Proppant-carrying Capacity Research Articles

Molecular dynamics simulation of solvation behavior and thickening properties of modified siloxanes in supercritical carbon dioxide under different pressure and temperature

Supercritical carbon dioxide (ScCO2) fracturing fluids have been limited in their application in unconventional reservoirs due to their weak proppant-carrying capacity resulting from their low viscosity. Consequently, numerous scholars have focused on modifying siloxanes to enhance their solubility and thickening performance in ScCO2. In this paper, the cohesive energy density, interaction energy, radial distribution function, shear viscosity and electrostatic potential distribution of modified siloxane with ScCO2 were calculated using molecular dynamics simulation. The effects of different temperatures and pressures on the dissolution and thickening ability of modified siloxanes in ScCO2 were investigated.The simulation results indicate that high temperature and low pressure have limited effects on promoting the solubility of modified siloxanes in ScCO2, with temperature exerting a more significant influence on solubility behavior than pressure. Additionally, PD4H+TMPTMA is less soluble in ScCO2 compared to PD4H+TAIC. The binding energy of ScCO2 and modified siloxanes decreases with increasing temperature but increases with increasing pressure. Van der Waals interactions and electrostatic interactions play decisive roles in the solubility of modified siloxanes in ScCO2. Finally, the thickening mechanism of modified siloxanes in ScCO2 was elucidated based on molecular structure and binding energy interactions.In summary, this paper aims to provide options and assistance in synthesis of better ScCO2 thickeners for unconventional reservoir fracturing applications through the study of modified siloxanes.

The Development and Performance of a Gemini Viscoelastic Surfactant with Tricationic Groups Applied in Unconventional Oil and Gas Reservoir Stimulation

AbstractTo improve water solubility and salt tolerance of viscoelstic surfactants (VESs), modifying the spacer of Gemini VES was adopted and a novel Gemini VES nominated TC‐2OH, with tri‐cationic groups and double hydroxyls on the spacer, was developed. The basic surface activity properties of TC‐2OH and the molecular aggregate behavior stimulated by NaCl or NaSal were measured and analyzed to investigate the mechanism of viscoelastic fluid forming by TC‐2OH solution, and it proved that TC‐2OH is more sensitive to NaSal, compared with NaCl, due to the embedded structure of salicylate. The molecular structure of TC‐2OH imparts excellent solubility to itself, and with the assistance of ethanol, the dissolution time in water can be shortened to within 45 seconds. In addition, oscillation experiments, heat and shear resistant experiments, and drag reduction tests were conducted to study the advantage of NaSal for stimulating the formation of the slickwater compared with NaCl. The slickwater stimulated by NaSal indeed exhibit superior drag reduction and proppant carrying capacity. To effectively disassemble the wormlike micelles for gel breaking, ethylene glycol butyl ether performs better than the hydrocarbons because of its high polarity and water solubility. The gel breaking fluids of slickwater caused extremely low damage to the tight sandstone cores. The successful development of TC‐2OH enables instant preparation of slickwater and variable‐viscosity for fracturing in unconventional reservoirs, which also realizes convenient switching between the slickwater with different viscosity.

New Method for Monitoring and Early Warning of Fracturing Construction

During fracturing operations, special situations are often encountered. For example, the insufficient proppant-carrying capacity of fracturing fluid can cause quartz sand or ceramsite to settle near the wellbore and form a sand plug. Alternatively, excessive sand injection intensity can lead to severe accumulation of injected sand near the wellbore and also form a sand plug. These special situations are reflected in the fracturing operation curve as an abnormal increase in oil pressure over a short period of time. If not handled promptly, they can have unimaginable consequences. Sand plugs in fracturing operations, characterized by their speed and unpredictability, often form rapidly, within about 20 s. Conventional methods for on-site sand-plug warnings during fracturing include the oil pressure–time double logarithmic slope method and the net pressure–time double logarithmic slope method. Although these methods respond quickly, their warning results are unstable and vary significantly during actual operations. This is mainly because the fluctuations in the actual fracturing operation curve are often large, and there can be sudden pressure rises and drops even during stable periods, albeit less pronounced. To address the identification of anomalies in conventional fracturing operation monitoring and warning methods, a sand-plug warning index method has been proposed for sand-plug identification. This method combines the oil pressure–time double logarithmic slope with the oil pressure increment within 5 s, the rate of change in the oil pressure–time double logarithmic slope, and the fitted oil pressure intercept as indicators. The method has been validated using Well A in Fuling as an example. The validation results show that the dynamic analysis method can predict sand plugs while reducing warning fluctuations without affecting sensitivity. Compared to conventional methods, the warning time can be advanced by about 10 s.

Experimental Research on the Proppant Settling and Transport Characteristics of Silica Gel-Based Fracturing Fluid

Summary Hydraulic fracturing is an effective stimulation method to establish high-conductivity channels in tight reservoirs, and the effectiveness of man-made fractures largely depends on the proppant-carrying capacity of the fracturing fluids used. As a novel completion fluid, silica gel-based fracturing fluids have shown desirable stimulation effect in application cases, but a comprehensive evaluation of their proppant settling and transport behaviors in the laboratory remains lacking. In this paper, a silica gel-based fracturing fluid was prepared first, and then the rheological properties, including shear thinning, recovery behavior, and viscoelasticity of the fluid system, were measured. Afterward, the settling velocity of single-particle proppant and the settling rate of multiparticle proppant under various experimental conditions were investigated in the static fluid system; in addition, the dynamic proppant-carrying performance was evaluated using a visualized rough fracture model to study different factors on the dune distribution inside the fractures. Lastly, the proppant-carrying mechanism of silica gel-based fracturing fluid was revealed in three aspects. The rheological test result showed that the shear viscosity of silica gel-based fracturing fluid increased as the SiO2 concentration increased. Furthermore, all tested fluid samples exhibited an elastic modulus that is consistently greater than the viscous modulus, indicating that the silica gel-based fracturing fluid system has a dominant elastic response behavior. In the single-particle static settling test, there was a significant increase in the settling velocities as the particle diameter increased and as the temperature increased. Meanwhile, the settling rate of multiparticles showed a decreasing trend with the increase in mesh size, while the proppant settling rate gradually increased as the proppant concentration rose. The results of dynamic proppant-carrying experiments demonstrate that a higher pumping rate leads to an extended migration distance for proppant, resulting in formed sand dunes with reduced height within fractures. Conversely, an increase in proppant concentration and a reduction in mesh size tend to form higher sand dunes. The proppant-carrying mechanisms of the silica gel-based fracturing fluid relate to the self-polymerization and syneresis of silica gel, the noticeable elasticity characteristics, and the structural encapsulation effect formed between silica gel and proppant. A better understanding of the proppant settling and transport behaviors of silica gel-based fracturing fluid can be helpful in optimizing the hydraulic fracturing design and promoting field application.

Stability study of aqueous foams under high-temperature and high-pressure conditions relevant to Enhanced Geothermal Systems (EGS)

In Enhanced Geothermal System (EGS) hydraulic fracturing is carried out by injecting cold water into deep Hot Dry Rocks (HDR) under carefully controlled conditions to create new or reopen existing fractures. Water-based fracturing fluids demonstrate some challenges including immense quantity of water usage, water sensitivity of the formations, water blocking, and lack of proppant carrying capacity and transportation. Thus, an alternative is to use foam-based fracturing fluid which offers potential advantage over conventional water-based fracturing fluid such as minimum water usage, reduced wellbore damage, high proppant carrying capacity, and less environmental damage. However, foams are complex mixture of gaseous phase and liquid phase which are thermodynamically unstable at downhole conditions, and their stability can decrease over time due to liquid drainage, bubble coarsening, and coalescence. This paper shows laboratory experiments executed to study foam stability at high temperature (200 °C) and high pressure (6.9 MPa) conditions which simulates the geothermal environment. Foam stability was characterized by half-life of foam, which is defined as the time taken by the foam to decreases by 50% of its original height due to drainage. In this paper, two types of gaseous phases, nitrogen (N2) and carbon dioxide (CO2) were investigated. Also, based on successful practice of foam-based fracturing fluid in oil and gas industries, four surfactants, including Alpha olefin sulfonate (AOS), Sodium dodecyl sulfonate (SDS), Tergitol™ (NP – 40), and Cetyltrimethylammonium chloride (CTAC) at optimum concentration of 1 wt.% were tested for best stability performance. In addition, different stabilizing agents including guar gum, bentonite clay, crosslinker, silicon dioxide nanoparticles (SiO2), graphene oxide (GO) were also studied. Experimental results showed that N2 foams were more stable than CO2 foams. It was observed that foam half-life decreased with the increase in temperature. Among all the surfactants, AOS foams showed the most promising thermal stability at high temperatures. Moreover, with the addition of stabilizing agents, foam's half-life was enhanced. Stabilizing agents such as crosslinker and GO dispersion showed the most stable foams with half-life recorded at 20 min and 17 min, respectively, at 200 °C and 6.9 MPa. Finally, pressure also showed a positive effect on foam stability; with increased pressure, foam half-life was increased. Based on the experimental data, analytical models for the effect of temperature and pressure were developed, considering foam degradation is a first-order kinetic reaction that linearly depends on the foam drainage mechanism. The effect of temperature on foam half-life was studied as an exponential decay model. In this model, foam half-life is a function of drainage rate constant (DA) and activation energy (Ea) of the foam system. The effect of pressure on foam half-life was found to obey a power-law model where an increase in pressure showed an increase in foam half-life. Furthermore, a linear relation was studied for the effect of pressure on foam activation energy and drainage rate. Then the combined effects of temperature and pressure were studied, which yielded an analytical model to predict the foam stabilities in terms of half-life for different foam compositions. This research indicates that with an appropriate selection of surfactants and stabilizing agents, it is possible to obtain stable foams, which could replace conventional water fracturing fluid under EGS conditions.

Construction and mechanism study of clean N2 foam fracturing fluid stabilized by viscoelastic surfactant in concentrated brines for unconventional oil and gas

As a much-anticipated clean thickener, viscoelastic surfactants (VESs) have drawn much attention in the development of foam fracturing fluids for unconventional oil and gas stimulation. Herein, the mechanism of foam stabilization by VESs and wormlike micelles (WLMs) under a high-salinity environment was investigated by evaluating three kinds of salt-tolerant VESs with different molecular structures through a series of experiments, including drainage tests, foam microscopic characteristic observations and interface rheology tests. The drainage test proved that the liquid film drainage was effectively inhibited under the proper salinity range for WLM construction. Based on microscopic observation, although WLMs are formed, gas diffusion inevitably occurs in each foam fluid as bubble size diversity exists, while the foam stabilized by VES-BC, the Gemini structure with steric hindrance on its spacer, exhibits comparably high uniformity of bubble size. Relying on the Gibbs criterion, this further proves that the foam stabilized by VES-BC resists gas diffusion better than the other two foams, as the critical shrinking speed of the VES-BC solution droplet to resist gas diffusion is lowest, which explains why the foam stabilized by VES-BC exhibits the best anti-coarsening capacity under static conditions. The oscillation droplet test proves that the VES-BC molecules and WLMs they construct impart the interface with the best resistance to external disturbance and deformation under the proper salinity range for WLM construction. Meanwhile, the interface shear modulus measurement indicates that the WLMs construed by VES-BC molecules and the interaction between WLMs and the VESs on the interface play crucial roles in anti-coalescence between bubbles. Under high-temperature and high-pressure conditions, the VES-C and VES-BC foam fracturing fluids prepared by brines, with 80% foam quality, both exhibit excellent thickening and proppant carrying capacity, and the VES-BC foam fracturing fluid can withstand 140 °C to sustain a low settling rate of proppant, which potentially decreases the cost of cleaning fracturing fluid by displacing 80% of the fluid into N2 and causes little damage to unconventional reservoirs. All experiments prove that foam coarsening is the key factor causing foam decay regardless of whether WLMs exist, yet WLMs can efficiently inhibit the drainage of liquid film and resist bubble coalescence by interacting with the molecules on the interface.

Mechanism analysis of enhancing the temperature and shear resistance of hydroxypropyl guar gum fracturing fluid by boron-functionalized nanosilica colloidal crosslinker

With the increasing depth of reservoir development, the temperature and shear resistance of fracturing fluids needs to be further improved. In comparison with traditional crosslinking agents, nano-crosslinkers have superior crosslinking properties and can enhance the temperature and shear resistance of fracturing fluids. However, the synthesis of nano-crosslinkers is complicated and not sufficiently explained to elucidate the crosslinking mechanism. In this study, a nanosilica colloidal crosslinker with a larger size and more crosslinking sites was synthesized by a simplified method using nanosilica. The structure and crosslinking mechanism of nanosilica crosslinkers were explored using FTIR, XPS, TGA, and SEM. The results indicated that the nanosilica and organoboron were bonded through B-N bonds. The nanosilica crosslinker has good dispersion and excellent thermal stability. The thermal and shear stability of nano-crosslinked fracturing fluids was better than that of fracturing fluids formed with organoboron crosslinkers. Specifically, temperature resistance is enhanced by 7–18 °C and shear resistance by 5–20 mPa s. In addition, the gel-breaking fluid changes the wettability of the core surface and enhances the flow capacity of the oil. The results of FTIR showed the synergistic effect of hydrogen and covalent bonding between the crosslinker and guar gum molecules. The results of SEM indicated that the guar gum molecules are transformed from a linear structure to a membrane structure during the transformation of the fracturing fluid from a base fluid to a gel, which gave the gel water retention capacity and good proppant-carrying capacity. Furthermore, the nanosilica crosslinker is distributed on the surface of the membrane or located in the membrane by binding to the membrane. The interaction between the nanoparticles and the membrane structure enhances the strength of the membrane structure, which allows for better shear stability of the nano-crosslinked fracturing fluid at high temperatures.

Effects of cationic and anionic surfactants on the stability, rheology and proppant suspension of nanoparticle-stabilized fracturing foams at elevated temperature

Much attention has been paid to applying liquid foams in hydraulic fracturing in the past few years due to their significant benefits, including minimal formation damage. In the current literature, the combination of anionic surfactants and nanoparticles (NP) has been thoroughly studied to improve foam-based fracturing fluids' thermal stability and viscosity. However, very little research has focused on the synergy between cationic surfactants and NP, which results in a limited understanding of the effects of this mixture on enhancing the properties of fracturing foams, especially at reservoir temperature. This paper investigates and compares the synergy between cationic/anionic surfactant and silica nanoparticles (SNP) in improving the fracturing foams' stability, rheology and proppant-carrying capacity under ambient and elevated temperature conditions. The experiments involved foamability, bulk static stability, viscosity measurement and proppant settling tests at fixed NP concentration and varied surfactant concentrations. The results showed that the foams' properties were gradually enhanced with increasing surfactant concentration until reaching a peak at around 0.05–0.1 wt%. At ambient and elevated temperatures, the foams stabilized by SNP and cationic hexadecyltrimethylammonium bromide (CTAB) surfactant had higher half-life, apparent viscosity, and better proppant-carrying ability than those stabilized by SNP and anionic sodium dodecyl benzene sulfonate (SDBS) surfactant. The properties of CTAB/SNP foams were found most outstanding at medium CTAB concentration; however, they declined dramatically at very low or very high surfactant concentration. This study enhances our understanding of the influences of surfactant type and concentration on the stability, rheology and proppant suspension behaviour of nanoparticle-stabilized foams, which directly contributes to developing an effective foam system for high-temperature fracturing application.

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.

Doubly cross‐linked polymer gels with ultra‐high‐thermal stability for hydrofracking

AbstractCross‐linked polymer gels have been commonly utilized in the hydraulic fracturing process for stimulating oil and gas production; however, their weak thermal stability still impedes their more broadly use. Here we report doubly cross‐linked polymer gel consists of a high‐viscosity friction reducer (HVFR), poly‐(acrylamide‐co‐acrylic acid‐co‐2‐acrylamido‐2‐methyl‐1‐propane‐sulfonic acid), and crosslinkers zirconium ion (Zr4+) and polyethyleneimine (PEI). The mixture solution of HVFR/Zr4+/PEI can be gelled spontaneously via heating to form double cross‐linked polymer gel due to the formation of physical and chemical crosslinks. The electrostatic interactions of Zr4+ and carboxylate moieties from HVFR to form first physically cross‐linked network at low temperature; the transamidation reaction between amide groups of HVFR and primary amines of PEI to generate second chemically cross‐linked network at high temperature. More significantly, the physical and chemical crosslinks can work synergistically to improve thermal stability of double cross‐linked polymer gel as compared to single cross‐linked polymer gel counterparts, which is capable of reaching fluid service temperatures up to 190°C. The double cross‐linked polymer gel features delayed crosslinking performance, the physically cross‐linked reaction of HVFR and Zr4+ occurs at approximately 52°C, while the onset of chemical crosslink of HVFR and PEI can be tuned from 154 to 180°C. Moreover, double cross‐linked polymer gel provides a high viscosity at ultra‐high temperatures, with remarkable heat‐ and shear‐resistance as well as proppant carrying capacity in hydrofracking process. The double cross‐linked polymer gel also can be completely broken with no apparent residues. This double cross‐linked polymer gel may provide a new approach for polymer gels used in ultra‐high‐temperature reservoirs.

Experimental study of the rheology of cellulose nanocrystals-enhanced C22-tailed zwitterionic wormlike micelles

Nano-materials enhanced zwitterionic surfactants fracturing fluids with greatly improved rheological properties are extensively employed in foam fracturing to stimulate unconventional gas/oil reservoirs. In this study, a novel worm-like micelles (WLMs) system composed of erucyl dimethyl amidopropyl betaine (EDAB, C22), alkyl polyglucoside (APG) and cellulose nanocrystals (CNC) is proposed. A series of rheology and dynamic light scattering tests were conducted to determine the optimal concentration, and the influence of various factors, including temperature, pH, and inorganic salts, on the viscoelasticity and structural morphology of WLMs systems were also analyzed. The results show that a 0.3 wt% EDAB/APG/CNC system exhibits optimal viscosity and viscoelastic fluid behavior. The increase of temperature accelerates the breaking rate of WLMs, resulting in a decrease in viscosity, but its shear viscosity can still maintain 87.42 mPa·s at 90 °C and is an order of magnitude greater than that of other systems. The change of pH can disturb the equilibrium state under the electrostatic interaction of EDAB and CNC, and the negative ions in EDAB and CNC molecules are easily protonated in acid medium, resulting in a lower viscosity than alkaline medium and much lower than neutral medium. The viscosity of the EDAB/APG/CNC system increases first and then decreases with the increase of inorganic salt concentration, and reaches a peak at 2.5 wt%. Proppant critical settling velocity tests show that the CNC improves the proppant-carrying capacity of the EDAB/APG/CNC system with favourable critical settling velocity. The CNC enhanced C22-tailed EDAB system provides a basis for optimizing foaming fracturing in unconventional reservoirs.

Simulation study of micro-proppant carrying capacity of supercritical CO2 (Sc-CO2) in secondary fractures of shale gas reservoirs

Micro-proppants with stronger portability have more potential to migrate to the massive micro-sized secondary fractures (SFs) or natural fractures activated by supercritical CO2 (Sc-CO2) fracturing in shale gas reservoirs. However, the transportation behaviour of micro-proppants in massive SFs has been scarcely studied to date. In this study, we report the simulation of micro-proppant migration across a fracture intersection during Sc-CO2 fracturing based on a combination of computational fluid dynamics and the discrete element method. A straight fracture intersection model was first validated against experimental data from an earlier study. Next, the influential factors, including fluid viscosity, cross angle, proppant diameter, fluid velocity and the ratio of proppant diameter to SF, were examined in the transportation behaviour of micro-proppants in Sc-CO2 fracturing. The results show that the poor proppant distribution in SFs is dominated by the ultralow viscosity of Sc-CO2, but the decrease of proppant diameter to 25 μm presents slurry flow behaviour, resulting in a migration distance around 8 times longer than that of 200 μm and much stronger proppant-carrying capacity into SFs. The transportation behaviour of micro-proppants into SFs depends on the suspended proppants concentration and the rolling proppants from the proppant embankment in the primary fracture (PF), determined by the combined effects of different factors. Fast fluid velocity of 0.2 m/s increases the priority of the proppant embankment formation in SFs. Cross angles greater than 45° limit the suspended proppants in SF, and the proppant embankment in the SF dominantly depends on rolling proppants from PF. Greater SF aperture facilitates proppants transportation into the SF due to the reduced bridging effect, but not into the PF. The key findings are optimized proppant-carrying capacity into SFs and improved stimulated volume during Sc-CO2 fracturing in shale reservoirs.

Preparation and Performance Evaluation of a Variable Viscosity Friction Reducer Suspension with High Salt Tolerance and Low Damage

In view of challenges such as the long dissolution time of powder friction reducers in high-salinity water, poor environmental friendliness of water-in-oil (W/O) emulsion friction reducers, and the poor proppant-carrying capacity of conventional slickwater, a novel variable viscosity friction reducer suspension (EACM) with high salt tolerance, low damage, and strong proppant-carrying capacity was prepared by dispersing salt-tolerant polymer powder in alcohol solvents. The solubility, drag reduction ability, viscoelasticity, proppant-carrying capacity, temperature and shear resistance, and gel breaking ability of EACM were investigated. The results showed that the best solvent for the friction reducer suspension was polyethylene glycol 400, in which EACM exhibited a rapid dissolution rate with a thickening rate of 89.5% within 2 min. Due to the synergic effect between fumed silica and polyamide wax as antisedimentation agents, both at a concentration of 2.0 wt %, the EACM could remain stable for 60 days. EACM showed an excellent drag reduction performance at both low and high viscosities in 100 000 mg/L salt brine. Specifically, a drag reduction of up to 72.4% was obtained using 0.21 wt % EACM (4.65 mPa s), and a 60.8% drag reduction was achieved using 1.0 wt % EACM (35.5 mPa s). When the concentration increased from 0.13 to 1.0 wt %, the EACM solution changed from viscous to elastic; the spatial network structure of the solution became more compact, and the proppant-carrying capacity was enhanced. The viscosity of 1.6 wt % EACM solution could be maintained at 55.9 mPa s after shearing at 90 °C for 120 min at a shear rate of 100 s–1. EACM solution also exhibited the advantages of easy breaking and low residue. This paper provides guidance for the design and selection of a novel friction reducer suspension in the oil and gas industry.

Rheological and fracturing characteristics of a cationic guar gum

Guar gum (GG) fracturing fluid is frequently used in the field of enhanced oil recovery. GG fracturing fluids must have increased the temperature resistance and salt tolerance due to the complexity of drilled formations. In this study, the cationic guar gum (GG-GTA) samples for fracturing fluids were successfully synthesized, which can even resist 120 °C. It can be directly prepared by formation water, even sea water. Besides hydrogen bonds and covalent bonds, the additional cationic groups can strengthen the network even more in the GG-GTA fracturing fluids, which is why the GG-GTA fracturing fluids had stronger rheological properties than the GG fracturing fluids. The GG-GTA fracturing fluids performed well in terms of temperature resistance, salt tolerance, pressure resistance, and proppant carrying capacity. In addition, the GG-GTA gel-breaking caused little damage to core permeability because it exhibited low viscosity, interfacial tension, and surface tension. These results provide a solid foundation for the application of GG-GTA fracturing fluids in oilfield production.

Techniques for improving fracture-controlled stimulated reservoir volume in ultra-deep fractured tight reservoirs: A case study of Kuqa piedmont clastic reservoirs, Tarim Basin, NW China

Based on analysis of the reasons for low efficiency and low production after fracturing of some wells in the ultra-deep fractured tight reservoirs of the Kuqa piedmont zone, Tarim Basin and the matching relationship between the in-situ stress field and natural fractures, technological methods for creating complex fracture networks are proposed. Through theoretical study and large-scale physical simulation experiments, the mechanical conditions for forming complex fracture network in the Kuqa piedmont ultra-deep reservoirs are determined. The effectiveness of temporary plugging and diversion, and multi-stage fracturing to activate natural fractures and consequently realize multi-stage diversion is verified. The coupling effect of hydraulic fractures and natural fractures activating each other and resulting in “fracture swarms” is observed. These insights provide theoretical support for improving fracture-controlled stimulated reservoir volume (FSRV) in ultra-deep tight reservoirs. In addition, following the concept of volume fracturing technology and based on the results of fracture conductivity experiments of different processes, fracturing technologies such as multi-stage fracture-network acid fracturing, “multi-stage temporary plugging + secondary fracturing”, fracturing of multiple small layers by vertically softness-and-hardness-oriented subdivision, and weighted-fluid refracturing are proposed to increase the FSRV. New environment-friendly weighted-fluid with low cost and new fracturing fluid system with low viscosity and high proppant-carrying capacity are also developed. These techniques have achieved remarkable results in field application.

Impact of Supercritical CO2 on Shale Reservoirs and Its Implication for CO2 Sequestration

Hydraulic fracturing has transformed the international energy landscape by becoming the go-to method for the exploitation of natural gas from unconventional shale reservoirs. However, in the recent years, the search for an alternative method of shale-gas exploration has intensified, because of various problems (e.g., contamination of ground and surface water, overexploitation of precious water resources, air pollution, etc.) associated with the usage of water-based fracturing techniques. The use of CO2 for shale gas exploitation has emerged as a better alternative to aqueous-based gas exploration techniques. CO2 when injected into deep shale reservoirs, transitions into supercritical CO2 (SC-CO2) when temperature and pressure condition exceeds the critical point, i.e., 31.1 °C and 7.38 MPa. In this paper, we comprehensively review the impact of SC-CO2 on shale gas reservoirs during the different stages of shale-gas exploration, i.e., (i) drilling, which involves the superiority of SC-CO2 over water-based drilling fluids, in terms of achieving under-balanced well condition, higher rates of penetration, and resistance to formation damage; (ii) fracturing, which involves factors affecting the tortuosity of fractures created by SC-CO2 fracturing, breakdown pressure, and proppant-carrying capacity; and (iii) injection, which involves the twin-headed benefit of enhanced recovery due to CO2/CH4 competitive adsorption and geological sequestration, CO2 vs CH4 excess sorption as a function of pressure, etc. Several research works have indicated discrepancies on how SC-CO2 impacts different shale properties. Some studies show low-pressure N2-gas-adsorption-derived surface area and total pore volume to be increasing with SC-CO2 imbibition, while others show a decreasing trend for the same. Similarly, for some shales, the quartz content, along with the clay mineral contents, decreased as the exposure to SC-CO2 increased, while in some other studies, with similar long-term exposure to SC-CO2, the quartz content was observed to increase along with the decrease in clay content and vice versa. Essentially, the increased exposure to SC-CO2 results in the dissolution of primary porous structures and fractures, and reformation of newer porous structure and conduits in shales. Nonetheless, these changes in the mineralogy weaken the microstructure of the rock bringing significant changes in the mechanical properties of the shales with implications on the wellbore stability and fracturing efficiency. The mechanical properties such as uniaxial compressive strength (UCS), Young’s modulus, and tensile strength decrease as the SC-CO2 saturation period increases. However, some studies have shown factors like bedding angle and phase-state of CO2 having varying effect on the strength behavior of the shales. Moreover, changes in the structure of shales caused by the creation of fractures and the reduction of their strength can also pose major risks, because of potential leakage of CO2 through these created pathways. How these processes would interact at field scale would control the sealing capacity, especially at field-scale for addressing long-term seepage of CO2.

Performance evaluation of a novel CO2-induced clean fracturing fluid in low permeability formations

After the limitations of polymer-based fracturing due to poor clean-up property during flowback after fracturing treatment, viscoelastic surfactant (VES) received very huge attention in the last three decades, especially in low permeability reservoirs. In this study, a Novel CO 2 -induced clean fracturing fluid (SDS-TMTAD-CO 2 ) is formulated with simulated formation water (23,003 mg L −1 ) after optimization experiments according to the proposed parameters (i.e., 70 °C, economical, easily preparation, and environment-friendly). The results of rheological experiments show that the apparent viscosity of the fracturing fluid system increases to a certain extent under high salt conditions and possesses sufficient self-healing property against high shear tolerance. At different temperatures (25, 50, and 70 °C), the thermodynamic properties, fluid viscoelasticity, and proppant carrying capacity meet the requirements of the fracturing fluid industry standards. After adding kerosene (0.02 mol L −1 ); the gel breaking fluid viscosity (3.2 mPa s), anti-swelling rate (91.3%), and interfacial tension (2.3 × 10 −2 mN m −1 ) are holding promising conditions during the flowback period, clay swelling, and residual oil saturation, respectively. The filtration and core damage experimental results meet the national industry standard for fracturing fluids. The SEM results show that the fluid system after reaction forms a unified adsorption film on the core surface. Hopefully, this fluid system will be proved as a good candidate by means of excellent proppant transportation ability, anti-swelling, easy gel structure breaking, low filtration, and less formation damage in low permeable formations with an increase in productivity. • Easy preparation of an economical and environment-friendly CO 2 -induced clean fracturing fluid system (SDS-TMTAD-CO 2 ). • Rheological and functional performances of the system meet the “SY/T 6376-2008, SY/T 5107-2016, and SY/T 5971-2016” standards. • Can fracture the low permeable formations with less filtration and low formation damage.

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.

Performance Evaluation and Site Application of a Hydrophobic Long-Chain Ester-Based CO2 Fracturing Fluid Thickener

Nowadays, there are a wide variety of thickeners developed for dry CO2 fracturing worldwide, but numerous problems remain during in situ testing. To address problems in CO2 fracturing fluid operation (high frictional drag, low viscosity, low proppant-carrying capacity, narrow reservoir fractures, etc.), the authors have synthesized the novel hydrophobic long-chain ester thickener, studied viscosity, frictional drag, and proppant-carrying capacity of CO2 fracturing fluid and core damage by CO2 fracturing fluid by varying the temperature, pressure, and level of injection of the novel thickener and explored the thickening mechanism for this thickener in CO2. Based on the study results, as the temperature, pressure, and amount of injected thickener increased, fracturing fluid viscosity increased steadily. In the case of shearing for 125 min under conditions of 170 S−1, 40°C, and 20 MPa, when the thickener level increased from 1% to 2%, fracturing fluid viscosity increased and then decreased, varying within 50–150 mPa·s, and the viscosity-enhancing effect was evident; under conditions of 20°C and 12 MPa, as the flow rate increased, drag reduction efficiency reached 78.3% and the minimal proppant settling speed was 0.09 m/s; under conditions of 40°C and 20 MPa, drag reduction efficiency reached 77.4% and the proppant settling speed was 0.08 m/s; with the increases in temperature, pressure, and injection amount, core damage rates of the thickener varied within 1.77%–2.88%, indicating that basically no damage occurred. This study is of significant importance to the development of CO2 viscosity enhancers and CO2 fracturing operation.

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

Summary In this paper, we discuss proppant transport behavior in a complex slot system. Specifically for this study, focus is placed on two different fluid systems, a water/glycerin solution and a water/sodium chloride solution, which represent varying fluid densities and viscosities. The effects of changing fluid viscosities, fluid densities, proppant densities, proppant sizes, proppant concentrations, and slurry injection rates on proppant transport were then experimentally investigated. The slot system consists of a 4-ft long, 0.2-in. primary slot with three secondary slots and two tertiary slots, all at 90° angles to each other. The fluid systems represented brine fluids up to 9.24 ppg and viscous fluids up to 4.3 cp. Although glycerin was used for viscosification, the results can be compared to fluid systems with similar viscosities that are created using other additives such as friction reducers. The proppants used in the study consisted of two sands of 100 and 40/70 mesh (specific gravity of 2.65) and two 40/70 ceramic proppants with specific gravities of 2.08 and 2.71. The study results 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. In addition, sieve analysis conducted on each of the various slots indicated that for all tested proppants that the water/glycerin systems were more capable of carrying larger particles to farther distances. Conversely, the results show that a water/sodium chloride solution of 9.24 ppg density has less capability to carry the proppant farther into the slots. From a comparison standpoint, in all tested cases, viscosity increases had a greater impact on the overall proppant transport than fluid density. In addition, results of the study showed that both increasing proppant concentrations and injection rates have a positive impact on proppant transport, with more proppant being transported farther into the slot system in both cases. The higher the proppant concentration, the sooner the equilibrium dune height (EDH; height when transport starts to occur after dune building) was achieved, the more efficient transport became. Increasing the injection rate led to improving proppant transport by increasing the drag and lift forces on the proppant, which lead to decreased proppant settling velocities and transport farther into the slots.