Search Results (958)

Conventional chemical gel plugging materials often suffer from poor high-temperature stability and inadequate mechanical properties. To address these issues, this study developed a high-performance composite gel material using a multi-component hybrid crosslinking strategy. The material employs γ-methacryloxypropyltrimethoxysilane (MPTMS) as the silica source, which hydrolyzes in situ to generate SiO₂, thereby enhancing temperature resistance. Laponite nanoplatelets are incorporated as a toughening agent and physical crosslinking points, while a self-synthesized reactive microgel (BWL) serves as the organic crosslinking core. Through copolymerization with monomers such as acrylamide (AM) and methacrylic acid (MAA), a triple-crosslinked network structure is constructed. Compared with conventional gels, the synthesized hybrid crosslinked composite gel maintains a high storage modulus and loss modulus after aging at 140 °C and exhibits excellent tensile and compressive properties. Furthermore, the gel was processed into particle-based lost circulation materials with different particle sizes. High-temperature and high-pressure plugging experiments demonstrate that when using a mixed system of 40–60 mesh, 20–40 mesh, and 10–20 mesh gel particles with a total concentration of 2%, it can effectively seal highly permeable sand beds and fractures with apertures up to 5 mm. This meets the engineering requirements for lost circulation materials with high strength and high stability in deep, high-temperature formations. Full article

This research-related study examines the relevance of mud pulse telemetry (MPT) systems and their intersection with drilling performance, focusing on data transmission signal propagation performance and overall operation under different drilling parameters conditions, with an additional focus on drilling fluid flow rate and downhole pressure conditions. The novelty of this study lies in the investigation of adjustments to drilling operating parameters that could potentially improve the transmission of telemetry signals during drilling, in real time, without requiring mechanical or functional modifications to the MPT system itself. Improvements on transmission performance in situations where the data rate may be limited are also addressed, presenting an alternative through possible propagation velocity improvements to counterbalance it. A detailed chronological technical scientific literature review details important parts on analyses of pressure pulse propagation velocities focused on data transmission. A systematic experimental approach was developed and put into practice to evaluate the MPT systems in regard to tendencies on transmission performances, emphasizing pressure pulse propagation velocity. The laboratory-scale experiments were conducted at the Institute of Drilling Engineering and Fluid Mining (IBF) from the Technical University Bergakademie Freiberg (TUBAF), namely the Flow-loop Research Facility, to assess the impact of fluid flow rate (and subsequent pressure) on data transmission efficiency. Experimental results demonstrate that increasing the flow rate significantly speeds up signal propagation. In the performed experiments, for the mud siren configuration, increasing the flow rate from 15 to 25 m³/h improved the data transmission performance by approximately, at minimum, 18%, while for the positive mud pulse system, an increase in flow rate from 11.5 to 14 m³/h resulted in a propagation velocity rise of about 19%. The results also showed that higher concentrations of glycerin in the working fluid reduced the propagation velocity, confirming the influence of the fluid’s rheological properties on telemetry performance. At the end, in the presented case study, for 6 bps data rate configurations and for a transmission of a 40-bit string, it was demonstrated that the propagation time from downhole to the surface could potentially represent approximately 40% of the total time demanded for transmitting the desired information (generation plus propagation time). It was verified that an increment of 0.02208 m³/s (350 gpm) could lead to shortening eventual surveying procedures by 1–2 s, and that it could equally represent 1.137 bps. This is a relevant outcome, since, without any physical or functional alteration to the MPT system, one could have the data transmission performance improved, an approach not yet analyzed in the literature nor at the industrial park. These results, added to the detailed literature investigation and interaction with field personnel, indicate that the drilling fluid flow rate is a critical operational parameter affecting both the telemetry signal transmission speed and the overall drilling efficiency. Increasing the flow rate can reduce survey transmission time and decrease operational exposure to drilling hazards, such as drill string sticking. The results provide quantitative information applicable in optimizing measurement-drilling telemetry and help support the development of integrated drilling optimization strategies that balance drilling performance with real-time data transmission assurance in deep drilling operations. Full article

The rotary steerable system (RSS) is the core equipment for precise wellbore trajectory control in deep oil and gas drilling, and its performance is directly determined by the coordination and adaptability of the tool’s offset actuator and control platform. To overcome the limitations of complex control architectures and low positioning accuracy of conventional offset actuators for rotary steering drilling tools, a novel three hydraulic cylinder synchronous steering offset actuator driven by a drilling fluid rotary valve distributor, along with its dedicated control strategy, is proposed. Laboratory experiments and numerical simulations are performed to analyze the piston displacement characteristics of the three hydraulic cylinder under different drilling fluid flow rates and rotary valve rotational speeds. The results demonstrate that the proposed actuator exhibits controllable piston displacement behavior. The simulated and experimental data show consistent variation tendencies with a relative error of less than 8%, thus validating the reliability of the proposed numerical model. Increasing the flow rate from 1 to 1.5 L/s increases the cycle-averaged peak-to-peak piston displacement by 14.5 mm, while raising the rotational speed from 60 rpm to 120 rpm reduces it by 25.3 mm, corresponding to a dogleg severity variation of approximately 1.9–3.1°/30 m. Piston displacement deviations are mainly attributed to valve port machining tolerance, drilling fluid compressibility, pipeline pressure loss, and internal leakage, and these discrepancies are exacerbated as the rotary valve speed or flow rate increases. Finally, optimization strategies for improving synchronization performance are proposed, thereby providing theoretical and technical support for the engineering implementation and parameter optimization of the proposed actuator. Full article

As global oil and gas exploration extends to deep and ultra-deep formations, high-temperature and high-salt environments have become major challenges for drilling fluid viscosifiers. In this study, a hydrophobic associative polymer viscosifier, HATA, was synthesized via free-radical copolymerization using acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), sodium styrene sulfonate (SSS), and stearyl methacrylate (SMA) as monomers, and its structure was systematically characterized, while its performance and action mechanism in a 4 wt% bentonite base slurry were evaluated. The results show that the base slurry modified with 3 wt% HATA maintains an apparent viscosity retention ratio of 69.20% following 16 h of hot rolling at 180 °C, with an API filtration loss of only 7.2 mL, and its HTHP filtration loss is 73.72% lower than that of the blank bentonite slurry system; this viscosifier sustains effective viscosity and yield point of the drilling fluid system at 200 °C and in 36 wt% NaCl brine. HATA achieves viscosity enhancement and filtration control by regulating surface charges of bentonite particles, constructing stable three-dimensional networks, and stabilizing clay hydration layers, thus presenting a high-performance viscosifier formulation for high-temperature and high-salinity water-based drilling fluids with important theoretical and engineering application values. Full article

The treatment of spent drilling fluids generated during the drilling of technological wells for uranium production represents an important engineering and environmental challenge associated with high energy consumption, significant waste generation, and the need for rational water use under arid regional conditions. Conventional phase separation methods based on gravitational settling and chemical–mechanical treatment are characterized by limited process controllability, long processing times, and increased consumption of reagents and energy. This study proposes an energy-efficient and reliable hydrodynamic technology for the treatment of spent drilling fluids based on the formation of controlled turbulent structures without the use of mechanical drives. The research object comprised spent drilling fluids (SDFs) generated during the drilling of technological wells for uranium production in the southern regions of the Republic of Kazakhstan and the Kyzylorda region. Experimental investigations were carried out using a laboratory–pilot hydrodynamic disperser with variations in velocity gradient, treatment time, flocculant dosage, and suspension flow rate. A mathematical model linking hydrodynamic process parameters with phase separation kinetics and energy characteristics was developed. Model calibration by weighted nonlinear least squares yielded a stable parameter set with 95% confidence intervals, and model validation demonstrated good agreement between calculated and experimental data (MAPE 8.4%; maximum relative error 11.8%). It was established that the use of a hydrodynamic disperser provides separation efficiency of up to 90–95% under optimal operating conditions while reducing specific energy consumption and maintaining stable repeated-cycle performance within the investigated operating window. Experimental results confirm that implementation of the hydrodynamic technology enables a reduction in sludge volume by 40–60%, recovery of up to 60–80% of process water, and a significant decrease in waste requiring transportation and disposal. The obtained results demonstrate the high environmental and resource-saving efficiency of the proposed technology and its suitability for scaling and industrial implementation at facilities drilling technological wells for uranium production. The developed hydrodynamic approach can be considered an effective engineering platform for creating energy-efficient and sustainable systems for drilling fluid treatment in regions with limited water resources and remote industrial infrastructure. Full article

In this study, a thermally crosslinking clay-free weak gel water-based drilling fluid based on salt-responsive polymers and crosslinking agents was investigated as a promising and feasible strategy. Firstly, a salt-tolerant polymer was synthesized using N,N-dimethylacrylamide (DMAA), [2-(methacryloyloxy)ethyl]dimethyl-(3-sulfonopropyl)ammonium hydroxide (DMAPS), and acrylamide (AM). BPEI_10,000 was selected as the thermal crosslinking agent. The optimal crosslinking was achieved at 180 °C and 36% NaCl, with RMFL at 2.0% and BPEI_10,000 at 0.1%. Performance evaluation demonstrated that the crosslinking between RMFL and BPEI_10,000 could enhance the AV, PV, and YP of the RMFL(BPEI_10,000)/CF-WBDFs after aging at 180 °C for 16 h and reduce FL_API. The RMFL(BPEI_10,000)/CF-WBDFs exhibited appropriate shear-thinning behavior, viscoelasticity, thixotropy, and recoverable viscosity under high-temperature, high-salinity, and high-pressure conditions. Mechanism analysis revealed that RMFL and BPEI_10,000 could form a predominantly negatively charged, three-dimensional crosslinking weak gel at high temperatures. The crosslinking weak gel could form dense filter cakes, improving rheological properties and reducing filtration loss of CFWBDFs in high-temperature, high-salinity environments. This paper proposed a novel method to address the technical challenge of rheological performance failure of CFWBDFs, offering valuable insights for subsequent investigations. Full article

The Xinqiao Cu-S polymetallic deposit is located in the Tongling ore concentration area of the Middle-Lower Yangtze River metallogenic belt. The orebodies consist of skarn orebodies and stratiform sulfide orebodies, but the genetic link between them remains controversial. In this study, magnetite was used as a proxy to systematically constrain the hydrothermal evolution from the intrusion to the contact zone and further to the stratiform orebodies. A representative drill hole (E603) was logged, and samples were systematically collected from the Jitou pluton outward to the contact zone. Composite samples from the 8–28 m interval were crushed and prepared as resin mounts for integrated TIMA automated mineralogy, BSE textural observation, and in situ LA-ICP-MS trace element analysis. Five types of magnetite (Mt1 to Mt5) were systematically identified. Mt1 occurs as inclusions within feldspar in the quartz monzodiorite. It exhibits typical magmatic magnetite characteristics and contains grid-like ilmenite exsolution, indicating crystallization during the late magmatic stage. Mt2 is distributed in the interstices of magmatic minerals, commonly showing hematitization and replacement of ilmenite exsolution lamellae by titanite. Its trace element geochemistry displays magmatic–hydrothermal transitional features. Mt3–Mt5 in the skarn and stratiform orebodies are paragenetic with retrograde alteration minerals (e.g., epidote, chlorite, and actinolite) and sulfides, and are characterized by low Ti, Al, and V contents and high Mg, Mn, and Sn contents, indicating a hydrothermal origin. From Mt3 to Mt5, (Ti + V) and (Al + Mn) decrease, while Zn and Mn increase, accompanied by a decrease in the (Si + Al)/(Mg + Mn) ratio. This reflects a trend of decreasing fluid temperature and progressively enhanced wall-rock buffering. The Mg-in-magnetite geothermometer yields relatively consistent results for Mt1–Mt3, but anomalously high temperatures for Mt4–Mt5. This suggests that the elevated Mg activity in the fluid, caused by reaction with carbonate wall rocks, can significantly influence the calculated temperatures. Therefore, this geothermometer should be used cautiously for magnetite in the outer skarn zone and interpreted in combination with other temperature constraints. The textures, paragenetic mineral assemblages, and trace element characteristics of magnetite collectively reveal a continuous mineralization process linking the skarn and stratiform orebodies at Xinqiao, providing robust mineralogical and geochemical evidence for the contribution of Yanshanian magmatic–hydrothermal activity to the stratiform mineralization. Full article

Wellbore stability is one of the major challenges during drilling operations in shale gas formations. Drilling fluid seepage can significantly alter the pore pressure around the wellbore, thereby inducing wellbore instability. In this study, the Darcy pore fluid flow model was applied to both the mud cake and wellbore to predict pore pressure, which helps improve the accuracy of calculating collapse pressure and fracture pressure. Shale samples were collected from the Puguang Gas Reservoir, and their composition and physicochemical properties were systematically analyzed. The results indicate that the clay content in the formation can reach up to 35.5%, with distinct hydrophilic characteristics, and the maximum hydration expansion rate of the shale is 5.79%. The permeabilities of shale and mud cake were measured via the pore pressure transmission test. Specifically, shale samples from Sub-layer 1 exhibit the highest permeabilities for both rock and mud cake, which are 8.27 × 10⁻¹⁸ m² and 2.07 × 10⁻²⁰ m², respectively. In contrast, samples from Sub-layer 3 show the lowest permeability values, being 2.76 × 10⁻²⁰ m² and 1.66 × 10⁻²² m². The borehole tensile breakdown pressure and compressive collapse pressure were calculated using a poro-mechanical coupling model. The Sub-layer with the lowest cohesion strength after drilling fluid immersion presents the narrowest mud density window of 0.04 g/cm³, making it the most susceptible to wellbore stability failures; furthermore, the maintenance of wellbore stability requires strict control of the drilling mud density within the range. This study can provide guidance for accurate prediction of mud density window during drilling operations in shale formations. Full article

Reliable subsurface temperature estimates are crucial for most geoenergy projects, as they directly influence the properties of both rocks and fluids. They are particularly important in geothermal energy exploration, where errors in estimating the static formation temperature (SFT) can lead to significant misinterpretations, potentially resulting in incorrect classification of the geothermal resource. Various corrections are applied to bottom-hole temperatures (BHTs), with the Horner correction being the most widely used. In addition, empirical methods have been developed to improve accuracy at the local scale. In this study, maximum temperature values (Tmax) reported for deep exploration wells in the Sava and Drava Basins were compared to both Horner-corrected temperatures (HPCTs) and those recorded during drill-stem tests (TDST). In both basins, Tmax values frequently significantly diverge from HPCT measurements, emphasizing the limited reliability of Tmax for estimating subsurface temperatures. In the Sava Basin, 61% of wells show Tmax-HPCT differences greater than 10 °C, and in seven wells the discrepancy exceeds 20 °C. Similarly, in the Drava Basin, nearly half of the wells exhibit differences greater than 10 °C, with five wells showing deviations above 20 °C. In most cases, the reported Tmax values do not represent true maxima, so the linear regression was performed between Tmax and temperatures obtained from DST measurements, providing a basis for refining subsurface temperature estimates. Full article

In ultra-high-temperature and high-pressure gas well drilling, the use of high-density drilling fluid inevitably invades the reservoir, and perforation operations require penetrating this invasion zone to further connect the reservoir. This paper first conducts core drilling fluid invasion experiments, introducing two parameters—filter cake loss and core slice permeability—to derive the long-term invasion depth pattern of drilling fluid. Then, through three types of perforation target experiments (steel target, cement ring target, and sandstone target), the penetration performance of this type of perforating charge is evaluated. The results indicate that the total volume of drilling fluid invasion depends on the pore permeability characteristics of the core, with a fitted final invasion depth of 7.24 cm after 30 days of actual operation. The edge effect of the perforating gun causes significant differences in penetration depth and hole diameter at different phases, where the near-edge penetration depth and hole diameter are 1.86 times and 1.75 times larger than the far-edge, respectively. When the temperature resistance exceeds 200 °C/100 h, penetration depth and hole diameter decrease significantly with increasing temperature and time, and under 250 °C/170 h conditions, the firing rate markedly decreases. Using sandstone targets with identical strength and pore permeability conditions as a South China Sea ultra-high-temperature and high-pressure well block, the average penetration depth is 197 mm, far exceeding the thickness of the drilling fluid invasion zone. These experimental results provide theoretical support for perforation operations in a South China Sea ultra-high-temperature and high-pressure well block. Full article

When a H₂S-containing gas kick occurs during drilling, the formation fluid containing hydrogen sulfide is mixed into the drilling fluid. Drilling fluid containing hydrogen sulfide is prone to causing hydrogen embrittlement when it comes into contact with the drill string during the upward return process. However, research on the risk and timing of hydrogen embrittlement in drill pipes remains limited. This study constructed a risk area and hydrogen embrittlement time analysis model. The risk area and time of hydrogen embrittlement in the drill pipe of the Jinyue 402 well in Tarim Oilfield were analyzed using the constructed model. The results indicate that the concentration of hydrogen sulfide in the Jinyue 402 well is in the area where the corrosion rate of steel increases rapidly, and the partial pressure of hydrogen sulfide is higher than the critical partial pressure at which corrosion cracking occurs. Taking into account the pH of the drilling fluid, fluid flow rate, hydrogen sulfide partial pressure, drill pipe tensile stress, hydrogen sulfide concentration, and gas partial pressure, the high-risk area for hydrogen sulfide corrosion damage in the Jinyue 402 well is 0–1680 m. The predicted highest risk point location and hydrogen embrittlement time are at a well length of 280 m and 21 h. Further predictions were made for the hydrogen embrittlement length and time of the Tazhong 83 and Zhonggu 503 wells in the Tarim Oilfield. The maximum prediction errors for the hydrogen embrittlement position and time of the drill pipe in the three wells were 4.8% and 5.2%, respectively. This indicates that the model can be applied to wells with different geological conditions and hydrogen sulfide concentrations. Full article

To address the critical challenge of drilling fluid invasion in deep coalbed methane (CBM) reservoirs, this study provides novel insight into the micro-scale sealing mechanism and pore structure evolution by leveraging Low-Field Nuclear Magnetic Resonance (LF-NMR) as a quantitative probe. Unlike traditional macroscopic evaluations, we utilized dynamic NMR T₂ spectral analysis to decipher the synergistic behavior of a proposed “Bridging–Filling–Densifying” ternary sealing system, which integrates a nano-plugging agent, micro-fillers, and size-matched skeletal agents. The results demonstrate a significant improvement in sealing efficiency. The optimized hierarchical architecture reduced the NMR signal intensity of the invaded cores by over 99.8% under a differential pressure of 10 MPa, effectively eliminating fluid invasion channels. Crucially, the study reveals that while multi-scale particle size matching is the precondition for sealing, the mechanical rigidity of the skeletal particles is the determinant for maintaining filter cake integrity against high-pressure deformation. These findings elucidate the transition from a “macropore-dominated” structure to a “zero-detectable” sealed state, establishing a robust theoretical framework for designing non-damaging drilling fluids tailored to the complex geomechanics of deep CBM exploration. Full article

As global oil and gas exploration extends to deep and ultra-deep wells, high bottom-hole temperature is prone to deteriorating the gelation and rheological properties of water-based drilling fluids, which manifests as undesirable thickening or thinning at elevated temperatures. Therefore, the development of high-temperature resistant and stable drilling fluids is crucial for ensuring safe and efficient drilling operations, and the enhancement of high-temperature performance is typically achieved by adding drilling fluid treatment agents. The main objective of this study is to apply sodium acetate (SA) to drilling fluid systems, developing an economical and efficient non-polymer treatment agent with dual functions as a composite sodium-modifier and a rheological regulator. By-product sodium acetate (TRSA) is adopted to provide better cost-effectiveness while maintaining equivalent performance, and its universality across seven types of bentonites is verified. Three grades of sodium acetate were added to the bentonites as either composite sodium-modifiers or rheological regulators. After high-temperature aging, rheological parameters, including mud density, plastic viscosity (PV), yield point (YP), and gel strength, were measured in accordance with standard API methods. The results indicate that adding 2 wt.% TRSA to drilling fluid and subjecting it to hot rolling at 180 °C for 16 h keeps the viscosity at a high shear rate (1022 s⁻¹) nearly unchanged (from 36 mPa·s to 37.5 mPa·s), while increasing the viscosity at a low shear rate (5.11 s⁻¹) from 250 mPa·s to 1400 mPa·s, thereby effectively improving the shear thinning effect of the sodium-modified calcium-based bentonite water-based drilling fluid. Although TRSA increases the filtration loss from 21.8 mL to 30 mL, this can be reduced to 20–25 mL by co-extrusion sodium modification with sodium carbonate or by adding additional TRSA to sodium-modified bentonite. This study provides a novel perspective for significantly improving the gelation characteristics and rheological properties of bentonite suspensions at high temperatures through a special inorganic substance, while realizing resource reuse and cost reduction. Full article

Deepwater drilling operations face critical challenges including narrow pore-fracture pressure windows, wellbore instability, and environmental concerns from drilling discharge. This paper presents a comprehensive systematic review of Riserless Mud Recovery (RMR) technology, tracing its evolution from its conceptual origins to its current applications, critically analyzing its technical limitations, and identifying future research directions. A systematic literature review was conducted covering peer-reviewed journals, SPE/IADC conference proceedings, industry technical reports, and independent academic studies from 1990 to 2025. Databases searched included Web of Science, Scopus, OnePetro, and Google Scholar, supplemented by Derwent Innovation Index for patents. After screening over 100 publications, approximately 60 references were selected following a two-step process excluding vendor-only promotional materials. Key findings reveal the following: (1) RMR technology has evolved through three distinct hardware generations—flexible hose systems, steel-pipe return lines with tandem pumps enabling deepwater breakthrough to 1419 m, and hybrid riser configurations for conceptual designs beyond 3000 m; (2) documented field benefits include 70% drilling fluid reduction, 9 days’ time savings per well, and successful mitigation of shallow geohazards across more than 1000 global well applications; (3) integration with casing-while-drilling and managed pressure cementing has enabled record-breaking performance of 1710 m in a single run; (4) independent academic validation confirms fatigue mechanisms affecting mud return lines; (5) systematic failure mode analysis identifies critical reliability issues in suction hoses, seals, and control systems; (6) quantitative economic analysis shows RMR cost-effectiveness depends on water depth, geological conditions, and environmental regulations. RMR technology has matured into a reliable drilling solution, yet its continued evolution requires addressing hardware limitations, developing dedicated well-control protocols, expanding to ultra-deepwater and emerging applications, and integrating digitalization for real-time optimization. Full article

Horizontal well drilling is the mainstream technology for developing deep oil and gas resources. Engineering practice has demonstrated that hydraulic oscillators can solve the problem of the backing pressure of pipe strings and improve drilling efficiency. However, the design of excitation parameters for hydraulic oscillators is currently largely based on idealized friction models and does not fully consider the nonlinear characteristics of friction between the drill string and the formation, resulting in a lack of quantitative basis for parameter selection under different operating conditions. A series of laboratory friction tests was conducted to systematically characterize the dependence of interfacial friction behavior on sliding velocity across different combinations of drill string materials, drilling fluid systems, and rock lithologies. Based on the experimentally determined velocity–friction relationships, a drill string dynamic model incorporating a hydraulic oscillator was developed in which nonlinear frictional effects at the interface were explicitly represented. Using this modeling framework, parametric simulations were carried out to examine how variations in excitation amplitude and excitation frequency influence drag reduction performance under diverse operating conditions. The simulation results indicate that the contribution of drill string material to overall drag reduction effectiveness is comparatively limited, whereas drilling fluid type plays a dominant regulatory role. Oil-based drilling fluids significantly enhance drag reduction performance relative to water-based systems and exhibit greater responsiveness to adjustments in excitation parameters. Rock lithology exerts a pronounced influence on the effectiveness of drag reduction. When water-based drilling fluids are used, the overall performance ranks from highest to lowest as limestone, shale, and sandstone. In contrast, under oil-based drilling fluid conditions, the relative ordering shifts to shale, followed by sandstone, and then limestone. Excitation amplitude is the dominant parameter in enhancing drag reduction capability, and in most cases, its incremental effect exceeds that of excitation frequency; however, under certain specific operating conditions, increasing the excitation frequency can provide additional drag reduction benefits. Based on the above findings, a hydraulic oscillator excitation parameter design method was proposed that matches drilling conditions and formation characteristics by distinguishing between different drilling fluid environments and lithologies, with amplitude as the primary control parameter and frequency as a supplementary parameter. This method provides a theoretical foundation for the design of output parameters of hydraulic oscillators operating under diverse working conditions. Full article