Proppant Concentration Research Articles

Numerical simulation of channel fracturing technology in developing shale gas reservoirs

HiWay flow channel fracturing, as a paradigm shift in the conventional hydraulic fracturing, was introduced by Schlumberger in 2010. The improvement of the new technology compared to conventional fracturing methods is presented by the scattered multi-layer proppants which concentrate loose proppants into fibered pillars in order to provide broader flow pathways in fractures. Although numerous experimental and theoretical research have been conducted in the last decade, limitations still exist. In this study, we investigate the performance of the technique in improving the shale gas productivity via integrating channel fracture models into the open-source framework, MATLAB Reservoir Simulation Toolbox (MRST). A new mathematical model is derived to determine the permeability and conductivity of channel fracturing by the shape changes of pillars in fractures. Verification and validation cases are conducted via comparing with a reference model and oilfield data, respectively. More computational cases are studied to demonstrate factors affecting the performance of channel fracturing, including natural fractures and the concentration of proppants. The simulation result reveals that the channeling fracturing benefits more from the natural fractures compared to the conventional fracturing technique, although the gas production is actually enhanced for both of the techniques. The proppant concentration is also an important parameter. A lower concentration scheme presents a high initial production rate because of the broader channels in fractures. While, a higher concentration scheme will enhance the support of the fracture aperture and benefit the long-term shale gas production. In the field case study, the simulation results are compared with shale gas production data from the well Heim 2H in Hawkville field. The simulated result matches the field data successfully in the stabilized period when the gas production is not affected by the screen out and flowback.

Comprehensive proppant settling model in hydraulic fractures of unconventional gas reservoir considering multifactorial influence

Thus far, hydraulic fracturing has played a crucial role in improving the production of unconventional gas resources. During hydraulic fracturing, the proppant is pumped into an artificial fracture with a low-viscosity fracturing fluid. Then, the proppant settles and makes the artificial fracture open. Therefore, the investigation of proppant settling in the hydraulic fracture is important for the development of unconventional gas reservoirs. This paper proposes a comprehensive mathematical model for quantitatively evaluating the proppant settling rate in the hydraulic fracture of unconventional gas reservoirs. In particular, the model considers the effects of fracture width, proppant size, proppant concentration, fluid viscosity, and flow regime. The model is verified by the experimental data and models found in literatures, and the effects of key parameters (e.g., fluid viscosity, concentration, fracture wall, proppant size, and flow regime) on the settling rate are analyzed. The results show that, with increasing fracture width or decreasing proppant diameter, the dimensionless settling rate increases. By contrast, fluid viscosity has a small effect on the dimensionless settling rate. In addition, the increase of proppant concentration results in a decrease in the dimensionless settling rate. The proppant concentration is the main factor affecting the settling rate, followed by the flow regime, the ratio of proppant diameter to fracture width, and the fluid viscosity. This work can provide a theoretical basis for the study of proppant placement in fractures of unconventional gas reservoirs. Additionally, the developed model can be easily incorporated into fracture simulators to simulate proppant transport.

An optimized model of calculating optimal packing ratio for graded proppant placement with consideration of proppant embedment and deformation

The method of micro-sized Graded Proppant Placement (GPP) has been proposed in the industry to increase the size of the stimulated zone in naturally fractured reservoirs. The models of determining the Optimal Proppant Packing Ratio (OPPR) and the optimal injection schedule have also been established. However, all the previous studies neglected the impact of Proppant Embedment into fracture wall and Proppant Deformation (PEPD), and therefore significant discrepancies between modeling results and experimental results have been observed. In this study, models of calculating PEPD are established and incorporated into the GPP model, and the influences of proppant embedment and deformation on OPPR, optimal injection schedule and predicted post-stimulation productivity increase are investigated. Conductivity Correction Factor (CCF) is introduced to find the OPPR and the results are compared with the results obtained from previous models which are based on Permeability Correction Factor (PCF).The results show that smaller proppant Elastic Modulus or smaller rock Elastic Modulus leads to bigger OPPR and lower PCF. The CCF -based OPPR matches better with previous experimental results than the PCF -based value. The study also shows that with consideration of PEPD, OPPR is significantly larger; the optimal proppant concentrations at different stages of graded proppant injection are accordingly larger, and the predicted folds of productivity increase after stimulation is much lower.The results from this study can be used to optimize the planning of GPP. For the stimulations of soft formations like CBM, shale etc. or the stimulations where less-rigid proppants like silica sand or walnut shell are used, the findings of this study are even more important. If the proppants and the formation rock are assumed to be rigid bodies and PEPD are neglected in such situations, 32.5% lower of proppant concentration will be caused, which will consequently lead to under-propping of the fracture and the productivity will not be maximized supposedly. Meanwhile, the predicted folds of productivity increase will be overestimated by 27.5% maximally. The larger the stimulation zone, the stronger the influence of PEPD. PEPD must be considered when planning a large-scale GPP in soft formations.This study is a continuation of the studies conducted by the authors earlier. The major novel elements are that PEPD are considered, the influences of PEPD are investigated, and fracture conductivity is used instead of permeability to find the optimal proppant packing ratio.

Experimental Study of Sand Distribution among Perforation Clusters in Horizontal Wellbore of Shale Gas Reservoir

Multistage horizontal fracturing is the key technique in developing shale gas reservoirs. In each stage, several perforation clusters will be placed to create complex fractures, and the parameters of perforation clusters are almost the same, so the production from each perforation cluster should be similar. However, in fact, production from each perforation cluster is different vastly. If the characteristics of the shale gas reservoir where the horizontal wellbore oriented through are similar, the cause that resulted in production difference may be uneven proppant distribution among perforation clusters. In order to investigate proppant distribution through perforation clusters, the theory about proppant settling along horizontal lateral is analyzed, which can provide a proper pumping rate for future experiments. Then, an experimental model to simulate horizontal lateral and perforated clusters is designed. Fresh water was pumped to transport proppant flowing into different clusters, the volume of water and proppant through each cluster was qualified. Some parameters, such as proppant concentration, sizes, flow rate, and perforation parameters, are changed in lab tests; the simulation results will be helpful in understanding the phenomenon of uneven proppant distribution in perforation clusters. There are some conclusions from the experimental results. First, proppant settling at different positions along horizontal lateral is different when the slurry is mixed by proppant and water is pumped at different rates. Meanwhile, proppants concentration also has an influence on proppants settling. The settling of proppants will impact proppants distribution among perforation clusters. Second, at a low pumping rate, uneven proppants distribution was observed mostly. When the pumping rate was increased, the phenomenon of uneven proppants distribution was decreasing. Thus, the pumping rate is the main influential factor. Third, uneven proppants distribution can be improved or even avoided by adjusting perforation parameters, such as perforation numbers and diameter.

The use of flowback data for estimating dynamic fracture volume and its correlation with completion-design parameters: Eagle Ford cases

Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between completion-design parameters (CDPs) and fracturing efficiency remains challenging. The objective of this paper is analyzing flowback data to 1) evaluate the change in effective fracture volume (Vef), and 2) investigate the existence of correlations between CDPs and Vef. We analyze flowback data and CDPs of 22 gas and oil wells completed in the Eagle Ford formation. First, we estimate ultimate water recovery and initial effective fracture volume (Vefi) using harmonic-decline (HD) model. Second, we estimate the loss in Vef (Vloss) during flowback using a new iterative approach that accounts for dynamic fracture porosity and compressibility. Third, we introduce a new parameter to characterize fracture closure rate (FCR) during flowback. FCR represents how fast Vef shrinks during flowback. Then, we present a dimensionless type curve to evaluate FCR and investigate its correlation with CDPs. Finally, we conduct a multivariate analysis to correlate CDPs with Vefi and FCR.The developed correlation between Vefi and CDPs shows that the gross perforated interval (GPI) has the most significant effect on Vefi. The proposed correlation between FCR and CDPs demonstrates the significant effect of proppant concentration on fracture closure during flowback.

Mechanics and fracturing techniques of deep shale from the Sichuan Basin, SW China

Deep shale gas exploration and production in Fuling (Sichuan Basin, SW China) are confronted with hydraulic fracturing challenges owing to high stress, high fracture pressure, low pump rate and proppant concentration, as well as high closing pressure in deep strata. This study focused on the mechanical properties of shale core samples from Fuling through high-temperature triaxial rock mechanical tests and in-situ stress tests based on the Kessel effect of acoustic emission. Their mechanical property variations with depth were delineated using brittleness index calculated via simulating different depths and different confining pressures for the samples. The results showed that several parameters of deep shale reservoirs, i.e. brittleness index, fracture density, performance of self-propping, and flow conductivity, are lower than that of shale reservoirs with moderate burial depth. Thus, the current operating pressure in deep shale reservoir stimulation should be taken full advantage of, rather than channeling the focus on the propagation of fracture length. The objective is to increase the complexity of the near-hole fracture network for enhancing self-propping and flow conductivity of the fractures. This can be achieved by reducing the number of perforation clusters and cluster spacing, adopting variable-rate fracturing, decreasing proppant size, increasing sand volume, and optimizing the fracturing parameters. A field application showed that, compared with the neighboring wells, the test well had larger drainage area, doubling the gas yield.

Coupled Hydraulic Fracture and Proppant Transport Simulation

This paper focuses on the study of proppant transport mechanisms in fractures during frac-packing operation. A multi-module, numerical proppant, reservoir and geomechanics simulator has been developed, which improves the current numerical modeling techniques for proppant transport. The modules are linked together and tailored to capture the processes and mechanisms that are significant in frac-pack operations. The proposed approach takes advantage of a robust and sophisticated numerical smeared fracture simulator and incorporates an in-house proppant transport module to calculate propped fracture dimensions and concentration distribution. In the development of software capability, the propped fracture geometry and proppant concentration, which are the output of the proppant module, are imported to the hydraulic fracture simulator through mobility modification. Complex issues of proppant transport in fractures that are addressed in the literature and captured by the current model are: hindered settling velocity (terminal velocity of proppant in the injection fluid), the effect of fracture walls, proppant concentration and inertia on settling (due to extra drag forces applied on particles, compared to single-particle motion in Stokes regime in unbounded medium), possible propped fracture porosity and also mobility change due to the presence of proppant, and fracture closure or extension during proppant injection. A sensitivity analysis is conducted using realistic parameters to provide guidelines that allow more accurate predictions of the proppant concentration and fluid flow. The main objective of this study is to link a numerical hydraulic fracture model to a proppant transport model to study the fracturing response and proppant distribution and to investigate the effect of proppant injection on fracture propagation and fracture dimensions.

IPACS: Integrated Phase-Field Advanced Crack Propagation Simulator. An adaptive, parallel, physics-based-discretization phase-field framework for fracture propagation in porous media

In this work, we review and describe our computational framework for solving multiphysics phase-field fracture problems in porous media. Therein, the following five coupled nonlinear physical models are addressed: displacements (geo-mechanics), a phase-field variable to indicate the fracture position, a pressure equation (to describe flow), a proppant concentration equation, and/or a saturation equation for two-phase fracture flow, and finally a finite element crack width problem. The overall coupled problem is solved with a staggered solution approach, known in subsurface modeling as the fixed-stress iteration. A main focus is on physics-based discretizations. Galerkin finite elements are employed for the displacement-phase-field system and the crack width problem. Enriched Galerkin formulations are used for the pressure equation. Further enrichments using entropy-vanishing viscosity are employed for the proppant and/or saturation equations. A robust and efficient quasi-monolithic semi-smooth Newton solver, local mesh adaptivity, and parallel implementations allow for competitive timings in terms of the computational cost. Our framework can treat two- and three-dimensional realistic field and laboratory examples. The resulting program is an in-house code named IPACS (Integrated Phase-field Advanced Crack Propagation Simulator) and is based on the finite element library deal.II. Representative numerical examples are included in this document.

Application of Koopman operator for model-based control of fracture propagation and proppant transport in hydraulic fracturing operation

This work explores the application of the recently developed Koopman operator approach for model identification and feedback control of a hydraulic fracturing process. Controlling fracture propagation and proppant transport with precision is a challenge due in large part to the difficulty of constructing approximate models that accurately capture the characteristic moving boundary and highly-coupled dynamics exhibited by the process. Koopman operator theory is particularly attractive here as it offers a way to explicitly construct linear representations for even highly nonlinear dynamics. The method is data-driven and relies on lifting the states to an infinite-dimensional space of functions called observables where the dynamics are governed by a linear Koopman operator. This work considers two problems: (a) fracture geometry control, and (b) proppant concentration control. In both cases, an approximate linear model of the corresponding dynamics is constructed and used to design a model predictive controller (MPC). The manuscript shows that in the case of highly nonlinear dynamics, as observed in the proppant concentration, use of canonical functions in the observable basis fails. In such cases, a priori system knowledge can be leveraged to choose the required basis. The numerical experiments demonstrate that the Koopman linear model shows excellent agreement with the real system and successfully achieves the desired target values maximizing the oil and gas productivity. Additionally, due to its linear structure, the Koopman models allow convex MPC formulations that avoid any issues associated with nonlinear optimization.

Geology and geomechanics of hydraulic fracturing in the Marcellus shale gas play and their potential applications to the Fuling shale gas development

Geological characteristics, geomechanical behavior and hydraulic fracture propagation mechanism in the Marcellus shale gas play are analyzed and compared with China’s Fuling shale play. Successful experiences in hydraulic fracturing and shale gas development in the Marcellus shale gas play are summarized, which might be applicable in other shale plays. The main factors contributing to the successful development of the Marcellus shale gas play include adoption of advanced drilling and completion technologies, increases of hydraulic fracturing stages, proppant concentration and fluid injection volume. The geological and geomechanical mechanisms related to those technologies are analyzed, particularly the in-situ stress impacts on hydraulic fracturing. The minimum horizontal stress controls where the fractures are initiated, and the maximum horizontal stress dominates the direction of the hydraulic fracture propagation. Hydraulic fracturing performed in the shale reservoir normally has no stress barriers in most cases because the shale has a high minimum horizontal stress, inducing hydraulic fractures propagating beyond the reservoir zone, resulting in inefficient stimulation. This is a common problem in shale plays, and its mechanism is studied in the paper. It is also found that the on-azimuth well has a higher productivity than the off-azimuth well, because shear fractures are created in the off-azimuth well, causing main fractures to kink and increasing fracture tortuosity and friction. The Fuling shale gas play has a markedly higher minimum horizontal stress and much smaller horizontal stress difference. The high minimum horizontal stress causes a much higher formation breakdown pressure; therefore, hydraulic fracturing in the Fuling shale gas play needs a higher treatment pressure, which implies higher difficulty in fracture propagation. The small difference in the two horizontal stresses in the Fuling shale gas play generates shorter and more complex hydraulic fractures, because hydraulic fractures in this case are prone to curve to preexisting fractures. To overcome these difficulties, we recommend reducing well spacing and increasing proppant concentration to increase gas productivity for the Fuling shale gas development.

Laboratory-scale study on proppant behaviour in unconventional oil and gas reservoir formations

Persisting oil/gas recovery controversies throughout the fracture stimulation stage due to early production reductions have raised questions about realistic proppant performance in deep in-situ fractures. Therefore, a detailed understanding of proppant behaviour and performance in fractures exposed to deep reservoir environments is required for enhanced oil/gas exploitation. This experimental study aims to analyse the importance of proppant injection techniques, and also oil and gas reservoir formation properties (fracture surface roughness and formation saturation conditions) on the mechanisms of proppant distribution, proppant crushing and proppant embedment. Importantly, the impact of injecting mono-sized proppants and different-sized proppant mixtures are analysed in this comprehensive experimental approach. Moreover, the influence of microstructural and mineralogical alterations in fracture surfaces on proppant behaviour upon exposure to different fracturing/reservoir fluids (deionized (DI) water, NaCl 10%, NaCl 25% and, oil) are studied. The results reveal that increased fracture surface roughness tends to result in non-uniform distribution of proppants in the fracture surface, which leads to greater proppant embedment and crushing. However, the injection of different-sized ceramic proppant mixtures upon subjecting to high stresses yields better results in terms of proppant distribution, reduced fracture aperture drop and reduced fracture tortuosity increase compared to injection of mono-sized proppants. Despite the proppant injection mechanism and fracture surface roughness, fracture tortuosity increases due to the effect of proppant re-arrangement, crushing and embedment. The microstructural analysis confirmed that proppant embedment is more likely to occur at kaolinite-rich zones. In addition, CT-scan analysis confirmed the initiation and propagation of secondary micro-cracks from proppant-embedded locations. Exposure of siltstone specimens to fracturing/reservoir fluid conditions substantially increased proppant embedment. Whatever the proppant size, concentration, roughness and axial load, the fracturing/reservoir fluid interaction-induced coupled process of fracture surface softening and chemical corrosion were found to be critical factors in estimating proppant embedment under reservoir conditions.

Experimental Study on the Damage of Artificial Fracture Permeability in Coal during the Flow Back of Guar-Based Fracturing Fluid

After the completion of fracturing operation in coalbed methane (CBM), the fracturing fluid needs to flow back to the ground in time to reduce the damage to the coal reservoir. The damage of guar-based fracturing fluid to the coal reservoir has an adverse effect on the fracturing stimulation. A series of flow experiments were carried out with the unconventional natural gas reservoir damage evaluation equipment. This paper investigates the evolution of fracture permeability in coal samples during the process of hydroxypropyl guar (HPG) fracturing fluid flow back. The experimental results show that the fracturing fluid concentration, proppant type, proppant particle size, and proppant concentration all affect fracture permeability. The high concentration of fracturing fluid caused irreversible damage to fracture permeability of coal samples. With the increase of fracturing fluid concentration, the permeability damage rate increased from 65.31% to 84.57%, and the damage degree was strong. KCL brine flushing can only decrease the damage rate of coal sample fracture permeability within a certain range. The proppant embedment and the generation of pulverized coal exacerbated the damage of fracture permeability. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in CBM reservoir.

Fracturing-Fluid Flowback Simulation with Consideration of Proppant Transport in Hydraulically Fractured Shale Wells.

Involving the fluid-particle hydrodynamic process and hydraulically created fracture network, fracturing-fluid flowback in hydraulically fractured shale wells is a complex transport behavior. However, there is limited research on investigating the influence of proppant transport on the fracturing-fluid flowback behavior and flowback data analysis. In this paper, a flowback model is developed to simulate the flowback behaviors of the carrying fluid and proppant from the recompacted fracture system in shale wells. The development of fluid pressure and proppant concentration profiles of the fractured shale well are presented. The fluid and proppant fluxes among the hydraulic primary fracture and the induced fracture are also calculated. The influences of proppant consideration or not, proppant density, proppant size, fracturing-fluid viscosity, and fracturing-fluid density on the flowback behavior are investigated. The simulation results are useful for fracturing-fluid optimization in the design phase. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China are used for matching the actual flowback data with the model results. The results prove that the proppant transport has influence on the flowback behavior to some degree and should be considered in the flowback model for a rather elaborate flowback analysis and post-treatment fracture evaluation.

Numerical analysis of proppants transport in tortuous fractures of shale gas reservoirs after shear deformation

For a better understanding of the proppants distribution in complicated hydraulic fractures, a numerical model was established to investigate the proppants transport in tortuous fractures after the shear displacement. First, a method combining the normal distribution random function and the random growth method was proposed to construct three-dimensional tortuous fractures. Because of the shear deformation, the tortuous fracture was divided into several branch channels, which was much more complicated than the parallel and smooth fracture. And then, proppants motion in tortuous fractures was simulated by the analysis of forces on proppants, considering the interaction between particles, between proppants and the slurry, and between proppants and the fracture surface. The accuracy of this model was verified by the comparison between the simulated result and the experimental observation. From the simulation under different conditions, it can be concluded that increasing the pumping rate and fracturing fluid viscosity and decreasing the proppant density are more effective ways to improve the proppant distribution compared with the increase of proppant concentration. However, problems of proppants distribution still remained by adjusting a single factor, which can be solved by the combination of multi-foctors. And the slurry pumping rate and proppant concentration needed to be optimized to avoid the sparse distribution of proppants in the fracture. This study is helpful to understand the mechanism of proppants transport in the complex fracture.

Crushing and embedment of proppant packs under cyclic loading: An insight to enhanced unconventional oil/gas recovery

Crushing and embedment are two critical downhole proppant degradation mechanisms that lead to a significant drop in production outputs in unconventional oil/gas stimulation projects. These persistent production drops due to the non-linear responses of proppants under reservoir conditions put the future utilization of such advanced stimulation techniques in unconventional energy extraction in doubt. The aim of this study is to address these issues by conducting a comprehensive experimental approach. According to the results, whatever the type of proppant, all proppant packs tend to undergo significant plastic deformation under the first loading cycle. Moreover, the utilization of ceramic proppants (which retain proppant pack porosity up to 75%), larger proppant sizes (which retain proppant pack porosity up to 15.2%) and higher proppant concentrations (which retain proppant pack porosity up to 29.5%) in the fracturing stimulations with higher in-situ stresses are recommended to de-escalate the critical consequences of crushing associated issues. Similarly, the selection of resin-coated proppants over ceramic and sand proppants may benefit in terms of obtaining reduced proppant embedment. In addition, selection of smaller proppant sizes and higher proppant concentrations are suggested for stimulation projects at depth with sedimentary formations and lower in-situ stresses where proppant embedment predominates. Furthermore, correlation between proppant embedment with repetitive loading cycles was studied. Importantly, microstructural analysis of the proppant-embedded siltstone rock samples revealed that the initiation of secondary induced fractures. Finally, the findings of this study can greatly contribute to accurately select optimum proppant properties (proppant type, size and concentration) depending on the oil/gas reservoir characteristics to minimize proppant crushing and embedment effects.

Optimization of proppant parameters for CBM extraction using hydrofracturing by orthogonal experimental process

Abstract Proppant placement concentration, particle size and creep time are important factors that affect the embedment of proppant into coal. Based on multistage creep, an orthogonal test is conducted, and an optimal proppant scheme for different closure stresses obtained. The results show that with increased proppant placement concentration, the number of coal fractures increases and the elastic modulus of the fracture area decreases. As the proppant particle size decreases, the plasticity of fracture-proppant assemblies increases gradually. The yield limit is highest when the particle size is 20/40 mesh. During the proppant embedding process, localization or uneven distribution of proppant results in tensile stress parallel to the fracture surface, which induces tensile fracture in the coal. In the fracture-proppant assembly areas, proppant fractures are severe and yield lines appear. As proppant concentration increases, more energy is accumulated during the proppant compaction stage, resulting in energy release producing craters and crevasses. The energy released also causes increased stress in the proppant-coal contact area and fracturing to the coal mass. The longer the creep time, the weaker the impact and the smaller is fluctuation. Moreover, we find that the orthogonal test can effectively analyze the importance of each parameter. Proppant placement concentration was found to have the highest influence on the process of proppant embedding into coal, followed by particle size and then time. Under experimental conditions, the lowest proppant-embedded value in coal samples was observed with proppant placement concentration of 2 kg m−2 and particle size of 20/40 mesh.

Parameters affecting the distribution of pulsed proppant in hydraulic fractures

Intermittent proppant injection into hydraulic fractures is a newly-developing technology in well stimulation. It is designed to form voids inside proppant packs which serve as highly conductive channels for oil and gas transport. However, it remains unclear the extent to which this non-homogeneous, pulse-like proppant concentration persists over the extent of the fracture. This paper models proppant transport in a PKN (Perkins–Kern–Nordgren) fracture in which the proppant-laden and proppant-free fluids are pumped intermittently. Simulations are performed to investigate proppant transport and final distribution under the influence of various factors. It can be observed that several parameters such as Young's modulus and fluid injection rate have significant influence on proppant transport, particularly the spatial period and attenuation of the resulting waves of proppant concentration as they move into the growing fracture. In contrast, when fluid viscosity is high, some parameters such as density difference, particle size do not strongly affect spatial period and attenuation of the proppant waves. The simulations show when the proppant is injected intermittently using high viscosity fracturing fluid, proppant concentration inside a hydraulic fracture from wellbore bottom hole to fracture tip is non-uniform and appears like a damped wave. An equation which is similar to damped wave solution is used to describe this proppant concentration characteristic, thus enabling a dimensional analysis to identify the key parameters affecting proppant distribution and specifically the attenuation of the concentration waves. Two characteristic lengths can be associated with attenuation of these proppant waves prior to severe screen-out and settlement– one for cases with leakoff and one for cases without leakoff. After scaling the horizontal coordinate by the appropriate characteristic length, the relationship between concentration amplitude and dimensionless distance for all cases can be depicted in a uniform way.

Numerical simulation of proppant transport and tip screen-out in hydraulic fracturing with the extended finite element method

In this paper, a numerical model is developed based on the X-FEM technique to simulate the proppant transport and tip screen-out in hydraulic fracturing. The governing equations are based on the momentum balance and mass conservation of the fluid. The hydro-mechanical coupling between the fracture and surrounding porous medium is fulfilled through the weak form of the governing equations. The fluid inflow within the fracture is modeled using the one-dimensional mass conservation of the injected slurry and proppant along the fracture, in which the viscosity of the slurry is dependent on the proppant concentration. The transition from the Poiseuille to Darcy flow regime is incorporated into the computational model as the proppant concentration reaches its maximum pack value. In order to represent the fracture, the extended finite element method (X-FEM) is employed by applying the appropriate enrichment functions. The fracture imposes a discontinuity in the rock displacement, as well as, the gradient of the fluid pressure in normal direction to the fracture. Finally, several numerical examples of typical hydraulic fracturing problems are simulated to investigate the behavior of the fracture propagation in the case of proppant transport and tip screen-out formation. The influence of various parameters of the proppant, such as the injection concentration and proppant size, as well as the porous medium, such as the permeability, is investigated.

Experimental and Simulation Studies of Energized Fracturing Fluid Efficiency in Tight Gas Formations

The use of water-based fracturing fluids during fracturing treatment can be a problem in water-sensitive formations due to the permeability damage hazard caused by clay minerals swelling. The article includes laboratory tests, analyses and simulations for nitrogen foamed fracturing fluids. The rheology and filtration coefficients of foamed fracturing fluids were examined and compared to the properties of conventional water-based fracturing fluid. Laboratory results provided the input for numerical simulation of the fractures geometry for water-based fracturing fluids and 50% N2 foamed fluids, with addition of natural, fast hydrating guar gum. The results show that the foamed fluids were able to create shorter and thinner fractures compared to the fractures induced by the non-foamed fluid. The simulation proved that the concentration of proppant in the fracture and its conductivity are similar or slightly higher when using the foamed fluid. The foamed fluids, when injected to the reservoir, provide additional energy that allows for more effective flowback, and maintain the proper fracture geometry and proppant placing. The results of laboratory work in combination with the 3D simulation showed that the foamed fluids have suitable viscosity which allows opening the fracture, and transport the proppant into the fracture, providing successful fracturing operation. The analysis of laboratory data and the performed computer simulations indicated that fracturing fluids foamed by nitrogen are a good alternative to non-foamed fluids. The N2-foamed fluids exhibit good rheological parameters and proppant-carrying capacity. Simulated fracture of water-based fracturing fluid is slightly longer and higher compared to foamed fluid. At the same time, when using a fluid with a gas additive, the water content in fracturing fluid is reduced which means the minimization of the negative results of the clay minerals swelling.

Aggressive Stimulation Design Yields Better Returns

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191864, “Aggressive or Not? Experimenting With Fracturing Design and Fluids in Pursuit of Better Returns,” by Max Nikolaev, SPE, Haiyan Zhao, Yenny Christanti, SPE, and Sergey Makarychev-Mikhailov, SPE, Schlumberger, prepared for the 2018 SPE Argentina Exploration and Production of Unconventional Resources Symposium, Neuquén, Argentina, 14–16 August. The paper has not been peer reviewed. The authors examine methods of adopting an aggressive approach to optimizing stimulation design to lower the breakeven level of operations and evaluate the results. Operators achieved significant improvements in production by changing parameters in the fracturing and completion design strategy, including, but not limited to, the amount of water used, the amount of sand pumped, stage spacing, maximum sand concentration, and fracturing-fluid selection. The complete paper addresses the importance of aggressive design, its evolution, and its enabling technologies. Trends in Development of Unconventional Resources Although completion practices and production numbers vary from basin to basin and from play to play, certain high-level trends remain in the development of unconventional reservoirs over the past few years. In most places, operators have been drilling increasingly longer laterals. Although public fracturing-stage-count information is scarce, internal service-company data still show a continuous increase in stage count and, in certain plays, an increase steeper than the increase seen in perforated intervals. Cased-hole completions with more than 50 stages per well are becoming common in all basins, thanks to the improved efficiency of fracturing and plug-and-perf•operations. At the same time, fracturing treatment sizes have grown even faster than have perforated intervals and stage counts. Median proppant volumes have nearly tripled during the past 5 years. The stimulation fluid volumes increased nearly proportionally to proppant volumes. Slickwater (SW) has become a fluid of choice in most plays, thanks to its operational simplicity and low cost. Hybrid treatments also remain popular; in these approaches, a high-viscosity crosslinked fluid, usually guar-based, often is pumped at the end of a treatment to deliver higher proppant concentrations and effectively prop the near-wellbore area. The number of higher-cost and operationally more-complex crosslinked fluid-fracturing jobs has decreased as placement of large amounts of proppant with crosslinked jobs becomes uneconomical. Longer laterals, better wellbore coverage, and significant amounts of fracturing materials enable increased well productivity in most plays. Production here is expressed in barrels of oil equivalent, calculated on the basis of relative cost, with 20 Mscf equal to 1 bbl of oil. Median production volumes, normalized by 1,000 ft of perforated interval, still demonstrate substantial increase over time. However, with production normalized by 1,000,000 lbm of proppant, or by proppant density per perforated interval, the trends turn negative, indicating diminished returns with further increase of proppant volumes per well.