Viscoelastic Surfactant Fracturing Fluid Research Articles

Long-time seepage evolution in coal fractures during injection of viscoelastic surfactant fracturing fluids

Long-time seepage evolution in coal fractures during injection of viscoelastic surfactant fracturing fluids

Physicochemical Effect on Coal Pores of Hydrocarbon Chain Length and Mixing of Viscoelastic Surfactants in Clean Fracturing Fluids.

Clean fracturing fluids are environmentally friendly and could have broad applications in permeability enhancement of coal seams. The hydrophobic chain length of the viscoelastic surfactant (VES) and the mixing of VESs with different ionic types have marked effects on the performance of clean fracturing fluids. This paper analyzes the effects of the hydrocarbon chain length of VES and mixing of VESs with different ion types on the pores of coal and discusses the mechanisms controlling the pore changes from a physical and chemical perspective. We found that the coal samples treated with clean fracturing fluid B had the largest porosity change. Adding two methylene groups to the hydrocarbon chain of the cationic VES will increase clay swelling in coal treated with fracturing fluids. Adding 0.1 wt % cocoamidopropyl betaine (zwitterionic VES) to cationic VES fracturing fluids can reduce the extent of clay expansion induced by fracturing fluids. VES with a long hydrocarbon chain has a strong ability to remove kaolinite in hard coal, and the addition of zwitterion VES increases the ability of a clean fracturing fluid to remove kaolinite. These results provide theoretical guidance for the synthesis of new VES molecules and the design of new fracturing fluid formulations.

Performance evaluation and formation mechanism of Janus-SiO2 nanoparticles assisted viscoelastic surfactant fracturing fluids

The eco-friendly viscoelastic surfactant (VES) system, whose viscoelasticity can be enhanced by nanoparticles (NPs), is an appropriate substitute for polymer fracturing fluid. In the present study, the JA12C NPs (Janus SiO2 nanoparticles decorated with dodecyl hydrophobic carbon chain) are successfully synthesized and characterized by Fourier transform infrared spectra (FTIR), thermal gravimetric analysis (TGA), dynamic light scattering (DLS), and transmission electron microscope (TEM). The prepared JA12C NPs are separately induced into three kinds of fracturing fluids (anionic-based VES (aVES), cationic-based VES (cVES), and zwitterionic-based VES (zVES) fluids) to investigate their effects on the rheological properties of various VES fluids. It is found that additional JA12C NPs significantly enhance the viscoelasticity of cVES fluid, while hardly affecting that of aVES and zVES fluids. Then the zeta potential of mixed JA12C/surfactant dispersions and the rheological parameters of diverse VES systems are measured to explore the interaction mechanism of wormlike micelles (WLMs)/JA12C mixture. It is believed that the intensive hydrophobic interaction and the moderate electrostatic repulsion between WLMs and JA12C should be responsible for the visibly enhanced viscoelasticity of JA12C-assisted cVES (cJAVES) fluid. This work suggests the feasibility of using Janus NPs to enhance the tolerance properties of VES fluids in harsh conditions, which fills the gap in the applications of VES fracturing fluids incorporating Janus NPs.

Rheology and delayed micellar formation process of novel tetrameric cationic surfactant fracturing fluid

AbstractTo enrich the clean fracturing fluid system with high temperature resistance, a novel tetrameric cationic surfactant (TET) was developed and used as a thickener and mixed with different concentrations of sodium salicylate (NaSal) to obtain a new clean fracturing fluid. The flow curves, thixotropy, viscoelasticity, temperature resistance property, and proppant‐suspending capacity were further investigated. The rheological study showed that the Casson model could be used to accurately describe the flow curve of TET/NaSal micelle solutions and the addition of NaSal improved the thixotropy and viscoelasticity of surfactant solution. The optimal mass ratio of TET/NaSal solution was 5/1.5 wt%, and it had good proppant‐suspending capacity. What is more, the retained viscosity of TET/NaSal (5/1.5 wt%) solution was 52.27 mPa·s after shearing at 140°C and 100.0 s−1 for 65 min, which met industry requirements (viscosity > 20 mPa·s) of viscoelastic surfactant fracturing fluids. Moreover, the combination of 10 wt% TET aqueous solution with pH value of 8.51 and 2.6 wt% salicylic acid (HSal) suspension of the same mass significantly delayed micellar formation. The four‐parameter rheo‐kinetics model can be used to fit the viscosity curves of micellar formation, which provided the rheological basis for the study of delayed viscoelastic micellar formation.

Performance Evaluation and Formation Mechanism of Viscoelastic Surfactant Fracturing Fluids with Moderate Interfacial Activity Enhanced by Janus-SiO2 Nanoparticles.

Nanoparticles (NPs) exhibit great potential to improve various properties of viscoelastic surfactant (VES) fracturing fluids in the development of low-permeability reservoirs. In the present study, the amphiphilic Janus NPs (JANPs) were fabricated via the Pickering emulsion method and employed to construct the novel JA12C (JANPs with dodecyl hydrophobic carbon chains)-assisted VES fracturing fluid (JAVES). The successful fabrication of JANPs was confirmed via Fourier transform infrared spectroscopy (FTIR) measurements and water contact angle tests. The rheology behavior of the VES fracturing fluid incorporating various SiO2 NPs including hydrophilic SiO2 NPs (HLNPs), JA8C (JANPs with octyl hydrophobic carbon chains), and JA12C was systematically investigated. It was revealed that the additional JA12C significantly improved the tolerance and proppant suspension properties. To explore the subsequent oil recovery performance of various gel breaking liquids, the formation wettability and the oil-water interfacial tension (IFT) were studied after the evaluation of breaking properties and formation damage properties of various fracturing fluids. The results suggested that the JAVES gel breaking liquid showed remarkable wettability alternation capability and moderate oil-water IFT reduction ability, which can partially reduce the impact on reservoir permeability. Moreover, the formation mechanism of the JAVES was proposed by molecular dynamics simulations at the molecular level, which was further visually verified via the cryo-TEM images. The improved viscoelasticity of developed the JAVES with moderate interfacial activity is advantageous to enhance subsequent oil recovery.

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.

Performance evaluation of oil-displacement viscoelastic zwitterionic surfactant fracturing fluid

Viscoelastic surfactant (VES) fracturing fluid has advantages in sand-carrying and micelle-breaking without residues, while its practical applications are always limited due to the poor temperature and shearing resistance. Accordingly, a kind of stearicamide propyl hydroxylsulfobetaine (SPHB) was self-synthesized by using stearic acid, N, N-dimethyl-1,3-propane diamine, and sodium 3-shloro-2-hydroxypropane sulfonate as raw materials, and a novel VES fracturing fluid (HCF) was prepared by optimizing the ratio of SPHB and counterion. The composition of the novel fracturing fluid system was determined according to the viscosity varies with temperature. Moreover, the temperature and shearing resistance, viscoelastic, sand-carrying, drag reduction, micelle-breaking, and oil displacement properties of the system were systematically studied. The results showed that the optimum molar ratio of SPHB to salicylate counterion in the fracturing fluid system was 1:1. Surface tension test showed the critical micelle concentration (CMC) of SPHB surfactant solution is 6.27 × 10-4 mol /L and the surface tension γcmc is 40 mN/m. The apparent viscosity of the novel fluid was kept above 50 mPa·s after continuous sheared for 60 min under the condition of 170 s−1 at 130 ℃. Besides, it has good viscoelastic property and sand-carrying performance, and the experimental results showed that the drag reduction rate of the novel fluid reaches more than 60% at different temperatures. The micelle-breaking performance of the novel system was perfect. There is basically no solid residue in the micelle-breaking solution, and the permeability damage rate of the micelle-breaking liquid to the natural core was only 9.41%, which showed the novel fluid has the characteristics of low damage. Finally, low-permeability natural cores were used to carry out micelle-breaking fluid oil displacement experiments, including single core flooding and double-tube parallel core flooding, and the mechanism of micelle-breaking fluid improving oil recovery was revealed.

Rheological behavior of a novel fracturing fluid formed from amine oxide surfactants

AbstractIn this paper, two kinds of long‐chain amine oxide surfactants, erucamidopropyl dimethylamine oxide (EAOS) and oleamidopropyl dimethylamine oxide (OAOS) were synthesized and compounded with different mass ratios. The rheological tests show that there is a synergistic effect between EAOS and OAOS, and this effect reaches the strongest at the EAOS/OAOS solution with α = 0.7 (α is the mass fraction of EAOS in the mixed surfactant). Through the synergistic effect between EAOS and OAOS, the temperature resistance of amine oxide surfactant solutions can be effectively improved. EAOS/OAOS (α = 0.7) solutions with total surfactant mass fractions of 3, 4, and 5 wt% show good high‐temperature resistance at 130, 140, and 150°C, respectively. After shearing for 60 min at 100 s−1, 160°C, the remaining viscosity of the 5 wt% EAOS/OAOS (α = 0.7) with 1 wt% KCl solution is 30 mPa s, meeting the demand of viscoelastic surfactant fracturing fluids.

Pseudo-interpenetrating network viscoelastic surfactant fracturing fluid formed by surface-modified cellulose nanofibril and wormlike micelles

Nano-material enhanced viscoelastic surfactant (VES) systems have attracted considerable attention as clean fracturing fluids due to their improved rheological properties compared to conventional VES systems. In this study, a pseudo-interpenetrating network VES (PINVES) fracturing fluid, which was composed of sodium oleate (NaOA), potassium chloride (KCl) and surface-modified cellulose nanofibril (SMCNF), was proposed. The rheological behavior of the PINVES fracturing fluid and the interaction mechanism between SMCNF and wormlike micelles (WLMs) were comprehensively studied. The zero-shear viscosity of PINVES increased with appropriate SMCNF addition but decreased with excess SMCNF addition. Meanwhile, the typical viscosity-flat of WLMs gradually disappeared when the concentration of SMCNF exceeded the optimum value. The optimum value was closely related to the functional groups on the surface of SMCNF. The SMCNF physically crosslinked the WLMs through hydrogen bonding but the sulfonic groups and hydrophobic groups on the surface of SMCNF destroyed the network of WLMs at relatively high SMCNF concentration. The network formed by SMCNF dominated the rheological behavior of the PINVES fracturing fluid simultaneously. In addition, due to the competition between the network of WLMs and the network of SMCNF, the PINVES fracturing fluid exhibited higher concentration dependence of surfactant in rheological behavior than conventional VES fracturing fluid. The SMCNF network also endowed the PINVES with better temperature-resistance. Furthermore, the relaxation time and elasticity of PINVES fracturing fluid increased with the increase in SMCNF concentration. The static proppant settling tests demonstrated that the addition of SMCNF improved the sand-carrying capability of PINVES fracturing fluid. The results of the study could provide some enlightenments on the application of SMCNFs in reservoir stimulation. • The rheological behavior of the fracturing fluid largely depends on the competition between the network of WLMs and the network of SMCNF. • The temperature-resistance and viscoelasticity of the fracturing fluid was improved by the network of SMCNF. • The interaction mechanism between SMCNF and WLMs is closely related to the functional groups on the surface of SMCNF.

Impact assessment of nanoparticles on microstructure and rheological behaviour of VES fracturing fluid formulated with mixed surfactant system

The nature and type of fracturing fluid play a vital role in a successful hydraulic fracturing job. The desired fracturing fluid should have non-damaging characteristics and an effective proppant carrying capacity. Though viscoelastic surfactant (VES) fluid has started to replace the polymer-based fluids for the fracturing of specific formations owing to its non-damaging characteristics; however, its wider application to high-temperature formation is still a challenge to the operators. Incorporation of nanoparticle has been able to extent the thermal stability of VES fluid. The current study examined the impacts of different nanoparticles at different concentrations on rheological and structural properties of VES fluid prepared from mixed surfactant system which is composed of NaOA/tween 80, Co-surfactant, oil and water. Nano-enhanced VES fluids were formulated using SiO2, Fe2O3, MgO, and ZnO nanoparticles at varied concentrations, ranging from 250 ppm to 1000 ppm. The rheological and morphological variations of VES fluids were studied at different shear rates and temperatures. MgO and Fe2O3 enhanced VES at 500 ppm concentration fluid showed excellent rheological characteristics with 3529 cp and 2817 cp viscosity at a shear rate of 100 S−1, temperature 35 °C, which is much above the required viscosity value. Zeta potential and surface area of nanoparticles both play an important role in the rheological enhancement of VES fluid. MgO enhanced VES fluid with a surface area (83.7 m2/g) and zeta potential (−15.9, mV) of MgO nanoparticles showed better rheological properties than silica enhanced VES gel with surface area (127.8 m2/g) and zeta potential (–33.8, mV). It was also observed that increasing the nanoparticle concentration improved VES fluid's rheological properties; however, the rate of increment decreased after 500 ppm concentration. The cryo-FESEM images clearly indicate the distict change in the lamellar structure of VES fluids on the addition of nanoparticles compared to that of in its absence. The dynamic rheology tests further confirmed the compact structure and stronger entanglement of micelles in the presence of nanoparticles.All the developed nano-enhanced VES fracturing fluids showed desired viscosity up to the temperature of 150 °C. Among all nano-enhanced fracturing fluid, MgO enhanced VES fracturing fluid showed excellent viscosity (i.e., 200 cP) with respect to time at 100 °C temperature and a shear rate of 100 S−1. All the nano-enhanced VES fluid was miscible with formation water & there were no residues observed. A static column test was also done to check the proppant carrying capacity of VES gel. The MgO enhanced VES gel has also showed lowest proppant settling velocity of 0.305 cm/min which is much lower than the maximum permissible proppant settling velocity of 5 cm/min. The findings of this study can help for a better understanding of nano-enhanced VES fracturing fluid in mitigating the constraints associated with hydraulic fracturing jobs in formation with high temperatures. Thus, the knowledge about the functional characteristics of different nanoparticles in enhancing the fracturing fluid properties will help us to select suitable nanoparticle-surfactant combinations for a particular field.

Coupling Effect of Temperature, Gas, and Viscoelastic Surfactant Fracturing Fluid on the Microstructure and its Fractal Characteristics of Deep Coal

The study of the microstructure evolution law of coal in a natural reservoir environment for the extraction of coalbed methane mining (ECBM), especially deep ECBM, is of major significance. We treated coal samples from Qinshui Basin under combined temperature–gas–fracturing fluid conditions and analyzed the evolution of the microstructure and its fractal characteristics to study the microstructural evolution of coal under natural hydraulic fracturing conditions. In the temperature range of 303.15 to 343.15 K and the gas-pressure range of 0.5–4.5 MPa, our data demonstrate that the pore structure is more susceptible to the temperature influence, compared with microfracture. The treatment of viscoelastic surfactant fracturing fluid (VES-FF) can effectively increase the permeation pore and fracture ratio by more than 300% and reduce the adsorption pore by more than 200% through dissolution, gas wedge, and other effects, which is favorable to ECBM. At the same temperature, as the gas pressure increases, the pore decreases, whereas the fracture ratio increases. The pore fractal dimension ranges from 2.90 to 2.99, which is significantly higher than that of microfractures. The temperature has a minor effect on the fracture fractal dimension, but it causes a decrease in the pore fractal dimension. The treatment of VES-FF induces an increase in the fracture fractal dimension, implying an increase in the fractal complexity. In contrast, the pore fractal characteristics show a contrary trend. At a gas pressure of 4.5 MPa, the negative effect of VES-FF on the pore structure reaches its maximum, whereas the effect on the fracture drops to its minimum. The results document that high temperature and high gas pressure can severely limit the penetration enhancement effect of VES-FF.

Effect of different types of fracturing fluid on the microstructure of anthracite: an experimental study

ABSTRACT A systematic understanding of the effects of different fracturing fluids on the chemical and pore structure of coal is of great significance for the exploitation of coalbed methane (CBM). In this study, Fourier-transform infrared spectroscopy and mercury intrusion porosimetry were used to analyze the chemical and pore structure of coal samples treated by different fracturing fluids. The results show that fracturing fluid treatment has little effect on the coal aromatic structure. The oxygen-containing and hydroxyl structures of the coal samples treated by acidic and viscoelastic surfactant (VES) fracturing fluids increased by >17%, which is beneficial for gas desorption and thereby increases CBM yield, whereas those of the coal sample treated with deionized water decreased by 3.8%. The acidic and VES fracturing fluid treatments are also beneficial for coal pore connectivity, which promotes gas migration. The three types of fracturing fluids increased the macropore volume by >350%. The deionized water treatment reduced mesopores and micropores by 20% and 5%, respectively, while the transition pores increased by 2.3%, resulting in a 2.6% increase of the specific surface area, which is not conducive to gas desorption and migration. The acidic fracturing fluid treatment increased the mesopore volume by 53.3%, reduced the transition pore and micropore volumes by 5.3% and 32.5%, respectively, and reduced the surface area by 13.2%, which reduces the amount of adsorption sites and facilitates gas migration. However, the adsorption pores and mesopores after VES fracturing fluid treatment decreased by 17.6% and 26.7%, respectively, which indicates that this treatment does not transform most adsorption pores into migration pores.

Experimental Study on the Drag Reduction Performance of Clear Fracturing Fluid Using Wormlike Surfactant Micelles and Magnetic Nanoparticles under a Magnetic Field.

This paper examines a new study on the synergistic effect of magnetic nanoparticles and wormlike micelles (WLMs) on drag reduction. Fe3O4 magnetic nanoparticles (FE-NPs) are utilized to improve the performance of viscoelastic surfactant (VES) solutions used as fracturing fluids. The chemical composition and micromorphology of the FE-NPs were analyzed with FT-IR and an electron microscope. The stability and interaction of the WLM-particle system were studied by zeta potential and cryo-TEM measurements. More importantly, the influences of the temperature, FE-NP concentration, magnetic field intensity, and direction on the drag reduction rate of WLMs were systematically investigated in a circuit pipe flow system with an electromagnetic unit. The experimental results show that a suitable content of magnetic nanoparticles can enhance the settlement stability and temperature resistance of WLMs. A magnetic field along the flow direction of the fracturing fluid can improve the drag reduction performance of the magnetic WLM system. However, under a magnetic field perpendicular to the direction of fluid flow, an additional flow resistance is generated by the vertical chaining behavior of FE-NPs, which is unfavorable for the drag reduction performance of magnetic VES fracturing fluids. This study may shed light on the mechanism of the synergistic drag reduction effects of magnetic nanoparticles and wormlike micelles.

A Novel CO2 Responsive Viscoelastic Surfactant based Clear Fracturing Fluid for High-Temperature Unconventional Reservoir

An unconventional reservoir is a term to describe a hydrocarbon resource that could not be technically or economically recoverable without stimulation. Unconventional oil and gas resources are 4-5 times over conventional oil and gas resources. Currently, there is a limitation for using slick-water volume fracturing and gas (water) injection adding energy for drainage and displacement individually. Also, the efficient hydrocarbons production from the high-temperature unconventional reservoir is the main challenge. In the current study, a CO2 based viscoelastic surfactant fracturing fluid with a specific molar ratio of erucic acid, 2,6,10-trimethyl-2,6,10-triazaundecane, potassium hydroxide, and carbon dioxide (EA-TMTAD-KOH-CO2) was developed as a good candidate for high-temperature and water alternating treatment for high-temperature unconventional reservoirs. The fracturing fluid will play the role of “one with multi-purpose” by proppant-carrying, CO2 energy supplementary displacement, and surfactant imbibition drainage displacement. The fracturing fluid (EA-TMTAD-KOH-CO2) performance evaluation method for determination of shear and heat resistance, viscoelasticity, proppant carrying capacity, gel breaking ability, and salt tolerance is employed as evaluation indices by using HTHP rheometer. The rheological results of steady shear viscosity of the fracturing fluid system confirm that the EA-TMTAD-KOH-CO2 was observed in the properties of a wormlike micelles (WLMs) structure, micelles assembly, and the intermolecular interactions. The steady shear viscosity above 41 mPa.s at a shear rate of 170 s‒1 and temperature 95 °C validates the excellent proppant carrying capacity as per national industry standards of the fracturing process. Further, the gel structure breaking at temperature 135 °C and 170 s‒1 bear the shear viscosity less than 5 mPa.s, which results in a rapid flow back from the well after the fracturing process. Moreover, the fluid system has high salt tolerance against different inorganic salts such as NaCl, KCl, CaCl2, and MgCl2 using different concentrations. By retaining the desirable qualities such as; easy to prepare, environment friendly, commercially available, high in viscoelasticity, and thermally stable; the fracturing fluid system (EA-TMTAD-KOH-CO2) will be an outstanding candidate in industrial applications like water-alternating and high-temperature unconventional reservoirs.

Organic Acid-Enhanced Viscoelastic Surfactant and Its Application in Fracturing Fluids

Viscoelastic surfactant (VES) fracturing fluids, with the advantages of low residues, complete gel breaking, and low formation damage, have received considerable attention in hydraulic fracturing techniques. However, the complicated synthesis process and high costs limit the widespread application of VESs. Herein, a VES fracturing fluid composed of wormlike micelles was developed by coupling an ultralong hydrophobic chain surfactant N-erucamidopropyl-N,N-dimethylamine (EA), with p-phthalic acid (p-PA), which behaved as a “Gemini-like” surfactant via noncovalent interactions. The macroscopic appearance and viscosity of this fluid were responsive to the regulation of pH values. Then, the related fracturing performance of this fluid was systematically investigated, from which it could be concluded that the VES fluid exhibited good temperature and shear resistance, excellent proppant-carrying and gel-breaking abilities and also caused less damage to core permeability and low corrosion of steel under acidic conditions. Finally, the rheological properties of the VES fluid could be switched multiple times without any decay by changing the pH values, indicating its excellent reusability for fracturing procedures. Consequently, this study demonstrates potential applications of reusable VES fracturing fluids based on supramolecular pH-responsive surfactants.

Gemini Surfactant with Unsaturated Long Tails for Viscoelastic Surfactant (VES) Fracturing Fluid Used in Tight Reservoirs.

The high dosage of surfactant terribly restrains the extensive application of viscoelastic surfactant (VES) fracturing fluid. In this study, a novel gemini surfactant (GLO) with long hydrophobic tails and double bonds was prepared and a VES fracturing fluid with a low concentration of GLO was developed. Because of the long tails bending near the double bonds, there is a significant improvement of the surfactant aggregate architecture, which realized the favorable viscosity of the VES fluid at a more economical concentration than the conventional VES fracturing fluids. Fourier transform infrared spectrometry (FT-IR), nuclear magnetic resonance spectrometry (1H NMR, 13C NMR), and high-resolution mass spectrometry (HRMS) were employed to study the formation of the product and the structure of GLO. The designed GLO was produced according to the results of the structure characterizations. The formula of the VES fracturing fluid was optimized to be 2.0 wt % GLO + 0.4 wt % sodium salicylate (NaSal) + 1.0 wt % KCl based on the measurements of the viscosity. The viscosity of the VES fluid decreased from 405.5 to 98.7 mPa·s as the temperature increased from 18 to 80 °C and reached equilibrium at about 70.2 mPa·s. The VES fluid showed a typical elastic pseudoplastic fluid with a yield stress of 0.5 Pa in the rheological tests. It realized a proppant setting velocity as low as 0.08 g/min in the dynamic proppant transport test carried by GLO-based VES fracturing fluid. Compared to the formation water, the filtrate of the VES fracturing fluid decreased the water contact angle (CA) from 56.2 to 45.4° and decreased the water/oil interfacial tension (IFT) from 19.5 to 1.6 mN/m. Finally, the VES fracturing fluid induced a low permeability loss rate of 10.4% and a low conductivity loss rate of 5.4% for the oil phase in the experiments of formation damage evaluation.

The role of KCl in cationic Gemini viscoelastic surfactant based clean fracturing fluids

KCl, as a kind of counter-ion salt, is often used in cationic viscoelastic surfactant (VES) clean fracturing fluid systems. The interaction between Cl− and VES cationic hydrophilic groups is used to promote the formation of VES micelles, which significantly improves the viscoelasticity, temperature resistance, and shear resistance of cationic VES fracturing fluid. At the same time, KCl is also a widely used inorganic salt clay stabilizer. K+ enters the interlayer of the clay and reduces the hydration expansion of clay by charge attraction. To determine whether Cl− and K+ in KCl can simultaneously play the role of counter-ion and clay stabilizer, we have evaluated the performance of KCl on viscoelasticity, temperature, shear resistance of cationic VES fracturing fluid and clay stability. The interaction of KCl and VES in clay stability was also studied. Results revealed that VES thickener has a clay stabilization effect in cationic VES fracturing fluid system, and the higher the concentration, the better the clay stabilization effect. KCl can not only effectively enhance the viscoelasticity and temperature resistance of cationic VES fracturing fluid, showing a counter-ion performance, but also acted as a clay stabilizer. However, VES and KCl can restrain each other in clay stability and produce antagonistic effects.

Evaluating the changes of sorption and diffusion behaviors of Illinois coal with various water-based fracturing fluid treatments

The water-based fracturing stimulation is commonly used for low permeability coalbed methane (CBM) reservoirs. The influence of various fracturing fluids on the gas sorption and diffusion behaviors were experimentally studied in the work. The Illinois basin coal was selected for the experimental measurements. We used slickwater, guar gel and viscoelastic surfactant (VES) fracturing fluids to treat the coal. The sorption and diffusion behaviors were measured and quantified by the volumetric sorption experiments. The microscope was employed for the coal sample surface observation to qualitatively characterize the coating and residue behavior of fracturing fluids. It was found that all types of fracturing fluids can significantly influence the gas sorption capacity of coal. Apart from the low concentration of polyacrylamide (0.1% and 0.3%) slickwater, all other fracking fluids damage the gas sorption capacity. For most fracturing fluids, the sorption capacity can be recovered closely back to its virgin coal condition with extensive water washing. For the coal samples treated by the VES fracturing fluid, both the Langmuir volume and Langmuir pressure were dramatically increased. The adverse effect of fracturing fluids on coal is apparent and all diffusion coefficients decrease with the treatment. Even with extensive washing, the diffusion coefficient cannot recover for slickwater and VES fluids. But guar gel fluid has the best diffusion recovery because of the easy removal of the guar gel. This study provides a preliminary data set for fracturing fluid selection for Illinois coal in terms of sorption and diffusion.

Fracture permeability damage and recovery behaviors with fracturing fluid treatment of coal: An experimental study

The water-based fracturing fluid is commonly used in coalbed methane (CBM) industry. The fracturing fluid invades into both stimulated and natural fractures. The fracture permeability are pivot parameter for fracturing stimulation and production planning. In this study, laboratory studies have been conducted to measure the fracture permeability evolutions for both artistically propped and natural fractures of anthracite. Three commonly used water-based fracturing fluids, including the slickwater, the guar gel and the viscoelastic surfactant (VES) fracturing fluids, were used for the experiments. The anthracite core specimens were prepared with either artistically propped (simulating hydraulic fracture) or natural fractures. The damage of the water-based fracturing fluid to the permeability of anthracite was comprehensively analyzed. Our experimental results show that both the slickwater and the guar gel can induce apparent damage to the permeability of the artificially propped and natural fractures. The VES fracturing fluid has less damage than the slickwater and the guar gel. The degree of permeability damage to the artificially propped fracture generally increases with an increase of concentration or the viscosity of the fracturing fluid. The fracturing fluid gives higher permeability damage to the artificially propped fracture supported by smaller proppant than that for large proppants. For each type of fracturing fluid, the size and density of the residue mass increased with the increase of the concentration of the fracturing fluid. For the permeability damage induced by the invasion of the fracturing fluid, the intrinsic reason is the blockage and occupation of the residue to the internal space of the fracture.

Evaluation of a Composite Flooding Formula Used to Enhance the Oil Recovery of Ansai Oil Field

The composite flooding formula utilizes the characteristics of polymer flooding and surfactant flooding to compensate for the shortage of single component chemical flooding, reduce the oil-water interfacial tension to a certain extent, and broaden the maintenance range of low interfacial tension. The combined effects and synergies in the oil displacement process enhance oil recovery and allow it to adapt to a wider range of reservoir conditions. In this paper, the high surface active polymer-surfactant flooding formula suitable for the Chang 6 reservoir in Ansai Oilfield was evaluated. The general technical index of the viscoelastic surfactant fracturing fluid and the composite flooding surfactant were evaluated. The technical requirements are evaluation criteria, and comprehensive evaluation is made from several aspects such as salt tolerance, interfacial tension and emulsifying properties.