Hydrate Plug Research Articles

Molecular mechanism for methane hydrate nucleation on corroded iron surface

Gas hydrate plugging in oil and gas transportation pipelines is a knotty problem for flow assurance practices. The nucleation mechanism of methane hydrate on corroded iron pipeline surface is still unclear. In this work, both smooth and corroded iron particles were packed into a hydrate reactor to investigate the relationship between the induction time of methane hydrate and the liquid–metal contact area. Experimental results indicated an insignificant difference among the particles of varied specific surface areas when submerged in the aqueous phase. However, the induction time was reduced by more than 60% when the particles were located above the gas–liquid interface and further shortened by 80% if the particles were corroded. Molecular dynamics simulations indicated that decreased interlayer spacing between the iron layers would facilitate methane hydrate formation in the initial period. Based on our energy analysis, this was ascribed to an increased curvature of the gas–liquid interface, causing a decrease of energy barrier by 54% for a methane molecule to transfer from the interface into the bulk liquid and subsequently, an increase of methane concentration in solution. Meanwhile, two layers of water molecules were observed to adsorb on the iron surface stably and no hydrate cages formed in such region throughout the simulation time. The microscopic phenomenon agreed well with the experimental results, which highlighted the influence of the gas–liquid–metal three-phase interface other than the liquid–metal contact area upon methane hydrate nucleation. The results shed new insights on predicting the prioritized locations of methane hydrate formation in metallic pipelines to reduce the potential hydrate plugging risk.

Monitoring gas hydrates under multiphase flow in a high pressure flow loop by means of an acoustic emission technology

The formation of natural gas hydrates in oil and gas pipelines is an important concern due to the risk of hydrate blockage. In order to reduce the expenses with the use of chemicals to avoid hydrate plugging, more studies about the slurry flow and the mechanisms of blockage in flowing conditions are necessary. In this study, it is presented an experimental work combined with a multi-instrumental data analysis to allow monitoring hydrate formation and track the particles in time and space. Acoustic emission (AE) is used in a high pressure flow loop apparatus to capture acoustic waves generated by the flow and to detect the presence of hydrates flowing in the system. The tests are conducted with Kerdane oil, saline water and natural gas at 75 bar and 4 °C. Two tests are presented, one at 30 and another at 80% water cut (water fraction in volume). It is shown that, with the absolute energy obtained from the AE sensors, it was possible to detect the beginning of hydrate crystallization and the hydrates displacement in the pipeline, because the absolute energy increases as the collisions of particles generate more acoustic emission. The results show that, for the tests performed, the flow became heterogeneous after hydrate formation, with some regions of the flowing volume containing more hydrates than others. It is also shown that the non-flowing volume of hydrates with entrapped liquid, caused by deposition or settling, can be estimated with AE.

Gas hydrate deposit formation in transient flowloop tests and mitigation with a surface treatment

Thermodynamic and thermal mitigation strategies are traditionally utilized to prevent gas hydrate formation but may be rendered ineffective for certain unplanned, extended shut-in scenarios. Unfortunately, the current knowledge regarding transient gas hydrate formation has been extremely limited to only a few studies and unable to address this complex issue adequately. This work, conducted in a lab-scale flowloop, aims to add to the understanding of this area by delving into the implications of transient conditions on gas hydrate formation mechanisms, while also exploring a possible mitigation strategy of a surface treatment. Specifically, the effects of phase separation on gas hydrate formation locations, transportability, and plugging are presented for an oil-dominated system. An omniphobic surface treatment is shown to affect initial gas hydrate deposition and its wall adherence strength, as well as the overall plugging outcome. Overall, this work combines observational information with process data measurements to provide a better understanding of phase separated gas hydrate systems and passive deposition mitigation strategies. This can further aid advanced gas hydrate modeling efforts, which currently do not adequately address transient flow effects on phase separation/dispersion. Furthermore, it offers representative gas hydrate testing for coatings, which have exclusively been limited to non-flowing and/or bench-scale analysis, to give confidence in their potential application as advanced deposition prevention tools.

Numerical simulation of hydrate slurry flow and deposit behavior based on openfoam-IATE

With the extension of oil exploitation from offshore to the deep sea, the development and utilization of natural gas hydrate have become one of the hottest energy issues. However, the agglomeration between hydrate particles will lead to severe pipeline hydrate plugging. Therefore, a dynamic model considering phase change about hydrate formation and decomposition as well as aggregation was proposed based on the interface area transportation equation and convection heat transfer equation, and then used to simulate hydrate slurry flow in this study. By integrating with traditional solid-liquid flow models, the aggregation, breakage, nucleation of hydrate particles, and deposits insulation were all considered in CFD software OpenFOAM-4.x. The influences of flow rate and the safe area for hydrate slurry flow were analyzed emphatically. Results show that flushing has a good dissociation effect on hydrate deposits formed by low-concentration slurry. By comparing deposition conditions of different concentrations and flow rates, it can be seen that high-concentration slurry results in a larger slope and thickness of the deposition front, while the flow rate mainly affects the extension of the deposits length. With the increase of the flow rates, the hydrate deposits evolve from belt-like deposits to point-like deposits. In addition, the hydrate deposition morphology function of different working conditions was constructed by the principal component analysis method.

Multi-functional oilfield production chemicals: maleic-based polymers for gas hydrate and corrosion inhibition

Several chemical problems can occur during the production of oil and gas through flow lines. This includes corrosion, scale deposition and gas hydrate plugging. Three separate chemicals may be needed to treat these issues. Kinetic hydrate inhibitors (KHIs) are used in cold oil or natural gas production flow lines to prevent the formation and plugging of the line with gas hydrates. They are often injected concomitantly with other production chemicals such as corrosion and scale inhibitors. KHIs are specific low molecular weight water-soluble polymers with amphiphilic groups formulated with synergists and solvents. However, many corrosion inhibitors (CIs) are antagonistic to the KHI polymer, severely reducing the KHI performance. It would be preferable and economic if the KHI also could act as a CI. We have explored the use of maleic-based copolymers as KHIs as well as their use as film-forming CIs. KHIs were tested using a natural gas mixture in high pressure rocking cells using the slow constant cooling test method. A terpolymer from reaction of vinyl acetate:maleic anhydride copolymer with cyclohexy lamine and 3,3-di-n-butylaminopropylamine (VA:MA-60% cHex-40% DBAPA), gave excellent performance as a KHI, better than the commercially available poly(N-vinyl caprolactam) (PVCap). CO2 corrosion inhibition was measured by Linear Polarization Resistance (LPR) in a 1 litre CO2 bubble test equipment using C1018 steel coupons. The new terpolymer gave good CO2 corrosion inhibition in 3.6 wt% brine, significantly better than PVCap, but not as good as a commercial imidazoline-based surfactant corrosion inhibitor. The terpolymer also showed good corrosion inhibition efficiency at high salinity conditions, (density 1.12 g/cm3). VA:MA-60% cHex-40% DBAPA shifted the open-circuit potential to more positive values and significantly decreased the corrosion rate.

Detection of hydrate plugs inside submarine pipelines using neutrons

ABSTRACT The objective of this study was to demonstrate the feasibility of localising and detecting hydrate plugs inside submarine pipelines, in situ and contactless, using neutron-induced analytical techniques. Cold and fast neutron-beam instruments at Heinz Maier-Leibnitz Zentrum (MLZ) were used to show that neutrons penetrate through the thick wall and the insulation of such pipes and even the induced gamma radiation can be detected outside to perform a non-destructive chemical analysis within the pipe. It was found that the change in the hydrogen concentration caused by a possible hydrate plug can be detected in seconds; while with a detailed analysis at a given spot lasting for a few hours, it is possible to unambiguously identify the hydrate phase inside the hydrocarbon phase.

Artificial Neural Network-based detection of gas hydrate formation

In the production process of natural gas one of the major problems is the formation of hydrate crystals creating hydrate plugs in the pipeline. The hydrate plugs increase production losses, because the removal of the plugs is a high cost, time consuming procedure. One of the solutions used to prevent hydrate formation is the injection of modern compositions to the gas flow, helping to dehydrate the gas. Dehydratation obviously means that the size of hydrate crystals does not increase. The substances used in low concentrations, have to be locally injected at the gas well sites. Inhibitor dosing depends on the amount of gas hydrate present. In the article two Artificial Neural Network (ANN)-based predictive detection solutions are presented. In both cases the goal is to predict hydrate formation. Data used come from two solutions. In the first one measurements were performed by a self-developed and -produced equipment in this case, differential pressure was used as input. In the second solution data are used from the measurement system of a motorised chemical-injector device, in this case pressure, temperature, quantity and type of inhibitor were used as inputs. Both systems are presented in the article.

Experimental Study on the Effect of Combination of Thermodynamic Inhibitors’ and Kinetic Inhibitors’ Hydrate Inhibition

In deepwater gas well testing, the high-pressure and low-temperature environment in the wellbore provides conditions for hydrate formation. When the thermodynamic inhibitor is used, it needs a large amount and is difficult to inject. Low-dose hydrate inhibitors such as kinetic inhibitors are rarely used in high supercooling and natural gas–dominated environments. The mixed use of thermodynamic inhibitors and kinetic inhibitors provides a new way. By simulating the wellbore temperature and pressure conditions during the deepwater gas well testing, the inhibiting effect of the mixtures of PVCap and methanol with various concentrations was experimentally tested by using rocking cells with a step-cooling method at 21MPa. The effect of PVCap and its mixture with methanol on hydrate plugging was evaluated by monitoring the movement of slider in the rocking cell. The results showed that 5 wt%, 16 wt%, and 20 wt% methanol mixed with 0.5 wt% PVCap could prolong the induction time, and the higher the methanol concentration, the longer the hydrate induction time. Among them, the best combination of 20wt% methanol and 0.5wt% PVCap can inhibit the hydrate for 379 min. The hydrate was formed but did not block the rocking cell, indicating that the combination of PVCap and methanol could not only prolong the hydrate formation time but also avoid the blockage after hydrate formation. The hydrate formation rate with various inhibitor concentrations was calculated; it may provide some guidance for making a shut-in plan for on-site wells.

Rapid screening method for hydrate agglomeration and plugging assessment using high pressure differential scanning calorimetry

Gas hydrate formation during subsea oil and gas production can result in flowline blockages, which present enormous economic and safety risks. Certain crude oils have natural anti-agglomerant (AA) properties, which facilitate their non-plugging behavior over a defined operating window. Thus, it is crucial to be able to easily screen a crude oil system for its tendency to form hydrate plugs. In this paper, we present a Hydrate Plugging Assessment (HPA) technique that can be used as a rapid screening method to evaluate the plugging tendency using a high pressure differential scanning calorimeter (HP-DSC). The technique requires a small crude oil sample (~15 mg), and the experimental time is relatively short. In this work, HP-DSC tests were conducted on 13 crude oils (22 to 45 ˚API). Tests were conducted at various water contents, salinity, chemical dosage (without/with AAs), and different hydrate structures. The results show that an increase in water content destabilizes the emulsion, and increases the hydrate plugging risks. An increase in salinity decreases hydrate plugging tendency. Different hydrate crystal structures showed that for a similar water content, salinity, and driving force, structure II (sII) hydrates have a slightly greater agglomeration tendency compared to structure I (sI) hydrates. Finally, the effect of combining a low stability oil with a high stability oil showed that the resulting emulsion retained the high stability property, paving the possibility for natural oil treatment. In summary, these studies show that the HPA technique is a cost-effective and attractive method to evaluate hydrate plugging tendency.

Numerical Simulation of Swirl Flow Characteristics of CO2 Hydrate Slurry by Short Twisted Band.

The development of oil and gas resources is gradually transferring to the deep sea, and the hydrate plugging of submarine pipelines at high pressures and low temperatures is becoming an important problem to ensure the safety of pipeline operations. The swirl flow is a new method to expand the boundary of hydrate safe flow. Numerical simulation of the hydrate slurry flow characteristics in a horizontal pipeline by twisted band has been carried out, and the flow of CO2 hydrate slurry in low concentration has been simulated by the RSM and DPM models. The results show that the heat transfer efficiency is also related to Re and particle concentration. The velocity distribution has the form of symmetrical double peaks, and the peaks finally merge at the center of the pipeline. Vortexes firstly appear on both sides of the edge of the twisted band, and then move to the middle part of the twisted band. Finally, the vortex center almost coincides with the velocity center. The rotation direction of hydrate particles is the same as the twisted direction of the twisted band, twist rate (Y) is smaller, Re is larger, and the symmetric vortex lines merge farther away. The initial swirl number is mainly related to Y, but not Re. The swirl flow attenuates exponentially, and its attenuation rate is mainly related to Re, but not Y. Compared with ordinary pipelines, the swirl flow can obviously improve the transportation distance of hydrate slurry.

Prediction of hydrate formation and plugging in the trial production pipes of offshore natural gas hydrates

Hydrate plugging in pipes is a serious issue that affects flow safety in the trial production of offshore natural gas hydrates. Current research on hydrate flow assurance has primarily focused on conventional oil-and-gas production and transportation processes. Therefore, models for predicting the hydrate formation region and hydrate deposition in the trial production pipes of offshore natural gas hydrate were developed in the present study, which can be used to estimate the risk of hydrate plugging in the production pipes. The results revealed that hydrate formation conditions could be satisfied in the water production pipe at a low water production rate, and hydrate generation was possible in a certain region in the gas production pipe. The hydrate deposition layer formed in the gas production pipe grew in a non-uniform manner; the longer the production time, the more obvious was the non-uniform distribution; this resulted in a high risk of hydrate plugging after a certain process time. Additionally, as the rate of gas production increased, the hydrate formation region in the gas production pipe gradually moved upward and decreased in size, and the degree of hydrate deposition also slightly decreased. Finally, the installation of a heater at the bottom of the gas pipe at a high production rate was proposed to increase the gas temperature, thereby decreasing the possibility of hydrate formation and plugging. For the water production pipe, a low dose of kinetic inhibitors or anti-agglomerants could be injected to avoid the risk of hydrate plugging and reduce the corresponding prevention costs. This study can provide a theoretical basis and technical support for the efficient prevention of hydrate plugging during production trials or long-term production of offshore natural gas hydrates.

New «green» inhibitors of gas hydrate formation for the oil and gas industry based on polysaccharides

The thermobaric conditions for the formation of gas hydrates in the presence of the sodium salt of carboxymethylcellulose, dextran, and arabinogalactan were studied in a quasi-equilibrium thermodynamic experiment. It is established that polysaccharides slow down the rate and change the conditions of gas hydrate formation of a mixture of natural gases, showing the properties of a thermodynamic and kinetic inhibitor with technological efficiency exceeding methanol by 170-270 times when used in the same dosages. The results of the development of a «green» synergistic inhibitor of gas hydrate formation «Glycan RU» on their basis are presented, which includes a combination of thermodynamic and kinetic inhibitors. Pilot field tests of «Glycan RU» were carried out at the wells of the Priobskoye, Prirazlomnoye, Ombinsky, Zapadno-Ugutskoye oilfields. It was found that at dosages of 1000 g/m3 and 500 g/m3, there is no formation of hydrate plugs in the annulus. «Glycan RU» is recommended for industrial use by the technology of periodic injection and/or continuous dosing through wellhead dispensers. Keywords: carboxymethylcellulose; dextran; arabinogalactan; polysaccharides; «green» inhibitor of gas hydrate formation; «Glycan RU».

SUBSTANTIATION OF APPLICATION OF UNDERGROUND REDUCTION CHAMBER IN LIQUEFIED PETROLEUM GAS SUPPLY SYSTEMS

Statement of the problem. When reducing the vapor phase of propane-butane in the pressure regulators of the above-ground closet gas control points, water falls out in free form and at subzero temperatures of ice and crystalline hydrates formation. In order to prevent this, methods are employed in the form of applying thermal insulation and heating the inner space of the cabinet, which significantly increases the cost of the structure and the reduction process. As an alternative, the authors set forth an underground reduction chamber. The article provides a scientific rationale for the use of this underground chamber in the practice of gas supply to consumers. Results. The configuration of the reduction chamber has been substantiated, mathematical modeling of the heat exchange processes of the chamber with the surrounding soil massif has been performed, the thickness of the thermal insulation of the ascending section of the vapor phase and the reduction chamber has been selected, and the process of reduction of the vapor phase in pressure regulators has been simulated. Conclusions. According to the results of the studies, the cylindrical shape is optimal for the reduction chamber, which provides the minimum total surface of the enclosing structures. The implementation of the economic and mathematical model made it possible to recommend the optimal thicknesses of the thermal insulation of the chamber and the ascending section of the vapor phase, enabling the process of throttling of the liquefied petroleum gas vapor phase in pressure regulators without the release of free water and the formation of ice and hydrate plugs.

Quantitative hydrate deposition prediction method and application in deep-water or permafrost gas pipelines

Hydrate formation in pipelines seriously affects the efficiency of energy transmission. Adopting the production process of gas pipelines in deep-water or permafrost regions as the engineering application background, hydrate formation and deposition characteristics at different locations in gas pipelines are analyzed to realize the quantitative prediction of high-risk areas and degree of hydrate plugging in pipelines. A typical deep-water gas pipeline in the South China Sea is selected as an example. The calculation results show that the long-distance pipeline exhibits an obvious hydrate blockage risk area, which occurs 700-3200 m away from the pipeline inlet. The high-risk area of hydrate plugging in the system moves upstream of the pipeline with decreasing ambient temperature. The risk of hydrate blockage increases with decreasing pipeline inner diameter. The established quantitative prediction method for hydrate deposition in deep-water or permafrost gas pipelines accurately locates high-risk areas of hydrate plugging, which could effectively guide hydrate prevention and notably reduce the cost of hydrate control in deep-water or permafrost gas pipelines.

Numerical Simulation Study on Flow Laws and Heat Transfer of Gas Hydrate in the Spiral Flow Pipeline with Long Twisted Band.

The natural gas hydrate plugging problems in the mixed pipeline are becoming more and more serious. The hydrate plugging has gradually become an important problem to ensure the safety of pipeline operation. The deposition and heat transfer characteristics of natural gas hydrate particles in the spiral flow pipeline have been studied. The DPM model (discrete phase model) was used to simulate the motion of solid particles, which was used to simulate the complex spiral flow characteristics of hydrate in the pipeline with a long twisted band. The deposition and heat transfer characteristics of gas hydrate particles in the spiral flow pipeline were studied. The velocity distribution, pressure drop distribution, heat transfer characteristics, and particle settling characteristics in the pipeline were investigated. The numerical results showed that compared with the straight flow without a long twisted band, two obvious eddies are formed in the flow field with a long twisted band, and the velocities are maximum at the center of the vortices. Along the direction of the pipeline, the two vortices move toward the pipe wall from near the twisted band, which can effectively carry the hydrate particles deposited on the wall. With the same Reynolds number, the twisted rate was greater, the spiral strength was weaker, the tangential velocity was smaller, and the pressure drop was smaller. Therefore, the pressure loss can be reduced as much as possible with effect of the spiral flow. In a straight light flow, the Nusselt number is in a parabolic shape with the opening downwards. At the center of the pipe, the Nusselt number gradually decreased toward the pipe wall at the maximum, and at the near wall, the attenuation gradient of the Nu number was large. For spiral flow, the curve presented by the Nusselt number was a trough at the center of the pipe and a peak at 1/2 of the pipe diameter. With the reduction of twist rate, the Nusselt number becomes larger. Therefore, the spiral flow can make the temperature distribution more even and prevent the large temperature difference, resulting in the mass formation of hydrate particles in the pipeline wall. Spiral flow has a good carrying effect. Under the same condition, the spiral flow carried hydrate particles at a distance about 3–4 times farther than that of the straight flow.

Assessment of hydrate flow obstacles during the initial restarting period of deep-water gas wells

Hydrate flow obstacles encountered during the exploitation of deep-water gas fields has received an increased attention. Based on the variations in the wellbore temperature of a deep-water gas well during the initial restarting period, and considering the interrelationship between the hydrate behavior and heat transfer, a prediction model for hydrate flow obstacle was established by comprehensively considering the hydrate formation, deposition, and decomposition. This model could be used to analyze the hydrate formation and decomposition regions dynamically and depict the evolution of the hydrate plug quantitatively during the restarting period. The computation results demonstrated that the wellbore temperature increased with the restarting time, which caused the hydrate formation region to decrease accordingly. During the initial restart under testing operations, hydrates always formed at low gas production rates in the tubing, which could plug the tubing after a certain restarting time. The risk of hydrate flow obstacle first increased and then decreased with an increase in the restarting production rate. During the initial restart under production operations, hydrates only formed at the initial restarting stage, which ranged from several minutes to more than 10 h. The hydrate flow obstacle risk first increased and then decreased with the restarting time, and no hydrate plugging occurred during the initial restarting period of the entire production process. Finally, the measures for preventing hydrate plugging during the initial restarting period were discussed. This work provides a valuable theoretical reference for preventing hydrate plugging during the initial restarting period of a deep-water gas well.

Preparation and performance of biomimetic superhydrophobic coating on X80 pipeline steel for inhibition of hydrate adhesion

The formation and accumulation of clathrate hydrates in oil/gas pipelines are responsible for flow blockages. How to effectively prevent the blockage of hydrate in the pipeline? Pipeline coating, as a potential new technology, is expected to solve this problem. In the present work, a biomimetic flower like CeO2/pDA@X80 coating was first fabricated using static self-assembly method. The coating exhibited excellent super-hydrophobicity both in air and oil conditions with contact angles of 154.7°, 155.5° and sliding angles of 3°, 2°, respectively. The coating possesses good mechanical stability, which was able to maintain its super-hydrophobicity during 2 h sand abrasion test. The adhesive ability of the CeO2/pDA@X80 coating was satisfied with the requirements of Grade 2, that standing for good adhesion between the coating and substrate. In addition, the hydrate adhesive forces were measured between CeO2/pDA@X80 coating and cyclopentane hydrate by a micromechanical force method. The results suggested that the hydrate adhesion force of CeO2/pDA@X80 coating was about 98.9% below compared with X80. More importantly, the coating can still achieve ultralow hydrate adhesion after 2 h sand abrasion tests. When a liquid water droplet was hanged on the X80 surfaces, the hydrate can be firmly connected with the substrate and failed to be separated, however, the coating can effectively avoid this condition, because the water droplet can easily detach from the superhydrophobic surface. The coating method can provide an alternative choice for preventing hydrate blockages and play a supplementary role in preventing hydrate plugging.

Gas Hydrate and Corrosion Inhibition Performance of the Newly Synthesized Polyurethanes: Potential Dual Function Inhibitors

Gas hydrate plugging and corrosion are two major flow assurance problems in oil and gas transmission pipelines. Since an incompatibility problem can occur during the simultaneous injection of gas h...

Inhibition of Methane Hydrates Using Biodegradable Additives

Prevention of hydrate plugs during transportation of oil and natural gas in the pipeline network is challenging. Certain additives are often introduced into the process to eliminate/delay plug formation. Dominantly synthetic inhibitors are deployed in large volumes (∼20 to 30% by volume) to counter the problem and are highly expensive and, in some circumstances, toxic. The search for novel additives that are eco-friendly and act as inhibitors is in demand. The present study reports the thermodynamic inhibition (THI) capacity of some vastly available natural biopowders, such as Azadirachta indica (neem), Piper betel (betel), and Nelumbo nucifera (Indian lotus) in low dosage (0.5 wt %), on methane hydrate (MH) formation. Since the gas flow is dynamic, experiments are conducted in stirred geometry by varying the speed range from 0 to 1000 rotations per minute (rpm). All of the studies are performed in the isochoric method procedure. The biopowders act as efficient thermodynamic hydrate inhibitors. Once the nucleation triggers, they act as kinetic hydrate promoters. Since sodium dodecyl sulfate (SDS) is an excellent kinetic hydrate promoter in both stirred and nonstirred geometries, the obtained results are compared with the SDS system. Hydrate nucleation is triggered at higher subcooling (∼8 to 10 K) in the presence of water-soluble bioextracts. The neem leaf extracts showed a ∼30% lower hydrate conversion than SDS in identical experimental conditions. Two-stage hydrate nucleation occurred at higher stirring speeds, and the hydrate conversion is inferior (∼6%) between the primary and secondary stages. The addition of biopowder extracts is useful in controlling hydrate formation. A small quantity of biopowders provides higher inhibition and reduces synthetic chemicals used in real-time applications.

Method for Determining the Mass Flow for Pressure Measurements of Gas Hydrates Formation in the Well

The work focuses on the inverse problem of determining differential equation coefficients for additional information on the behavior of solution. Furthermore, the algorithm for determining parameters of systems of ordinary differential equations on the basis of stomatal pressure measurements is generalized for the model of hydrate formation when the internal well section of changes with time and also has to be determined during the solution of the general problem. The computational experiment has been conducted for wells of Otradninsky gas condensate deposits of the Republic Sakha (Yakutia), the exploitation of which indicates that the complications are most likely caused by formation of gas hydrates both in the bottom-hole and in the well and its plumes. It has been established that the most important influence on the dynamics of hydrate plugs formation in wells is the gas production mode, its equation of state, reservoir and geocryological conditions. Time dependency of mass flow has been determined, which knowledge will make it possible to control the change of flow area of the entire well and, if necessary, to prevent and remove formation of natural gas hydrates