Search Results (27)

To address the industry challenge that the formation breathing effect in fractured formations narrows the safe mud weight window and significantly increases well control difficulty, this study employs two approaches—a self-designed experimental apparatus for the formation breathing effect and a combined finite-discrete element method (FDEM) numerical model—to systematically reveal the characteristic behavior and underlying mechanism of this effect, and to establish a prediction method for near-wellbore lost-circulation pressure that accounts for the breathing effect. The numerical simulation achieves high quantitative accuracy, with errors of less than 2.1% during the loss stage and less than 4.1% during the flowback stage. The results show that the typical signature of the breathing effect in fractured formations is a sustained loss of drilling fluid followed by rapid flowback, resulting in a pronounced reversible volume change in the wellbore. The intrinsic mechanism lies in the switching between fracture opening and closure triggered by the shift in the pressure differential between the wellbore and the formation. Parametric sensitivity analysis indicates that increasing wellbore pressure intensifies the breathing effect; formations with low fracture opening pressure, high porosity, and high permeability are more prone to severe breathing effects. Increasing the plastic viscosity and yield point of the drilling fluid can suppress the breathing effect, but careful management of the resulting increase in circulating friction and equivalent circulating density (ECD), which raises bottomhole pressure, is required. Field case calculations for a well in the Cameroon block show that, after improving the lost-circulation pressure calculation method to incorporate the breathing effect, the safe mud weight window can narrow by up to 0.03 g/cm³. This study advances the understanding of breathing effects in fractured formations and provides theoretical support for safe drilling within the narrow mud weight windows commonly encountered in such formations. Full article

To address wellbore instability and the technical challenges associated with high-density water-based drilling fluid loss control in deep shale gas formations of the Sichuan-Chongqing region in China, a novel nano-micro sealant designated CLG-Seal was synthesized via molecular structural optimization. The molecular structure of newly developed CLG-Seal exhibits distinct core–shell structural characteristics. The inorganic nano-silica constitutes the rigid core of CLG-Seal, which guarantees its plugging performance. The hydrophobically associating polymer which is coated on the surface of nano-silica constructs the flexible shell of CLG-Seal, endowing the CLG-Seal with excellent gel-forming capacity, adhesion film-forming capacity, deformability and perfect dispersibility. Transmission electron microscopy and scanning electron microscopy were employed to characterize the morphology of the CLG-Seal nanomicron-scale plugging agent. The sealing performance and underlying mechanisms of CLG-Seal were subsequently evaluated via particle plugging apparatus tests, displacement experiments, and etched glass micromodel simulations. Field trials conducted in the third section of Well WY3-2-3HF validated the application effectiveness of this agent in drilling fluid systems. The results indicate that the nano-micro sealant CLG-Seal exhibits a median particle size of D₅₀ is 146 nm, which can be modulated by adjusting the synthesis conditions. The nano-micro sealant CLG-Seal significantly mitigates fluid loss in low-permeability microfractures and fissures. Notably, a concentration of merely 3% is sufficient to achieve optimal nano-micro plugging performance. The results of the mechanism study indicate that while the CLG-Seal particles are close to each other, the polymer chains with flexible long chain structure which are coated on the surface of nano-silica constructs tend to be intertwined, forming a cross-linked network structure of gel film, thereby increasing the interaction between nano-micron particles and forming an impermeable plugging film. In addition, due to the nanoscale effect, the CLG-Seal has a strong tendency to adsorb onto the surface of shale rock through hydrogen bonding with the shale matrix. The hydrophobically associating polymer with high elastic modulus and excellent mechanical properties can enhance the pressure-bearing capacity of the filter cake through elastic deformation. Therefore, these nano-micron particles can form a strong sealing film on the filter cake and at the micropores of shale rock, thereby creating a dense mud cake on the outside of the shale formation. Field trial results demonstrate that the incorporation of the nano-micro sealant CLG-Seal into the drilling fluid for the third section of Well WY3-2-3HF reduced the PPA fluid loss to 4.6 mL. This value represents a substantial reduction compared to adjacent wells and signifies a remarkable improvement over the drilling fluids previously employed in the Longmaxi Formation of this block. Furthermore, the treated drilling fluid exhibited a superior filtration control pressure capacity of 10.5 MPa. The operation was completed successfully without any lost circulation or wellbore instability, and achieved a drilling footage of 42 h with an average penetration rate of 7.81 m/h. The mud weight was reduced by approximately 0.08–0.10 g/cm³ compared to offset wells. These results confirm the excellent application efficiency of the newly developed CLG-Seal in field operations. Full article

This study develops a fully coupled thermo–hydro–mechanical (THM) finite-element model to investigate fracture-induced fluid loss in depleted formations. To address the issue of assuming a homogeneous, unfractured medium, this approach incorporates the effects of pre-existing or induced fractures. By integrating thermoelastic stresses, fluid flow, and transient heat transfer, the model provides a more accurate simulation of coupled interactions, enabling a deeper understanding of stress evolution and fracture aperture behavior under temperature variations. The results show that pressure depletion reduces horizontal principal stresses in an approximately linear manner, with the minimum horizontal stress being more sensitive. The influence of wellbore pressure is concentrated in the near-wellbore region (r/rw < 2), where it increases circumferential stress at low azimuths and exhibits an almost linear positive correlation with fracture aperture. Fracture length has a negligible effect on pore-pressure variations (≤0.19 MPa) but increases circumferential stress at high azimuths and enlarges the aperture near the wellbore. Temperature effects, through thermoelastic stresses, dominate local stress redistribution, with the 90° azimuth showing the strongest sensitivity. Higher injection temperatures increase circumferential and radial stresses while decreasing near-wellbore aperture, whereas lower temperatures produce the opposite response. Although temperature differences cause only minor changes in pore pressure and far-field stresses, they exert first-order control on near-wellbore width evolution and the likelihood of lost circulation. These findings indicate that coordinated optimization of wellbore pressure, fracture dimensions, and injection temperature under depletion conditions is important for mitigating fracture-induced fluid loss and improving drilling safety and efficiency. Full article

The plugging of fractured gas reservoirs with severe lost circulation during oil and gas drilling and production has long been challenged by technical issues such as low plugging strength and short effective duration. This paper reports the preparation of a high-strength supramolecular gel plugging agent via micellar copolymerization based on the synergistic effects of hydrophobic association and hydrogen bonding. Systematic optimization determined the optimal synthesis formula: acrylamide (AM) 12%, 2-acrylamido-2-methylpropanesulfonic acid (AMPS) 2%, stearyl methacrylate (SMA) 0.4%, sodium dodecyl sulfate (SDS) 1.5%, and potassium persulfate 0.3%, with a reaction temperature of 60 °C. Performance evaluations revealed that the gel possesses a controllable gelation time (120 min) and excellent viscoelastic recovery properties. At a compressive strain of 87%, the compressive stress reached 1.43 MPa while maintaining structural integrity. Swelling behavior analysis indicated that the gel follows a non-Fickian diffusion mechanism, with its swelling process governed by the synergistic interplay of water molecule diffusion and polymer network relaxation. Core plugging experiments demonstrated that the gel achieved plugging efficiencies exceeding 95% for cores with permeabilities ranging from 0.18 to 0.90 μm², with a maximum breakthrough pressure gradient of up to 11.48 MPa/m. These results highlight the gel’s efficient and broad-spectrum plugging capability for fractured lost circulation zones. This preliminary study provides experimental foundations for the material design and performance optimization of supramolecular gel-based long-lasting plugging agents for severe lost circulation gas reservoirs, and further field-scale validation is required for engineering application. Full article

Lost circulation remains a persistent and costly challenge in drilling operations for oil, gas, and geothermal energy systems, particularly when wide fractures and cavernous formations are encountered. Although a wide range of lost circulation materials (LCMs) is commercially available, multiple laboratory studies report that many conventional products are unable to effectively seal fractures of approximately 5 mm width under controlled conditions. In contrast, recent investigations of shape memory polymer (SMP)-based LCMs have demonstrated successful sealing of fractures up to approximately 12 mm in width. This review examines recent advances in SMP-based LCMs as an emerging class of smart materials capable of overcoming geometric and operational constraints associated with drilling equipment, particularly bottom-hole assembly (BHA) components. Through thermomechanical programming, these materials are transformed into compact temporary shapes suitable for seamless circulation and are subsequently triggered by reservoir temperatures to recover permanent geometries up to an order of magnitude larger. Upon activation, these discrete elements function collectively as a hierarchical, jammed system. The resulting multiscale networks—comprising ladder-shaped elements, interwoven fibers, and granular particles—bridge large apertures, enhance mechanical interlocking, and achieve superior hydraulic isolation. Full article

Severe fluid loss in fractured, depleted reservoirs usually defeat conventional water-based drilling fluids (WBDFs), and rigid lost-circulation materials (LCMs) struggle to form durable, conformal seals. We report an eco-oriented colloidal gas aphron (CGA) fluid built from a nanostructured corn biopolymer (NCBP) and a biodegradable peanut-oil-derived surfactant, benchmarked against a reference fluid (RF) and aphron-only baselines (aphron based fluid, ABF). NCBP, produced by ball milling, was confirmed nanostructured by x-ray diffraction (XRD), Fourier transform infrared spectroscopy (FTIR), electron and atomic microscopies. Performance was evaluated from 25 to 90 °C for rheology, aphron stability and filtration at low temperature and low pressure (LTLP) of 100 psi and 25 °C, with post-test mud cake imaging. The optimized formulation, NCBP-2, showed stronger shear-thinning and higher gel strengths with heat, sustained stable and uniform aphrons for at least 120 min with foam persistence beyond 24 h, and delivered 3.0 mL filtrate with a 0.8 mm mud cake. These outcomes correspond to 60% less filtrate and approximately 73% thinner mud cakes than RF (7.5 mL; 3.0 mm), and about 14% and 33% improvements over the best ABF (3.5 mL; 1.2 mm). Micrographs revealed denser, finer-pored mud cakes, consistent with a mechanism in which deformable aphrons bridge micro-fractures while nano-scale polymeric fillers tighten the mud cake network. The results demonstrate decisive loss-control gains with temperature-tolerant rheology, supporting bio-based CGA fluids for depleted and fractured formations. Full article

Frequent drilling fluid lost circulation in the Kuqa foreland area of the Tarim Oilfield severely constrains drilling efficiency and safety. The complex formation structures and diverse lost circulation types in this region are compounded by a lack of systematic classification in existing studies and weak correlation between mechanism analysis and field plugging measures, leading to a deficiency in quantitative decision-making for lost circulation prevention and control. Based on lithology analysis, loss zone pressure differential calculation, well log interpretation, and core observations, this study establishes an integrated “formation–lithology–pressure” diagnostic and classification method for lost circulation. A systematic classification framework comprising five types of lost circulation channels and mechanisms was developed. Based on this, the dominant lost circulation types and characteristics of three typical vertical formations in the Kuqa foreland were clarified: ① The supra-salt sandy conglomerate formations (e.g., Q1x, N2k) are dominated by permeability loss, where the loss rate (V) and bottomhole pressure differential (ΔP) exhibit a strong positive correlation (V ∝ ΔP). On-site application of graded bridging plugging formulations achieved a first-attempt success rate of ≥90%. ② The salt–gypsum formations (E1-2km) are primarily characterized by induced fracture loss, with a weak correlation between V and ΔP and dynamic fracture opening/closing behavior. Conventional rigid plugging materials showed limited effectiveness, resulting in a first-attempt success rate of <50%. ③ The K1bs formation is dominated by vertically developed natural fracture loss, where V and ΔP also demonstrate a strong positive correlation. In a specific Keshen block, a power-law relationship between the fracture aperture (W) and loss rate was established (W = 0.26·V^0.62, R² = 0.98), providing a basis for predicting fracture aperture and optimizing plugging formulations, with a plugging success rate of ≥80%. The classification system and quantitative criteria developed in this study effectively link lost circulation mechanisms, dynamic characteristics, and engineering countermeasures, offering theoretical support and a decision-making framework for optimizing lost circulation prevention and control measures and improving success rates in the Kuqa foreland area. Full article

Lost circulation in oil-based drilling fluids (OBDFs) remains difficult to mitigate because particulate lost circulation materials depend on bridging/packing and gel systems for aqueous media often lack OBDF compatibility and controllable in situ sealing. A dual-precursor oil–water biphasic metal–organic supramolecular gel enables rapid in situ sealing in OBDF loss zones. The optimized formulation uses an oil-phase to aqueous gelling-solution volume ratio of 10:3, with 2.0 wt% Span 85, 12.5 wt% TXP-4, and 5.0 wt% NaAlO₂. Apparent-viscosity measurements and ATR–FTIR analysis were used to evaluate the effects of temperature, time, pH, and shear on MOSG gelation. Furthermore, the structural characteristics and performances of MOSGs were systematically investigated by combining microstructural characterization, thermogravimetric analysis, rheological tests, simulated fracture-plugging experiments, and anti-shear evaluations. The results indicate that elevated temperatures (30–70 °C) and mildly alkaline conditions in the aqueous gelling solution (pH ≈ 8.10–8.30) promote P–O–Al coordination and strengthen hydrogen bonding, thereby facilitating the formation of a three-dimensional network. In contrast, strong shear disrupts the nascent network and delays gelation. The optimized MOSGs rapidly exhibit pronounced viscoelasticity and thermal resistance (~193 °C); under high shear (380 rpm), the viscosity retention exceeds 60% and the viscosity recovery exceeds 70%. In plugging tests, MOSG forms a dense sealing layer, achieving a pressure-bearing gradient of 2.27 MPa/m in simulated permeable formations and markedly improving the fracture pressure-bearing capacity in simulated fractured formations. Full article

Severe lost circulation frequently occurs in deep and ultra-deep wells under high-temperature/high-pressure (HPHT) conditions and in fracture-cavity composite loss channels. Conventional lost-circulation materials (LCMs) often fail because of premature loss of mobility, insufficient residence in loss paths, and irreversible failure after solidification. Cement-based sealing systems, owing to their ability to plug large leakage channels and their cost-effectiveness, have become the mainstream solution. To improve their performance under extreme downhole conditions, recent studies have focused on base-cement design, reinforcement phases, and property regulation strategies-including the use of granular/fibrous/nanoscale additives for bridging reinforcement, rheology and thickening control to enhance injectability and residence, and chemical/functional modifiers to improve compactness and durability of the hardened matrix. Significant progress has been achieved in terms of HPHT resistance, densification design, regulation of rheological properties and thickening behavior, and self-healing/responsive sealing functions. However, most existing studies still focus on improving individual properties and lack a cross-scale, holistic design and unified mechanistic perspective for fracture-cavity coupled flow and long-term sealing stability. Distinct from previous reviews that mainly catalogue material types or discuss single-performance optimization, this review is framed by fracture-cavity composite loss channels and long-term sealing requirements under HPHT conditions, systematically synthesizes the material design strategies, reinforcement mechanisms and applicability boundaries of cement-based plugging systems, builds cross-scale linkages among these aspects, and proposes future research directions toward sustainable plugging design. Full article

Conventional polymer-based plugging materials often fail in deep-well environments due to passive thermal softening and network relaxation, which significantly compromise mechanical integrity and interfacial retention. To address this challenge, a novel smart Upper Critical Solution Temperature (UCST)-responsive hybrid microgel (SUPA) was synthesized for adaptive plugging in complex formations. The distinctive UCST responsiveness was conferred by incorporating N-(2-amino-2-oxoethyl)acrylamide (NAGA) and N-(2-hydroxypropyl) methacrylamide (HPMA) functional units into a robust dual-crosslinked network. Particle size analysis and oscillatory rheology in saline solution revealed the thermal activation mechanism: surpassing the critical temperature triggers the dissociation of intramolecular hydrogen bonds, driving polymer chain extension and volumetric expansion. This conformational transition induces dynamic network reinforcement, quantified by a significant ~7.5-fold increase in the storage modulus (G′). Consequently, the SUPA-enhanced fluid exhibited superior rheological performance, including a 4.4-fold increase in low-shear viscosity and rapid thixotropic recovery (ratio of 1.06). Crucially, lost circulation tests confirmed reliable and highly efficient sealing performance under harsh conditions of 150 °C and 5 MPa, even in fractured models. This study validates a design strategy centered on UCST-activated network reinforcement, offering a robust, mechanism-driven solution for severe lost circulation control in deep-well drilling. Full article

In response to the requirements of wellbore plugging and lost circulation control, this study designed and prepared a new type of thixotropic polymer gel system. The optimal formula was obtained through systematic screening of the types and concentrations of high molecular polymers, cross-linking agents, flow pattern regulators, and resin curing agents. Comprehensive characterization of the gel’s gelling performance, thixotropic properties, high-temperature stability, shear resistance, and plugging capacity was conducted using methods such as the Sydansk bottle test, rheological testing, high-temperature aging experiments, plugging performance evaluation, as well as infrared spectroscopy, nuclear magnetic resonance, and thermogravimetric analysis, and its mechanism of action was revealed. The results show that the optimal formula is 1.2% AM-AA-AMPS terpolymer + 0.5% hydroquinone + 0.6% S-Trioxane + 0.8% modified montmorillonite + 14% modified phenolic resin. This gel system has a gelling time of 6 h, a gel strength reaching grade H, and a storage modulus of 62 Pa. It exhibits significant shear thinning characteristics in the shear rate range of 0.1~1000 s⁻¹, with a viscosity recovery rate of 97.7% and a thixotropic recovery rate of 90% after shearing. It forms a complete gel at a high temperature of 160 °C, with a dehydration rate of only 8.5% and a storage modulus retention rate of 80% after aging at 140 °C for 7 days. Under water flooding conditions at 120 °C, the converted pressure-bearing capacity per 100 m reaches 24.0 MPa. Mechanism analysis confirms that the system forms a stable composite network through the synergistic effect of “covalent cross-linking—hydrogen bonding—physical adsorption”, providing a high-performance material solution for wellbore plugging in high-temperature and high-salt environments. Full article

Geothermal energy, recognized as a sustainable and clean resource, is playing an increasingly critical role in the global shift toward low-carbon energy systems. Nevertheless, the exploitation of fractured geothermal reservoirs is often impeded by severe lost circulation during drilling, where conventional plugging materials fail under high-temperature, high-salinity, and high-pressure conditions due to inadequate mechanical strength, poor thermal resistance, and lack of self-adaptive sealing behavior. In response, self-healing materials have emerged as an innovative strategy for developing intelligent lost circulation control technologies. Herein, we report a novel self-healing gel (XFFD) synthesized via inverse emulsion polymerization using acrylamide (AM), acrylic acid (AA), p-nitroblue tetrazolium (PNBT), and modified silica nanoparticles (PAS). The resulting material exhibits exceptional thermal stability, with decomposition onset above 356 °C, as determined by thermogravimetric analysis. Rheological and mechanical assessments reveal outstanding viscoelasticity, moderate swelling capacity (4.17-fold in deionized water), and a high self-recovery efficiency of 91.15%, accompanied by a bearing strength of 3.65 MPa. Mechanistic investigations indicate that the autonomous repair capability stems from dynamic non-covalent interactions—primarily hydrogen bonding and ionic associations—enabled by amide and carboxyl groups within the polymer network. Sand bed filtration tests under simulated geothermal conditions (150 °C, 8% salinity) demonstrate that XFFD forms a robust sealing barrier with significantly shallower invasion depth compared to conventional materials such as sulfonated asphalt and calcium carbonate. This work presents an effective self-healing gel system that ensures reliable wellbore strengthening and fluid loss control in challenging high-temperature, high-salinity geothermal drilling operations. Full article

To elucidate the lost circulation mechanism in naturally fractured shale, this study employs fluid seepage theory and fracture deformation theory, assumes the polymer-based drilling fluid system behaves as a Herschel–Bulkley (H–B) fluid, and develops a calculation model for lost circulation pressure that comprehensively incorporates fracture geometry, fracture stress state, drilling fluid properties, and the pressure differential between the wellbore and the formation. Research shows that the lost circulation rate of drilling fluid increases with greater initial fracture width, fracture deformation index, fluid consistency coefficient, yield stress, and pressure differential between the wellbore and the formation, while it decreases with increasing fracture radial extension length, fracture roughness, drilling fluid density, and normal stress on the fracture surface. The initial fracture width, fracture radial extension length, and fluid consistency coefficient have a significant influence on the lost circulation rate of drilling fluid. In contrast, the effects of the fracture deformation index and dynamic yield stress are relatively minor, indicating that they are not the primary controlling factors of fracture-induced lost circulation. Full article

With the advancement of oil and gas exploration and development technologies into deeper and ultra-deep reservoirs, complex geological conditions here render them highly susceptible to severe lost circulation. However, conventional bridging plugging methods struggle with large-sized lost circulation channels, while chemical gel plugging faces challenges such as low success rates and insufficient pressure-bearing capacity. To address this, a novel leak plugging method combining bridging and gel plugging is proposed herein. From structural stability and mechanical properties perspectives, the enhancing effect of nanomaterials on the gel system is revealed, and the synergistic mechanism of gel-bridging coupled plugging is elucidated. For the experimental setup, orthogonal experiments determined a base formulation with controllable gelation time: 10 wt% main agent, 2 wt% crosslinking agent, and a 1:3 pH regulator ratio. Introducing 1.0 wt% nanosilica enhanced gel properties, achieving 30 N strength at 120 °C aging. An optimized walnut shell bridging agent constructed the supporting skeleton, yielding a coupled plugging formulation with up to 8 MPa pressure for a 7 mm fracture. Lost circulation volume is controlled at 163 mL, outperforming single plugging methods. Research results demonstrate gel-bridging coupled plugging’s advantages for large fractures, providing new technical insights for severe lost circulation field construction. Full article

Lost circulation is a major challenge in oil and gas drilling operations, severely restricting drilling efficiency and compromising operational safety. Conventional bridging and plugging materials rely on precise particle-to-fracture size matching, resulting in low success rates. Self-healing gels penetrate loss zones as discrete particles that progressively swell, accumulate, and self-repair in integrated gel masses to effectively seal fracture networks. Self-healing gels effectively overcome the shortcomings of traditional bridging agents including poor adaptability to fractures, uncontrollable gel formation of conventional downhole crosslinking gels, and the low strength of conventional pre-crosslinked gels. This work employs stearyl methacrylate (SMA) as a hydrophobic monomer, acrylamide (AM) and acrylic acid (AA) as hydrophilic monomers, and graphene oxide (GO) as an inorganic dopant to develop a GO-based self-healing organic–inorganic hybrid plugging material (SG gel). The results demonstrate that the incorporation of GO significantly enhances the material’s mechanical and rheological properties, with the SG-1.5 gel exhibiting a rheological strength of 3750 Pa and a tensile fracture stress of 27.1 kPa. GO enhances the crosslinking density of the gel network through physical crosslinking interactions, thereby improving thermal stability and reducing the swelling ratio of the gel. Under conditions of 120 °C and 6 MPa, SG-1.5 gel demonstrated a fluid loss volume of only 34.6 mL in 60–80-mesh sand bed tests. This gel achieves self-healing within fractures through dynamic hydrophobic associations and GO-enabled physical crosslinking interactions, forming a compact plugging layer. It provides an efficient solution for lost circulation control in drilling fluids. Full article