Hydrated Aggregates Research Articles

Numerical simulation of hydrate flow in gas-dominated undulating pipes considering nucleation and deposition behaviors

The distribution and deposition of hydrates in deep-water gas transportation pipelines are crucial for safety. Current simulations of hydrate flow based on the population balance model have predominantly focused on water-dominant systems and neglect the nucleation and deposition of hydrates. By establishing a model for a hydrate flow in a gas-dominant system that considers the uneven distribution of the liquid film on the wall, hydrate nucleation, gas–liquid mass transfer, particle adhesion and aggregation, and dynamic deposition, we achieved simulation of the entire process of hydrate formation, aggregation, breakage, and deposition. Simulations in undulating pipelines were carried out to investigate the effects of gas velocity, liquid injection, pressure, and pipeline structure on distribution patterns. The results showed increasing the gas velocity enhanced the dispersion of particles and increasing the pressure increased the rate of aggregation. The formation of blocky aggregates posed significant risk in the rear section of the lower-bend pipe.

Influence of Unconverted Droplets on Hydrate Aggregation in the Oil-Dominated System

Influence of Unconverted Droplets on Hydrate Aggregation in the Oil-Dominated System

Effect of wax on hydrate formation and aggregation characteristics of water-in-oil emulsion

In recent years, the formation and aggregation of wax and hydrate under the condition of coexistence has become a hot spot in the safety assurance of deep-water pipeline flow. In order to clarify the influence mechanism of wax and hydrate in deep-sea crude oil under coexistence conditions, the effects of different wax-containing conditions on the nucleation, growth and aggregation characteristics of hydrate in oil–water emulsion were studied by macroscopic and microscopic experimental equipment. The results show that low wax content (0–3.wt%) provides nucleation sites for hydrate formation and thus promotes hydrate formation. High wax content (>3.wt%) inhibits hydrate formation by preventing water droplets from contacting gas molecules. Low wax content (0–3.wt%) significantly reduces hydrate interparticle aggregation. High wax content (>3.wt%) promotes hydrate interparticle aggregation, which changes the flow characteristics of the hydrate slurry. In addition, through further analysis by PVM and high-speed camera, a wax-containing hydrate aggregation mechanism model was established.

Experimental study on gas separation from the oil–water-emulsion mixture via hydrate method

The gas separation technology based on hydrate method offers several advantages, including a short process flow, simple equipment, no pollution, less corrosion, and lower energy consumption. It has a broad application prospect in the acid gas purification, biogas purification and CO2 sequestration., etc. However, demanding hydrate formation conditions and lower gas separation effects constrain its application. Oil-water emulsion shows promise in improving mass and heat transfer efficiency, enhancing hydrate slurry fluidity, and reducing hydrate aggregates. Thus, this study investigates the effects of different oil–water ratios, promoter concentrations, and surfactants on hydrate formation and separation efficiency in an oil–water emulsion system. At an oil–water ratio of 1:1, the purification rate increased to 6.06, five times higher than in a pure water system. The addition of 1,3-Dioxolane (DIOX) facilitated bidirectional growth properties of hydrate formation on droplet surfaces, enhancing hydrate nucleation and formation, leading to a CO2 recovery increase to 87% with 1.5 wt% DIOX. Furthermore, lipophilic surfactants were more likely to promote hydrate slurry fluidization. The addition of Span80 reduced hydrate agglomeration and increased the rate of hydrate formation as concentration rose. The results suggest that adding DIOX and increasing the concentration of Span80 could improve the hydrate method’s separation efficiency at an oil–water ratio of 1:1.

Study of Sintering Behavior of Methane Hydrate Particles on the Wall Surface.

The sintering of hydrate aggregates on the pipe wall is a major form of hydrate deposition. Understanding the sintering behavior of hydrates on the wall is crucial for promoting hydrate safety management and preventing pipeline blockage. However, limited research currently exists on this topic. In this study, the cohesive force strength of hydrate particles on the wall surface under different conditions was directly measured using a high-pressure micromechanical force device (HP-MMF). Subsequently, the effects of subcooling and glycine on the cohesive force were investigated. The results indicate that the cohesive force is influenced by different growth states during the process of free water on the wall surface gradually growing into hydrate. Three states with larger measured values during the growth process were selected for research. Observation showed that increased subcooling strengthened sintering by accelerating the growth rate of the hydrate film, resulting in a significant increase in cohesive force. The role of glycine in the methane hydrate system was then evaluated. Glycine was found to reduce the degree of sintering by reducing the growth rate of the hydrate film, thereby decreasing the cohesive force. The optimal concentration in the system was determined to be 0.25 wt %. Moreover, compared with low subcooling (1 °C), glycine had a better effect at high subcooling (5 °C). At 5 °C subcooling and the optimal concentration, the cohesive force in the wall droplet state decreases from 677.38 to 489.02 mN/m, the cohesive force at the low-saturation state decreases from 951.79 to 543.32 mN/m, and the cohesive force at the high-saturation state decreases from 1194.95 to 641.76 mN/m. These findings contribute to a better understanding of the cohesive force behavior of gas hydrate on the inner wall of the pipeline and provide basic data for reducing the risk of hydrate blockage.

Molecular insights into the effects of mass transfer ability of anti-agglomerant monolayers with different densities on the growth and wetting behavior of methane hydrate

Anti-agglomerants (AAs) have been recognized as an effective method for gas hydrate risk management in oil and gas pipelines. However, a limitation of AAs is their poor inhibitory effect on hydrate growth and aggregation in gas–water systems. In addition, the density of the AAs monolayer is considered one of the main factors affecting the growth and aggregation of hydrate particles, but the mechanism of this effects remains unclear. Herein, molecular dynamics (MD) simulations were employed to investigate the effects of anti-agglomerant (cocamidopropyl dimethylamine) monolayers with different densities on hydrate growth and the wetting behavior of hydrate surface. The results revealed that AA monolayers primarily suppress hydrate growth and reduce the wetted area by modulating mass transfer processes of gas and water molecules. The high-density monolayer can effectively hinder the flattening and diffusion of droplet on the hydrate surface due to its ability to maintain the aggregation state of water molecules and reduce the contact area between droplet and hydrates. The high-density AA monolayers simultaneously enhance the bonding strength between the monolayer and the hydrate, as well as the intermolecular interactions between AA molecules. The Coulomb interaction and h-bonds make the main contributions to the binding strength. Therefore, enhancing the adsorption density of AAs on the hydrate surface and the binding strength between AA molecules in the gas–water system should serve as a strategic approach in designing efficient AAs. These molecular insights on the anti-agglomeration mechanism are beneficial to guide the screening and design of efficient AAs molecules.

Hydrate aggregation in oil-gas pipelines: Unraveling the dual role of asphalt and water

Molecular dynamics was employed to investigate the micro-mechanism of water and asphalt on hydrate aggregation, addressing the mechanism of aggregation caused by hydrates, asphalt, and water droplets in pipelines. In low-water-content pipelines, the oxygen atoms in asphalt form hydrogen bonds with hydrates, anchoring them to the hydrates. Asphalt forms stable molecular films through π-π interactions, effectively preventing hydrate aggregation. In addition to traditional hydrogen bonds (bond energies around 18 kJ/mol), asphalt also form π hydrogen bonds (bond energies around 9 kJ/mol), making it easier to bind with water. The water droplets reduce the face-to-face stacking of asphalt molecules from 35.63 % to 30.63 %. Hydrogen bonds drive asphalt to approach water droplets, and the number of hydrogen bonds between asphalt and water droplets is almost 3 times that between asphalt and hydrates. This greatly disrupts the pre-existing asphalt films between hydrate particles and weakens the anti-aggregation effect. Water bridges between hydrate particles further promote hydrate aggregation. In the HWA model, hydrate particles begin to aggregate at 27.15 ns. Water droplets can easily change the distribution status of asphalt and other anti-agglomeration agents. When designing anti-agglomeration agents, it is necessary to consider maintaining the stability of water droplets to prevent water diffusion.

Investigation of flow and viscosity characteristics of hydrate slurries within a visual-loop system

With the gradual advancement of oil and gas exploration into deep offshore, the hydrate blockage has emerged as a critical concern for the flow assurance. We conducted constant-velocity hydrate formation and variable-velocity rheology experiments with a novel visual-loop to analyze slurry flow and viscosity change in pipelines. Results showed staged pressure variations during hydrate formation-aggregation-deposition process, and it could be analyzed judiciously with a developed viscosity model. Initially, hydrates dispersed as small flocculent particles with minor aggregation, gradually raising differential pressure, and the critical viscosity model parameter, hydrate aggregation rate (m) was <1. Subsequently, particle aggregation and wall adhesion dominated, resulting in reduced hydrate flow volume and possible blockage of special pipelines (e.g., dead-leg), with m-values >1. Finally, as hydrate growth continued, substantial adhesion to the pipeline reduced flow diameter, significantly increasing blockage risk. However, the addition of sufficient surface-active ingredients improved hydrate dispersibility and enabled the slurry to maintain the first stage, exhibiting long-term stability with an m-value <1. Additionally, the apparent viscosity of the hydrate slurry within the pipeline was accurately determined utilizing a novel approach, accounting for its yield-pseudoplastic behavior. The calculated viscosities closely matched post-sampling rheometer measurements, and were effectively predicted by the developed viscosity model.

Electrokinetic and Microstructural Peculiarities of the Portland Cement Hydration with Microadditives

AbstractThe results of given studies included a comparison of changes in temperature, redox potential, OH‐ions concentration and pH values in the Portland cement‐water‐additive system depending on the hydration time and features of hydration processes in the microstructure of the cement stone. The studied additives were selected taking into account the prospects for their use in the complex modifiers compositions for cement‐containing building materials. The results of electrokinetic measurements are presented and regularities and features of the influence of each studied additives on the processes of hydration structure and phase formation in Portland cement paste in the early stages of hardening are determined. The microstructure and fracture surfaces of cement stone samples formed during cement paste hardening with the optimal content of additives and features of hydration processes of cement stone were studied. The features of the mutual arrangement of individual phases in crystalline hydrate aggregates of cement stone, as well as the nature of the porosity of its microstructure, were investigated.

Gas Hydrate Formation and Slurry Flow Characteristics of Gas–Liquid–Solid Multiphase Systems

Hydrate formation, aggregation, and deposition have become major hazards for the safe transportation of oil and gas pipelines. Although there has been a great deal of research into the behavior of particles during hydrate formation and transport, there is less research into the multiphase generation and flow characteristics of hydrate gas and liquids. In this paper, the flow characteristics of hydrate slurry and the flow pattern transition in gas–liquid multiphase system were studied, and the generations of it were compared between a gas–liquid multiphase system and oil–water emulsion system. The results showed that the flow parameters such as pressure, pressure drop, and density fluctuated more drastically in the gas–liquid system than that in the emulsion system, the higher fluctuation meant a higher risk of pipe plugging. At the same time, the influence of pressure and dosage on multiphase flow pattern transformation and boundary change conditions were studied. A gas-slurry flow pattern transformation diagram was drawn based on the defined transformation conditions between flow patterns. The results also indicated that, with the increase of pressure from 5 to 6 MPa, the boundary of slug flow and air mass flow changed to the direction of higher gas and liquid flow velocity. While the boundary of slug flow and wave flow, stratified flow and wave flow changed to the direction of higher gas flow velocity. The boundary of slug flow and air mass flow changed to the direction of lower liquid flow velocity. In contrast, the boundary of slug flow and wave flow, stratified flow and wave flow, slug flow and stratified flow changed to the direction of higher gas flow velocity and lower liquid flow velocity in the 1% inhibitor period compared with that without the inhibitor. This study will provide theoretical references and technological supports for the safety of multiphase transportation pipelines and the safety of deep water production.

Investigation on microscopic forces between methane hydrate particles in gas phase dominated system

Hydrate aggregation and deposition on the pipe wall are the main causes of hydrate plugging in pipelines. Microscopic forces between hydrate particles are an important reference for determining the behavior of aggregation or separation from the pipe wall of hydrate particles. Based on a high-pressure visual micro-force measurement system, this study measured the hydrate particle-hydrate particle cohesive force and hydrate particle–wall liquid droplet adhesion force under pure water, as well as hydrate particle–wall liquid droplet adhesion force under anti-agglomerants (AAs). It was found that the magnitude of hydrate particle-hydrate particle cohesive force was ×10 mN/m, and the magnitude of hydrate particle–wall liquid droplet adhesion force was ×103 mN/m. The effects of 4 AAs in the methane gas-dominated system were evaluated from a micro-perspective, revealing that after adding DDBAB, D1021, AEO-9, and CDEA, the maximum reduction of adhesion force was 67%, 64%, 51%, and 53% compared with that under pure water, respectively. The mechanism of AAs reducing adhesion force was further explored, revealing that the adhesion force arose from a liquid bridge and was affected by the gas–water interfacial tension of solutions at low subcoolings. While at high subcoolings, the force was determined by the combined force of the liquid bridge and the hydrate shell. The addition of AAs reduced the gas–water interfacial tension of solutions, and the steric hindrance effect of AA molecules also weakened the tensile strength of the hydrate shell, leading to a decreased adhesion force. These experimental data can help deepen our understanding of the microscopic forces between methane hydrate particles, and provide experimental data and scheme design basis for wellbore flow assurance of deepwater gas wells.

Experimental study on visualization of TBAB hydrate formation in confined small channels

Hydrate crystals' microscopic characteristics and agglomerating morphologies play an important role in the hydrate reaction equipment's flow assurance and heat transfer. In order to study the formation process of hydrate, experimental quartz tubes with small diameters were selected, and a fully visualized flow loop system was established. The study investigated the effects of supercooling, solution concentration, tube diameter, and flow rate on hydrate blockage time and agglomeration morphology. The results show that under the same supercooling conditions, the density of single crystal hydrate formed in 10 wt%-20 wt% TBAB (Tetra-n-butylammonium bromide) hydrate solution is low, and the crystal front appears needle-like or sword-like, which is conducive to mass and heat transfer. High concentration TBAB solution(30 wt%-40 wt%) can form dense hydrate crystals, and the tip effect was significantly weakened. For low concentration TBAB solution, the increased flow rate can accelerate the formation of new nuclei and inhibit the growth of large crystals. Grout solutions with different particle sizes can be obtained by adjusting the flow rate. It was found that the initial morphology of TBAB hydrate crystals included spherical and cylindrical shapes, and the morphological evolution process of a single hydrate crystal was similar. Finally, a microscopic physical model of the TBAB hydrate growth and aggregation process was established.

Co-deposition characteristics of hydrates and sands in gas-salty water-sands flow system

The study of hydrate flow assurance is critical for the efficient and safe development of natural gas hydrates. The natural gas produced by the dissociation of hydrate may re-hydrate in the gathering pipeline, and even lead to the blockage of the gathering pipeline. However, the co-deposition mechanism of the Micron-sized Sand Particles(MSPs) produced in the exploitation, and natural gas hydrate particles during pipeline transportation is still unclear. Therefore, the hydrates and MSPs slurry flow law and co-deposition mechanism are studied by horizontal high-pressure flow loop experiments. A new method to calculate the thickness of the deposition layer for water-dominant systems is proposed. Then, based on the variation of deposition layer thickness, the solid deposition process and flow behaviors are discussed in the pure water system, the salt-containing system, the sand-containing system, and the salt-sand coexistence system, respectively. The results show that the hydrate-MSPs co-deposition process is divided into five stages in the salt-sand coexistence system: the initial deposition stage, hydrate formation and adhesion on the pipe wall stage, rapid deposition stage, deposition layer sloughing stage, and stable deposition stage. And the hydrate-MSPs co-deposits in various stages are characterized by the Hydrate Aggregates Deposition Rate, the Hydrate Aggregates Deposition Layer Thickness, and the particle Chord Length Distribution. The influence of sand particle concentration and initial flow velocity on the hydrate-MSPs co-deposition process in the salt-sand coexistence system is also explored. In addition, the interaction between particles in the deposition process is revealed by Particle Vision and Measurement. The findings of this work provide insights into the solid deposition process in the salt-sand coexistence system, which is beneficial for flow assurance in natural gas hydrate production.

The impact of mineral compositions on hydrate morphology evolution and phase transition hysteresis in natural clayey silts

Natural gas hydrate is a clean and high-efficient energy resource, and more than 90% of its reserves are contained in fine-grained (typically clayey silts) sediment. In this work, for the first time, the micro-scale imaging is performed to explore hydrate phase transition, morphology evolution and fundamental characteristics (mineral compositions, pore structures and seepage capacity) in clayey silt sediments. The results indicate that clayey silts formation properties strongly depend on dominant minerals component in the sediments. The clay-rich clayey silt possesses more microcapillary interstice with smaller permeability than that in quartz-rich sediment. Hydrates generally occur as microfracture-filling (veins) and grain-displacing (nodulus) in sand-rich clayey silt. While they occur in the form of fracture-filling (vein) and foraminifera-filling in clay-rich clayey silt sediments. Biological fossils (especially foraminifera) provides potential space for hydrate aggregates. But hydrate formed inside it depends on the structures of fossils, the mineral components and pore structure of surrounding matrix. The hysteresis between hydrate formation and decomposition found to be more significant in clay-rich clayey silt sediment than quartz-rich sediment. And this hysteresis inside foraminifera is much more serious compared with that in matrix. In addition, dispersed pore-filling hydrates forms during decomposition, which has adverse effect on continuous gas production.

Microscopic Insights into the Effects of Anti-Agglomerant Surfactants on Surface Characteristics of Tetrahydrofuran Hydrate

The formation of clathrate hydrates in pipelines is potentially threatening to exploration and gas transportation in the petroleum industry. To reduce such risks, various surfactants have been explored as anti-agglomerants to prevent the aggregation of hydrate particles. However, the anti-agglomeration mechanisms are not yet fully understood. In this study, modified atomic force microscopy is first developed to investigate the effects of two surfactants, namely, 1-naphthaleneacetic acid and dodecylbenzenesulfonic acid, on the surface of a tetrahydrofuran (THF) hydrate. The surfactants have remarkable effects in terms of changing the grain size and decreasing the grain boundary depth and surface roughness of the THF hydrate. In addition, the surfactants reduce the quasi-liquid layer (QLL) thickness of the THF hydrate and the adhesion forces between the hydrate and the microsphere probe. This phenomenon may be caused by the changes induced by surfactant molecules on the water–guest molecule structure near the gas/water interface. Thus, hydrate growth is enhanced in the QLL. The adhesion forces decrease linearly with QLL thickness after adding the surfactants. These findings indicate that surfactants reduce the adhesion forces by reducing the QLL thickness at higher temperatures. The effects of surfactants on the QLL thickness and surface morphology of the hydrate are investigated, providing critical information on the cohesive behaviors among hydrate particles or between hydrate particles with other materials. Our work provides new insights into the underlying mechanism of how surfactants prevent hydrate aggregation, which is crucial in hydrate-related safety management.

Hydrate growth and agglomeration in the presence of wax and anti-agglomerant: A morphology study and cohesive force measurement

During deep-sea and ultra-deep-sea oil and gas exploitation, multiphase transmission lines are prone to be clogged by sediments produced by the various components in crude oils under extreme subsea conditions, such as hydrates, wax, resins, and asphaltenes. The pipelines face higher plugging risks when these deposits exist simultaneously. In order to elucidate the effects of wax and anti-agglomerants (AA) on hydrate growth and aggregation, microscopic morphology observation and cohesive force measurement of cyclopentane hydrate particles were conducted through a piece of equipment similar to the micromechanical force (MMF) apparatus. Results showed that in the low concentration of AA (0.05 wt%), hydrate particles experienced an approximately 10 % reduction in the profile area after converting water droplets to hydrate particles. Furthermore, the cohesive force between hydrate particles decreased from 8.57 ± 0.90 mN/m to 3.51 ± 0.43 mN/m as the AA concentration increased from 0.05 to 0.2 wt%. On the other hand, the presence of wax significantly altered the morphologies of hydrate particles. When wax coexisted with AA, the hydrate cohesive force was reduced by wax under low AA concentration (0.05 wt%) but increased under higher AA concentration. For a given concentration of AA, the hydrate cohesive force increased with the increasing wax content (from 0.1 to 0.3 wt%), indicating that wax crystals weakened the efficiency of AA, such as Span 80. Additionally, the effect of surface wetness of waxy hydrate particles on their cohesion was also investigated. The liquid bridge appeared between wet waxy hydrate particles, while the solid–solid contact existed between dry waxy hydrate particles. The cohesive force between dry waxy hydrate particles was smaller. Either liquid bridge or solid–solid contact that dominated hydrate cohesive force was affected by wax.

Effect of Surfactants with Different Hydrophilic–Lipophilic Balance on the Cohesive Force between Cyclopentane Hydrate Particles

Effective control of the cohesive force between hydrate particles is the key to prevent their aggregation, which then causes pipeline blockage. The hydrophilic–lipophilic balance (HLB) value of surfactants was proposed as an important parameter for the evaluation and design of hydrate anti-agglomerants. A microscopic manipulation method was used to measure the cohesive forces between cyclopentane hydrate particles in the presence of Tween and Span series surfactants with different HLB values; moreover, the measured cohesive force was compared with the results of calculations based on the liquid bridge force model. Combined with the surface morphology and wettability of the hydrate particles, we analyzed the mechanism by which surfactants with different HLB values influence the cohesion between hydrate particles. The results show that for both Tween (hydrophilic, HLB &gt; 10) and Span (hydrophobic, HLB &lt; 10) surfactants, the cohesive force between cyclopentane hydrate particles decreased with decreasing HLB. The experimental results were in good agreement with the results of calculations based on the liquid bridge force model. The cohesive force between hydrate particles increased with increasing concentration of Tween surfactants, while in the case of the Span series, the cohesive force decreased with increasing surfactant concentration. In the formation process of cyclopentane hydrate particles, the aggregation of low-HLB surfactant molecules at the oil–water or gas–water interface increases the surface roughness and hydrophobicity of the hydrate particles and inhibits the formation of liquid bridges between particles, thus reducing the cohesion between particles. Therefore, the hydrate aggregation and the associated blockage risks can be reduced.

Exploiting Natural Oil Surfactants to Control Hydrate Aggregation

Exploiting Natural Oil Surfactants to Control Hydrate Aggregation

Effects of wax on CH4 hydrate formation and agglomeration in oil–water emulsions

The solid sediments, resulted from hydrate formation and wax crystallization in crude oil, may generate catastrophic blockage in the pipeline under adverse conditions; this poses a formidable threat to the transportation of deep-sea crude oil. To shed light on the mechanism of the effects of waxes and hydrates in deep-sea crude oil under coexisting conditions, this work systematically investigates the effects of wax crystal precipitation and hydrate formation time-series on hydrate nucleation, growth, aggregation, and crystal structure in oil–water emulsions through experiments. Research results demonstrate that the time sequence of wax crystal precipitation and hydrate formation is concerned with the possibility of significant solid deposit formation; when wax crystal precipitation precedes hydrate formation, the wax crystals inhibit hydrate nucleation and growth; conversely, when hydrate formation precedes wax crystal precipitation, the wax significantly reduces hydrate particle aggregation, which in turn improves the flow characteristics of the hydrate slurry. Additionally, the microscopic analysis further reveals that the presence of wax has no effect on the crystal structure of CH4 hydrate, yet it has a significant effect on the distribution of CH4 in the cavities, i.e. it reduces the occupancy of large cages.

Deep-Sea Sediment and Water Simulator for Investigation of Methane Seeping and Hydrate Formation

The ubiquitous methane seeping process in the deep-sea environment could significantly influence the global methane cycle and carbon budget. Hydrate formation on the methane bubble during the seeping process is an important way for sequestrating methane during bubble migration. Uncovering the complete methane leakage process needs to reveal the methane leakage pathway and hydrate conversion mechanism. Hence, we built a deep-sea sediment and water simulator to investigate the methane seeping and hydrate formation. The simulator can mimic the deep-sea sediment and water environment with a lower sediment chamber and an upper seawater chamber. The monitoring of the bubble migration path and hydrate transformation and aggregation in the sediment chamber is realized mainly through the spatial distribution of electric resistance and temperature variations. The seawater chamber is equipped with a built-in movable camera and four external windows to observe the rising and morphological evolution of gas and hydrate bubbles. The quantitative storage and escape of CH4 gas could be realized through the measurement of multiple gas/liquid collection ports and cumulative incoming/outgoing gas volume. In addition, a movable biological liquid injection port was designed in the seawater chamber for the coupling CH4 conversion of hydrate formation and microorganism-mediated oxidation. Through the experimental test on each function of the system, the effectiveness of the device was proved. The development of this device has pioneering significance for the experimental simulation of the methane seeping process in a simulated submarine cold spring area.