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During ultra‐deep well drilling, the narrow safety density window of the drilling fluid makes it prone to complex conditions such as gas invasion. The high‐temperature and high‐pressure environment causes changes in the properties of the drilling fluid, making the gas invasion process highly covert and increasing the difficulty of well control. To address the challenge of accurately predicting gas migration velocity under gas invasion conditions in ultra‐deep wells, this study considers the impact of temperature and pressure on the properties of the drilling fluid. A fluid state equation for ultra‐deep wells was established. Based on the coupling effects of various parameters, a gas migration velocity model applicable to multi‐well types and multi‐factor coupling influences was developed. This model can calculate conditions for high‐viscosity drilling fluids and analyze the impact of different parameters on gas migration velocity in vertical and horizontal wells. Additionally, suppression methods for gas migration velocity in ultra‐deep wells were proposed. The study shows that an increase in drilling fluid viscosity, drilling fluid density, annular backpressure, and gas‐liquid density ratio reduces the gas content in the wellbore and suppresses the increase in gas migration velocity. An increase in formation permeability results in a higher gas content in the wellbore, promoting an increase in gas migration velocity. The impact of drilling fluid displacement on wellbore gas content is complex. To reduce gas migration velocity, high‐density and high‐viscosity drilling fluids can be used, along with appropriate increases in wellhead backpressure and drilling fluid flow rate, to prevent gas invasion. This study helps to better understand the multiphase flow characteristics in the wellbore under gas invasion conditions in ultra‐deep wells, ensuring the smooth operation of ultra‐deep well drilling.

Solid-free brine completion fluids, characterized by their exceptional reservoir protection capabilities and optimal rheological behavior, are highly desirable for applications in oil and gas reservoirs and have attracted significant attention in recent decades. However, as the core component of completion fluids, the viscosifier was prone to curling or even precipitating in high-temperature, high-density inorganic salt (divalent calcium) environments, leading to failure in thickening performance. In this study, a micro-crosslinked amphoteric viscosifier (i.e., A-DDAS) resistant to high temperature and calcium ions was synthesized via free radical copolymerization of N,N-dimethylacrylamide (DMAA), diallyl dimethyl ammonium chloride solution (DMDAAC), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), [2-(methacryloyloxy) ethyl] dimethyl-(3-sulfopropyl) ammonium hydroxide (SBMA), and pentaerythritol triallyl ether (APE). The molecular structure and physicochemical properties of the copolymer were systematically studied by NMR, FTIR, XPS, TGA and XRD. Rheological experiments demonstrated that calcium bromide brine containing A-DDAS copolymers exhibited outstanding shear-thinning behavior and rapid thixotropic recovery, essential for efficient wellbore cleaning and fluid displacement during completion operations. As the density of calcium bromide brine increased, more calcium ions shield electrostatic attractions between the cationic and anionic moieties along the copolymer backbone, thereby promoting full extension of the polymer chains and enhancing the binding energy with water molecules. After adding 1.0 wt% A-DDAS copolymer to a 1.75 g/cm3 calcium bromide brine and aging the mixture at 180 °C for 16 h, the completion fluids exhibited an apparent viscosity of 71 mPa·s, plastic viscosity of 64 mPa·s, and yield point of 7 Pa, which were significantly better than common viscosifiers (HE300 and Dristemp). Therefore, A-DDAS copolymers demonstrated exceptional thickening capacity and dynamic shear enhancement in high-temperature, high-density calcium bromide brine, notably rendering it ideally suited for deployment in completion fluids for deep and ultra-deep wells.

The exploitation of oil resources has now extended to ultra-deep formations, with depths even exceeding 10,000 m. During drilling operations, the bottomhole temperature (BHT) can surpass 240 °C. Under such high-temperature conditions, measurement while drilling (MWD) instruments are highly likely to malfunction due to the inadequate temperature resistance of their electronic components. As a wellbore temperature control approach, the application of thermal insulated drill pipe (TIDP) has been proposed to manage the wellbore temperature in ultra-deep wells. This paper developed a temperature field model for ultra-deep wells by coupling the interactions of multiple factors on the wellbore temperature. For the first time, five distinct TIDP deployment methods were proposed, and their corresponding wellbore temperature variation characteristics were investigated, and the heat transfer laws of the ultra-deep wellbore-formation system were quantitatively elucidated. The results revealed that TIDP can effectively restrain the rapid rise in the temperature of the drilling fluid inside the drill string by reducing the heat flux of the drill string. Among the five deployment methods, the method of deploying TIDP from the bottomhole upwards exhibits the best performance. For a 12,000 m simulated well, when 6000 m of TIDP are deployed from the bottomhole upwards, the BHT decreases by 52 °C, while the outlet temperature increases by merely 1 °C. This not only achieves the objective of wellbore temperature control but also keeps the temperature of the drilling fluid at the outlet of annulus at a relatively low level, thereby reducing the requirements for the heat exchange equipment on the ground. The novel findings of this study provide significant guidance for wellbore temperature control in ultra-deep and ultra-high-temperature wells.

With the continuous exploitation of deep oil and gas resources, the drilling depth keeps increasing, the sensitivity of the dynamic characteristics of the drill string in the downhole is exacerbated, and the impact of the high-temperature environment in the downhole on the dynamic characteristics of the drill string has also become non-negligible. Firstly, the temperature field distribution of ultra-deep wells is initially calculated using the energy conservation equation. Secondly, the influence of high-temperature environments in ultra- deep wells on the physical and dynamic parameters of drill strings is analyzed, and the finite element model for drill string dynamics in ultra-deep wells is improved and solved numerically. Finally, an example is used to compare and analyze the effect of underground high temperatures on the dynamic characteristics of drill strings. The results indicate that high temperatures significantly impact the movement characteristics of the drill string, while exerting minimal influence on dynamic load, particularly dynamic torque.

With continuous attenuation of reservoir pressure, an increasing number of self‐flowing wells in deep and ultra‐deep reservoirs will face flow cessation. Accurately predicting wellbore pressure drop and bottom‐hole flow pressure is key to determining flow cessation time. Existing commonly used pressure models in engineering exhibit poor prediction performance due to the limitation of high‐temperature and high‐pressure conditions in deep and ultra‐deep wellbores. This study first considers the effect of wellbore temperature and pressure on fluid properties, and corrects the crude oil high‐pressure physical parameters based on the measured results of high‐pressure PVT parameter. Second, a new liquid holdup model is established by fitting the fluid holdup derived from the back‐calculation of actual temperature and pressure from production wells. The new model is validated by an example well in Shunbei Oilfield to be significantly superior to other commonly used engineering models in predicting wellbore flow pressure. Finally, a prediction method for self‐flowing well cessation is established using nodal system analysis. Further validation using wells that experienced natural flow cessation in Shunbei Oilfield confirms < 3% error in predicting cessation reservoir pressure. This study develops a framework for predicting flow cessation in ultra‐deep wells, featuring a crude oil property correction model accounting for ultrahigh pressure/temperature effects, a revised liquid holdup model with field‐fitted coefficients, and an integrated pressure drop model coupled with nodal analysis to link reservoir inflow and wellbore outflow dynamics. These innovations address the limitations of conventional methods in ultra‐deep well conditions, enabling accurate flow cessation prediction.

The reinterpretation of deep wells and the reprocessing and interpretation of 115 km of industrial seismic lines can be used to update the geometry, depositional environments and tectonic evolution of the Carboniferous–Permian Brécy depocenter (southwest Paris Basin). The present-day geometry of the Brécy depocenter is controlled by several eastward dipping normal faults, some of which possibly connected to deep detachments that were active during the late Carboniferous–Permian history. It is estimated that the maximum thickness of the Brécy depocenter is 3900 m. The filling provides evidence for a thick late Carboniferous–lower Permian syn-rift stage overlain by a thin post-rift stage, probably similar to the tectonic evolution of the northeastward basins in the Lorraine region of France and Germany and thus attributed to the lower-middle Permian. The facies generally characterize lake environments, with occurrences of sediment supply attributed to fluvial, alluvial fan and delta fan deposits. They mainly display a retrogradational–progradational pattern during the syn-rift stage, and a retrogradational pattern during the post-rift stage. The Brécy area was part of a larger late Variscan basin during the latest Carboniferous–early Permian times in the northern Massif Central region.

In drilling ultra-deep wells, the drilling fluid circulation usually causes erosion damage to downhole casing and drilling tools. However, the extent and process of this damage to the downhole tools is intricate and less understood. In order to systematically evaluate and clarify this damage process for different types of drilling fluid contamination, this research uses a high-temperature drilling fluid damage device to simulate the damage caused to the casing/drilling tools by various drilling fluid under a field thermal gradient. The results show that the drilling fluid residues are mainly solid-phase particles and organic components. The degree of casing/tool damage decreases with an increase in bottom hole temperature, and the casing/tool is least damaged within a temperature range of 150–180 °C. Moreover, the surface of the casing/tool damaged by different types of drilling fluid shows different roughness, and the wettability of drilling fluid on the casing/tool surface increases with an increase in the degree of roughness. Oil-based drilling fluid have the strongest adhesion contamination on casing/drilling tools. In contrast, polysulfonated potassium drilling fluid and super-micro drilling fluid have the most potent erosion damage on casing/drilling tools. By analyzing the damage mechanism, it was established that the damage was mainly dominated by the abrasive wearing from solid-phase particles in concert with corrosion ions in drilling fluid, with solids producing many abrasion marks and corrosive ions causing a large number of pits. Clarifying drilling fluid's contamination and damage mechanism is significant in guiding the wellbore cleaning process and cutting associated costs.

The complex vibration directly affects the dynamic safety of drill string in ultra-deep wells and extra-deep wells. It is important to understand the dynamic characteristics of drill string to ensure the safety of drill string. Due to the super slenderness ratio of drill string, strong nonlinearity implied in dynamic analysis and the complex load environment, dynamic simulation of drill string faces great challenges. At present, many simulation methods have been developed to analyze drill string dynamics, and node iteration method is one of them. The node iteration method has a unique advantage in dealing with the contact characteristics between drill string and borehole wall, but its drawback is that the calculation consumes a considerable amount of time. This paper presents a dynamic simulation method of drilling string in extra-deep well based on successive over-relaxation node iterative method (SOR node iteration method). Through theoretical analysis and numerical examples, the correctness and validity of this method were verified, and the dynamics characteristics of drill string in extra-deep wells were calculated and analyzed. The results demonstrate that, in contrast to the conventional node iteration method, the SOR node iteration method can increase the computational efficiency by 48.2% while achieving comparable results. And the whirl trajectory of the extra-deep well drill string is extremely complicated, the maximum rotational speed downhole is approximately twice the rotational speed on the ground. The dynamic torque increases rapidly at the position of the bottom stabilizer, and the lateral vibration in the middle and lower parts of drill string is relatively intense.

The permeability (κ[m2]) of fractured crystalline basement of the upper continental crust is an intrinsic property of a complex system of rocks and fractures that characterizes the flow properties of a representative volume of that system. Permeability decreases with depth. Permeability can be derived from hydraulic well test data in deep boreholes. Only a handful of such deep wells exist on a worldwide basis. Consequently, few data from hydraulically tested wells in crystalline basement are available to the depth of 4–5 km. The permeability of upper crust varies over a very large range depending on the predominant rock type at the studied site and the geological history of the drilled crystalline basement. Hydraulic tests in deep boreholes in the continental crystalline basement revealed permeability (κ) values ranging over nine log‐units from 10−21 to 10−12 m2. This large variance also decreases with depth, and at 4 km depth, a characteristic value for the permeability κ is 10−15 m2. The permeability varies with time due to deformation‐related changes of fracture aperture and fracture geometry and as a result of chemical reaction of flowing fluids with the solids exposed along the fractures. Dissolution and precipitation of minerals contribute to the variation of the permeability with time. The time dependence of κ is difficult to measure directly, and it has not been observed in hydraulic well tests. At depths below the deepest wells down to the brittle ductile transition zone, evidence of permeability variation with time can be found in surface exposures of rocks originally from this depth. Exposed hydrothermal reaction veins are very common in continental crustal rocks and witness fossil permeability and its variation with time. The transient evolution of permeability can be predicted from models using fictive and simple starting conditions. However, a geologically meaningful quantitative description of permeability variation with time in the deeper parts of the brittle continental crust resulting from combined fracturing and chemical reaction appears very difficult. The permeability of continental crust varies with depth and time. A few deep boreholes drilled to 4–5 km depth provided transmissivity data from hydraulic well tests. We discuss the surprisingly complex conversion of transmissivity to permeability. We also present unique permeability data at different depths from a single 4 km deep borehole. We use exposed hydrothermal reaction veins to assess the permeability structure of the crust at depths >5 km and its variation with time.

Accurately determining the extraction volumes from various aquifers is crucial for effectively managing groundwater overexploitation. A key initial step in quantifying extracted groundwater volumes involves the classification of groundwater wells as either deep or shallow. This study evaluated 881,872 groundwater wells in the Hebei Plain, applying machine learning techniques to classify wells with unknown depths. Through the hydrogeological borehole data, the groundwater wells with known depth are divided into deep wells and shallow wells. Four machine learning algorithms—Random Forest, Support Vector Machine, Logistic Regression, and Naive Bayes—were employed to classify groundwater wells with unknown depths. The accuracy of these models was validated using known-depth well classifications. The results reveal that the Random Forest algorithm exhibited the highest performance among the models, achieving an overall accuracy of 91.23%. According to the Random Forest model, 43.51% of groundwater wells with unknown depths were classified as deep, while 56.49% were classified as shallow. The study also found that wells in areas where salinity exceeds 2 g/L are primarily deep groundwater wells. These findings provide valuable technical insight for groundwater well decommissioning and facilitate the assessment of extracted volumes of deep and shallow groundwater.