Academic literature on the topic 'Gas Hydrate Plug Flow Experiments'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the lists of relevant articles, books, theses, conference reports, and other scholarly sources on the topic 'Gas Hydrate Plug Flow Experiments.'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Journal articles on the topic "Gas Hydrate Plug Flow Experiments"
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.
Full textAbstract:
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.
2
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.
Full textAbstract:
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.
3
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.
Full textAbstract:
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.
4
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.
Full textAbstract:
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.
5
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.
Full textAbstract:
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.
6
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.
Full textAbstract:
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.
7
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.
Full text
8
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.
Full textAbstract:
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.
9
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.
Full textAbstract:
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.
10
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.
Full textAbstract:
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.
Dissertations / Theses on the topic "Gas Hydrate Plug Flow Experiments"
1
Pham, Trung-Kien. "Etude expérimentale et modélisation de la cristallisation d’hydrates de méthane en écoulement a partir d’une dispersion eau-huile a fort pourcentage d’eau." Thesis, Lyon, 2018. https://tel.archives-ouvertes.fr/tel-02869624.
Full textAbstract:
La production de pétrole brut avec du gaz naturel et de l'eau à basse température et à haute pression favorise les conditions de formation d'hydrates de gaz qui peuvent causer de nombreux problèmes d’écoulement jusqu'au blocage des pipelines. Pour éviter le bouchage, diverses méthodes sont appliquées aux pipelines par addition d'inhibiteurs thermodynamiques (THIs), cinétiques (KHIs) et d'antiagglomérants (AAs). Récemment, l’utilisation des AAs est devenue plus courante car non seulement à cause de leur haute performance dans des conditions sévères, mais aussi grâce à la réduction du coût d’opération dû à avec une faible dose d’AAs utilisée (AA-LDHIs). La plupart des études antérieures sur la formation et transport d’hydrates de gaz se limitent à de faibles fractions d’eau et sans antiagglomérants. Pour des fortes fractions d’eau, la formation et le transport d'hydrates de gaz en présence d’AA-LDHI et/ou de sel dans les conduites d'écoulement restent mal compris. L'objectif principal de cette étude est une meilleure compréhension de la formation et de l’agglomération des hydrates, en testant l’influence des additifs commerciaux pour éviter le colmatage. Ce travail traite plus précisément de la cinétique de cristallisation et d'agglomération des hydrates, ainsi que du transport et du dépôt des suspensions en fonction des conditions d'écoulement (en particulier dans les systèmes à haute fraction d'eau). Les effets de divers paramètres sont étudiés, notamment : à faible dose d’antiagglomérant (AA-LDHI), et fraction volumique d'eau et de salinité dans l'eau variables dans un mélange avec du Kerdane®. Des expériences ont été menées dans la boucle "Archimède". Cet appareillage, capable de fonctionner à plus de 80 bar, permet de reproduire les conditions de transport de pétrole et de gaz dans les pipelines sous-marins. Il est équipé d'une sonde FBRM (Focused Beam Reflectance Measurement) et d'une sonde PVM (Particle Video Microscope) ainsi que de capteurs de température, de perte de charge, de débit et de masse volumique. La mise en circulation du fluide est assurée par une pompe Moineau et/ou un système dit de "gaz-lift". Les résultats ont révélé que dans le protocole avec gaz-lift, les hydrates se forment à la surface des bulles de gaz et des gouttelettes d'eau et leur transport a lieu dans les phases continues d'huile ou d'eau. Généralement, les hydrates ont tendance à se déposer à haute fraction d'eau et à s'agglomérer à une faible fraction d'eau. Des mécanismes de formation et transport des hydrates en présence de bulles ont été proposés. Dans le protocole avec pompe Moineau, les effets de la formation des hydrates, de l'agglomération, du dépôt et du colmatage dans le cadre d’un écoulement multiphasique et vice-versa ont été identifiés, analysés et évalués à fort pourcentage d’eau. Quelques mécanismes de formation et transport d'hydrates dans des conditions expérimentales différentes sont aussi proposés. Un modèle a été développé pour prédire la perte de charge relative dans les pipelines une fois l'hydrate formé<br>Production of crude oil with natural gas and water at low temperature and high pressure favors conditions for gas hydrate formation which might cause many troubles in flow assurance, up to blockage of pipelines. To prevent plugging, varieties of methods are applied to flowlines by addition of thermodynamic inhibitors (THIs), kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs). Recently, AAs are more widely used due to not only their high performance at severe conditions but also the reduction in costs of operation at low dosage (AA-LDHIs). Mostly, previous studies on gas hydrate formation and transport have focused on low water cuts and without anti-agglomerants. On the contrary, at high water cuts, the gas hydrate formation and transport in the presence of AA-LDHI and/or salt in pipelines are not widely understood. The principal objective of this study is a better understanding on hydrate formation and plugging by testing the role of commercial additives to avoid plugging. In details, this work deals with hydrate kinetics of crystallization and agglomeration together with hydrate slurry transport and deposition under flowing conditions (especially at high water cuts). Effects of various parameters were studied, including the amount of commercial anti-agglomerants (AA-LDHIs), water volume fraction, and water salinity in a mixture of Kerdane® oil and water. The experiments were performed in the “Archimède” 80 bar - pilot scale flowloop which reproduces the conditions in oil and gas transport in subsea pipelines. The experimental apparatus is equipped with a FBRM (Focused Beam Reflectance Measurement) and a PVM (Particle Video Microscope) probe and temperature, pressure drop, flowrate and density sensors. The flow was induced through Moineau pump and/or a “gas-lift” system. The results revealed that with gas-lift protocol; hydrates formed on the surface of gas bubbles and water droplets and they were transported in oil and water continuous phases. Generally, the hydrates tend to deposit at high water cut and agglomerate at low water cut. Mechanisms of hydrate formation and transport with and without AA-LDHI in bubble conditions were proposed. With Moineau pump protocol; effects of hydrate formation
2
Seong, Kwanjae, Myung Ho Song, Jung Hyuk Ahn, and Kwang Sung Yoo. "FORMATION OF HYDRATE PLUG WITHIN RECTANGULAR NATURAL GAS PASSAGE." 2008. http://hdl.handle.net/2429/1402.
Full textAbstract:
In order to obtain a better understanding of hydrate plug formation mechanism in natural gas pipelines, formation and growth of hydrate layer within a rectangular channel formed by brass bottom and top surfaces and an insulated inner and an outer surface of transparent polycarbonate tube was studied experimentally. A gas mixture of 90 % methane balanced with propane was supplied at specified flow rates while the humidity and temperature of the supply gas was controlled at desired values using bubble type saturators and heat exchangers placed in series. Hydrate formation occurred along the top and bottom brass surfaces maintained at temperatures below equilibrium hydrate formation temperature, while the transparent tube served as window for visual observation. A series of carefully controlled laboratory experiments were performed to reveal the shape of porous hydrate layer under different combinations of under-cooling and moisture concentrations. The observed transient characteristics of hydrate layer profiles will provide important data that can be used for validation of numerical models to predict hydrate plugging of natural gas pipelines.
3
Kinnari, Keijo, Catherine Labes-Carrier, Knud Lunde, et al. "HYDRATE PLUG FORMATION PREDICTION TOOL – AN INCREASING NEED FOR FLOW ASSURANCE IN THE OIL INDUSTRY." 2008. http://hdl.handle.net/2429/1149.
Full textAbstract:
Hydrate plugging of hydrocarbon production conduits can cause large operational
problems resulting in considerable economical losses. Modeling capabilities to predict
hydrate plugging occurrences would help to improve facility design and operation in
order to reduce the extent of such events. It would also contribute to a more effective
and safer remediation process. This paper systematically describes different operational
scenarios where hydrate plugging might occur and how a hydrate plug formation
prediction tool would be beneficial.
The current understanding of the mechanisms for hydrate formation, agglomeration and
plugging of a pipeline are also presented. The results from this survey combined with the
identified industrial needs are then used as a basis for the assessment of the capabilities
of an existing hydrate plug formation model, called CSMHyK (The Colorado School of
Mines Hydrate Kinetic Model). This has recently been implemented in the transient
multiphase flow simulator OLGA as a separate module.
Finally, examples using the current model in several operational scenarios are shown to
illustrate some of its important capabilities. The results from these examples and the
operational scenarios analysis are then used to discuss the future development needs of
the CSMHyK model.
Book chapters on the topic "Gas Hydrate Plug Flow Experiments"
1
Koh, Carolyn, and Jefferson Creek. "Safety in Hydrate Plug Removal." In Natural Gas Hydrates in Flow Assurance. Elsevier, 2011. http://dx.doi.org/10.1016/b978-1-85617-945-4.00003-0.
Full text
2
Fakher, Sherif, and Abdelaziz Khlaifat. "Gas Slippage in Tight Formations." In Gas Reservoirs [Working Title]. IntechOpen, 2022. http://dx.doi.org/10.5772/intechopen.106839.
Full textAbstract:
In order to address the gas slippage for flow through tight formation, with a very low porosity (less than 10%) and permeability in micro-Darcy range, a series of single-phase gas flow experiments were conducted. Two different gases (N2 and He) were used to carry out many single-phase experiments at different overburden and pressure drops and were compared with carbon dioxide (CO2) flow types. The pore size distribution measurements showed the existence of a wide range of pore size distribution. Also, the single-phase gas flow experiments through the core plug, mostly at low pressure, showed Knudsen diffusion type, which is an indication of gas molecules’ slippage at the wall of the pores.
3
Deusner, C., E. Kossel, N. Bigalke, et al. "The role of high-pressure flow-through experiments for evaluating the mechanical behaviour of gas hydrate-bearing soils." In Energy Geotechnics. CRC Press, 2016. http://dx.doi.org/10.1201/b21938-70.
Full textConference papers on the topic "Gas Hydrate Plug Flow Experiments"
1
Kvarekval, Jon, and Arne Dugstad. "Corrosion Mitigation with pH Stabilisation in Slightly Sour Gas/Condensate Pipelines." In CORROSION 2006. NACE International, 2006. https://doi.org/10.5006/c2006-06646.
Full textAbstract:
Abstract An experimental study focused on the applicability of pH-stabilisation for corrosion control in sour environments with hydrate preventer has been carried out, consisting of flow loop experiments with 50 % diethylene glycol, 0.02 bar H2S and 2 bar CO2. pH values in the range of 6.0-7.0 were investigated. The experiments were run at flow velocities between 1 and 3 m/s and temperatures of 20, 60 and 120°C. It has been shown that pH-stabilisation at a target pH of 7.0 seems to give sufficient corrosion protection under these conditions. The steady state uniform corrosion rates were 10 times less at pH 7 (0.01 mm/y) than at pH 6.5 (0.1-0.2 mm/y). While a few cases of pitting and edge corrosion were found on the specimens exposed at pH 6.5, no localised attacks occurred at pH 7.0. The intensity of corrosion attacks was similar for the three types of carbon steel (St52, X65 and Cr0.5) used in the tests. The findings have contributed to increased confidence in pH stabilisation as a viable corrosion control method for natural gas pipelines with low H2S levels.
2
Dugstad, Arne, and Per-Erik Drønen. "Efficient Corrosion Control of Gas Condensate Pipelines by pH-Stabilisation." In CORROSION 1999. NACE International, 1999. https://doi.org/10.5006/c1999-99020.
Full textAbstract:
Abstract The corrosion rate of gas condensate pipelines can be substantially reduced by increasing the pH artificially. The technique is called pH stabilisation and has been used with success in gas condensate pipelines. The reduction is based on the precipitation of protective corrosion products on the steel surface. When corrosion product films are formed, it is the transport of reactants and corrosion products through the film which governs the corrosion rate. Film properties like porosity, thickness and composition therefore become important. All these properties are strongly related to the precipitation process which depends very much on supersaturation and temperature. A large number of flow loop and glass cell experiments have been carried out in order to study these aspects. In addition to the CO2 partial pressure, the hydrate preventer, the flow velocity, and the pH, a number of variables related to the steel surface conditions and the operation of a real pipeline were studied in the experiments. The last group of variables included the presence of mill scale and rust on the steel surface prior to exposure, periods without flow (shut down), draining of the pipeline and scratches in the protective film. The paper discusses how these parameters affected the performance of carbon steel in water-glycol(50%) systems with 0.6 MPa CO2 partial pressure and with sodium bicarbonate added as pH stabilisator.
3
Kvarekval, J., A. Dugstad, and M. Seiersten. "Localized Corrosion on Carbon Steel in Sour Glycolic Solutions." In CORROSION 2010. NACE International, 2010. https://doi.org/10.5006/c2010-10277.
Full textAbstract:
Abstract Results from joint industry projects (JIP) on corrosion in sour wet gas pipelines with hydrate preventers (glycols) are presented and discussed. Experiments were run in flow loops and glass cell equipment with 0.1-5 bar CO2, 0.1-5 bar H2S and temperatures in the range of 15-90°C. Salinity and pH were also adjusted to simulated different operating conditions. It was found that alkaline chemical treatment for corrosion control (pH stabilization) was inefficient against localized sour corrosion above 0.1 bar H2S, and in some cases even promoted localized attacks.
4
Jevremović, I., V. Mišković-Stanković, M. Achour, M. Singer, and S. Nešić. "Evaluation of a Novel Top-of-the-Line Corrosion (TLC) Mitigation Method in a Large Scale Flow Loop." In CORROSION 2013. NACE International, 2013. https://doi.org/10.5006/c2013-02321.
Full textAbstract:
Abstract Innovative top-of-the-line corrosion (TLC) inhibition techniques are being investigated as an alternative to batch treatment. A novel idea consists of injecting the corrosion inhibitor within a foam matrix. Previously, a “proof of concept” validation of the novel TLC mitigation method was successfully conducted in a small scale laboratory setup. This paper reports a study of foam characteristics: its consistency and stability in experiments conducted in a large scale flow loop, in order to simulate more realistic TLC conditions (including: flow, temperature, water condensation rate).The foam was generated pneumatically by sparging CO2 through the mixture of a foaming agent and a corrosion inhibitor. The foam was then injected into the flow loop, forming a dense plug which is pushed forward by the gas. This provided uniform delivery of the inhibitor to the inner pipe wall. Hydrodynamic tests in flow loop were performed in order to investigate the foam stability as a function of gas velocity as well as the effect of different foaming agent concentrations on the consistency and strength of the foam. Corrosion rate was monitored under condensing conditions using electrical resistance (ER) measurements. The TLC rate of mild steel, as measured in the wet gas flow using the ER probe, was reduced by periodic treatment using the optimized foam composition.
5
Grasso, Giovanny A., Prithvi Vijayamohan, E. Dendy Sloan, Carolyn A. Koh, and Amadeu K. Sum. "Gas Hydrate Deposition in Flowlines: A Challenging Problem in Flow Assurance." In ASME 2013 32nd International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2013. http://dx.doi.org/10.1115/omae2013-11027.
Full textAbstract:
Gas hydrate deposition on the pipeline wall is one of the key processes leading to hydrate plug formation; however, this phenomenon is still poorly understood and missing in a full comprehensive model for simulating/predicting hydrate cold slurry flow (1). To gain a better understanding on hydrate deposition, we have performed several experiments of hydrate deposition on a solid surface for liquid systems (gas free). This preliminary investigation helps to better understand the challenges for further investigations of hydrate deposition in multiphase fluid flow. From this research, the importance of maintaining a constant concentration of the hydrate former and simulating a single pass system were identified; the challenges to control the temperature of the deposition surface, as well as the gradient of the temperature between the fluid and metal surface to promote deposition have also been identified.
6
Della Pietà, A., C. Galimberti, A. Corneo, S. Scaringi, and G. Calzavara. "A Data-Driven Hydrate Plug Detection in Offshore Gas & Condensate Flowlines." In International Petroleum Technology Conference. IPTC, 2024. http://dx.doi.org/10.2523/iptc-23599-ms.
Full textAbstract:
Abstract In multiphase transport pipelines, gas hydrate blockages are a major flow assurance challenge, due to the difficulties in remedial actions and the potential massive production losses. Scope of this study is to define an innovative data-driven methodology to early detect hydrates formation, provide an alarm, and permit early intervention before the complete blockage of the flowline. The proposed approach is applied on a Gas & Condensate pipeline during cold restart, which is the most critical scenario for hydrates formation. In the absence of reliable field data, the methodology was validated on synthetic data. Through a Design of Experiment (DoE) strategy, a wide range of operating conditions (with and without hydrate plug) has been simulated using a multiphase flow model, by varying some key parameters. Only field-measurable variables have been considered for the machine learning model training. In addition, a custom "Friction Factor" indicator and its derivative over time have been calculated, as they emerged to be crucial for model’s performance enhancing. A classification model (XGBoost), called "Alarm Model", was defined to detect the formation of a hydrate plug and raise an alarm, based on a "RiskProbability" estimate. As a result, the model consistently managed to detect in advance the formation of hydrate plugs, particularly in cases of long-time formation. A second model (XGBoost), called "Failure Temporal Distance Model", was developed to classify the system status after an alarm is raised, giving information about the residual time to reach the failure event. This model showed good performances, with 85% of recall for the most critical class (i.e., imminent events), and a global accuracy of 80%. As a conclusion, this research highlights the successful application of machine learning and the relevance of the "Friction Factor" derivative in dynamically detecting plug formation in pipeline systems, without relying only on static thresholds. The use of DoE methodology has proven to be useful in obtaining sufficiently diverse simulations to achieve an algorithm that provides accurate and timely predictions. These findings contribute to the advancement of plug formation detection techniques, with potential applications in enhancing the operational efficiency and maintenance strategies of pipeline networks.
7
Qu, Anqi, Sriram Ravichandran, Stephan Hatscher, et al. "Predicting Hydrate Formation and Plugging in a Gas Condensate Subsea Tieback Using a Transient Hydrate Simulation Tool." In SPE Annual Technical Conference and Exhibition. SPE, 2023. http://dx.doi.org/10.2118/215013-ms.
Full textAbstract:
Abstract A case study based on the Norwegian Vega asset is presented to illustrate the application of a transient gas hydrate formation model to a gas condensate subsea pipeline. The study considers hydrate formation during continuous production and subsequent shut-in and restart of fluid flow in the gas condensate subsea tieback. A hydrate kinetics model is coupled with a dynamic multiphase flow simulator to predict when and where hydrate blockages occur during the transient operations of the subsea tieback. The predicted location of hydrate plugs has also been determined to further guide the design of hydrate plug remediation strategies in the field. A previous version of the hydrate kinetics model has been improved to predict hydrate plugging risks in transient (shut-in/restart) conditions. Observations and measurements from multiscale experiments, including high pressure micromechanical force measurements (HP-MMF) and flowloop tests, were incorporated to provide physical basis for the improved model. Mathematical models were implemented to account for surface area of hydrate formation during the shut-in condition in the subsea tieback. Shear stress and cohesive force were modified to account for hydrate agglomeration during restart. The transient hydrate model was then coupled with the one-dimensional multiphase flow simulator to simulate when and where hydrate formed in the gas condensate subsea tieback. The number and location of hydrate blockages were determined based on the simulation results and compared with field data. The simulation assumed phase separation of liquid phases (stratified water/condensate layers) in the pipeline during the shut-in condition. This assumption is based on prior flowloop experiments performed during shut-in conditions for a gas condensate system. The simulation results showed that 10 vol.% of hydrate formed during steady-state continuous production. During production shut-in, as the temperature of the entire pipeline further drops down and enters the hydrate equilibrium region, slightly more hydrate around 3 vol.% formed at the end of shut-in period of two days. Due to the long shut-in time, cohesive force between hydrate particles was assumed to be one order of magnitude higher than the cohesive force with shorter contact time, as demonstrated in prior measurements. With this input, the production restart simulation has demonstrated the presence of two hydrate blockages at 5.6 mile and 6.8 mile (at the downhill inclination of this 6.95 mile pipeline), based on the definition of plugs occurring where there is high liquid holdup and high relative viscosity. This work has provided a new tool to predict hydrate plug formation in a gas condensate field during transient operations. The interpretation of results from simulations in this work could be further fed into a hydrate plug dissociation model to determine hydrate dissociation time and facilitate remediation of hydrate plugs.
8
Onyekachi, P. N., S. S. Ikiensikimama, Virtue Urunwo Wachikwu-Elechi, and O. E. Okon. "Deep Water Mitigation of Gas Hydrate Formation Using Alium Cepa Skin Extract (ACSE)." In SPE Nigeria Annual International Conference and Exhibition. SPE, 2024. http://dx.doi.org/10.2118/221766-ms.
Full textAbstract:
Abstract The formation of Gas Hydrates is a major flow assurance challenge affecting the Oil and Gas Industry. Hydrates are ice-like, non-stoichiometric crystalline compounds formed at high pressures, and low temperatures usually in the presence of water as the ‘host’, and gases as the ‘guest’. When hydrates form, they tend to clog or plug the flowlines thereby, leading to flow restrictions. This study evaluates the performance of Allium Cepa Skin Extract (ACSE) in gas hydrate formation mitigation. Experiments were carried out using a locally fabricated High Pressure Magnetic Stirrer Autoclave equipment to compare the performance of ACSE to a conventional Kinetic Hydrate Inhibitor (PVP), and to ascertain the inhibitory capacity of the ACSE. For this experiment, Hydrate formation was detected by an increase in the temperature of the Reactor Cell and a drastic decrease in Pressure. The different weight percentages used were 0.01 wt%, 0.02 wt%, and 0.03 wt% respectively. Plots of Pressure, Temperature, and Time of the both inhibitors were made and results obtained were analysed. For the various concentrations (0.01-0.03 wt%) of ACSE, 0.02 wt%, and 0.03 wt% showed a higher inhibitory capacity compared to the PVP. For experiments with 0.01 wt% at the end of 120 minutes for PVP and ACSE, the final pressure drops were 12.3 bar, and 11.2 bar respectively. This shows that PVP was a better inhibitor than ACSE at that weight percentage. 0.02 wt% ASCE proved to be the most effective concentration in preventing gas hydrate formation because at this weight percent, the highest inhibitory capacity was obtained showing that increasing the dosage beyond this concentration would be uneconomical. Although for 0.01wt% which is the lowest concentration, PVP (pressure of 12.3 bar at the end of 120 minutes) performed better than ACSE (11.2 bar), the ACSE solves the challenge of environmental unfriendliness, toxicity, non-biodegradability, and availability. ACSE is eco-friendly, biodegradable, and locally available. Hence, it is recommended that it should be developed as an alternative to the toxic, and hydrate inhibitors used in the Oil and Gas Industry. Since the results of the experimental runs indicated that ACSE had a good performance, it therefore, implies that it may effectively inhibit hydrate when used for field trial.
9
Turco Neto, Eugenio, M. A. Rahman, Syed Imtiaz, and Salim Ahmed. "Numerical Flow Analysis of Hydrate Formation in Offshore Pipelines Using Computational Fluid Dynamics (CFD)." In ASME 2016 35th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2016. http://dx.doi.org/10.1115/omae2016-54534.
Full textAbstract:
Hydrate formation is one of the major challenges faced by the Oil and Gas industry in offshore facilities due to its potential to plug wells and reduce production. Several experimental studies have been published so far in order to understand the mechanisms that govern the hydrate formation process under its thermodynamic favorable conditions; however, the results are not very accurate due to the uncertainties related to measurements and metastable behavior observed in some cases involving hydrate formation. Moreover, thermodynamic models have been proposed to overcome the latter constraints but they are formulated assuming thermodynamic equilibrium, which such condition is difficult to be achieved in flow systems due to the turbulence effects. Due to the low solubility of methane in water, the mass transfer effects can possibly control several mechanisms that are still unknown about the hydrate formation process. Also, the reaction kinetics plays a major rule in minimizing hydrate formation rate. The objective of this work is to develop a mechanistic Computational Fluid Dynamics (CFD) model in order to predict the formation of hydrate particles along the pipeline from a hydrate-free gas dominated stream constituted by methane and water only. The transient simulations were performed using a commercial CFD software package considering the multiphase hydrate chemical reaction and mass transfer resistances. The geometry used was a straight pipe with 5 m length and 0.0254 m diameter. The results have shown the appearance of regions in the pipeline at which hydrate formation is controlled either by the mass transfer or reaction kinetics. The rate of hydrate formation profile has shown to be high at the inlet even though the temperature at that regions was high, which can be a possible explanation for metastable region encountered in most of recent phase diagrams.
10
Gonçalves, Marcelo, Ricardo Camargo, Angela O. Nieckele, Rafael Faraco, Claudio Veloso Barreto, and Luis Fernando G. Pires. "Hydrate Plug Movement by One-Sided Depressurization." In ASME 2012 31st International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2012. http://dx.doi.org/10.1115/omae2012-83969.
Full textAbstract:
A new model that accurately predicts hydrate plug displacement during a one-sided depressurization is presented. This model is both simple to handle and rigorous in the physical representation of the phenomenon. It was implemented as a finite volume transient simulator capable of determining the flow field coupled with the plug displacement dynamics after its detachment. It takes into consideration velocity, pressure and temperature profiles across chambers upstream and downstream the plug at each instant of time, as well as pipe deformation due to pressure variations inside the chambers. Typical cases for deep offshore production are analyzed. The influence on the plug displacement of the gas composition, the temperature variation due to the heat loss to the environment and high pressure variation is addressed. Results show that, depending on the conditions, and after performing a careful risk evaluation, it may be safe to remediate hydrate plug by one-sided depressurization in a number of typical situations in offshore production scenario.
Reports on the topic "Gas Hydrate Plug Flow Experiments"
1
Kim, Jihoon, I. Yucel Akkutlu, Tim Kneafsey, et al. Advanced Simulation and Experiments of Strongly Coupled Geomechanics and Flow for Gas Hydrate Deposits: Validation and Field Application. Office of Scientific and Technical Information (OSTI), 2020. http://dx.doi.org/10.2172/1616018.
Full text