ABSTRACT Accurately predicting temperature distribution in horizontal wells is essential for controlling bottom-hole temperatures and improving drilling efficiency. In this study, we developed a temperature field model based on energy conservation to examine the effect of frictional heat between the drill string and wellbore during horizontal drilling. The dynamic changes in the rheology of oil-based drilling fluids were also considered. Field data validated the model. The results indicate that frictional heat and fluid dynamics are critical factors in temperature prediction for horizontal wells. Findings also reveal that WOB significantly affects annular temperature distribution in the build section, whereas its effect on the vertical section is minimal. Increased rotary speeds enhance the frequency of contact between the drill string and wellbore, generating additional frictional heat and subsequently raising the annular fluid temperature. When WOB fluctuates between 50% and 200%, the associated change in bottom-hole temperature does not exceed 0.25%. When rotary speed adjusted within the range of 30% to 70%, it yields a temperature reduction rate of approximately 0.5%. The effect of various operational control parameters on the reduction of bottom-hole temperatures has been quantified. These parameters are ranked in terms of their effectiveness for temperature reduction as follows: inlet temperature > circulation rate > circulation time > drilling fluid density > WOB > rotary speed. These findings provide theoretical guidance for predicting bottom-hole temperatures and optimizing drilling strategies.

Abstract Barite is a commonly used weighting material in WBMs due to its high specific gravity and cost-effectiveness. However, variations in barite particle size distribution (PSD) can significantly impact the performance of drilling fluids, affecting properties such as filtration, rheology, and formation damage. This study investigates the influence of barite PSD on drilling fluid performance and explores the potential benefits of adding perlite to enhance these properties. This work aims to examine how different barite PSDs affect the filtration behavior, filter cake characteristics, and rheological properties of WBMs. Three barite grades with distinct PSDs were prepared using a combination of sieving and ball milling. These grades were then used to formulate three distinct drilling muds. The effect of perlite addition on these mud formulations was assessed. A series of laboratory tests, including particle size analysis, scanning electron microscopy (SEM), x-ray diffraction (XRD), and filtration tests, were conducted to characterize the materials and evaluate the drilling fluids' performance. The findings reveal that barite PSD significantly influences the drilling fluid properties. Smaller barite particles improved mud stability and reduced filtration issues, while larger particles increased filter cake thickness and permeability, potentially leading to greater formation damage. The addition of perlite to the mud formulations enhanced rheological stability, reduced filter cake thickness, and improved overall fluid performance. These results highlight the importance of optimizing barite PSD and incorporating suitable additives to develop more efficient and cost-effective drilling fluid formulations, ultimately contributing to safer and more economical petroleum extraction operations.

Significant thermal dynamics occur during both well construction and injection-production cycles in underground energy storage systems. Accurately determining the wellbore temperature distribution is crucial for optimizing drilling processes, enhancing energy storage efficiency, and evaluating reservoir thermal impacts. Existing measurement-while-drilling (MWD) temperature technologies are mostly limited to single-point measurements at the bottomhole, making it difficult to obtain a full wellbore temperature profile. This study proposes a novel microchip logging technology that achieves breakthroughs in power control and high-temperature resistance through optimized system architecture and workflow, with a maximum operating temperature of 160 °C and the ability to function continuously for 5 h under high-temperature conditions. Field tests successfully captured dynamic temperature data during the microchips’ circulation with the drilling fluid. The study established a temperature field model, applied the temperature measurement data to the model improvement, and analyzed the temperature evolution laws throughout the entire process, including bottomhole circulation, reaming operations, and microchip deployment. The model exhibits excellent consistency with the measured values, which is significantly higher than that of traditional models. The research indicates that this technology can be extended to temperature monitoring during cyclic injection and production processes in underground energy storage systems, supporting the design and operation of underground renewable energy storage (URES) systems.

The viscosity of drilling fluid directly affects the efficiency and safety of drilling operations. An appropriate viscosity ensures that the drilling fluid effectively carries drill cuttings and maintains wellbore stability. The conventional measurement of drilling fluid viscosity requires offline analysis after sampling, which cannot meet the requirements of real-time monitoring and adjustment of drilling fluid properties. Utilizing the non-contact measurement and real-time online detection features of ultrasonic waves, research on the drilling fluid viscosity detection method has distinct advantages. First, the fluctuation and attenuation characteristics of ultrasonic waves are analyzed to demonstrate that viscosity affects the propagation of ultrasonic waves in drilling fluid. Next, an experimental setup for ultrasonic drilling fluid viscosity measurement was constructed to obtain ultrasonic echo signals of drilling fluids with different viscosities and temperatures under different pipe diameters and to investigate the effects of various conditions on the propagation and attenuation of ultrasonic waves. Finally, a prediction model for drilling fluid viscosity based on support vector regression and the sparrow search optimization algorithm was established to achieve effective prediction of drilling fluid viscosity.

Performance of cationic asphalt particles synthesized through (CH3O)2SO2 displacement reaction on water-based drilling fluid properties and evaluation of their impact on wellbore stability in shale formation drilling

Thermal-setting resin-modified silica nanocomposites for self-regenerating and wide plugging distribution in water-based drilling fluids

One-step synthesized filtration control agent for high-temperature and high-salt water-based drilling fluid

The effect of hydration and fluctuating pressure in drifting conditions presents challenges to wellbore stability, impacting cost savings and safety in drilling operations. This study investigates the stability of thin mudstone-limestone and claystone interlayers in the East Baghdad oil field, introducing strength damage variables influenced by hydration and fluctuating pressure. Utilizing damage mechanics, elasticity, and joint strength theories, and accounting for matrix and weak plane failures, drilling fluid hydration reactions, and fluctuating pressures, a wellbore stability model is established. Key parameters such as wellbore trajectory, weak plane quantity, hydration time on collapse pressure, and tripping speed are examined, assessing stability under combined hydration and pressure effects. The results suggest optimizing wellbore trajectory, particularly the inclination angle, can reduce collapse pressure and increase fracture pressure, thus enhancing operational safety. Weak planes raise collapse pressure, reduce fracture pressure, and limit safe drilling directions, heightening wellbore instability and tripping challenges. Prolonged formation exposure to drilling fluids should be minimized, and fluid density optimized to widen the safe density window. Controlling tripping speed and monitoring wellbore pressure are critical to mitigating instability risks. Field validation confirms the model's accuracy, aligning predictive outcomes with real conditions and enhancing safe drilling fluid density and tripping speed guidance.

Oil sands drilling frequently contaminates water-based xanthan gels with highly viscous asphaltenes, collapsing their three-dimensional network and causing barite sag, high fluid loss and poor cuttings transport. Nitrogen-functionalized carbon quantum dots (N-CQDs) were hydrothermally synthesised from citric acid and 1-hexadecylamine and characterised by means of FT-IR, TEM and TGA. The concentration-dependent influence of N-CQDs (0–1.2 wt%) on gel viscoelasticity, microstructure and filtration properties was evaluated through rheometry, API and fluid-loss tests. At 0.01 wt% N-CQDs, the viscosity of the adsorbed oil phase dropped by 50% and the mean droplet diameter decreased from 247.7 µm to <100 µm. Consequently, the xanthan gel exhibited a significant enhancement in its mechanical strength and fluid loss performance. Wax-crystal growth was simultaneously inhibited, lowering the pour point by 6 °C. N-CQDs act as nanospacers that disrupt π-stacking of asphaltenes and hydrogen-bond to the polymer backbone, thereby restoring gel strength and sealing capacity. The work provides a sustainable, low-toxicity route to rejuvenate gel-based drilling fluids contaminated by heavy oil and facilitates their reuse in oil sands reservoirs.

ABSTRACT This study addresses the critical challenge of insufficient thermal stability in conventional starch‐based drilling fluid additives by developing an innovative inorganic polymer‐starch composite (polymerized ferrous sulfate‐potato starch, PFTS). Through optimized material synergy, PFTS significantly enhances high‐temperature resistance (up to 150°C) and hydration inhibition in eco‐friendly drilling fluids. Performance evaluations demonstrated a 29.3% reduction in fluid loss (from 12.6 to 8.9 mL) and improved rheological stability, with apparent viscosity decreasing from 7.0 to 4.9 mPa·s after 150°C aging. Multi‐scale characterization (TGA, XRD, FTIR) revealed that inorganic polymers form chemically cross‐linked networks with starch via metal ion coordination, restricting starch chain mobility and delaying thermal degradation. The composite further inhibited clay hydration by adsorbing onto clay surfaces, reducing interlayer spacing from 0.3353 nm (hydrated) to 0.3329 nm through synergistic physical barrier and charge modulation effects. Particle size analysis confirmed enhanced clay aggregation (median size increased from 6.1 to 11.0 µm), validated by mud ball experiments showing superior structural integrity under hydration stress. PFTS exhibited excellent compatibility with polyacrylamide and heteropolysaccharide systems, maintaining stable rheology and low friction coefficients under thermal aging. These results establish PFTS as a sustainable, dual‐functional solution for high‐temperature drilling operations, offering mechanistic insights for designing starch‐inorganic hybrids to overcome temperature limitations in water‐based drilling fluids. The composite's eco‐friendly profile and scalable synthesis further underscore its industrial viability.

Guar gum (GG) is a classic polysaccharide gel former in drilling fluids, but its native network is hindered by high water-insoluble residue, modest yield-point (YP) build-up and poor tolerance to temperature ≥ 120 °C and salinity ≥ 12 wt% NaCl. Here we transformed GG into a sulfonated guar gum (SGG) hydrogel via alkaline etherification with sodium 3-chloro-2-hydroxy-propane sulfonate. FTIR, EA and TGA corroborate the grafting of –SO3− groups (DS = 0.18), while rheometry shows that a 0.3 wt% SGG aqueous gel exhibits 34% higher YP/PV ratio and stronger shear-thinning than native GG, indicating a denser yet still reversible three-dimensional network. In 4 wt% Ca-bentonite mud the SGG gel film reduces API fluid loss by 12% and maintains YP/PV = 0.33 after hot-rolling at 120 °C, a retention 4.7-fold that of GG; likewise, in 12 wt% NaCl brine the gel still affords YP/PV = 0.44, evidencing electrostatically reinforced hydration layers that resist ionic compression. Linear-swell tests reveal shale inhibition improved by 14%. The introduced –SO3− functions strengthen inter-chain repulsion and water binding, yielding a thermally robust, salt-tolerant polysaccharide gel network. As a green, high-performance gel additive, SGG offers a promising route for next-generation water-based drilling fluids subjected to high temperature and high salinity.

ABSTRACT Drilling fluid plays many important roles in drilling operations of oil and gas wells, and the research on the rheological properties of drilling fluid to combat several challenges has gained attention in recent years. The environmentally friendly ternary copolymer drilling fluid viscosity reducer poly‐ISAD was designed and synthesized from itaconic acid (IA), sodium p‐styrene sulfonate (SSS), 2‐acrylamido‐2‐methylpropane sulfonic acid (AMPS), and dimethyl diallyl ammonium chloride (DMDAAC), and the key technical parameters were obtained based on the single factor experimental method. Then, the chemical structure, molecular weight, thermal stability, and microscopic morphology of poly‐ISAD were characterized by Fourier transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance (H 1 ‐NMR), gel chromatography (GPC), thermogravimetric analysis (TG‐DTG), and scanning electron microscope (SEM). Moreover, the poly‐ISAD was introduced into polymer‐based drilling fluid to study its rheological, filtration, and inhibition performances. As a result, the chemical structure of poly‐ISAD is consistent with the design, with excellent thermal stability, and the starting temperature for thermal decomposition of polymer molecular chains is 223°C. The weight average molecular weight ( M w ) and number average molecular weight ( M n ) of poly‐ISAD are 1.3396 × 10 6 g/mol and 7.1652 × 10 5 g/mol, respectively, and the 0.5 wt% poly‐ISAD solution shows a uniform network structure after freeze‐drying. Simultaneously, the poly‐ISAD had an excellent reducing effect on the viscosity of polymer‐based drilling fluids; specifically, the apparent viscosity (AV) and yield point (YP) of polymer‐based drilling fluids with 0.5 wt% poly‐ISAD were reduced by 40.5% and 70.5%. Meanwhile, the results show that the poly‐ISAD has excellent filtration and inhibition performances, and the API filtration volume (FL API ) of polymer‐based drilling fluids was reduced from 15.4 to 9.0 mL and 6.9 mL by 1.0 and 1.5 wt% poly‐ISAD, respectively. Besides, the mechanism of poly‐ISAD on the reducing viscosity effect of polymer‐based drilling fluids was studied via particle size analysis, zeta potential and SEM. The innovation of this study is that a novel viscosity reducer poly‐ISAD is designed and synthesized for use in high‐temperature oil and gas reservoirs; the performance and mechanism are investigated, which provided a theoretical reference for other research.

Maintaining the optimal properties of drilling fluids such as rheology, fluid loss, and mud cake thickness is crucial for wellbore stability, shale inhibition, and efficient drilling operations. However, the addition of shale swelling inhibitors can alter these properties either positively or negatively, necessitating a thorough investigation of their compatibility and effectiveness. In this study, polyethyleneimine (PEI) and potassium citrate (PC) were used as a shale swelling inhibitor, and their effect on water-based muds’ (WBM) compatibility and rheological properties were investigated and compared to the commercial inhibitor, potassium chloride (KCl). Compatibility tests were conducted to visually examine the water-based drilling fluid after the addition of the shale swelling inhibitors for over 24 hours. Mud density and pH were measured using a mud balance and a pH meter. The rheological properties were then determined using a rotational viscometer by taking readings at 600 rpm and 300 rpm. These are done to observe the flow behavior of the fluids and their abilities to maintain wellbore stability. Further, the fluid loss and mud cake thickness properties of the WBM formulations were determined using a dynamic fluid loss apparatus (HPHT API RP 13B-1) at a pressure of 1000 psi and 90°C. Based on this study, the PEI, PC, and KCl inhibitors were found to be compatible with the drilling fluid as their interactions affected the optical properties but not the physical state. Also, the rheological properties of the WBM were not highly compromised upon the addition of 1 v/v % KCl as a shale inhibitor. However, it was highly compromised upon the addition of 1 v/v % PEI and PC. It was found that cationic PEI interfered with the interactions and structures developed by the anionic components in the drilling fluid. This led to a 16% reduction in viscosity, a 21% reduction in yield point, and a 46% reduction in gel strength. The effects were also most adverse on the fluid loss characteristics of the fluids. In contrast, the use of 1 v/v % PC improved structural integrity and interactions and thus increased the viscosity and the yield point by 16 % and 68 %, respectively. The optimal balance was achieved with the formulation of 0.6 v/v % PEI: 0.4 v/v % PC, which effectively maintained and enhanced the desirable rheological properties of the WBM while maintaining favorable fluid loss control and mud cake formation. The PEI and PC interactions appear to have had a synergistic effect on the overall performance of the WBM.

Preparation and Mechanism of High Temperature Lubricant of Water-Based Drilling Fluids for Ultradeep Wells

The need for proper assessment of shale’s mechanical strength has gained much interest due to its implications on wellbore stability and hydraulic fracturing processes. During drilling and hydraulic fracturing, shale’s mechanical strength is impacted by chemical, mechanical, and geological phenomena as a result of shale’s direct interaction with drilling and fracturing fluids. In this work, the impact of dehydration and ionic strength on the uniaxial compressive strength of shale under various conditions was examined. Data suggest that shale’s moisture content has a substantial impact on its mechanical stability by lowering its Young’s modulus and compressive strength. Results also support the notion that Poisson’s ratio of shale exhibits little sensitivity to moisture changes. Data also showed that shale’s compressive strength decreased due to the invasion of ions. The potassium ion had a lesser effect on the compressive strength of shale than the sodium and calcium ions. The flow of ions weakens the rock’s structure, alters pore fluid composition, modifies the pore network configuration, weakens cementation between grains, reduces frictional resistance, and ultimately decreases strength. Results from this work should help in improving drilling fluid design, wellbore stability management, and the understanding of how shale behaves mechanically when exposed to salt solutions.

Polydopamine Nanospheres as a Plugging Agent in Water-Based Drilling Fluids

Biodegradable lubricants are essential to meet the demand for sustainable and environment-friendly drilling activities in the oil and gas industry. Lubricants play a major role in decreasing frictional, drag, and torque values that result from the interaction of drill bit, drill string, wellbore, or any other metal surfaces in contact, particularly in directional and extended-reach wells. Oil-based muds (OBMs) pose environmental challenges despite being the ideal lubricating mud. Alternate to this, water-based muds (WBMs) with biodegradable lubricants have promising benefits of lubricity, reduced pour point, increased flash point, and high thermal as well as oxidative stabilities. The potential of biodegradable additives like nano-sized lubricants and lubricants derived and modified from mineral oil and vegetable oil have been explored in this paper. It also highlights recent developments in enhancing drilling fluid using materials such as Henna extract, Wild Jujube Pit Powder (WJPP), and Okra powder. The performance of lubricity of mud is determined through the evaluation of the coefficient of friction directly, whereas the coefficient of adhesion and other mud properties also help to assess lubricity performances. The knowledge of the mechanisms of lubricants – like particle rolling, adsorption mechanism, and layered structure sliding ‒ is essential to find other materials that can possess the same mechanisms and enhance the lubricating property. Therefore, this paper focuses on reviewing the already existing and utilized biodegradable lubricants along with their results and future development ideas. By utilizing biodegradable materials having the properties of enhancing lubricity, the drilling operations can successfully result in less pollution to the environment, and switch to cost-effective and superior lubricating properties without compromising performance.

Fluid loss from borehole to formation is a prominent challenge that arises during drilling operations. Excessive fluid loss can lead to various issues such as formation damage, well-bore instability, reduced drilling efficiency, and increased operational costs. Chemical additives are used to improve drill-fluid sealing capacity and reduce fluid loss. Chemical additives create harmful impacts on the environment. This research presents an experimental study on coconut fiber to investigate its effectiveness as a fluid loss control additive. This study aimed to evaluate the potential of coconut fiber as a sustainable alternative to chemical additives. The experimental work involves the preparation of drilling fluids using varying concentrations of coconut fiber and evaluating their performance. Laboratory tests are conducted to measure filtration loss, rheological properties, resistivity, pH, mud weight, and sand content of samples. Four different concentrations of 0.5%, 1%, 1.5%, and 2% coconut fibers, particle sizes from 125 to 212 µm, are used in the test. The results of this study show that fluid loss is reduced with increasing concentration of coconut fiber. The coconut fiber acted as a bridging and sealing agent, creating thin, impermeable mud cake and minimizing fluid invasion. The findings highlight the potential of coconut fiber as an effective and sustainable option for mitigating fluid loss in drilling operation. The eco-friendly nature of coconut fiber adds to its appeal as a greener alternative in the petroleum industry. The outcomes of this research focus on environmentally conscious drilling practices and promote the practice of biodegradable materials in drilling operations.

Efficient extraction of subsurface resources relies heavily on the performance of drilling fluids, which necessitates constant innovation in their formulation. This study introduces a novel Polylactic Acid/Henna composite for significant enhancement of drilling fluid properties. The composites was characterized via Scanning Electron Microscopy (SEM), Energy-Dispersive X-ray Spectroscopy (EDS), and Fourier-Transform Infrared Spectroscopy (FTIR), confirming the uniform Henna particles dispersion in PLA matrix. The composite was added to water-based drilling fluids at concentrations of 0.5 wt%, 1 wt%, 2 wt%, 4 wt%, and 10 wt%, followed by rigorous evaluation of rheological and filtration performance. Experimental results demonstrated that fluids containing 2 wt% PLA/Henna composite exhibited the best performance, with a 32% increase in yield point and a 21% improvement in plastic viscosity compared to the base fluid. Furthermore, filtration volume decreased by 42%, while spurt loss was reduced by 35% due to improved filter cake formation. These quantitative improvements optimize fluid efficiency and minimize permeability, enhancing the ability to control fluid loss under simulated drilling conditions. Such enhancements promote better wellbore stability and operational reliability.

A novel experimental study aided with image analysis is used to investigate the flow characteristics such as penetration depth, fluid front velocity, kinetic to capillary transition and wettability behaviour of pressure-induced suspension flow through the dry-dense porous medium. For the three drilling fluid compositions adopted, the penetration response is predominantly governed by the particle size and the specific gravity of the additives present in the suspension. Due to the intricate particle migration/deposition process, the fluid front velocity decreases with an increase in space and time. By utilising fractal analysis, a unique transitional zone based on the linear relationship between the scaled fractal dimension and time is identified which partitions the permeation-dominated kinetic flow and capillary-dominated flow regimes. This transition holds relevance in understanding wellbore instability, drainage control and grouting. Finally, the quantification of the time-dependent contact angle from the fractal analysis revealed that due to the filtration process, the rheological properties of the suspension get altered which impacts the wettability characteristics.