Viscoelastic Fracturing Fluid Research Articles

Synthesis and evaluation of water-soluble fracturing fluid thickener based on hydrophobic association

• Hydrophobically associative polymers. • Cross-linked fracturing fluid has excellent performance. • The residue content is low, and the damage to the reservoir is small. A cyclic quaternary ammonium salt type hydrophobic monomer VIM-16 was synthesized by 1-vinylimidazole and 1-bromohexadecane, and the hydrophobically associative polymer PAAV was prepared with AM and AMPS. It was cross-linked with 0.3% zirconium acetylacetonate to form a viscoelastic fracturing fluid. The rheological properties of it were found to have good thickening and shear resistance properties. Using 0.2% gel breaker, the gel was completely broken. No residue, it was a low damage fracturing fluid. Scanning electron microscopy was used to observe the microscopic morphology, and the morphology after cross-linking to form the jelly showed a uniform, regular and ordered network structure.

Fabrication and Performance of Gemini Oleamidopropyl Hydroxy Sulfobetaine (GOHSB) Used as a Viscoelastic Fracturing Fluid

Fabrication and Performance of Gemini Oleamidopropyl Hydroxy Sulfobetaine (GOHSB) Used as a Viscoelastic Fracturing Fluid

A novel CO2 sensitive and recyclable viscoelastic fluid system for fracturing

Hydraulic fracturing is one of the most commonly used processes of stimulating oil and gas wells to improve the production in low permeability reservoirs or damaged wells. In response to the serious water waste caused by the flowback fluid after the fracturing operation and the huge environmental pressure, a novel CO2 sensitive and recyclable viscoelastic fracturing fluid was developed. This CO2 sensitive property allows fracturing fluids to be recycled. The system consists of viscoelastic surfactants called fatty methyl ester sulfonates (FMES), triethylenetetramine and NaCl. The system shows a strong sensitivity to CO2. When the system is repeatedly contacted and separated from CO2, the viscosity rises and falls rapidly and regularly. The experiments of viscoelasticity, shear resistance and microstructure confirmed that the increasing viscosity of the system after contacting with CO2 was caused by the formation of viscoelastic fluid. When the system leak-off into the formation matrix, the microstructure of the system will be rapidly destroyed under the action of hydrocarbons, and the viscosity will drop to 1.225 mPa·s. Low viscosity after destroying reduces the retention of the system in the formation, resulting in formation damage rate of less than 35%. This research not only provides high-performance, low-cost fracturing fluids, but also provides new insights for the recovery and utilization of fracturing fluids.

Development of CO2-Sensitive Viscoelastic Fracturing Fluid for Low Permeability Reservoirs: A Review

There are economic and technical challenges to overcome when increasing resource recovery from low permeability reservoirs. For such reservoirs, the hydraulic fracturing plan with the development of clean and less expensive fracturing fluid plays a vital aspect in meeting the energy supply chain. Numerous recent published studies have indicated that research on worm-like micelles (WLMs) based on viscoelastic surfactant (VES) fluid has progressed substantially. This study looks at the development of CO2-sensitive viscoelastic fracturing fluid (CO2-SVFF), its applications, benefits, limitations, and drawbacks of conventional fracturing fluids. The switchable viscoelasticity of CO2-SVFF system signifies how reusing of this fluid is attained. Compared to conventional surfactants, the CO2-SVFF system can be switched to high viscosity (to fracture formation and transporting proppants) and low viscosity (easy removal after causing fracture). The effect of pH, conductivity, temperature, and rheological behaviors of CO2-SVFFs are also highlighted. Further, the aid of Gemini surfactants and nanoparticles (NPs) with low concentrations in CO2-SVFF can improve viscoelasticity and extended stability to withstand high shear rates and temperatures during the fracturing process. These studies provide insight into future knowledge that might lead to a more environmentally friendly and successful CO2-SVFFs in low-permeability reservoirs. Despite the increased application of CO2-SVFFs, there are still several challenges (i.e., formation with high-temperature range, pressure, and salinity).

Viscoelasticity and microstructural properties of zwitterionic surfactant induced by hydroxybenzoate salt for fracturing

The viscoelasticity and microstructural behaviors of wormlike micelles (WLMs) solutions induced by different organic salts are interesting. However, the influence of different hydroxybenzoate salts on zwitterionic surfactant, erucylamidopropyl carboxybetaine (EDAB) is unknown. The effects of hydroxybenzoate salts; sodium 2-hydroxybenzoate (oBen), sodium 3-hydroxybenzoate (mBen), on sodium 4-hydroxybenzoate (pBen) on EDAB were studied. The rheological and micelle aggregates transformation of the zwitterionic-hydroxybenzoate system were investigated by rheology, dynamic light scattering, and cryo-microscopy transmission electron (Cryo-TEM) measurements. The properties of the EDAB-hydroxybenzoate solutions as fracturing fluid were evaluated based on viscoelasticity, temperature and shear tolerance, sand suspension, gel breaking, and core permeability damage. The micellar development in EDAB-hydroxybenzoates was governed by intramolecular interactions within EDAB molecule, hydrophobic interactions, and electrostatic interactions. Apart from these interactions, the position of the hydroxyl group relative to the carboxyl group in hydroxybenzoates induced hydrogen bonding which was responsible for varied rheological properties of EDAB-hydroxybenzoate fluids. It was found that EDAB-oBen (EoBen) demonstrated higher viscoelasticity than other EDAB-hydroxybenzoates. Switching pH values alters acidity around the carboxylate head groups of EDAB causing structural transformations of EDAB-hydroxybenzoate solutions. EoBen and EDAB-mBen (EmBen) solutions demonstrated a viscoelastic fluid characteristic at pH 7 and a viscous behavior at pH 2. Moreover, the EoBen, EmBen, and EDAB-pBen (EpBen) as fracturing fluids maintained a viscosity of 50, 35.7, and 32.2 mPa·s respectively for 2 h at 90 °C and 170 s−1, these viscosities indicate that all solutions can effectively transport sand during fracturing. The settling velocities in EoBen, EmBen, and EpBen at 90 °C were 0.0018, 0.0035, and 0.0066 cm/s respectively after 5 h. The viscosity of the studied EDAB-hydroxybenzoates breaks to <5 mPa·s within half an hour. The residual content and core permeability damage for EoBen were 9.5 mg/L and 5.5% respectively. Thus, compared to EmBen, and EpBen, the EoBen is the best prospect for the development of pH-responsive viscoelastic fracturing fluid.

Investigation of cellulose nanofiber enhanced viscoelastic fracturing fluid system: Increasing viscoelasticity and reducing filtration

Viscoelastic fracturing fluid (VFF) is considered to have great potential as fracturing agent with no residues and low damage to formation. However, traditional VFF composed of surfactant and salt is difficult to form filter cake due to its low molecular weight components, resulting in high filtration during fracturing operation. In order to solve this problem, cellulose nanofiber (CNF) enhanced viscoelastic fracturing fluid (CNEVFF) formed by sodium oleate (NaOA)/potassium chloride (KCl) and CNF was proposed and studied. The rheological properties of CNEVFF were investigated by rheometer. With the addition of CNF, the zero-shear viscosity of CNEVFF is higher than that of VFF. Moreover, the microstructures of core surface filtrated by different systems were detected by scanning electron microscopy (SEM) measurement, proving the formation of filter cake. The dynamic filtration damage (DFD) measurement was employed to investigate the damage effect of different fracturing fluids on the cores with different permeabilities. In addition, more details of different flooding stages during DFD experiment were measured by nuclear magnetic resonance (NMR) technology, exhibiting the damaging process of CNEVFF to the core dynamically. The removal of filter cake and an appropriate mechanism describing the formation and destruction of novel network formed by VFF and CNF was discussed.

Development and evaluation of a novel seawater-based viscoelastic fracturing fluid system

Based on the situation of the freshwater shortage during the large scale hydraulic fracturing on offshore-platform, a novel seawater-based viscoelastic fracturing fluid system was developed. The system was composed with a commercial anionic – nonionic viscoelastic surfactant named Fatty Methyl Ester Sulfonates (FMES) with the concentration of 60 mmol/L, the South China Sea simulated seawater with the TDS of 32500 mg/L and Na+ with the concentration of 1320 mmol/L. On the basis of this fracturing fluid system, a series of performances have been evaluated through extensive experiments. Analysis of laboratory tests indicated that the new fluid has good viscosity stability, low fluid loss and high proppant suspending ability under 75 °C. This fluid always appeared as a pseudoplastic fluid at various shearing speeds. After high speed shearing, the viscosity recovered quickly which means the fluid has remarkable self-repairability. This fluid breaks rapidly once oil injected. The observed permeability return rate achieved through core flooding experiment was over 70%, which indicated low formation damage after fracturing. Furthermore, the vermicular micelle and microstructure of fluid system has been discovered through Cryogenic Transmission Electron Microscope (cryo-TEM), which well explained the mechanism of excellent performances of fluid system.

Viscoelastic surfactant fracturing fluid for underground hydraulic fracturing in soft coal seams

Hydraulic fracturing is an effective and increasingly popular method of improving the permeability of coal deposits. However, fracturing fluids specifically designed for coal deposits are required, as the properties of the fracturing fluid can affect the permeability improvement. A numerical model and rheological tests were used to determine the optimum viscosity and composition of fracturing fluid for underground fracturing. The effect of this optimized viscoelastic surfactant fracturing fluid on coal porosity, gas adsorption and permeability were experimentally investigated and compared with water as a fracturing fluid. Results showed that the viscoelastic surfactant fracturing fluid increased coal pore volume and surface area by 33.9% and 30.6% respectively, compared with samples processed with water. Adsorption and permeability tests on the coal samples processed with viscoelastic surfactant fracturing fluid and water showed that the adsorption capacity was reduced by 22.4% when using viscoelastic fracturing fluid, while the permeability increased by 178%. Using viscoelastic surfactant fracturing fluid can increase the fracturing area and promote gas desorption and seepage, thus improving gas extraction. The results of this study demonstrate the potential for applying of viscoelastic surfactant fracturing fluid in underground fracturing in coal mines.

PH- and KCl-induced formation of worm-like micelle viscoelastic fluids based on a simple tertiary amine surfactant

To explore the application of pH-responsive surfactant, a pH-responsive N,N-dimethyl-erucamide-propylamine (DEAPA) self-assembly system was prepared and characterized. The rheological property and structural transformation of DEAPA molecular aggregations were comprehensively discussed with decreasing pH or increasing of Cl− concentration using rheology, dynamic light scattering (DLS), ultraviolet-visible (UV) spectrophotometry, and cryo-transmission electron microscopy (cryo-TEM). The properties of the DEAPA-KCl viscoelastic fluid used as the fracturing fluid were discussed in terms of the viscoelasticity, temperature-tolerance, and shear-tolerance, proppant suspension, and core permeability damage at pH 1.5. Results revealed that the microstructure of the DEAPA micelle first transformed from vesicles to spherical micelles, and finally changed to worm-like micelles when HCl solution was added. In addition, on increasing the KCl concentration, the system transforms from spherical micelles to worm-like micelles. When the Cl− concentration was increased to 0.50 mol/L (pH = 1.5), the storage modulus (G′) of the DEAPA-KCl fluid became over 15 Pa and loss modulus (G″) was over 5 Pa, which suggests that elasticity is the predominant property of these worm-like micelles. Also, the viscosity of the DEAPA-KCl fracturing fluid was constant at about 110 mPa s at 80 °C and shear rate of 170 s−1. The settling velocity of the DEAPA-KCl fluid was lower than 0.004 mm/s at 60 °C, and the core permeability damage was 6.75%. Therefore, the DEAPA-KCl system is suitable for use as an acidic viscoelastic fracturing fluid.

The influence of fiber on the rheological properties, microstructure and suspension behavior of the supramolecular viscoelastic fracturing fluid

An innovative fiber-based fracturing fluid technology has been developed to enhance the productivity of low-permeability and ultra-low-permeability reservoirs. However, few studies have focused on the influence of fiber on the rheological properties, microstructure and suspension behavior of a supramolecular fracturing fluid. In this article, the rheological properties, microstructure and proppant suspension behavior of the supramolecular fluid affected by the fibers were discussed. The rheological measurement showed the addition of fibers facilitated the formation of the fiber network and strengthened the mechanical network structure which improved the rheological properties of the fluid. The addition of fibers did not change the reversible shear thinning behavior of this fluid. Meanwhile, it was proven that the power-law model could accurately predict the rheological parameters of this fiber-laden fracturing fluid. Both temperature and shear rate could disassemble the complex structure of this fiber-based fracturing fluid resulting in the decrease of viscosity. The scanning electron microscopes (SEM) micrographs demonstrated the supramolecular network honeycomb structure of the fluid, which was made up of the wormlike micelles and polymer chains with extremely efficient physical crosslinking. The proppant suspension data indicated the elasticity factor did not represent the proppant suspension capacity of the liquid. The results of the rheological measurement, SEM and the static-column test showed that the fiber network could improve the proppant suspension capacity through strengthening the ability of load bearing and consolidation of the fluid.

Enhanced Sand-Control System Successfully Treats Six Zones in Offshore Indonesia Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24879, ’Enhanced Multizone Single-Trip Sand-Control System Successfully Treats Six Zones in Offshore Indonesia Well,’ by Leon Zhou and Indra Gunawan, ConocoPhillips, and Ricki Jannise, Casey Suire, and Tyson Eiman, Halliburton, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed. Although multiple-zone, downhole sand-control-tool systems have been in use since the early 1990s, these systems have been designed for jobs that require only low pump rates with low pressure differentials. Multiple-zone systems capable of high fracturing pump rates and the associated differentials only recently have been introduced to the oil field, but most of these completions have been limited to four or five treated zones. This paper presents a case history from Indonesia in which six discrete zones in an offshore deployment were treated successfully in a single trip. Field History The Bawal field is located in Block B, 1000 km north of Jakarta, in the South China Sea. The average water depth across the field is 280 ft. The Bawal field was discovered in 1979; the field is approximately 5 km long and 2 km wide. The Bawal reservoirs consist of subangular-to- rounded, well-sorted silt to extremely fine quartz sand. The initial development concept was to drill and complete two to three subsea wells and tie them back to a nearby production facility, Hangtuah, 43 km away. The first-gas-production target was 2012. The reservoirs all require sand control, varying degrees of stimulation, high-rate water packing at rates of 8 to 20 bbl/min, and fracture treatments at rates of 22 to 35 bbl/min. The operator has completed multiple fields with two dominant completion methods: openhole standalone screen (OHSAS) and cased-hole frac pack (CHFP). The OHSAS completions typically are installed in horizontal wells or very-high-angle wells. The OHSAS requires special reservoir-drill-in fluid with calcium carbonate to drill the reservoir section, run the premium screen, wash the pipe, and conduct mudcake cleanout. Typically, a CHFP is conducted with tubing- conveyed perforation and alternative- flow-path sand screen being run in one trip; then, a frac pack is pumped with viscoelastic fracturing fluid. Historically, the operator has completed subsea wells with downhole sand control using the OHSAS method for single- zone completions and singletrip frac-pack/high-rate water packs for multizone commingled production. For frac-pack completions, the completion system used previously was capable of treating only up to three zones; therefore, the treatment rate per zone became lower, and there was always an issue with slurry distribution. If more than two to three zones were required per well, a stacked frac-pack completion was implemented. Completing these wells with conventional stacked sand-control methods meant spending many rig days tripping pipe in and out of each well. The single-trip multizone methods previously used in the area typically would provide only a limited pump rate of up to 10 bbl/min per zone and pressure ratings of 6,000 psi. For the new wells, the fracture treatments would require a more-robust system that would include a pressure rating of 10,000 psi because of sandout conditions. Another challenge was that commingling these zones into one well has historically resulted in 50% less recovery compared with single-zone completions. Early water breakthrough coming in from one of the zones would cause the well to load up and die. Therefore, the operator also wanted to include installation of an intelligent-completion system that would allow zonal isolation without intervention, to optimize reserves recovery. The multizone frac-pack completion not only would have to be capable of completing up to six zones in one run but also would have to be compatible with the planned intelligent-system equipment.

Performance and application of new anionic D3F-AS05 viscoelastic fracturing fluid

Recently, polymer free fracturing fluid was investigated to reduce formation and fracture conductivity damage during and after hydraulic fracture treatment. This fluid system uses a viscoelastic surfactant (VES). Some shortcomings of VES fluid such as excessive leakoff and the limit of temperature range have limited the use of the conventional VES fluid. On the basis of the conventional VES fracturing fluid system, a new anionic VES fracturing fluid “D3F-AS05” was developed through an extensive experiments. The fluid utilizes a specially formulated anionic surfactant. Analysis of laboratory tests indicates that the new fluid has good viscosity stability with high ability of carrying sand; the fluid also has low fluid loss and low frictional resistance. On the other hand, more than 97% returned permeability was achieved, which indicates low formation damage after gel-breaking. The temperature stability of the new fluids extended to more than 90 °C. This allowed the fluid to be used in the deep well with a high injection rate. This paper provides the procedures and the chemical additive of the new fluid and has focused on the performance of the fluid under different concentrations. The paper also illustrates the effect of the fluid in fracture geometry with a field application result.