Water-based Fracturing Fluids Research Articles

Fracture propagation characteristics of water and CO2 fracturing in continental shale reservoirs

Exploring the adaptability of CO2 and water-based fracturing to shale oil reservoirs is important for efficiently developing shale oil reservoirs. This study conducted fracturing experiments and acoustic emission (AE) monitoring on the Jurassic continental shale. Based on high-precision computed tomography scanning technology, digital reconstruction analysis of fracture morphology was carried out to quantitatively evaluate the complexity of fractures and the stimulation reservoir volume (SRV). The results show that the fracturing ability of a single water-based fracturing fluid is limited. Low-viscosity fracturing fluid tends to activate thin layers and has limited fracture height. High-viscosity fracturing fluid tends to result in a wide and simple fracture. A combination injection of low-viscosity and high-viscosity water-based fracturing fluid can comprehensively utilize the advantages of low-viscosity and high-viscosity fracturing fluids, effectively improving the complexity of fractures. CO2 fracturing is adaptable to Jurassic shale. The breakdown pressure of the supercritical CO2 (SC-CO2) fracturing is low. Branch fractures form, and laminas activate during SC-CO2 fracturing due to its high diffusivity. Under high-temperature and high-pressure conditions, the aqueous solution formed by mixing CO2 with water can promote the formation of complex fractures. Compared with water-based fracturing fluid, the complexity of fractures and effective stimulation reservoir volume (ESRV) increased by 8.7% and 47.6%, respectively. There is a high correlation between SRV and ESRV, and the proportion of AE shear activity is also highly correlated with the complexity of fractures. The results are expected to provide better fracturing schemes and effectiveness for continental shale oil reservoirs.

Impact of water-rock interaction on natural fractures and shale permeabilities under the closure stress

During the shut-in treatment after hydraulic fracturing, the interaction between the water-based fracturing fluid and the reservoir rock can cause the swell of clay minerals. This can alter the stress condition of the rock, thus activating and expanding the natural fractures in the shale reservoir. However, it is currently controversial whether the effect of water-rock interaction on shale permeability is positive or negative under different closure stresses.To investigate this effect on natural fractures and rock permeabilities under closure stress, imbibition experiments are conducted, and the nuclear magnetic resonance (NMR) T2 spectrum is continually scanned to identify the fracture formation.Results show that the water-rock interaction can activate and expand the natural fractures, resulting in increases of 20.0%–61.6% in rock permeability during the spontaneous imbibition without closure stress; as the percentage of clay minerals increases in shale samples, the degree of rock permeability enhancement also increases. Meanwhile, during the forced imbibition without closure stress (i.e., centrifuge), increases of 1.14–46,912 times in rock permeability are observed, indicating that higher imbibition pressure (or pore pressure) results in a greater degree of rock permeability enhancement. However, when the closure stress exists, the increase of shale permeability during the forced imbibition is only 8.3%–11.5%, even though the activation and expansion of natural fractures are observed; this indicates that the closure stress can hinder the activation and expansion of natural fractures, thus hinders the enhancement of shale permeability by the water-rock interaction.Experimental results of this study indicate the stress condition can significantly affect the impact of water-rock interaction on natural fractures and shale permeability; therefore, operators should consider this effect when designing the shut-in time after hydraulic fracturing to maximize the oil recovery rate.

The Carrying Behavior of Water-Based Fracturing Fluid in Shale Reservoir Fractures and Molecular Dynamics of Sand-Carrying Mechanism

Water-based fracturing fluid has recently garnered increasing attention as an alternative oilfield working fluid for propagating reservoir fractures and transporting sand. However, the low temperature resistance and stability of water-based fracturing fluid is a significant limitation, restricting the fracture propagation and gravel transport. To effectively ameliorate the temperature resistance and sand-carrying capacity, a modified cross-linker with properties adaptable to varying reservoir conditions and functional groups was synthesized and chemically characterized. Meanwhile, a multifunctional collaborative progressive evaluation device was developed to investigate the rheology and sand-carrying capacity of fracturing fluid. Utilizing molecular dynamics simulations, the thickening mechanism of the modified cross-linker and the sand-carrying mechanism of the fracturing fluid were elucidated. Results indicate that the designed cross-linker provided a high viscosity stability of 130 mPa·s and an excellent sand-carrying capacity of 15 cm2 at 0.3 wt% cross-linker content. Additionally, increasing reservoir pressure exhibited enhanced thickening and sand-carrying capacities. However, a significant inverse relationship was observed between reservoir temperature and sand-carrying capacity, attributed to changes in the drag coefficient and thickener adsorption. These results verified the effectiveness of the cross-linker in enhancing fluid viscosity and sand-carrying capacity as a modified cross-linker for water-based fracturing fluid.

Reservoir Damage Induced by Water-Based Fracturing Fluids in Tight Reservoirs: A Review of Formation Mechanisms and Treatment Methods

Reservoir Damage Induced by Water-Based Fracturing Fluids in Tight Reservoirs: A Review of Formation Mechanisms and Treatment Methods

Quantitative characterization of the crosslinking degree of hydroxypropyl guar gum fracturing fluid by low-field NMR

As a widely used water-based fracturing fluid, the performance of hydroxypropyl guar gum fracturing fluid is closely related to the degree of crosslinking, the quantitative characterization of which can reveal a detailed crosslinking mechanism and guide the preparation of fracturing fluid gels with an excellent performance. However, the commonly used high-temperature rheology method for evaluating the performance of fracturing fluids only qualitatively reflects the degree of crosslinking. In this study, low-field nuclear magnetic resonance (LF-NMR) was used to characterize the degree of crosslinking in guar gum fracturing fluid gels. The spin-spin relaxation time of the H proton in guar gum was molecularly analyzed using LF-NMR. The viscoelastic properties met the requirements when the crosslinking degree of the gel was 88–94 %. The transformation of the linear structure into a membrane structure during the crosslinking process of the guar gum fracturing fluid was confirmed by freeze-drying and scanning electron microscopy (SEM) from a microscopic perspective. The changing trend of the microstructure and viscoelastic properties of the fracturing fluid gel under different crosslinker dosages was consistent with changes in the degree of crosslinking. The LF-NMR test process is non-destructive to the gel structure, and the test results demonstrate good accuracy and repeatability.

Mechanical degradation of Longmaxi shale exposed to water-based fluids and supercritical carbon dioxide

Mechanical alterations in shale formations due to exposure to water-based fracturing fluids and supercritical carbon dioxide (ScCO2) significantly affect the performance of shale gas exploration and CO2 geo-sequestration. In this study, a hydrothermal (HT) reaction system was set up to treat Longmaxi shale samples of varying mineralogies (carbonate-, clay-, and quartz-rich) with different fluids, i.e. deionized (DI) water, 2% potassium chloride (KCl) solution, and ScCO2 under HT conditions expected in shale formation. Statistical micro-indentation was conducted to characterize the mechanical property alterations caused by the shale-fluid interactions. An in situ morphological and mineralogical identification technique that combines scanning electron microscopy (SEM) and backscattered electron (BSE) imaging with energy-dispersive X-ray spectroscopy (EDS) was used to analyze the microstructural and mineralogical changes of the treated shale samples. Results show no apparent changes in the Young’s modulus, E, and hardness, H, after treatment with DI water under room temperature (20 °C) and atmospheric pressure for 7 d. In contrast, E and H were decreased by 31.2% and 37.5% at elevated temperature (80 °C) and pressure (8 MPa), respectively. The addition of 2% KCl into DI water mitigated degradation of the mechanical properties. Quartz-rich shale specimens are the least sensitive to the water-based fracturing fluids, followed by the clay-rich and carbonate-rich shale formations. Based on in situ morphological and mineralogical identification, the primary factors for the mechanical degradation induced by water-based fluids include carbonate dissolution, clay swelling, and pyrite oxidation. Slight increases in the measured E and H and compression of porous clay aggregates were observed after treatment with ScCO2. The major factor contributing to the mechanical changes resulting from the exposure to scCO2 appears to be the competition between swelling caused by adsorption and compression of shale matrix.

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

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

Further Investigation of CO2 Quasi-Dry Fracturing in Shale Reservoirs—An Experimental Study

The physical properties of shale reservoirs are typically poor, necessitating the use of fracturing technology for effective development. However, the high clay content prevalent in shale formations poses significant challenges for conventional hydraulic fracturing methods. To address this issue, CO2-based fracturing fluid has been proposed as an alternative to mitigate the damage caused by water-based fracturing fluids. In this paper, the applicability of quasi-dry CO2 fracturing in shale reservoirs is examined from three key perspectives: the viscosity of CO2 fracturing fluid, the fracture characteristics induced by the CO2 fracture fluid, and the potential reservoir damage caused by the fracturing fluid. Firstly, the viscosity of CO2 fracturing fluid was determined by a rheological experiment. Rheological tests revealed that the viscosity of CO2 fracturing fluid was significantly influenced by the water–carbon ratio. Specifically, when the water–carbon ratio was 30:70, the maximum viscosity observed could reach 104 mPa·s. Moreover, increasing reservoir temperature resulted in decreased fracturing fluid viscosity, with a 40 °C temperature rise causing a 20% viscosity reduction. Secondly, matrix permeability tests were conducted to investigate permeability alteration during CO2 fracturing fluid invasion. Due to the weak acidity of CO2-based fracturing fluid, the permeability reduction induced by clay hydration was inhibited, and an increase in permeability was observed after a 3-day duration. However, the matrix permeability tends to decrease as the interaction time is prolonged, which means prolonged soaking time can still cause formation damage. Finally, triaxial fracturing experiments facilitated by a three-axis servo pressure device were conducted. The fracture properties were characterized using computed tomography (CT), and 3D reconstruction of fractured samples was conducted based on the CT data. The results demonstrate that CO2 fracturing fluid effectively activates weak cementation surfaces in the rock, promoting the formation of larger and more complex fractures. Hence, CO2 quasi-dry fracturing technology emerges as a method with significant potential, capable of efficiently stimulating shale reservoirs, although a reasonable soaking time is necessary to maximize hydrocarbon production.

Synergistic Effect of Carbon Nanotubes, Zinc, and Copper Oxides on Rheological Properties of Fracturing Fluid: A Comparative Study

Nanomaterials play a beneficial role in enhancing the rheological behavior of fracturing (frac) fluid by reacting with intermolecular structures. The inclusion of these materials into the fluid improves its stability, increases the viscosity of polymers, and enhances its resistance to high temperature and pressure. In this investigation, multi-walled carbon nanotubes (CNTs), nano-zinc oxides (N-ZnO), and nano-copper oxides (N-CuO) have been utilized to ameliorate the rheological properties of water-based fracturing fluid. Different concentrations of these aforementioned nanomaterials were prepared to determine their effects on the rheological behavior of the fluid. The results revealed that the size of nanoparticles ranged from 10 to 500 nm, 300 nm, and 295 nm for CNTs, N-ZnO, and N-CuO, respectively. Moreover, employing CNTs exhibited a resistance of 550 cp at 25 °C and reached 360 cp at 50 °C with a CNT concentration of 0.5 g/L. In contrast, N-CuO and N-ZnO showed a resistance of 206 cp at 25 °C and significantly decreased to 17 cp and 16 cp with higher concentrations of 10 g/L and 1 g/L, respectively. Based on these findings, this study recommends utilizing CNTs to enhance fracking fluid’s chemical and physical properties, which need to be highly viscous and stable under reservoir conditions.

Promotion of CO2 fracturing for CCUS—the technical gap between theory and practice

CO2, used as an environmentally friendly fracturing fluid, has encountered a bottleneck in development in recent years. Despite great efforts in research work, limited progress has been made in field applications. In this study, an extensive literature review of research work and field cases was performed to summarize the technical issues and challenges of CO2 fracturing. The key issues of CO2 fracturing were analyzed to reveal the gap between fundamental research and field operations. The effects of CO2 properties on fracture creation and proppant transport were synthetically analyzed to extract new common research orientations, with the aim of improving the efficiency of CO2 injection. The hydraulic parameters of CO2 fracturing were compared with those of water-based fracturing fluids, which revealed a theory-practice gap. By studying the developing trends and successful experiences of conventional fluids, new strategies for CO2 fracturing were proposed. We identified that the major theory-practice gap in CO2 fracturing exists in pump rate and operation scale. Consequently, the friction reducer, effects of flow loss (due to leak-off) and distribution (within fracture networks), and shear viscosity of thickened CO2 are key factors in improving both fracture propagation and proppant transport. By increasing the scale of injected CO2, the CO2 fracturing technique can be enhanced, making it an essential option for carbon capture, utilization, and storage (CCUS) to reduce carbon emissions and mitigate climate change.

Study of a small molecule gel fracturing fluid and its in situ conversion into an efficient oil displacement agent

Viscoelastic surfactants (VESs) are critical components of water-based fracturing fluids.

Low-temperature gel breaking fracturing fluid for marine hydrate reservoir fracturing and its effect on phase equilibrium of methane hydrates

Hydraulic fracturing has been proven useful for improving the gas production efficiency of low-permeability hydrate reservoirs. However, no specific fracturing fluid system exists for marine hydrate reservoirs. Applying conventional water-based fracturing fluids in low-temperature (<293.2 K) marine hydrate reservoirs can lead to difficulties in gel-breaking and hydrate instability caused by external additives. In this study, we developed two water-based fracturing fluid systems that exhibited good gel-breaking performance at low temperatures (278.2–288.2 K), one comprising ammonium persulfate (APS), ferrous sulfate (FeSO4), and citric acid (CA), the other APS and triethanolamine (TEA). In addition, we investigated the influence of crosslinking and gel-breaking reactions of the fracturing fluids on the methane hydrate phase equilibrium. The breaking time of the APS-FeSO4-CA system at 278.2K, 283.2K, and 288.2K was 30 min, 75 min, and 120 min respectively. On the other hand, the APS-TEA system accomplished the same task in 3 h, 6 h, and 10 h respectively. Furthermore, methane hydrate phase-equilibrium data showed that the fracturing fluid's three states, base fluid (BF), fracturing fluid gel (FFG), and gel-breaking liquid (GBL), all exerted an inhibitory effect on the phase equilibrium, with the hydrate suppression temperature (ΔT) ranging from 0.4 to 1.0 K. The differences in their inhibitory effect were primarily related to the micromorphology of the hydroxypropyl guar gum (HPG) molecules and the number of active hydroxyl (-OH) groups in the solution. Cryo-scanning electron microscopy (SEM) measurements revealed that the micromorphology of HPG in BF, FFG, and GBL transformed from regular ribbon-like structures to 3-D network structures and then to hole-containing, short ribbon-like structures. FFG formed a regular 3-D network structure after adding crosslinking agents to the BF. The ΔT values reversed from FFG < BF to FFG > BF when the HPG concentration increased from 0.3 wt% to 0.5 wt%, possibly due to the difference in the HPG molecules' water adsorption capacity before and after crosslinking. The broken HPG molecules with OH− groups in the solution were transformed into residues after gel-breaking, decreasing the GBL's inhibitory effect. Therefore, our results indicated that micromorphology variations could cause differences in the HPG molecules' water adsorption capacity, ultimately leading to ΔT differences. Based on our findings, the gel-breaking fracturing fluid systems we developed demonstrated potential for optimizing hydraulic fracturing in marine hydrate reservoirs.

Fe3+-crosslinked alkyl phosphate ester as thickener for oil-based fracturing fluids

To reduce damage to the formation of water locking and water sensitivity causing poor fracturing effect during the fracturing by water-based fracturing fluid in shale oil and gas reservoirs, the oil-based fracturing fluid as anhydrous fracturing fluid were prepared with dialkyl phosphate (PO(OH)(OR)(OR’)) as gelling agent, complexed iron ion solution as activating agent, n-hexane or kerosene as base fluid. The dialkyl phosphate was synthesized by two-step processes. In the first step, the optimal reaction conditions for preparing monoalkyl phosphate intermediate were the reaction time 5 h, reaction temperature 85 °C, molar ratio of triethyl phosphate to phosphorus pentoxide 3.4:1. In the second step, the optimal synthesis conditions for preparing dialkyl phosphate esters were the reaction time 4 h, reaction temperature 80 °C, molar ratio of the intermediate monoalkyl phosphate esters to the mixed alcohol 1:1.4. Complexed iron ion solution as activating agent was prepared by a consisting of 30 wt% trisodiun citrate, 10 wt% ethanediol, 30 wt% ferric sulfate (Fe2(SO4)3) and 30 wt% deionized water. The effects of gelling agent, activating agent and based fluid on oil-based fracturing fluid performance were examined. The experiments showed that with the increase of gelling agent dosage, the gelation time was significantly shortened and the viscosity gradually increased. When the amounts of gelling agent and activating agent were 2.5 wt% and 4 wt%, respectively, the gelling time and the viscosity of fracturing fluid was up to 166 s and 450 cP. The viscosities of the fracturing fluid were always greater than 100 cP after it was sheared by shear rate of 170 s−1 for 1 h at 80 °C, indicating that the fracturing fluid have good shearing resistance and temperature resistance. The viscosity of the fracture fluid with n-hexane as based fluid was 1.32 cP at 70 °C when the sodium acetate as broken gent was 0.40 wt%, thus the broken gelation effect was remarkable. And the core damage rate of prepared oil-based fracturing fluid was also much lower than that of the common water-based fracturing fluids.

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.

Preparation and properties evaluation of novel silica gel-based fracturing fluid with temperature tolerance and salt resistance for geoenergy development

Various polymers are the most widely used product to provide rheology for water-based fracturing fluid, however, they have weaknesses in terms of temperature resistance and salt resistance. The change from organic-based to inorganic thickeners may be a meaningful attempt. Inorganic silica gel is a potentially alternative viscosifier with high temperature resistance, excellent proppant carrying capacity, and can even be used to prepare fracturing fluids with high salinity of produced water. In this paper, the silica gel viscosifier was firstly prepared using sol–gel method. Then, the gelation time under different influencing factors and rheological properties of the silica gel viscosifier were studied in detail. Subsequently, the silica gel-based fracturing fluid was prepared by adding the desired amount of drag reducer to the silica sol solution, and the properties of novel fracturing fluid were systematically evaluated with regard to the temperature and shearing resistance, drag reduction, and static proppant suspension. The potential mechanism of gelation process by syneresis of silica gel was revealed at last. Results showed that the microstructure of silica gel is synthetic, amorphous and consists of a three-dimensional network of SiO2 particles. The effect of SiO2 concentration on the gelation time is more pronounced than other factors such as temperature and pH level. In addition, the silica gel viscosifier exhibits strong salt resistance, whether monovalent ions (Na+, K+) or divalent ions (Ca2+, Mg2+), and the gelation time decreased significantly with the increase of salt concentration. The shear viscosity of the silica gel viscosifier increased with an increase of SiO2 concentration, showing shear thinning behavior as well. Meanwhile, the silica gel-based fracturing fluid prepared by adding drag reducer into silica sol solution also presented excellent thermal stability and shear resistance, drag reduction and proppant suspension performances. The retained viscosity can be maintained above 50 mPa·s after shearing at 180 °C for 60 mins; the drag reduction rate shows a declining trend at high displacement due to the gelation process; the settling rate of 40/70 mesh sand proppant with 35 % sand ratio is less than 30 % after standing at 90 °C for 4 h. In addition, the gelation process is essentially the formation of Si-O-Si linkage by dehydration between SiO2 particles, which is gradually extended at both ends and sides of the chain, and eventually forms a rigid, highly porous, entangled network. Findings found in this study provide a research basis for the popularization and application of silica gel-based fracturing fluid.

Permeability damage and hydrate dissociation barrier caused by invaded fracturing fluid during hydrate reservoir stimulation

Hydraulic fracturing is a promising stimulation technology for enhancing the gas productivity and energy efficiency of low-permeability hydrate reservoirs. Presently, most studies focus on the fracturing feasibility of hydrate-bearing sediments and recovery efficiency after fracturing. Although the fracturing fluid inevitably invades the hydrate reservoirs during fracturing, the effects of invaded fracturing fluid on sediment permeability and hydrate dissociation have not been investigated yet. In this study, the invasion of water-based fracturing fluid into hydrate-bearing sediments was experimentally studied to clarify the dynamic characteristics of the fracturing fluid invasion, including its effects on sediment permeability and hydrate dissociation. The results revealed that the fracturing fluid loss rate was initially high but abruptly became extremely small, potentially because of the filter cake deposition on the fracture surface and the secondary hydrate formation in the invaded zone. However, the invaded fracturing fluid increased the dissociated gas flow resistance and inhibited the hydrate dissociation and gas production that yielded a two-stage gas production process, including slow hydrate dissociation in the invaded zone followed by relatively fast hydrate dissociation in the uninvaded zone. Furthermore, the degree of permeability damage in the invaded zone gradually decreased with the increasing invasion distance that was caused by the variations in the microscopic filtrate–sediment reactions. Interestingly, the water saturation measured by NMR gradually decreased from about 90% to 60% (initial water saturation) along the invasion distance. This phenomenon indicates that water sensitivity and water lock acted as the primary sources of permeability damage to the clayey–silty sediments after fracturing fluid invasion, suggesting that inhibiting clay swelling and increasing the flowback rate of the invaded fluid were essential for reducing permeability damage. Noted that using the fracturing fluid with breaker and KCl exhibited the lowest degree (25%) and shortest distance (<15 cm) of sediment permeability damage. The present results are vital for applying hydraulic fracturing in the field tests of hydrate reservoirs to optimize the fracturing fluid and improve the fracturing stimulation effect.

Effect of roughness characteristics of hydraulic fractures on the proppant transport using supercritical CO2

The morphology of rough fractures significantly affects proppant transport in hydraulic fractures. The fracture roughness is even more critical in proppant transport using supercritical CO2 since supercritical CO2 produces rougher fractures than other conventional fracturing fluids. In this study, we used roughness characteristics of the fractures generated by using supercritical CO2 and real rock samples determined by direct measurement together with coupled CFD (Computational Fluid Dynamics)-DEM (Discrete Element Method) to investigate the effects of different roughness characterization parameters on the efficiency of proppant transport using supercritical CO2. Laboratory experimental data of proppant transport in supercritical CO2 within the fracture were used to verify the reliability of the model. The results show that as the ratio of proppant diameter to average width of rough fracture increases, the proppant is more likely to bridge or even form sand blockage when transported in rough fractures, while better transport can be obtained when the ratio is less than 0.4. The main form of proppant particle transport within the rough fractures are the scouring and throwing of particles as the slurry flows through the bridging locations. In addition, the variation of root mean square (RMS) of asperity height values and fractal dimensions can have dissimilar effects on the proppant transport in rough fractures. The distance of proppant transport within the fracture decreases with the increasing fractal dimension, but increasing the RMS of asperity height value will yield proppant transport to longer distance. The proppant is transported farther in rough fractures than in planar fractures, but also, the required pumping pressure is higher in rough fractures, and the pumping pressure is positively related to the fracture roughness. Since using supercritical CO2 for fracturing produces rougher fractures than that of water-based fracturing fluids, higher pump power is required for efficient proppant transport using supercritical CO2, otherwise sand plug may occur. The results of this study lead to a better insight into the proppant transport behavior using supercritical CO2 in rough rock fractures and, therefore, would be useful for the improved field design of waterless fracturing operations conducted by using supercritical CO2.

A Study on Fracture Propagation Law of CO2 Composite Fracturing in Shale Reservoir

Background: In recent years, CO2 composite fracturing technology has been widely used in unconventional reservoirs. Compared to conventional hydraulic fracturing, CO2 fracturing can create complex fractures, replenish formation energy and reduce oil flow resistance. For shale oil reservoirs with natural fractures, CO2 composite fracturing can not only give full play to the advantages of complex fracture networks created by CO2 but also make use of water-based fracturing fluid to create long fractures with high conductivity. Methods: Based on fracture fluid flow, stress interference, natural fracture description, and CO2 phase change equation, a CO2 composite fracture propagation model was established in this paper to simulate the effects of fracturing fluid type, CO2 proportion, construction scale, natural fracture development, fracturing fluid injection rate and other factors on the propagation morphology of CO2 injection fracture network in shale oil reservoirs. Results: The results show that the water-based fracturing fluid is beneficial to the formation of long main fractures, but the overall complexity of the fracture network and the effective stimulated volume of the fracture network are significantly lower than that of CO2 fracturing. The application of the appropriate proportion of CO2 composite fracturing fluid can give full play to the comprehensive advantages of CO2 and water-based fracturing fluid and realize the full stimulation of the reservoir. CO2 fracturing in shale oil reservoirs with low principal stress difference and high natural fracture development extent can communicate natural fractures in a large range and form a complex fracture network. For shale oil reservoirs with natural fractures, a high fracturing fluid injection rate can significantly improve the complexity of the fracture network. Conclusion: The CO2 composite fracturing technology is applied to horizontal wells in X shale reservoir, and the production after fracturing is significantly higher than that of offset wells, which can be applied in the same type of reservoir and has broad application prospects.

Effect of nano-SiO2 on the flowback-flooding integrated performance of water-based fracturing fluids

Nanomaterials have the characteristics of reducing water molecular clusters and improving surface properties. Therefore, it can effectively enhance the oil displacement (or imbibition) effect while developing low permeability and unconventional reservoirs. Volume fracturing based on horizontal wells has become the primary technology in developing unconventional reservoirs. In this paper, we investigated the effect of nano-SiO2 on the rheology, flowback, and subsequent oil displacement performance of fracturing fluid. Results showed that nano-SiO2 had little impact on the swelling and dispersion properties of the two thickeners (i.e., guar gum and emulsion polymer). The apparent viscosity of these two thickener solutions decreased by less than 15% after aging for 24 h. Nevertheless, nano-SiO2 particularly influenced the rheological properties of guar gum based fracturing fluid. That is to say, the increase in the amount of nano-SiO2 gradually reduced the temperature and shear resistance of the fracturing fluid. When the concentration of nano-SiO2 reached 5%, the temperature and shear resistance of fracturing fluid decreased by 40%–60% in the temperature range of 80 to 100 °C. However, nano-SiO2 had little effect on the fracturing fluid's breaking time and the solution's viscosity after breaking, and the surface tension of the solution slightly increased after breaking. The fracturing fluid added with nano-SiO2 improved the performance of inhibiting clay swelling after the gel was broken. In addition, the solution after gel breaking had an excellent demulsification effect on emulsified crude oil when the concentration of nano-SiO2 was less than 0.2%. While the concentration of nano-SiO2 was greater than 0.5%, the increase in nano-SiO2 concentration gradually strengthened the emulsification between crude oil and gel-breaking fluid. Nano-SiO2 also had an excellent oil displacement effect, and it increased the recovery efficiency of primary water flooding by 9.99–13.34 percentage points. IThe field test of nanoparticle flooding and fracturing integrated technology was carried out for two wells in the Mahu tight oil reservoir of Xinjiang Oilfield, NW China. The pilot tests of the two wells were very successful, and the cumulative oil production on the 180th day after the fracturing operation was 20–50% higher than that of the comparison well.

Cyclic Liquid Nitrogen Fracturing Performance on Coal with Various Coal Ranks: Laboratory Investigation and Mechanism Analysis

Summary Hydraulic fracturing is one of the important stimulation methods to enhance the productivity of coalbed methane (CBM) wells. However, the commonly used water-based fracturing fluids can bring some bottlenecks such as large amount of water consumption, clay-mineral swelling, and poor fracturing performance on ductile coals. Cyclic liquid nitrogen (LN2) fracturing, as a novel nonaqueous stimulation method, has the potential to solve the above problems. In cyclic LN2 fracturing, supercooling LN2 is injected in a cyclic manner [i.e., alternating high injection rate (or pressure) and low injection rate (or pressure)]. Coals will be subjected to cyclic freeze-thaw, stress oscillation, and fatigue damage, which is expected to improve the stimulated reservoir volume. First, laboratory cyclic LN2 fracturing tests were conducted on coal samples with various coal ranks to investigate the fracture initiation/propagation behavior and fracture network patterns. Cyclic water fracturing tests were also conducted as comparisons. Then, computed tomography (CT) scanning and geomechanical/petrophysical properties tests before and after LN2 fracturing were performed to assist in understanding the cyclic LN2 fracturing mechanisms and implications. Finally, to solve the field application concerns, we investigated the possible fracture geometries at the field scale, temperature distribution of LN2 along the wellbore during injection, and the economic feasibility. The key factors affecting the temperature distribution during LN2 transportation along the wellbore were clarified for the first time. The results indicate that cyclic LN2 fracturing shows the potential to decrease the breakdown pressure and produce complex fracture networks. Different coal ranks have different responses to cyclic LN2 fracturing attributed to the variances in natural fracture development and geomechanical/petrophysical properties. Besides, increasing the cycle number is effective in enhancing the cyclic LN2 fracturing performance on coals with relatively higher geomechanical strengths and tighter rock mass. The suggested cycle numbers from low to high for different coal ranks are listed here: low-rank coal &amp;lt; high-rank coal &amp;lt; middle-rank coal. In field applications, gaseous nitrogen (N2) can be used as the annulus fluid to provide an effective insulation for heat transfer between the low-temperature LN2 and the surrounding environment. In addition, the net present value (NPV) analysis indicates that LN2 fracturing is an economically feasible stimulation method, which can exceed slickwater fracturing in some cases. The key findings are expected to provide preliminary insights into the potential field applications of cyclic LN2 fracturing in CBM or other unconventional oil/gas exploitation.