Fracture Conductivity Research Articles

Model for fracture conductivity considering particle size redistribution caused by proppant crushing

Clarifying the dynamic evolution and control mechanisms of fracture conductivity is crucial for optimizing hydraulic fracturing design. Previous studies on fracture conductivity mechanisms in deep shale reservoirs have been insufficient, particularly when considering proppant crushing, rendering existing models inapplicable. Therefore, in this study, the coupled effects of particle size redistribution caused by proppant crushing were considered. A particle crushing model based on fractal theory was introduced. It was combined with the Kozeny–Carman equation, and equations were derived for the evolution of the equivalent diameter of the proppant pile gradation curve and permeability, establishing a new model for predicting the fracture conductivity considering the particle size redistribution caused by proppant crushing. Furthermore, it provides an optimized chart of conductivity that matches the supply conductivity of the reservoir. The results of the study reveal that the fracture conductivity decreases owing to proppant rearrangement, compaction, and crushing, with a more significant decline in the initial compression stage, where the rate of conductivity reduction is 2.5 times that of the compaction stage. Proppant crushing shifts the gradation curve leftward, reducing the equivalent particle diameter and, consequently, the fracture conductivity. By adjusting the crushing ratio, apparent Young's modulus, looseness factor, and proportion of large-particle components of the proppant, the fracture conductivity can be controlled. This provides a theoretical basis for the development of proppant properties and fracturing optimization in deep shale reservoirs.

Optimization Design of Hydraulic Fracturing Fracture Parameters of Horizontal Wells in Algal Limestone Reservoir

The algal limestone reservoir has extremely low permeability, developed dissolution pores and weak structural planes, and has heterogeneity. There is a problem of significant differences in single-well production after fracturing in oilfield sites. It is crucial to clarify the matching relationship between hydraulic fracture parameters and production. This article establishes a triple medium seepage mathematical model of “fracture—dissolution pore—matrix pore” considering the lithological characteristics of algal limestone, which is used to predict the cumulative production of horizontal wells after fracturing, and its reliability is verified through example well production data. The influence of fracture parameters on the production of horizontal wells was revealed through numerical simulation, filling the gap in the study of parameters for the stimulation of algal limestone reservoirs. The results indicate that the proposed triple medium model can accurately characterize the characteristics of algal limestone and is suitable for simulating the production capacity of algal limestone reservoirs. The production of horizontal wells is influenced by various hydraulic fracture parameters. The length, conductivity, and height of hydraulic fractures are positively correlated with production, while the spacing between fractures is negatively correlated with production. Taking the overall production of the platform horizontal well group as the optimization objective, and the change in production increase as the discrimination criterion, the optimal values of various fracture parameters are determined. At the same time, simulation results show that using the staggered fracture pattern is beneficial for improving the overall production. The research results have reference significance for the development of algal limestone reservoirs

A five field formulation for flow simulations in porous media with fractures and barriers via an optimization based domain decomposition method

The present work deals with the numerical resolution of coupled 3D–2D problems arising from the simulation of fluid flow in fractured porous media modeled via the Discrete Fracture and Matrix (DFM) model. According to the DFM model, fractures are represented as planar interfaces immersed in a 3D porous matrix and can behave as preferential flow paths, in the case of conductive fractures, or can actually be a barrier for the flow, when, instead, the permeability in the normal-to-fracture direction is small compared to the permeability of the matrix. Consequently, the pressure solution in a DFM can be discontinuous across a barrier, as a result of the geometrical dimensional reduction operated on the fracture. The present work is aimed at developing a numerical scheme suitable for the simulation of the flow in a DFM with fractures and barriers, using a mesh for the 3D matrix non conforming to the fractures and that is ready for domain decomposition. This is achieved starting from a PDE-constrained optimization method, currently available in literature only for conductive fractures in a DFM. First, a novel formulation of the optimization problem is defined to account for non permeable fractures. These are described by a filtration-like coupling at the interface with the surrounding porous matrix. Also the extended finite element method with discontinuous enrichment functions is used to reproduce the pressure solution in the matrix around a barrier. The method is presented here in its simplest form, for clarity of exposition, i.e. considering the case of a single fracture in a 3D domain, also providing a proof of the well posedness of the resulting discrete problem. Four validation examples are proposed to show the viability and the effectiveness of the method.

Role of Fracture Roughness in Fracture Surface Evolution During Acidized Corefloods of Calcareous Shales

Summary During the hydraulic fracturing process, an acidic hydraulic fracturing fluid (HFF) is injected at high flow rates to break the rock and enhance its flow potential. This rock-fluid interaction induces both physical and chemical alterations on the fracture surface, resulting in the formation of a “reaction-altered zone.” Recent research has revealed that the depth of reaction penetration is minimal, and most changes occur on the fracture surface. To gain a deeper understanding of how fracture roughness affects fracture aperture change, in this work we adopt an experimental approach. Two similar samples of carbonate-rich Wolfcamp shale with calcite-filled fractures are selected. One sample is cut through the center creating a smooth fracture (SF), while the other is fractured by parting along the calcite-filled fracture, generating a rough fracture (RF). The fracture surface topography, mineral distribution, fracture aperture, and rock hardness are characterized before a reactive coreflood using an equilibrated acidic brine is conducted. The pressure drop across the core is measured, and the effluent is periodically collected and analyzed using mass spectrometry. The temporal changes in the fracture surface are observed by conducting physicochemical surface characterization after the coreflood. The results indicate that calcite dissolution is the primary chemical reaction occurring on the fracture surface, weakening it. Furthermore, this dissolution decreases the fracture roughness, which results in fracture closure and ultimately a decrease in the fracture conductivity. The most significant change in the fracture aperture is observed near the inlet. These results highlight the potential impact of fracture roughness on the mechanism of fracture evolution during acidized corefloods. Higher fracture roughness is associated with increased fines migration and a more significant overall change in fracture aperture during injection. This research provides valuable insights into the intricate processes at play during hydraulic fracturing and aids in understanding the dynamics of fracture growth in such conditions.

Effect of proppant injection condition on fracture network structure and conductivity

AbstractThe hydraulic fracturing of shale reservoirs is an important topic, and adjusting the fracturing process can enhance fracturing efficiency. To analyze the effect of injection conditions on the fracture network structure and conductivity, numerical simulations and theoretical calculations are carried out based on the construction data, and the variation patterns of the fracture network parameters are determined. During the theory study, a fracture network conductivity model was obtained by combining the fracture network expansion model and the fracture diversion model. Then a numerical model was set up according to the analysis results of monitoring data. The numerical simulation results showed the fracture network structure and proppant distribution under different conditions. Throughout the simulation process, the structural parameters and conductivity of the fracture network can be determined by controlling the injection amount and adjusting the injection method, speed, and sand ratio. Results indicated that the proppant pulse frequency during the injection process was a major factor affecting the structure and conductivity of the fracture network. At the same time, a comparison of the distribution structure of the proppant revealed that although the intermittent injection of the proppant improved the flow channel, the efficiency of fracture utilization can still be improved.

Revelling pore microstructure impacts on the compressive strength of porous proppant based on finite and discrete element method

Ceramic spheres, typically with a particle diameter of less than 0.8 mm, are frequently utilized as a critical proppant material in hydraulic fracturing for petroleum and natural gas extraction. Porous ceramic spheres with artificial inherent pores are an important type of lightweight proppant, enabling their transport to distant fracture extremities and enhancing fracture conductivity. However, the focus frequently gravitates towards the low-density advantage, often overlooking the pore geometry impacts on compressive strength by traditional strength evaluation. This paper numerically bypasses such limitations by using a combined finite and discrete element method (FDEM) considering experimental results. The mesh size of the model undergoes validation, followed by the calibration of cohesive element parameters via the single particle compression test. The stimulation elucidates that proppants with a smaller pore size (40 µm) manifest crack propagation evolution at a more rapid pace in comparison to their larger-pore counterparts, though the influence of pore diameter on overall strength is subtle. The inception of pores not only alters the trajectory of crack progression but also, with an increase in porosity, leads to a discernible decline in proppant compressive strength. Intriguingly, upon crossing a porosity threshold of 10 %, the decrement in strength becomes more gradual. A denser congregation of pores accelerates crack propagation, undermining proppant robustness, suggesting that under analogous conditions, hollow proppants might not match the strength of their porous counterparts. This exploration elucidates the underlying mechanisms of proppant failure from a microstructural perspective, furnishing pivotal insights that may guide future refinements in the architectural design of porous proppant.

Optimizing the preparation of multi-colored dye-tracer proppants: A potential approach for quantitative localization and volume assessment of proppant flowback in multistage fractured horizontal wells

Proppant flowback is a common phenomenon after hydraulic fracturing of oil and gas wells. Especially in the large-scale sanding mode of horizontal wells, sand production after fracturing is usually serious. Proppant flowback can not only clog wellbore and wear out equipment, add additional hauling and disposal costs, but also reduce conductivity of the propped fractures, severely affecting oil and gas production. However, there is still a lack of effective means for locating sand production in horizontal wells. Traditional tracer proppants mainly use radioactive elements to monitor the shape of fractures, but they cannot tell the location and amount of sand production. In this work, dye tracer proppant of eight different colors was prepared by dyeing quartz sand proppant. The results show that all the eight kinds of dyes can dye the quartz sand proppant effectively and evenly. The optimal ratio of proppant mass to MB solution volume was determined to be 1:0.015, and the ratio of proppant mass to fixing agent volume was 1:0.0125. The dyed tracer proppant showed good dyeing stability at pH values of 6–13 and surfactant concentrations of 0–200 mg/L. The salinity and fracturing fluid did not affect its stability, and temperature had a negative effect on the stain stability. However, even in the most severe case of decolorization in the experiment, that is, after the dyed proppant was soaked for 24 h at a high temperature of 120 °C, the color of the dried dyed proppant was still clearly distinguished from that of ordinary quartz sand. In theory, using these dyed proppants can potentially tell quantitively the location and volume of sand production during horizontal large-scale fracturing flowback. Since this method has not been used in hydraulic fracturing, it only provides a new way to monitor the sand production of horizontal wells after fracturing. It can provide valuable data for adjusting subsequent fracturing process and has important implications for improving efficiency of fracturing operation of unconventional oil and gas reservoirs.

Robust and tunable hydrogels strengthened by dynamic amphiphilic ionic domains

Hydrogels have gained increasing attentions in wearable electronics, but endure notch-sensitive and poor mechanical behavior in real-world applications. Herein, a robust and tunable hydrogel network was constructed by involving a polymerizable amphiphilic ionic liquid in polymer chains through a facile and novel strategy without additional chemical crosslinkers. The ingeniously designed dynamic amphiphilic ionic domains that are tuned by the structural domain and functional domain are crucial for reinforcing the structural integrity and allowing the polymer chains to accomplish reversible unfolding and ordered migration. The robust and functional microstructures effectively prevent crack propagation, enhancing the fracture strain (1200–2390%), tensile stress (380–1560 kPa), toughness (5–15 MJ m−3), and conductivity (0.13–0.2 mS cm−1). The obtained hydrogel acts as an excellent mechanoresponsive sensor to perceive various external stimuli to sensitively detect diverse human activities including large body motions and subtle muscle movements via electrical signals. Additionally, this strategy shows good applicable potential for preparing high-performance hydrogels based on monomers containing active double bonds, overcoming the disadvantages of poor mechanical properties of traditional free radical polymerization gels. It is anticipated that the design of dynamic amphiphilic ionic domains will provide guidance for regulating the polymer network of hydrogels and show great application potentials in real-life scenarios.

Effect of Proppant Damages on Fracture Conductivity and Long-Term Recovery in Shale Gas Reservoirs

Effect of Proppant Damages on Fracture Conductivity and Long-Term Recovery in Shale Gas Reservoirs

Acid-etched fracture morphology and conductivity of acid fracturing in carbonate rock using novel isolation membrane acid

In recent years, low-viscosity isolation membrane acid (ISM acid) has emerged as a novel retardant acid for matrix acidizing and acid-fracturing in carbonate reservoir. Its ability to create long wormholes in carbonate rock has been extensively studied, while its potential to etch hydraulic fracture and generate conductivity has received less attention. To address the knowledge gap, a series of experiments were conducted in this study, including rheological test, acid-etching simulation experiments, surface laser scanning of acid-fractures, and conductivity tests. The differences in rheological characteristics between ISM acid, blank HCl acid, and gelled acid were compared across different lithology along with the morphology and conductivity of the etched fractures. The viscosity of ISM acid is found to be nearly identical to that of blank HCl, which is 1/26th that of gelled acid. However, the acid-rock reaction rate of ISM acid is only 46–55% compared to blank HCl acid. In dolomite formations, the rate approximates that of gelled acid but is lower in limestone formations, indicating a strong ability for low-viscosity retarding. The heterogeneity of ISM acid etching morphology approaches that of blank HCl acid but exhibits greater retard strength than gelled acid. Under medium to high closure pressure (10–30 MPa), ISM acid generates higher conductivity and better retention ability. This study provides certain guidance for the design of ISM acid fracturing in carbonate reservoir.

Efficient placement technology of proppants based on structural stabilizers

Fiber is highly escapable in conventional slickwater, making it difficult to form fiber-proppant agglomerate with proppant and exhibit limited effectiveness. To solve these problems, a novel structure stabilizer (SS) is developed. Through microscopic structural observations and performance evaluations in indoor experiments, the mechanism of proppant placement under the action of the SS and the effects of the SS on proppant placement dimensions and fracture conductivity were elucidated. The SS facilitates the formation of robust fiber-proppant agglomerates by polymer, fiber, and quartz sand. Compared to bare proppants, these agglomerates exhibit reduced density, increased volume, and enlarged contact area with the fluid during settlement, leading to heightened buoyancy and drag forces, ultimately resulting in slower settling velocities and enhanced transportability into deeper regions of the fracture. Co-injecting the fiber and the SS alongside the proppant into the reservoir effectively reduces the fiber escape rate, increases the proppant volume in the slickwater, and boosts the proppant placement height, conveyance distance and fracture conductivity, while also decreasing the proppant backflow. Experimental results indicate an optimal SS mass fraction of 0.3%. The application of this SS in over 80 wells targeting tight gas, shale oil, and shale gas reservoirs has substantiated its strong adaptability and general suitability for meeting the production enhancement, cost reduction, and sand control requirements of such wells.

Large-scale physical simulation of injection and production of hot dry rock in Gonghe Basin, Qinghai Province, China

Based on the independently developed true triaxial multi-physical field large-scale physical simulation system of in-situ injection and production, we conducted physical simulation of long-term multi-well injection and production in the hot dry rocks of the Gonghe Basin, Qinghai Province, NW China. Through multi-well connectivity experiments, the spatial distribution characteristics of the natural fracture system in the rock samples and the connectivity between fracture and wellbore were clarified. The injection and production wells were selected to conduct the experiments, namely one injection well and two production wells, one injection well and one production well. The variation of several physical parameters in the production well was analyzed, such as flow rate, temperature, heat recovery rate and fluid recovery. The results show that under the combination of thermal shock and injection pressure, the fracture conductivity was enhanced, and the production temperature showed a downward trend. The larger the flow rate, the faster the decrease. When the local closed area of the fracture was gradually activated, new heat transfer areas were generated, resulting in a lower rate of increase or decrease in the mining temperature. The heat recovery rate was mainly controlled by the extraction flow rate and the temperature difference between injection and production fluid. As the conductivity of the leak-off channel increased, the fluid recovery of the production well rapidly decreased. The influence mechanisms of dominant channels and fluid leak-off on thermal recovery performance are different. The former limits the heat exchange area, while the latter affects the flow rate of the produced fluid. Both of them are important factors affecting the long-term and efficient development of hot dry rock.

Investigation of Effective Fracture Height Using Strain Responses in a Vertical Monitoring Well during a Well Interference Test

Summary Understanding and characterizing the effective hydraulic fracture height are critical for optimizing completion design and well performance in unconventional reservoirs. Rayleigh frequency shift distributed strain sensing (RFS-DSS) data provide crucial information about the fracture geometry by measuring the strain change along the fiber. Recently, the strain data from the vertical monitoring well [VMW; Boxwood 5 Pilot Hole (B5PH)] at Hydraulic Fracture Test Site 2 (HFTS-2) was collected during a well interference test conducted on two neighboring horizontal wells [Boxwood 3H (B3H) and Boxwood 4H (B4H)] in September 2020. However, this data set was overlooked and not comprehensively analyzed. Consequently, the valuable information that this data may provide remains unexplored. The objective of this study is to determine how to interpret this vertical strain data and assess its potential to provide insights into the effective fracture height generated in the horizontal wells. To understand the measured strain data, we have developed a coupled fluid flow and geomechanics model to simulate the vertical strain responses observed during production and the well interference test. The characteristics of the strain responses are thoroughly analyzed to establish guidelines for identifying the upper and lower tips of the effective fracture in different fracture geometry scenarios. In addition, field-measured data are examined, and a history-matching process is conducted by comparing the numerical matching results with the observed data to identify the effective fracture height. Furthermore, the pressure gauge data are analyzed and compared with the strain data results to further validate the findings. The study has demonstrated that vertical strain measurements obtained from a VMW can be used to determine the effective fracture height. Large strain responses, characterized by both negative and positive peaks, are observed near the tips of the effective fractures. The upper and lower tips of the effective fracture can be identified by examining the locations of zero-strain change. The magnitude of strain response is affected by the distance between the fracture and the fiber. It is worth noting that the locations where the absolute value of the derivative of fracture conductivity changes abruptly correspond to the positions of the fracture tips. Furthermore, we study and history match the field-measured vertical strain change in HFTS-2 data sets. The pressure gauge data are analyzed to further validate our findings. The effective fracture height determined from the strain measurements falls within the range of 11,360–11,616 ft, which is consistent with the values obtained from pressure gauges (11,360–11,635 ft). Specifically, for B4H, the effective fracture height was determined to be 256 ft at a distance of 330 ft away at the time of data acquisition. Overall, the strain measurements provide valuable, time-dependent insights into the effective fracture height and the active drainage interval.

Research on optimization of conductivity of multilevel fractures in tight sandstone based on similar circuit principle

AbstractVolume fracturing technology is commonly used to develop tight sandstone reservoirs. During the fracturing process, it is important to not only focus on achieving a larger stimulation volume but also on creating a fracture network conductivity that is suitable for the tight reservoir. However, while there have been numerous studies on optimizing the conductivity of individual fractures, the optimization of fracture network conductivity is still incomplete. To address this issue, a reservoir numerical model is established to optimize the equivalent conductivity of the post‐fracturing fracture network, considering it as a high permeability zone, optimizing the equivalent conductivity to 9.7 μm2 cm. Utilizing the discrete element theory, a “pipe domain” discrete element model is developed to analyze fracture expansion. The findings indicate that the ratios of first‐level, second‐level, and third‐level fractures differ based on the number of clusters, such as 1:4:8 and 1:5:9 for three‐cluster and four‐cluster perforations. By applying the hydropower similarity principle, the fracture network is treated as a three‐level circuit to determine the conductivity of each fracture level. Finally, the model is fitted based on conductivity to determine the optimal fracture conductivity for different fracture number ratios, thereby enhancing the flow capability.

Stimulation effect of network fracturing combined with sealing boundaries on the depressurization development of hydrate reservoir in China's offshore test site

This study investigated the stimulation of reservoir reconstruction by network fracturing combined with sealing boundaries (RC-HFBS) for hydrate development in China's offshore test site. We first studied the influence of different boundary-sealing characters on development performance. Then, the response of development performance to key production parameters including fracture conductivity (CF), fracture spacing (SF), and production pressure (Pp) under permeable and impermeable boundaries was studied. Lastly, the long-term commercial CH4 production potentials were evaluated. Results showed that compared to unreconstruction reservoirs, the CH4 production of RC-HFBS increased by 11.1 times, and the gas-to-water ratio increased by 13.3 times. The harm of permeable boundaries on reservoir depressurization leads to a short effective stimulation time of fractures (about 1000 out of 3650 days) and results in the insensitivity of exploitation performance to production parameters. However, the impermeable boundaries improve the fractures' stimulation, meanwhile, making exploitation performance extremely sensitive to production parameters. For RC-HFBS, commercial production can be realized by diverse production parameter combinations, including SF, CF, and Pp are 15 m, 10D•cm, 4 MPa; 15 m, 10D•cm, 2 MPa; 25 m, 10D•cm, 2 MPa; 5 m, 40D•cm, 4.5 MPa.

Analysis of Ultimate Gas Recovery in Shale Reservoirs

Abstract Horizontal wells with multistage fracture treatments enabled economic gas production from shale gas reservoirs. Recovery from a typical shale reservoir is usually quite low as numerous factors can affect the ultimate recovery. However, recovery factors inside and outside the stimulated reservoir volume (SRV), especially the variations spatially and temporally, are not yet fully understood as the numerical simulation of shale gas production is still challenging. In this study, a dual-porosity, dual-permeability model was built to investigate ultimate gas recovery and its spatial variations throughout the production period. Parametric studies were conducted to evaluate the effect of matrix permeability, fracture conductivity, fracture half length, and operating conditions on recovery factors. Systematic and comprehensive numerical experiments were carried out to generate a probability distribution of ultimate recovery factors. The results presented in this article provide insight into the impact that key parameters have on these recovery factors in and outside the SRV and the range of recovery factors one can expect from shale gas reservoirs. Fracture conductivity has the most impact on recovery in the SRV while matrix permeability can affect the recovery outside the SRV significantly. The expected recovery in the SRV is 24% in shale reservoirs. The methodology in this study provides a foundation to develop more reliable models in accurately forecasting ultimate gas recoveries spatially for shale gas reservoirs. The new understanding can be applied to optimize field development, well spacing, and infill drilling to increase economic recovery.

An Analytic Element Model for Seepage Forces in Fractured Media

There are many situations where groundwater flow has high flow rates, causing large seepage forces. Examples are flows around highly conductive fractures and tunnels. We present a new analytic element for a tunnel in an elastic medium. We combined the analytic element method for groundwater flow with that for linear elasticity, and include the seepage force as a body force in the linearly elastic model. We represent tunnels and fractures as analytic elements. The solution for the case considered is limited to steady state flow and fluid-to-solid coupling. We present examples of the computed seepage forces around a tunnel and a fracture as well as a comparison with another numerical model.

Response characteristics and novel understandings of dual induction logging of horizontal wells in fractured reservoirs

Previous studies commonly used dual laterolog or induction logging in vertical wells to study fractured reservoirs. However, there are few studies about the response characteristics of dual induction logging of horizontal wells in fractured reservoirs, which interferes with the evaluation of horizontal wells in fractured reservoirs. In this study, firstly, the finite element method is used to establish the fractured reservoir model and the dual induction instrument of horizontal well. Then, the response characteristics of dual induction logging in fractured reservoirs with different fracture conductivity, fracture dip angle, fracture width and fracture length are simulated and analyzed. The results show the response characteristics as follows: (1) The apparent conductivity of dual induction logging increases first and then decreases along with the increase of fracture conductivity, when the fracture conductivity is lower than formation conductivity, the apparent conductivity is similar to formation conductivity; (2) The fracture dip angle has little effect on the apparent conductivity of induction logging, when the fracture conductivity is high, the apparent conductivity decreases with the increase of the fracture dip angle; (3) The effect of fracture width and fracture length on apparent conductivity is similar. The larger the fracture width or length, the greater their influence on the apparent conductivity, which is different from the response characteristics of laterologs. In applications, these characteristics can be demonstrated by two wells in the southwest Ordos Basin, China. Finally, advantages and disadvantages of the simulation method, applications, logging responses discussed in detail, as well as the response characteristics and the shielding effect of fractures on electromagnetic waves of dual induction instrument are discussed in detail. The applications and discussions show that this study can provide response characteristics and novel understandings for the evaluations of horizontal wells in fractured reservoirs, especially in areas where dual induction logging is widely used.

Numerical Simulation of Proppant Transport in Transverse Fractures of Horizontal Wells

Proppant transport and distribution law in hydraulic fractures has important theoretical and field guidance significance for the optimization design of hydraulic fracturing schemes and accurate production prediction. Many studies aim to understand proppant transportation in complex fracture systems. Few studies, however, have addressed the flow path mechanism between the transverse fracture and horizontal well, which is often neglected in practical design. In this paper, a series of mathematical equations, including the rock elastic deformation equation, fracturing fluid continuity equation, fracturing fluid flow equation, and proppant continuity equation for the proppant transport, were established for the transverse fracture of a horizontal well, while the finite element method was used for the solution. Moreover, the two-dimensional radial flow was considered in the proppant transport modeling. The results show that proppant breakage, embedding, and particle migration are harmful to fracture conductivity. The proppant concentration and fracture wall roughness effect can slow down the proppant settling rate, but at the same time, it can also block the horizontal transportation of the proppant and shorten the effective proppant seam length. Increasing the fracturing fluid viscosity and construction displacement, reducing the proppant density and particle size, and adopting appropriate sanding procedures can all lead to better proppant placement and, thus, better fracturing and remodeling results. This paper can serve as a reference for the future study of proppant design for horizontal wells.

Experimental and Modeling Investigation on Artificial Fracture Conductivity for Hybrid Fracturing in a Deep Carbonate Reservoir Using an Acid and a Proppant

Experimental and Modeling Investigation on Artificial Fracture Conductivity for Hybrid Fracturing in a Deep Carbonate Reservoir Using an Acid and a Proppant