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1
PSR, Prasad. "Influence of Low Dosage Green Extracts on CO2 Hydrate Formation." Petroleum & Petrochemical Engineering Journal 4, no. 3 (2020): 1–10. http://dx.doi.org/10.23880/ppej-16000234.
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Gas clathrates or the gas hydrates are the solid ice particles encapsulating gas molecules (commonly methane - CH 4 and carbon dioxide - CO 2 ) within the water cavities, at moderately high-pressure and low-temperature conditions. The petroleum extraction process from the deep-sea environment favours the occurrence of hydrates, and CO 2 hydrates require milder p, T conditions than CH 4 hydrates. Thus, chocking the pipeline network and obstructing the petroleum flow; leading to a substantial economic loss and hazardous. Conventional hydrate inhibitors (methanol, ethanol, glycols, Amino acids, and ionic liquids, etc.) are used, which are chemically toxic, costly, and required in large volumes (30-50 wt %). Therefore a suitable additive preventing plug formation is on high demand. The present study disclosures the use of three green leaf extracts Azadirachta indica (Neem - NL), Piper betel (betel - BL), and Nelumbo nucifera (Indian lotus - LL) in low dosage (0.5 wt %) on the CO 2 hydrate formation. Experiments are conducted in the isochoric method, with 0.5 wt % green-additives. The hydrates nucleate at higher subcooling (̴ 7-9 K), and the conversion is about ̴ 33-40 %. The induction time is nearly the same both pure- H 2 O and H2O with LL, whereas, it is ̴3 and 4 times higher for NL and BL. The hydrate growth kinetics also indicate significant retardation (2 – 4 times). Thus, these bio-additives, in low-dosage, could be an effective THI and also KHI for preventing the CO 2 hydrates plugs.
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Lv, Xiaofang, Bohui Shi, Shidong Zhou, Shuli Wang, Weiqiu Huang, and Xianhang Sun. "Study on the Decomposition Mechanism of Natural Gas Hydrate Particles and Its Microscopic Agglomeration Characteristics." Applied Sciences 8, no. 12 (2018): 2464. http://dx.doi.org/10.3390/app8122464.
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Research on hydrate dissociation mechanisms is critical to solving the issue of hydrate blockage and developing hydrate slurry transportation technology. Thus, in this paper, natural gas hydrate slurry decomposition experiments were investigated on a high-pressure hydrate experimental loop, which was equipped with two on-line particle analyzers: focused beam reflectance measurement (FBRM) and particle video microscope (PVM). First, it was observed from the PVM that different hydrate particles did not dissociate at the same time in the system, which indicated that the probability of hydrate particle dissociation depended on the particle’s shape and size. Meanwhile, data from FBRM presented a periodic oscillating trend of the particle/droplet numbers and chord length during the hydrate slurry dissociation, which further demonstrated these micro hydrate particles/droplets were in a dynamic coupling process of breakage and agglomeration under the action of flow shear during the hydrate slurry dissociation. Then, the influences of flow rate, pressure, water-cut, and additive dosage on the particles chord length distribution during the hydrate decomposition were summarized. Moreover, two kinds of particle chord length treatment methods (the average un-weighted and squared-weighted) were utilized to analyze these data onto hydrate particles’ chord length distribution. Finally, based on the above experimental data analysis, some important conclusions were obtained. The agglomeration of particles/droplets was easier under low flow rate during hydrate slurry dissociation, while high flow rate could restrain agglomeration effectively. The particle/droplet agglomerating trend and plug probability went up with the water-cut in the process of hydrate slurry decomposition. In addition, anti-agglomerates (AA) greatly prohibited those micro-particles/droplets from agglomeration during decomposition, resulting in relatively stable mean and square weighting chord length curves.
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Zhao, Xiaolong. "Plugging Experiments on Different Packing Schemes during Hydrate Exploitation by Depressurization." Processes 11, no. 7 (2023): 2075. http://dx.doi.org/10.3390/pr11072075.
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Marine natural gas hydrate (NGH) can mainly be found in argillaceous fine-silt reservoirs, and is characterized by weak consolidation and low permeability. Sand production is likely to occur during the NGH production process, and fine-silt particles can easily plug the sand-control media. In view of this, experiments were conducted to assess the influence of the formation sand on the sand retention media in gravel-packed layers under gas–water mixed flow, and the plugging process was analyzed. The results show that following conclusions. (1) The quartz-sand- and ceramic-particle-packed layers show the same plugging trend, and an identical plugging law. The process can be divided into three stages: the beginning, intensified, and balanced stages of plugging. (2) The liquid discharge is a key factor influencing the plugging of gravel-packed layers during NGH exploitation by depressurization. As the discharge increases, plugging occurs in all quartz-sand packing schemes, while the ceramic-particle packing scheme still yields a high gas-flow rate. Therefore, quartz sand is not recommended as the packing medium during NGH exploitation, and the grain-size range of ceramic particles should be further optimized. (3) Due to the high mud content of NGH reservoirs, a mud cake is likely to form on the surface of the packing media, which intensifies the bridge plugging of the packed layer. These experiment results provide an important reference for the formulation and selection of sand-control schemes.
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de Lima Silva, Paulo H., Mônica F. Naccache, Paulo R. de Souza Mendes, Adriana Teixeira, and Leandro S. Valim. "Rheology of THF hydrate slurries at high pressure." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 16. http://dx.doi.org/10.2516/ogst/2020007.
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One of the main issues in the area of drilling and production in deep and ultra-deep water in the oil industry is the formation of natural gas hydrates. Hydrates are crystalline structures resembling ice, which are usually formed in conditions of high pressure and low temperature. Once these structures are formed, they can grow and agglomerate, forming plugs that can eventually completely or partially block the production lines, causing huge financial losses. To predict flow behavior of these fluids inside the production lines, it is necessary to understand their mechanical behavior. This work analyzes the rheological behavior of hydrates slurries formed by a mixture of water and Tetrahydrofuran (THF) under high pressure and low temperature conditions, close to the ones found in deep water oil exploration. The THF hydrates form similar structures as the hydrates originally formed in the water-in-oil emulsions in the presence of natural gas, at extreme conditions of high pressure and low temperature. The experiments revealed some important issues that need to be taken into account in the rheological measurements. The results obtained show that the hydrate slurry viscosity increases with pressure. Oscillatory tests showed that elasticity and yield stress also increase with pressure.
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Aguguo, Johnbosco, and Matthew Clarke. "On the Necessity of Including the Dissociation Kinetics When Modelling Gas Hydrate Pipeline Plug Dissociation." Energies 17, no. 12 (2024): 3036. http://dx.doi.org/10.3390/en17123036.
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Gas hydrate plugs in petroleum fluid pipelines are a major flow assurance problem and thus, it is important for industry to have reliable mathematical models for estimating the time required to dissociate a hydrate pipeline plug. The existing mathematical models for modelling hydrate plug dissociation treat the problem as a pure heat transfer problem. However, an early study by Jamaluddin et al. speculated that the kinetics of gas hydrate dissociation could become the rate-limiting factor under certain operating conditions. In this short communication, a rigorous 2D model couples the equations of heat transfer and fluid flow with Clarke and Bishnoi’s model for the kinetics of hydrate dissociation. A distinguishing feature of the current work is the ability to predict the shape of the dissociating hydrate–gas interface. The model is used to correlate experimental data for both sI and sII hydrate plug dissociation, via single-sided depressurization and double-sided depressurization. As a preliminary examination on the necessity of including dissociation kinetics, this work is limited to conditions for which hydrate dissociation rate constants are available; kinetic rate constants for hydrate dissociation are available at temperatures above 273.15 K. Over the range of conditions that were investigated, it was found that including the intrinsic kinetics of hydrate dissociation led to only a very small improvement in the accuracy of the predictions of the cumulative gas volumes collected during dissociation. By contrast, a sensitivity study showed that the predictions of hydrate plug dissociation are very sensitive to the value of the porosity. Thus, it is concluded that unless values of the thermophysical properties of a hydrate plug are known, accounting for the dissociation kinetics need not be a priority.
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Aman, Zachary M., Luis E. Zerpa, Carolyn A. Koh, and Amadeu K. Sum. "Development of a Tool to Assess Hydrate-Plug-Formation Risk in Oil-Dominant Pipelines." SPE Journal 20, no. 04 (2015): 884–92. http://dx.doi.org/10.2118/174083-pa.
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Summary This work presents a new simple algorithm for the rapid screening of hydrate plug formation risk, using experimental models of gas hydrate plug formation in oil-dominant systems. The algorithm is based on hydrate formation from an emulsified water phase, where resultant hydrate particles may interact to form large aggregates that increase slurry viscosity and pressure drop. Predictions of pressure drop were compared with a hydrate-forming industrial flow loop, resulting in average absolute deviations between model and experiment of less than 5 psi for liquid-phase Reynolds numbers of less than 75,000 and water content below 70 vol% of all liquid.
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Zhang, Hao, Jianwei Du, Yanhong Wang, et al. "Investigation into THF hydrate slurry flow behaviour and inhibition by an anti-agglomerant." RSC Advances 8, no. 22 (2018): 11946–56. http://dx.doi.org/10.1039/c8ra00857d.
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Aman, Zachary, William G. T. Syddall, Paul Pickering, Michael Johns, and Eric F. May. "Attributes and behaviours of crude oils that naturally inhibit hydrate plug formation." APPEA Journal 55, no. 2 (2015): 416. http://dx.doi.org/10.1071/aj14051.
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The severe operating pressures and distances of deepwater tiebacks increase the risk of hydrate blockage during transient operations such as shut-in and restart. In many cases, complete hydrate avoidance through chemical management may be cost prohibitive, particularly late in a field’s life. For a unique subclass of crude oils, however that have not been observed to form a hydrate blockage during restart, active hydrate prevention may be unnecessary. In the past 20 years, limited information has been reported about the chemical or physical mechanisms that enable this particular non-plugging behaviour. This extended abstract demonstrates a systematic method of characterising this oil, including: physical property analysis that includes and builds upon ASTM standards; water-in-oil emulsion behaviour; and, the effect of oil on hydrate blockage formation mechanics. This last set of experiments uses a sapphire autoclave to allow direct observation of hydrate aggregation and deposition, combined with resistance-to-flow measurements. The effect of shut-ins and restarts on the oil’s plugging tendency is also studied in these experiments. The method was tested with several Australian crude oils, some of which exhibited non-plugging behaviour. In general, these particular crude oils do not form stable water-in-oil emulsions but do form stable non-agglomerating hydrate-in-oil dispersions. The oils suppress hydrate formation rates and their resistance-to-flow does not increase significantly when the amount of hydrate present would normally form a plug.
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Merkel, Florian Stephan, Carsten Schmuck, Heyko Jürgen Schultz, Timo Alexander Scholz, and Sven Wolinski. "Research on Gas Hydrate Plug Formation under Pipeline-Like Conditions." International Journal of Chemical Engineering 2015 (2015): 1–5. http://dx.doi.org/10.1155/2015/214638.
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Hydrates of natural gases like methane have become subject of great interest over the last few decades, mainly because of their potential as energy resource. The exploitation of these natural gases from gas hydrates is seen as a promising mean to solve future energetic problems. Furthermore, gas hydrates play an important role in gas transportation and gas storage: in pipelines, particularly in tubes and valves, gas hydrates are formed and obstruct the gas flow. This phenomenon is called “plugging” and causes high operational expenditure as well as precarious safety conditions. In this work, research on the formation of gas hydrates under pipeline-like conditions, with the aim to predict induction times as a mean to evaluate the plugging potential, is described.
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Shi, Bohui, Jiaqi Wang, Yifan Yu, Lin Ding, Yang Liu, and Haihao Wu. "Investigation on the Transition Criterion of Smooth Stratified Flow to Other Flow Patterns for Gas-Hydrate Slurry Flow." International Journal of Chemical Engineering 2017 (2017): 1–13. http://dx.doi.org/10.1155/2017/9846507.
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A stability criterion for gas-hydrate slurry stratified flow was developed. The model was based on one-dimensional gas-liquid two-fluid model and perturbation method, considering unstable factors including shear stress, gravity, and surface tension. In addition, mass transfer between gas and liquid phase caused by hydrate formation was taken into account by implementing an inward and outward natural gas hydrates growth shell model for water-in-oil emulsion. A series of gas-hydrate slurry flow experiments were carried out in a high-pressure (>10 MPa) horizontal flow loop. The transition criterion of smooth stratified flow to other flow patterns for gas-hydrate slurry flow was established and validated and combined with experimental data at different water cuts. Meanwhile, parameters of this stability criterion were defined. This stability criterion was proved to be efficient for predicting the transition from smooth to nonsmooth stratified flow for gas-hydrate slurry.
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Lv, X. F. F., J. Gong, W. Q. Q. Li, B. H. H. Shi, D. Yu, and H. H. H. Wu. "Experimental Study on Natural-Gas-Hydrate-Slurry Flow." SPE Journal 19, no. 02 (2013): 206–14. http://dx.doi.org/10.2118/158597-pa.
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Summary To better understand hydrate-slurry flow, a series of experiments was performed, including water, natural gas, and diesel oil, under 4-MPa system pressure and 1.25-m/s initial linear velocity. The experiments have been conducted in a high-pressure hydrate-flow loop newly constructed at China University of Petroleum (Beijing), and dedicated to flow-assurance studies. A focused-beam reflectance measurement (FBRM) probe is installed in this flow loop, which provides a qualitative chord length distribution (CLD) of the particles/droplets in the system. First, the influence of flow rate on the hydrate-slurry flow was discussed. Then, we studied other influencing factors—such as water cut and additive dosage—on the hydrate induction period and the CLD before/after hydrate formation. Third, a new correlation was fitted between the dimensionless rheological index n′ and water cut as well as additive dosage, according to these experimental data. Finally, a laminar-flow model for the prediction of the pressure drop for the quasisingle-phase hydrate slurry was established, and tested by comparison with the experimental results in this paper.
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Caputo, Francesco, F. Cascetta, Giuseppe Lamanna, G. Rotondo, and Alessandro Soprano. "The Role of Methane Hydrates in the Failure of a Gas Pipeline." Key Engineering Materials 577-578 (September 2013): 377–80. http://dx.doi.org/10.4028/www.scientific.net/kem.577-578.377.
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Gas hydrates are known to form plugs in pipelines. Gas hydrates are crystalline compounds that form when hydrocarbons such as methane come in contact with water under thermodynamical opportune conditions, as high pressure and low temperature. Hydrates, like any obstruction in a pipeline, reduce flow, increase back pressure in the system and increase the differential pressure across the obstruction. When the line section is obstructed by a plug, the differential pressure can put the hydrate in movement and quickly accelerate it up to a speed approaching that of sound; in this case, the moving mass can cause serious mechanical damages at downstream locations where the plug can also meet restrictions or obstacles such as valves, elbows or tees. In this paper a real case of a gas pipeline failure, due to the presence of a moving mass of methane hydrate, has been investigated by considering an analytical and numerical modeling of the motion of the hydrates, as well as of their impact against the pipes.
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Fu, Weiqi, Zhiyuan Wang, Litao Chen, and Baojiang Sun. "Experimental Investigation of Methane Hydrate Formation in the Carboxmethylcellulose (CMC) Aqueous Solution." SPE Journal 25, no. 03 (2020): 1042–56. http://dx.doi.org/10.2118/199367-pa.
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Summary In the development of deepwater crude oil, gas, and gas hydrates, hydrate formation during drilling operations becomes a crucial problem for flow assurance and wellbore pressure management. To study the characteristics of methane hydrate formation in the drilling fluid, the experiments of the methane hydrate formation in water with carboxmethylcellulose (CMC) additive are performed in a horizontal flow loop under flow velocity from 1.32 to 1.60 m/s and CMC concentration from 0.2 to 0.5 wt%. The flow pattern is observed as bubbly flow in experiments. The experiments indicate that the increase of CMC concentration impedes the hydrate formation while the increase of liquid velocity enhances formation rates. In the stirred reactor, the hydrate formation rate generally decreases as the subcooling condition decreases. However, in this work, with the subcooling condition continuously decreasing, hydrate formation rate follows a “U” shaped trend—initially decreasing, then leveling out and finally increasing. It is because the hydrate formation rate in this work is influenced by multiple factors, such as hydrate shell formation, fracturing, sloughing, and bubble breaking up, which has more complicated mass transfer procedure than that in the stirred reactor. A semiempirical model that is based on the mass transfer mechanism is developed for current experimental conditions, and can be used to predict the formation rates of gas hydrates in the non-Newtonian fluid by replacing corresponding correlations. The rheological experiments are performed to obtain the rheological model of the CMC aqueous solution for the proposed model. The overall hydrate formation coefficient in the proposed model is correlated with experimental data. The hydrate formation model is verified and the predicted quantity of gas hydrates has a discrepancy less than 10%.
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Chizhevskaya, E. L., A. D. Vydrenkov, A. N. Anton N. Shipovalov, Yu D. Zemenkov, and M. Yu Zemenkova. "INTELLIGENT EXPERT HYDRATE INHIBITOR FLOW CONTROL SYSTEMS IN FLOWLINES." Petroleum Engineering 22, no. 6 (2024): 128–42. https://doi.org/10.17122/ngdelo-2024-6-128-142.
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The article presents the development of an intelligent system for determining the optimal volume of hydrate formation inhibitors to be injected into field gas gathering systems. It describes the system's operating principles, methods of analyzing and forecasting hydrate formation, and the results of testing the developed model. The relevance of this work is driven by the fact that existing methodological approaches are insufficient for adequately assessing the risks of hydrate formation in gas gathering systems, which can lead to significant material and financial losses. To justify the most accurate method for calculating the hydrate equilibrium curve to predict the onset of crystalline structure formation in the gas flow, the study presents the results of modeling the equilibrium curve for a multicomponent gas mixture from one of the Cenomanian gas reservoirs. The analysis was conducted using widely applied methodologies available in software such as Pipesim and Aspen HYSYS, which are based on different equations of state.To enhance the accuracy of simulation modeling, the proposed risk analysis methodology includes a supplementary algorithm developed and integrated into the Python environment. This algorithm, based on basic mathematical balance principles, allows for the recombination of the component composition of the gas flow for each individual segment of the field pipeline. The algorithm takes into account the inlet composition based on the production rates of wells entering a specific network section, the component composition and mass of each element, and the presence of water in the flow. In combination, the proposed methodology for risk analysis and mitigation in hydrate formation processes not only enables the use of the resulting composition to accurately calculate the hydrate formation temperature by integrating an algorithm similar in function to the hydrate equilibrium curve module from Pipesim, but also determines the optimal volume of inhibitor to mitigate the risk of hydrate plugs in pipeline sections, significantly improving the model's calculation accuracy by considering the multiphase flow composition for each specific gathering system segment. The scientific novelty of this work lies in the development of a new comprehensive approach to hydrate formation risk analysis for each segment of the well product gathering system. This approach is partially based on existing methodologies and incorporates machine learning technologies to promptly detect hydrate formation risks and determine the necessary inhibitor volume to mitigate these risks. The obtained results of calculations of the risk of hydrate formation and inhibitor for cycles allow us to conclude that the reliability of the operation of field gas pipelines due to the premature identification of potentially dangerous places in the operation of the system and the timely supply of a hydrate formation inhibitor to compensate for them, which together reduces material losses from excessive consumption of the inhibitor and from stopping the pipeline due to the formation of a hydrate plug, using the developed intelligent methodology.
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Qu, Anqi, Nur Aminatulmimi Ismail, Jose G. Delgado-Linares, Ahmad A. A. Majid, Luis E. Zerpa, and Carolyn A. Koh. "Gas Hydrate Plugging Mechanisms during Transient Shut–In/Restart Operation in Fully Dispersed Systems." Fuels 5, no. 3 (2024): 297–316. http://dx.doi.org/10.3390/fuels5030017.
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Gas hydrate formation poses a significant challenge in offshore oil and gas production, particularly during cold restarts after extended shut–ins, which can lead to pipeline blockages. Although steady–state models have traditionally been used to predict hydrate formation under continuous production conditions, these models are often inadequate for transient operations due to issues like near–zero fluid flow shear affecting the viscosity calculations of hydrate slurries. This study introduces novel conceptual models for dispersed water–in–crude oil systems specifically designed for cold restart scenarios. The models are supported by direct observations and various experimental approaches, including bottle tests, rheometer measurements, micromechanical force apparatus, and rocking cell studies, which elucidate the underlying mechanisms of hydrate formation. Additionally, this work introduces a modeling approach to represent conceptual pictures, incorporating particle settling and yield stress, to determine whether the system will plug or not upon restart. Validation is provided through transient large–scale flowloop tests, confirming the plugging mechanisms outlined. This comprehensive approach offers insights into conditions that may safely prevent or potentially lead to blockages in the fully dispersed system during field restarts, thereby enhancing the understanding and management of gas hydrate risks in offshore oil and gas operations.
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Carpenter, Chris. "Subsea Production System Allows Safe and Successful Gas Hydrate Plug Remediation." Journal of Petroleum Technology 76, no. 08 (2024): 67–70. http://dx.doi.org/10.2118/0824-0067-jpt.
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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215580, “Safe and Successful Gas Hydrate Plug Remediation in Vega Asset—Norwegian Gas Condensate Subsea Production System,” by Seetharaman Navaneetha Kannan, SPE, Wintershall Dea and Colorado School of Mines, and Magne Torsvik and Luis Ugueto, Wintershall Dea, et al. The paper has not been peer reviewed. _ Gas hydrate plugs in subsea flowlines create complex challenges in plug-remediation operations and can result in significant operational expenditures. This work chronicles a series of operational activities in detection of a hydrate blockage, modeling assessment, and safe and successful plug-remediation efforts in a 12-in. inner diameter (ID) flowline in Vega, a Norwegian Sea gas-condensate subsea asset. The operational experiences from hydrate-plug detection and melting, as well as modeling activities, provide valuable input for future hydrate-remediation operations. Field Description Field layout consists of three daisy-chained subsea templates [South (S), Central (C), and North (N)]. At production startup in 2010, all templates housed two wells each. In 2021 and 2022, an infill well campaign took place, with one new well added to both the South and Central templates. The wells are named after the templates to which they are added [i.e., South includes Wells S1, S2, and S3 (Fig. 1)]. One multiphase flowline connects the three templates with, initially, 12-in. ID line from South to Central and Central to North and a 14-in. ID export line to the host. The backbone of the flow-assurance philosophy is continuous injection of monoethylene glycol (MEG) to the templates, with reclamation on the host platform. Continuous MEG injection is used to ensure operation outside of the hydrate-formation window, even under shut-in conditions. Therefore, a 90:10 MEG/water mix is injected into each template’s manifold. The injection volumes are aimed to ensure an approximate MEG concentration of 50% in the produced aqueous fluids to the topsides. Production Outside Predefined Boundaries Vega was initially designed to accommodate limited volumes of formation water only. Subsequently, formation-water-producing wells would be choked back gradually, worked over, or shut in. The design included only minor contingencies of a few cubic meters of saline water in the system. The initial breakthrough of formation water in the S wells occurred well within the boundaries of the system. Because of the minor influx observed, the original MEG strategy was maintained. However, as water production increased, the well had to be choked down to remain within the limit of the MEG reclamation unit. At one point, the primary source of water from the well shifted from condensed water to formation water, but the actual MEG injection rates were not adjusted to address this new situation. Because of the subsea flowmeter accuracy on the still very low formation-water rates, this change was not picked up in time. This created a completely new operational scenario for which the original design had not accounted without considering the increased risk of hydrates in the field.
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Longinos, Sotirios Nik, and Mahmut Parlaktuna. "Examination of behavior of lysine on methane (95%)–propane (5%) hydrate formation by the use of different impellers." Journal of Petroleum Exploration and Production Technology 11, no. 4 (2021): 1823–31. http://dx.doi.org/10.1007/s13202-021-01146-w.
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AbstractHydrate formation characteristics and hydrodynamic behavior have been investigated for mixture of methane–propane hydrate formation with pure water and with the amino acid of lysine 1.5 wt% at 24.5 bars and 2 °C. There were total 12 experiments with full and no baffle estimating the induction time, rate of hydrate formation, hydrate productivity and power consumption. The outcomes showed that radial flow experiments with radial flow have better behavior compared to mixed flow ones due to better interaction between gas and liquid. Furthermore, lysine experiments formed hydrates more quickly compared to pure water experiments showing that lysine functions as promoter and not as inhibitor. RT experiments consume more energy compared to PBT ones, while induction time is always smaller in RT experiments compared to PBT ones.
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Tang, Yang, Peng Zhao, Xiaoyu Fang, Guorong Wang, Lin Zhong, and Xushen Li. "Numerical Simulation on Erosion Wear Law of Pressure-Controlled Injection Tool in Solid Fluidization Exploitation of the Deep-Water Natural Gas Hydrate." Energies 15, no. 15 (2022): 5314. http://dx.doi.org/10.3390/en15155314.
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The pressure-controlled injection tool (PCIT) is the key equipment in the process of high-pressure water jet fragmentation in the solid fluidization exploitation of deep-sea natural gas hydrate (NGH). The internal flow field erosion wear numerical simulation model of PCIT is established through computational fluid dynamics software to study the influence law and main factors of the drilling fluid erosion wear of PCIT. The influence laws of different drilling fluid physical parameters and different structural parameters on PCIT erosion wear were analyzed based on the Euler–Lagrangian algorithm bidirectional coupled discrete phase model (DPM) and the solid–liquid two-phase flow model. The results show that the easily eroded areas are the cone of the sliding core, the plug transition section, the plug surface, and the axial flow passage. The sliding core inlet angle and solid particle size are the main factors affecting the PCIT erosion rate. When the inlet angle of the sliding core is 30°, the diameter of solid-phase particles in drilling fluid is less than 0.3 mm, and the erosion degree of the PCIT could be effectively reduced. The research results can provide guidance for the design and application of the PCIT and advance the early realization of the commercial exploitation of hydrate.
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Ma, Yun, Jinzhao Zhu, Qingguo Meng, et al. "Analysis of Influencing Factors in Pilot Experiment for Synthesis of Natural Gas Hydrate by Spray Method." Processes 10, no. 12 (2022): 2740. http://dx.doi.org/10.3390/pr10122740.
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In recent years, the technology of storing and transporting natural gas in the form of hydrate has received a lot of attention. At present, the research on the synthesis of natural gas hydrate for the purpose of storage and transportation is still in the laboratory stage, and its synthesis process is in the design and conception stage. The influencing factors of natural gas hydrate synthesis under pilot-scale conditions are more complex. Moreover, pilot experiments are oriented to actual production, and its economic feasibility and operational convenience have higher requirements. This paper aimed to study the influencing factors of gas hydrate synthesis by spray method under pilot-scale conditions. Under specific conditions of surfactant and pressure, we carried out research on the effects of reaction temperature, different forms of atomizers, high-pressure pump flow, experimental water, and other factors. Experiments show that the optimal synthesis conditions were a temperature of −5 °C, a pressure of 5 MPa, a conical nozzle, a generated gas hydrate as the hydrate of type I structure, and a gas storage capacity of 1:123 (gas–water ratio).
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Longinos, Sotirios Nik, Dionisia Dimitra Longinou, Nurbala Myrzakhmetova, et al. "Kinetic Analysis of Methane Hydrate Formation with Butterfly Turbine Impellers." Molecules 27, no. 14 (2022): 4388. http://dx.doi.org/10.3390/molecules27144388.
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Heat generation during gas hydrate formation is an important problem because it reduces the amount of water and gas that become gas hydrates. In this research work, we present a new design of an impeller to be used for hydrate formation and to overcome this concern by following the hydrodynamic literature. CH4 hydrate formation experiments were performed in a 5.7 L continuously stirred tank reactor using a butterfly turbine (BT) impeller with no baffle (NB), full baffle (FB), half baffle (HB), and surface baffle (SB) under mixed flow conditions. Four experiments were conducted separately using single and dual impellers. In addition to the estimated induction time, the rate of hydrate formation, hydrate productivity and hydrate formation rate, constant for a maximum of 3 h, were calculated. The induction time was less for both single and dual-impeller experiments that used full baffle for less than 3 min and more than 1 h for all other experiments. In an experiment with a single impeller, a surface baffle yielded higher hydrate growth with a value of 42 × 10−8 mol/s, while in an experiment with dual impellers, a half baffle generated higher hydrate growth with a value of 28.8 × 10−8 mol/s. Both single and dual impellers achieved the highest values for the hydrate formation rates that were constant in the full-baffle experiments.
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Jeong, Kwanghee, Bruce W. E. Norris, Eric F. May, and Zachary M. Aman. "Hydrate Formation from Joule Thomson Expansion Using a Single Pass Flowloop." Energies 16, no. 22 (2023): 7594. http://dx.doi.org/10.3390/en16227594.
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Hydrate risk management is critically important for an energy industry that continues to see increasing demand. Hydrate formation in production lines is a potential threat under low temperature and high-pressure conditions where water and light gas molecules are present. Here, we introduce a 1-inch OD single-pass flow loop and demonstrate the Joule-Thomson (JT) expansion of a methane-ethane mixture. Initially, dry gas flowed through the apparatus at a variable pressure-differential. Larger pressure differentials resulted in more cooling, as predicted by standard thermodynamic models. A systematic deviation noted at higher pressure differentials was partially rectified through corrections incorporating heat transfer, thermal mass and kinetic energy effects. A wet gas system was then investigated with varying degrees of water injection. At the lowest rate, hydrate plugging occurred close to the expansion point and faster than for higher injection rates. This immediate and severe hydrate plugging has important implications for the design of safety relief systems in particular. Furthermore, this rate of plugging could not be predicted by existing software tools, suggesting that the atomization of liquids over an expansion valve is a critical missing component that must be incorporated for accurate predictions of hydrate plug formation severity.
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Ivanov, Gavril I., and Igor I. Rozhin. "Mass flow rate determination under reservoir conditions changing in the problem of gas extraction with hydrate plug formation." E3S Web of Conferences 592 (2024): 05017. http://dx.doi.org/10.1051/e3sconf/202459205017.
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The influence of changes of pressure and temperature of the reservoir bed on the process of formation and deposition of natural gas hydrates on the wall of a producing well is investigated in the computational experiment. The problem is summarized to the solution of differential equations describing the non-isothermal flow of real gas in a porous medium and in a well, considering the formation and deposition of gas hydrates, heat propagation in rocks with appropriate conjugation conditions. The gas withdrawal mode with constant wellhead pressure is studied. The algorithm of numerical solution of the inverse problem of determining the dynamics of gas mass flow rate is based on the method of half division. The comparison of the calculation results for cases when the pressure at the well bottom is: 1) changing with time in the process of gas withdrawal; 2) remaining constant. It is indicated that consideration of changes in reservoir conditions leads to a significant increase in the time of complete plugging of the well by gas hydrates and to reduction of accumulated gas production.
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Zhang, Jin, An Chen, and Menglan Duan. "Study on microscopic growth mechanism of emulsion system hydrate." Underwater Technology 37, no. 3 (2020): 71–77. http://dx.doi.org/10.3723/ut.37.071.
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In order to master the microscopic growth mechanism of natural gas hydrate, a series of experiments were carried out using a high-pressure hydrate flow loop. The microscopic physical information of the growth of hydrates in the emulsion system is captured by advanced microscopic equipment and the phenomena of the experiments show that: 1) not all water droplets instantaneously generate a hydrate shell, but only a few of the water droplets gradually generate a hydrate shell when reaching the conditions of the hydrate formation; and 2) the coalescence and shear do occur in the hydrate formation process, and the distribution of hydrate particle size has changed.
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Jasamai, Mazuin, Mazlin Idress, Mohd Zahdan Arshad, and Mohd Faisal Taha. "MITIGATION OF METHANE HYDRATE BLOCKAGE IN SUBSEA PIPELINES USING IONIC LIQUID AS HYDRATE INHIBITOR." Platform : A Journal of Engineering 3, no. 1 (2019): 13. http://dx.doi.org/10.61762/pajevol3iss1art4865.
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Gas hydrates one of a major problem in the oil and gas industry. Formation of gas hydrates causes flow assurance issues as it can plug the pipeline. The use of chemical inhibitors; kinetic hydrate inhibitors and thermodynamic hydrate inhibitors is one of the most feasible ways to solve this problem. However, the problem with thermodynamic inhibitors is that it required in a large dosage and cause environmental issues. Thus, this study emphasises on the usage of ionic liquid as an effective kinetic hydrate inhibitor. The ionic liquid is a green chemical that can be fine-tuned explicitly as a hydrate inhibitor. The aim is to study the effectiveness of 1-Ethyl-3-Methylimidazolium Tetrafluoroborate (EMIMBF4), an ionic liquid as a kinetic hydrate inhibitor at various pressure and concentration. Micro Differential Scanning Calorimeter was used to measure the induction time of methane hydrate. The performance of ionic liquid was tested in different concentration and compared to the commercial kinetic hydrate inhibitor, Polyvinylpyrrolidone (PVP). From the experimental work, it was found that EMIMBF4 shows a dynamic inhibition effect as it can delay the induction time of hydrate. EMIMBF4 shows a higher induction time at a low concentration of 0.1wt%. At the pressure of 60 bar, the effectiveness of EMIMBF4 is comparable with PVP. However, PVP shows superior kinetic inhibition effect at the pressure of 40 bar. This study indicates that an effective, green hydrate inhibitor can be developed to counter hydrate formation problems in offshore subsea pipelines in a more cost-effective and environmentally friendly
 Keywords: Methane Hydrate; Hydrate Inhibitor; Ionic Liquid; EMIMBF4; Micro DSC; pipeline blockage
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Pham, Trung-Kien, Ana Cameirao, Aline Melchuna, Jean-Michel Herri, and Philippe Glénat. "Relative Pressure Drop Model for Hydrate Formation and Transportability in Flowlines in High Water Cut Systems." Energies 13, no. 3 (2020): 686. http://dx.doi.org/10.3390/en13030686.
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Today, oil and gas fields gradually become mature with a high amount of water being produced (water cut (WC)), favoring conditions for gas hydrate formation up to the blockage of pipelines. The pressure drop is an important parameter which is closely related to the multiphase flow characteristics, risk of plugging and security of flowlines. This study developed a model based on flowloop experiments to predict the relative pressure drop in pipelines once hydrate is formed in high water cutsystems in the absence and presence of AA-LDHI and/or salt. In this model, the relative pressure drop during flow is a function of hydrate volume and hydrate agglomerate structure, represented by the volume fraction factor (Kv). This parameter is adjusted for each experiment between 1.00 and 2.74. The structure of the hydrate agglomerates can be predicted from the measured relative pressure drop as well as their impact on the flow, especially in case of a homogeneous suspension of hydrates in the flow.
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Musakaev, N. G., and M. P. Galchanskii. "Calculation of the required methanol consumption during the flow of wet hydrocarbon gas in a horizontal pipeline." Oil and Gas Studies, no. 2 (May 20, 2024): 79–92. http://dx.doi.org/10.31660/0445-0108-2024-2-79-92.
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One of the main problems that have to be solved during the development of hydrocarbon deposits is the formation of gas hydrates in pipelines. In this regard, the article presents a preventive method to struggle against the formation of gas hydrate deposits on the pipes inner walls associated with the supply of a hydrate formation inhibitor to the gas stream. The research was conducted on the basis of a mathematical model of the wet hydrocarbon gas flow in a horizontal pipeline. The research object is to determine the minimum required consumption of methanol, in which there is no formation of gas hydrate deposits on the channel inner walls. The practical significance of this study is that it is aimed at reducing the risks associated with the formation of gas hydrates in pipelines. The numerical implementation of a mathematical model of natural gas flow in a horizontal channel is based on a sequential solution of a system of four differential equations by the Runge-Kutta method of 4 orders of accuracy, followed by a search for sequential approximations of the minimum inhibitor flow rate, in which the "gas + water ↔ gas hydrate phase" transition process does not occur on the inner surface of the channel. The article presents a calculation of the proportion of a hydrate formation inhibitor in the liquid phase by solving a cubic equation using the Cardano method. Based on the computational experiments results, graphs were constructed and interpreted of the dependencies of the minimum inhibitor consumption on the soil temperature, inlet gas pressure, total water concentration in the gas flow, initial gas temperature and total gas flow rate.
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Foo, Khor Siak, Omar Nashed, Bhajan Lal, Cornelius Borecho Bavoh, Azmi Mohd Shariff, and Raj Deo Tewari. "The Effect of Nonionic Surfactants on the Kinetics of Methane Hydrate Formation in Multiphase System." Colloids and Interfaces 6, no. 3 (2022): 48. http://dx.doi.org/10.3390/colloids6030048.
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Gas hydrate inhibitors have proven to be the most feasible approach to controlling hydrate formation in flow assurance operational facilities. Due to the unsatisfactory performance of the traditional inhibitors, novel effective inhibitors are needed to replace the existing ones for safe operations within constrained budgets. This work presents experimental and modeling studies on the effects of nonionic surfactants as kinetic hydrate inhibitors. The kinetic methane hydrate inhibition impact of Tween-20, Tween-40, Tween-80, Span-20, Span-40, and Span-80 solutions was tested in a 1:1 mixture of a water and oil multiphase system at a concentration of 1.0% (v/v) and 2.0% (v/v), using a high-pressure autoclave cell at 8.70 MPa and 274.15 K. The results showed that Tween-80 effectively delays the hydrate nucleation time at 2.5% (v/v) by 868.1% compared to the blank sample. Tween-80 is more effective than PVP (a commercial kinetic hydrate inhibitor) in delaying the hydrate nucleation time. The adopted models could predict the methane hydrate induction time and rate of hydrate formation in an acceptable range with an APE of less than 6%. The findings in this study are useful for safely transporting hydrocarbons in multiphase oil systems with fewer hydrate plug threats.
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Yoon, Hyun Chul, Jihoon Kim, Evan Schankee Um, and Joo Yong Lee. "Integration of Electromagnetic Geophysics Forward Simulation in Coupled Flow and Geomechanics for Monitoring a Gas Hydrate Deposit Located in the Ulleung Basin, East Sea, Korea." Energies 15, no. 10 (2022): 3823. http://dx.doi.org/10.3390/en15103823.
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We investigate the feasibility of electromagnetic (EM) geophysics methods to detect the dissociation of gas hydrate specifically from a gas hydrate deposit located in the Ulleung Basin, East Sea, Korea via an integrated flow-geomechanics-EM geophysics simulation. To this end, coupled flow and geomechanics simulation is first performed with the multiple porosity model employed, where a mixed formulation with the finite volume (FV) and finite element (FE) methods are taken for the flow and geomechanics, respectively. From the saturation and porosity fields obtained from the coupled flow and geomechanics, the electrical conductivity model is established for the EM simulation. Solving the partial differential equation of electrical diffusion which is linearized using the 3D finite element method (FEM), the EM fields are then computed. For numerical experiments, particularly two approaches in the configuration for the EM methods are compared in this contribution: the surface-to-surface and the surface-to-borehole methods. When the surface-to-surface EM method is employed, the EM is found to be less sensitive, implying low detectability. Especially for the short term of production, the low detectability is attributed to the similarity of electrical resistivity between the dissociated gas (CH4) and hydrate as well as the specific dissociation pattern within the intercalated composites of the field. On the other hand, when the surface-to-borehole EM method is employed, its sensitivity to capture the produced gas flow is improved, confirming its detectability in monitoring gas flow. Hence, the EM geophysics simulation integrated with coupled flow and geomechanics can be a potential tool for monitoring gas hydrate deposits.
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Thieringer, Julia R. D., Nicolas Hafen, Jörg Meyer, Mathias J. Krause, and Achim Dittler. "Investigation of the Rearrangement of Reactive–Inert Particulate Structures in a Single Channel of a Wall-Flow Filter." Separations 9, no. 8 (2022): 195. http://dx.doi.org/10.3390/separations9080195.
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Wall-flow filters are a standard component in exhaust gas aftertreatment and have become indispensable in vehicles. Ash and soot particles generated during engine combustion are deposited in diesel or gasoline particulate filters. During regeneration, the soot particles are oxidized. The remaining ash particles can form different deposition patterns: a homogenous layer or plug-end filling. It has not yet been clarified whether the plug-end filling is first formed by rearrangements of agglomerates before and during the regeneration of the reactive particles. In this study, experiments are carried out with a single channel of a wall-flow filter. For the investigations, a layer of inert and reactive particles is formed. The rearrangement of agglomerates is achieved by flowing through the model filter channel and observed with a high-speed camera. The particulate structures detach at the channel inlet, are transported along the channel and deposited at the plug. The velocity of the detached agglomerates depends on their size, shape, track and the gas velocity in the channel. If the agglomerate is near the walls of the model filter channel, the gas velocity deviates from the gas velocity in the core flow. The higher the gas velocity, the higher the agglomerate velocity achieved and the larger the detached agglomerates.
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Khan, Rehan, Hamdan H. Ya, Imran Shah, et al. "Influence of Elbow Angle on Erosion-Corrosion of 1018 Steel for Gas–Liquid–Solid Three Phase Flow." Materials 15, no. 10 (2022): 3721. http://dx.doi.org/10.3390/ma15103721.
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Erosive wear due to the fact of sand severely affects hydrocarbon production industries and, consequently, various sectors of the mineral processing industry. In this study, the effect of the elbow geometrical configuration on the erosive wear of carbon steel for silt–water–air flow conditions were investigated using material loss analysis, surface roughness analysis, and microscopic imaging technique. Experiments were performed under the plug flow conditions in a closed flow loop at standard atmospheric pressure. Water and air plug flow and the disperse phase was silt (silica sand) with a 2.5 wt % concentration, and a silt grain size of 70 µm was used for performing the tests. The experimental analysis showed that silt impact increases material disintegration up to 1.8 times with a change in the elbow configuration from 60° to 90° in plug flow conditions. The primary erosive wear mechanisms of the internal elbow surface were sliding, cutting, and pit propagation. The maximum silt particle impaction was located at the outer curvature in the 50° position in 60° elbows and the 80° position in 90° elbows in plug flow. The erosion rate decreased from 10.23 to 5.67 mm/year with a change in the elbow angle from 90° to 60°. Moreover, the microhardness on the Vickers scale increased from 168 to 199 in the 90° elbow and from 168 to 184 in the 60° elbow.
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Geranutti, Bianca L. S., Mathias Pohl, Daniel Rathmaier, Somayeh Karimi, Manika Prasad, and Luis E. Zerpa. "Multiphysics Measurements for Detection of Gas Hydrate Formation in Undersaturated Oil Coreflooding Experiments with Seawater Injection." Energies 17, no. 13 (2024): 3280. http://dx.doi.org/10.3390/en17133280.
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A solid phase of natural gas hydrates can form from dissolved gas in oil during cold water injection into shallow undersaturated oil reservoirs. This creates significant risks to oil production due to potential permeability reduction and flow assurance issues. Understanding the conditions under which gas hydrates form and their impact on reservoir properties is important for optimizing oil recovery processes and ensuring the safe and efficient operation of oil reservoirs subject to waterflooding. In this work, we present two fluid displacement experiments under temperature control using Bentheimer sandstone core samples. A large diameter core sample of 3 inches in diameter and 10 inches in length was instrumented with multiphysics sensors (i.e., ultrasonic, electrical conductivity, strain, and temperature) to detect the onset of hydrate formation during cooling/injection steps. A small diameter core sample of 1.5 inches in diameter and 12 inches in length was used in a coreflooding apparatus with high-precision pressure transducers to determine the effect of hydrate formation on rock permeability. The fluid phase transition to solid hydrate phase was detected during the displacement of live-oil with injected water. The experimental procedure consisted of cooling and injection steps. Gas hydrate formation was detected from ultrasonic measurements at 7 °C, while strain measurements registered changes at 4 °C after gas hydrate concentration increased further. Ultrasonic velocities indicated the pore-filling morphology of gas hydrates, resulting in a high hydrate saturation of theoretically up to 38% and a substantial risk of intrinsic permeability reduction in the reservoir rock due to pore blockage by hydrates.
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Sell, Kathleen, Beatriz Quintal, Michael Kersten, and Erik H. Saenger. "Squirt flow due to interfacial water films in hydrate bearing sediments." Solid Earth 9, no. 3 (2018): 699–711. http://dx.doi.org/10.5194/se-9-699-2018.
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Abstract. Sediments containing gas hydrate dispersed in the pore space are known to show a characteristic seismic anomaly which is a high attenuation along with increasing seismic velocities. Currently, this observation cannot be fully explained albeit squirt-flow type mechanisms on the microscale have been speculated to be the cause. Recent major findings from in situ experiments, using the gas in excess and water in excess formation method, and coupled with high-resolution synchrotron-based X-ray micro-tomography, have revealed the systematic presence of thin water films between the quartz grains and the encrusting hydrate. The data obtained from these experiments underwent an image processing procedure to quantify the thicknesses and geometries of the aforementioned interfacial water films. Overall, the water films vary from sub-micrometer to a few micrometers in thickness. In addition, some of the water films interconnect through water bridges. This geometrical analysis is used to propose a new conceptual squirt flow model for hydrate bearing sediments. A series of numerical simulations is performed considering variations of the proposed model to study seismic attenuation caused by such thin water films. Our results support previous speculation that squirt flow can explain high attenuation at seismic frequencies in hydrate bearing sediments, but based on a conceptual squirt flow model which is geometrically different than those previously considered.
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Liu, Xinfu, Chunhua Liu, and Jianjun Wu. "Dynamic Characteristics of Offshore Natural Gas Hydrate Dissociation by Depressurization in Marine Sediments." Geofluids 2019 (November 13, 2019): 1–11. http://dx.doi.org/10.1155/2019/6074892.
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Dynamic characteristics of offshore natural gas hydrate (NGH) dissociation will provide the theoretical basis to analyze technical issues of oceanic hydrate exploitation. A mathematical model is developed to simulate offshore NGH dissociation by depressurization in marine sediments. Different phase combination statuses are involved in the process of NGH dissociation by taking ice melting and water freezing into account. The proposed methodology can analyze the processes of hydrate and water phase transitions, decomposition kinetics and thermodynamics, viscosity and permeability, ice-water phase equilibrium, and natural gas and water production. A set of an experimental system is built and consists of one 3-D visual reactor vessel, one isothermal seawater vessel, one natural gas and water separator, and one data acquisition unit. The experiments on offshore NGH dissociation by depressurization in 3-D marine sediments are carried out, and this methodology is validated against the full-scale experimental data measured. The results show that during the prophase, natural gas flow is preceded by water flow into the production wellbore and natural gas occupies more continuous flow channels than water under a large pressure gradient. Then, the natural gas flow rate begins to decline accompanied by an increase of water production. During the second phase, natural gas flow rate decreases slowly because of the decreased temperature of hydrate-bearing formation and low pressure gradient. The lower the intrinsic permeability in marine sediments, the later the water flow rate reaches the peak production. And the space interval of the production wellbore should be enlarged by an increase of the intrinsic permeability. The stable period of natural gas production enhances, and the water flow rate reduces with the increase of bottom-hole pressure in production wellbores. The main reason is the slow offshore NGH dissociation under the low producing pressure and the restriction of heat conductivity under the low temperature.
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Hanus, Robert, Marcin Zych, Barbara Wilk, Marek Jaszczur, and Dariusz Świsulski. "Signals features extraction in radioisotope liquid-gas flow measurements using wavelet analysis." EPJ Web of Conferences 213 (2019): 02023. http://dx.doi.org/10.1051/epjconf/201921302023.
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Knowledge of the structure of a flow is significant for the proper conduct of a number of industrial processes. In this case, a description of a two-phase flow regimes is possible by use of the time-series analysis in time, frequency and state-space domain. In this article the Discrete Wavelet Transform (DWT) is applied for analysis of signals obtained for water-air flow using gamma ray absorption. The presented method was illustrated by use data collected in experiments carried out on the laboratory hydraulic installation with a horizontal pipe, equipped with two Am-241 radioactive sources and scintillation probes with NaI(Tl) crystals. Signals obtained from detectors for slug, plug, bubble, and transitional plug – bubble flows were considered in this work. The recorded raw signals were analyzed and wavelet energy was extracted using multiresolution analysis. It was found that energies of wavelet approximation at 1-5 levels are useful to recognize the structure of the flow.
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Saikia, Tinku, and Vikas Mahto. "Temperature Augmented Visual Method for Initial Screening of Hydrate Inhibitors." Oil & Gas Sciences and Technology – Revue d’IFP Energies nouvelles 73 (2018): 1. http://dx.doi.org/10.2516/ogst/2017040.
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The formation of gas hydrates in oil & gas pipelines and drilling fluid flow lines is a major issue in the petroleum industry. Gas hydrate inhibitors are normally used to inhibit the formation of gas hydrates in the pipelines/flowlines. Initial screening of hydrate inhibitors and AntiAgglomerants (AA) requires a safe and economical experimental setup/method. Conventional visual method was used for initial screening of hydrate inhibitors in many researches. Some researchers also suggested modified visual methods, but all of them lacks accurate measurement of induction time and found to be inappropriate for experimental solutions like drilling mud, etc. In this work, a temperature augmented visual method was presented which can be used in academic research laboratories for study and initial screening of hydrate inhibitors. This method is capable of parallel screening of inhibitors and determines hydrate induction time precisely. Experiments were conducted to determine the hydrate induction time of different inhibitors using augmented method and compared with conventional visual method. The developed method found to be more precise in determining the induction time of hydrates in all types of experimental solutions.
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Majid, Ahmad A., Wonhee Lee, Vishal Srivastava, et al. "Experimental Investigation of Gas-Hydrate Formation and Particle Transportability in Fully and Partially Dispersed Multiphase-Flow Systems Using a High-Pressure Flow Loop." SPE Journal 23, no. 03 (2017): 937–51. http://dx.doi.org/10.2118/187952-pa.
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Summary As the oil-and-gas industries strive for better gas-hydrate-management methods, there is the need for improved understanding of hydrate formation and plugging tendencies in multiphase flow. In this work, an industrial-scale high-pressure flow loop was used to investigate gas-hydrate formation and hydrate-slurry properties at different flow conditions: fully dispersed and partially dispersed systems. It has been shown that hydrate formation in a partially dispersed system can be more problematic compared with that in a fully dispersed system. For hydrate formation in a partially dispersed system, it was observed that there was a significant increase in pressure drop with increasing hydrate-volume fraction. This is in contrast to a fully dispersed system in which there is gradual increase in the pressure drop of the system. Further, for a partially dispersed system, studies have suggested that there may be hydrate-film growth at the pipe wall. This film growth reduces the pipeline diameter, creating a hydrate bed that then leads to flowline plugging. Because there are different hydrate-formation and -plugging mechanisms for fully and partially dispersed systems, it is necessary to investigate and compare systematically the mechanism for both systems. In this work, all experiments were specifically designed to mimic the flow systems that can be found in actual oil-and-gas flowlines (full and partial dispersion) and to understand the transportability of hydrate particles in both systems. Two variables were investigated in this work: amount of water [water cut (WC)] and pump speed (fluid-mixture velocity). Three different WCs were investigated: 30, 50, and 90 vol%. Similarly, three different pump speeds were investigated: 0.9, 1.9, and 3.0 m/s. The results from these measurements were analyzed in terms of relative pressure drop (ΔPrel) and hydrate-volume fraction (ϕhyd). It was observed that, for all WCs investigated in this work, the ΔPrel decreases with increasing pump speed, at a similar hydrate-volume fraction. Analysis conducted with the partially-visual-microscope (PVM) data collected showed that, at constant WC, the hydrate-particle size at the end of the tests decreases as the mixture velocity increases. This indicates that the hydrate-agglomeration phenomenon is more severe at low mixture velocity. Calculations of the average hydrate-growth rate for all tests conducted show that the growth rate is much lower at a mixture velocity of 3.0 m/s. This is attributed to the heat generated by the pump. At a high mixing speed of 3.0 m/s, the pump generated a significant amount of heat that then increased the temperature of the fluid. Consequently, the hydrate-growth rate decreases. It should be stated that this warming effect should not occur in the field. Flow-loop plugging occurred for tests with 50-vol% WC and pump speeds lower than 1.9 m/s, and for tests with 90-vol% WC at a pump speed of 0.9 m/s. In addition, in all 90-vol%-WC tests, emulsion breaking, where the two phases (oil and water) separated, was observed after hydrate formation. From the results and observations obtained from this investigation, proposed mechanisms are given for hydrate plugging at the different flow conditions. These new findings are important to provide qualitative and quantitative understanding of the key phenomena leading to hydrate plugging in oil/gas flowlines.
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Carpenter, Chris. "New Monoethylene-Glycol Sensor Validated by Flow Loop Under Hydrate-Forming Conditions." Journal of Petroleum Technology 73, no. 08 (2021): 49–50. http://dx.doi.org/10.2118/0821-0049-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202375, “Validation of a Novel MEG Sensor Employing a Pilot-Scale Subsea Jumper,” by Asheesh Kumar, The University of Western Australia; Mauricio Di Lorenzo, SPE, CSIRO Energy; and Bruce W.E. Norris, SPE, The University of Western Australia, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Online pipeline-management systems provide real-time and look-ahead functionality for production networks. They are limited, however, by a dearth of data with which to inform their predictions. This represents a barrier to a true, high-fidelity digital twin. Greater integration with new sensor technologies is needed to bound model predictions and improve their reliability. In this work, the authors present a novel monoethylene-glycol (MEG) sensing system and validate it in a specially constructed flow loop. Introduction Subsea jumpers experience a high probability of hydrate blockages. The most common practice used to avoid hydrate formation in subsea wellhead jumpers essentially is based on the injection of thermodynamic hydrate inhibitors such as MEG and methanol at high flow rates to flush out and inhibit the water pooled in the low spots of the jumper spools. Such hydrate management operations in deep water require adequate planning to minimize unproductive time and may not be feasible in unplanned well shutdowns. To improve the models implemented in current sensing technologies and explore their potential for new functionalities to detect hydrate formation, measurements under realistic field conditions in a controlled environment are vital. In this work, a flow loop that replicates the geometry of industrial subsea jumpers was deployed to investigate the performance of a new MEG sensor for subsea applications under hydrate-forming conditions. Preliminary baseline experiments were performed at steady state and during gas-restart operations in the absence of any hydrates in the jumper flow loop. Experiments were performed at 64.4°F with nitrogen (N2) gas at 1,200 psig and superficial gas velocity ranges from 0.82 to 2.88 ft/s. The MEG-sensing system’s performance was investigated under hydrate-forming conditions with and without MEG (10–30 wt% in water) in the jumper test section. These experiments were performed at temperatures ranging from 25.2 to 35.6°F. Experimental Flow Loop The flow loop consists of a test section connected to independent gas and liquid injection equipment at the inlet and gas-separation facilities at the outlet, which allows for continuous recirculation of gas and a once-through pass of the liquid. The test section has a complex geometry, with three identical low points (LPs) and two high points. The horizontal length of each low and high points is 12 ft, 10 in., and 7 ft, 7 in., respectively, and total height is 13 ft, 2 in. The test section is equipped with 12 pressure and temperature sensors distributed at regular intervals, a MEG sensor at the second LP, a throttling valve downstream of the first high point to mimic a wellhead choke, and a viewing window at the outlet.
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Liu, Pingli, Qisheng Huang, Juan Du, Hui Shu, and Ming Wang. "Experimental study on acidizing of natural gas hydrate reservoirs." Journal of Physics: Conference Series 2834, no. 1 (2024): 012115. http://dx.doi.org/10.1088/1742-6596/2834/1/012115.
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Abstract Natural gas hydrates (NGH) are a promising resource. Due to the weak cementation of hydrate reservoirs, the reservoirs are prone to sand production or destabilization during hydrate dissociation. Samples of hydrate sediments were manually prepared, consolidated using a cementing agent, and then subjected to flow experiments using an acid solution. Comparative experiments were also conducted with unconsolidated samples. The consolidation samples could maintain the skeleton morphology after acidizing, and no sand production was observed; the unconsolidated samples had severe skeleton deformation after acidizing and serious sand production. The permeability of the consolidation samples after acidizing was 2.95mD, and porosity increased by 8.56%; the permeability of the unconsolidated samples after acidizing was 1.26mD, and the porosity decreased by 7.45%. CT scan images and mercury intrusion curves show good pore development after acidizing the consolidation samples, while the unconsolidated samples have poor pore development and sand plugging after acidizing. This result is because the cementing agent can consolidate the sand and gravel so that it will not be dislodged and transported during the acidizing process, thus maintaining reservoir stability. This study demonstrates the feasibility of acid modification technology in hydrate reservoirs, which is informative for the safe development of gas hydrates.
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Arabi, Abderraouf, Yacine Salhi, Amina Bouderbal, Youcef Zenati, El-Khider Si-Ahmed, and Jack Legrand. "Onset of intermittent flow: Visualization of flow structures." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 76 (2021): 27. http://dx.doi.org/10.2516/ogst/2021009.
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The transition from stratified to intermittent air-water two-phase flow was investigated experimentally, by flow visualization and pressure drop signals analyses, in a 30 mm ID pipe. The intermittent flow’s onset was found to be mainly dependent on the liquid superficial velocity and the pipe diameter. Plug flow, Less Aerated Slug (LAS) or Highly Aerated Slug (HAS) flows could be obtained on the gas superficial velocity grounds. The available models, compared to experiments, could not predict adequately the intermittent flow onset. The appearance of liquid slugs was revealed by peaks in the pressure drop signal. Furthermore, it was shown that the available slug frequency correlations were not valid in the zone of the onset of intermittent flow.
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Lien, Ingebjørg. "Direct electric heating: an environmentally friendly flow-assurance tool." APPEA Journal 53, no. 2 (2013): 448. http://dx.doi.org/10.1071/aj12059.
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In subsea flowlines, water in the line can form an ice-like structure called a hydrate plug. Wax appearance in flowlines also is a common flow assurance issue. Hydrate and wax appearance can reduce or stop production for weeks. Preventing hydrate and wax in pipelines is a major concern for the oil and gas industry. Direct electric heating (DEH) is a modern and environmentally friendly flow-assurance tool that can reduce capital expenditures (CAPEX) and operating expenditures (OPEX) in field development, reduce the probability of pollution, and reduce handling of toxic disposals as a result of traditional chemical flow assurance methods. DEH is based on using the pipeline as part of the electrical circuit, generating losses in the steel pipe to keep the pipeline and its content above the critical temperatures. Use of DEHs also increases the efficiency at the process plant after planned or unplanned production stops. For marginal fields and fields with heavy or waxy oil, DEH is a flow-assurance method that can enable these fields to be developed profitably. DEH is now a mature technology used for 13–14 years on the Norwegian continental shelf and technology implemented and used in West Africa recently. How successful this technology has been can be summarised by the Tyrihans field where Statoil quoted that they—on this project alone—saved about $USD175 million by implementing DEH. Wärtsilä has been part of the DEH development in Norway since the 90s, and undertakes design and supply of the complete topside power package in addition to electric and optical protection specially developed for DEH systems.
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Gusakov, V. N., D. V. Silnov, S. N. Petrenko, A. N. Semenovyh, and A. V. Pegov. "CALCULATION OF TECHNOLOGY ALGORITHM AND SUCCESSFUL APPLICATION OF THERMOCHEMICAL METHOD DURING WELL WORKOVER." Petroleum Engineering 21, no. 6 (2023): 155–63. http://dx.doi.org/10.17122/ngdelo-2023-6-155-163.
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This article is devoted to the analysis of the success of the thermochemical method of generating and transferring thermal energy for underground workover technologies of producing wells. In order to justify the design and consumption of reagents, an algorithm and calculator were compiled based on the well design and thermophysical properties of consumables and fluids: heat capacity of steel, water, ice, enthalpy of ice melting and chemical reaction, the length of the paraffin hydrate plug interval.Thermophysical calculations have shown that for a well with a diameter of 146 and a 73 mm tubing lift, 153 kg of fuel reagent is required for thermal destruction of a paraffin hydrate plug 100 meters long. Based on the geometry of the candidate well and the expected intervals of waxhydrate plug formation, reagent consumption is determined, and a design and work plan are drawn up. The algorithm makes it possible to calculate the flow rate and concentration of working solutions of reagents in order to reach the target temperature at the thermal exposure interval.Measurements of the deep thermometer made it possible to determine that the selected composition of reagents and the exothermic reaction with a delay in heat generation allow to achieve a loss of heat to dissipation at the level of 17 % by 2500 meters of the tubing elevator.The technology of thermal destruction of paraffin-hydrate plugs in gascondensate wells was implemented at the East-Tarkosalinskoye oil and gas condensate field and the Komsomolskoye field with achievement of the specified success criteria.Technologies for development and removal of water from the bottomhole of gas and gas-condensate wells ensure formation of a gas-liquid mixture and removal of water from the bottomhole at the wellhead. The technologies were used at the production facilities of the Vuktyl field (Komi Republic), Amangeldygaz (Kazakhstan Republic), and the East-Tarkosalinsky field (Yamalo-Nenets Autonomous Okrug). As a result of water development, gas wells are switched from pulsating to permanent operation. Heat (thermal) treatment of producing wells uses injection of heat and nitrogen-generating solutions with transfer of thermochemical energy of reagents through permafrost and low-temperature intervals with minimal heat losses. The efficiency of the heat transfer technology was confirmed by temperature measurement by downhole sensors at 139–147 °C at development facilities with reservoir temperatures of 41–43 °C (Ural-Volga region, Purovsky region).The technology of restoring the productivity of gas and gas condensate wells using aerated acids makes it possible to increase the success of subsequent development. The use of the technology of foam acid treatment with methanol makes it possible to successfully restore the productivity of gas and gas condensate wells prone to water removal. Aeration and heating of process solutions of reagents makes it possible to carry out comprehensive measures for treatment of the bottomhole zone of the well with acid and thermochemical impact.
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Ibraheem, S. O., M. A. Adewumi, and J. L. Savidge. "Numerical Simulation of Hydrate Transport in Natural Gas Pipeline." Journal of Energy Resources Technology 120, no. 1 (1998): 20–26. http://dx.doi.org/10.1115/1.2795004.
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Accurate modeling of hydrate transportation in natural gas pipelines is becoming increasingly important in the design and operation of offshore production facilities. The dynamics involved in the formation of hydrate particles and in its transportation are governed by the multiphase hydrodynamics equations ensuing from the balance of mass, momentum, and energy. In this study, a two-fluid model is solved to characterize particulate transportation. The numerical algorithm employed is stable and robust and it is based on higher-order schemes. This is necessary since the governing equations describing the simultaneous flow of gas and solid particles are hyperbolic and, thus, admit discontinuities. Specialized higher-order schemes provide a viable approach for efficient frontal tracking of continuity waves in particular. Several simulation experiments that can facilitate thorough understanding of the design and maintenance of pipelines susceptible to hydrate formation are presented.
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Zhao, Xiaolong, Yizhong Zhao, Meng Mu, Aiyong Zhou, Haifeng Zhao, and Fei Xie. "Plugging Experiments for Ceramic Filling Layer with Different Grain Sizes Under Gas–Water Mixed Flow for Natural Gas Hydrate Development." Energies 18, no. 7 (2025): 1761. https://doi.org/10.3390/en18071761.
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The natural gas hydrate reservoir in the sea area is shallowly buried and mainly composed of silty silt. The reservoir sediment is weakly consolidated and has fine particles, which shows a higher sand production risk and needs sand control. However, the fine silt particles can easily cause blockages in the sand control medium, so the balance between sand control efficiency and gas production should be considered. At present, there is a lack of reasonable and effective measures to prevent pore blockage in the sand control medium. In this study, the influence of the formation of sand on the blockage in sand-retaining mediums under the condition of gas–water mixed flow is discussed, and the plugging process is analyzed. The results show that: (1) Although the ceramic particles have high sphericity and regular shape, they can form higher porosity and permeability, but the finer ceramic particles will also cause blockages in the muddy silt and reduce productivity. (2) The experimental results of different ceramide filling schemes show that Saucier’s empirical criteria are not suitable for hydrate reservoir development and cannot be directly used for reference. In order to balance the problem of sand control and productivity in the development of the hydrate reservoir, it is recommended to use a 40 × 70 mesh ceramide as the critical optimal condition. The experimental results of this paper have important guiding significance for the development of pre-filled sand control screens and the formulation and optimization of sand control schemes.
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Shi, Haoxian, Yixin Zhong, Yanjiang Yu, et al. "Sand Production Characteristics of Hydrate Reservoirs in the South China Sea." Applied Sciences 14, no. 16 (2024): 6906. http://dx.doi.org/10.3390/app14166906.
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The degree and amount of sand production in hydrate reservoirs is related to the selection of stable production processes, but there is currently a lack of quantitative sand production prediction research using real logging data and formation samples from hydrate reservoirs. To reveal the dynamic change characteristics of in-situ reservoirs during hydrate decomposition, and explore quantitative prediction methods for guiding production practice, it is conducted a series of numerical simulations and quantitative prediction experiments. The numerical simulations are carried out using different sand-out prediction methods by using hydrate logging data during drilling, while quantitative prediction experiments of water production and sand-out are carried out based on in-situ reservoir samples. Our experiments indicate that hydrate mining is facing a serious risk of sand-out. The particle transport in the reservoir changes from “large-channel seepage” to “umbrella seepage” and then to “uniform fine flow” as the replacement flow rate decreases. A quantitative prediction model for water and sand production is also established. As a result, our study can provide support for the advancement of technology for long-term stable production and sand control of hydrates, laying the groundwork for developing a stable production plan for natural gas hydrates in offshore areas and determining the optimal depressurisation method.
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Musakaev, Nail G., Stanislav L. Borodin, and Sherzodbek Sh Khojimirzaev. "Mathematical modeling of thermal impact on a closed hydrate-saturated reservoir." Tyumen State University Herald. Physical and Mathematical Modeling. Oil, Gas, Energy 10, no. 1 (2024): 104–20. http://dx.doi.org/10.21684/2411-7978-2024-10-1-104-120.
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In 2014, a crater was discovered in Yamal near the Bovanenkovo oil and gas condensate field. A number of researchers indicate among the possible causes of its occurrence an avalanche-like release of gas formed during the dissociation of gas hydrates. To carry out numerical experiments for analyzing such phenomena, a mathematical model of gas-liquid flow in a saturated porous medium was constructed taking into account the phase transition “gas + water gas hydrate”. A two-dimensional axisymmetric formulation of the problem of heating from above through impermeable rocks of a closed hydrate-saturated reservoir, initially containing gas hydrate and gas, was carried out; to take into account external heat exchange, it is assumed that the reservoir is surrounded by rocks impermeable to matter. An algorithm for numerically solving the equations of the mathematical model is presented. A series of calculations was carried out, on the basis of which an analysis was made of the processes occurring in a closed hydrate-saturated reservoir, namely, changes in temperature, phase saturations and pressure. Calculations have shown that during the dissociation of gas hydrate in a closed reservoir, for a certain set of parameters, a significant increase in pressure can occur from 2.7 to 17.4 MPa. It has been revealed that the shallower the depth of a hydrate-saturated reservoir, the smaller its size and the greater the initial hydrate saturation, the greater increase in pressure can be observed, and, accordingly, the greater risk of violating the integrity of a closed impermeable porous medium and the subsequent avalanche-like release of gas from such object.
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Minero, Claudio, Andrea Bedini, and Marco Minella. "On the Standardization of the Photocatalytic Gas/Solid Tests." International Journal of Chemical Reactor Engineering 11, no. 2 (2013): 717–32. http://dx.doi.org/10.1515/ijcre-2012-0045.
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Abstract The central problem for standardization of photocatalytic efficiency of whatever substrate on an illuminated catalyst is the rate evaluation. For gas/solid experiments different reactors, like batch or flow-through either continuous stirred-tank reactor (CSTR) or plug flow reactor (PFR), could be envisaged. The basic equations governing these reactors and the rate expression for them are presented here. Experiments show that a CSTR configuration presents a lot of advantages for practical use, as any volume, any shape of catalyst and any flow of gas into the reactor can possibly be used. A CSTR configuration is superior to the standardized PFR as the resistance to mass transfer can be reduced by inside forced ventilation. Consequently, it gives an evaluation of the photocatalytic rate more close to the actual surface one. The rate for CSTR at steady state must be calculated as r(Co) = Co F η/S(1−η), where η is the conversion.
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Sun, Zhiqiang, and Hui Gong. "Energy of Intrinsic Mode Function for Gas-Liquid Flow Pattern Identification." Metrology and Measurement Systems 19, no. 4 (2012): 759–66. http://dx.doi.org/10.2478/v10178-012-0067-y.
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Abstract Gas-liquid flows abound in a great variety of industrial processes. Correct recognition of the regimes of a gasliquid flow is one of the most formidable challenges in multiphase flow measurement. Here we put forward a novel approach to the classification of gas-liquid flow patterns. In this method a flow-pattern map is constructed based on the average energy of intrinsic mode function and the volumetric void fraction of gas-liquid mixture. The intrinsic mode function is extracted from the pressure fluctuation across a bluff body using the empirical mode decomposition technique. Experiments adopting air and water as the working fluids are conducted in the bubble, plug, slug, and annular flow patterns at ambient temperature and atmospheric pressure. Verification tests indicate that the identification rate of the flow-pattern map developed exceeds 90%. This approach is appropriate for the gas-liquid flow pattern identification in practical applications.
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Musakaev, Nail G., and Denis S. Belskikh. "Numerical study of the gas production process from a gas hydrate deposit in the presence of thermal and depression effects." Tyumen State University Herald. Physical and Mathematical Modeling. Oil, Gas, Energy 9, no. 3 (2023): 83–99. http://dx.doi.org/10.21684/2411-7978-2023-9-3-83-99.
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Today the issue of gas production technology from existing gas hydrate deposits discovered on the shelf of the World Ocean and in permafrost areas is still very significant since the methane reserves in the free state are significantly inferior to its reserves in the form of its gas hydrates. One of the tasks for possible gas production from a hydrate-containing porous medium is to study the process of gas hydrate decomposition under thermal and depression effects since they are most commonly used ones. It is necessary to conduct a theoretical study including the development of a mathematical mode and its algorithmization, the creation of a computational program and the conduct of numerical experiments. The paper presents one-dimensional axisymmetric problem of heating and/or pressure reduction at the bottom of a well passing through the entire thickness of a porous formation when its pores are initially filled with methane and its hydrate. The utilized mathematical model includes the continuity equations for methane, its hydrate and water; the equation of the gas phase motion in a porous medium as the Darcy filtration law; the state equation of methane and water, the energy conservation equation considering the Joule–Thomson effects and adiabatic cooling for gas, the latent heat of the “gas hydrate methane + water” phase transition. A numerical implementation of the proposed mathematical model and a numerical study of the thermal and/or depression impact on the studied hydrate-bearing deposit are carried out. The results of calculations show that the size of a zone containing only the gas hydrate decomposition products (gas and water) slightly increases with a smaller length of a porous layer. They also show that the thermal effect (increasing the temperature at the bottomhole of production well) on the hydrate-saturated reservoir simultaneously with the depression effect is not efficient enough due to the intensive flow of cold gas (with a temperature equal to the initial temperature of the reservoir) from the hydrate-containing deposit to the well.
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He, Yufa, Yang Tang, Yunjian Zhou, Na Xie, and Guorong Wang. "Experimental Study on Sand Removal by a Downhole In Situ Spiral-Swirl Natural Gas Hydrate Coupling Separator." Applied Sciences 15, no. 5 (2025): 2833. https://doi.org/10.3390/app15052833.
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In natural gas hydrate exploitation, the large amount of sand production directly or indirectly leads to the low efficiency of hydrate exploitation and even the termination of exploitation. A spiral-cyclone coupling separator was used to achieve the separation of mud and sand. In this study, based on the actual size of the spiral-cyclone separator for natural gas hydrate, an experimental prototype of the spiral-cyclone separator suitable for indoor experiments was processed, and an indoor experimental system was built. A pressure loss experiment on the hydrate separation device was carried out, and the results proved the correctness of the numerical simulation model of the spiral-swirl separator and the calculation results. The influence of the inlet flow rate of the separator on the separation effect was studied. It was found that with an increase in the flow rate, the mud/sand separation area began to move up, and the mud/sand settlement area at the bottom appeared to have different degrees of mud/sand accumulation. The indoor experimental results and numerical simulation results show that the separation efficiency increases with the flow rate increase in the range of 5–25 m3/h. This study can provide theoretical guidance for the indoor experimental verification of downhole in situ separators.
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Li, Peng, Xuhui Zhang, and Xiaobing Lu. "Dissociation Behaviors of CO2 Hydrate-Bearing Sediment Particle during Settling in Water." Energies 11, no. 11 (2018): 2896. http://dx.doi.org/10.3390/en11112896.
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Dissociation processes of gas hydrate-bearing sediment particles in water flow condition were investigated. Experiments were carried out by observing a spherical CO2 hydrate-bearing sediment (CHBS) particle settling in water. The release process of gas bubbles from CHBS particles was recorded by a high-speed camera and the total time of dissociation was obtained for different particle diameters and water temperatures. An intrinsic dissociation model was presented based on the assumption that the dissociation rate of the CHBS particle is exponential with the concentration of remaining hydrate. The model considered the influences of changing temperature, pressure and the particle concentration on the dissociation rate. The constants in the model were obtained based on fitting the experimental data. The presented model can reveal the dissociation behavior of the CHBS particle.