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Journal articles on the topic 'Gas viscosity measurement'
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1
Perez, M., L. Salvo, M. Suéry, Y. Bréchet, and M. Papoular. "Contactless viscosity measurement by oscillations of gas-levitated drops." Physical Review E 61, no. 3 (March 1, 2000): 2669–75. http://dx.doi.org/10.1103/physreve.61.2669.
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Yoshimura, Kosuke, Temujin Uehara, Kan'ei Shinzato, Tatsuya Hisatsugu, Naoya Sakoda, Masamichi Kohno, and Yasuyuki Takata. "Development of Gas Viscosity Measurement System with Vibrating Wire Method." Netsu Bussei 28, no. 1 (2015): 15–21. http://dx.doi.org/10.2963/jjtp.28.15.
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Perez, M., J. C. Barbé, C. Patroix, Y. Bréchet, L. Salvo, M. Suéry, and M. Papoular. "Contactless viscosity measurement by a gas film levitated droplet technique." Matériaux & Techniques 88, no. 9-10 (2000): 19–24. http://dx.doi.org/10.1051/mattech/200088090019.
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KOBAYASHI, Yohei, Akira KUROKAWA, and Masaru HIRATA. "Viscosity Measurement of Hydrogen-Methane Mixed Gas for Future Energy Systems." Journal of Thermal Science and Technology 2, no. 2 (2007): 236–44. http://dx.doi.org/10.1299/jtst.2.236.
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Sahu, Abhishek, and Saurabh Kumar. "Alternative Method for Measurement of Apparent Viscosity of Gas Solid Fluidized Bed." Research Journal of Engineering and Technology 8, no. 3 (2017): 174. http://dx.doi.org/10.5958/2321-581x.2017.00028.9.
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Shimokawa, Y., Y. Matsuura, T. Hirano, and K. Sakai. "Gas viscosity measurement with diamagnetic-levitation viscometer based on electromagnetically spinning system." Review of Scientific Instruments 87, no. 12 (December 2016): 125105. http://dx.doi.org/10.1063/1.4968026.
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Yusibani, E., P. L. Woodfield, K. Shinzato, Y. Takata, and M. Kohno. "A compact curved vibrating wire technique for measurement of hydrogen gas viscosity." Experimental Thermal and Fluid Science 47 (May 2013): 1–5. http://dx.doi.org/10.1016/j.expthermflusci.2012.11.008.
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Stanimirovic, Andrej, Emila Zivkovic, Divna Majstorovic, and Mirjana Kijevcanin. "Transport properties of binary liquid mixtures - candidate solvents for optimized flue gas cleaning processes." Journal of the Serbian Chemical Society 81, no. 12 (2016): 1427–39. http://dx.doi.org/10.2298/jsc160623083s.
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Thermal conductivities and viscosities of three pure chemicals, monoethanol amine (MEA), tetraethylene glycol dimethyl ether (TEGDME) and polyethylene glycol 200 (PEG 200) and two binary mixtures (MEA + + TEGDME and MEA + PEG 200) were measured at six temperatures: 298.15, 303.15, 308.15, 313.15, 318.15 and 323.15 K and atmospheric pressure. Measurement of thermal conductivities was based on a transient hot wire measurement setup, while viscosities were measured with a digital Stabinger SVM 3000/G2 viscometer. From these data, deviations in thermal conductivity and viscosity were calculated and fitted to the Redlich-Kister equation. Thermal conductivities of mixtures were correlated using Filippov, Jamieson, Baroncini and Rowley models, while viscosity data were correlated with the Eyring-UNIQUAC, Eyring-NRTL and McAlistermodels.
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Xie, Wei-Qi, and Xin-Sheng Chai. "Measurement of Viscosity in Polymer Solutions by a Tracer-based Gas Chromatographic Technique." Chemistry Letters 46, no. 8 (August 5, 2017): 1161–64. http://dx.doi.org/10.1246/cl.170320.
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Baba, Archibong-Eso, Aliyu, Ribeiro, Lao, and Yeung. "Slug Translational Velocity for Highly Viscous Oil and Gas Flows in Horizontal Pipes." Fluids 4, no. 3 (September 12, 2019): 170. http://dx.doi.org/10.3390/fluids4030170.
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Slug translational velocity, described as the velocity of slug units, is the summation of the maximum mixture velocity in the slug body and the drift velocity. Existing prediction models in literature were developed based on observation from low viscosity liquids, neglecting the effects of fluid properties (i.e., viscosity). However, slug translational velocity is expected to be affected by the fluid viscosity. Here, we investigate the influence of high liquid viscosity on slug translational velocity in a horizontal pipeline of 76.2-mm internal diameter. Air and mineral oil with viscosities within the range of 1.0–5.5 Pa·s were used in this investigation. Measurement was by means of a pair of gamma densitometer with fast sampling frequencies (up to 250 Hz). The results obtained show that slug translational velocity increases with increase in liquid viscosity. Existing slug translational velocity prediction models in literature were assessed based on the present high viscosity data for which statistical analysis revealed discrepancies. In view of this, a new empirical correlation for the calculation of slug translational velocity in highly viscous two-phase flow is proposed. A comparison study and validation of the new correlation showed an improved prediction performance.
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Damasceno, Magalí Araújo, Janaina Karla de Medeiros Penha, Nivaldo Ferreira da Silva Junior, Raimundo Nonato B. Felipe, Renata Carla Tavares dos Santos Felipe, and Gilson Gomes de Medeiros. "Influence of the temperature, pressure and viscosity on the oil measurement with turbine type measurers." Brazilian Archives of Biology and Technology 49, spe (January 2006): 65–72. http://dx.doi.org/10.1590/s1516-89132006000200011.
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The flow measurement of liquids and gases is a necessity in many industrial applications. There is a great amount of measurers for such purpose, as, for example, the coriolis, positive displacement and type turbine measurers. A measurer sufficiently used for the oil flow measurement is the turbine type, because it uses the proper extracted energy of the measured flow for its functioning, moreover is also used as standard for the calibration of other measurers. For this reason, it is important to study the parameters that influence the measurement process for turbine measurers. In Brazil, to measure the volume of oil, regardless the type of measurer, it is necessary to observe "Portaria Conjunta Nº. 1", of June 19, 2000, that approved the Technical Regulation of Measurement of Oil and Natural Gas, establishing the minimum conditions and requirements for the systems of oil and natural gas measurement, in order to get a measurement standard. As such, the present work has the objective of determining parameters that influence in the measurement of oil volumes using turbine measurers.
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Nourozieh, Hossein, Mohammad Kariznovi, and Jalal Abedi. "Measurement and Modeling of Solubility and Saturated-Liquid Density and Viscosity for Methane/Athabasca-Bitumen Mixtures." SPE Journal 21, no. 01 (February 18, 2016): 180–89. http://dx.doi.org/10.2118/174558-pa.
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Summary In the steam-based recovery processes, the coinjected gas can dissolve and diffuse into bitumen or heavy oil for viscosity reduction. The equilibrium concentration and solubility of methane are governed by the complex interaction with the bitumen. Thus, it is necessary to know the quantitative effects of gas dissolution on bitumen viscosity, density, and phase behavior at elevated temperatures in which steam-based processes are applied. Thus, this study aims at providing necessary experimental data for methane/Athabasca bitumen over a wide range of temperatures and pressures (up to 190°C and 10 MPa); that is, conditions that approach the temperatures at in-situ steam processes. Our previously designed phase-behavior experimental apparatus was used to measure the solubility of methane in Athabasca bitumen and its corresponding saturated-phase properties. Then, the measured solubility and density data were modeled with the Peng-Robinson equation of state (EOS) (Robinson and Peng 1978). The results indicate that the effect of temperature on the solubility profile of the methane/Athabasca-bitumen mixture is negligible at high temperatures and there is a distinct difference in the solubility data at 50°C compared with other isotherms (100, 150, and 190°C). Therefore, a reduction in viscosity at higher temperatures is much lower compared with a similar reduction at low temperature (50°C). There is a linear relationship between the methane-saturated viscosity and pressure for all temperatures in a semilog plot. The EOS modeling results also show that temperature-dependent binary-interaction parameters and volume-translation values should be considered to match density and solubility data.
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Huber, Christof, Maria Pilar Pina, Juan José Morales, and Alexandre Mehdaoui. "A Multiparameter Gas-Monitoring System Combining Functionalized and Non-Functionalized Microcantilevers." Micromachines 11, no. 3 (March 10, 2020): 283. http://dx.doi.org/10.3390/mi11030283.
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The aim of the study is to develop a compact, robust and maintenance free gas concentration and humidity monitoring system for industrial use in the field of inert process gases. Our multiparameter gas-monitoring system prototype allows the simultaneous measurement of the fluid physical properties (density, viscosity) and water vapor content (at ppm level) under varying process conditions. This approach is enabled by the combination of functionalized and non-functionalized resonating microcantilevers in a single sensing platform. Density and viscosity measuring performance is evaluated over a wide range of gases, temperatures and pressures with non-functionalized microcantilevers. For the humidity measurement, microporous Y-type zeolite and mesoporous silica MCM48 are evaluated as sensing materials. An easily scalable functionalization method to high-throughput production is herein adopted. Experimental results with functionalized microcantilevers exposed to water vapor (at ppm level) indicate that frequency changes cannot be attributed to a mass effect alone, but also stiffness effects dependent on adsorption of water and working temperature must be considered. To support this hypothesis, the mechanical response of such microcantilevers has been modelled considering both effects and the simulated results validated by comparison against experimental data.
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Abdessalam, Hichem, Boussad Abbès, Yu Ming Li, Ying Qiao Guo, Elvis Kwassi, and Jean-Luc Romain. "Parameter Identification by Inverse Analysis Coupled with a Finite Pointset Method for Polyurethane Foam Expansion." Key Engineering Materials 611-612 (May 2014): 868–75. http://dx.doi.org/10.4028/www.scientific.net/kem.611-612.868.
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This paper deals with the parameter identification for polyurethane foaming process simulation by using an inverse analysis coupled with a Finite Pointset Method. Simultaneous measurements of the foam height rise, the reaction temperature and the viscosity on a cylindrical cardboard test tube are obtained by using the foam measurement system (FOAMAT). The simulation of the foam expansion is obtained by solving unsteady Navier-Stokes equations coupled with the energy equation, the curing reaction (reaction of isocyanate with polyol) and the foaming reaction (reaction of isocyanate with water to emit the CO2 gas) by using a mesh-free method. The inverse identification method consists in determining the parameters by comparing the computed quantities (height rise, reaction temperature and viscosity) computed by the finite pointset method to those measured experimentally.
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Iglesias, L., M. T. Boudjiet, and I. Dufour. "Discrimination and concentration measurement of different binary gas mixtures with a simple resonator through viscosity and mass density measurements." Sensors and Actuators B: Chemical 285 (April 2019): 487–94. http://dx.doi.org/10.1016/j.snb.2019.01.070.
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Russell, P. A., B. A. Buffham, G. Mason, D. J. Richardson, and M. J. Heslop. "Perturbation viscometry measurement of viscosity ratios for ternary gas mixtures and quantification of the errors." Fluid Phase Equilibria 215, no. 2 (February 2004): 195–205. http://dx.doi.org/10.1016/j.fluid.2003.08.013.
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Czernek, Krystian, and Stanisław Witczak. "Non-Invasive Evaluation of Wavy Liquid Film." Chemical and Process Engineering 34, no. 2 (June 1, 2013): 241–52. http://dx.doi.org/10.2478/cpe-2013-0020.
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The study presents the possible use of optoelectronic system for the measurement of values specific for hydrodynamics of two-phase gas very-high-viscosity liquid flow in vertical pipes. An experimental method was provided, and the findings were presented and analysed for selected values which characterise the two-phase flow.
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Davani, Ehsan, Gioia Falcone, Catalin Teodoriu, and William D. McCain. "Rolling Ball Viscometer Calibration with Gas Over Whole Interest Range of Pressure and Temperature Improves Accuracy of Gas Viscosity Measurement." Industrial & Engineering Chemistry Research 51, no. 46 (November 6, 2012): 15276–81. http://dx.doi.org/10.1021/ie301751y.
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Goodarzi, Nina Naireka, Jonathan Luke Bryan, An Thuy Mai, and Apostolos Kantzas. "Novel Techniques for Measuring Heavy-Oil Fluid Properties." SPE Journal 12, no. 03 (September 1, 2007): 305–15. http://dx.doi.org/10.2118/97803-pa.
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Summary Investigating the properties of live heavy oil, as pressure declines from the original reservoir pressure to ambient pressure, can aid in interpreting and simulating the response of heavy-oil reservoirs undergoing primary production. Foamy oil has a distinctly different and more complex behavior compared to conventional oil as the reservoir pressure depletes and the gas leaves solution from the oil. Solution gas separates very slowly from the oil; thus, conventional pressure/volume/temperature (PVT) measurements are not trivial to perform. In this paper, we present novel experiments that utilize X-ray computerized assisted technology (CT) scanning and low field nuclear magnetic resonance (NMR) techniques. These nondestructive tomographic methods are capable of providing unique in-situ measurements of how oil properties change as pressure depletes in a PVT cell. Specifically, this paper details measurements of oil density, oil and gas formation volume factor, solution gas/oil ratio, (GOR), and oil viscosity as a function of pressure. Experiments were initially performed at a slow rate, as in conventional PVT tests, allowing equilibrium to be reached at each pressure step. These results are compared to non-equilibrium tests, whereby pressure declines linearly with time, as in coreflood experiments. The incremental benefit of the proposed techniques is that they provide more detailed information about the oil, which improves our understanding of foamy-oil properties. Introduction Understanding fluid behavior of heavy oils is important for reservoir simulation and production response predictions. In heavy-oil reservoirs, the oil viscosity and density are commonly reported, but there is little experimental data in the literature reporting how oil properties change with pressure. This information would be especially useful for production companies seeking to understand and improve their primary (cold production) response. It is already widely known that foamy-oil behavior is a major cause for increased production in cold heavy-oil reservoirs along with sand production. Therefore, it would be valuable to first study the bulk fluid properties of live heavy oil prior to sandpack-depletion experiments. If the response of these properties to incremental pressure reduction can be established, this can be compared with fluid expansion during pressure depletion in a sandpack. CT scanning is useful in studying high-pressure PVT relationships. Images of a pressure vessel filled with live oil can be taken as the volume of the vessel is expanded and used to calculate bulk densities and free gas saturation. Also, CT images allow us to visually see where free gas is formed in the vessel. For example, CT scanning can be used to provide an indication of whether or not small bubbles nucleate within the oil and then slowly coalesce into a gas cap, or if free gas forms straight away. CT scanning provides much more information than conventional PVT cells. Uncertainties about where gas is forming in the oil, its effect on oil properties, and transient behavior cannot be reconciled in conventional PVT cells. Also, from CT images, the formation of microbubbles could be inferred based on the density of the oil with the dissolved gas. If the oil density decreases below the bubblepoint pressure, then it is likely that gas has come out of solution but remains within the oil; therefore, the resulting mixture is less dense than the original live oil. However, if oil density increases as the gas evolves, then the oil does not contain small gas bubbles, and gas has separated from the oil. Also, the free gas saturation growth with time, and comparison of images at equilibrium vs. immediately after the expansion of the vessel, can provide mass transfer information about gas bubble growth, supersaturation, and gravity separation. When characterizing heavy oil and bitumen fluid properties, oil viscosity is one of the most important pieces of information that has to be obtained. The high viscosities of heavy oil and bitumen present a significant obstacle to the technical and economic success of a given enhanced oil recovery option. As a result, in-situ oil viscosity measurement techniques would be of considerable benefit to the industry. In heavy-oil reservoirs that are undergoing primary production, this problem is further complicated by the presence of the gas leaving solution with the oil. Above the bubblepoint, the gas is fully dissolved into the oil; thus, the live oil exists as a single-phase fluid. Once the pressure drops below the bubblepoint and gas begins to leave solution, the oil viscosity behavior is no longer well understood. In addition to our CT analysis, this work also presents the use of low field NMR as a tool for making in-situ viscosity estimates of live and foamy oil. NMR spectra change significantly as pressure drops and gas leaves solution, and these changes can be correlated to physical changes in the oil viscosity.
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Suwaid, M. A., A. A. Al-muntaser, N. I. Abdaljalil, M. A. Varfolomeev, R. Djimasbe, M. M. Saleh, and A. B. Alfarttoosi. "Effect of reaction time on the process of upgrading heavy oils in the presence and in the absence of oil soluble catalysts at 250 ° C." World of Oil products the Oil Companies Bulletin 04, no. 1 (2021): 29–34. http://dx.doi.org/10.32758/2071-5951-2021-1-4-29-34.
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This work presents the possibility of improving the quality of heavy oil during in-situ upgrading using oil-soluble catalysts based on copper (copper oleate) at 250 ° C under high pressure for 12, 24, 48 and 72 hours using a 300 ml stainless steel batch reactor. Different technique analyzes for heavy oil befor and after upgrading were carried out: Analysis of the evolved gas components by gas chromatography, determination of the group composition of oil (SARA analysis), measurement of viscosity, gas chromatographic analysis of saturated hydrocarbons. The results showed that with an increase in the time of experiments and the use of oil-soluble catalysts, the content of saturated fractions increases due to a decrease in the content of resins and asphaltenes, which leads to a decrease in viscosity of heavy oil from 2073.7 to 1290.5 mPa.s. According to the obtained results, it can be said that reaction time and the use of an oil-soluble catalyst increase the efficiency of the in-situ upgrading.
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Mullins, G., and J. Truhan. "Measurement of semi-volatiles in used natural gas engine oil using thermogravimetric analysis." International Journal of Engine Research 8, no. 5 (October 1, 2007): 439–48. http://dx.doi.org/10.1243/14680874jer00907.
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Semi-volatile in internal combustion engine lubricating oil may be responsible for limiting service life and can lead to in-cylinder deposit formation. In order to measure semivolatile content, a new thermogravimetric analysis (TGA) procedure has been adapted from existing soot procedures to determine the levels of semi-volatile compounds in progressively aged lubricating oil samples from a natural gas engine dynamometer test cell run. The per cent weight remaining at 550 °C, while heated at a constant rate in an inert atmosphere, varied linearly with running time, viscosity, and oxidation and nitration. The method yielded reproducible run-to-run results and showed good agreement between helium and argon atmospheres. Mass spectroscopy data confirmed increased levels of high molecular weight species during engine operation. This method may be applicable to diesel engine oil samples.
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Kita, Kenichiro, Masaki Narisawa, Hiroshi Mabuchi, Masayoshi Itoh, Masaki Sugimoto, and Masahito Yoshikawa. "Synthesis of SiC Based Fibers with Continuous Pore Structure by Melt- Spinning and Controlled Curing Method." Advanced Materials Research 66 (April 2009): 5–8. http://dx.doi.org/10.4028/www.scientific.net/amr.66.5.
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Silicon carbide (SiC) based fibers with continuous pore structures were synthesized by the precursor method using a polycarbosilane (PCS) and polymethylhydrosiloxane (PMHS) polymer blends. The pore formation process can be explained by hydrogen gas dissolution in the polymer melt and desaturation process of the dissolved gas during the fiber spinning. We investigated the effect of PMHS additives with different chemical and physical natures on the obtained pore structures, because PMHS decomposition process played a role of hydrogen gas source. The individual polymer melts were characterized by viscosity measurement, gas chromatograph analysis and thermogravimetric (TG) analysis in order to obtain details of pore structure control.
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Fang, Xin, Xiang’an Yue, Joseph Y. Fu, Weiqing An, Jirui Zou, Xuegang Feng, Wenhao Tian, and Weijie An. "Experimental study on factors affecting the end effect in gas viscosity measurement using capillary-tube viscometer." Review of Scientific Instruments 90, no. 7 (July 2019): 074101. http://dx.doi.org/10.1063/1.5088683.
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Kurokawa, Akira, Hisao Hojo, and Takichi Kobayashi. "Viscosity Measurement Using Impedance and Frequency of a Quartz Resonator Vibrating in a Viscous Flowing Gas." Applied Physics Express 4, no. 3 (March 10, 2011): 037201. http://dx.doi.org/10.1143/apex.4.037201.
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Setyawan, Andriyanto, Indarto, Deendarlianto, and Apip Badarudin. "Effects of Liquid Viscosity on the Wave Velocity and Wave Frequency in Horizontal Annular Flow." Applied Mechanics and Materials 758 (April 2015): 7–12. http://dx.doi.org/10.4028/www.scientific.net/amm.758.7.
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An investigation on the liquid holdup, wave velocity, and wave frequency in horizontal annular flow has been experimentally conducted through the measurement of liquid holdup using constant electric current method (CECM) sensors. To investigate the effect of viscosity, water and glycerin were used as working liquid, using superficial liquid velocity and superficial gas velocity of 0.05 to 0.2 m/s and 12 to 40 m/s, respectively. Liquids with higher viscosity give the higher liquid holdup, lower wave velocity, and lower wave frequency. Correlations for liquid holdup and mean film thickness, wave velocity, and wave frequency have been developed with mean average errors (MAE) of 13.5%, 9.2%, and 8.6%, respectively.
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He, Xian Ru, Shi Rong Zheng, Rui Zhang, Chang Fa Xiao, and Cheng Yu Yang. "Effects of Eva-Hot Melt Adhesive Polarity and Rheology on 3PE Modes." Advanced Materials Research 463-464 (February 2012): 58–62. http://dx.doi.org/10.4028/www.scientific.net/amr.463-464.58.
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The quality of modes of 3PE heat shrinkable sleeve is determined by tackiness of hot melt adhesive rather than aging, according to TGA and aging tests. The tackiness of hot melt adhesive influences on pipeline remaining life and the transmission safety of oil or gas. This paper mainly discussed how the tackiness is determined by hot melt adhesive moisture performance which depends on melt rheology and polymer polarity and offer basic information to further modification. Finally, this paper offers a choice data after such follow experiment. About rheology, apparent viscosity was tested by capillary rheometer and tackiness strength was measured by universal material testing machine. Those tests show that Eτ (Fe/Fe) raises and Ep(Fe/PE) increases at first then decreases with apparent viscosity increasing. About polarity, the polarity was tested by dynamic contact angle locator. This measurement indicates that the moisture improves with polarity increasing and tackiness increases at same time. Generally, the hot-melt adhesive apparent viscosity and polarity extend, consider to pipeline materials properties and oil or gas transmission condition, should hold at 450 Pa•s≤ηa (100°C ,20kg)≤520 Pa•s and 82.0°≤γ≤90.6°.
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Tao, Chengcheng, Eilis Rosenbaum, Barbara G. Kutchko, and Mehrdad Massoudi. "A Brief Review of Gas Migration in Oilwell Cement Slurries." Energies 14, no. 9 (April 22, 2021): 2369. http://dx.doi.org/10.3390/en14092369.
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Gas migration in oil and gas wells is defined as gases and/or fluids from adjacent formations invading a freshly cemented annulus. During well completions, gas and/or fluids can migrate to zones with lower pressure or even to the surface. Static gel strength (SGS), related to the yield stress of the cement, is a widely accepted measurement used to predict and minimize gas migration. In this review article, we look at the mechanisms and some possible solutions to gas migration during oil and gas well cementing. The use of static gel strength (SGS) and experimental measurements for SGS and wellbore pressure reduction are discussed. Rheological properties, including the yield stress and the viscosity of cement slurries, are also briefly discussed. Understanding the rheological properties of cement is complex since its material properties depend on cement type, as well as the shape and size distribution of cement particles. From this brief review, it is evident that in order to reduce free water and settling of the cement particles, to lower fluid loss, and to develop compressive strength in the early stages of cementing, an optimal cement slurry design is needed. The SGS test is a standard method used in estimating the free water in the well and could be a reference for gas migration reduction for oilwell cement slurries.
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Wang, Guohua, Yaru Cui, Ze Yang, Ziliang Guo, Lv Zhao, Xiaoming Li, Junxue Zhao, and Wendan Tang. "Volatilization characteristics of high-lead slag and its influence on measurement of physicochemical properties at high temperature." Journal of Mining and Metallurgy, Section B: Metallurgy 56, no. 1 (2020): 59–68. http://dx.doi.org/10.2298/jmmb190219003w.
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Volatilization causes measurement deviations of physicochemical properties for volatiles-containing slag at high temperature. Hence, investigating the degree of volatilization and identifying the volatilization mechanism and deviation rules are crucial to improve the accuracy of the measured properties. Here, PbO-FeOx-CaO-SiO2-ZnO slag system was selected as a research subject. The volatile characteristics and non-isothermal intrinsic kinetic models of high-temperature volatilization for lead slag were established by thermogravimetric analysis (TGA), and the volatilization mechanism and deviation in the measured properties were determined by analyzing the phase and chemical composition of the residues. In addition, experimental measurements of the melting temperature/ viscosity were compared with theoretically calculated results. The volatilization of PbO decreased the lead-containing phase, but increased the amount of precipitated spinel phase, which led to the deviation in the measured physicochemical properties of the studied slags. The volatilization kinetics for PbO in the slags followed three-dimensional diffusion. The diffusion of PbO gas from PbO-FeOx-CaO-SiO2-ZnO slag was the restrictive step of volatile reaction, and mechanism function was g(?)=1-(1-?)1?3. Moreover, during the slag properties measurement at high temperatures, a high heating rate and protective gas can be used to reduce volatilization of lead slag and avoid consequent properties deviation.
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Saito, Noritaka, Daiji Nakata, Sohei Sukenaga, and Kunihiko Nakashima. "Viscosity Measurement of Molten RE-Mg-Si-O-N (RE=Y, Gd, Nd and La) Glasses." Key Engineering Materials 403 (December 2008): 69–72. http://dx.doi.org/10.4028/www.scientific.net/kem.403.69.
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Viscosities of molten RE-Mg-Si-O-N (RE=Y, Gd, Nd and La) glasses have been measured using rotating bob viscometer with a gas tight furnace at elevated temperature (~1873 K). Moreover, structural characterizations of these quenched vitreous samples have been investigated using solid state 29Si MAS-NMR, which would resolve the relationship between the viscosity of high temperature melts and network structure of RE-Mg-Si-O-N systems. The viscosities of molten RE-Mg-Si-O-N glasses exponentially increased with nitrogen content. 29Si MAS-NMR spectra of RE-Mg-Si-O-N (RE=Y and La) glasses revealed that content of silicon-oxynitride species, like SiO3N, increased with nitrogen content, which indicates that nitrogen clearly modifies the glass network structure. Depending on cationic radius of rare-earth elements, Y was found to be more effective in silicon-oxynitride species formation than La, which are consistent with the results of viscosity measurement of molten RE-Mg-Si-O-N glasses at elevated temperature (~1873 K).
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Shuai, Qun, Gen Lin Niu, Hui Zhao, and Qiang Li. "Numerical Simulation of the Gas-Solid Flow in a Mini-Riser Reactor." Advanced Materials Research 396-398 (November 2011): 356–60. http://dx.doi.org/10.4028/www.scientific.net/amr.396-398.356.
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The implementation of the kinetic theory for granular flows added strength to the two-phase flow model in the mini-riser. This model uses simulating and calculating commercial software of Fluent to simulate the mini-riser with 0.012m ID and 3m height. Euler-Euler two fluid model was adopted in two dimensional numerical simulation, according to kinetic theory，the solid stress was calculated based on granular temperature and granular viscosity obtained through simulation which could be used to describe the collision between particles. Simulation results, such as solid phase fraction and solid phase velocity, under different operational conditions basically agree well with the experimental measurement.
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Yang, Xiao Zhan, Bing Wang, Zhen Sheng Li, and Wen Lin Feng. "Gas-Electrospun Degradable PEG/PBT-HA: Potential Scaffold for Tissue Engineering." Advanced Materials Research 284-286 (July 2011): 923–27. http://dx.doi.org/10.4028/www.scientific.net/amr.284-286.923.
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In this work, the composite nanofibers of polybutylene terephthalate/polyethylene glycol (PEG/PBT) with difference intrinsic viscosity and different ratio of the hard-segment to the soft-segment were obtained by gas-electrospun. The PEG/PBT-HA composite nanofibers were also obtained by gas-electrospun. PEG/PBT and PEG/PBT-HA composite nanofibers were characterized using scanning electron microscopy (SEM), horizontal attenuated total reflectance for Fourier transformation infra-red spectrometer (HATR-FTIR), dynamic contact angle measurement and differential scanning calorimetry (DSC). The results strongly suggest that this synthetic matrix combines with the advantages of synthetic biodegradable polymers, nanometer-scale dimension mimicking the natural ECM, may represent an ideal tissue engineering scaffold, especially for soft tissue, such as skin and cartilage tissue engineering scaffold.
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Ratnakar, Ram R., Edward J. Lewis, and Birol Dindoruk. "Effect of Dilution on Acoustic and Transport Properties of Reservoir Fluid Systems and Their Interplay." SPE Journal 25, no. 06 (May 14, 2020): 2867–80. http://dx.doi.org/10.2118/190480-pa.
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Summary Acoustic velocity is one of the key thermodynamic properties that can supplement phase behavior or pressure/volume/temperature (PVT) measurements of pure substances and mixtures. Several important fluid properties are relatively difficult to obtain through traditional measurement techniques, correlations, or equation of state (EOS) models. Acoustic measurements offer a simpler method to obtain some of these properties. In this work, we used an experimental method based on ultrasonic pulse-echo measurements in a high-pressure/high-temperature (HP/HT) cell to estimate acoustic velocity in fluid mixtures. We used this technique to estimate related key PVT parameters (such as compressibility), thereby bridging gaps in essential data. In particular, the effect of dilution with methane (CH4) and carbon dioxide (CO2) at pressures from 15 to 62 MPa and temperatures from 313 to 344 K is studied for two reservoir fluid systems to capture the effect of the gas/oil ratio (GOR) and density variations on measured viscosity and acoustic velocity. Correlative analysis of the acoustic velocity and viscosity data were then performed to develop an empirical correlation that is a function of GOR. Such a correlation can be useful for improving the interpretation of the sonic velocity response and the calibration of viscosity changes when areal fluid properties vary with GOR, especially in disequilibrium systems. In addition, under isothermal conditions, the acoustic velocity of a live oil decreases monotonically with decreasing pressure until the saturation point where the trend is reversed. This observation can also be used as a technique to estimate the saturation pressure of a live oil or as a byproduct of the target experiments. It supplements the classical pressure/volume measurements to determine the bubblepoint pressure.
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Firoozabadi, Abbas, and Andrew Aronson. "Visualization and Measurement of Gas Evolution and Flow of Heavy and Light Oil in Porous Media." SPE Reservoir Evaluation & Engineering 2, no. 06 (December 1, 1999): 550–57. http://dx.doi.org/10.2118/59255-pa.
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Summary In a number of experiments, the efficiency of solution-gas drive for both light and heavy oils was studied. In these experiments a special coreholder was used to visually observe the formation of gas bubbles on the rock surface of a Berea core and the production from the core outlet. The results from all the experiments reveal that the critical gas saturation for three hydrocarbon liquids; 1. a light model oil, 2. an 11-API gravity oil, and 3. a 35-API gravity oil, does not exceed 3%. However, the gas mobility for the heavy oil is very low and for the light model oil very high. Consequently, solution-gas drive for a heavy oil of 11-API gravity is more efficient than for a light oil. Introduction Solution-gas drive is a basic recovery mechanism. The two parameters that affect the efficiency of this process are: critical gas saturation, and mobility of the gas and liquid phases. A high critical gas saturation implies a high recovery; a 30% critical gas saturation would result in 30% oil recovery provided the oil shrinkage is negligible. On the other hand, a low critical gas saturation does not necessarily imply a low recovery; a low gas mobility or a high liquid mobility would result in high recovery. Generally, solution-gas drive may not be efficient for very light oils. Factors which are believed to contribute to the low recovery are low critical gas saturation and high gas mobility. However, for a heavy oil, the recovery in solution-gas drive could be high either when the critical gas saturation is high or when the gas mobility is low and the liquid mobility is high. One purpose of this paper is to understand solution-gas drive for both light and heavy oils. Solution-gas drive is initiated with bubble nucleation, where at some critical supersaturation pressure (the pressure at which gas evolves from the supersaturated liquid) below the bubblepoint pressure, the formation of gas bubbles occurs. The bubbles may form instantaneously or according to the progressive nucleation theory.1 In progressive nucleation, the rate of bubble formation is related to the supersaturation. Recently, based on theoretical analysis, we have postulated that bubble nucleation in porous media can be an instantaneous nucleation process; all bubbles form instantaneously at the critical supersaturation pressure.1 Another objective of this work is to establish experimentally the instantaneous nature of nucleation in porous media. It has been known for some time that a number of heavy oil reservoirs in Canada (viscosity in the range of 200 to 20,000 cp) have high recovery efficiencies—around 15% to 20% by primary depletion.2,3 The high recovery occurs in the absence of gravity drainage and water drive. A number of authors have made attempts to explain the high recovery from heavy oil reservoirs. In an earlier paper, Smith2 hypothesized that solution-gas drive in heavy oil reservoirs is a two-phase flow, with the gas in the form of tiny bubbles moving with oil. Based on the work of Ward et al.,4 Smith argued that the radius of a stable bubble for a finite volume should be much smaller than the average pore throat. Ward et al.4 had estimated that for a bubble density of 103 cm3, the stable bubble may have a radius of 40 µm. These bubble densities and stable sizes may not apply to a heavy oil in porous media. Further theoretical work is needed to establish the bubble density and stable bubble size for heavy oils. In a later attempt, Islam and Chakma5 used both a long capillary tube and a horizontal core packed with unconsolidated sand to study mechanisms of bubble flow in heavy oil reservoirs. They used Dow Corning oils of 10, 1,000, and 5,000 cp viscosity and heavy oils to conduct flow experiments by simultaneous injection of gas bubbles and liquid. These experiments revealed that bubbles in a flowing stream of a viscous fluid will reduce the apparent viscosity. Islam and Chakma suggested a gas-oil relative permeability with a critical gas saturation of 40%. In-situ gas bubble formation and injection of gas bubbles in a liquid phase are fundamentally different processes. The work of these authors may not directly apply to solution-gas drive in heavy oil reservoirs. In a more recent study, Maini et al.,6 conducted many experiments using unconsolidated sand and heavy oils to study solution-gas drive. A 2-m long sand pack was employed by these authors. The recovery factor was obtained by dropping the pressure suddenly at the core outlet from a saturation pressure of some 700 psi to atmospheric pressure. More than 20% of the original heavy oil was produced in the primary depletion process. As has been observed by Islam and Chakma5 and others,1 a sudden drop in pressure may result in a higher recovery than a gradual pressure drop. From a number of tests, Maini et al. concluded that the critical gas saturation for the formation of a continuous gas phase could be about 40%. The critical gas saturation for heavy oils in the work of Islam and Chakma et al., and Maini et al., are much higher than the values for light oils.7 The above brief review reveals that further work is needed to understand the solution-gas drive in heavy oil reservoirs. The main objectives of this study are to: resolve the issue of very high critical gas saturations; find out whether tiny gas bubbles move with the oil phase; and determine the nature of bubble nucleation and bubble density and to better understand the efficiency of solution-gas drive for heavy oils in porous media. In this work, experiments with both light and heavy oils are performed in order to compare the solution-gas drive for light and heavy oils. A new visual coreholder is used to visually observe the appearance and flow of the gas phase. Experiment A schematic of the experimental apparatus is shown in Fig. 1. The setup, with slight differences, was used for the three sets of experiments. The main components of the apparatus include: the visual coreholder, a high pressure chromatography pump, pressure transducers, a system for providing a constant temperature of 77°F (±0.3°F) and a video recording system. The specially designed visual coreholder consists of an 8 in. long, 2 in. diameter Berea sandstone core (pore volume˜95 cm3, permeability˜500 md), capped at either end with a plexiglass cap (the top cap was machined with a dead end for trapping gas evolved from the core) and sealed with a heat-shrunk teflon sleeve. Surrounding the core is a water-filled translucent chamber, which is pressurized and acts as an overburden sleeve. Plumbed to the coreholder is a constant flow/pressure pump. The pump is used both for saturating the core system and for pressure decline through volume expansion.
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Langenberg, Stefan, Torsten Carstens, Dirk Hupperich, Silke Schweighoefer, and Ulrich Schurath. "Technical note: Determination of binary gas-phase diffusion coefficients of unstable and adsorbing atmospheric trace gases at low temperature – arrested flow and twin tube method." Atmospheric Chemistry and Physics 20, no. 6 (March 26, 2020): 3669–82. http://dx.doi.org/10.5194/acp-20-3669-2020.
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Abstract. Gas-phase diffusion is the first step for all heterogeneous reactions under atmospheric conditions. Knowledge of binary diffusion coefficients is important for the interpretation of laboratory studies regarding heterogeneous trace gas uptake and reactions. Only for stable, nonreactive and nonpolar gases do well-established models for the estimation of diffusion coefficients from viscosity data exist. Therefore, we have used two complementary methods for the measurement of binary diffusion coefficients in the temperature range of 200 to 300 K: the arrested flow method is best suited for unstable gases, and the twin tube method is best suited for stable but adsorbing trace gases. Both methods were validated by the measurement of the diffusion coefficients of methane and ethane in helium and air as well as nitric oxide in helium. Using the arrested flow method the diffusion coefficients of ozone in air, dinitrogen pentoxide and chlorine nitrate in helium, and nitrogen were measured. The twin tube method was used for the measurement of the diffusion coefficient of nitrogen dioxide and dinitrogen tetroxide in helium and nitrogen.
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MacLeod, J. D., and W. Grabe. "Comparison of Coriolis and Turbine-Type Flowmeters for Fuel Measurement in Gas Turbine Testing." Journal of Engineering for Gas Turbines and Power 117, no. 1 (January 1, 1995): 132–37. http://dx.doi.org/10.1115/1.2812761.
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The Machinery and Engine Technology (MET) Program of the National Research Council of Canada (NRCC) has established a program for the evaluation of sensors to measure gas turbine engine performance accurately. The precise measurement of fuel flow is an essential part of steady-state gas turbine performance assessment. Prompted by an international engine testing and information exchange program, and a mandate to improve all aspects of gas turbine performance evaluation, the MET Laboratory has critically examined two types of fuel flowmeters, Coriolis and turbine. The two flowmeter types are different in that the Coriolis flowmeter measures mass flow directly, while the turbine flowmeter measures volumetric flow, which must be converted to mass flow for conventional performance analysis. The direct measurement of mass flow, using a Coriolis flowmeter, has many advantages in field testing of gas turbines, because it reduces the risk of errors resulting from the conversion process. Turbine flowmeters, on the other hand, have been regarded as an industry standard because they are compact, rugged, reliable, and relatively inexpensive. This paper describes the project objectives, the experimental installation, and the results of the comparison of the Coriolis and turbine-type flowmeters in steady-state performance testing. Discussed are variations between the two types of flowmeters due to fuel characteristics, fuel handling equipment, acoustic and vibration interference, and installation effects. Also included in this paper are estimations of measurement uncertainties for both types of flowmeter. Results indicate that the agreement between Coriolis and turbine-type flowmeters is good over the entire steady-state operating range of a typical gas turbine engine. In some cases the repeatability of the Coriolis flowmeter is better than the manufacturer’s specification. Even a significant variation in fuel density (10 percent), and viscosity (300 percent) did not appear to compromise the ability of the Coriolis flowmeter to match the performance of the turbine flowmeter.
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Badarlis, Anastasios, Axel Pfau, and Anestis Kalfas. "Measurement and Evaluation of the Gas Density and Viscosity of Pure Gases and Mixtures Using a Micro-Cantilever Beam." Sensors 15, no. 9 (September 22, 2015): 24318–42. http://dx.doi.org/10.3390/s150924318.
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Cheng Seong, Khor, Nur Nelly Sofia Nurazrin, Fatimah Mohd Hanafi, Sarat C. Dass, Shahrul Azman Zainal Abidin, and Farah Syamim Anuar. "Correlation Model Development for Saybolt Colour of Condensates and Light Crude Oils." ASM Science Journal 13 (June 24, 2020): 1–7. http://dx.doi.org/10.32802/asmscj.2020.434.
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Saybolt colour or number is a measured physical property of petroleum condensates and light crude oils which can be used as a quality indicator. As an alternative approach to the laboratory-based colour measurement method, this work aims to determine the influential physical properties in predicting Saybolt colour by applying a regression modelling approach. Data available on Saybolt colour and several physical properties are obtained from assay reports for condensates and light crude oils of Malaysian oil and gas fields. Other unavailable but potentially influential properties are estimated using a commercial process simulation software, iCON. The properties identified as explanatory variables in this study are refractive index, kinematic viscosity at 40C, and characterization factor. This machine learning problem gives rise to applying multiple linear regression techniques based on a backward elimination approach in developing a correlation to predict Saybolt colour using the identified key properties of characterization factor, kinematic viscosity at 40C, and refractive index.
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Bonilla Riaño, Adriana, Hugo Fernando Velasco Peña, Oscar Mauricio Hernandez Rodriguez, and Antonio Carlos Bannwart. "High spatial and temporal resolution film thickness planar sensor: comparison of geometries." Sensor Review 39, no. 1 (January 21, 2019): 78–86. http://dx.doi.org/10.1108/sr-08-2017-0177.
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Purpose The purpose of this paper is to study planar sensor geometries for the measurement of film thickness in a viscous oil–water flow. The study is relevant due to there are only a few measurement techniques for oil-water flow and these techniques involve oil with low viscosity (close to the water viscosity). Specifically, some techniques have been used in the studies of annular flow (gas–liquid and liquid–liquid flows), but applications in other flow patterns were not encountered. Design/methodology/approach Different sensor geometries were numerically simulated to compare their characteristics and choose the best to measure the water film thickness in the oil–water flow through an impedance-based technique. Finite element method was used for resolving the tridimensional electric field over each sensor. The compared characteristics were the penetration depth, the sensitivity, the minimum spatial resolution (high spatial resolution) and the quasi-linear curve. Findings The best geometry tested has a spatial resolution of 2 × 2 mm, a penetration depth of 700 µm and a quasi-linear response in the measuring range. This geometry was tested by means of conductance and capacitance static experiments. From these experiments, it could be determined that conductance and the capacitance systems are promising for measuring water film thickness in an oil–water flow. Originality/value Several measurement techniques such as micro-PIV, planar laser-induced fluorescence and planar conductive or capacitive sensors that are supposed to be adaptable to the liquid–liquid flow have been proposed recently. Micro-PIV and planar-induced fluorescence need transparent pipes and fluids. On the other hand, conductive or capacitive methods have been only applied to low viscosity fluids. In that context, this paper proposes to study a new technique for non-intrusive measurement of the liquid-liquid flow. The main goal is the validation of the new planar sensor as a reference tool for the development of instrumentation for oilfield application.
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Matthews, G. P., D. C. Dowdell, and I. Wells. "The measurement and estimation of the low-pressure gas viscosity of the replacement ternary blend halo-alkane refrigerant MP-39." Journal of Physics D: Applied Physics 30, no. 14 (July 21, 1997): 2012–17. http://dx.doi.org/10.1088/0022-3727/30/14/008.
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Jaworski, Jacek, and Adrian Dudek. "Study of the Effects of Changes in Gas Composition as Well as Ambient and Gas Temperature on Errors of Indications of Thermal Gas Meters." Energies 13, no. 20 (October 17, 2020): 5428. http://dx.doi.org/10.3390/en13205428.
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Thermal gas meters represent a promising technology for billing customers for gaseous fuels, however, it is essential to ensure that measurement accuracy is maintained in the long term and in a broad range of operating conditions. The effect of hydrogen addition to natural gas will change the physicochemical properties of the mixture of natural gas and hydrogen. Such a mixture will be supplied through the gas system, to consumers, including households, where the amounts of received gas will be metered. The physicochemical properties of hydrogen, including the specific density or viscosity, differ significantly from those of the natural gas components, such as methane, ethane, propane, nitrogen, etc. Therefore, it is of utmost importance to establish the impact of the changes in the gas composition caused by the addition of hydrogen to natural gas on the metrological properties of household gas meters, including thermal gas meters. Furthermore, since household gas meters can be installed outdoors and, taking into account the fact that household gas meters are good heat exchangers, the influence of ambient and gas temperature on the metrological properties of those meters should be investigated. This article reviews a test bench and a testing method concerning errors of thermal gas meter indicators using air and natural gas, including the type containing hydrogen. The indication errors for thermal gas meters using air, natural gas and natural gas with an addition of 2%, 4%, 5%, 10% and 15% hydrogen were determined and then subjected to metrological analysis. Moreover, the test method and test bench are discussed and the results of tests on the impact of ambient and gas temperatures (‒25 °C and 55 °C, respectively) on the errors of indications of thermal gas meters are presented. Conclusions for distribution system operators in terms of gas meter selection were drawn based on the test results.
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Dang, Son, Carl Sondergeld, and Chandra Rai. "Effects of gas pressurization on the interpretation of NMR hydrocarbon measurements in organic rich shales." E3S Web of Conferences 146 (2020): 03008. http://dx.doi.org/10.1051/e3sconf/202014603008.
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The estimation of total hydrocarbons (HCs) in place is one of the most important economic challenges in unconventional resource plays. Nuclear magnetic resonance (NMR) has proven to be a valuable tool in directly quantifying both hydrocarbons and brines in the laboratory and the field. Some major applications of NMR interpretation include pore body size distributions, wettability, fluid types, and fluid properties. However, for tight formations, the effects of the factors on NMR relaxation data are intertwined. One purpose of this study is to review the interpretation of NMR response of HCs in a tight rock matrix through illustrated examples. When comparing NMR data between downhole wireline and laboratory measurement, three important elements need to be considered: 1) temperature differences, 2) system response differences, and 3) pressure (mainly due to the lost gasses.) The effect of temperature on HCs would be presented with experimental results for bulk fluids. Whereas, the effect of pressure is investigated by injecting gas back into rock matrix saturated with original fluids. The experiments were performed within an NMR transparent Daedalus ZrO2 pressure cell, which operates at pressures up to 10,000 psi. The results show that, at ambient temperature and pressure, NMR responds to a fraction of HCs, which is volatile enough to be observed as an NMR relaxation sequence. The invisible fraction of HCs to NMR sequence at ambient condition can be up to 20% of the total extractable HCs. Molecular relaxation is impacted by fluid viscosity, pore size, and surface affinity. In other words, the fluid with higher viscosity (either due to temperature or gas loss), presenting in smaller pore, or highly affected by the pore surface, will relax faster, and would be partially invisible to NMR, especially in the field. This is critical to the interpretation of NMR response for liquid rich source rocks, in which all of the above molecular relaxing restrictions can be found. Thus, engineers can underestimate movable HCs by using routine core analysis data.
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Kao, R. L., D. A. Edwards, D. T. Wasan, and E. Chen. "Measurement of interfacial dilatational viscosity at high rates of interface expansion using the maximum bubble pressure method. I. Gas—liquid surface." Journal of Colloid and Interface Science 148, no. 1 (January 1992): 247–56. http://dx.doi.org/10.1016/0021-9797(92)90133-7.
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Chen, Songhua, D. T. Georgi, Oscar Olima, Hector Gamin, and J. C. Minetto. "Estimation of Hydrocarbon Viscosity With Multiple-te Dual-tw MRIL Logs." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 498–508. http://dx.doi.org/10.2118/68021-pa.
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Summary We report a case study of using nuclear magnetic resonance (NMR) multiple-te, dual wait-time (tw) log acquisitions for quantitative characterization of San Jorge Basin reservoir oil viscosity. Previously, dual-tw logs have been used to discern gas and oil from water, while dual-te logs have been used as a qualitative light oil indicator. Although theoretically simple, quantitative determination of viscosity from dual-te logs is complicated by several factors, including poor signal-to-noise ratio, difficulties in separating oil from water, and the uncertainty of internal gradient strength. In the present study, multiple-te acquisitions of dual-tq logs were used to isolate the oil from the water signal. The values of viscosity of the reservoir fluids can be estimated from either intrinsic T2 or T1. In estimation of the apparent T2, we used a model that does not explicitly require knowledge of the internal gradient, thereby minimizing the effects arising from the uncertainty of the internal and tool gradient strengths. Because T1 and intrinsic T2 are estimated independently, the degree of agreement between the two values provides an indication of the reliability of the two estimates. The main example in the study of four pay zones was thought to contain viscous oil. However, our analysis indicated that the viscosity values of the oil are less than 5 cP. The predictions have been substantiated by production of light hydrocarbons from the three zones that have been perforated. Further, a good agreement is obtained for the viscosity estimates based on NMR log data and laboratory pressure/volume/temperature (PVT) analysis. Introduction Hydrocarbon viscosity is an important reservoir fluid parameter that significantly affects oil recovery and economics. Fluid flow is inversely proportional to viscosity and the higher the viscosity the lower the flow rate and the slower the recovery. Further, when two or more fluids are flowing, the ratio of the viscosities, the mobility ratio, is one of the key parameters that affects sweep efficiency and ultimate recovery. In many reservoirs, it is uneconomical to produce heavy, viscous oil, and thus it is crucial to determine oil viscosity before completing the well. The problem is even more pressing when oil viscosities vary within a hydrocarbon column or from zone to zone when attempting to commingle multiple zones. Many laboratory procedures can determine viscosity. Samples for viscosity determination may be obtained from reservoir fluid samples recovered from well tests or drill stem tests, downhole fluid samplers, or reconstituted from separator samples. Sampling procedures are generally limited to a few depths; and, of course, samples reconstituted from separators are associated with the entire producing interval and may not be associated with a single depth. Further, there is always the concern that the fluid samples may not be representative of the in-situ reservoir fluids. Nuclear magnetic resonance (NMR) logging measurements have the potential to provide in-situ viscosity measurement because the NMR relaxation times, T1 and T2, correlate strongly with fluid viscosity. The difficulty with NMR-determined viscosity is that the measurement is relatively shallow. Thus, the hydrocarbon saturations may be significantly reduced (So or Sor), and hence, the sought NMR oil signal is small. Further, the interpretation may be complicated by NMR signals originating from the invading fluids. NMR response is controlled by both rock and fluid properties. In fact, NMR log interpretation is complicated because it is not always clear whether the T2 decay reflects hydrocarbon and/or rock properties. However, we are fortunate because two NMR experiment parameters, te and tw (Fig. 1), can be used to tailor the NMR data acquisition to separate the hydrocarbon and rock property effects. One of the first specialized NMR applications that took advantage of the ability to control NMR log acquisition parameters was hydrocarbon typing.1 NMR hydrocarbon typing in porous media relies on the difference in NMR response in either or both of the relaxation times (T1 and T2) or diffusivity of oil, water, and gas. By carefully designing the logging program and using combinations of pulse sequences, one can enhance the relaxation and diffusivity contrasts between the different fluid phases. The two commonly used approaches for magnetic resonance image log (MRIL®)** based hydrocarbon typing are dual-tq logging1,2 and dual-te logging.3,4 Dual-tw logging utilizes the T1 contrast between nonwetting light hydrocarbons and the wetting water for quantitative light hydrocarbon typing, while dual-te logging utilizes the viscosity (and thus diffusivity) contrast between reservoir fluids. The latter, to our knowledge, previously has been used mainly as a qualitative, or, at best semiquantitative, hydrocarbon indicator. Quantitative estimation of oil viscosity and saturation require solving problems related to uncertainty of internal magnetic-field gradient and separating oil from water signals. We combined the dual-tw and dual-te approaches to maximize the advantages of both T1 and T2 contrasts. With multiple-te passes of dual-tw logs, we are able to eliminate a majority of the water signal from dual-tw logs; the remaining signal is predominantly an oil signal. The characterization of oil viscosity is achieved by analyzing the relaxation times and diffusion effect on the isolated oil signal with the multiple-te data acquisition. This reduces uncertainties due to the interfering water signal originating from either the irreducible and bound water or from the invading mud filtrate present on conventional dual-te logs.
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Silva, Leonardo BM, and Edval JP Santos. "Modeling high-resolution down-hole pressure transducer to achieve semi-distributed measurement in oil an d gas production wells." Journal of Integrated Circuits and Systems 14, no. 2 (August 25, 2019): 1–9. http://dx.doi.org/10.29292/jics.v14i2.25.
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A full 3D computer model is developed to evaluate the performance impact of intrinsic loss and various geometrical features in high-resolution pressure transducer. The intrinsic loss is modeled as viscosity factors, which allows for a more efficient computer model. In this paper, the developed model is applied to yield an insight in the evolution of high-resolution down-hole pressure transducer, from Hewlett-Packard\texttrademark\, to Quartzdyne\texttrademark. As the quality factor is related to the inverse of the resolution, the transducing element optimization process to achieve the highest quality factor possible is investigated, considering the impact of crystal quality and geometrical features, such as: thickness, diameter and convexity (plano-convex and bi-convex). Temperature-dependent elastic constants are used to improve the model accuracy in modeling temperature effects on the vibrating resonator-type transducer. Boundary load conditions are used to simulate hydrostatic pressure. The simulations to extract the frequency shift are carried out in the range of $14\,psi$ ($96.5\,kPa$) to $20000\,psi$ ($137.89\,MPa$) and $0\,^oC$ to $200\,^oC$ for pressure and temperature, respectively, as such ranges are typically found in oil and gas wells. A discrepancy in the published temperature dependence has been found. A miniaturization path to achieve semi-distributed measurement in oil and gas production wells is presented.
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Chen, Yujia, Ao Li, Dingding Yang, Tianyu Liu, Xiaowei Li, Jun Tang, and Chenglin Jiang. "Study on the Interaction between Low-Viscosity High-Permeability Pregrouting Sealing Material and Coal and Its Application." Advances in Polymer Technology 2020 (February 12, 2020): 1–11. http://dx.doi.org/10.1155/2020/1217285.
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In order to ensure the intactness of pressure-measuring boreholes and the accuracy of gas pressure determination, pregrouting treatment with polymer materials is frequently applied to bedding drilling in coal mines. However, the existing polyurethane materials are of high viscosity, low permeability, and poor safety, bringing great difficulties to their field promotion and application. In view of this problem, after optimization and experiments, polylactide polyol/polyether polyol 4110/isocyanate was determined as the target system. Bio-based benzoxazine (Boz-F), red phosphorus, and melamine with a mass ratio of 2 : 1 : 2 were used as the flame retardant, which then underwent mechanical modification by hollow glass bubbles. Finally, the pregrouting material with low viscosity and high permeability was compounded, and its interaction with coal was experimentally studied. The results show that compared with traditional polyurethane, the new material increases the effective consolidation distance in the coal seam by 40% on average. Its permeation radius is also larger than the calculated radius of the plastic softening zone of a borehole. In addition, the strengths of coal-new material consolidated products with different ratios fully surpass those of coal-polyurethane material consolidated products. The enhancement of compressive strength and bending strength is up to 153% and 161%, respectively. The field application indicates that after pregrouting treatment of boreholes in the coal seam with the new material, the borehole formation rate reaches 100%. Therefore, the new material is safe and practical for gas pressure measurement through bedding drilling on site.
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Grenier, D., T. Lucas, and D. Le Ray. "Measurement of local pressure during proving of bread dough sticks: Contribution of surface tension and dough viscosity to gas pressure in bubbles." Journal of Cereal Science 52, no. 3 (November 2010): 373–77. http://dx.doi.org/10.1016/j.jcs.2010.06.016.
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Stauffenberg, Jaqueline, Steve Durstewitz, Martin Hofmann, Tzvetan Ivanov, Mathias Holz, Waleed Ehrhardt, Wolf-Ulrich Riegel, Jens-Peter Zöllner, Eberhard Manske, and Ivo Rangelow. "Determination of the mixing ratio of a flowing gas mixture with self-actuated microcantilevers." Journal of Sensors and Sensor Systems 9, no. 1 (February 27, 2020): 71–78. http://dx.doi.org/10.5194/jsss-9-71-2020.
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Abstract. Microcantilevers offer a wide range of applications in sensor and measurement technology. In this work cantilever sensors are used as flow sensors. Most conventional flow sensors are often only calibrated for one type of gas and allow an analysis of gas mixtures only with increased effort. The sensor used here is a cantilever positioned vertically in the flow channel. It is possible to operate the sensor in dynamic and static mode. In the dynamic mode the cantilever is oscillating. Resonance frequency, resonance amplitude and phase are measured. In static mode, the bending of the cantilever is registered. The combination of the modes enables the different measured variables to be determined simultaneously. A flow influences the movement behaviour of the sensor, which allows the flow velocity to be deduced. In addition to determining the flow velocity, it is also possible to detect different types of gas. Each medium has certain properties (density and viscosity) which have different effects on the bending of the sensor. As a result, it is possible to measure the mixing ratio of a known binary gas mixture and their flow velocity simultaneously with a single sensor. In this paper this is investigated using the example of the air–carbon-dioxide mixture.
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Sugiyama, S., Y. Liang, S. Murata, T. Matsuoka, M. Morimoto, T. Ohata, M. Nakano, and E. S. Boek. "Construction, Validation, and Application of Digital Oil: Investigation of Asphaltene Association Toward Asphaltene-Precipitation Prediction." SPE Journal 23, no. 03 (February 6, 2018): 952–68. http://dx.doi.org/10.2118/189465-pa.
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Summary Digital oil, a realistic molecular model of crude oil for a target reservoir, opens a new door to understand properties of crude oil under a wide range of thermodynamic conditions. In this study, we constructed a digital oil to model a light crude oil using analytical experiments after separating the light crude oil into gas, light and heavy fractions, and asphaltenes. The gas and light fractions were analyzed by gas chromatography (GC), and 105 kinds of molecules, including normal alkanes, isoalkanes, naphthenes, alkylbenzenes, and polyaromatics (with a maximum of three aromatic rings), were directly identified. The heavy fraction and asphaltenes were analyzed by elemental analysis, molecular-weight (MW) measurement with gel-permeation chromatography (GPC), and hydrogen and carbon nuclear-magnetic-resonance (NMR) spectroscopy, and represented by the quantitative molecular-representation method, which provides a mixture model imitating distributions of the crude-oil sample. Because of the low weight concentration of asphaltenes in the light crude oil (approximately 0.1 wt%), the digital oil model was constructed by mixing the gas, light-, and heavy-fraction models. To confirm the validity of the digital oil, density and viscosity were calculated over a wide range of pressures at the reservoir temperature by molecular-dynamics (MD) simulations. Because only experimental data for the liquid phase were available, we predicted the liquid components of the digital oil at pressures lower than 16.3 MPa (i.e., the bubblepoint pressure) by flash calculation, and calculated the liquid density by MD simulation. The calculated densities coincided with the experimental values at all pressures in the range from 0.1 to 29.5 MPa. We calculated the viscosity of the liquid phase at the same pressures by two independent methods. The calculated viscosities were in good agreement with each other. Moreover, the viscosity change with pressure was consistent with the experimental data. As a step for application of digital oil to predict asphaltene-precipitation risk, we calculated dimerization free energy of asphaltenes (which we regarded as asphaltene self-association energy) in the digital oil at the reservoir condition, using MD simulation with the umbrella sampling method. The calculated value is consistent with reported values used in phase-equilibrium calculation. Digital oil is a powerful tool to help us understand mechanisms of molecular-scale phenomena in oil reservoirs and solve problems in the upstream and downstream petroleum industry.
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Mirea, Radu, and Mihaiella Cretu. "Experimental Assessment of PAO and PAG Based Oil Performances in a Screw Compressor." Revista de Chimie 70, no. 8 (September 15, 2019): 2733–36. http://dx.doi.org/10.37358/rc.19.8.7417.
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The paper presents comparative results of an experimental assessment for behaviour and performances evolution of poly-alpha-olefin (PAO) and poly-alkyl-glycol (PAG) based oil, used in a natural gas screw compressor. Within such compressor type the oil is directly injected and has simultaneous multiple roles: lubrication, coolant, compressing and sealant. Taking into account the gas composition, the oil type used within the screw compressor directly influences its performances and life span. For a known composition of processed the gas, the PAO and PAG oil was used in the same compressor. Each type of oil has been monitored and specifically analyzed: flash point determination, cinematic viscosity measurement, FTIR analysis for contamination and usage determination. The literature highlights that a thorough monitoring and analyze of the oil is, in fact, one of the most important ways to assess the performances and usage of a screw compressor. Thus, many of the compressor maintenance problems can be identified and solved resulting the increase of its lifespan and decrease of the maintenance expenditures. The data have been centralized and a comparative analysis of PAO and PAG has been made, thus resulting the best solution for the specific problem encountered at the natural gas shaft.
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Yuan, Hemin, De-Hua Han, and Weimin Zhang. "Heavy oil sands measurement and rock-physics modeling." GEOPHYSICS 81, no. 1 (January 1, 2016): D57—D70. http://dx.doi.org/10.1190/geo2014-0573.1.
Full textAbstract:
Heavy oil reservoirs are important alternative energy resources to conventional oil and gas reservoirs. However, due to the high viscosity of heavy oil, much production of heavy oil reservoirs involves injecting steam, and determining the temperature distribution is significant for production. To do this, time-lapse inversion is commonly used to derive the change of the oil sand properties during steam injection, and rock-physics models are used to link the properties and temperature. Many people have done research on simulating variations of the oil sand properties with temperature; however, the previous models fail to adequately represent our experimental data, and they overestimate their values. The errors between previous models’ predictions and measurements are quite large, especially at low temperatures. To study the oil sand properties, we first measured eight oil sand samples including five presteam samples and three poststeam samples, and we experimentally quantified the pressure sensitivity of velocity, the temperature sensitivity of velocity, and the corresponding [Formula: see text] ratios. Then we developed a new model, introducing a frame damage parameter and a solid oil proportion parameter. This model integrates the solid oil into the sand frame, and it incorporates the temperature-dependent frame damage to characterize the frame moduli variations with increasing temperature. The solid-Gassmann equation was then applied to saturate the sands’ frame with heavy oil. Our simulation results determined that the errors at low temperature and high temperature were both compensated, and the new model fitted better than previous models over the whole measurement temperature range. The modeling was also extended to the thermal production temperature range, and the phase transition of water was considered, which provided a useful indicator of the steam.