Search Results (91)

Water within coal reservoirs exerts dual effects on methane adsorption–desorption by competing for adsorption sites and reducing permeability. The bound water effect, caused by coal wettability, significantly constrains coalbed methane (CBM) production, rendering investigations into coal wettability crucial for efficient CBM development. Compared with other geological formations, coals are characterized by a highly developed microporous structure, making the CO₂ sequestration mechanism in coal seams closely linked to the microscale interactions among gas, water, and coal matrixes. However, the intrinsic mechanisms remain poorly understood. In this study, molecular dynamics simulations are employed to investigate the wettability behaviors of CO₂, CH₄, and water on different coal matrix surfaces under varying temperature and pressure conditions, for coal macromolecules representative of four coal ranks. The study reveals the evolution of water wettability in response to CO₂ and CH₄ injection, identifies wettability differences among coal ranks, and analyzes the microscopic mechanisms governing wettability. The results show the following: (1) The contact angle increases with gas pressure, and the variation in wettability is more pronounced in CO₂ environments than in CH₄. As pressure increases, the number of hydrogen bonds decreases, while the peak gas density of CH₄ and CO₂ increases, leading to larger contact angles. (2) Simulations under different temperatures for the four coal ranks indicate that temperature has minimal influence on low-rank Hegu coal, whereas for higher-rank coals, gas adsorption on the coal surface increases, resulting in reduced wettability. Interfacial tension analysis further suggests that higher temperatures reduce water surface tension, cause dispersion of water molecules, and consequently improve wettability. Understanding the wettability variations among different coal ranks under variable pressure–temperature conditions provides a fundamental model and theoretical basis for investigating deep coal seam gas–water interactions and CO₂ geological sequestration mechanisms. These findings have significant implications for the advancement of CO₂-ECBM technology. Full article

The concept of “material effort” appears in continuum mechanics wherever the response of a material to the currently existing state of loads and boundary conditions loses its previous, predictable character. However, within the material, which still descriptively remains a continuous medium, new physical structures appear and new previously unused physical features of the continuum are activated. The literature is dominated by a simplified way of thinking, which assumes that all these states can be characterized and described by one and the same measure of effort—for metals it is the Huber–Mises–Hencky equivalent stress. Quantitatively, perhaps 90% of the literature is dedicated to this equivalent stress. The remaining authors, as well as the author of this paper, assume that there is no single universal measure of effort that would “fit” all operating conditions of materials. Each state of the structure’s operation may have its own autonomous measure of effort, which expresses the degree of threat from a specific destruction mechanism. In the current energy sector, we are increasingly dealing with “low-cycle thermal fatigue states”. This is related to the fact that large, difficult-to-predict renewable energy sources have been added. Professional energy based on coal and gas units must perform many (even about 100 per year) starts and stops, and this applies not only to the hot state, but often also to the cold state. The question arises as to the allowable shortening of start and stop times that would not to lead to dangerous material effort, and whether there are necessary data and strength characteristics for heat-resistant steels that allow their effort to be determined not only in simple states, but also in complex stress states. Do these data allow for the description of the material’s yield surface? In a previous publication, the author presented the results of tension and compression tests at elevated temperatures for two heat-resistant steels: St12T and 26H2MF. The aim of the current work is to determine the properties and strength characteristics of these steels in a pure torsion test at elevated temperatures. This allows for the analysis of the strength of power turbine components operating primarily on torsion and for determining which of the two tested steels is more resistant to high temperatures. In addition, the properties determined in all three tests (tension, compression, torsion) will allow the determination of the yield surface of these steels at elevated temperatures. They are necessary for the strength analysis of turbine elements in start-up and shutdown cycles, in states changing from cold to hot and vice versa. A modified testing machine was used for pure torsion tests. It allowed for the determination of the sample’s torsion moment as a function of its torsion angle. The experiments were carried out at temperatures of 20 °C, 200 °C, 400 °C, 600 °C, and 800 °C for St12T steel and at temperatures of 20 °C, 200 °C, 400 °C, 550 °C, and 800 °C for 26H2MF steel. Characteristics were drawn up for each sample and compared on a common graph corresponding to the given steel. Based on the methods and relationships from the theory of strength, the yield stress and torsional strength were determined. The yield stress of St12T steel at 600 °C was 319.3 MPa and the torsional strength was 394.4 MPa. For 26H2MH steel at 550 °C, the yield stress was 311.4 and the torsional strength was 382.8 MPa. St12T steel was therefore more resistant to high temperatures than 26H2MF. The combined data from the tension, compression, and torsion tests allowed us to determine the asymmetry and plasticity coefficients, which allowed us to model the yield surface according to the Burzyński criterion as a function of temperature. The obtained results also allowed us to determine the parameters of the Drucker-Prager model and two of the three parameters of the Willam-Warnke and Menetrey-Willam models. The research results are a valuable contribution to the design and diagnostics of power turbine components. Full article

Unconventional hydrocarbon reservoirs with low matrix permeability (<0.3 mD), high temperatures, and sour conditions present significant challenges for stimulation and production enhancement. This study examines field trials for a large oil and gas operator in the UAE, focusing on tight carbonate deposits with reservoir temperatures above 93 °C and high sour gas content. A novel multi-stage chemical stimulation workflow was created, beginning with a pre-flush phase that alters rock wettability and reduces interfacial tension at the micro-scale. This was followed by a second phase that increased near-wellbore permeability and ensured proper acid placement. The treatment’s core used a thermally stable, corrosion-resistant retarded acid system designed to slow reaction rates, allow deeper acid penetration, and build prolonged conductive wormholes. Simulations revealed considerable acid penetration of the formation beyond the near-wellbore zone. The post-treatment field data showed a tenfold improvement in injectivity, which corresponded closely to the acid penetration profiles predicted by modeling. Furthermore, oil production demonstrated sustained, high oil production of 515 bpd on average for several months after the treatment, in contrast to the previously unstable and low-rate production. Finally, the findings support a reproducible and technologically advanced stimulation technique for boosting recovery in ultra-tight carbonate reservoirs using the acid retardation effect where traditional stimulation fails. Full article

Aiming at the problems of insufficient natural productivity and large seepage resistance in low-permeability oil and gas reservoirs, a nano relative permeability improver based on nano SiO₂ was developed in this study. The nano relative permeability improver was prepared by the reversed-phase microemulsion method, and the formula was optimized (nano SiO₂ 5.1%, Span-80 33%, isobutanol 18%, NaCl 2%), so that the minimum median particle size was 4.2 nm, with good injectivity and stability. Performance studies showed that the improvement agent had low surface tension (30–35 mN/m) and interfacial tension (3–8 mN/m) as well as significantly reduced the rock wetting angle (50–84°) and enhanced wettability. In addition, it had good temperature resistance, shear resistance, and acid-alkali resistance, making it suitable for complex environments in low-permeability reservoirs. Full article

We experimentally studied the effect of a surfactant on bubble formation on a superhydrophobic surface (SHS). The bubble was created by injecting gas through an orifice on the SHS at a constant flow rate in the quasi-static regime. The surfactant, 1-pentanol, was mixed with water at concentration C ranging from 0 to 0.08 mol/L, corresponding to surface tension σ ranging from 72 to 43 mN/m. We found that as C increased, the bubble detachment volume (V_d) and maximum bubble base radius (R_d^max) decreased. For a low surfactant concentration, the static contact angle θ₀ remained nearly constant, and V_d and R_d^max decreased due to lower surface tensions, following the scaling laws R_d^max~σ^1/2 and V_d~σ^3/2. The bubble shapes at different concentrations were self-similar. The bubble height, bubble base radius, radius at the bubble apex, and neck radius all scaled with the capillary length. For high surfactant concentrations, however, θ₀ was greatly reduced, and V_d and R_d^max decreased due to the combined effects of reduced θ₀ and smaller σ. Lastly, we found that the surfactant had a negligible impact on the forces acting on the bubble, except for reducing their magnitudes, and had little effect on the dynamics of bubble pinch-off, except for reducing the time and length scales. Overall, our results provide a better understanding of bubble formation on complex surfaces in complex liquids. Full article

The Invar steel molten pool is characterized by low fluidity of the molten pool due to high tension, which hinders the escape of gases and exacerbates the formation of porosity defects. In this study, the influences of different welding process parameters, material properties, and U-groove on the flow behavior of the molten pool of laser–tungsten inert gas (TIG) hybrid welding of Invar steel are investigated by numerical simulation and high-speed photography. This research proposes effective measures to suppress porosity defects, such as optimizing process parameters and extending the existence time of the molten pool. In conclusion, this study systematically investigates the dynamic mechanism of the formation of welding defects in 4J36 Invar steel and provides important theoretical support for the optimization of the welding process of 4J36 Invar steel. The results indicate that controlling the laser power at 4–6 kW, welding speed at 0.5–1.0 m/min, and welding current at 150–170 A can stabilize the molten pool flow and keyhole and promote the molten pool flow and gas escape. Full article

High-pressure low-permeability gas reservoirs have a complex gas–water distribution, a lack of a unified gas–water interface, and widespread water intrusion in localized high areas, which seriously constrain sweet spot prediction and development deployment. In this study, the high-pressure, low-permeability sandstone of Huangliu Formation in Yinggehai Basin is taken as the object, and the micro gas–water distribution mechanism and the main controlling factors are revealed by combining core expulsion experiments and COMSOL two-phase flow simulations. The results show that the gas saturation of the numerical simulation (20 MPa, 68.98%) is in high agreement with the results of the core replacement (66.45%), and the reliability of the model is verified. The natural gas preferentially forms continuous seepage channels along the large pore throats (0.5–10 μm), while residual water is trapped in the small throats (<0.5 μm) and the edges of the large pore throats that are not rippled by the gas. The breakthrough mechanism of filling pressure grading shows that the gas can fill the 0.5–10 μm radius of the pore throat at 5 MPa, and above 16 MPa, it can enter a 0.01–0.5 μm small throat channel. The distribution of gas and water in the reservoir is mainly controlled by the pore throat structure, formation temperature, and filling pressure, and the gas–liquid interfacial tension and wettability have weak influences. This study provides a theoretical basis for the prediction of sweet spots and optimization of development plans for low-permeability gas reservoirs. Full article

The demand for sustainable packaging has increased the interest in biopolymer coatings as alternatives to plastic-based barriers on paper and board. Alginate and chitosan offer promising barrier properties by improving gas barrier and grease resistance. However, their high viscosity at low solid contents presents challenges for uniform coatings, especially in possible future large-scale applications but also in existing research. This study evaluates spray coating, a non-conventional application method in the paper industry, to apply biopolymer coatings, an approach underexplored in previous studies. The effects of substrate surface energy and biopolymer surface tension on air permeability, grease resistance, and water vapor transmission were evaluated. Contact angle measurements showed that surface energy strongly influences the wetting behavior of these biopolymers, with hydrophilic substrates and lower-surface-energy liquids promoting better droplet spreading. This improved wetting resulted in better barrier performance at low application weights, further enhanced by surfactant addition. At higher application weights, surface energy had less impact on barrier properties. SEM imaging revealed drying defects at increased coat weights, affecting film integrity. These findings demonstrate the potential of spray coating as a scalable method for biopolymer application while highlighting the need for optimized drying conditions to enhance film uniformity and barrier performance. Full article

This study investigates the combined effects of impurities in CO₂ stream, geochemistry, water salinity, and wettability alteration on oil recovery and CO₂ storage in carbonate reservoirs and optimizes injection strategy to maximize oil recovery and CO₂ storage ratio. Specifically, it compares the performance of pure CO₂ water-alternating gas (WAG), impure CO₂-WAG, pure CO₂ low-salinity water-alternating gas (LSWAG), and impure CO₂-LSWAG injection methods from perspectives of enhanced oil recovery (EOR) and CO₂ sequestration. CO₂-enhanced oil recovery (CO₂-EOR) is an effective way to extract residual oil. CO₂ injection and WAG methods can improve displacement efficiency and sweep efficiency. However, CO₂-EOR has less impact on the carbonate reservoir because of the complex pore structure and oil-wet surface. Low-salinity water injection (LSWI) and CO₂ injection can affect the complex pore structure by geochemical reaction and wettability by a relative permeability curve shift from oil-wet to water-wet. The results from extensive compositional simulations show that CO₂ injection into carbonate reservoirs increases the recovery factor compared with waterflooding, with pure CO₂-WAG injection yielding higher recovery factor than impure CO₂-WAG injection. Impurities in CO₂ gas decrease the efficiency of CO₂-EOR, reducing oil viscosity less and increasing interfacial tension (IFT) compared to pure CO₂ injection, leading to gas channeling and reduced sweep efficiency. This results in lower oil recovery and lower storage efficiency compared to pure CO₂. CO₂-LSWAG results in the highest oil-recovery factor as surface changes. Geochemical reactions during CO₂ injection also increase CO₂ storage capacity and alter trapping mechanisms. This study demonstrates that the use of impure CO₂-LSWAG injection leads to improved oil recovery and CO₂ storage compared to pure CO₂-WAG injection. It reveals that wettability alteration plays a more significant role for oil recovery and geochemical reaction plays crucial role in CO₂ storage than CO₂ purity. According to optimization, the greater the injection of gas and water, the higher the oil recovery, while the less gas and water injected, the higher the storage ratio, leading to improved storage efficiency. This research provides valuable insights into parameters and injection scenarios affecting enhanced oil recovery and CO₂ storage in carbonate reservoirs. Full article

This study systematically investigates the formation mechanism and development characteristics of the “foamy oil” phenomenon during pressure depletion development of high-viscosity crude oil through a combination of physical experiments and numerical simulations. Using Venezuelan foamy oil as the research subject, an innovative heterogeneous pore-etched glass model was constructed to simulate the pressure depletion process, revealing for the first time that bubble growth predominantly occurs during the migration stage. Experimental results demonstrate that heavy components significantly delay degassing by stabilizing gas–liquid interfaces, while the continuous gas–liquid diffusion effect explains the unique development characteristics of foamy oil—high oil recovery and delayed phase transition—from a microscopic perspective. A multi-scale coupling analysis method was established: molecular-scale simulations were employed to model component diffusion behavior. By improving the traditional Volume of Fluid (VOF) method and introducing diffusion coefficients, a synergistic model integrating a single momentum equation and fluid volume fraction was developed to quantitatively characterize the dynamic evolution of bubbles. Simulation results indicate significant differences in dominant controlling factors: oil phase viscosity has the greatest influence (accounting for ~50%), followed by gas component content (~35%), and interfacial tension the least (~15%). Based on multi-factor coupling analysis, an empirical formula for bubble growth incorporating diffusion coefficients was proposed, elucidating the intrinsic mechanism by which heavy components induce unique development effects through interfacial stabilization, viscous inhibition, and dynamic diffusion. This research breaks through the limitations of traditional production dynamic analysis, establishing a theoretical model for foamy oil development from the perspective of molecular-phase behavior combined with flow characteristics. It not only provides a rational explanation for the “high oil production, low gas production” phenomenon but also offers theoretical support for optimizing extraction processes (e.g., gas component regulation, viscosity control) through quantified parameter weightings. The findings hold significant scientific value for advancing heavy oil recovery theory and guiding efficient foamy oil development. Future work will extend to studying multiphase flow coupling mechanisms in porous media, laying a theoretical foundation for intelligent control technology development. Full article

Surfactants significantly influence the flow patterns of gas-liquid two-phase flows. Understanding the behavior of multiphase flows in the presence of surfactants is crucial for optimizing hydrate transport in pipelines. This study presents experimental investigations into the effects of surfactant-induced surface tension variations on gas-liquid two-phase spiral flows in horizontal pipelines. Four distinct flow patterns were identified: spiral linear flow, spiral wave-stratified flow, spiral axial flow, and spiral dispersed flow. Notably, spiral bubbly flow and spiral slug flow were absent in gas-liquid two-phase spiral flows with a low concentration of the anionic surfactant sodium dodecyl sulfate (SDS). A flow pattern map was developed to describe gas-liquid two-phase spiral flows in horizontal pipelines with low SDS concentrations. The results indicate that increasing the liquid-phase velocity reduces the spiral diameter and attenuates the flow patterns while increasing the pitch of the spiral flows. Furthermore, at a constant gas-phase void fraction, the pressure drop is highest in spiral wave-stratified flow and lowest in spiral dispersed flow. Full article

Graphene aerogels with high surface areas, ultra-low densities, and thermal conductivities have been attracted a lot of attention in recent years. However, considerable difference in their deformation behavior and mechanical properties lead to their poor performance. The problem can be solved by preparing graphene aerogel of given morphology and by control the properties through the special structure of graphene cells. In the present work, molecular dynamics simulation is used to overview the mechanical properties of four different morphologies of graphene aerogel: honeycomb, cellular, lamellar and randomly distributed graphene flakes. All the structures are considered under uniaxial compression and tension with the detailed analysis of the deformation behavior. It is found that cellular structures have much better compressibility and elasticity. During both compression and tension, cellular structures can be transformed from one to another by controlling the compression/tensile direction. The highest strength and fracture strain are found for the lamellar GA under tension along the direction perpendicular to the alignment of the graphene walls. This reveals that the mechanical properties of graphene aerogels can be controlled by enhancing the structural morphology. The obtained results is the contribution which provide the insights into recent developments concerning the design of carbon-based structures and their application. Full article

With increasing energy demands and depleting oil accessibility in reservoirs, the investigation of more effective enhanced oil recovery (EOR) methods for deep and tight reservoirs is imminent. This study investigates a novel hybrid EOR method, a synergistic approach of nonionic surfactant flooding with intermediate CO₂-based oil swelling. This study is focused on the efficiency of surfactant flooding and low-pressure oil swelling in oil recovery. We conducted a fluorescence-based microscopic analysis in a microchannel to explore the effect of sodium dodecyl sulfate (SDS) surfactant on CO₂ diffusion in Texas crude oil. Based on the change in emission intensity of oil, the results revealed that SDS enhanced CO₂ diffusion at low pressure in oil, primarily due to SDS aggregation and reduced interfacial tension at the CO₂ gas–oil interface. To validate the feasibility of our proposed EOR method, we adopted a ‘reservoir-on-a-chip’ approach, incorporating flooding tests in a polymethylmethacrylate (PMMA)-based micromodel. We estimated the cumulative oil recovery by comparing the results of two-stage surfactant flooding with intermediate CO₂ swelling at different pressures. This novel hybrid approach test consisted of a three-stage sequence: an initial flooding stage, followed by intermediate CO₂ swelling, and a second flooding stage. The results revealed an increase in cumulative oil recovery by nearly 10% upon a 2% (w/v) solution of SDS and water flooding compared to just water flooding. The results showed the visual phenomenon of oil imbibition during the surfactant flooding process. This innovative approach holds immense potential for future EOR processes, characterized by its unique combination of surfactant flooding and CO₂ swelling, yielding higher oil recovery. Full article

Coalbed Methane (CBM) accounts for about 5% of China’s domestic gas supply, which has been regarded as one of the most promising energies for alleviating the energy supply–demand imbalance. Deep CBM reservoirs have the characteristics of low permeability, low porosity, and low water saturation, which easily experience reservoir damage during the drilling process, further affecting the gas productivity. Based on the analysis of coal mineral composition, pore structure distribution, and the surface micromorphology change in coal surface before and after hydration, a possible mechanism for CBM formation damage was revealed. It was found that the damage caused by drilling fluid intrusion can be divided into three stages: stripping, migration, and plugging. Based on the water-sensitive, acid-sensitive, and stress-sensitive evaluation tests, a novel anti-waterblocking agent with both wettability alteration and surface tension reduction was developed; then a reservoir protection drilling fluid for deep coal formation in Daning-Jixian block was constructed; then the reservoir protection performance of drilling fluid was evaluated. The results show that as the concentration of the anti-waterblocking agent FSS increases from 0% to 1%, the surface tension of the water phase is significantly reduced from 72.15 mN/m to 26.58 mN/m, while the maximum contact angle of water on the surface reaches 117°. This enhancement in wettability leads to an improvement in the permeability recovery rate from 56.6% to 80.0%, indicating a substantial reduction in waterblocking effects and better fluid mobility within the reservoir. These findings highlight the efficacy of FSS in mitigating formation damage and optimizing gas production in coalbed methane reservoirs. The drilling fluid has good wettability alteration, inhibition, and sealing performance, which is of great significance for protecting gas well productivity. Full article

A major problem in natural gas production is the waterlogging of gas wells. This problem occurs at the end of a well’s life when the reservoir pressure becomes low and the gas velocity in the well tubing is no longer sufficient to bring the gas-related fluids (water and gas condensate) up to the surface. This causes water to accumulate at the bottom of the gas well, which can seriously reduce or even stop gas production altogether. This paper presents a study of the foaming of reservoir water using foaming sticks with the trade names BioLight 30/380, BioCond 30, BioFoam 30, BioAcid 30/380, and BioCond Plus 30/380. The reservoir waters tested came from near-well separators located at three selected wells that had undergone waterlogging and experienced a decline in natural gas production. They were characterised by varying physical and chemical parameters, especially in terms of mineralisation and oil contaminant content. Laboratory studies on the effect of foaming agents on the effectiveness of foaming and lifting of reservoir water from the well were carried out on a laboratory bench, simulating a natural gas-producing column using surfactant doses in the range of 1.5–5.0 g/m³ and measuring the surface tension of the water, the volume of foam generated as a function of time and the foamed reservoir water. The performance criterion for the choice of surfactant for the test water was its effective lifting in a foam structure from an installation, simulating a waterlogged gas well and minimising the dose of foaming agent introduced into the water. The results obtained from the laboratory tests allowed the selection of effective surfactants in the context of foaming and uplift of reservoir water from wells, where a decline in natural gas production was observed as a result of their waterlogging. In the next stage, well tests were carried out based on laboratory studies to verify their effectiveness under conditions typical for the production site. Tests carried out at natural gas wells showed that the removal of water from the bottom of the well resulted in an increase in natural gas production, ranging from 56.3% to 79.6%. In practice, linking the results of laboratory tests for the type and dosage of foaming agents to the properties of reservoir water and gas production parameters made it possible to identify the types of surfactants and their dosages that improve the production of a given type of natural gas reservoir in an effective manner, resulting in an increase in the degree of depletion of hydrocarbon deposits. Full article