Slickwater Fracturing Fluid Research Articles

Nano-SiO2 enhanced slickwater fracturing fluid for improved imbibition recovery in tight gas reservoirs: Performance and mechanism

Inspired by the exceptional performance of nanomaterials in oilfield development, yet it is rarely applied in tight gas reservoir. In this study, focusing on the tight gas reservoir of the Liuyangbao, Ordos Basin, a slickwater fracturing fluid was synthesized by incorporating nano-SiO2 and surfactant to enhance its stability and activity, aiming to optimize the utilization efficiency of slickwater. The prepared SiO2-enhanced slickwater fracturing fluid exhibited excellent interfacial regulation properties involving surface tension reduction (71.65–28.31 mN/m) and wettability alteration (69.3–21.5º). In addition, SEM images indicated that the self-assembled nano-SiO2 adsorbed on the core surface, sequentially forming a large number of micro/nano structures in “spot adsorption”, “sheet adsorption”, “lobe adsorption” and “cluster adsorption” shapes, altering the original pore structure. Meanwhile, LP-N2GA results showed an upward shift in the hysteresis loop of isotherms after nano-SiO2 was adsorbed on the core samples, with a considerable increase in specific surface area (SSA) and transitional pores. Moreover, the system showed an outstanding capacity for imbibition gas production, and finally recovered 78.2 % (∼21.4 % higher than slickwater system). The underlying mechanism responsible for the system enhanced gas recovery were attributed to capillary pressure, structural disjoining pressure and Jamin effect. This work provides feasibility of the application of nano-SiO2 in the development of tight gas reservoirs.

Experimental Study on the Efficiency of Fracturing Integrated with Flooding by Slickwater in Tight Sandstone Reservoirs

Tight reservoirs, with their nanoscale pore structures and limited permeability, present significant challenges for oil recovery. Composite fracturing fluids that combine both fracturing and oil recovery capabilities show great potential to address these challenges. This study investigates the performance of a slickwater-based fracturing fluid, combined with a high-efficiency biological oil displacement agent (HE-BIO), which offers both production enhancement and environmental compatibility. Key experiments included tests on single-phase flow, core damage assessments, interfacial tension measurements, and oil recovery evaluations. The results showed that (1) the slickwater fracturing fluid effectively penetrates the rock matrix, enhancing oil recovery while minimizing environmental impact; (2) it causes substantially less damage to the reservoir compared to traditional guar gum fracturing fluid, especially in cores with little higher initial permeability; and that (3) oil recovery improves as HE-BIO concentration increases from 0.5% to 2.5%, with 2.0% as the optimal concentration for maximizing recovery rates. These findings provide a foundation for optimizing fracturing oil displacement fluids in tight sandstone reservoirs, highlighting the potential of the integrated fracturing fluid to enhance sustainable oil recovery.

Realizing the Rapid Release of Drag Reducers via pH-Induced Oil Phase Transition of Inverse Emulsion.

As a key component of slickwater fracturing fluids, emulsion drag reducers play a vital role. The dissolving capacity of traditional emulsion drag reducers is improved by adding hydrophilic surfactants, which leads to poor stability of the emulsion drag reducer. In order to eliminate the contradiction between stability and release of the emulsion drag reducer, here, pH-responsive polymer emulsion was fabricated using the switching solvent (HA) and white oil as the continuous phase. Monomer emulsions exhibit obvious pH-responsive behavior. This is because the deprotonation of HA by pH stimulation leads to a change in the oil-water ratio of the emulsion, thereby facilitating the demulsification of emulsion. The remarkable stability of the monomer emulsion benefits the preparation of inverse emulsion polymers (P(AM-AA-AMPS)). The obtained P(AM-AA-AMPS) polymer emulsion features remarkable stability even after 15 days of storage. Importantly, the P(AM-AA-AMPS) polymer was released from the emulsion efficiently by pH stimulation instead of introducing an extra hydrophilic surfactant, which confirmed the improvement of polymer release by pH stimulation. The viscosity of the P(AM-AA-AMPS) polymer aqueous solution reaches a maximum value of 96 mPa s within 80 s at a pH value of 9.2. The release efficiency of P(AA-AM-AMPS) polymer emulsion is increased by 33% in comparison with that of traditional polymer emulsion (2 min). The P(AM-AA-AMPS) emulsion demonstrated remarkable drag-reduction performance by achieving a drag-reduction rate of 73% at a concentration of 0.05 wt %. P(AM-AA-AMPS) polymer emulsion with pH responsiveness eliminates the contradiction between the stability and release of emulsion drag reducers. Research based on pH-responsive P(AM-AA-AMPS) polymer emulsion provides other ideas for the development of quickly dissolving and long-term storage drag reducers, which is helpful for the development of low-permeability oil and gas resources.

Investigations of thermochemical fluids as cleanup system for polymer-based fracturing fluids

The cleanup of fracturing fluids, involving polymer degradation and well flowback, is crucial for the success of the fracturing operations and revenue generation. Breakers, such as oxidizers and enzymes, are commonly employed to break down polymers, resulting in lower viscosity, improved flowback, and facilitated well cleanup. However, these conventional breakers, which contribute solely to the cleanup process through polymer degradation, have some drawbacks, such as premature breaking and insufficient release of breakers. In this study, thermochemical fluids (TCFs) are proposed as a cleanup system. This system can improve the cleanup process by lowering viscosity through temperature increase and thermal degradation of polymers, reducing hydrostatic pressure via gas generation, and eliminating phase trapping damage in tight reservoirs through the heat produced. The TCFs investigated in this study were NH4Cl and NaNO2 solutions, where a substantial amount of heat was determined from the thermal energy study using an autoclave reactor. In this study, the thermal degradation of guar gum (GG) polymer derivatives, hydroxypropyl guar gum (HPG), and carboxymethyl hydroxypropyl guar gum (CMHPG) were assessed using Fourier Transform Infrared Spectroscopy (FTIR), Thermal Gravimetric Analysis (TGA), viscosity measurements, and coreflood experiments. Both FTIR and TGA analyses of linear gels of GG and its derivatives confirmed alterations in the chemical and thermal properties of these polymers following thermal treatments. The coreflood results showed a regained permeability of 87% for thermally treated HPG borate-crosslinked, 96% for CMHPG dual crosslinked (borate and zirconate), and 90% for slickwater fracturing fluids, respectively. The regained permeability of thermally treated slickwater was even better than that for slickwater with ammonium persulfate breaker.

A novel water‐in‐water emulsion drag reducer with instant solubility and viscosity enhancement for slickwater fracturing fluid

AbstractDrag reducers are indispensable components of slickwater fracturing fluids and play a pivotal role in the reconstitution of unconventional oil and gas reservoirs. Water‐in‐water emulsion (W/W) drag reducers have garnered significant attention owing to their rapid dissolution and environmentally benign properties. The solubility and viscosity enhancing ability of W/W drag reducers were further enhanced by synthesizing a novel W/W drag reducer through dispersion polymerization, thereby meeting the requirements of real‐time mixed fracturing construction technology. The solubility, viscosity enhancement, and synthesis state of the synthetic drag reducer were employed as evaluation criteria, whereby the synthetic systems underwent screening and optimization of the synthesis conditions. The final synthetic conditions were determined as follows: the monomer (AM and DMC) had a total mass concentration of 25 wt%, with an AM to DMC molar ratio of 95:5. The dispersion medium (sodium sulfate and sodium chloride) had a total mass concentration of 12 wt%, with a sodium sulfate to sodium chloride mass ratio of 1:2. The dispersion stabilizer PVP K60 had a mass concentration of 7 wt%. The initiator had a total mass concentration of 0.05 wt%, with an ammonium persulfate to sodium bisulfite mass ratio of 1:1. The reaction was conducted at 35°C and a stirring speed of 500 r min−1 for a duration of 8 h. The successful synthesis of the polymer was demonstrated using Fourier transform infrared spectroscopy. Environmental scanning electron microscopy and atomic force microscopy have characterized that the drag reducer has good viscosity enhancement potential. The performance evaluation results show that the solid content of drag reducer was 32.68%, and the residue content was 11.70 mg L−1. The viscosity enhancement rate of 1.3 wt% drag reducer was 93.7%. The dissolution time of 0.1 wt% drag reducer was only 25 s. The drag‐reduction rate of drag reducer reached 73.52%. Experimental results have proved that the drag reducer has the advantages of instant solubility, appreciable viscosity enhancement and drag‐reduction efficiency, fully meeting the real‐time mixing fracturing construction conditions, improving construction efficiency, and reducing construction costs. We expect that this study can broaden the application of W/W drag reducers in unconventional reservoir and provide a theoretical basis for field applications.

Investigation of Grewia mollis Gum as Biopolymer Drag Reducing Agent

The hydraulic fracturing treatment relies heavy on fracturing fluid. Finding inexpensive polymer that lowers the pressure gradient in turbulent flow systems during hydraulic fracturing is crucial for the development of shale gas. Most researches focused on investigating the effects of polymers such as partially hydrolysed polyacrylamide, polyethylene oxide, guar gum, xanthan gum and synergies of mixtures as friction reducing polymers. The use of Grewia Mollis mucilage as the natural polymer as a potential friction reducer in slickwater fracturing treatment was the main focus of this study. The sample of Grewia gum was obtained and the mucilage was extracted from the inner stem bark by maceration in water at ambient temperature. The mucilage was the oven-dried at a temperature of 50 oC. Atomic Absorption spectrophotometer (AAS) and Fourier Transform Infrared (FT-IR) were employed to identify the elemental composition and the functional groups of the plant. The FT-IR spectrum exhibited typical peaks and bands characteristics of polysaccharide, while the ASS result shows the presence of minute quantity (0.219 mg/100 g) of lead (Pb) in the plant may show contamination (toxicity). The rheological measurements of the mucilage plotted on the shear viscosity graph exhibit shear-thinning or pseudo-plastic behaviour. Formulated slickwater fracturing fluid at various concentrations ranging from 200 to 500 ppm, were run in a constructed closed flow loop of 0.01905 m diameter of galvanised steel pipe, test section length of 2 m and entrance length of 2 m. Drag reduction was measured at flow rates (2.3, 2.8, 3.2, 3.6 and 4.0) m3/hour at different concentrations (200 to 500) ppm. Percentage friction reduction of 37% was achieved at Reynolds number of 74269 by addition of 200 ppm of the fluid while 56% was achieved at Reynolds number 74269 by addition of 500 ppm. This indicates that Grewia mollis mucilage exhibit drag reducing potential and can be applied in slickwater hydraulic fracturing application.

A Review of Weak Gel Fracturing Fluids for Deep Shale Gas Reservoirs.

Low-viscosity slickwater fracturing fluids are a crucial technology for the commercial development of shallow shale gas. However, in deep shale gas formations with high pressure, a higher sand concentration is required to support fractures. Linear gel fracturing fluids and crosslinked gel fracturing fluids have a strong sand-carrying capacity, but the drag reduction effect is poor, and it needs to be pre-prepared to decrease the fracturing cost. Slick water fracturing fluids have a strong drag reduction effect and low cost, but their sand-carrying capacity is poor and the fracturing fluid sand ratio is low. The research and development of viscous slick water fracturing fluids solves this problem. It can be switched on-line between a low-viscosity slick water fracturing fluid and high-viscosity weak gel fracturing fluid, which significantly reduces the cost of single-well fracturing. A polyacrylamide drag reducer is the core additive of slick water fracturing fluids. By adjusting its concentration, the control of the on-line viscosity of fracturing fluid can be realized, that is, 'low viscosity for drag reduction, high viscosity for sand-carrying'. Therefore, this article introduces the research and application status of a linear gel fracturing fluid, crosslinked gel fracturing fluid, and slick water fracturing fluid for deep shale gas reservoirs, and focuses on the research status of a viscous slick water fracturing fluid and viscosity-controllable polyacrylamide drag reducer, with the aim of providing valuable insights for the research on water-based fracturing fluids in the stimulation of deep shale gas reservoirs.

Development of degradable fiber slickwater system and enhanced proppants-carrying mechanism

Slickwater fracturing fluid has become one of the most popular fracturing fluids due to its low frictional resistance and cleanness. However, slickwater has limited proppants-carrying ability because of its low viscosity. It often leads to proppants deposition in the near-wellbore and even sand plug. Simultaneously, it is impossible to transport the proppants to the distal end of the fractures, affecting the hydraulic fracturing effect. In this work, a degradable fiber slickwater fracturing fluid is innovatively constructed to carry proppants better. The adopted fibers have excellent degradability, no formation residues after complete degradation, and low reservoir damage. A series of rheological experiments are conducted to investigate the rheology of the fiber slickwater. Static proppants-carrying experiments and large visual dynamic proppants-carrying equipment simulate the proppants-carrying process in the reservoir to investigate its proppants-carrying performance. The fiber slickwater has the stronger structure than pure slickwater, the zero-shear viscosity can be enhanced by 20–1000 times, and the viscoelasticity is significantly improved. The dynamic proppants-carrying results show that the amount of proppants residue in the near-wellbore is reduced dramatically, and the proppants are laid more uniformly. About 11.8% of the proppants are delivered to the distal end. Finally, scanning electron microscope and electron microscope characterizations are used to reveal the proppants-carrying mechanism. This endeavor will develop a novel proppants-carrying concept for slickwater fracturing fluid.

A Novel Slickwater System with Strong-Polarity Fibers for High-Efficiency Proppant Flowback Mitigation

To avoid or mitigate proppant flowback after a massive hydraulic fracturing of tight formations and to reduce its impairment to well productivity, this study developed a new type of fiber material with strong polarity based on polyester fiber. This fiber material is modified by introducing a strong-polar functional monomer into the molecular structure and adopting the means of surface grafting. On the basis of this fiber material, a fiber slip-water system with excellent dispersion performance can be established to prevent proppant backflow. Laboratory experiments were performed to analyze the specific function of the fibers with strong polarity and its working mechanisms. The results indicate that strong-polarity fibers have excellent dispersion performance. The fibers and resistance-reducing agents form an interwoven structure that can carry proppants, resulting in the enhancement of the sand-carrying capacity of the fracturing fluid system and the overall strength of the sand bank. In terms of the sand-carrying capacity and mitigation of proppant flowback, strong-polar fibers have significantly improved compared to unmodified fibers. In a 5 mm simulated crack, strong-polar fibers can increase the static settling time of 70/140 mesh quartz sand proppant by 26.5%. Meanwhile, the placement height of the sand embankment increased by 23.4% after the settlement of the proppant. In proppant transport experiments, strong-polar fibers with a mass fraction of 0.4% can increase the transport distance of proppants by more than 50%. Within the closed stress range of 2–10 MPa, the concentration of 0.5% strong-polar fibers increases the critical sand flow rate of the proppant by more than twice. The strong-polarity fiber system introduced in this study can be used to develop a fiber slickwater fracturing fluid system suitable for the massive hydraulic fracturing of tight reservoirs and has broad application prospects in the field of proppant flowback mitigation in tight reservoirs.

PH-switchable W/O drag reducer emulsions based on dynamic covalent stabilizers for efficient stabilization and rapid dissolution of drag reducers

As the global emphasis on shale oil extraction grows, there is a rising demand for slickwater fracturing fluids for reservoir stimulation. Polyacrylamide drag reducers plays a crucial role in slickwater and are available in two primary forms: powder and emulsion. Powder-based drag reducers suitable for long-term transportation and storage, but increasing their dissolution rate remains a challenge. While emulsion-based drag reducers are valued for the efficient dissolution facilitated by hydrophilic phase-inversion surfactants, the incorporation of the surfactants compromise the stability of W/O emulsions. In this work, an imine-functionalized pH-switchable stabilizer was synthesized, and the W/O emulsion constructed with the stabilizer underwent demulsification at a pH of 4.9. The pH-switchable emulsion system was optimized, and inverse emulsion polymerization using the stable monomer emulsion was performed for preparing pH-switchable drag reducer emulsions. The drag reducer emulsion features remarkable resistance to instability even after 30 days of storage owing to the absence of phase-inversion surfactants. The imine bond on the stabilizer was cleaved in acid solution, allowing the switchable drag reducer emulsion to be rapidly released and dissolved in water at pH 2.75, boasting an impressive dissolution rate of only 150 s. Furthermore, the pH-switchable drag reducer emulsion demonstrated effective drag-reduction performance, achieving a drag-reduction rate as 73 % at a concentration of 0.06 wt%. The pH-switchable drag reducer emulsion effectively resolves the conflict between rapid dissolution and efficient stabilization of drag reducer, thus offering potential improvements in the formulation process of slickwater and the efficiency of shale oil development.

Distribution Characteristics and Backflow Flow Pattern of a Slickwater Fracturing Fluid in Shale Based on Low-Field Nuclear Magnetic Resonance

Distribution Characteristics and Backflow Flow Pattern of a Slickwater Fracturing Fluid in Shale Based on Low-Field Nuclear Magnetic Resonance

The Effect of Slickwater on Shale Properties and Main Influencing Factors in Hydraulic Fracturing

As shale gas reservoirs have low porosity and low permeability, hydraulic fracturing is a necessary means for industrial exploitation of shale gas. In this study, aiming at the problem of reservoir damage in the process of hydraulic fracturing of shale gas reservoir, a physical simulation method of slickwater fracturing fluid flow in shale core has been established. The change laws of physical parameters of the shale were quantified after slickwater fracturing fluid filtrating into it. The main factors affecting physical parameters of shale matrix around fractures were found out in the process of fracturing, shut-in, and flowback of slickwater fracturing fluid. The results show that after treated by slickwater fracturing fluid, the wettability of shale becomes more uniform in distribution (the water contact angles from 43° to 48°). In the fracturing filtration zone, the damage rate of fracturing fluid to shale porosity is 6.4%-42.0%. Low differential pressure flowback can reduce the damage of the shale, and prolonging the time of shut-in has no obvious effect on the damage to porosity. After 0.3 d (imbibition stability time), the damage of fracturing fluid to shale permeability is basically stable (55.9%). Permeability damage is mainly caused by residue of the fracturing fluid in large pores and bound water in small pores. Analysis of weights of all fracturing parameters shows that flowback differential pressure has the largest influence weight on shale porosity (51.4%), and well shut-in time has the largest influence weight on shale permeability (62.7%). Therefore, in the production process, it is suggested to properly reduce the backflow differential pressure and moderately shorten the well shut-in time.

Vertical height growth mechanism of hydraulic fractures in laminated shale oil reservoirs based on 3D discrete lattice modeling

Bedding planes are abundant in shale oil reservoirs, but the intrinsic mechanism of fracture-height containment by these weak interfaces remains unclear. To investigate the effects of interface properties, stress conditions, and fracturing fluid viscosity on the vertical propagation of fracture heights in laminated shale oil reservoirs, a three-dimensional hydro-mechanical coupling numerical model was developed. The model is based on the 3D discrete lattice algorithm (DLA), which replaces the balls and contacts in the conventional synthetic rock mass model (SRM) with a lattice consisting of spring-connected nodes, resulting in improved computational efficiency. Additionally, the interaction between hydraulic fractures and bedding planes is automatically computed using a smooth joint model (SJM), without making any assumptions about fracture trajectories or interaction conditions. The results indicate that a higher adhesive strength of the laminated surface promotes hydraulic fracture propagation across the interface. Increasing the friction coefficient of the laminated surface from 0.15 to 0.91 resulted in a twofold increase in the fracture height. Furthermore, as the difference between vertical and horizontal principal stresses increased, the longitudinal extension distance of the fracture height significantly increased, while the activated area of the laminar surface decreased dramatically. Moreover, increasing the viscosity of the fracturing fluid led to a decrease in filtration loss along the laminar surface of the fracture and a rapid increase in net pressure, making the hydraulic fracture more likely to cross the laminar surface directly. Therefore, for heterogeneous shale oil reservoirs, a reverse-sequence fracturing technique has been proposed to enhance the length and height of the fracture. This technique involves using a high-viscosity fracturing fluid to increase the fracture height before the main construction phase, followed by a low-viscosity slickwater fracturing fluid to activate the bedding planes and promote fracture complexity. To validate the numerical modeling results, five sets of laboratory hydraulic fracturing physical simulations were conducted in Jurassic terrestrial shale. The findings revealed that as the vertical stress difference ratio increased from 0.25 to 0.6, the vertical fracture area increased by 1.98 times. Additionally, increasing both the injection displacement and the viscosity of the fracturing fluid aided in fracture height crossing of the laminar facies. These results from numerical simulation and experimental studies offer valuable insights for hydraulic fracturing design in laminated shale oil reservoirs.

The effects of various factors on spontaneous imbibition in tight oil reservoirs

Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.

Study on Optimum Selection Method of Additives for Slick-Water Fracturing Fluid

In order to clarify the research idea of fluid system optimization in slick-water fracturing, a scientific and effective single-agent optimization method was selected to study the performance optimization method and performance evaluation method of drag reducer, clay stabilizer and cleanup additive in slick-water fracturing fluid. The specific experimental steps and application examples were investigated. To select the drag reducer, the drag reduction rate rate of the drag reducer at different concentrations should be measured first, the optimal concentration of a single agent should be selected, and then the stability test of temperature, flow rate and shear time should be performed on the optimal concentration of a single agent, and finally the combination formula with high drag reduction rate rate and stable performance can be selected. To optimize the clay stabilizer, the optimal concentration of single agent should be obtained by measuring the anti-swelling rate of different single agent and different concentration, and then the anti-swelling rate of each compound formula should be determined according to the optimal concentration of single agent, and finally the anti-swelling performance of the composite combination should be evaluated according to the core flow experiment. The optimal concentration of a single agent should first be optimized according to the surface tension of the cleanup additive, and then the combined formula should be optimized according to the surface tension of the combined combination, and the cleanup additive ability should be evaluated by core spontaneous imbibition or measuring the increase rate of cleanup additive.

A new temperature-resistant and fast dissolving nano-silica/poly (AM-AMPS) composite drag reducer for slickwater fracturing

Polyacrylamide-based drag reducers are an essential component of slickwater fracturing fluids and are used to reduce friction during the fracturing process. However, the elevated temperature accelerates the mechanical and oxidative degradation of polyacrylamide, resulting in a dramatic decrease in the drag reduction capability. To improve the temperature resistance of polyacrylamide, many researchers have focused on introducing rigid groups into the side chains of polyacrylamide. However, the improvement in the temperature resistance of polyacrylamide is limited. To address this problem, a novel water-in-water nanocomposite drag reducer, called ANS-PAA, was developed. ANS-PAA was synthesized by in-situ dispersion polymerization, which involved the use of amino-functionalized nano-silica, acrylamide, and 2-acrylamido-2-methylpropane sulfonic acid. The nanoparticles were linked to the polymer through hydrogen bonding and electrostatic interactions, which dramatically improved the thermal stability of ANS-PAA molecules. The drag reducer exhibits fast dissolving and strong temperature-resistant. Its dissolution time in tap water is 19 s and its drag reduction rate at 120 °C is 70.2 %. In addition, the nanoparticles embedded in the polymer network enhanced the strength of the structure. This study provides valuable insights into the development of drag reducers in slickwater fracturing fluids that more efficiently handle the high temperatures encountered in deep oil and gas reservoirs.

Synthesis and performance evaluation of water-in-water polymer drag-reducing agent

With abundant reserves and huge exploitation potential, shale oil is the focus of exploration and development. Slickwater fracturing fluid is widely used in shale oil reservoir reconstruction because of its low viscosity and strong ability to create fractures. Drag-reducing agent is the core of slickwater fracturing fluid. There are some problems such as poor solubility, long dissolution time and serious pollution in the existing slickwater drag-reducing agents. Therefore, a novel water-in-water (W/W) polymer drag-reducing agent is synthesized by dispersion polymerization. The state, drag reduction and solubility performance of the synthetic polymer drag-reducing agent are taken as evaluation indexes. The dispersion stabilizer, dispersion medium, initiator, monomer and other synthesis additives are screened. The experimental conditions such as their dosage and synthesis temperature are also optimized. Under the optimal synthesis conditions, the W/W polymer drag-reducing agent is obtained. The product is characterized and its rheological, dissolution and drag reduction properties are evaluated. The results show that the molecular weight of the W/W polymer drag-reducing agent ranges from 1.9 million to 2.4 million. The dissolution time is 24 s, and the drag reduction rate reaches 73.08% at the flow rate of 6.38 m·s-1. It proves that the W/W polymer drag-reducing agent has instant solubility and high drag reduction efficiency. It is of great significance to realize the efficient development of shale oil reservoir.

New insights of further enhanced tight oil recovery after hydraulic fracturing by VES fracturing fluid

In the process of fracturing in tight reservoirs, viscoelastic surfactant (VES) fracturing fluid has many advantages that can significantly increase the recovery of tight oil. However, there is a risk of formation blockage due to heavy emulsification in the formation. In this study, a VES microemulsion (VES-M) system with low reservoir damage and high oil displacement efficiency is constructed using VES fracturing fluid and polyhydroxy alcohol. The average particle size in the fluid is only 3%–10% of the average pore size of the tight reservoir, and the formation damage is 16.00%. The new fluid can achieve ultra-low interfacial tension (IFT) with Winsor type III microemulsion. Compared with slickwater fracturing fluid and formation water, the new fluid can filtrate deeper into the matrix and increase the oil recovery by 7.20%–11.32% during the flowback process. This study provides a possibility for the field application of VES fracturing fluid in tight reservoirs and new insights into the effects and rules of employing the VES-M system to enhance tight oil recovery.

Development and Drag Reduction Behaviors of a Water-in-Water Emulsion Polymer Drag Reducer

As a key component of slickwater fracturing fluids, drag reducers play a critical role. Water-in-water (W/W) emulsion polymer drag reducers with the characteristics of rapid dissolution and the ability to increase viscosity are attracting substantial attention. In this work, a W/W emulsion polymer drag reducer P(AM-DMC) was synthesized via dispersion polymerization. The material P(AM-DMC) was characterized using Fourier transform infrared spectrometry, hydrogen nuclear magnetic resonance spectrometry, and environmental scanning electron microscopy. The results showed that the aqueous P(AM-DMC) solution was a pseudoplastic fluid with appreciable viscosity enhancement and shear resistance. The dissolution time of 0.1 wt % P(AM-DMC) was only 29 s. The drag-reduction rate of P(AM-DMC) reached 71.75%. The drag reducer also exhibited good temperature and salt resistance. Finally, a drag-reduction mechanism was proposed. We hope that this study can broaden the application of W/W drag reducers in shale reservoir development.

A comprehensive study on the enhancements of rheological property and application performances for high viscous drag reducer by adding diluted microemulsion

Slickwater fracturing has become the mainstream fracturing technology for unconventional reservoirs. High viscous friction reducer (HVFR) is considered as the substitute for conventional slickwater fracturing fluid to overcome the poor proppant carrying capability and reduce the fluid types to lower the treatment cost. In this study, diluted microemulsion (DME) is selected as a novel additive for HVFR. Comprehensive experiments were conducted to evaluate the performance enhancement of HVFR in terms of rheological properties, temperature stability, salinity stability, proppant carrying capacity and spontaneous imbibition. Experimental results show that DME can effectively increase the resistance to salinity, temperature and shear for HVFR. The drag reduction rate of HVFR with DME is up to 74% at the temperature of 90 °C. The proppant settling velocities with the addition of DME for different mesh sizes can be reduced from 47.3% to 66.7% compared to the HVFR system. With the addition of DME, oil recovery through spontaneous imbibition is improved by 24.9%. Based on the results of NMR scans and electron microscopy, HVFR and DME can form quasi-crosslinked structures when the DME acts as the adsorption point. This structure can enhance the strength of the polymer chains and generate a tighter polymer network, which can effectively improve the viscosity and viscoelasticity of the slickwater. This study suggests that DME can be selected as a promising additive for HVFR and proposes a comprehensive evaluation method to screen the additives for slickwater.