will provide optimized hydraulic fracture treatment. In addition, high-strength proppants is efficient for shale formations with closure stress exceeding 5000 psi to achieve optimum fracture conductivity and fracture half-length. Furthermore, we observed the high-density proppant produced greater fracture lengths and lower dimensionless fracture conductivity (CFD), while the low-density proppant produced greater effective propped-fracture lengths and higher CFD. In some of the cases investigated, we observed that stress shadowing and interference can hinder fracture growth, eventually led to a collapse of some fractures. Our results provide valuable critical decision-making insight for optimizing hydraulic fracturing process in unconventional reservoirs across the world.

A numerical study of fracture initiation under different loads during hydraulic fracturing

The fracture initiation behavior for hydraulic fracturing treatments highlighted the necessity of proposing fracture criteria that precisely predict the fracture initiation type and location during the hydraulic fracturing process. In the present study, a Mohr-Coulomb criterion with a tensile cut-off is incorporated into the finite element code to determine the fracture initiation type and location during the hydraulic fracturing process. This fracture criterion considers the effect of fracture inclination angle, the internal friction angle and the loading conditions on the distribution of stress field around the fracture tip. The results indicate that the internal friction angle resists the shear fracture initiation. Moreover, as the internal friction angle increases, greater external loads are required to maintain the hydraulic fracture extension. Due to the increased pressure of the injected water, the tensile fracture ultimately determines the fracture initiation type. However, the shear fracture preferentially occurs as the stress anisotropy coefficient increases. Both the maximum tensile stress and equivalent maximum shear stress decrease as the stress anisotropy coefficient increases, which indicates that the greater the stress anisotropy coefficient, the higher the external loading required to propagate a new fracture. The numerical results obtained in this paper provide theoretical supports for establishing basis on investigating of the hydraulic fracturing characteristics under different conditions.