Search Results (77)

In geothermal systems, polymer injection is vital for improving the sweep efficiency of fluid, but the critical challenge is managing the fluid flow in severely fractured systems. Developing stable plugging agents for these systems is a recurring challenge, allowing the loss of the fluid into the large fractures, hence making the recovery very difficult. The fluid is crucial for several applications like power generation, heating, and cooling without producing any toxic emissions. This study presents a gel system formulated with hydroxyethyl cellulose, and a HMTA–resorcinol crosslinker system for harsh conditions of temperature and salinity. The study employed a Central Composite Design (CCD) for optimizing gel formulation. The system achieved optimal conditions at a gelation time of 0.5 h, and the properties were investigated. The experimental outcomes reveal that the polymer gel can exhibit excellent stability under harsh conditions, withstanding temperatures up to 352 °C. This confirms the robustness of the plugging agent at elevated temperatures. This study offers a sustainable and efficient solution for fluid flow control in severely fractured geothermal systems. Full article

With the increasing exploration and development of deep shale gas resources, water-based fracturing fluids face multiple challenges, including high-temperature resistance, salt tolerance, and efficient proppant transport. In this study, a zwitterionic polymer (polyAMASV) is synthesized via aqueous two-phase dispersion polymerization, using acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), acrylic acid (AA), stearyl methacrylate (SMA), and 4-vinylpyridine propylsulfobetaine (4-VPPS) as monomers. The introduction of hydrophobic alkyl chains effectively adjusts the viscoelasticity of the emulsion, while the incorporation of zwitterionic units provides salt tolerance through their intrinsic anti-polyelectrolyte effect. As a result, the solutions of such copolymers exhibit stable apparent viscosity in both NaCl and CaCl₂ solutions and under high temperatures. Meanwhile, polyAMASV outperforms conventional samples across various saline environments, reducing proppant settling rates by approximately 20%. Moreover, the solutions exhibit rapid gel-breaking and low residue characteristics, ensuring effective reservoir protection. These results highlight the promising potential of polyAMASV for deep shale gas fracturing applications. Full article

The transition to a sustainable energy mix is essential to mitigate climate change. Enhanced Oil Recovery (EOR) using low-salinity water (smart water) has emerged as a promising strategy for reducing environmental impacts in the petroleum industry, producing a highly valuable energy source due to both its energy density and market value. This study critically reviews intermediate technological readiness levels (TRL), applying a patent-based approach (TRL 4–5) and a review of articles (TRL 3) to analyze various aspects of smart water for EOR, including its composition. A total of 23 patents from the European Patent Office (Questel Orbit) and 1395 articles from Elsevier’s Scopus database were analyzed, considering annual trends, country distribution, international collaborations, author and applicant affiliations, citation dependencies, and factorial analyses. Both patents and articles show exponential growth; however, international collaboration is more frequent in the scientific literature, while patents remain concentrated in a few countries aligned with their markets. Technologies are focused on wettability, surface complexation, CO₂ interactions, emulsification, aerogels, reinjection water treatment, carbonate reservoirs, effluent treatment, nanofluidics, and ASP fluids. Recent topics include CO₂ associations, permeability, fractured reservoirs, gels, reservoir water, wettability alteration, and reservoir/oil heterogeneity. The findings indicate the need for multivariated development of customized smart waters to address complex interfacial synergistic mechanisms. International Joint Industry Projects and global regulations on the safe use and composition of hybrid injections are recommended to accelerate development, reduce environmental impacts, and enhance the efficient use of existing fields, alleviating the challenges of finding new reservoirs. Full article

With the continuous progress and innovation of petroleum engineering technology, the development of new oilfield additives with superior environmental benefits has attracted widespread attention. Konjac glucomannan (KGM) is a natural resource characterized by abundant availability, low cost, biodegradability, and environmental compatibility. Konjac gum easily forms a weak gel network in water, but its water solubility and thermal stability are poor, and it is easily degraded at high temperatures. Therefore, its application in drilling fluid and fracturing fluid is limited. In this paper, a method of carboxymethyl modification of KGM was developed, and a carboxymethyl group was introduced to adjust KGM’s hydrogel forming ability and stability. Carboxymethylated Konjac glucomannan (CMKG) is a water-soluble anionic polysaccharide derived from natural Konjac glucomannan. By introducing carboxymethyl groups, CMKG overcomes the limitations of the native polymer, such as poor solubility and instability, while retaining its safe and biocompatible nature, making it an effective natural polymer additive for oilfield applications. The results show that when used as a drilling fluid additive, CMKG can form a stable three-dimensional gel network through molecular chain cross-linking, significantly improving the rheological properties of the mud. Its unique gel structure can enhance the encapsulation of clay particles and inhibit clay hydration expansion. When used as a fracturing fluid thickener, the viscosity of the gel system formed by CMKG at 0.6% (w/v) is superior to that of the weak gel system of KGM. The heat resistance/shear resistance tests confirm that the gel structure remains intact under high-temperature and high-shear conditions, meeting the sand-carrying capacity requirements for fracturing operations. The gel-breaking experiment shows that the system can achieve controlled degradation within 300 min, in line with on-site gel-breaking specifications. This modification process not only improves the rheological properties and water solubility of the CMKG gel but also optimizes the gel stability and controlled degradation through molecular structure adjustment. Full article

Conventional fracturing fluids, while essential for large-volume stimulation of unconventional reservoirs, often induce significant reservoir damage through water retention and capillary trapping. To address this problem, this study developed a novel superhydrophobic nano-viscous drag reducer (SN-DR), synthesized through a multi-monomer copolymerization and silane modification strategy, which enhances structural stability and minimizes reservoir damage. The structure and thermal stability of SN-DR were characterized by FT-IR, ¹H NMR, and TGA. Rheological evaluations demonstrated that the gel fracturing fluid exhibits a highly stable three-dimensional network structure, with a G′ maintained at approximately 3000 Pa and excellent shear recovery under cyclic stress. Performance tests showed that a 0.15% SN-DR achieved a drag reduction rate of 78.1% at 40 L/min, reduced oil–water interfacial tension to 0.91 mN·m⁻¹, and yielded a water contact angle of 152.07°, confirming strong hydrophobicity. Core flooding tests revealed a flowback rate exceeding 50% and an average permeability recovery of 86%. SEM and EDS indicated that the gel formed nanoscale, tightly packed papillary structures on core surfaces, enhancing roughness and reducing water intrusion. The study demonstrates that gel fracturing fluid enhances structural stability, alters wettability, and mitigates water-blocking damage. These findings offer a new strategy for designing high-performance fracturing fluids with integrated drag reduction and reservoir protection properties, providing significant theoretical insights for improving hydraulic fracturing efficiency. Full article

To address issues of traditional coalbed methane (CBM) fracturing fluids (high displacement, weak sand-carrying, poor stability, severe coal seam damage), this study synthesized CO₂-responsive erucamide propyl dimethylamine surfactant (C₂₂ZEA, yield 99%), with molecular structure verified by ¹H NMR (400 MHz, CDCl₃) matching the target. Molecular simulation showed CO₂ protonates C₂₂ZEA into EA⁺: 1 wt% forms a simple micelle network, while 3 wt% enhances entanglement into a dense 3D network. Experiments indicated: 3 wt% solution reaches 160 mPa·s viscosity in 200 s under CO₂ (0.2 L·min⁻¹); 1.5–4.5 wt% solutions are pseudoplastic (n = 0.14–0.18), with G′ > G″ when concentration > 2 wt%; viscosity recovery rate > 95% after alternating shear (170 s⁻¹/10 s⁻¹); viscosity remains > 160 mPa·s after 1 h shear (170 s⁻¹) at 70 °C; gel breaks to 0.01–0.02 Pa·s in 15 min with N₂ at 45 °C; 1.0–3.0 wt% solutions meet non-toxic standards via EC₅₀/96 h LC₅₀. This study supports high-efficiency low-damage smart fracturing fluids, boosting CBM extraction efficiency. Full article

Multistage hydraulic fracturing significantly increased oil and gas production in the past two decades. After drilling, fracturing fluids are pumped into the formation to create fractures that provide pathways to the hydrocarbon. These fluids are usually viscous to provide the mechanical power to frack the formation and carry the proppants, which keep the fractures open. After fracking, the viscous gel should be broken to allow the flowback of the fluid to avoid formation damage. The key player in the fracturing fluid system is the polymer, which is responsible for the fluid viscosity of the system. All other additives are added to improve the polymer’s performance under different conditions and reduce formation damage. The formation damage appears as fine migration, residue precipitation, adsorption, and wettability alteration. All of these types are affected by the polymer types and behavior. This paper reviews the polymers used in fracturing treatments, their classifications, preparations, mechanisms, degradation behavior, and interactions with other fracturing fluid additives. It also covers their impact on the formation damage and environmental concerns raised with fracturing treatments, including spills and flaring activities. The paper discussed the cost of the main polymers used in fracturing fluids and suggested practical recommendations to select a robust, cost-effective polymer. By integrating these concepts, the review gives the researcher the necessary knowledge to design and prepare effective fracturing fluids tailored to a wide range of operational scenarios. Full article

The development of robust and efficient β-mannanases is key to advancing environmentally friendly industrial processes, such as guar gum fracturing fluid gel-breaking. Here, we report the identification and characterization of MG4, a novel thermotolerant and alkaliphilic β-mannanase mined from the Earth’s Microbiome database. The recombinant enzyme has a molecular weight of 63 kDa. MG4 displayed maximum activity at 65 °C and pH 9.0, and exhibited remarkable stability across a broad pH range (7.0–10.0). It retained over 80% of its activity after incubation at 50 °C for 1 h, and its activity was enhanced more than 40% by Mg²⁺ or Ca²⁺. Moreover, MG4 (20 mg/L) reduced the viscosity of guar gum fracturing fluid to <5 m·PaS within 30 min, outperforming ammonium persulfate (APS, 500 mg/L) which required 1 h, and produced 64.5% less insoluble residue. TEM imaging directly visualized the disruption of the guar gum polymer network by MG4, explaining its efficacy and suggesting reduced formation damage risk compared to chemical breakers. This work characterizes a highly promising biocatalyst whose thermostability, alkaliphily, efficient gel-breaking, low residue yield, and minimal formation damage potential position it as a superior, eco-friendly alternative for petroleum industry applications. Full article

Aiming at the problem that traditional fracturing fluids are prone to failure in coalbed methane (CBM) extraction under deep high-temperature and high-shear environments, this study proposes a method to prepare Zr-N-SiO₂ water-based crosslinkers using silane coupling agent-modified nano-silica as the inorganic framework combined with zirconium ions. The optimal fracturing fluid formulation is identified as 0.8 wt% Zr-N-SiO₂ and 0.4% HPAM thickener. This formulation exhibits rapid viscosity recovery under cyclic shear, retains a viscosity exceeding 140 mPa·s at 180 °C, and maintains long-term viscosity stability across 90–180 °C, with operational viability even at 180 °C. Its gel-breaking performance is controllable: with 0.08 wt% ammonium persulfate, viscosity drops to 2.91 mPa·s within 480 min. With 0.10 wt%, it decreases to 2.762 mPa·s in 400 min. This research aims to offer a novel technical approach for efficient and eco-friendly CBM extraction, with significant theoretical and practical value. Full article

This study focuses on investigating the damage characteristics and mechanisms of Slickwo clean fracturing fluid to the reservoir by using the deep coal seam in the Yan’an gas field as the research subject. During the experiment, fracturing fluids with varying A content were employed to displace coal and rock cores. The impact of these fluids on the permeability and pore structure of coal and rock was analyzed using a combination of nuclear magnetic resonance and high-pressure mercury injection technology. The findings indicate that the permeability damage rates of cores Y-1 and Y-2 post-displacement are 48.4% and 53.6% correspondingly, with the damage worsening as the agent A content increases. NMR data reveals that the fracturing fluid exhibits the highest retention in small pores, followed by medium-sized pores, and the least in large pores. The rise in agent A content enhanced the retention degree in individual pore throats and overall, increasing from 62.24% to 68.74%. The escalation in agent A content results in higher macromolecular residues, causing seepage channel blockages and enhancing the adsorption properties between fracturing fluid and coal rock. This phenomenon leads to inadequate backflow, primarily in smaller apertures. Simultaneously, the interaction between the gel breaker and clay minerals triggers particle migration, blockage, and expansion, consequently diminishing the permeability of coal and rock and inducing specific damages. Full article

Traditional petroleum engineering materials have problems such as single functionality and poor environmental adaptability in terms of lost circulation control and enhanced oil recovery. Supramolecular gels, with their dynamic reversible non-covalent network structure, demonstrate unique advantages in this regard. This paper classifies supramolecular gels into hydrogen bond type, metal coordination type, host–guest type, and electrostatic interaction type based on differences in crosslinking structures. It explains the construction principles and characteristics of each type of gel and analyses their application progress in petroleum engineering fields, such as lost circulation control in drilling, temporary plugging in fracturing, and profile control in enhanced oil recovery. It also discusses the advantages and disadvantages of different systems and future development directions. Research has shown that the molecular design strategy of supramolecular gels can effectively address technical challenges under complex conditions, offering new insights for oil and gas field development. Further optimization of their long-term stability and large-scale production technology is needed to advance their practical application. Full article

During drilling operations, lost circulation frequently occurs, leading to significant loss of drilling fluids which causes environmental damage and increasing drilling costs. To address the problem of fracture plugging, gel materials have emerged as an ideal solution due to stable physicochemical properties and excellent environmental compatibility. However, most existing gels exhibit poor stability and low mechanical strength under high-temperature conditions. To overcome these limitations, high-temperature-resistant phase-conversion stiffened dual-network hydrogel for oil-based drilling fluids was developed. Phase-conversion was realized by immersing synthesized double-network hydrogel in ethylene glycol (EG), polyethylene glycol (PEG), and glycerol (Gly), optimizing and enhancing its mechanical properties, followed by plugging performance evaluations. Experimental results demonstrated that the phase-conversion stiffened gels achieved significantly improved compressive strength and plugging efficiency at elevated temperature. The GC-MS results indicated that dehydration and reagent exchange occurred during immersion, with change in the solid content of the sample. After being treated by white oil at high temperature, the oil phase almost replaced the water phase in the gel. The results of ATR-IR confirmed the formation of hydrogen bonds in the gel. TGA data revealed that PEG enhanced the thermal stability of the gel, EG negatively affected thermal stability, and Gly had negligible influence. The enhancement in gel strength primarily stems from the increase in solid content caused by phase transformation. Dehydration and multiple hydrogen bonds formed between organic reagent molecules and polymer chains in the gel have a synergistic enhancement effect. Full article

Lost circulation, a prevalent challenge in drilling engineering, poses significant risks including drilling fluid loss, wellbore instability, and environmental contamination. Conventional plugging materials often exhibit an inadequate performance under high-temperature, high-pressure (HTHP), and complex formation conditions. To address that, this study developed a high-performance gel–resin composite plugging material resistant to HTHP environments. By optimizing the formulation of bisphenol-A epoxy resin (20%), hexamethylenetetramine (3%), and hydroxyethyl cellulose (1%), and incorporating fillers such as nano-silica and walnut shell particles, a controllable high-strength plugging system was constructed. Fourier-transform infrared spectroscopy (FTIR) and thermogravimetric analysis (TGA) confirmed the structural stability of the resin, with an initial decomposition temperature of 220 °C and a compressive strength retention of 14.4 MPa after 45 days of aging at 140 °C. Rheological tests revealed shear-thinning behavior (initial viscosity: 300–350 mPa·s), with viscosity increasing marginally to 51 mPa·s after 10 h of stirring at ambient temperature, demonstrating superior pumpability. Experimental results indicated excellent adaptability of the system to drilling fluid contamination (compressive strength: 5.04 MPa at 20% dosage), high salinity (formation water salinity: 166.5 g/L), and elevated temperatures (140 °C). In pressure-bearing plugging tests, the resin achieved a breakthrough pressure of 15.19 MPa in wedge-shaped fractures (inlet: 7 mm/outlet: 5 mm) and a sand-packed tube sealing pressure of 11.25 MPa. Acid solubility tests further demonstrated outstanding degradability, with a 97.69% degradation rate after 24 h in 15% hydrochloric acid at 140 °C. This study provides an efficient, stable, and environmentally friendly solution for mitigating drilling fluid loss in complex formations, exhibiting significant potential for engineering applications. Full article

To address critical technical challenges in coalbed methane fracturing, including the uncontrollable release rate of conventional breaker agents and incomplete gel breaking, this study designs and fabricates an intelligent controlled-release breaker system based on paraffin-coated mesoporous silica nanoparticle carriers. Three types of mesoporous silica (MSN) carriers with distinct pore sizes are synthesized via the sol-gel method using CTAB, P123, and F127 as structure-directing agents, respectively. Following hydrophobic modification with octyltriethoxysilane, n-butanol breaker agents are loaded into the carriers, and a temperature-responsive controlled-release system is constructed via paraffin coating technology. The pore size distribution was analyzed by the BJH model, confirming that the average pore diameters of CTAB-MSNs, P123-MSNs, and F127-MSNs were 5.18 nm, 6.36 nm, and 6.40 nm, respectively. The BET specific surface areas were 686.08, 853.17, and 946.89 m²/g, exhibiting an increasing trend with the increase in pore size. Drug-loading performance studies reveal that at the optimal loading concentration of 30 mg/mL, the loading efficiencies of n-butanol on the three carriers reach 28.6%, 35.2%, and 38.9%, respectively. The release behavior study under simulated reservoir temperature conditions (85 °C) reveals that the paraffin-coated system exhibits a distinct three-stage release pattern: a lag phase (0–1 h) caused by paraffin encapsulation, a rapid release phase (1–8 h) induced by high-temperature concentration diffusion, and a sustained release phase (8–30 h) attributed to nano-mesoporous characteristics. This intelligent controlled-release breaker demonstrates excellent temporal compatibility with coalbed methane fracturing processes, providing a novel technical solution for the efficient and clean development of coalbed methane. Full article

Channeling in cementing causes interlayer interference, severely restricting oilfield recovery. Existing channeling plugging agents, such as cement and gels, often lead to reservoir damage or insufficient strength. Oil-soluble resin (OSR) particles show great potential in selective plugging of channeling fractures due to their excellent oil solubility, temperature/salt resistance, and high strength. However, their application is limited by the efficient filling and retention in deep fractures. This study innovatively combines the OSR particle plugging system with the mature rapid filtration loss plugging mechanism in drilling, systematically exploring the influence of particle size and sorting on their filtration, packing behavior, and plugging performance in channeling fractures. Through API filtration tests, visual fracture models, and high-temperature/high-pressure (100 °C, salinity 3.0 × 10⁵ mg/L) core flow experiments, it was found that well-sorted large particles preferentially bridge in fractures to form a high-porosity filter cake, enabling rapid water filtration from the resin plugging agent. This promotes efficient accumulation of OSR particles to form a long filter cake slug with a water content <20% while minimizing the invasion of fine particles into matrix pores. The slug thermally coalesces and solidifies into an integral body at reservoir temperature, achieving a plugging strength of 5–6 MPa for fractures. In contrast, poorly sorted particles or undersized particles form filter cakes with low porosity, resulting in slow water filtration, high water content (>50%) in the filter cake, insufficient fracture filling, and significantly reduced plugging strength (<1 MPa). Finally, a double-slug strategy is adopted: small-sized OSR for temporary plugging of the oil layer injection face combined with well-sorted large-sized OSR for main plugging of channeling fractures. This strategy achieves fluid diversion under low injection pressure (0.9 MPa), effectively protects reservoir permeability (recovery rate > 95% after backflow), and establishes high-strength selective plugging. This study clarifies the core role of particle size and sorting in regulating the OSR plugging effect based on rapid filtration loss, providing key insights for developing low-damage, high-performance channeling plugging agents and scientific gradation of particle-based plugging agents. Full article