Search Results (103)

Formation damage caused by wellbore fluids remains a key concern in carbonate reservoirs, where pore plugging and filtrate invasion can severely reduce permeability. This study investigates the influence of filtrate-control components in cellulose-based polymeric fluids on the potential for formation damage in carbonate rocks and evaluates the performance of HPA starch as an alternative to cellulose, focusing on its comparative effects on formation permeability. Experimental tests were performed using Indiana Limestone cores to measure filtration behavior and permeability recovery after exposure to different polymeric solutions. The results revealed distinct mechanisms associated with each additive: PAC LV controlled fluid loss mainly by adsorption and pore plugging, while HPA starch formed more deformable and permeable structures. Glycerin, when used alone, did not induce formation damage but increased fluid viscosity, favoring more stable dispersion of the polymeric phase. Micronized calcite enhanced external cake consolidation through particle bridging. The combined use of PAC LV, glycerin, and calcite provided the most efficient filtration control and minimized formation damage. These findings contribute to understanding the isolated and synergistic roles of filtrate-control agents and support the design of optimized polymer-based fluids for well intervention and abandonment operations. Full article

Hydrocarbon exploration and extraction increasingly rely on drilling fluids that guarantee operating safety and efficiency, particularly in ultra-deep, high-temperature, and unconventional reservoirs. Traditional drilling fluids, especially for water-based muds (WBMs), have several problems, including excessive fluid loss, severe swelling in shale and instability in high-pressure/high-temperature (HPHT) conditions. Polymer nanocomposites (PNCs) are new types of drilling fluid additives that combine the vast surface area and reactivity of nanoparticles (NPs) with the structural flexibility and stability of polymers. This combination enhances rheology, reduces filtrate loss, and, most importantly, creates hydrophobic and pore-blocking barriers that prevent shale from swelling. This review highlights important improvements in drilling fluids with PNCs regarding exceptional rheological properties, low fluid loss, and improved suppression of the shale swelling. The particular focus was placed on the specific mechanisms and role that PNCs play in enhancing shale stability, as well as their responsibilities in improving rheology, heat resistance, and salt tolerance. Current advancements, persistent hurdles, and prospective prospects are rigorously evaluated to emphasize the scientific and industrial trajectories for the development of next-generation, high-performance drilling fluids. Moreover, the current challenges and future opportunities of PNCs in drilling fluids are discussed to motivate future contributions and explore new possibilities. Full article

This work examines the colloidal properties of clays sampled from two different locations in Ventzia basin processed as low-density solid additives for water-based drilling fluid applications. The obtained samples were mechanically processed to reach a size less than 2 cm. The material was then activated with 3 wt% soda ash without oven drying, keeping the moisture in environmental conditions to simulate industrial activation conditions. After laying for one month curing time, samples were oven dried at 60 °C and further ground to <120 μm. Two groups of samples were created mixing clays from Ventzia basin and additives. The first group contained clay, xanthan gum and sodium polyacrylate (PAA), while the second group contained clay, xanthan gum and sodium hexametaphosphate (SHMP). Standard tests were performed for the rheological behavior and filtration properties prior to and after dynamic thermal aging. Results obtained were compared with commercial clays from Milos and Wyoming used in drilling fluid systems, after thermally deteriorating also their properties. The obtained results revealed that the enhanced clays under study maintain excellent thermal stability. Notably, the top-performing formulation met the critical American Petroleum Institute (API) benchmark for filtrate loss (<15 mL) and exhibited a robust rheological profile at temperatures up to 105 °C, demonstrating its suitability for water-based fluid (WBF) applications. Full article

A novel fracture fluid based on a grafting polymer, PAM-co-PAMS-g-PEG (PAM-AMS-AEG), cross-linked by an organic Zr reagent was successfully produced via free-radical polymerization and an in situ cross-linking reaction with a high conversion rate of 96%, resulting in a low molecular weight of 250 kg·mol⁻¹. The effect of fluid constitution on the rheological behavior demonstrates that the P(AM₁₀-AMS₂-AEG_1.4)/[Zr]_0.35/TBAC_0.1 (PASG/[Zr]) aqueous solution has the best comprehensive performance. The PASG/[Zr] solution with a low critical associating concentration (CAC) of 0.15 wt% showed faster and steadier disassociation–reassociation processes. The synergy of ionic hydrogen bonds between sulfonic and amine groups and Zr⁴⁺-coordination results in steady interactions and fast reconstitution of association, leading to remarkable temperature resistance from 30 to 120 °C and a fast response during thixotropic processes. The PASG/[Zr] solution reduces the damage under high pressure based on the rheological characteristics and compatibility with sand, leading to a low filtration loss of the artificial cores. The PASG/[Zr] solution exhibits a good sand-carrying ability based on the rheological and interfacial performance, resulting in slow settlement and fast suspension. The filtration performance of the PASG/[Zr] fracturing fluid showed that it is not sensitive to the shearing rate, core permeability, or pressure. The comprehensive performance of the PASG/[Zr] fracture fluid is better than that of traditional guar fluid, suggesting that it can be used under various conditions for stratum protection and shale gas extraction. Full article

Efficient reinjection is critical for maintaining reservoir pressure and ensuring the sustainable development of sandstone geothermal systems. However, complex thermal–hydraulic–chemical (THC) interactions often lead to progressive permeability reduction, significantly impairing injection performance. This study systematically investigates the coupled effects of injection flow rate, temperature, and suspended particle size on permeability evolution during geothermal reinjection. Laboratory-scale core flow-through experiments were conducted using sandstone samples from the Guantao Formation in the Huanghua Depression, Bohai Bay Basin. The experimental schemes included graded flow rate tests, temperature-stepped injections, particle size control, long-term seepage, and reverse-flow backflushing operations. The results reveal that permeability is highly sensitive to injection parameters. Flow rates exceeding 6 mL/min induce irreversible clogging and pore structure damage, while lower rates yield more stable injection behavior. Injection at approximately 35 °C resulted in a permeability increase of 15.7%, attributed to reduced fluid viscosity and moderate clay swelling and secondary precipitation. Particles larger than 3 μm were prone to bridging and persistent clogging, whereas smaller particles exhibited more reversible behavior. During long-term seepage, reverse injection implemented upon permeability decline restored up to 98% of the initial permeability, confirming its effectiveness in alleviating pore throat blockage. Based on these findings, a combined reinjection strategy is recommended, featuring low flow rate (≤5 mL/min), moderate injection temperature (~35 °C), and fine filtration (≤3 μm). In addition, periodic backflushing should be considered when permeability loss exceeds 30% or a sustained injection pressure rise is observed. This study provides robust experimental evidence and practical guidance for optimizing geothermal reinjection operations. Full article

Polymers derived from renewable polysaccharides offer promising avenues for the development of high-temperature, environmentally friendly drilling fluids. However, their industrial application remains limited by inadequate thermal stability and poor colloidal compatibility in complex mud systems. In this study, we report the rational design and synthesis of epichlorohydrin-crosslinked carboxymethyl xylan (ECX), developed through a synergistic strategy combining covalent crosslinking with hydrophilic functionalization. When incorporated into water-based drilling fluid base slurries, ECX facilitates the formation of a robust gel suspension. Comprehensive structural analyses (FT-IR, XRD, TGA/DSC) reveal that dual carboxymethylation and ether crosslinking impart a 10 °C increase in glass transition temperature and a 15% boost in crystallinity, forming a rigid–flexible three-dimensional network. ECX-modified drilling fluids demonstrate excellent colloidal stability, as evidenced by an enhancement in zeta potential from −25 mV to −52 mV, which significantly improves dispersion and interparticle electrostatic repulsion. In practical formulation (1.0 wt%), ECX achieves a 620% rise in yield point and a 71.6% reduction in fluid loss at room temperature, maintaining 70% of rheological performance and 57.5% of filtration control following dynamic aging at 150 °C. Tribological tests show friction reduction up to 68.2%, efficiently retained after thermal treatment. SEM analysis further confirms the formation of dense and uniform polymer–clay composite filter cakes, elucidating the mechanism behind its high-temperature resilience and effective sealing performance. Furthermore, ECX demonstrates high biodegradability (BOD₅/COD = 21.3%) and low aquatic toxicity (EC₅₀ = 14 mg/L), aligning with sustainable development goals. This work elucidates the correlation between molecular engineering, gel microstructure, and macroscopic function, underscoring the great potential of eco-friendly polysaccharide-based crosslinked polymers for industrial gel-based fluid design in harsh environments. Full article

To address the issue of drilling fluid performance drop and wellbore instability induced by desorption between treatment agents and clay in the high-temperature environment of ultra-deep drilling, this study synthesized three organosilicon polymers (ADE, ADM, ADD) with different substituents. The study confirmed that the covalent bond significantly improved the high-temperature adsorption resistance of clay, which is closely related to the interface behavior of gels. Through rolling recovery, rheology, and filtration experiments for performance evaluation, these organic silicon polymers showed excellent high-temperature performance: the shale rolling recovery rate exceeded 80% at 210 °C, and the filtration loss was reduced to 14 mL, with a reduction rate of 53.3%. The adsorption capacity of the three polymers on clay remained unchanged from 150 °C to 210 °C, among which the adsorption amount of trimethoxy groups stabilized at 8–11 mg/g after 150 °C. The adsorption capacity of ethoxy groups increased by 7.9% at 150–210 °C. The adsorption capacity of dimethoxy groups with methyl steric hindrance increased by 28.1% at 150–210 °C. These results indicate that covalent bonds effectively enhance the high-temperature adsorption of clay, allowing for polymer molecules to firmly anchor on the clay surface at high temperatures. This breakthrough overcomes the limitations of traditional inhibitors in high-temperature desorption, and provides a valuable reference for the preparation of high-temperature adsorption resistant functional materials in water-based drilling fluid gel systems. Full article

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