Proppant Transport? Viscosity Is Not All It's Cracked Up To Be

2015 ◽  
Author(s):  
A.M.. M. Gomaa ◽  
D.V.S.. V.S. Gupta ◽  
P.. Carman
Keyword(s):  
Shear Stress ◽  
Hydraulic Fracturing ◽  
Main Tool ◽  
Solid Material ◽  
Viscosity Reduction ◽  
Fluid Viscosity ◽  
Fracture Conductivity ◽  
Proppant Transport ◽  
Two Fluids ◽  
Fluid Elasticity

Abstract Post-treatment production analyses for hydraulic fracturing treatments with conventional crosslinked gel often indicate that the treatments do not achieve the designed stimulation effectiveness, which could be attributed to non-optimal proppant placement and/or significantly damaged fracture conductivity. Although conventional crosslinked fluids are observed to provide good proppant suspension in laboratory environments, they might not provide the desired proppant transport under downhole conditions. Crosslinked fluids are known to be difficult to clean up, and thus are notorious for imparting gel damage to proppant pack and formation. Surfactant gels have been developed to mitigate some of the issues. Viscosity measurements are used as the main tool to judge and optimize the performance of both polymer and surfactant based fracture fluids, especially their ability to transport proppant. While efficient proppant transport is essential for successful hydraulic fracturing, recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. The objective of the paper is to investigate and determine the minimum rheological properties required for efficient proppant transport. Thus, combinations of rotational and oscillatory measurements were conducted to better predict the proppant transport characteristics. Also, proppant settling tests were conducted at static and dynamic conditions. A strong correlation was established between fluid's elasticity and its ability to suspend the proppant with a required minimum elastic modulus (G') value to be greater than viscous modulus (G”). Experimental results show that for two fluids that both have a close viscosity value (similar power law parameters); one fluid with G'>G” while the other one G'< G”, the fluid that has G'>G” behaves as semi-solid material where it deforms instead of flowing when shear stress is applied, while the fluid that has G”>G', flows when shear stress is applied and time to flow depends on viscosity. A proppant particle in a fluid undergoes shear stress due to its density. Therefore, for the fluid G”>G', proppant settles as the fluid moves around it and the speed of settling depends on fluid viscosity, whereas for the elastic fluid (G'>G”), fluid elasticity does not allow the proppant to settle. This observation was confirmed for both polymer and surfactant based fracturing fluids. Additives can be divided into categories that may enhance or reduce fluid elasticity based on their effect on the internal structure of the fluids. For example, breakers tend to significantly reduce the fluid elasticity, even when viscosity reduction is minimized. Data obtained from this study can be used as a guideline to optimize and select the fluid that has ability to carry proppant for field treatment design.

Fracture Conductivity Comparison of Ceramic Proppants

1985 ◽  
Vol 25 (02) ◽  
pp. 157-170 ◽  
Author(s):  
R.A. Cutler ◽  
D.O. Enniss ◽  
A.H. Jones ◽  
S.R. Swanson
Keyword(s):  
Specific Gravity ◽  
Hydraulic Fracturing ◽  
Settling Velocity ◽  
Fracturing Fluid ◽  
High Quality ◽  
Pumping Rate ◽  
Fracture Conductivity ◽  
Proppant Transport ◽  
Closure Stress ◽  
Economic Analyses

Abstract Lightweight, intermediate-strength proppants have been developed that are intermediate in cost between sand and bauxite. A wide variety of proppant materials is characterized and compared in a laboratory fracture conductivity study. Consistent sample preparation, test, and data reduction procedures were practiced, which allow a relative comparison of the conductivity of various proppants at intermediate and high stresses. Specific gravity, proppants at intermediate and high stresses. Specific gravity, corrosion resistance, and crush resistance of each proppant also were determined. proppant also were determined. Fracture conductivity was measured to a laminar flow of deaerated, deionized water over a closure stress range of 6.9 to 96.5 MPa [1,000 to 14,000 psi] in 6.9-MPa [1,000-psi] increments. Testing was performed at a constant 50 degrees C [122 degrees F] temperature. Results of the testing are compared with values from the literature and analyzed to determine proppant acceptability in the intermediate and high closure stress regions. Fracture strengths for porous and solid proppants agree well with calculated values. Several oxide ceramics were found to have acceptable conductivity at closure stresses to 96.5 MPa [14,000 psi]. Resin-coated proppants have lower conductivities than uncoated, intermediate-strength oxide proppants when similar size distributions are tested. Recommendations are made for obtaining valid conductivity data for use in proppant selection and economic analyses. proppant selection and economic analyses. Introduction Massive hydraulic fracturing (MHF) is used to increase the productivity of gas wells in low-permeability reservoirs by creating deeply penetrating fractures in the producing formation surrounding the well. Traditionally, producing formation surrounding the well. Traditionally, high-purity silica sand has been pumped into the created fracture to prop it open and maintain gas permeability after completing the stimulation. The relatively low cost, abundance, sphericity, and low specific gravity of high-quality sands (e.g., Jordan, St. Peters, and Brady formation silica sands) have made sand a good proppant for most hydraulic fracturing treatments. The closure stress on the proppants increases with depth, and even for selected high-quality sands the fracture conductivity has been found to deteriorate rapidly when closure stresses exceed approximately 48 MPa [7,000 psi]. Several higher-strength proppants have been developed to withstand the increased closure stress of deeper wells. Sintered bauxite, fused zirconia, and resin-coated sands have been the most successful higher-strength proppants introduced. These proppants have improved proppants introduced. These proppants have improved crush resistance and have been used successfully in MHF treatments. The higher cost of these materials as compared to sand has been the largest single factor inhibiting their widespread use. The higher specific gravity of bauxite and zirconia proppants not only increases the volume cost differential compared to sand but also enhances proppant settling. Lower-specific-gravity proppants not only are more cost effective but also have the potential to improve proppant transport. Novotny showed the effect of proppant diameter on settling velocity in non-Newtonian fluids and concluded that proppant settling may determine the success or failure of a hydraulic fracturing treatment. By using the same proppant settling equation as Novotny, the settling velocity of 20/40 mesh proppants is calculated for four different specific gravities and shown as a function of fluid shear rate in Fig. 1. The specific gravity of bauxite is 3.65 and sand is 2.65; therefore, bauxite is 37.7 % more dense than sand. The settling velocity for bauxite, as shown in Fig. 1, however, is approximately 65 % higher than sand. Work on proppants with specific gravities lower than bauxite was initiated to improve the transport characteristics of the proppant during placement. It has been demonstrated that vertical propagation of the fracture can be limited by reducing the fracturing fluid pressure. The viscosity range of existing fracturing pressure. The viscosity range of existing fracturing fluids makes minimizing fluid viscosity a much more effective method of controlling pressure than lowering the pumping rate. A potential advantage of decreasing the pumping rate. A potential advantage of decreasing the specific gravity of the proppant is that identical proppant transport to that currently achievable can take place in lower-viscosity fluids. (Alternatively, higher volumes of proppant can be pumped in a given amount of a proppant can be pumped in a given amount of a high-viscosity fracturing fluid.) Not only are low-viscosity fluids capable of allowing better fracture control, they are also less expensive. More importantly, it recently was shown that the conductivity of a created hydraulic fracture in the Wamsutter area is about one-tenth of that predicted by laboratory conductivity tests. P. 157

scholarly journals A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study

2020 ◽  
Vol 10 (9) ◽  
pp. 3027
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Zhili Li ◽  
Fenglan Huang ◽  
Chuhao Huang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Variable Viscosity ◽  
Oil Reservoirs ◽  
Fluid Viscosity ◽  
Low Density ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Fracturing Fluids ◽  
Transport Experiment

For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil reservoirs.

scholarly journals Multi-Size Proppant Pumping Schedule of Hydraulic Fracturing: Application to a MP-PIC Model of Unconventional Reservoir for Enhanced Gas Production

Processes ◽  
2020 ◽  
Vol 8 (5) ◽  
pp. 570 ◽  
Author(s):  
Prashanth Siddhamshetty ◽  
Shaowen Mao ◽  
Kan Wu ◽  
Joseph Sang-Il Kwon
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Computational Cost ◽  
Three Dimensional ◽  
Sensitivity Study ◽  
Gas Production ◽  
Field Scale ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Proppant Transport

Slickwater hydraulic fracturing is becoming a prevalent approach to economically recovering shale hydrocarbon. It is very important to understand the proppant’s transport behavior during slickwater hydraulic fracturing treatment for effective creation of a desired propped fracture geometry. The currently available models are either oversimplified or have been performed at limited length scales to avoid high computational requirements. Another limitation is that the currently available hydraulic fracturing simulators are developed using only single-sized proppant particles. Motivated by this, in this work, a computationally efficient, three-dimensional, multiphase particle-in-cell (MP-PIC) model was employed to simulate the multi-size proppant transport in a field-scale geometry using the Eulerian–Lagrangian framework. Instead of tracking each particle, groups of particles (called parcels) are tracked, which allows one to simulate the proppant transport in field-scale geometries at an affordable computational cost. Then, we found from our sensitivity study that pumping schedules significantly affect propped fracture surface area and average fracture conductivity, thereby influencing shale gas production. Motivated by these results, we propose an optimization framework using the MP-PIC model to design the multi-size proppant pumping schedule that maximizes shale gas production from unconventional reservoirs for given fracturing resources.

The Effects of Fluid Viscosity and Density on Proppant Transport in Complex Slot Systems

2021 ◽  
Author(s):  
Ashtiwi Bahri ◽  
Jennifer Miskimins
Keyword(s):  
Sodium Chloride ◽  
Chloride Solution ◽  
Sodium Chloride Solution ◽  
Positive Impact ◽  
Fluid Viscosity ◽  
Fluid Density ◽  
Fracture Conductivity ◽  
Proppant Transport ◽  
Glycerin Solution ◽  
Injection Rates

Abstract The main functions of hydraulic fracturing fluids are to create a fracture network and to carry and place the proppant into the created fractures networks, thus, adding to fracture conductivity. Significant research has been performed to develop ideal fracturing fluid systems. The development focus has mainly been on optimization of a fluid rheology that can transport and place the proppant into the primary and any subsidiary fractures with less damage to the formation and at a lower cost. The main goal of this work is to add to the understanding and optimization of proppant transport in complex hydraulic fracture networks. Specifically for this study, focus is placed on two different fluids, water-glycerin solution and water-sodium chloride solution, representing varying fluid densities and viscosities. The effects of changing fluid viscosities, densities, proppant densities, proppant sizes, proppant concentrations, and slurry injection rates on proppant transport were then experimentally investigated. This experimental work shows that viscosity has a greater impact on the proppant transport than fluid density does, thus implying a larger impact on the resulting fracture conductivity. The results of this work show that a water-glycerin solution, with a viscosity of 4.3 cp, has significant proppant carrying capacity with proppants delivered uniformly to greater distances. On the other hand, the results show that a water-sodium chloride solution of 9.24 ppg density has less capability to carry the proppant deep into the fractures indicating that viscosity has a greater impact on the proppant transport than fluid density does. The lab results also showed that increasing proppant concentrations and injection rates has a positive impact on proppant transport.

Propagation, proppant transport and the evolution of transport properties of hydraulic fractures

2018 ◽  
Vol 855 ◽  
pp. 503-534 ◽  
Author(s):  
Jiehao Wang ◽  
Derek Elsworth ◽  
Martin K. Denison
Keyword(s):  
Preferential Flow ◽  
Fluid Pressure ◽  
Fracture Propagation ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Fluid Viscosity ◽  
Fracture Conductivity ◽  
Proppant Transport ◽  
Fracture Closure ◽  
Proppant Embedment

Hydraulic fracturing is a widely used method for well stimulation to enhance hydrocarbon recovery. Permeability, or fluid conductivity, of the hydraulic fracture is a key parameter to determine the fluid production rate, and is principally conditioned by fracture geometry and the distribution of the encased proppant. A numerical model is developed to describe proppant transport within a propagating blade-shaped fracture towards defining the fracture conductivity and reservoir production after fracture closure. Fracture propagation is formulated based on the PKN-formalism coupled with advective transport of an equivalent slurry representing a proppant-laden fluid. Empirical constitutive relations are incorporated to define rheology of the slurry, proppant transport with bulk slurry flow, proppant gravitational settling, and finally the transition from Poiseuille (fracture) flow to Darcy (proppant pack) flow. At the maximum extent of the fluid-driven fracture, as driving pressure is released, a fracture closure model is employed to follow the evolution of fracture conductivity with the decreasing fluid pressure. This model is capable of accommodating the mechanical response of the proppant pack, fracture closure of potentially contacting rough surfaces, proppant embedment into fracture walls, and most importantly flexural displacement of the unsupported spans of the fracture. Results show that reduced fluid viscosity increases the length of the resulting fracture, while rapid leak-off decreases it, with both characteristics minimizing fracture width over converse conditions. Proppant density and size do not significantly influence fracture propagation. Proppant settling ensues throughout fracture advance, and is accelerated by a lower viscosity fluid or greater proppant density or size, resulting in accumulation of a proppant bed at the fracture base. ‘Screen-out’ of proppant at the fracture tip can occur where the fracture aperture is only several times the diameter of the individual proppant particles. After fracture closure, proppant packs comprising larger particles exhibit higher conductivity. More importantly, high-conductivity flow channels are necessarily formed around proppant banks due to the flexural displacement of the fracture walls, which offer preferential flow pathways and significantly influence the distribution of fluid transport. Higher compacting stresses are observed around the edge of proppant banks, resulting in greater depths of proppant embedment into the fracture walls and/or an increased potential for proppant crushing.

Numerical Simulation Study of Proppant Transport in Cross Fractures

2022 ◽  
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Jianchun Guo
Keyword(s):  
Hydraulic Fracturing ◽  
Transport Model ◽  
Injection Rate ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Natural Fractures ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Approach Angle

Abstract Hydraulic fracturing technology is an important means to stimulate unconventional reservoirs, and the placement morphology of proppant in cross fractures is a key factor affecting the effect of hydraulic fracturing. It is very important to study the proppant transport law in cross fractures. In order to study the proppant transportation law in cross fractures, based on the CFD-DEM method, a proppant transport model in cross fractures was established. From the two aspects of the flow field in the fractures and the morphology of the proppant dune, the influence of the natural fracture approach angle, the fracturing fluid viscosity and injection rate on the proppant transport is studied. Based on the principle of hydropower similarity, the conductivity of proppant dune under different conditions is quantitatively studied. The results show that the natural fracture approach angle affects the distribution of proppant and fracturing fluid in natural fractures, and further affects the proppant placement morphology in hydraulic fractures and natural fractures. When the fracturing fluid viscosity is low and the displacement is small, the proppant forms a "high and narrow" dune at the entrance of the fracture. With the increase of the fracturing fluid viscosity and injection rate, the proppant settles to form a "short and wide" placement morphology. Compared with the natural fracture approach angle, the fracturing fluid viscosity and injection rate have a more significant impact on the conductivity of proppant dune. This paper investigated the proppant transportation in cross fractures, and quantitatively analyzes the conductivity of proppant dunes with different placement morphology. The results of this study can provide theoretical guidance for the design of hydraulic fracturing.

scholarly journals Quantitative Study on Bed Load Proppant Transport during Slickwater Hydraulic Fracturing

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Chunting Liu ◽  
Mingzhong Li ◽  
Guodong Zhang ◽  
Yong Zhang
Keyword(s):  
Friction Coefficient ◽  
Hydraulic Fracturing ◽  
Mass Flux ◽  
Static Friction ◽  
Rolling Friction ◽  
Bed Load ◽  
Fluid Viscosity ◽  
Proppant Transport ◽  
Sand Bank ◽  
Equilibrium Height

Abstract Bed load proppant transport is a significant phenomenon during slickwater hydraulic fracturing. However, the mechanism of bed load proppant transport is still unclear. In the present study, the proppant transport process during slickwater hydraulic fracturing was simulated with a coupled computational fluid dynamics- (CFD-) discrete element method (DEM) model, and the mechanism of the bed load proppant transport was analyzed. A model for calculating the mass flux of the bed load layer was proposed and verified with experimental results from the literature. The results show that bed load migration is an essential mechanism of proppant transport. When the shear force of fluid acting on the surface of the sand bank reaches the critical Shields number, the proppant in the upper layer of the sand bank begins to migrate in the form of bed load. The movement of the bed load layer increases the time for the sand bank to reach the equilibrium height. In addition, the mass flux of the bed load layer significantly affects the equilibrium height of the sand bank. The mass flux of the bed load layer decreases, and the equilibrium height increases as the proppant density, proppant diameter, or rolling friction coefficient and static friction coefficient of the proppant increase, but the mass flux of the bed load layer increases, and the equilibrium height decreases as the fluid viscosity increases.

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

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1783
Author(s):  
Klaudia Wilk-Zajdel ◽  
Piotr Kasza ◽  
Mateusz Masłowski
Keyword(s):  
Hydraulic Fracturing ◽  
Guar Gum ◽  
Polymer Concentration ◽  
Laboratory Research ◽  
Damage Effect ◽  
Tight Gas ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Fracturing Fluids ◽  
Sandstone Rock

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.

Simulation of proppant transport and fracture plugging in the framework of a radial hydraulic fracturing model

2020 ◽  
Vol 35 (6) ◽  
pp. 325-339
Author(s):  
Vasily N. Lapin ◽  
Denis V. Esipov
Keyword(s):  
Numerical Model ◽  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Injection Rate ◽  
Fluid Injection ◽  
Subtraction Technique ◽  
Gas Industry ◽  
Proppant Transport ◽  
Hydraulic Fracture Propagation

AbstractHydraulic fracturing technology is widely used in the oil and gas industry. A part of the technology consists in injecting a mixture of proppant and fluid into the fracture. Proppant significantly increases the viscosity of the injected mixture and can cause plugging of the fracture. In this paper we propose a numerical model of hydraulic fracture propagation within the framework of the radial geometry taking into account the proppant transport and possible plugging. The finite difference method and the singularity subtraction technique near the fracture tip are used in the numerical model. Based on the simulation results it was found that depending on the parameters of the rock, fluid, and fluid injection rate, the plugging can be caused by two reasons. A parameter was introduced to separate these two cases. If this parameter is large enough, then the plugging occurs due to reaching the maximum possible concentration of proppant far from the fracture tip. If its value is small, then the plugging is caused by the proppant reaching a narrow part of the fracture near its tip. The numerical experiments give an estimate of the radius of the filled with proppant part of the fracture for various injection rates and leakages into the rock.

scholarly journals Performance Evaluation of Enzyme Breaker for Fracturing Applications under Simulated Reservoir Conditions

Molecules ◽  
2021 ◽  
Vol 26 (11) ◽  
pp. 3133
Author(s):  
Yuling Meng ◽  
Fei Zhao ◽  
Xianwei Jin ◽  
Yun Feng ◽  
Gangzheng Sun ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Shear Resistance ◽  
Ammonium Persulfate ◽  
Fracturing Fluid ◽  
Medium Temperature ◽  
Fracture Conductivity ◽  
Wide Range ◽  
Reservoir Conditions ◽  
Alkaline Conditions ◽  
Resistance Performance

Fracturing fluids are being increasingly used for viscosity development and proppant transport during hydraulic fracturing operations. Furthermore, the breaker is an important additive in fracturing fluid to extensively degrade the polymer mass after fracturing operations, thereby maximizing fracture conductivity and minimizing residual damaging materials. In this study, the efficacy of different enzyme breakers was examined in alkaline and medium-temperature reservoirs. The parameters considered were the effect of the breaker on shear resistance performance and sand-suspending performance of the fracturing fluid, its damage to the reservoir after gel breaking, and its gel-breaking efficiency. The experimental results verified that mannanase II is an enzyme breaker with excellent gel-breaking performance at medium temperatures and alkaline conditions. In addition, mannanase II did not adversely affect the shear resistance performance and sand-suspending performance of the fracturing fluid during hydraulic fracturing. For the same gel-breaking result, the concentration of mannanase II used was only one fifth of other enzyme breakers (e.g., mannanase I, galactosidase, and amylase). Moreover, the amount of residue and the particle size of the residues generated were also significantly lower than those of the ammonium persulfate breaker. Finally, we also examined the viscosity-reducing capability of mannanase II under a wide range of temperatures (104–158 °F) and pH values (7–8.5) to recommend its best-use concentrations under different fracturing conditions. The mannanase has potential for applications in low-permeability oilfield development and to maximize long-term productivity from unconventional oilwells.

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