Fluid Intrusion Research Articles

Coupling mechanism of trace elements and maceral in medium and high sulphur coal in the Jurassic terrestrial environment of Zhongyuan mine in the Hengshan mining area and adjacent areas

ABSTRACT Considering the urgency of resource utilization and environmental protection, the geochemistry of anomalous trace transition metal elements in coal formed in terrestrial environments has been studied using methods such as inductively coupled plasma atomic emission spectrometry analysis, electron probe micro-area analysis, sequential chemical extraction procedures, and correlation analysis. The results indicate that minerals in the coal samples included pyrite, kaolinite, quartz, dolomite, calcite, and celestite. Furthermore, compared with the average values of coals in China and the upper continental crust, the coal samples were rich in transition metal trace elements such as Ni, Cr, and Sr and were deficient in Be, Cd, Cu, Co, Ga, Mo, Sb, Tl, V, Zn, and Ti. We found that Ni preferentially occurred in the organic matter over minerals, while Cr primarily bonded with sulfide minerals and to a lesser extent with the iron-manganese oxide minerals. Sr had a low correlation with organic matter but adhered to clay minerals and celestite. Ni enrichment in coal samples was the result of terrigenous input, while the Cr enrichment was related to intrusion of magmatic hydrothermal fluids. Sr enrichment was caused by the presence of SO4 2- in the terrigenous debris and the influence of Sr-rich water underground.

Stability Characteristics of Natural Gas Hydrate Wellbores Based on Thermo-Hydro-Mech Modeling

During drilling operations, drilling fluids undergo heat exchange with hydrate-bearing formations. The intrusion of drilling fluids affects hydrate stability, leading to variations in stress fields around a wellbore and complex scenarios such as borehole collapse, significantly hindering the efficient development of natural gas hydrate resources. This study establishes a thermo-hydro-mech model for hydrate-bearing inclined wells based on linear thermoelastic porous media theory and an appropriately high inhibitive drilling fluid temperature. This research reveals that drilling should follow directions of minimum horizontal stress or perpendicular to maximum horizontal stress during drilling operations to control wellbore stability. Hydrate decomposition due to factors like drilling fluid pressure and temperature can rapidly reduce the strength of low-saturation formations, significantly increasing the risk of wellbore instability. Therefore, selecting appropriate highly inhibitive and low-temperature drilling fluids during drilling operations helps control hydrate decomposition and reduce fluid intrusion, thereby mitigating risks associated with wellbore instability.

Preparation of zwitterionic polymer and its application for dual-functional inhibition in deepwater drilling

During deep-water drilling operations, due to the conditions with low temperature and high pressure in the wellbore, methane hydrate can be easily formed in the presence of methane and plug the wellbore. In addition, the deep-water sediments are dominated by clay-silty with weak cementation, so well instability may be occurred due to clay hydration. In order to inhibit hydrate formation and clay hydration in deepwater drilling, a zwitterionic polymer AADV was synthesized through quaternary copolymerization of AM/AMPS/DMDAAV/VAC. The hydrate inhibition performance of AADV was evaluated in a high-pressure reactor chamber, and the results showed that AADV can delay the hydrate formation time from 330 min in pure water to 2204 min, indicating an excellent inhibition effect of hydrate formation. Meanwhile, 1 % AADV can significantly reduce the linear swelling rate of the calcium-based bentonite to 3.69 % for 10 h and increase the rolling recovery rate to 94.7 %, suggesting an excellent inhibition effect on clay hydration. The mechanism of dual-functional inhibition of AADV was further analyzed. The zwitterionic group in AADV and the hydrophilic amide group can strongly adsorb the water molecules through a strong hydration effect and the hydrogen bonding effect, respectively, which contributes to destroy the water molecules cage structure, and thus to suppress the hydrate formation. Besides, AADV can effectively obstruct mass transfer of methane molecules by increasing the viscosity of the aqueous phase and absorbing on the hydrate surface, leading to hydrate formation inhibition. For the inhibition of clay hydration, the SEM and XRD results proved that AADC inhibits the clay hydration through the film-forming effect. In addition, the contact angle of Na-Bent/AADC composite reached to 55.68° when the polymer concentration increased to 2 %, suggesting that the hydrophobicity of Na-Bent surface can be enhanced after AADC treatment. AADV can wrap around clay particles and form hydrophobic film through adsorption and intercalation, preventing the intrusion of external fluids and inhibiting clay hydration.

Synthesis and performance evaluation of polymer-ceramic composite microcapsules as reservoir protectant for natural gas hydrate drilling.

Natural gas hydrate is a promising unconventional natural gas source due to its high energy density and huge global reserves. During exploitation, the drilling fluid may invade the hydrate formation and induce hydrate decomposition, causing reservoir damage. Herein, a novel reservoir protectant made by bio-degradable temporary plugging material (BDTPM) was developed in the form of polymer-ceramic composite microcapsules. As an additive to the drilling fluid, the BDTPM can minimize drilling fluid intrusion by plugging the reservoir during drilling and afterwards maximize permeability recovery by degrading the material. The particle size distribution was in the range of 1-130μm. The optimal mass ratio between modified ceramic particles, ethyl cellulose and epoxy resin was found to be 4:2:1. The plugging rate was 100% when ethyl cellulose and epoxy resin were mixed to coat the ceramic particles to form BDTPM, and the plugging performance was the best. At a temperature close to the typical hydrate reservoir environment (5°C), 0.02 wt% low-temperature complex enzyme can degrade BDTPM, and the permeability recovery rate is 64.66%. The efficient reservoir protectant developed in this work could play an important role in the successful drilling of natural gas hydrate reservoirs.

Hydrothermal activity near the Permian–Triassic transition in the south‐western Ordos Basin, China: Evidence from carbonate cementation in Upper Permian sandstones

ABSTRACTCarbonate cementation in the Upper Permian sandstones informs the timing and temperature of hydrothermal activity in the south‐western Ordos Basin. This study presents a detailed examination of these hydrothermally influenced carbonate cements, constraining their age, carbonate diagenesis and relationship with regional geodynamic evolution. Sedimentological analyses demonstrate the development of deltaic plain and front sand bodies in the study area, which resulted in interbeds of volcanic matrix‐rich sandstones with matrix‐free sandstones. Petrography and electron microprobe analysis reveal four carbonate mineral growth phases of matrix‐free sandstones in the following sequence; scarce pure siderite, scarce Mg‐rich siderite, abundant blocky calcite and moderately abundant grain‐replacing calcite. The fluid inclusion data show anomalies of homogenization temperature of blocky carbonate cements during early diagenesis, over a wide range of ca 148 to 228°C. In addition, blocky carbonate cements show low δ13C (−5.9 to −13.1‰ Vienna PeeDee Belemnite) and δ18O (clustered tightly from −12.4 to −14.6‰ Vienna PeeDee Belemnite) values, interpreted to result from elevated temperatures during cementation, associated with activation of basement faults and concomitant hydrothermal fluid intrusion triggered by oceanic crust subduction in the south‐west margin of the Ordos Basin. Using in situ calcite U–Pb geochronology, the timing of hydrothermal activity was constrained to ca 247.0 ± 11 to 248.2 ± 4.7 Ma. This work provides a case study for applying intergranular calcite U–Pb dating to determine the absolute timing of fluid flow in sedimentary basins, offering tremendous potential to capture snapshots of various diagenetic evolution stages in sediments. The proposed diagenetic model can also provide new insights and understanding regarding hydrothermally influenced sediments. More importantly, hydrothermal activity may have commenced earlier than previously thought. The North Qinling Orogen uplift and associated Mianlue oceanic crust subduction may have begun at the Permian–Triassic transition with a protracted hydrothermal event in the south‐western Ordos Basin.

Hydrocarbon Accumulation and Overpressure Evolution in Deep–Ultradeep Reservoirs in the Case of the Guole Area of the Tarim Basin

Usually, deep oil and gas accumulation is often controlled by strike–slip faults. However, in the Tarim Basin, deep Ordovician oil and gas accumulations are also found in areas far from the fault zone. The process of oil and gas accumulation in deep reservoirs far from strike–slip fault zones is still unclear at present. The source and evolution of Ordovician fluids were analyzed using inclusion geochemical methods and the U–Pb dating technique. The analysis of rare earth elements and carbon–oxygen–strontium isotopes in the reservoirs showed that the reservoirs were weakly modified by diagenetic fluid. The fluid was derived from the fluid formation during the same period as the seawater, and no oxidizing fluid invaded the reservoir. The late oil and gas reservoirs had good sealing properties. The U–Pb dating results combined with homogenization temperature data revealed that the first-stage oil was charged during the Late Caledonian Period, and the second-stage natural gas was charged during the Middle Yanshanian Period. The evolution of the paleo-pressure showed that the charging of natural gas in the Middle Yanshanian was the main reason for the formation of reservoir overpressure. The strike–slip fault zone was basically inactive in the Middle Yanshanian. During this period, the charged natural gas mainly migrated to the reservoir along the unconformity surface and the open strike–slip fault zone in the upper part of the Ordovician reservoir. The source of the fluid shows that the reservoir in the late stage had good sealing properties, and there was no intrusion of exogenous fluid. The overpressure in the reservoir is well preserved at present.

A quantitative study of the microstructure of Indian Gondwana shale: a fractal and algebraic topology approach

This paper covers a novel micro-level application of image processing in understanding the topological and petrophysical properties of Indian Gondwana shale using X-ray computed microtomography images. The complexity and randomness in the pore system are explained through the concept of fractal dimension (FD). In this paper, a quantitative analysis of 2D and 3D fractal dimensions of pores, grains and interfaces was performed for Indian Gondwana shale, using the box-counting method. A pore network is formed by the connection of many subpore clusters, each with a different volume. Hence, an image segmentation algorithm was applied to label different subclusters, and subsequently an analysis of FD was carried out on such subclusters of pores and grains. We implemented a novel application of Betti numbers (B0, B1 and B2) and Euler characteristics on our sample and calculated the possible flow channels of the sample. The FD of grains was found to be greater than the FD of the pore–grain interfaces, while the FD of pores was found to have the smallest value. Consequently, we also observed how the FD of both pores and grains was majorly controlled by the largest subcluster, and during fluid intrusion we observed a significant decrease in the FD of pores. Finally, the pore network with a larger B0 and larger difference of B1 was proved to be best for the storage of hydrocarbons and for fluid movement along more flow channels.

Temperature-sensitive polymer grafted with nano-SiO2 improves sealing and inhibition performance of shale water-based drilling fluid

Drilling fluid loss is an important factor restricting oil and gas production. The development of pores and micro-fractures in shale formations is the main cause of drilling fluid loss. In this study, silane coupling agent modified nano-SiO2 was used as the rigid core, and N-isopropylacrylamide and 2-hydroxyethyl methacrylate were used as the flexible outer shell. The temperature-sensitive blocking agent PKSHN was synthesized by inverse microemulsion polymerization method. PKSHN was analyzed and tested through Fourier transform infrared spectroscopy, simultaneous thermal analysis, transmission electron microscopy, dynamic laser scattering and other methods. The results show that PKSHN can achieve a hydrophilic/hydrophobic transition under the response temperature, with a median particle size of 189.35 nm, which can form a hydrophobic layer on the shale surface and reduce fluid intrusion into the shale formation. This study tested the performance of three drilling fluids with different densities by adjusting the amount of weighting agent. The results showed that the high-temperature and high-pressure filter losses of the three different densities of drilling fluids were all less than 10 mL. The addition of PKSHN can effectively reduce fluid loss. The rolling recovery experiment and linear expansion experiment show that after aging for 16 h at 150 °C, the rolling recovery rate is above 90 % and the linear expansion rate is below 7 %, indicating that the addition of PKSHN can effectively control the hydration expansion of shale.

Interplay Between Fluid Intrusion and Aseismic Stress Perturbations in the Onset of Earthquake Swarms Following the 2020 Alex Extreme Rainstorm

AbstractThe 2020 Alex storm in southern France led to localized extreme rainfall exceeding 600 mm in less than 24 hr. In the 100 days following the storm, a series of small earthquakes swarm occurred beneath the Tinée valley, a region characterized by a low background deformation. To gain insight into the mechanisms controlling swarm evolution, we used an enhanced seismic catalog to detect 188 events. These events exhibited magnitudes comprised between −1.03 and 2.01, and 78 of them were relocated using relative locations at an average depth of 3–4 km. Additionally, we estimated the directions and velocities of seismicity migration. Our analyses reveal multiple episodes of hypocenter expansion and migration within a fluid‐saturated fault system. Observations provide evidence of a bi‐directional seismicity migration marked by dual velocities within a swarm. The northward seismicity migration aligns with velocities indicative of aseismic slip (∼130 m/hr), while the southward migration corresponds to velocities associated with fluid pressure diffusion (∼5 m/hr). This migration pattern underscores the interplay of multiple physical mechanisms in both triggering and driving earthquakes. A stress‐driven model based on rate‐and‐state friction successfully explains the overall evolution of observed seismicity, whereas a fluid‐driven model fails to reproduce the data. Our observations and models suggest that fluid pressure changes resulting from intense rainfall caused aseismic slip in the shallow portion of the crust. We hypothesize that aseismic deformation serves as the driving force for the earthquake swarms, coupled with the invasion of pressurized fluid due to diffusing rainfall.

Study on the Spatial Damage Characteristics of Working Fluid in a Sandstone Reservoir and an Unplugged Fluid System.

Due to its good physical properties and low pressure coefficient, the K75 reservoir is prone to leakage and intrusion of drilling and completion fluids during well construction, resulting in plugging of the borehole throat, which will inevitably affect the injection and recovery capacity of the gas well. In order to ensure the strong injection and production capacity of the K75 reservoir, this paper clarifies the reservoir space damage characteristics under different pressure differences and different entry fluids by establishing physical simulation of the damage, selecting the optimal system of the decongestant, and conducting dynamic flow decongestion experiments, as well as combining with the characterization means of the continuous scanning system of the core and the permeability test of the gas measurement. The test results show that the degree of damage of the same working fluid increases with the increase of differential pressure of repulsion, and the degree of damage of sequential working fluids (drilling fluid, completion fluid, and perforating fluid) is greater than that of drilling fluid damage under the same differential pressure of repulsion. In order to relieve the damage of wellbore working fluids, a set of multifunctional, low-corrosion composite acid system formulas was selected through rock powder, mud cake dissolution experiments, and dynamic flow unblocking experiments; the permeability recovery rate of this acid system after unblocking was more than 90%, which is widely applicable, and it is useful for the acidizing and unblocking practice in similar reservoirs.

Effect of pH on Spontaneous Imbibition in Calcareous Rocks

AbstractReactive transport in porous media exhibits multifaceted interactions that are dependent on the matrix and fluid properties, and which ultimately alter these properties. A set of calcareous rock samples with unique mineralogy and varying petrophysical properties are selected for this study. A capillary rise experiment is performed in each sample, first with deionized water and then with a dilute, pH 2, HCl solution. Pre‐ and post‐acid petrophysical properties such as porosity, permeability, pore size distribution, and contact angle are measured for each sample along with the capillary rise profile. The latter is tracked by applying image analysis on video recording. The rock mineralogy significantly affects the acidic fluid intrusion into the rock samples. Calcite dissolution is the main reaction that results in the opening of the pore space. This is more prominent in all the carbonate samples where a higher proportion of calcite minerals is present. A higher capillary rise is consistently observed compared to the neutral fluid along with an increase in porosity and the mean pore size. The contact angle also undergoes changes making the carbonate matrix from oil‐wet to neutral‐wet. Coupling capillary interactions with fluid reactivity is often neglected in fluid transport phenomena. This study offers new insights into the relative importance of reactivity at the timescale of spontaneous imbibition. This is important in understanding dissolution and precipitation processes during capillary flow.

Experimental and numerical simulation research on hot dry rock wellbore stability under different cooling methods

The exploitation of geothermal energy commonly occurs at depths ranging from 3000 to 10000 m. At these depths, the surrounding rocks experience substantial temperature and pressure, leading to alterations in their physical and mechanical properties. The infiltration of drilling fluid into the wellbore result in thermal exchange with the surrounding rocks, causing a decrease in their strength and stability. Consequently, the wellbore becomes more susceptible to instabilities. This objective of this study was to investigate the physical and mechanical properties of heated granite under three distinct cooling methods: liquid nitrogen cooling, water cooling, and natural cooling. Based on experimental findings, this study enhanced the failure criteria for high-temperature granite and established a thermal-solid coupling model to assess the stability of wellbores in high-temperature granite formations. To examine the impacts of temperature variations between the wellbore and drilling fluid, analyze the stress distribution around the wellbore at various depths, and evaluate the consequences of high-temperature fluid intrusion on wellbore stability. The research indicates that: (1) Under identical high-temperature conditions, it has been observed that liquid nitrogen cooling causes the most significant damage to granite, followed by water cooling. On the other hand, natural cooling has the least detrimental effect on the rock. (2) With increasing temperature, the physical and mechanical properties of the rock undergo two distinct stages of change. The first stage is a gradual variation that occurs between 25 and 400 °C, while the second stage is a rapid variation observed between 400 and 800 °C. Notably, the temperature of 400 °C serves as a critical threshold for the observed property changes in this granite. (3) The rock failure criteria have been modified based on the thermal damage characteristics of cold fluid intrusion into granite and a thermal-hydraulic-mechanical coupled wellbore model has been established. (4) The numerical simulation results revealed that liquid nitrogen cooling had the greatest impact on wellbore temperature, stress, and damage zone. At 500 s, the temperature on the wellbore surface decreased by approximately 700 °C due to liquid nitrogen cooling. The circumferential stress and radial stress decreased by 180 MPa and 35 MPa, respectively. (5) After the intrusion of cold fluid into high-temperature granite, the stress around the wellbore decreases and the rate of decrease in circumferential stress is significantly greater than that of radial stress. This will increase the likelihood of wellbore instability.

Extremely improved the corrosion resistance and anti-wear behavior of aluminum alloy in 3.5% NaCl solution via amorphous CrAlN coating protection

The low hardness and limited anti-wear of aluminum alloys pose obstacles to their stability and service life, especially in corrosive environments. Here, the amorphous CrAlN coating was first deposited on aluminum alloy by DC magnetron sputtering. The CrAlN coating with 30.2% nitrogen content was dense and prevented the intrusion of oxidation and corrosive fluids, thus greatly improving the anti-corrosion of the coating. The wear rate of the coated aluminum alloy in 3.5% NaCl solution decreased by three orders of magnitude. This work paves the way for constructing amorphous protective coatings on light alloys.

Research on the Influence of Heterogeneity and Viscosity on the Fluid Intrusion Mechanism of the Water Flooding Process Based on the Microscopic Visualization Experiment.

The flow law of immiscible fluids in porous media plays an important role in the development of oil and gas fields. In the process of water flooding reservoir development, when the water phase displaces the oil phase, a fluid with higher viscosity, as a fluid with lower viscosity, the oil-water interface will always be unstable, resulting in different fingering effects. After water flooding, the distribution law of oil and water in the reservoir is mainly affected by the fluid intrusion mechanism. Due to the difference of capillary force, viscous force, and other microscopic forces, the fluid intrusion mechanism is mainly divided into two types: viscous fingering and capillary fingering. At the same time, due to the influence of reservoir heterogeneity, the fingering effect in the process of water displacement in porous media will be influenced to a certain extent. Based on the two-dimensional microscopic visualization experiment, this paper extracted the variance of the static parameter G in the capillary number calculation method of the two-dimensional microscopic model to represent the heterogeneity and conducted displacement experiments with different viscosities and flow rates to study the influence of the flow rate, viscosity, and heterogeneity on the results of water flooding. The experiments found that as for the influence of flow velocity, with the increase of flow velocity, that is, with the increase of capillary number, the recovery degree decreases first and then increases. As for the influence of viscosity, from a numerical point of view, the displacement efficiency and conformance coefficient of the low-viscosity group are higher than those of the high-viscosity group. From the trend, with the increase of the capillary number, the displacement efficiency of both the low-viscosity and high-viscosity groups increases, while the conformance coefficient decreases first and then increases, indicating that capillary fingering and viscous fingering can occur in different viscosity reservoirs. As for the influence of heterogeneity, the conformance coefficient of the water flooding decreases with the increase of heterogeneity, and the viscous pointing trend caused by heterogeneity is stronger, resulting in an uneven water injection sweep and higher oil displacement efficiency within the swept area. It can be seen from the fluid intrusion mechanism diagram that with the increase of heterogeneity, the viscous fingering trend becomes more obvious; with the increase of viscosity, the fluid intrusion mechanism boundary moves down and the viscous fingering trend becomes more obvious.

Numerical simulation study on the action law of low temperature drilling fluid intrusion into rock formation in polar drilling

In this paper, based on the experimental parameters of polar permafrost formation, the mathematical module, solid mechanics module, and Darcy?s law module of COMSOL Multiphysics software are used to realize the coupled solution of PDE of temperature field, moisture field, and stress field considering the ice-water phase transition and moisture convection, and the relationship between the permafrost moisture convection and temperature change is analyzed by using the heat-flow-solid-moisture mutual coupling, which reveals that the law of action of low temperature intrusion into rock formation by polar drilling.

Effects of SEM image resolution on organic pore structure estimation of shale reservoirs

SEM images on ion-polished shale samples can visualize organic pores and can be used to analyze the organic pore structures quantitatively. Compared to the routine fluid intrusion methods (e.g., helium porosity, N2 adsorption, mercury intrusion, etc.), the SEM image-based organic pore structure analysis has many unique benefits. However, image resolution can significantly influence the analysis results. This should be investigated carefully. The image resolution effects on the analysis of organic pore structures was confirmed and estimated through (1) imaging organic matters and their organic pores at different resolutions (0.7–29.2 nm/pixel), and (2) comparing the differences of 2D organic porosity, pore size distribution (PSD), and organic pore geometry calculated at different image resolutions. The two ways of image resolution effect on organic pore analysis was revealed. First, organic pores with a wall close to the sample surface were more challenging to recognize at low image resolution. Any incorrect recognition of these organic pores can significantly affect the calculated 2D organic porosity and the sectional area-based PSD. Second, the small size organic pores were also difficult to recognize at low image resolution, considerably affecting the estimation of pore amount-based PSD but only slightly affecting the calculated organic porosity and sectional area-based PSD due to their small pore size. When SEM image resolution is less than 10nm/pixel, organic porosity will be significantly underestimated, and the estimated PSD and geometry usually have high uncertainty. Therefore, SEM images with 5nm/pixel or higher resolution are recommended to assess organic pore structures.

Scale-Dependent Fractal Properties and Geological Factors for the Pore Structure in Shale: Insights from Field Emission Scanning Electron Microscopy and Fluid Intrusion

Scale-Dependent Fractal Properties and Geological Factors for the Pore Structure in Shale: Insights from Field Emission Scanning Electron Microscopy and Fluid Intrusion

Pore structure of low-permeability coal and its deformation characteristics during the adsorption–desorption of CH4/N2

The pore structure of coal plays a key role in controlling the storage and migration of CH4/N2. The pore structure of coal is an important indicator to measure the gas extraction capability and the gas displacement effect of N2 injection. The deformation characteristic of coal during adsorption–desorption of CH4/N2 is an important factor affecting CH4 pumpability and N2 injectability. The pore structure characteristics of low-permeability coal were obtained by fluid intrusion method and photoelectric radiation technology. The multistage and connectivity of coal pores were analyzed. Subsequently, a simultaneous test experiment of CH4/N2 adsorption–desorption and coal deformation was carried out. The deformation characteristics of coal were clarified and a coal strain model was constructed. Finally, the applicability of low-permeability coal to N2 injection for CH4 displacement technology was investigated. The results show that the micropores and transition pores of coal samples are relatively developed. The pore morphology of coal is dominated by semi-open pores. The pore structure of coal is highly complex and heterogeneous. Transition pores, mesopores and macropores of coal have good connectivity, while micropores have poor connectivity. Under constant triaxial stress, the adsorption capacity of the coal for CH4 is greater than that for N2, and the deformation capacity of the coal for CH4 adsorption is greater than that for N2 adsorption. The axial strain, circumferential strain, and volumetric strain during the entire process of CH4 and N2 adsorption/desorption in the coal can be divided into three stages. Coal adsorption–desorption deformation has the characteristics of anisotropy and gas-difference. A strain model for the adsorption–desorption of CH4/N2 from coal was established by considering the expansion stress of adsorbed gas on the coal matrix, the compression stress of free gas on the coal matrix, and the expansion stress of free gas on micropore fractures. N2 has good injectability in low-permeability coal seams and has the dual functions of improving coal seam permeability and enhancing gas flow, which can significantly improve the effectiveness of low-permeability coal seam gas control and promote the efficient utilization of gas resources.

Research and application of construction technology of digital mud cake formed by drilling fluid filtration

In drilling engineering, mud cake is formed when drilling fluid invades the near-wellbore zone, which can reduce drilling fluid leakage and reservoir pollution and maintain wellbore stability. To study the three-dimensional spatial characteristics of mud cakes, such as heterogeneity, particle accumulation, and porous media, CT scan images of cores and mud cakes before and after drilling fluid intrusion are used as the research object. The composite filtering and segmentation method for typical regions of images based on grayscale values and the batch segmentation method for large regions of images based on deep learning are investigated. On this basis, a visualized digital mud cake is constructed, and microscopic evaluation indexes such as the percentage, equivalent radius, throat length, sphericity, and coordination number of pores and particles in the mud cake are established. The application results show that the number of isolated pores in the outer mud cake formed by static filtration of drilling fluid is more than that of dynamic ones, the connectivity of pores is poor, and the particles have a better sealing effect on pores. The combined effect of the outer and inner mud cake results in different effects on core intrusion. The construction technique of digital mud cake can study the structure at a micron scale. This technique can provide more detailed guidance for engineering situations, such as optimization of drilling fluid systems in fractured formations, damage evaluation of reservoirs by drilling fluid, and influence of mud cake on cementing quality.

A Novel Amphoteric Ion-Modified, Styrene-Based Nano-Microsphere and Its Application in Drilling Fluid.

With the gradual depletion of shallow oil and gas, deep oil and gas has become the focus of development. However, deep formations generally face the challenge of high-temperature and high-salinity, and drilling fluid agents are prone to failure, leading to drilling fluid intrusion into the formation that can cause serious drilling accidents such as well bore collapse. For this, a styrene-based nano-microsphere (SSD) modified with amphoteric ions was developed, with a particle size of 228 nm which could resist temperatures up to 200 °C and sodium chloride (NaCl) up to saturation. SSD has significant salt-responsive properties and its aqueous dispersion becomes transparent with increasing salinity. The SSD provided superior plugging performance in solutions containing NaCl, with a core plugging efficiency of 95.2%, and it was significantly better than the anion-modified microspheres. In addition, in drilling fluids under high temperature and high-salinity conditions, the SSD promotes particle gradation of drilling fluids and improves the zeta potential through its own plugging and synergistic effect with clay, which significantly improves the comprehensive performance of drilling fluids, such as stability, rheological performance, and filtration reduction performance. The development of SSD provides a new idea for research of high-temperature and high-salinity-resistant drilling fluid agents.