Water-based Fracturing Fluids Research Articles

Preparation and Performance Evaluation of a Self-Crosslinking Emulsion-Type Fracturing Fluid for Quasi-Dry CO2 Fracturing

Quasi-dry CO2 fracturing technology is a new CO2 fracturing technology that combines liquid CO2 fracturing (dry CO2 fracturing) and water-based fracturing. It uses a liquid CO2 system containing a small amount of water-based fracturing fluid to carry sand, and it is characterized by sand blending at normal pressure, convenient preparation, the integrated application of resistance reduction and sand carrying, and no dedicated closed sand blender requirement. We developed a self-crosslinking emulsion-type water-based fracturing fluid (ZJL-1), which contained ionic bonds, hydrogen bonds, van der Waals forces, and hydrophobic associations, for quasi-dry CO2 fracturing, and the comprehensive properties of the ZJL-1 fracturing fluid were evaluated. The results showed that the ZJL-1 fracturing fluid had obvious viscoelastic characteristics, a heat loss rate of less than 10% at 200 °C, a good thermal stability, sufficient rheology under high temperature and high shear conditions, and a good thermal stability. The resistance reduction rate reached 70%, which demonstrates a good resistance reduction performance. Compared with conventional guar fracturing fluid, ZJL-1 can carry more sand and has a lower core damage rate. The on-site use of quasi-dry fracturing showed that optimizing the mixing ratio of liquid CO2 fracturing fluid and ZJL-1 fracturing fluid effectively enhanced oil and gas recovery. This can be used to optimize quasi-dry fracturing and can be used as a reference.

The effect of adding tiny granules on the adsorption characteristics of granulated coal

ABSTRACT Water-based fracturing fluid is a key component in coal bed methane (CBM) extraction, which is a promising way forward for the green extraction of methane. The adsorption by coal is highly affected by tiny particles in the fracturing fluid. Aiming at exploring the effect of mixing non-adsorbent particles into coal on the adsorption, an atmospheric pressure granulated coal adsorption system with a flow meter was designed to perform tests. During the experiments, the effect of coal particle size, coal mass, and addition of tiny granules on adsorption was analyzed. The obtained results show that the addition of iron powder reduces the adsorption capacity and average adsorption rate of granular coal, and makes the adsorption speed peak earlier. It is found that the change in the adsorption amount has a weak positive correlation with the coal particle size, and the change of the average adsorption rate has a weak positive correlation with the size. However, in the absence of iron powder, the average adsorption rate is negatively correlated with the coal size, and the effect of the coal mass on the average adsorption rate and adsorption capacity is very weak. In large granular coal, the adsorption capacity is independent of size. Under the experimental conditions, strong adsorption occurred between 500 and 1750 s, and the adsorption kinetic process showed a slow-fast-slow “S”- curved distribution.

Corrosion inhibitor and chelating agent impact on foam stability for formation stimulation applications

Injection of foam into petroleum reservoirs has attracted special interest in the last years. Utilizing foam in well stimulation is promising as it consumes less water than water-based fracturing fluids. Nevertheless, the success of foam application mainly depends on its stability. Thus, it is essential to understand the role of gas type, water chemistry, and other additives such as acids (e.g., chelating agent) and corrosion inhibitors on the generation and stabilization of foam. Hence, a dynamic foam analyzer (DFA) and optical interfacial tensiometer were used to study foam stability under different conditions. Surfactant screening showed that Duomeen TTM and Armovis are superior foamers at low pH (3.5), and therefore were used in this study. The liquid phase typically contained high salinity water, 15 %wt. Chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA), and 1 %wt. surfactant with and without a corrosion inhibitor (CI). First, we investigated the effect of gas types on the stability of the foam. The results revealed that N2-foam is more stable compared to CO2-foam. Also, the results showed that the corrosion inhibitor reduced the foam stability for both N2-foam and CO2-foam. Three types of water were examined; distilled water (DI), produced water (PW), and seawater (SW) for foam stabilization. The water chemistry had little effect on the stability of TTM compared to its impact on Armovis. Finally, we found that GLDA addition to Armovis increased the stability of foam by four times compared to no GLDA addition. Moreover, the stability GLDA/Armovis system was six times higher with CO2 and more than 20 times higher with N2 as compared to TTM stability. The foamability, foam volume, bubble count, and foam structure were studied to determine the foam behavior at given conditions. This study provides a broad understanding of additives’ impact on stimulating foam stability.

Experimental comparisons of different cryogenic fracturing methods on coals

Hydraulic fracturing using water-based fracturing fluids is widely used in coalbed methane (CBM) reservoir development. However, the stimulation efficiency of conventional hydraulic fracturing in CBM reservoir is low. Liquid nitrogen (LN2) cryogenic fracturing is one possible method to improve the stimulation efficiency. To test the feasibility of the LN2 cryogenic fracturing, laboratory fracturing tests were conducted to investigate the performances of different LN2 cryogenic fracturing methods in this paper. The breakdown pressure and fracture morphology of water fracturing, LN2 direct fracturing, LN2 freeze fracturing, LN2 freeze-thaw fracturing and LN2 compound fracturing were compared. And the mechanisms of different cryogenic fracturing techniques are revealed. The results demonstrate that thermal damage caused by LN2 freezing is the main reason for the complicated fracture pattern in cryogenic fracturing. LN2 freeze-thaw fracturing has the lowest breakdown pressure and can create the most complex fractures among these cryogenic fracturing methods due to the huge thermal damage. LN2 freeze fracturing has the highest breakdown pressure. Because the thermal damage cracks and natural fractures in frozen rock are in freezing shrinkage, which activation are difficult. LN2 compound fracturing is the most potential technologies, which can produce more complex fracture networks than water fracturing and LN2 fracturing.

Experimental investigation of the mechanism of supercritical CO2 interaction with tight sandstone

One of the important technologies for combating global climate change is CCUS (Carbon Capture, Utilization, and Storage), which aims to address the issue of “greenhouse effect” generated by a significant amount of greenhouse gas emissions. Supercritical CO2, a new type of anhydrous fracturing fluid with broad application prospects in low-pressure tight sandstone gas reservoirs, has several advantages over traditional water-based fracturing fluids, including quick flowback, minimal damage to the reservoir, and the ability to realize in-situ storage of greenhouse gases. The tight sandstone cores from the Jinqiu Gas field in the Sichuan Basin were used in an experimental investigation on the interaction mechanism between supercritical CO2 and tight sandstone to examine the viability of supercritical CO2 fracturing with tight sandstone, and analysis of the samples’ post-reaction samples’ mineral composition, microstructure, mass change, and total salinity change. The interaction of tight sandstone with supercritical CO2 results in an increase in quartz content, a decrease in clay mineral content, the formation of new minerals, and partial mineral dissolution on the surface of the sample. Since the degree of mineral dissolution of sandstone samples increases with time, CO2 can be stored in tight sandstone as carbonate minerals. This study evaluates how supercritical CO2 interacts with tight sandstone and can offer a solid theoretical foundation and experimental evidence in favor of CO2in-situ storage in tight sandstone gas reservoir.

Optimization and performance evaluation of a novel anhydrous CO2 fracturing fluid

The conventional water-based fracturing fluids have such defects as large water consumption, serious environmental pollution and water-sensitive damage to reservoirs in the development of tight oil. In this study, a novel anhydrous CO2 fracturing fluid system was constructed with the compositions of 7 wt% polydimethylsiloxane (100 cs), 5 wt% ethanol and 88 wt% liquid CO2. The viscosity of the system could reach 6.52 mPa s, which was 37 times higher than that of pure liquid CO2 at −15 °C and 30 MPa. The pressure resistance, temperature resistance, anti-swelling property, filtration loss property, core damage property, corrosion property and wetting inversion property of anhydrous CO2 fracturing fluid were systematically evaluated by physical simulation experiments. The environmental scanning electron microscopy (ESEM) and mercury injection experiment were conducted. The viscosity retention rate of anhydrous CO2 fracturing fluid reaches 47.92% when the temperature increases by 50 °C. When the pressure increases by 25 MPa, the viscosity increases by 2.6 times. It ensures that the viscosity of anhydrous CO2 fracturing fluid is well retained after injection into the formation. In addition, the anti-swelling rate of anhydrous CO2 fracturing fluid reaches 90.91%. The filtration coefficient is reduced by 69.20%. For low permeability sandstone cores, the permeability damage rate is 18.80% and the porosity damage rate is 12.58%. After aging for 30 h, the permeability and porosity of core increased 39.23% and 5.52%, respectively. Meanwhile, the wettability of the core could be changed from hydrophilic to neutral, which reduced the flow resistance of the oil phase and improved tight oil recovery. Through this study, we hope to broaden the application of anhydrous CO2 fracturing fluids in tight oil development.

Influence of organoboron cross-linker and reservoir characteristics on filtration and reservoir residual of guar gum fracturing fluid in low-permeability shale gas reservoirs.

To effectively reduce the filtration rate of water-based fracturing fluid and promote the pressure holding effect of fracturing fluid in underground unconventional reservoirs, an efficient and clean organic-boron cross-linker was synthesized with boric acid and low alcohols. The results obtained that the synthesized organoboron cross-linker exhibits better fluid loss performance to water-based fracturing fluid than the commercially available cross-linker. This organoboron cross-linker allowed decreasing filtration coefficient more than 0.74 × 10-2 m3·min1/2 as a result of the network structure formed by the organoboron cross-linker and guar gum molecule. However, commercially available cross-linker exhibits a relatively large filtered mass of water more than 1.33 × 10-2 m3·min1/2 at the same condition. Meanwhile, the cross-linked guar gum fracturing fluid can significantly improve the fluid loss property with the increase of cross-linker content and pressure, and an increased fluid filtration gradually was revealed with increasing the reservoir temperature and current speed. Moreover, the damage of shale reservoir caused by the prepared boron cross-linker was only 11%, which was lower than 18% of the commercial boron cross-linker under the same conditions.

An experimental apparatus for supercritical CO2 fracturing of shale: System design and application tests

Supercritical CO2 (SC–CO2) would be a potential substitute for water-based fracturing fluid widely used in the present hydraulic fracturing of shale reservoirs. However, the field application of SC-CO2 fracturing is still in its infancy. Laboratory experiments are crucial for understanding the effects of various fracturing parameters and validating numerical simulations before conducting costly field trials. This paper first introduces the design of a self-developed experimental apparatus for fracturing cylindrical rock specimens and outlines the working principles of six functional modules. The entire experimental system is flexible because its functional modules can be used interchangeably. Subsequently, some key designs are emphasized. (1) A packer with the sealing of O and Y rings exhibits a good seal efficiency for a relatively small wellbore; moreover, this packer can be conveniently moved out from the fractured shale without damaging the specimen. (2) Downhole temperature measurement structure integrated into the packer can sensitively monitor the CO2 temperature variation at a high sampling rate during the entire SC-CO2 fracturing process. (3) The design of the triaxial core holder contributes to the realization of withstanding high axial-confining and fluid injection pressures and customized installation of acoustic emission (AE) sensors. Ultimately, some fracturing experiments with water and SC-CO2 as fracturing fluids and seepage tests with nitrogen (N2) under various test parameters are successfully conducted. The results indicate that, after the specimen fractures, the injection pressure would be approximately decreased to the confining pressure due to the confining chamber sealing design; there is a simultaneous sharp variation in the temperature at the bottom of the wellbore. SC-CO2 fracturing generates more fractures with greater bifurcation and higher tortuosity. The gas flow rate decreases with increasing confining pressure, whereas it increases significantly with increasing injection pressure. In general, these experimental results can validate the performance and feasibility of the self-developed experimental apparatus.

Foam Based Fracturing Fluid Characterization for an Optimized Application in HPHT Reservoir Conditions

Water-based fracturing fluids are among the most common fluid types used in hydraulic fracturing operations. However, these fluids tend to cause damage in water-sensitive formations. Foam comprises a small amount of base fluid, and compressible gas such as carbon dioxide and nitrogen has emerged as a more ecologically friendly option to fracture such formations. Foam is an attractive option since it has a low density and high viscosity. The applicability of foamed frac fluid is characterized by foam stability and rheology, encompassing the viscosity and proppant carrying ability. The foam quality, pressure and temperature affect the foam rheology. Generally, foam viscosity and stability increase with pressure but decrease when the temperature increases. Hence, it is essential to preserve foam stability in high pressure and high temperature (HPHT) reservoir conditions. The addition of nanoparticles could increase the thermal stability of the foam. This article provides the basis of foam-based fracturing fluid characterization for an optimal application in HPHT reservoir conditions. Then, focusing on improving thermal stability, it reviews the research progress on the use of nanoparticles as foam stabilizing agent. This paper also sheds light on the literature gaps that should be addressed by future research.

Applicability Assessment of Viscoelastic Surfactants and Synthetic Polymers as a Base of Hydraulic Fracturing Fluids

Hydraulic fracturing (HF) is currently the most widespread and effective method of oil production stimulation. The most commonly used fracturing fluid is crosslinked guar gels. However, when using these systems, problems such as clogging of the pore space, cracking, and proppant packing with the remains of the undestroyed polymer arise. Therefore, the efficiency of the hydraulic fracturing process decreases. In this work, compositions based on viscoelastic surfactants (VES) and synthetic polymers (SP) were considered as alternatives capable of minimizing these disadvantages. Most often, the possibility of using a composition as a fracturing fluid is evaluated using rotational viscometry. However, rotational viscometry is not capable of fully assessing the structural and mechanical properties of fracturing fluid. This leads to a reduced spread of systems based on VES and SP. This paper proposes an integrated approach to assessing the effectiveness of a water-based fracturing fluid. The proposed comprehensive approach includes an assessment of the main characteristics of water-based fracturing fluids, including an analysis of their structural and mechanical properties, which is based on a combination of rotational and oscillatory rheology and a comparative analysis of methods for studying the influence of fluids on the reservoir rock. The use of the developed approach to assess the technological properties of fracturing fluids makes it possible to demonstrate the potential applicability of new, unconventional fracturing fluids such as systems based on VES and SP.

Modeling study on supercritical CO2 fracturing applicability and capacity to stimulate reservoirs with different permeabilities

Hydraulic fracturing (HF) using water-based fluids is an effective approach for reservoir stimulation in the exploitation of unconventional resources. Recently, supercritical carbon dioxide (S–CO2) has been proposed as a prospective fracturing fluid in reservoir stimulation because it exhibits higher fracturing capacity compared with water-based fracturing fluid. However, S–CO2 appears to have a distinct drawback of intensifying leak-off when used in reservoirs with relatively high rock matrix permeability (RMP). In this work, a modeling study on water fracturing and S–CO2 fracturing (SCF) was implemented in reservoirs with varied RMPs to assess their applicability. In the modeling, the natural fracture system in the reservoir was considered through the discrete fracture network method for simulating different reservoirs. The lower viscosity and density of S–CO2 compared with those of water enable the easier fracturing of reservoir rocks and allow the generation of more complex fracture networks. However, the intensifying leak-off of S–CO2 due to fracture propagation can hamper the build-up of hydraulic pressure and affect fracture propagation, especially in reservoirs with relatively high RMP. The inflection of fracture length development during HF can also reflect the impact of fluid leak-off. Permeability determines the final fracture network of SCF, and the injection rate increase can offset the leak-off to a certain extent; however, the improvement in fracturing results becomes limited. The modeling results clearly demonstrate the importance of RMP, which can directly determine the applicability and capacity of SCF.

Experimental investigation on the high-pressure sand suspension and adsorption capacity of guar gum fracturing fluid in low-permeability shale reservoirs: factor analysis and mechanism disclosure.

Guar fracturing technology has been considered as a kind of popular EOR technology, but the weak static suspension capacity becomes a challenge due to the poor temperature resistance and stability of guar fracturing fluid. The main goal of this investigation is to explore the effect of different factors on the high-pressure static sand suspension of guar gum fracturing fluid by a synthetic efficient nano-ZrO2 cross-linker. In particular, a mechanism of static suspended sand of nano-ZrO2 cross-linker is analyzed by microscopic simulation. The adsorption performance of guar fracturing fluid on the shale surface is also studied for analyzing the environmental pollution and damage of guar gum fracturing fluid to shale reservoirs after cross-linking in this investigation. The results obtained that the inclusion of a small content of nano-ZrO2 cross-linker (0.4%) leads to an apparent increase of fracturing fluid viscosity and decrease in the falling quality of gravel (104mPa·s and 0.3g) compared to the classical cross-linker (63mPa·s and 3.5g). The lower adsorption capacity of guar fracturing fluid containing nano-ZrO2 cross-linker on the shale surface means that it has a weaker pollution ability to the shale reservoir than the commercially available cross-linker. Meanwhile, the grid structure density formed by nano-cross-linker and guar gum is considered to be the key factor to significantly change the suspended sand capacity. The investigation of nano-cross-linker cannot only provide necessary theoretical technology and data support for the stability of water-based fracturing fluid, efficient sand carrying, and the development of water-based fracturing technology, but also effectively protect the underground shale reservoir.

Perspective Review of Polymers as Additives in Water-Based Fracturing Fluids.

After successful implementation for more than 6 decades by the oil and gas industry, hydraulic fracturing remains the pioneer well stimulation method to date. Polymers are one of the additives in fracturing fluids that play a significant role. Polymers are used as friction reducers and viscosifiers to provide a transport medium for proppants in fracturing fluids. There are many polymer-based fracturing fluid systems, but choosing the most appropriate type and system depends on the type of application and a wide range of parameters. Currently, there is no complete review study that gives a reference and hence a perspective for researchers on the use of polymers in hydraulic fracturing. This paper summarizes the published literature on polymers used in fracturing fluids and discusses the current research issues, efforts, and trends in the field, aiming to provide an overview of the polymer applications in slick-water and cross-linked gel systems. The mechanism and limitation of polymer use such as polymer degradation, fracture conductivity reduction, and polymer adsorption are also reviewed in this paper. The reviewed literature suggested that polymers are important additives in fracturing fluids not only to provide adequate transportation of proppants but also to determine the width of the fracture whereby higher viscosities yield wider fractures. The development of synthetic polymers and associative polymers in fracturing fluids showed a remarkable potential to improve the stability of fracturing fluids in unconventional reservoirs under reservoir conditions, which makes it an interesting topic for future studies.

High-Temperature-Resistant, Clean, and Environmental-Friendly Fracturing Fluid System and Performance Evaluation of Tight Sandstone.

Hydraulic fracturing, as an oil-water well stimulation and injection technology, is particularly important in the production and stimulation of low-permeability oil and gas fields, and the performance of the fracturing fluid directly affects the success of the fracturing operation. Compared with traditional water-based fracturing fluids, clean fracturing fluids have the advantages of strong sand-carrying ability and easy gel breaking with no residue. Aiming at the problem of poor temperature resistance and shear resistance of the clean fracturing fluid, based on previous research, this paper selects a high-temperature-resistant clean fracturing fluid system and evaluates the performance of the system. The research results show that the system has better rheological properties, better sand-carrying performance, shorter gel-breaking time, and less damage to the reservoir.

Effects of imidazolium- and ammonium-based ionic liquids on clay swelling: experimental and simulation approach

Water-based fracturing fluids without an inhibitor promote clay swelling, which eventually creates wellbore instability. Several ionic liquids (ILs) have been studied as swelling inhibitors in recent years. The cations of the ILs are crucial to the inhibitory mechanisms that take place during hydraulic fracturing. Individual studies were carried out on several ILs with various cations, with the most frequently found being ammonium and imidazolium cations. As a result, the goal of this study is to compare these two cations to find an effective swelling inhibitor. A comparison and evaluation of the clay swelling inhibitory properties of tetramethylammonium chloride (TMACl) and 1-ethyl-3-methylimidazolium chloride (EMIMCl) were conducted in this work. Their results were also compared to a conventional inhibitor, potassium chloride (KCl), to see which performed better. The linear swelling test and the rheology test were used to determine the inhibitory performance of these compounds. Zeta potential measurements, Fourier-transform infrared spectroscopy, and contact angle measurements were carried out to experimentally explain the inhibitory mechanisms. In addition, the COSMO-RS simulation was conducted to explain the inhibitory processes and provide support for the experimental findings. The findings of the linear swelling test revealed that the swelling was reduced by 23.40% and 15.66%, respectively, after the application of TMACl and EMIMCl. The adsorption of ILs on the negatively charged clay surfaces, neutralizing the charges, as well as the lowering of the surface hydrophilicity, aided in the improvement of the swelling inhibition performance.

Modeling Hydraulic Fracturing Using Natural Gas Foam as Fracturing Fluids

Stranded gas emission from the field production because of the limitations in the pipeline infrastructure has become one of the major contributors to the greenhouse effects. How to handle the stranded gas is a troublesome problem under the background of global “net-zero” emission efforts. On the other hand, the cost of water for hydraulic fracturing is high and water is not accessible in some areas. The idea of using stranded gas in replace of the water-based fracturing fluid can reduce the gas emission and the cost. This paper presents some novel numerical studies on the feasibility of using stranded natural gas as fracturing fluids. Differences in the fracture creating, proppant placement, and oil/gas/water flowback are compared between natural gas fracturing fluids and water-based fracturing fluids. A fully integrated equation of state compositional hydraulic fracturing and reservoir simulator is used in this paper. Public datasets for the Permian Basin rock and fluid properties and natural gas foam properties are collected to set up simulation cases. The reservoir hydrocarbon fluid and natural gas fracturing fluids phase behavior is modeled using the Peng-Robinson equation of state. The evolving of created fracture geometry, conductivity and flowback performance during the lifecycle of the well (injection, shut-in, and production) are analyzed for the gas and water fracturing fluids. Simulation results show that natural gas and foam fracturing fluids are better than water-based fracturing fluids in terms of lower breakdown pressure, lower water leakoff into the reservoir, and higher cluster efficiency. NG foams tend to create better propped fractures with shorter length and larger width, because of their high viscosity. NG foam is also found to create better stimulated rock volume (SRV) permeability, better fracturing fluid flowback with a large water usage reduction, and high natural gas consumption. The simulation results presented in this paper are helpful to the operators in reducing natural gas emission while reducing the cost of hydraulic fracturing operation.

Comparative Studies on Hydraulic Fracturing Fluids for High-Temperature and High-Salt Oil Reservoirs: Synthetic Polymer versus Guar Gum.

The increasing energy demand has prompted engineers to explore deeper wells where rich oil and gas reserves exist. However, the high-temperature and high-salt conditions have impeded the further application of traditional water-based fracturing fluids in such reservoirs. Therefore, it is urgent to develop fracturing fluids that are suitable for such geographic characteristics. In this study, for the first time, a novel synthetic polymer, poly-(acrylamide-co-acrylic acid-co-2-acrylamido-2-methyl-1-propanesulfonic acid) (P3A), was investigated as a rheological modifier for water-based fracturing fluids in high-temperature and high-salt conditions and compared with a guar gum system. Results showed that the apparent viscosity increased with increasing P3A and guar gum concentrations, and the thickening ability of P3A was much better than that of guar gum. Despite the better shear and temperature resistance and proppant suspension ability of guar gum fluids in high-temperature and saturated salt conditions, plentiful solid residues after gel-breaking have prevented their progress in the petroleum industry. P3A fluids have no residues, but the unsatisfying proppant suspension capability and high dosage encourage us to promote their rheological performance via interaction with an organic zirconium crosslinker. Infrared spectroscopy and scanning electron microscopy were applied to guarantee the successful reaction of P3A with the crosslinker. The subsequent investigation indicated that the transformed fracturing fluid exhibited remarkably improved thickening capability and satisfying rheological performance in terms of temperature and shear resistance and proppant-carrying ability as well as gel-breaking results in a high-temperature and saturated salt environment. All of the above results suggest the potential application of crosslinked P3A in hydraulic fracturing for the reservoirs with hostile conditions, and this article also provides a new orientation for synthetic polymers utilized in the oil and gas industry.

A new method for plugging the dominant seepage channel after polymer flooding and its mechanism: Fracturing–seepage–plugging

AbstractAfter polymer flooding, a low-resistant dominant seepage channel forms at the bottom of the high-permeability reservoir, which is extremely disadvantageous for further enhanced oil recovery. In this study, we proposed a new method to plug the dominant seepage channel after polymer flooding, through fracturing–seepage–plugging using a solid-free plugging agent, which can achieve deeper and further regional plugging. This method involved dissolving the crosslinking agent and stabilizer in the water-based fracturing fluid (hereinafter referred to as the fracturing plugging agent) and transporting it to the target reservoir through hydraulic fractures. The fracturing plugging agent percolated into the deep part of the reservoir under the action of fracture closure pressure and gelled with the residual polymer in the formation to achieve deep regional plugging of the advantageous channel. To study the percolation law of fracturing plugging agent in the dominant channel, high-pressure displacement experiments were conducted using natural cores under different permeability and concentration conditions of the fracturing plugging agent. The results showed that the percolation rate of the fracturing plugging agent was almost linearly related to reservoir permeability. Due to the formation of micro-fractures and crosslinking reactions, the percolation rate first increased and then decreased to a stable state. After a certain period, the pores were blocked, resulting in a sharp decrease in the percolation rate and then decayed. In addition, the higher the concentration of fracturing plugging agent, the better the core plugging performance. Moreover, when the concentration of fracturing plugging agent injected into the core exceeded 3,000 mg/L, the core permeability increased, and the breakthrough pressure evidently increased three to four times. On the basis of this, rheometer tests, scanning electron microscopy (SEM) observations, and mercury intrusion tests were performed to evaluate gelation performance, shear effect, and pore retention morphology of the crosslinking system made by mixing the injected plugging agent and residual polymer in the reservoir. The results showed that the shear action could reduce the gelling property, and the concentration of fracturing plugging agent should be >3,000 mg/L to meet the requirements of gelling. Furthermore, the viscosity of the crosslinking system reached the peak value at approximately 72 h, forming a network space structure of layered superposition, thereby increasing viscosity by 40–50 times. Finally, SEM images revealed that after the fracture plugging agent was injected into the core, the micelles were mostly concentrated in the front and middle sections. The average pore radius of the core decreased by 8.620 μm, and the average porosity decreased by 54.85%.

Surfactants are Ineffective for Reducing Imbibition of Water-Based Fracturing Fluids in Deep Gas Reservoirs

Minimizing loss of injected hydraulic fracturing fluids into shale along fracture-matrix boundaries is desired because imbibed water restricts gas production and wastes valuable water resources. This problem has motivated the addition of surfactants into water-based hydraulic fracturing fluids in order to reduce the capillary driving force for imbibition. Here, we show that reduction in interfacial tension and wettability alteration has negligible ability to reduce imbibition in deep gas reservoirs. The effectiveness of altering capillary forces acting at the wetting front also depends on the injection pressure acting at the fracture-matrix boundary. The pressure at the interface between the fracture and the shale matrix is constrained between the reservoir pore pressure and formation pressure (rock fracture pressure, also known as breakdown pressure of the rock) and increases with depth to magnitudes that greatly exceed that of capillary pressures. The analyses presented here show that even maximum alteration of interfacial properties that result in strongly hydrophobic interactions between the fracturing fluid and reservoir rock is incapable of significantly reducing imbibition in deep reservoirs. Instead of using surfactants, this analysis points to decreases in wellbore shut-in pressures and shut-in times as practical options for reducing imbibition losses of water-based fluids.

Impact of water saturation on gas permeability in shale: Experimental and modelling

Shale gas is becoming more important in clean energy supply. There is original water content in shale pores under reservoir condition. In addition, the introduction of water-based fracturing fluid during hydraulic fracturing process also changes the shale reservoir water saturation. Water saturation has a profound impact on the gas effective permeability and its anisotropy, thus on shale gas production. Previous experimental studies on gas effective permeability were mostly on dry samples. Due to the great difficulty in gas-water two-phase flow experiment, there are very few experiments to study the impact of shale water saturation on gas permeability. How water content affects gas effective permeability is not well understood. This work proposes an experimental method to investigate the effect of water saturation on stress-dependent gas permeability. Moreover, the experimental method and gas permeability results are compared between this work and literature. An integrated permeability model considering the impact of water saturation is proposed. It is found that the water content has significant impact on gas effective permeability and the impact is more significant for low permeability samples.