Search Results (96)

Developing ultra-high-temperature geothermal resources is challenging, as traditional drilling fluids, including foam systems, lack thermal stability above 160 °C. To address this key technical bottleneck, this study delves into the screening principles for high-temperature-resistant foaming agents and foam stabilizers. Through high-temperature aging experiments (foaming performance evaluated up to 240 °C and rheological/filtration properties evaluated after aging at 200 °C), specific additives were selected that still exhibit good foaming and foam-stabilizing performance under high-temperature and high-salinity conditions. Building on this, the foam drilling fluid system formulation was optimized using an orthogonal experimental design. The optimized formulations were systematically evaluated for their density, volume, rheological properties (apparent viscosity and plastic viscosity), and filtration properties (API fluid loss and HTHP fluid loss) before and after high-temperature aging (at 200 °C). The research results indicate that specific formulation systems exhibit excellent high-temperature stability and particularly outstanding performance in filtration control, with the selected foaming agent FP-1 maintaining good performance up to 240 °C and optimized formulations demonstrating excellent HTHP fluid loss control at 200 °C. This provides an important theoretical basis and technical support for further research and field application of foam drilling fluid systems for deep high-temperature geothermal energy development. 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

Some additives currently used to enhance drilling mud’s rheological qualities have a substantial economic impact on society. Carboxymethyl cellulose (CMC) and calcium carbonate (CaCO₃) are currently imported. Food crops have influences on food security; hence, this research explored the potential of utilizing cow bone powder (CBP), a bio-waste product and a renewable resource, as an environmentally friendly fluid-loss additive for drilling applications, in comparison with CaCO₃. Both samples (CBP and CaCO₃) were evaluated to determine the most efficient powder sizes (coarse, medium, and fine powder), concentrations (5–15 g), and aging conditions (before or after aging) that would offer improved rheological and fluid-loss control. The results obtained showed that CBP had a significant impact on mud rheology when compared to CaCO₃. Decreasing the particle size (coarse to fine particles) and increasing the concentration from 5 to 15 g positively impacted mud rheology. Among all the conditions analyzed, fine-particle CBP with a 15 g concentration produced the best characteristics, including in the apparent viscosity (37 cP), plastic viscosity (29 cP), and yield point (25.5 lb/100 ft²), and a gel strength of 16 lb/100 ft² (10 s) and 28 lb/100 ft² (10 min). The filtration control ability of CaCO₃ was observed to be better than that of the coarse and medium CBP particle sizes; however, fine-particle-size CBP demonstrated a 6.1% and 34.6% fluid-loss reduction at 10 g and 15 g concentrations when compared to respective amounts of CaCO₃. The thermal behavior of the Mud Samples demonstrated that it positively impacted rheology before aging. In contrast, after aging, it exhibited a negative effect where samples grew more viscous and exceeded the API standard range for mud properties. Therefore, CBP’s excellent rheological and fluid-loss control ability makes it a potential, sustainable, and economically viable alternative to conventional materials. This superior performance enhances the thinning properties of drilling muds in stationary and circulating conditions. Full article

The design of high-performance drilling fluid systems is of vital importance for the safe and efficient exploitation of natural gas hydrates. Incorporating appropriate nanoparticles into drilling fluids can significantly enhance drilling fluid loss control, wellbore stability, and hydrate inhibition. However, the combined effects of nanoparticles and conventional additives on hydrate inhibition in drilling fluid systems remain poorly understood. In this study, the influence of nanoparticles on hydrate formation was first evaluated in a base mud, followed by an investigation of their combined effects with common drilling fluid additives. The results demonstrate that hydrophilic nano-CaCO₃ particles exhibit hydrate inhibitory effects, with the strongest inhibition observed at 3.0%. Composite system tests (incorporating nanoparticles with sepiolite, filtrate reducers, and flow modifiers) revealed diverse effects on hydrate formation. Specifically, the combination of nanoparticles and sepiolite promoted hydrate formation; the combination of nanoparticles and filtrate reducers showed divergent effects. Mixtures of nanoparticles with 0.2% low-viscosity anionic cellulose (LV-PAC), carboxymethyl starch (CMS), and low-viscosity carboxymethyl cellulose (LV-CMC) inhibited hydrate formation, while mixtures with 0.2% sulfonated phenolic resin (SMP-2) and hydrolyzed ammonium polyacrylonitrile (NH₄-HPAN) accelerated hydrate formation. Notably, the incorporation of nanoparticles with 0.3% guar gum, sesbania gum, high-viscosity carboxymethyl cellulose (HV-CMC), or high-viscosity polyanionic cellulose (HV-PAC) resulted in the complete inhibition of hydrate formation. By contrast, the synergistic inhibition effect of the nanoparticle/xanthan gum (XC) composite system was relatively weak, with the optimal compounding concentration determined to be 0.3%. These findings provide critical insights for the development of drilling fluid systems in natural gas hydrate reservoirs, facilitating the optimization of drilling performance and enhancing operational safety in hydrate-bearing formations. Full article

Coalbed methane (CBM), a significant unconventional natural gas resource, holds a crucial position in China’s ongoing energy structure transformation. However, the inherent low permeability, high brittleness, and strong sensitivity of CBM reservoirs to drilling fluids often lead to severe formation damage during drilling operations, consequently impairing well productivity. To address these challenges, this study developed a novel low-damage, plugging, and anti-collapse water-based drilling fluid gel system (ACWD) specifically designed for coalbed methane drilling. Laboratory investigations demonstrate that the ACWD system exhibits superior overall performance. It exhibits stable rheological properties, with an initial API filtrate loss of 1.0 mL and a high-temperature, high-pressure (HTHP) filtrate loss of 4.4 mL after 16 h of hot rolling at 120 °C. It also demonstrates excellent static settling stability. The system effectively inhibits the hydration and swelling of clay and coal, significantly reducing the linear expansion of bentonite from 5.42 mm (in deionized water) to 1.05 mm, and achieving high shale rolling recovery rates (both exceeding 80%). Crucially, the ACWD system exhibits exceptional plugging performance, completely sealing simulated 400 µm fractures with zero filtrate loss at 5 MPa pressure. It also significantly reduces core damage, with an LS-C1 core damage rate of 7.73%, substantially lower than the 19.85% recorded for the control polymer system (LS-C2 core). Field application in the JX-1 well of the Ordos Basin further validated the system’s effectiveness in mitigating fluid loss, preventing wellbore instability, and enhancing drilling efficiency in complex coal formations. This study offers a promising, relatively environmentally friendly, and cost-effective drilling fluid solution for the safe and efficient development of coalbed methane resources. Full article

Microfluidic devices offer well-defined physical environments that are suitable for effective cell seeding and in vitro three-dimensional (3D) cell culture experiments. These platforms have been employed to model in vivo conditions for studying mechanical forces, cell–extracellular matrix (ECM) interactions, and to elucidate transport mechanisms in 3D tissue-like structures, such as tumor and lymph node organoids. Studies have shown that fluid flow behavior in microfluidic slides (µ-slides) directly influences shear stress, which has emerged as a key factor affecting cell proliferation and differentiation. This study investigates fluid flow in the porous channel of a µ-slide using computational fluid dynamics (CFD) techniques to analyze the impact of perfusion flow rate and porous properties on resulting shear stresses. The model of the µ-slide filled with a permeable biomaterial is considered. Porous media fluid flow in the channel is characterized by adding a momentum loss term to the standard Navier–Stokes equations, with a physiological range of permeability values. Numerical simulations are conducted to obtain data and contour plots of the filtration velocity and flow-induced shear stress distributions within the device channel. The filtration flow is subsequently measured by performing protein perfusions into the slide embedded with native human-derived ECM, while the flow rate is controlled using a syringe pump. The relationships between inlet flow rate and shear stress, as well as filtration flow and ECM permeability, are analyzed. The findings provide insights into the impact of shear stress, informing the optimization of perfusion conditions for studying tissues and cells under fluid flow. Full article

Controlling fluid loss during acid fracturing remains challenging, as acid may partially or completely leak into reservoir pores and fractures, preventing effective flow within the formation and thereby reducing stimulation effectiveness. The acid leakoff mechanism is fundamentally distinct from that of non-reactive pad fluid (fracturing fluid), with the most critical distinction manifested through wall-confined acid-etched wormholes formed during reactive flow processes, which exert a dominant influence on acid filtration behavior. To address this challenge, a modified dual-scale continuum model based on the Brinkman equation was developed. This model establishes a numerical simulation framework for acid fracturing–etching processes in dolomite reservoirs of the Xi Xiangchi Formation. The study systematically reveals acid leakoff patterns at fracture walls under the influence of operational parameters (injection rate, acid concentration, acid viscosity) and reservoir characteristics (porosity heterogeneity). For field operations, medium-viscosity acid initially enhances distal fracture communication, followed by viscosity reduction to promote non-uniform etching. Prioritizing acid concentration over injection rate optimizes fracture connectivity, while minimizing leakoff. In high-porosity reservoirs, process parameters require optimization through acid retardation and leakoff control strategies. Full article

In well drilling operations, interactions between drilling fluid water-based and the well-bore present significant challenges, often escalating project costs and timelines. Particularly, fractures (both induced and natural) and permeable zones at the wellbore can result in substantial mud loss or increased filtration. Addressing these challenges, our research introduces a novel coupled numerical model designed to precisely calculate fluid losses in fractured and permeable zones. For the permeable zone, fundamental variables such as filtration velocity, filtrate concentration variations, permeability reduction, and fluid cake growth are calculated, all based on the law of continuity and convection-dispersion theory. For the fracture zone, the fluid velocity profile is determined using the momentum balance equation and both Newtonian and non-Newtonian rheology. The model was validated against laboratory data and physical models, and adapted for field applications. Our findings emphasize that factors like mud particle size, shear stress, and pressure differential are pivotal. Effectively managing these factors can significantly reduce fluid loss and mitigate formation damage caused by fluid invasion. Furthermore, the understanding gathered from studying mud behavior in both permeable and fractured zones equips drilling personnel with valuable information related to the optimal rheological properties according to field conditions. This knowledge is crucial for optimizing mud formulations and strategies, ultimately aiding in the reduction of non-productive time (NPT) associated with wellbore stability issues. Full article

In this study, nanosilica-based polymers were synthesized and optimized for water-based drilling fluid applications using response surface methodology (RSM). The synthesis process involved the polymerization of methacryloyloxyethyl trimethyl ammonium chloride (DMC), methacrylic acid (MAA), and silane-modified nanosilica (KH570-SiO₂) under varying conditions of temperature, initiator concentration, and pH. Characterization by Fourier transform infrared spectroscopy (FTIR), nuclear magnetic resonance (¹H-NMR), thermogravimetric analysis, and optical microscopy confirmed the successful polymerization and incorporation of nanosilica while maintaining structural integrity and thermal stability. The reaction conditions were optimized using RSM with variables including the temperature, pH, and initiator concentration. The optimized conditions (70.9 °C, pH 7, and 0.57 wt.% initiator concentration) resulted in significant enhancements in drilling fluid performance, including a 46.0% reduction in filtration loss, a 28.6% decrease in coefficient of friction (CoF), and improved cutting-carrying capacity (YP/PV ratio). Post-reaction analyses demonstrated the thermal stability and reusability of the synthesized polymers under high-temperature conditions, confirming their applicability in field operations. This work highlights the potential of nanosilica-based polymers in improving drilling fluid performance, offering insights into optimization strategies and enhanced material stability. Full article

In order to prevent and control the problem of wellbore instability during the drilling process in shale formations, this study, based on the unique rheological properties, water solubility, and thermal stability of sodium alginate (SA), systematically investigated the rheological properties, filtration properties, and temperature resistance of sodium alginate-based drilling fluids before and after salt contamination. Additionally, it explored the wellbore stability and plugging mechanism of these drilling fluids in shale formations. The research shows that the BF + 0.4 wt% SA system significantly improves the rheological properties of the drilling fluid, effectively reduces the filtration loss, and exhibits good stability under the conditions of salt contamination and a high temperature of 100 °C. Sodium alginate binds to clay particles through hydrogen bonds and ionic bonds, enhancing the hydration and dispersion ability of the particles. The absolute value of its zeta potential reaches 39 mV and 37 mV before and after salt contamination, respectively, which is better than that of the control group, thus improving the colloidal stability of the drilling fluid. At the same time, through the moderate flocculation of clay particles, low-permeability filter cakes with filtration losses of 14 mL and 25 mL before and after salt contamination are formed, realizing a wellbore stability mechanism that combines physical plugging and chemical inhibition. Full article

Shale formations pose significant challenges to traditional drilling fluids, including issues such as fluid invasion, cutting dispersion, and shale swelling, contributing to wellbore instability. While oil-based drilling fluids (OBM) effectively address these challenges, concerns over their environmental impact and cost limit their widespread adoption. Nanoparticles (NPs) have emerged as a promising frontier for enhancing the performance of water-based drilling fluids (WBDFs) in shale applications. This study examines the effectiveness of water-based drilling fluids (WBDFs) enhanced with a nanocomposite of graphene oxide (GO) and nanocellulose (NC) compared to that of conventional WBDFs. The combination of GO and NC is chosen for its synergistic effects: GO provides enhanced mechanical strength and barrier properties, while NC serves to stabilize the dispersion and improve the compatibility with WBDF matrices. The modification with NC aims to optimize the interaction between GO and the drilling fluid components, enhancing performance in regards to shale inhibition and fluid loss control. This research involved the successful synthesis and characterization of a GO/NC nanocomposite, which underwent examination through FTIR, PSD, and SEM analyses. We also evaluated the filtration properties of water-based drilling fluids (WBDF) enhanced with a graphene oxide/nanocellulose (GO/NC) nanocomposite and compared the results to those for conventional WBDF. Filtration performance was assessed under both low-temperature, low-pressure (LTLP) and high-temperature, high-pressure (HTHP) conditions, and contact angle measurements were conducted to examine the wettability of the shale. The results demonstrated that incorporating GO/NC into the WBDF reduced the filtrate volume by 17% under LTLP conditions and by 23.75% under HTHP conditions, indicating a significant improvement in filtration control. Furthermore, the GO/NC-WBDF increased the hydrophobicity of the shale, as shown by a 61° increase in the contact angle. These findings suggest that GO/NC enhances the performance of WBDF, particularly in unconventional shale formations, by reducing fluid loss and improving wellbore stability. Full article

Polymer flooding has been gradually applied in Chinese offshore oilfields to enhance oil recovery (EOR). Injectivity loss during polymer flooding is a common issue that could cause lower displacement speed and efficiency, and eventually compromise the polymer flooding result. This paper presents a case study of a Chinese offshore field where injectivity loss issues were encountered in the polymer flooding project. A series of measures are applied to enhance the injectivity. The injectivity enhancement strategies are proposed and conducted from three main aspects, namely, (1) surface polymer fluid preparation; (2) downhole wellbore stimulation; and (3) reservoir–polymer compatibility, respectively. For the surface polymer fluid preparation, a series of sieve flow tests are conducted to obtain the optimal mesh size to improve the polymer fluid preparation quality and reduce the amount of “fish eyes”. The downhole wellbore stimulations involve oxidization-associated acidizing treatment and re-perforation. Polymer–reservoir compatibility tests are conducted to optimize the molecular weight (MW). Regarding the surface measures, the optimal filtration sieve mesh number is 200, which could reduce fish eyes to a desirable level without causing mesh plugging. After mesh refinement, the average injection pressure of the twelve injection wells decreases by 0.5 MPa. For the downhole stimulations, acidizing treatment are applied to six injection wells, which decreases the injection pressures by 6 to 7 MPa. For Well A, where acidizing does not work, the re-perforation measure is used and enhances the injectivity by 300%. Moreover, the laboratory and field polymer–reservoir compatibility tests show that the optimal polymer molecular weight (MW) is sixteen million. Proposed strategies applied from the surface, downhole, and reservoir aspects could be used to resolve different levels of injectivity loss, which could provide guidance for future offshore polymer projects. Full article

Water-based drilling fluids (WBDFs) cannot be effectively applied in long horizontal wells, such as shale gas wells, due to their high coefficient of friction (COF) and filtration loss that can strongly limit the efficient and environmentally friendly development of oil and gas resources. The objective of this study is the formulation of a WBDF characterized by ultra-low friction and ultra-low filtration properties, with a high-concentration polyepoxysuccinic acid (PESA) solution being utilized in the continuous phase. The research aims at the exploration of the feasibility of the method, the validation of the results, and the elucidation of the underlying mechanisms. The experimental results confirmed that the proposed WBDFs have excellent rheological properties, a COF of 0.016 and an API filtration of 0.4 mL. Microscopic analysis confirmed a direct and positive correlation between the macroscopic properties of the drilling fluids and their adsorption behavior at high PESA concentrations. This approach can be used to redesign traditional WBDFs and provide new possibilities to realize super performance in WBDFs that can be used to replace oil-based drilling fluids. Full article

To address the critical challenges of wellbore instability in deep coal seam drilling operations, this investigation developed an innovative organic–inorganic composite nanosealing agent (NS) through chemical modification of nano-silica. Advanced characterization techniques including Fourier Transform Infrared Spectroscopy, laser particle size analysis, and Scanning Electron Microscopy revealed that the optimized NS possessed a uniform particle distribution (mean diameter 86 nm) and enhanced surface hydrophobicity, effectively mitigating particle agglomeration. Systematic experimental evaluation demonstrated the material’s multifunctional performance: the NS-enriched drilling fluid achieved an 88.7% reduction in sand bed invasion depth and 76.4% decrease in filtrate loss at optimal concentration. Notably, comparative inhibition tests showed the NS outperformed conventional KCl and KPAM inhibitors, achieving 91.2% shale rolling recovery rate and 65.3% lower swelling rate than deionized water baseline. Core flooding experiments further confirmed superior sealing capability, with 2% NS addition attaining 88% sealing efficiency for low-permeability cores (0.5 mD) and establishing a 10 MPa breakthrough pressure threshold. Field implementation in the SSM1 well at Shenmu Huineng Liangshui Coal Mine validated the technical efficacy, the NS-enhanced drilling fluid system achieved 86.7% coal seam encounter rate with zero wellbore collapse incidents, while core recovery rate improved by 32.6% to 90.4% compared to conventional systems. This research breakthrough provides a scientific foundation for developing next-generation intelligent drilling fluids, demonstrating significant potential for ensuring drilling safety and enhancing gas recovery efficiency in deep coalbed methane reservoirs. Full article

Drilling fluids are vital in oil and gas well operations, ensuring borehole stability, cutting removal, and pressure control. However, fluid loss into formations during drilling can compromise formation integrity, alter permeability, and risk groundwater contamination. Water-based drilling fluids (WBDFs) are favored for their environmental and cost-effective benefits but often require additives to address filtration and rheological limitations. This study explored the feasibility of using vegetable waste, including pumpkin peel (PP), courgette peel (CP), and butternut squash peel (BSP) in fine (75 μm) and very fine (10 μm) particle sizes as biodegradable WBDF additives. Waste vegetable peels were processed using ball milling and characterized via FTIR, TGA, and EDX. WBDFs, prepared per API SPEC 13A with 3 wt% of added additives, were tested for rheological and filtration properties. Results highlighted that very fine pumpkin peel powder (PP_10) was the most effective additive, reducing fluid loss and filter cake thickness by 43.5% and 50%, respectively. PP_10 WBDF maintained mud density, achieved a pH of 10.52 (preventing corrosion), and enhanced rheological properties, including a 50% rise in plastic viscosity and a 44.2% increase in gel strength. These findings demonstrate the remarkable potential of biodegradable vegetable peels as sustainable WBDF additives. Full article