Hydraulic Fracturing Fluid Research Articles

Sensitivity Analysis of Depth-Controlled Oriented Perforation in Horizontal Wells Based on the 3D Lattice Method

The main method used to exploit unconventional oil and gas reservoirs involves multi-cluster perforation combined with hydraulic fracturing in horizontal wells. However, as the use of this technology has expanded, challenges like reduced perforation efficiency and elevated fracture initiation pressure have surfaced. The depth-controlled oriented perforation technique helps achieve uniform fracture initiation, enhance efficiency, and lower initiation pressure. In this study, a hydraulic fracturing fluid–solid coupling model at the perforation scale was established using the 3D lattice method to compare the near-wellbore fracture morphologies of depth-controlled oriented perforation, spiral perforation, and oriented perforation. Additionally, this study analyzes the effects of injection rate, reservoir elastic modulus, and horizontal stress difference on the fracture morphology and initiation pressure of depth-controlled oriented perforation. This study clarifies the applicability of depth-controlled oriented perforation in different types of reservoirs for the first time. The results indicate that intermediate fractures between spiral and oriented perforations are hindered, while depth-controlled oriented perforation ensures uniform fracture initiation. In the injection rate range of 0.144 to 0.360 L/min, an increase in injection rate accelerates the rise of fluid pressure within the perforations, leading to an increase in fracture initiation pressure. Therefore, excessively high injection rates are unfavorable for fracture initiation. Through depth-controlled oriented perforation, long and singular fractures can be formed in reservoirs with significant horizontal stress differences and high elastic moduli.

A National Study of the Associations between Hormonal Modulators in Hydraulic Fracturing Fluid Chemicals and Birth Outcomes in the United States of America: A County-Level Analysis.

Risk of preterm birth (PTB) and low birth weight (LBW) due to hydraulic fracturing (HF) exposure is a growing concern. Regional studies have demonstrated links, but results are often contradictory among studies. This is the first US national study to our knowledge linking fracturing fluid ingredients to the human hormone pathways targeted-estrogen, testosterone, or other hormones (e.g., thyroid hormone)-to assess the effect of HF ingredients on rates of PTB and LBW. We constructed generalized linear regression models of the impact of HF well density and hormone targeting chemicals in HF fluids (2001-2018) on the county-level average period prevalence rates of PTB and LBW (2015-2018) with each outcome measured in separate models. Our data sources consisted of publicly available datasets, including the WellExplorer database, which uses data from FracFocus, the March of Dimes Peristats, the US Census Bureau, the US Department of Agriculture, and the Centers for Disease Control and Prevention. We conducted additional stratified analyses to address issues of confounding. We used stratification to address issues regarding outcomes in rural vs. urban communities by assessing whether our models achieved similar results in nonmetro counties, as well as farming and mining counties. We also stratified by the year of the HF data to include HF data that was closer to the time of the birth outcomes. We also added covariate adjustment to address other important factors linked to adverse birth outcomes, including the proportion of the population belonging to various racial and ethnic minority populations (each modeled as a separate variable); education (bachelor's degree and high school); use of fertilizers, herbicides, and insecticides, acres of agricultural land per square mile; poverty; insurance status; marital status; population per square mile; maternal care deserts; and drug deaths per 100,000 people. We found that the density of HF wells in a county was significantly associated with both PTB and LBW rates (percentage of live births) in our fully adjusted models. We report the results from our more restrictive stratified analysis with a subset including only the 2014-2018 data, because this resulted in the most meaningful time frame for comparison. Across all models, the magnitude of effect was highest for wells with ingredients that include estrogen targeting chemicals (ETCs), testosterone targeting chemicals (TTCs) and other hormone targeting chemicals (OHTCs), and, finally, all wells grouped regardless of chemical type. For every unit increase in well density per square mile of wells that use chemicals that include an ETC, we observed a 3.789-higher PTB rate (95% CI: 1.83, 5.74) compared with counties with no ETC wells from 2014 to 2018 and likewise, we observed a 1.964-higher LBW rate (95% CI: 0.41, 3.52). Similarly, for every unit increase in well density per square mile of wells that use TTC, we observed a 3.192-higher PTB rate (95% CI: 1.62, 4.77) compared with counties with no TTC wells. Likewise, for LBW, we found a 1.619-higher LBW rate (95% CI: 0.37, 2.87). We also found that an increase in well density per square mile among wells that use chemicals that include an OHTC resulting in a 2.276-higher PTB rate (95% CI: 1.25, 3.30) compared with counties with no OHTC wells, and for LBW, we found a 1.244-higher LBW rate (95% CI: 0.43, 2.06). We also explored the role of HF well exposure in general (regardless of the chemicals used) and found that an increase in total well density (grouped regardless of hormonal targeting status of the chemicals used) resulted in a 1.228-higher PTB rate (95% CI: 0.66, 1.80) compared with counties with no wells, and for LBW, we found a 0.602-higher LBW rate (95% CI: 0.15, 1.05) compared with counties with no wells. We found similar results in our primary analysis that used all data without any exclusions and the statistical significance did not change. Our findings reinforce previously identified regional associations between HF and PTB and LBW, but on a national scale. Our findings point to dysregulation of hormonal pathways underpinning HF exposure risk on birth outcomes, which warrants further exploration. Future research must consider the specific ingredients used in HF fluids to properly understand the differential effects of exposure. https://doi.org/10.1289/EHP12628.

Mitigation of biocorrosion of X80 carbon steel by a shale microbiome biofilm using a green biocide enhanced by d-amino acids

Microbiologically influenced corrosion (MIC) in shale gas field is a major threat with the hydraulic fracturing fluid injected into the subsurface. In this study, the microbiome collected from a shale gas produced water sample was extracted and cultivated in ATCC 1249 medium modified with 10 g/L NaCl anaerobically at 30 °C. d-amino acids, which were reported as biocide enhancers, were found to enhance 2,2-dibromo-3-nitrilopropionamide (DBNPA) biocide on the mitigation of shale microbiome MIC on X80 carbon steel. The combination of 50 ppm (w/w) d-leucine + 50 ppm d-alanine + 1 ppm d-tyrosine had the best enhancement effect on 50 ppm DBNPA with 84 % less weight loss, and 67 % lower corrosion current density (icorr) compared to 50 ppm DBNPA alone. The corrosion data were consistent with the enhanced biofilm inhibition observation. The experimental data also indicated that d-tyrosine used alone at a low dosage of 1 ppm enhanced DBNPA considerably, with 44 % less weight loss and 47 % less icorr. The electrochemical results showed the positive response of shale gas microbiome biofilm to the injected magnetite nanoparticles indicating the extracellular electron transfer might be a main mechanism for its corrosion.

The effect of sodium chloride on the charge state of soot particles in a laminar diffusion flame

This study investigates the effect of sodium chloride on the charge state of soot nanoparticles formed in a laminar diffusion flame by measuring the soot particle size distribution, average charge per particle, and charge fraction at various heights within the flame. The well-studied Santoro burner with methane as the fuel (at 0.35 L/min) and co-flow air (at 70 L/min) was used, which produced a stable laminar diffusion flame with flame height of 61 mm. Samples of soot nanoparticles were extracted via a 0.3 mm orifice in a 3-mm stainless steel tubular probe at various heights above the burner and were immediately diluted by a factor of a few thousand for aerosol measurement. The effect of sodium chloride on a methane flame was investigated by comparing the experimentally measured data for methane-only and methane-NaCl flames. The addition of NaCl particles to the laminar diffusion flame did not have a significant effect on the particles in the nucleation region of the flame. The majority of the incipient soot particles in both flames are uncharged, and their sizes are nearly the same, with diameters of approximately 5 nm or less. However, the size of soot particles differs by approximately 10 % to 25 % between methane-only and methane-NaCl flames in the coagulation-dominated region of the flame. The net charge on soot particles within the coagulation region of the methane-only flames is negative, while it is positive with NaCl addition. The fraction of charged particles and ion concentration decreases with NaCl addition within the coagulation region. The study indicates that the smaller particle size observed in methane-NaCl flames may be attributed to reduced coagulation via altered particle charge states. These factors could be the major contributor to the variations in soot formation between methane-only and methane-NaCl flames. Novelty and Significance StatementThis research addresses a notable knowledge gap concerning the influence of NaCl, a prevalent component of hydraulic fracturing fluids, on soot particle behaviour in flames. By explaining the impact of NaCl on soot formation and charge states, the findings contribute to a deeper understanding of combustion processes in environments influenced by hydraulic fracturing operations, thereby informing strategies for reducing emissions and improving environmental sustainability in energy production. Overall, this article represents a significant advancement in the field of combustion science, with implications for environmental stewardship in energy production.This study provides valuable insights into how the introduction of NaCl alters the electrostatic properties of soot particles. This investigation expands upon existing knowledge by shedding light on the intricate mechanisms underlying soot formation and evolution in the presence of NaCl, elucidating its potential implications for combustion processes involving fossil fuels and industrial flaring.

Understanding the Dynamics of Matrix-Fracture Interaction: The First Step Toward Modeling Chemical EOR and Selecting Suitable Fracturing Fluid in Unconventional Oil/Gas Recovery

Summary The effects of chemical additives on mitigating water blocking and improving oil recovery were experimentally examined for gas-water and oil-water systems in spontaneous imbibition cells. In these attempts, two factors are critically important: (1) understanding the physics of the interaction, whether it is co- or countercurrent, and (2) characteristics of the chemical additives to suitably orient the interaction for specific purposes (accelerate/decelerate matrix-fracture interactions). Co- and countercurrent imbibition experiments were conducted on sandstone rock samples using various oil samples (viscosities between 1.37 cp and 54.61 cp) as well as gas (air). The selected new-generation chemical additives included deep eutectic solvents, cationic/anionic/nonionic surfactants, and inorganic and organic alkalis. We observed that the functionality of the chemicals varied depending on the fluid type, interaction type (co- or countercurrent), and application purposes. For instance, chemicals such as the cationic surfactant cetyltrimethylammonium bromide (CTAB) significantly reduced water invasion into the gas-saturated sandstone cores during fracturing, while chemicals such as the nonionic surfactant Tween® 80 provided considerable oil recovery improvement in the oil-saturated sandstone cores. The surface tension and wettability of the rock surface are crucial factors in determining the suitability of chemicals for mitigating water blockage. In terms of oil recovery, certain chemical additives, such as O342 and Tween 80, may result in a lower recovery rate in the early stage because of their strong ability in interfacial tension (IFT) reduction but could lead to a higher ultimate recovery factor by altering the wettability. Additionally, the introduction of chemicals resulted in notable spontaneous emulsification, especially in countercurrent imbibition, thereby enhancing oil recovery. The spontaneous emulsification and its stability are influenced by factors such as oil drop size, boundary condition, interaction type, IFT, wettability, as well as rock surface charges. The results have implications for understanding the physics and dynamics of matrix-fracture interactions in co- and countercurrent conditions. In addition, they serve as the first step toward selecting appropriate chemical additives in hydraulic fracturing fluid design and enhancing oil recovery in unconventional reservoirs.

Influence of fracturing fluids on shale matrix permeability and micro-mechanical properties after chemical interactions

Geochemical interactions between shale and hydraulic fracture fluids (HFFs), principally mineral dissolution and precipitation, can result in alteration of matrix permeability and tendency of proppant embedment, ultimately impacting hydrocarbon migration through the shale formation. This study aimed to quantify changes of core permeability and micromechanical properties after shale-HFF chemical interactions. Extent of chemical alteration of the solid phase was characterized by synchrotron X-ray fluorescence mapping, micro-computed tomography, and scanning electron microscopy. Post-reaction brine was evaluated for elemental concentrations. Both low-carbonate and high-carbonate shale exhibited carbonate dissolution, an iron oxidation zone, and barite precipitates partially infilling secondary porosity. These reactions were more obvious in the high-carbonate shale but extended further into the low-carbonate shale. Pulse-decay permeability measurements generally revealed increase in permeability after reactions, whereas hardness and modulus reduction were observed only in reaction zones of high carbonate shale. Inevitable heterogeneity of natural shale samples resulted in large deviations in hydromechanical measurements both on the core scale and on the microscale.

CH4 and CO2 adsorption–desorption-diffusion characteristics in surfactant-modified coal under microscopic conditions

Hydraulic techniques are integral to both coal mining and gas extraction procedures, and the precise inclusion of surfactants in hydraulic fracturing fluids serves as a crucial factor influencing the wettability of coal and facilitating gas desorption. Nevertheless, relatively few investigations have focused on the influence of surfactants within coal on the adsorption–desorption-diffusion dynamics of gases. In this study, Xin Tian high-rank coal was treated with different surfactants, and the pore structure and functional groups of the coal samples were determined by fluid invasion methods, Fourier transform infrared (FT-IR) spectroscopy, X-ray photoelectron spectroscopy (XPS), and 13C nuclear magnetic resonance (13C NMR) spectroscopy. Moreover, molecular-scale models were constructed to simulate the adsorption–desorption-diffusion performance of the gases in the surfactant-modified coal. As per the results, modification with methyltrimethoxysilane (MTMS) and polyethylene oxide (PEO) surfactants reduced the proportion of micropores and relative content of oxygen functional groups, resulting in reduced the adsorption of gases and enhanced diffusion performance, consistent with molecular simulations result. These results provide a theoretical foundation for elucidating the adsorption–desorption mechanisms of surfactant-treated coal and its application in mining areas.

The high energetic potential of hydraulic fracturing wastewaters with both salinity and temperature gradients for electricity generation using a reverse electrodialysis stack

Hydraulic fracturing (HF) wastewaters have high salinities relative to feed waters and can be an economic and environmental burden. However, salinity differences between these two solutions offer the opportunity for electricity generation using reverse electrodialysis (RED) stacks. HF wastewaters are much hotter than feed waters, but the relative impact of temperature for RED has been relatively unexplored. We investigated power generation using HF fluids in RED stacks, focusing on the impact of temperature differences between feed and wastewater. Power from synthetic solutions (mixtures of NaCl, Na2SO4, and CaCl2) produced up to 0.96 W/cp m2 when both solutions were 25 °C and increased to 1.51 W/cp m2 when both solutions were at 60 °C. With an actual HF wastewater power production was 1.27 W/cp m2 at 25 °C with no temperature difference, and 3.74 W/cp m2 with a 25 °C feed solution and 60 °C HF wastewater. Comparing synthetic and HF wastewaters showed that the presence of sulfate and calcium ions reduced permselectivity and increased the electrical resistance of the membranes. Increasing the temperature, however, reduced electrical resistances. A thermodynamic model using Gibbs energies, and short- and long-range interactions of ions/ion-water was used to assess energy efficiency. The overall energy efficiency of the RED stack, based on ion concentrations in the inlet/outlet streams, was 24 % using NaCl at 50 °C. These results show that electricity can be effectively generated using salinity differences of HF streams and highlight the additional benefits of using solutions with different temperatures.

Impact of surfactants used in oil and gas extraction on produced water treatment by membrane distillation

Produced water from unconventional oil and gas reservoirs often contains non-ionic surfactants that are added to the hydraulic fracturing fluid to facilitate water release and enhance gas production. This study investigates the impact of currently used surfactants (i.e., nonylphenol ethoxylates (NPEOs) and octylphenol ethoxylates (OPEOs)) and proposed alternative surfactants on the performance of membrane distillation (MD) for produced water treatment. The impact of NPEOs and OPEOs on wetting of PTFE membranes was studied as a function of their concentrations and ethoxylate (EO) chain length in a lab-scale DCMD system. Additionally, alternative surfactants, including linear alcohol ethoxylates (LAEs), branched secondary alcohol ethoxylates (BAEs), and alkyl polyglycosides (APGs), were evaluated for their potential to replace NPEOs and OPEOs. Experimental results indicate that the increase in the number of EO units in NPEOs decreased their tendency to cause membrane wetting by reducing their interaction with hydrophobic surfaces. It was also observed that LAEs and APGs that are environmentally friendly alternatives did not cause membrane wetting. This study provides valuable insights into the underlying mechanisms of surfactant-membrane interactions and offers guidelines for surfactant alternatives that can potentially improve hydraulic fracturing and lower environmental concerns while facilitating the use of MD for produced water treatment and recovery.

Assessment of the effect of process fluids injected into injection wells on the possibility of changing the rheological parameters of hydraulic fracturing fluids after destruction

Assessment of the effect of process fluids injected into injection wells on the possibility of changing the rheological parameters of hydraulic fracturing fluids after destruction

Role of Fracture Roughness in Fracture Surface Evolution During Acidized Corefloods of Calcareous Shales

Summary During the hydraulic fracturing process, an acidic hydraulic fracturing fluid (HFF) is injected at high flow rates to break the rock and enhance its flow potential. This rock-fluid interaction induces both physical and chemical alterations on the fracture surface, resulting in the formation of a “reaction-altered zone.” Recent research has revealed that the depth of reaction penetration is minimal, and most changes occur on the fracture surface. To gain a deeper understanding of how fracture roughness affects fracture aperture change, in this work we adopt an experimental approach. Two similar samples of carbonate-rich Wolfcamp shale with calcite-filled fractures are selected. One sample is cut through the center creating a smooth fracture (SF), while the other is fractured by parting along the calcite-filled fracture, generating a rough fracture (RF). The fracture surface topography, mineral distribution, fracture aperture, and rock hardness are characterized before a reactive coreflood using an equilibrated acidic brine is conducted. The pressure drop across the core is measured, and the effluent is periodically collected and analyzed using mass spectrometry. The temporal changes in the fracture surface are observed by conducting physicochemical surface characterization after the coreflood. The results indicate that calcite dissolution is the primary chemical reaction occurring on the fracture surface, weakening it. Furthermore, this dissolution decreases the fracture roughness, which results in fracture closure and ultimately a decrease in the fracture conductivity. The most significant change in the fracture aperture is observed near the inlet. These results highlight the potential impact of fracture roughness on the mechanism of fracture evolution during acidized corefloods. Higher fracture roughness is associated with increased fines migration and a more significant overall change in fracture aperture during injection. This research provides valuable insights into the intricate processes at play during hydraulic fracturing and aids in understanding the dynamics of fracture growth in such conditions.

Hydraulic fracturing potential of tight gas reservoirs: A case study from a gas field in the Bredasdorp Basin, South Africa

The issue of hydraulic fracturing in the onshore Karoo Basin has triggered an intense political, social and environmental debate in South Africa. This research paper proposes the relatively under-explored F–O tight gas field in South Africa as a demonstration site that can shed light on the ongoing debate on the use of hydraulic fracturing in the Karoo Basin. By combining petrographic and geomechanical analyses with critical velocity experiments and rock mechanics testing, a step-by-step guide for assessing the hydraulic fracturing potential of tight gas reservoirs was presented. K-Means clustering was used to improve the sampling strategy and to capture reservoir heterogeneity. The results obtained showed that K-Means clustering improves reservoir characterisation by revealing heterogeneous intervals, thus optimising petrographic and geomechanical analyses. In addition, the hydraulic fracturing fluid was found not to cause formation damage in the reservoir at a critical velocity of 0.155 ml/min. The elastic properties also showed that the F–O Tight Gas Field has a high degree of brittleness with good hydraulic fracturing potential. Finally, the characterisation of the fractures shows that partially open fractures are prevalent, which can dilate under the high differential stresses in the reservoir. Although further investigation is required, this study has shown that the F–O gas field is a promising candidate for hydraulic fracturing.

Coupled Computational and Laboratory Investigations of Interface Interactions between Binary Polymers, Hydroxypropyl Guar, and Potassium Formate for Crosslinked Hydraulic Fracturing Fluids

Summary Guar gum is an economically and environmentally important material. However, reduced rheological properties of hydroxypropyl guar (HPG) in saline conditions of potassium formate (PF) impeded its hydraulic fracturing (HF) applications. In this study, we coupled molecular dynamics simulation and bench experiments to design binary polymers that can be used to mitigate the reduced viscosity of the HPG-PF system and investigate the relevant physiochemical processes in the fluid. The modeling showed that binary polymer P(AM-AA) with acrylamide (AM) and acrylic acid (AA) monomers had the highest ability to bind water molecules in the HPG-PF solution among four representative binary polymers. Multiple analyses showed that adding P(AM-AA) decreased the number of formate ions around the HPG molecules, bonded with the HPG molecule through hydrogen bonds, and mitigated the coiling of the HPG molecular chain in PF solutions. Further experiments and characterization at the macro- and microscale showed that adding P(AM-AA) indeed improved the viscosity, microrheology, viscoelasticity, and thermal tolerance [>120°C (248°F)] of the HPG-PF solution (1.47 g/cm3) and its associated gel system. Our study indicates the potential application of HPG-PF-P(AM-AA) weighting crosslinked HF fluids (HFFs) for wells with stringent wellbore pressure constraints. It also highlights the significant role of binary polymers in enhancing rheological properties in gel-based crosslinked HFF and addressing complex fluid interface interactions through molecular dynamics simulations.

Oxidative Hydraulic Fracturing Fluid to Enhance Production from Source Rock Reservoirs

Summary The steep production declines generally observed after hydraulic fracturing in unconventional source rock reservoirs has been attributed to several potential causes. Recently, a new additive to the stimulation fluid system was proposed to extend economical longer-term production from these formations. Oxidizer-laden fracturing fluid systems are shown to create cracks and deep channels within the organic matter present in the source rock, such as kerogen, thereby increasing the source rock permeability and enhancing the hydraulic conductivity of the exposed fracture faces. To this end, the fluid design and recommendations for its application are illustrated herein. Oxidants composed of oxychlorine (ClOn−) and oxybromine (BrOn–) (where n = 0 to 4) are effective for kerogen depolymerization or degradation at depth. This study illustrates the beneficial effects of two specific oxidizers—sodium chlorite (NaClO2) and sodium bromate (NaBrO3)—on kerogen-rich source rock subjected to in-situ reservoir conditions. Source rock samples were cut and polished to test the oxidizer’s impact on the organic and inorganic regions. Scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS) were performed on the rock surface to identify specific organic matter features. The samples were then chemically treated with varying conditions of NaClO2 or NaBrO3 (concentration range: 0.013–0.054 M; temperature: 150°C; and time: 3–24 hours). Samples were returned to the scanning electron microscope for post-treatment analysis. Furthermore, the oxidants were packaged within a slickwater hydraulic fracturing fluid system for field application, and their effects on viscosity and friction reduction were also studied. SEM images and EDS maps of kerogen-rich rock samples observed before and after treatment with oxidizing fluid showed a series of cracks formed throughout the organic matter domains, where increasing the concentration of oxidizer in the treatment fluid showed a clear increase in the prevalence of cracks throughout the surface. The effect of time was also observed, as short treatment times resulted in porosity/permeability creation in the kerogen, though longer treatment times were associated with more severe degradation. Optimal conditions for NaClO2 and NaBrO3 concentrations in the additive fluid systems were different and will be herein highlighted. Each oxidizer (10–20 pptg concentration) was added to slickwater with variable friction reducer concentration (1 gpt, 2 gpt, and 4 gpt), and shear sweeps performed at both 70°F and 180°F. A negligible difference is observed between the viscosities of the base fluid and the fluid with either oxidant at low friction reducer concentration. Meanwhile, flow loop tests demonstrated that the oxidizer did not affect the friction reducer except to slightly boost the performance due to the salt effect on the polymer. Two strong oxidants, available as commodity chemicals, are shown to be effective in cracking kerogen and any present organic matter, thus creating permeable channels and enhancing the overall permeability of the exposed source rock fracture faces. Meanwhile, the proposed fracturing fluid additives display good compatibility with other slickwater fluid components, demonstrating the potential for universal usage in unconventional stimulations. The recommendations for its application as a fluid additive in slickwater are herein illustrated.

Dual Semi-Interpenetrating Networks of Water-Soluble Macromolecules and Supramolecular Polymer-like Chains: The Role of Component Interactions

Dual networks formed by entangled polymer chains and wormlike surfactant micelles have attracted increasing interest in their application as thickeners in various fields since they combine the advantages of both polymer- and surfactant-based fluids. In particular, such polymer-surfactant mixtures are of great interest as novel hydraulic fracturing fluids with enhanced properties. In this study, we demonstrated the effect of the chemical composition of an uncharged polymer poly(vinyl alcohol) (PVA) and pH on the rheological properties and structure of its mixtures with a cationic surfactant erucyl bis(hydroxyethyl)methylammonium chloride already exploited in fracturing operations. Using a combination of several complementary techniques (rheometry, cryo-transmission electron microscopy, small-angle neutron scattering, and nuclear magnetic resonance spectroscopy), we showed that a small number of residual acetate groups (2–12.7 mol%) in PVA could significantly reduce the viscosity of the mixed system. This result was attributed to the incorporation of acetate groups in the corona of the micellar aggregates, decreasing the molecular packing parameter and thereby inducing the shortening of worm-like micelles. When these groups are removed by hydrolysis at a pH higher than 7, viscosity increases by five orders of magnitude due to the growth of worm-like micelles in length. The findings of this study create pathways for the development of dual semi-interpenetrating polymer-micellar networks, which are highly desired by the petroleum industry.

Effect of wettability on fracturing fluid microscale flow in shale oil reservoirs

The wettability of shale reservoirs has an important influence on the flow of external fluids. In this paper, the effect of wettability on the self-absorption of hydraulic fracturing fluid under different pore size conditions is first analyzed. Then, the mechanism of the influence of wettability pore size on the flow coefficient is elucidated. The results show that (a) as the pore size decreases, the importance of various forces acting on the fluid during the flow process changes, and the solid-liquid interaction will greatly affect the fluid flow in the nanopore. (b) When the radius is 5, the flow enhancement increases from 0.6331 to 0.998 as the radius increases from 0 to 3.141594.(c) The shale inorganic material contains a variety of minerals, and the interaction forces between different mineral surfaces and water molecules are different, resulting in different apparent viscosities.

Fluid Spontaneous Imbibition Under the Influence of Osmotic Pressure in Deep Coalbed Methane Reservoir in the Ordos Basin, China

Summary The flowback rate of a hydraulic fracturing fluid is related to coalbed methane (CBM) production in gas wells. The deep (>2000 m) CBM reservoir in the Ordos Basin has an extremely high salinity (>200 000 mg/L), which results in a very low flowback rate of fracturing fluid. The mechanism underlying the extremely low flowback rate of the fracturing fluid remains unclear. This study experimentally simulated two patterns of osmotic pressure variation that exist at a hydraulic fracturing site: the processes of injection of a low-salinity fracturing fluid into a high-salinity reservoir and a high-salinity fracturing fluid into a low-salinity reservoir. Low-field nuclear magnetic resonance (NMR) technology was used to monitor dynamic fluid migration and fluid distribution in the coals. Results showed that osmotic pressure is a driving force for spontaneous imbibition when the salinity of the fracturing fluid is lower than that of the reservoir water, and more fluid enters the coal as the osmotic pressure increases. This causes the displacement of the high-salinity fluid already present in the micropores by the low-salinity fracturing fluid. In high-salinity deep coal seams, both osmotic pressure and capillary forces cause the spontaneous imbibition of the fracturing fluid from fractures into pores, promoting CH4 desorption, alleviating the water-blocking effect, and enhancing the filtration loss of the fracturing fluid. In contrast, the injection of a high-salinity fluid into the reservoir with a low-salinity brine (LSB) creates an osmotic pressure difference that prevents fluid imbibition. In shallow, low-salinity coal seams, the injection of high-salinity fracturing fluids can result in high flowback rates. Therefore, these two injection schemes are significant for an understanding of the role of osmotic pressure in deep CBM extraction and serve as valuable guides for optimizing the selection of the fracturing fluid and improving its effective flowback.

A hydro-thermo-damage-mechanical fully coupled cohesive phase-field model for fracking in quasi-brittle thermo-poroelastic media

A hydro-thermo-damage-mechanical fully coupled cohesive phase-field method is developed for modelling of fracking in quasi-brittle thermo-poroelastic media. A new sigmoid interpolation function is proposed to characterize the transitional behaviour from porous media to cracks for permeability, specific heat capacity, and thermal conductivity. A fluid continuity equation with the Darcy-Poiseuille law and an energy conservation equation with the Fourier’s law are then used to simulate fluid flow and heat transfer in cracking porous media, respectively. The fluid pressure and temperature of fluids and solids are fully incorporated into the governing equation of the phase-field regularized cohesive zone model to efficiently simulate complicated quasi-brittle hydro-thermal fracking, without the need of remeshing, crack tracking or auxiliary fields. The resultant displacement–pressure-temperature-damage coupled multiphysics system of equations is solved using a staggered Newton–Raphson iterative algorithm within the finite element framework. The method is first validated by five two-dimensional thermally or hydro-thermally induced fracture examples with analytical solutions, experimental data, and published numerical solutions. Three-dimensional fracking and fluid circulation problems in a vertical five-spot wellbore system with complex natural fracture networks, are then simulated as an application to energy harvesting in enhanced geothermal systems (EGS). It is found that the present method is capable of accurately and robustly modelling complicated hydraulic fracture propagation and fluid circulation problems and has the potential to be used for fracking design and optimization of EGS.

Numerical Evaluation of Commingled Production Potential of Marine Multilayered Gas Hydrate Reservoirs Using Fractured Horizontal Wells and Thermal Fluid Injection

Multilayered reservoirs with coexisting free gas and hydrates are primary targets for commercialization, nevertheless, the extremely low permeability greatly limits their extraction efficiency. Herein, multilayer commingled production using horizontal wells stimulated by hydraulic fracturing and thermal fluid injection was proposed to enhance productivity, and the effects of key factors on co-production performance were numerically examined, with the reservoir located in the Shenhu Area as the geological background. The results indicated that due to severe interlayer contradictions, the stimulation capabilities of using fracturing or thermal fluid injection alone were limited, in particular, the extraction of hydrates severely lagged behind. However, their combination exhibited tantalizing productivity due to strengthened inter-well interaction. Reducing the fracture spacing was more effective than increasing fracture conductivity in shortening the production cycle, and intensive fractures with adequate flow capacity were suggested for gas enhancement and water control. When the fracture spacing was reduced from 30 to 5 m and the fracture conductivity increased from 10 to 100 D·cm, the horizontal section length for commercial production (average daily gas production of 50,000 m3 and recovery ratio of 0.7) was reduced from 1758 to 146 m, which is lower than the on-site horizontal section length of 250–300 m. Therefore, the proposed development mode is promising for the commingled production of gas and hydrates.

An Optimal Model for Determination Shut-In Time Post-Hydraulic Fracturing of Shale Gas Wells: Model, Validation, and Application

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing the shale reservoirs. However, a large amount of mining data indicate that the fracturing fluid trapped in the reservoir will inevitably cause hydration interaction between water and rock. On the one hand, the intrusion of fracturing fluid into the formation causes cracks to expand, which is conducive to the formation of complex fracture networks; on the other hand, the intrusion of fracturing fluid into the formation causes the volume expansion of clay minerals, resulting in liquid-phase trap damage. At present, the determination of well closure time is mainly based on experience without theoretical guidance. Therefore, how to effectively play the positive role of shale hydration while minimizing its negative effects is the key to optimizing the well closure time after fracturing. This paper first analyzes the shale pore characteristics of organic pores, clay pores, and brittle mineral pores, and the multi-pore self-absorption model of shale is established. Then, combined with the distribution characteristics of shale hydraulic fracturing fluid in the reservoir, the calculation model of backflow rate and shut-in time is established. Finally, the model is validated and applied with an experiment and example well. The research results show that the self-imbibition rate increases with the increase in self-imbibition time, and the flowback rate decreases with the increase in self-imbibition time. The self-imbibition of slick water is the maximum, the self-imbibition of breaking fluid is the minimum, and the self-imbibition of mixed fluid is the middle, and the backflow rates of these three liquids are in reverse order. It is recommended the shut-in time of Longmaxi Formation shale is 17 days according to the hydration and infiltration model.