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Journal articles on the topic 'Oil and gas flow'

Author: Grafiati

Published: 4 June 2021

Last updated: 18 February 2022

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1

Mlkvik, Marek, Róbert Olšiak, and Marek Smolar. "Comparison of the Viscous Liquids Spraying by the OIG and the Oil Configurations of an Effervescent Atomizer at Low Inlet Pressures." Strojnícky casopis – Journal of Mechanical Engineering 66, no. 1 (July 1, 2016): 53–64. http://dx.doi.org/10.1515/scjme-2016-0011.

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AbstractIn this work we studied the influence of the fluid injection configuration (OIG: outside-in-gas, OIL: outside-in-liquid) on the internal flows and external sprays parameters. We sprayed the viscous aqueous maltodextrin solutions (μ = 60 mPa·s) at a constant inlet pressure of the gas and the gas to the liquid mass flow ratio (GLR) within the range 2.5 to 20%. We found that the fluids injection has a crucial influence on the internal flows. The internal flows patterns for the OIG atomizer were the slug flows, the internal flow of the OIL device was annular which led to the significant improvement of the spray quality: Smaller droplets, faster atomization, fewer pulsations.

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2

Li, Yingwei, Jing Gao, Xingbin Liu, and Ronghua Xie. "Energy Demodulation Algorithm for Flow Velocity Measurement of Oil-Gas-Water Three-Phase Flow." Mathematical Problems in Engineering 2014 (2014): 1–13. http://dx.doi.org/10.1155/2014/705323.

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Flow velocity measurement was an important research of oil-gas-water three-phase flow parameter measurements. In order to satisfy the increasing demands for flow detection technology, the paper presented a gas-liquid phase flow velocity measurement method which was based on energy demodulation algorithm combing with time delay estimation technology. First, a gas-liquid phase separation method of oil-gas-water three-phase flow based on energy demodulation algorithm and blind signal separation technology was proposed. The separation of oil-gas-water three-phase signals which were sampled by conductance sensor performed well, so the gas-phase signal and the liquid-phase signal were obtained. Second, we used the time delay estimation technology to get the delay time of gas-phase signals and liquid-phase signals, respectively, and the gas-phase velocity and the liquid-phase velocity were derived. At last, the experiment was performed at oil-gas-water three-phase flow loop, and the results indicated that the measurement errors met the need of velocity measurement. So it provided a feasible method for gas-liquid phase velocity measurement of the oil-gas-water three-phase flow.

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3

Bonilla Riaño, Adriana, Antonio Carlos Bannwart, and Oscar M. H. Rodriguez. "Film thickness planar sensor in oil-water flow: prospective study." Sensor Review 35, no. 2 (March 16, 2015): 200–209. http://dx.doi.org/10.1108/sr-09-2014-702.

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Purpose – The purpose of this paper is to study a multiphase-flow instrumentation for film thickness measurement, especially impedance-based, not only for gas–liquid flow but also for mixtures of immiscible and more viscous substances such as oil and water. Conductance and capacitive planar sensors were compared to select the most suitable option for oil – water dispersed flow. Design/methodology/approach – A study of techniques for measurement of film thickness in oil – water pipe flow is presented. In the first part, some measurement techniques used for the investigation of multiphase flows are described, with their advantages and disadvantages. Next, examinations of conductive and capacitive techniques with planar sensors are presented. Findings – Film thickness measurement techniques for oil–water flow are scanty in the literature. Some techniques have been used in studies of annular flow (gas–liquid and liquid–liquid flows), but applications in other flow patterns were not encountered. The methods based on conductive or capacitive measurements and planar sensor are promising solutions for measuring time-averaged film thicknesses in oil–water flows. A capacitive system may be more appropriate for oil–water flows. Originality/value – This paper provides a review of film thickness measurements in pipes. There are many reviews on gas – liquid flow measurement but not many about liquid – liquid flow.

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4

Wang, Hai Qin, Lei Zhang, Yong Wang, and De Xuan Li. "The Effects of Low Flow Rate Gas Involvement on Oil-Water Flow in Horizontal Pipes." Advanced Materials Research 354-355 (October 2011): 41–44. http://dx.doi.org/10.4028/www.scientific.net/amr.354-355.41.

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The experiments were conducted in a horizontal multiphase flow test loop (50mm inner diameter, 40m long) to investigate the flow of oil/water and the influence of an involved gas phase with low flow rate in horizontal pipes, specifically including oil/water flow patterns, cross-section water holdup and pipe flow pressure gradient. The experimental results indicated that the involved gas with low flow rate had a considerable effect on oil/water flow characteristics, which shows the complexity of gas/oil/water three-phase flow. Thus, this effect could not be ignored in design and operation management of oil/gas gathering and transportation system.

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Samuel, Revelation J., and Haroun Mahgerefteh. "Transient Flow Modelling of Start-up CO2 Injection into Highly-Depleted Oil/Gas Fields." International Journal of Chemical Engineering and Applications 8, no. 5 (October 2017): 319–26. http://dx.doi.org/10.18178/ijcea.2017.8.5.677.

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6

Hoffman, Monty, and James Crafton. "Multiphase flow in oil and gas reservoirs." Mountain Geologist 54, no. 1 (January 2017): 5–14. http://dx.doi.org/10.31582/rmag.mg.54.1.5.

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The porous rocks that make up oil and gas reservoirs are composed of complex combinations of pores, pore throats, and fractures. Pore networks are groups of these void spaces that are connected by pathways that have the same fluid entry pressures. Any fluid movement in pore networks will be along the pathways that require the minimum energy expenditure. After emplacement of hydrocarbons in a reservoir, fluid saturations, capillary pressure, and energy are in equilibrium, a significant amount of the reservoir energy is stored at the interface between the fluids. Any mechanism that changes the pressure, volume, chemistry, or temperature of the fluids in the reservoir results in a state of energy non-equilibrium. Existing reservoir engineering equations do not address this non-equilibrium condition, but rather assume that all reservoirs are in equilibrium. The assumption of equilibrium results in incorrect descriptions of fluid flow in energy non-equilibrium reservoirs. This, coupled with the fact that drilling-induced permeability damage is common in these reservoirs, often results in incorrect conclusions regarding the potential producibility of the well. Relative permeability damage, damage that can change which fluids are produced from a hydrocarbon reservoir, can occur even in very permeable reservoirs. Use of dependent variables in reservoir analysis does not correctly describe the physics of fluid flow in the reservoir and will lead to potentially incorrect answers regarding producibility of the reservoir.

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7

Tang, Guo-Qing, Yi Tak Leung, Louis M. Castanier, Akshay Sahni, Frederic Gadelle, Mridul Kumar, and Anthony R. Kovscek. "An Investigation of the Effect of Oil Composition on Heavy Oil Solution-Gas Drive." SPE Journal 11, no. 01 (March 1, 2006): 58–70. http://dx.doi.org/10.2118/84197-pa.

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Summary This study probes experimentally the mechanisms of heavy-oil solution gas drive through a series of depletion experiments employing two heavy crude oils and two viscous mineral oils. Mineral oils were chosen with viscosity similar to crude oil at reservoir temperature. A specially designed aluminum coreholder allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs. pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation vs. pressure. Both depletion rate and oil composition affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however, foam-like flow behavior is still found for the more viscous crude oil. No foam-like flow is observed for the mineral oils. In-situ imaging shows that the gas saturation distribution along the sandpack is not uniform. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow. Additionally, results show that solution-gas drive is effective even at reservoir temperatures as great as 80°C. Oil recovery ranges from 12 to 30% OOIP; the higher the depletion rate, the greater the recovery rate. Introduction Solution gas drive has shown unexpectedly high recovery efficiency in some heavy-oil reservoirs. The mechanisms, however, that have been proposed are speculative, sometimes contradictory, and do not explain fully the origin of high primary oil recovery and slow decline in reservoir pressure. Smith (1988) first identified this effect. He hypothesized that gas bubbles smaller than pore constrictions are liberated from the oil, but are not able to form a continuous gas phase and flow freely. Instead, the gas bubbles exist in a dispersed state in the oil and only flow with the oil phase. Smith stated that oil viscosity is reduced significantly, resulting in high recovery performance. Later, many researchers focused on so-called foamy-oil behavior. Claridge and Prats (1995) hypothesized that heavy-oil components (such as asphaltenes) concentrate at the interfaces between oil and gas bubbles, thereby preventing bubbles from coalescing into a continuous gas phase. Bubbles are assumed to be smaller than pore dimensions. Claridge and Prats stated that the concentration of heavy-oil components at the interfaces results in a reduction of the viscosity of the remaining oil. Bora et al. (2000) discussed the flow behavior of solution gas drive in heavy oils. Based on their studies, they found that dispersed gas bubbles do not coalesce rapidly in heavy oil, especially at high depletion rate. They stated that the main feature of the gas/oil dispersion is a reduced viscosity compared to the original oil. Models to explain the experimental results were also established (Sheng et al. 1994, 1996, 1999, 1995).

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8

Bannwart, Antonio C., Oscar M. H. Rodriguez, Carlos H. M. de Carvalho, Isabela S. Wang, and Rosa M. O. Vara. "Flow Patterns in Heavy Crude Oil-Water Flow." Journal of Energy Resources Technology 126, no. 3 (September 1, 2004): 184–89. http://dx.doi.org/10.1115/1.1789520.

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This paper is aimed to an experimental study on the flow patterns formed by heavy crude oil (initial viscosity and density 488 mPa s, 925.5kg/m3 at 20°C) and water inside vertical and horizontal 2.84-cm-i.d. pipes. The oil-water interfacial tension was 29 dyn/cm. Effort is concentrated into flow pattern characterization, which was visually defined. The similarities with gas-liquid flow patterns are explored and the results are expressed in flow maps. In contrast with other studies, the annular flow pattern (“core annular flow”) was observed in both horizontal and vertical test sections. These flow pattern tends to occur in heavy oil-water flows at low water input fractions. Because of the practical importance of core flow in providing an effective means for heavy oil production and transportation, this paper discusses criteria that favor its occurrence in pipes.

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9

Xin, D., J. Feng, X. Jia, and X. Peng. "An investigation into oil—gas two-phase leakage flow through micro gaps in oil-injected compressors." Proceedings of the Institution of Mechanical Engineers, Part C: Journal of Mechanical Engineering Science 224, no. 4 (April 1, 2010): 925–33. http://dx.doi.org/10.1243/09544062jmes1704.

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This article presents the investigation on the oil—gas two-phase leakage flow through the micro gaps in oil-injected compressors and provides a new way of investigating the internal leakage process in the compressors. The oil—gas leakage rates were measured through the micro gaps of various gap sizes, the volume ratios of oil to gas, and pressure differences/ratios; and the flow patterns reflecting the flow characteristics were observed by using a high-speed video. The experimental results showed that the leakage flowrate was significantly related to the flow patterns in the gap, which were similar to those found in the existing literature and agreed well with the predicted ones by the Weber number. The gas leakage flowrate through the gap increased rapidly with the increased pressure ratio until the pressure ratio reached the critical pressure ratio, which ranged from 1.8 to 2.7. At the critical pressure ratio, the flow pattern transition from churn flow to annular flow occurred, resulting in gas leakage driven by a different sealing mechanism. As the volume ratio of oil to gas increased by 0.5 per cent, the gas leakage flowrate decreased by 77 per cent.

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10

Carcaño-Silvan, C. A., G. Soto-Cortes, and F. Rivera-Trejo. "Characterization of slug flow in heavy oil and gas mixtures." Revista Mexicana de Ingeniería Química 20, no. 1 (March 26, 2020): 1–12. http://dx.doi.org/10.24275/rmiq/proc1289.

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11

Khidr, T. T., and E. A. El Shamy. "Effect of Flow Improvers on the Rheological Properties of Gas Oil and Gas Oil Raffinate." Petroleum Science and Technology 26, no. 1 (January 22, 2008): 114–24. http://dx.doi.org/10.1080/10916460500442361.

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12

Zhao, An, Ning-de Jin, Ying-yu Ren, Lei Zhu, and Xia Yang. "Multi-Scale Long-Range Magnitude and Sign Correlations in Vertical Upward Oil–Gas–Water Three-Phase Flow." Zeitschrift für Naturforschung A 71, no. 1 (January 1, 2016): 33–43. http://dx.doi.org/10.1515/zna-2015-0348.

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AbstractIn this article we apply an approach to identify the oil–gas–water three-phase flow patterns in vertical upwards 20 mm inner-diameter pipe based on the conductance fluctuating signals. We use the approach to analyse the signals with long-range correlations by decomposing the signal increment series into magnitude and sign series and extracting their scaling properties. We find that the magnitude series relates to nonlinear properties of the original time series, whereas the sign series relates to the linear properties. The research shows that the oil–gas–water three-phase flows (slug flow, churn flow, bubble flow) can be classified by a combination of scaling exponents of magnitude and sign series. This study provides a new way of characterising linear and nonlinear properties embedded in oil–gas–water three-phase flows.

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13

Roach, G. J., M. J. Millen, and T. S. Whitaker. "DUET MULTIPHASE FLOW METER." APPEA Journal 40, no. 1 (2000): 492. http://dx.doi.org/10.1071/aj99029.

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CSIRO Minerals has developed a Multiphase Flow Meter (MFM) for measuring oil, water and gas flow rates in offshore topside and sub-sea oil production pipelines. In 1997 Kvaerner Oilfield Products (KOP) signed an exclusive licence agreement with CSIRO Minerals for production and further development of the dual energy gamma-ray transmission (DUET) MFM. This new technology has the potential to save the oil industry many millions of dollars in capital, operating and maintenance costs. Essentially, the MFM consists of two specialised gamma-ray transmission gauges, pressure and temperature sensors, which are mounted on a pipe spool carrying the full flow of the well stream, and processing electronics. Measurements of the intensities of transmitted gamma rays are made to infer the proportions of oil, water and gas, and flow velocities are determined from cross-correlation of gamma-ray signals.Prototype MFM's have completed several Australian and overseas trials, including an extended four-year trial (1994–1998) on Esso's West Kingfish platform in Bass Strait and Texaco's test loop facility in Humble, Texas. During these and other trials the MFM has determined water cut to accuracies of 2–4%, and liquid and gas flow to accuracies of 5–10%, up to a gas volume fraction (G VF) of 95%. Full production versions of the MFM are presently under construction by KOP, and the first installation is due to take place early in 2000 at Texaco's Captain oilfield in the North Sea. CSIRO Minerals is presently consulting with the Australian oil industry to assess interest in the development of a wet gas MFM, capable of operating at GVF's in excess of 95%

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14

Li, Ju Hua, Rui Tang, Jun Xu, and Tao Jiang. "Foamy-Oil Flow Characteristic Considering Relaxation Effects in Porous Media." Applied Mechanics and Materials 318 (May 2013): 486–90. http://dx.doi.org/10.4028/www.scientific.net/amm.318.486.

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The production of heavy oil reservoirs has present anomalous phenomena, in which simultaneous mixture flow of gas as very tiny bubbles entrained in heavy oil is observed in solution gas drive and natural gas huff and puff process. The foamy oil in viscosity fluid has strong mobility to lead to high production and high recovery. Flow properties in pseudo-single phase result in a new feature of reservoir performance. The objective of this paper is to investigate the foamy oil flow characteristic taking account of relaxation effects. Assumed to dual-component of the foamy oil, heavy oil component and tiny gas component, respectively, analytical formulas of the foamy oil flowing pressure distribution during the initial and later stage are derived by the mathematical analytical model of one dimensional unsteady boundary flow in porous media. The result compared with classical Newtonian fluid flow shows that relaxation effects on flowing pressure decrease slowly. By taking L Block formation and injection parameters as an example, the flowing pressure distribution at injection well and production well reveals that effective radius of the foamy oil and injection time have optimal value. Heavy oil component volume concentration is smaller, the greater the corresponding tiny gas volume concentration, i.e., the more foamy oil flow, the greater the pressure effective radius. Through analytical calculation, the injection parameters of natural gas huff and puff for heavy oil reservoirs are assessed. In the practice of heavy oil development, the relaxation effects on heavy oil flow in porous media should be reasonably utilized.

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15

Lisin, Yu V., and A. A. Korshak. "Dispersion of gas bubbles in turbulent oil flow." Neftyanoe khozyaystvo - Oil Industry, no. 9 (2017): 128–30. http://dx.doi.org/10.24887/0028-2448-2017-9-128-130.

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16

WANG, Weiwei. "Voidage Measurement of Gas-Oil Two-phase Flow." Chinese Journal of Chemical Engineering 15, no. 3 (June 2007): 339–44. http://dx.doi.org/10.1016/s1004-9541(07)60090-1.

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17

Meribout, Mahmoud, Abdelwahid Azzi, Nabil Ghendour, Nabil Kharoua, Lyes Khezzar, and Esra AlHosani. "Multiphase Flow Meters Targeting Oil & Gas Industries." Measurement 165 (December 2020): 108111. http://dx.doi.org/10.1016/j.measurement.2020.108111.

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18

El-Gamal, I. M., E. A. M. Gad, S. Faramawi, and S. Gobiel. "Flow improvement of waxy western desert gas oil." Journal of Chemical Technology & Biotechnology 55, no. 2 (April 24, 2007): 123–30. http://dx.doi.org/10.1002/jctb.280550205.

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19

Qian, Huanqun, Zhihua Hu, Hedong Sun, and Fangde Zhou. "Fractal characteristics of oil-gas-water multiphase flow." Journal of Thermal Science 11, no. 1 (February 2002): 49–52. http://dx.doi.org/10.1007/s11630-002-0021-5.

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20

Tayebi, D., S. Nuland, and P. Fuchs. "Droplet transport in oil/gas and water/gas flow at high gas densities." International Journal of Multiphase Flow 26, no. 5 (May 2000): 741–61. http://dx.doi.org/10.1016/s0301-9322(99)00054-3.

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21

GAO, ZHONG-KE, MENG DU, LI-DAN HU, TING-TING ZHOU, and NING-DE JIN. "VISIBILITY GRAPHS FROM EXPERIMENTAL THREE-PHASE FLOW FOR CHARACTERIZING DYNAMIC FLOW BEHAVIOR." International Journal of Modern Physics C 23, no. 10 (October 2012): 1250069. http://dx.doi.org/10.1142/s0129183112500696.

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We systematically carried out oil–gas–water three-phase flow experiments for measuring the time series of flow signals. We first investigate flow pattern behaviors from the energy and frequency point of view and find that different flow patterns exhibit different flow behaviors. In order to quantitatively characterize dynamic behaviors underlying different oil–gas–water three-phase flow patterns, we infer and analyze visibility graphs (complex networks) from signals measured under different flow conditions. The results indicate that the combination parameters of network degree are sensitive to the transition among different flow patterns, which can be used to distinguish different flow patterns and quantitatively characterize nonlinear dynamics of the three-phase flow. In this regard, visibility graph can be a useful tool for characterizing the nonlinear dynamic behaviors underlying different oil–gas–water three-phase flow patterns.

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22

Lakehal, D., M. Labois, D. Caviezel, and B. Belhouachi. "Transition of Gas-Liquid Stratified Flow in Oil Transport Pipes." Journal of Engineering Research [TJER] 8, no. 2 (December 1, 2011): 49. http://dx.doi.org/10.24200/tjer.vol8iss2pp49-58.

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Large-Scale Simulation results of the transition of a gas-liquid stratified flow to slug flow regime in circular 3D oil transport pipes under turbulent flow conditions expressed. Free surface flow in the pipe is treated using the Level Set method. Turbulence is approached via the LES and VLES methodologies extended to interfacial two-phase flows. It is shown that only with the Level Set method the flow transition can be accurately predicted, better than with the two-fluid phase-average model. The transition from stratified to slug flow is found to be subsequent to the merging of the secondary wave modes created by the action of gas shear (short waves) with the first wave mode (high amplitude long wave). The model is capable of predicting global flow features like the onset of slugging and slug speed. In the second test case, the model predicts different kinds of slugs, the so-called operating slugs formed upstream that fill entirely the pipe with water slugs of length scales of the order of 2-4 D, and lower size (1-1.5 D) disturbance slugs, featuring lower hold-up (0.8-0.9). The model predicts well the frequency of slugs. The simulations revealed important parameter effects on the results, such as two-dimensionality, pipe length, and water holdup.

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23

Frank, Michael, Robin Kamenicky, Dimitris Drikakis, Lee Thomas, Hans Ledin, and Terry Wood. "Multiphase Flow Effects in a Horizontal Oil and Gas Separator." Energies 12, no. 11 (June 3, 2019): 2116. http://dx.doi.org/10.3390/en12112116.

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An oil and gas separator is a device used in the petroleum industry to separate a fluid mixture into its gaseous and liquid phases. A computational fluid dynamics (CFD) study aiming to identify key design features for optimising the performance of the device, is presented. A multiphase turbulent model is employed to simulate the flow through the separator and identify flow patterns that can impinge on or improve its performance. To verify our assumptions, we consider three different geometries. Recommendations for the design of more cost- and energy-effective separators, are provided. The results are also relevant to broader oil and gas industry applications, as well as applications involving stratified flows through channels.

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24

Efird, K. D. "Disturbed Flow and Flow-Accelerated Corrosion in Oil and Gas Production." Journal of Energy Resources Technology 120, no. 1 (March 1, 1998): 72–77. http://dx.doi.org/10.1115/1.2795013.

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The effect of fluid flow on corrosion of steel in oil and gas environments involves a complex interaction of physical and chemical parameters. The basic requirement for any corrosion to occur is the existence of liquid water contacting the pipe wall, which is primarily controlled by the flow regime. The effect of flow on corrosion, or flow-accelerated corrosion, is defined by the mass transfer and wall shear stress parameters existing in the water phase that contacts the pipe wall. While existing fluid flow equations for mass transfer and wall shear stress relate to equilibrium conditions, disturbed flow introduces nonequilibrium, steady-state conditions not addressed by these equations, and corrosion testing in equilibrium conditions cannot be effectively related to corrosion in disturbed flow. The problem in relating flow effects to corrosion is that steel corrosion failures in oil and gas environments are normally associated with disturbed flow conditions as a result of weld beads, pre-existing pits, bends, flanges, valves, tubing connections, etc. Steady-state mass transfer and wall shear stress relationships to steel corrosion and corrosion testing are required for their application to corrosion of steel under disturbed flow conditions. A procedure is described to relate the results of a corrosion test directly to corrosion in an operation system where disturbed flow conditions are expected, or must be considered.

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25

Wang, H., D. Vedapuri, J. Y. Cai, T. Hong, and W. P. Jepson. "Mass Transfer Coefficient Measurement in Water/Oil/Gas Multiphase Flow." Journal of Energy Resources Technology 123, no. 2 (November 10, 2000): 144–49. http://dx.doi.org/10.1115/1.1368121.

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Mass transfer studies in oil-containing multiphase flow provide fundamental knowledge towards the understanding of hydrodynamics and the subsequent effect on corrosion in pipelines. Mass transfer coefficient measurements in two-phase (oil/ferri-ferrocyanide) and three-phase (oil/ferri-ferrocyanide/nitrogen) flow using limiting current density technique were made in 10-cm-dia pipe at 25 and 75 percent oil percentage. Mass transfer coefficients in full pipe oil/water flow and slug flow were studied. A relationship is developed between the average mass transfer coefficient in full pipe flow and slug flow. The mass transfer coefficient decreased with a decrease of in-situ water cut. This was due to the existence of oil phase, which decreased the ionic mass transfer diffusion coefficient.

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26

Xu, Zhuoqun, Fan Wu, Xinmeng Yang, and Yi Li. "Measurement of Gas-Oil Two-Phase Flow Patterns by Using CNN Algorithm Based on Dual ECT Sensors with Venturi Tube." Sensors 20, no. 4 (February 21, 2020): 1200. http://dx.doi.org/10.3390/s20041200.

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In modern society, the oil industry has become the foundation of the world economy, and how to efficiently extract oil is a pressing problem. Among them, the accurate measurement of oil-gas two-phase parameters is one of the bottlenecks in oil extraction technology. It is found that through the experiment the flow patterns of the oil-gas two-phase flow will change after passing through the venturi tube with the same flow rates. Under the different oil-gas flow rate, the change will be diverse. Being motivated by the above experiments, we use the dual ECT sensors to collect the capacitance values before and after the venturi tube, respectively. Additionally, we use the linear projection algorithm (LBP) algorithm to reconstruct the image of flow patterns. This paper discusses the relationship between the change of flow patterns and the flow rates. Furthermore, a convolutional neural network (CNN) algorithm is proposed to predict the oil flow rate, gas flow rate, and GVF (gas void fraction, especially referring to sectional gas fraction) of the two-phase flow. We use ElasticNet regression as the loss function to effectively avoid possible overfitting problems. In actual experiments, we compare the Typical-ECT-imaging-based-GVF algorithm and SVM (Support Vector Machine) algorithm with CNN algorithm based on three different ECT datasets. Three different sets of ECT data are used to predict the gas flow rate, oil flow rate, and GVF, and they are respectively using the venturi front-based ECT data only, while using the venturi behind-based ECT data and using both these data.

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27

Aguilera, Roberto. "Flow Units: From Conventional to Tight-Gas to Shale-Gas to Tight-Oil to Shale-Oil Reservoirs." SPE Reservoir Evaluation & Engineering 17, no. 02 (February 20, 2014): 190–208. http://dx.doi.org/10.2118/165360-pa.

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Summary Core data from various North American basins with the support of limited amounts of data from other basins around the world have shown in the past that process speed or delivery speed (the ratio of permeability to porosity) provides a continuum between conventional, tight-, and shale-gas reservoirs (Aguilera 2010a). This work shows that the previous observation can be extended to tight-oil and shale-oil reservoirs. The link between the various hydrocarbon fluids is provided by the word “petroleum” in the “total petroleum system (TPS),” which encompasses liquid and gas hydrocarbons found in conventional, tight, and shale reservoirs. Results of the present study lead to distinctive flow units for each type of reservoir that can be linked empirically to gas and oil rates and, under favorable conditions, to production decline. To make the work tractable, the bulk of the data used in this paper has been extracted from published geologic and petroleum-engineering literature. The paper introduces an unrestricted/transient/interlinear transition flow period in a triple-porosity model for evaluating the rate performance of multistage-hydraulically-fractured (MSHF) tight-oil reservoirs. Under ideal conditions, this flow period is recognized by a straight line with a slope of –1.0 on log-log coordinates. However, the slope can change (e.g., to –0.75), depending on reservoir characteristics, as shown with production data from the Cardium and Shaunavon formations in Canada. This interlinear flow period has not been reported previously in the literature because the standard assumption for MSHF reservoirs has been that of a pseudosteady-state transition between the linear flow periods. It is concluded that there is a significant practical potential in the use of process speed as part of the flow-unit characterization of unconventional petroleum reservoirs. There is also potential for the evaluation of production-decline rates by the use of the triple-porosity model presented in this study.

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Gao, Qiang, and Hong Ye Zhao. "Design of Flare Gas Flow Measurement System on Offshore Oil Platform." Applied Mechanics and Materials 385-386 (August 2013): 460–63. http://dx.doi.org/10.4028/www.scientific.net/amm.385-386.460.

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Aiming at the problems of flare gas flow monitoring on offshore oil platform, a flare gas flow measurement system is designed. This system is integrated in the whole flare control system and reaches the effective monitoring of flare gas flow. Besides it adopts ultrasonic flow-meters for the more accurate flow-meter data and adopts hot-cap method for the realization of being installed without halting production. Results indicate that the design could offshore oil platform improve the efficiency and safety of production in offshore oil platform.

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29

Shade, W. N., and D. E. Hampshire. "An Experimental Investigation of Oil-Buffered Shaft Seal Flow Rates." Journal of Engineering for Gas Turbines and Power 107, no. 1 (January 1, 1985): 170–80. http://dx.doi.org/10.1115/1.3239679.

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An experimental investigation was conducted to identify an optimum oil-buffered shaft seal for use on centrifugal compressors, with the primary objective being minimal seal oil exposure to process gases that cause seal oil degradation or are toxic. Types of seals tested included smooth bore cylindrical bushings, spiral groove cylindrical bushings, radial outward-flow face seals, and radial inward-flow face seals. The influence of shaft speed, gas pressure, seal oil differential pressure, oil bypass flow rate, and oil supply temperature on process side seal oil flow rate was determined. The investigation revealed some surprising relationships between seal oil flow rates and the escape of process gas.

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Ward, Terry J. "Cash Flow Information And The Prediction Of Financially Distressed Mining, Oil And Gas Firms: A Comparative Study." Journal of Applied Business Research (JABR) 10, no. 3 (September 22, 2011): 78. http://dx.doi.org/10.19030/jabr.v10i3.5927.

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<span>This study tests whether cash flow information is more useful to creditors in predicting financially distressed mining, oil and gas firms than it is in predicting financial distress in other industries. The results of this study suggest that cash flows are more useful to creditors in predicting financially distressed mining, oil and gas firms than they are predicting financially distressed firms in other industries. Results also show that different cash flows are useful in predicting financial distressed mining, oil and gas firms than are useful in predicting financially distressed control firms.</span>

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Liu, Weixin, Yunfeng Han, Dayang Wang, An Zhao, and Ningde Jin. "The Slug and Churn Turbulence Characteristics of Oil–Gas–Water Flows in a Vertical Small Pipe." Zeitschrift für Naturforschung A 72, no. 9 (August 28, 2017): 817–31. http://dx.doi.org/10.1515/zna-2017-0119.

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AbstractThe intention of the present study was to investigate the slug and churn turbulence characteristics of a vertical upward oil–gas–water three-phase flow. We firstly carried out a vertical upward oil–gas–water three-phase flow experiment in a 20-mm inner diameter (ID) pipe to measure the fluctuating signals of a rotating electric field conductance sensor under different flow patterns. Afterwards, typical flow patterns were identified with the aid of the texture structures in a cross recurrence plot. Recurrence quantitative analysis and multi-scale cross entropy (MSCE) algorithms were applied to investigate the turbulence characteristics of slug and churn flows with the varying flow parameters. The results suggest that with cross nonlinear analysis, the underlying dynamic characteristics in the evolution from slug to churn flow can be well understood. The present study provides a novel perspective for the analysis of the spatial–temporal evolution instability and complexity in oil–gas–water three-phase flow.

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Wang, Ruihe, Zhangxin Chen, Jishun Qin, and Ming Zhao. "Performance of Drainage Experiments With Orinoco Belt Heavy Oil in a Long Laboratory Core in Simulated Reservoir Conditions." SPE Journal 13, no. 04 (December 1, 2008): 474–79. http://dx.doi.org/10.2118/104377-pa.

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Summary When some heavy-oil reservoirs are produced using gas drive, they show three important features: low production gas/oil ratios, higher-than-expected production rates, and relatively high oil recovery. The mechanism for this unusual behavior remains controversial and poorly understood, though the term "foamy oil" is often used to describe such behavior. The impetus for this work stems from some recent projects performed in the Orinoco belt, Venezuela. There exist nearly one trillion bbl of heavy oil (oil in place) in this region on the basis of a recent evaluation. Two crucial issues must be addressed before or during designing production projects: What is a suitable method for evaluating the foamy-oil drive mechanism that plays a major role during such oil recovery, and how do we obtain a reasonable percentage of ultimate oil recovery? Unfortunately, it is still difficult to give good explanations for these two issues, although several studies were performed. This paper attempts to present better explanations for these two issues using experimental drainage in a long laboratory core in simulated reservoir conditions. Our experiments show that ultimate oil recovery for the heavy oil in the Orinoco belt can be as high as 15-20%. This high recovery comes from three contributions: fluid and rock expansion, foamy-oil drive, and conventional-solution-gas drive. Approximately 3-5% of recovery is from fluid and rock expansion, 11-16% from foamy-oil drive, and 2-4% from conventional-solution-gas drive. This ultimate-oil-recovery percentage is much higher than the 12% that has been used in the field-development plan for the Orimulsion project. The experiments performed and their findings obtained in this paper are representative at least in the Orinoco belt region. Introduction Most practitioners try to produce as much oil as possible under primary recovery. In all solution-gas-drive reservoirs, gas is released from solution as the reservoir pressure declines. Gas initially exists in the form of small bubbles created within individual pores. As time evolves and pressure continues to decline, these bubbles grow to occupy the pores. With a further decline in pressure, the bubbles created in different locations become large enough to coalesce into a continuous gas phase. Conventional wisdom indicates that the discrete bubbles that are larger than pore throats remain immobile (trapped by capillary forces) and that gas flows only after the bubbles have coalesced into a continuous gas phase. Once the gas phase becomes continuous, which is equivalent to the gas saturation becoming larger than critical, the minimum saturation at which a continuous gas phase exists in porous media (Chen et al. 2006), traditional two-phase (gas and oil) flow with classical relative permeabilities occurs. A result of this evolution process is that the production gas/oil ratio (GOR) increases rapidly after the critical gas saturation has been exceeded. Field observations in some heavy-oil reservoirs, however, do not fit into this solution-gas-drive description in that the production GOR remains relatively low. The recovery factors (percentage of the oil in a reservoir that can be recovered) in such reservoirs are also unexpectedly high. A simple explanation of these observations could be that the critical gas saturation is high in these reservoirs. This explanation cannot be confirmed by direct laboratory measurement of the critical gas saturation. An alternative explanation of the observed GOR behavior is that gas, instead of flowing only as a continuous phase, also flows in the form of gas-in-oil dispersion. This type of dispersed gas/oil flow is what is referred to as "foamy-oil" flow. Although the unusual production behavior in some heavy-oil reservoirs was observed as early as the late 1960s, Smith (1988) appears to have been the first to report it and used the terms "oil/gas combination" and "mixed fluid" to describe the mixture of oil and gas that is entrained in heavy oil as very tiny bubbles. Baibakov and Garushev (1989) used the term "viscous-elastic system" to describe highly viscous oil with very fine bubbles present. Sarma and Maini (1992) were the first to use the phrase "foamy oil" to describe viscous oil that contains dispersed gas bubbles. Claridge and Prats (1995) used the terms "foamy heavy oil" and "foamy crude." Although there is continuing debate on the suitability of the term "foamy-oil flow" to describe the anomalous flow of the oil/gas mixture in primary production of heavy oil (Firoozabadi 2001; Tang and Firoozabadi 2003; Tang and Firoozabadi 2005), this expression has become a fixture in the petroleum-engineering terminology (Chen 2006, Maini 1996). The actual structure of foamy-oil flow and its mathematical description are still not well understood. Much of the earlier discussion of such flow was based on the concept of microbubbles [i.e., bubbles much smaller than the average pore-throat size and, thus, free to move with the oil during flow (Sheng et al. 1999)]. This type of dispersion can be produced only by nucleation of a very large number of bubbles (explosive nucleation) and by the presence of a mechanism that prevents these bubbles from growing into larger bubbles with decline in pressure (Maini 1996). This hypothesis has not been supported by experimental evidence. A more plausible hypothesis on the structure of foamy-oil flow is that it involves much larger bubbles migrating with the oil and that the dispersion is created by the breakup of bubbles during their migration with the oil. The major difference between the conventional-solution-gas drive and the foamy-solution-gas drive is that the pressure gradient in the latter is strong enough to mobilize gas clusters after they have grown to a certain size. Maini (1999) presented experimental evidence that supports this hypothesis for foamy-oil flow. This hypothesis seems consistent with the visual observations in micromodels that show the bubble size to be larger than the pore size. However, more laboratory experiments must be conducted to validate this hypothesis. The impetus for this work stems from some recent projects performed in the Orinoco belt, Venezuela. The largest heavy-oil reserves in the world are in this region, with nearly one trillion bbbl of heavy oil in place on the basis of a recent evaluation (Fig. 1) (Andarcia et al. 2001). The unusual recovery performance mentioned previously has been observed during drainage of heavy-oil reservoirs in the Orinoco belt. The problems we now face are the following. How will we estimate the production performance for the present project by taking into account the foamy-oil-drive mechanism? In addition, what will be an applicable measure to evaluate the production potential of this project? What will a production profile of this project look like? How much oil will be produced within a certain time period of our operation? Unfortunately, there were no satisfactory answers yet for these questions. This paper attempts to address these issues using results from a suite of laboratory experiments. The attempts to address these issues will improve our understanding of foamy-oil behavior and its mechanism.

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Alhosani, Abdulla, Alessio Scanziani, Qingyang Lin, Ahmed Selem, Ziqing Pan, Martin J. Blunt, and Branko Bijeljic. "Three-phase flow displacement dynamics and Haines jumps in a hydrophobic porous medium." Proceedings of the Royal Society A: Mathematical, Physical and Engineering Sciences 476, no. 2244 (December 2020): 20200671. http://dx.doi.org/10.1098/rspa.2020.0671.

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We use synchrotron X-ray micro-tomography to investigate the displacement dynamics during three-phase—oil, water and gas—flow in a hydrophobic porous medium. We observe a distinct gas invasion pattern, where gas progresses through the pore space in the form of disconnected clusters mediated by double and multiple displacement events. Gas advances in a process we name three-phase Haines jumps, during which gas re-arranges its configuration in the pore space, retracting from some regions to enable the rapid filling of multiple pores. The gas retraction leads to a permanent disconnection of gas ganglia, which do not reconnect as gas injection proceeds. We observe, in situ , the direct displacement of oil and water by gas as well as gas–oil–water double displacement. The use of local in situ measurements and an energy balance approach to determine fluid–fluid contact angles alongside the quantification of capillary pressures and pore occupancy indicate that the wettability order is oil–gas–water from most to least wetting. Furthermore, quantifying the evolution of Minkowski functionals implied well-connected oil and water, while the gas connectivity decreased as gas was broken up into discrete clusters during injection. This work can be used to design CO 2 storage, improved oil recovery and microfluidic devices.

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34

Ashoori, E., T. L. M. L. M. van der Heijden, and W. R. R. Rossen. "Fractional-Flow Theory of Foam Displacements With Oil." SPE Journal 15, no. 02 (March 3, 2010): 260–73. http://dx.doi.org/10.2118/121579-pa.

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Summary Fractional-flow theory provides key insights into complex foam enhanced-oil-recovery (EOR) displacements and acts as a benchmark for foam simulators. In some cases with mobile oil present, the process can be represented as a two-phase displacement. We examine three such cases. A first-contact-miscible (FCM) gasflood with foam injection includes a chemical shock defining the surfactant front and a miscible shock defining the gas front. The optimal water fraction for the foam, that which gives the fastest oil recovery in 1D, maintains the gas front slightly ahead of the foam (surfactant) front. The success of a foam process with FCM CO2 and surfactant dissolved in the (supercritical) CO2 depends on the strength of foam at very low water fractional flow, such as for a surfactant- alternating-gas (SAG) process with surfactant dissolved in water. The speed of propagation of the foam front depends on surfactant adsorption on rock and on the partitioning of surfactant between water and CO2 but is always less than the velocity of the foam front in a SAG flood with surfactant ahead of the gas. A foam with surfactant that partitions preferentially into water rather than into CO2 would propagate slowly, regardless of the surfactant's absolute solubility or the level of adsorption on rock. An aqueous surfactant preflush can speed the advance of foam, however. An idealized model of a surfactant flood pushed by foam suggests that it is best to inject a relatively high water content into the foam to ensure that the gas front remains behind the surfactant front as the flood proceeds. Any gas that passes ahead of the surfactant front would finger through the oil and be wasted. We present simulations to verify the solutions obtained with fractional-flow methods and illustrate the challenges of accurate simulation of these processes.

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35

Park, S. Y., and D. L. Rhode. "Predicted Geometry Effects on Oil Vapor Flow Through Buffer-Gas Labyrinth Seals." Journal of Engineering for Gas Turbines and Power 125, no. 1 (December 27, 2002): 193–200. http://dx.doi.org/10.1115/1.1520540.

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Mass transport characteristics of buffer-gas labyrinth seals operating in the flooded, nonmist regime were studied using numerical simulations. Discussion is given of the extension, to account for oil vapor mass transport, of a finite volume computer code that was previously validated using nonoil labyrinth hot-film anemometer as well as leakage measurements. A parametric study was conducted to obtain a first understanding of oil vapor transport from the liquid film on the stator wall and to assist oil seal designers. Various geometry effects with various oil film lengths were investigated. It was found in the present investigation that increasing the buffer gas pressure can increase the oil vapor mass flow to the process gas due to increased evaporation from the liquid oil film. In addition, it was found that buffer-gas mass flow is mainly affected by the clearance and the total flow area of the buffer-gas injection.

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36

Roach, G. J., J. S. Watt, H. W. Zastawny, P. E. Hartley, and W. K. Ellis. "TRIALS OF A MULTIPHASE FLOW METER ON PRODUCTION PIPELINES FROM OIL WELLS." APPEA Journal 34, no. 1 (1994): 101. http://dx.doi.org/10.1071/aj93008.

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This paper describes trials of a new multiphase flow meter (MFM) on the Vicksburg offshore production platform and at the oil processing facilities on Thevenard Island. The flow meter is based on two specialised gamma-ray transmission gauges mounted on a pipe carrying the full flow of oil, water and gas.Two MFMs were used in both trials, one mounted on a vertical (up flow), and the other on a horizontal, section of a pipeline linking the test manifold to the test separator. Measurements were made on flows of oil/water/gas mixtures from each well, and on combined flows of different pairs of wells.The r.m.s. difference between the flow rates determined by the MFM and by the separator output meter was determined by least squares regression. For the Vicksburg trial, the ratio of r.m.s. difference and mean flow rate was 8.9 per cent for oil, 5.6 per cent for water, 5.2 per cent for liquids, and 8.2 per cent for gas for flows in the vertical pipeline and slightly larger for flows in the horizontal pipeline. For the Thevenard Island trial, the preliminary results for flows in the vertical pipeline show the ratio to be 6.8 per cent for oil, 6.0 per cent for water, 3.4 per cent for liquids, and 5.9 per cent for water cut.

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37

Zhijun, Jin, Liu Quanyou, Qiu Nansheng, Ding Feng, and Bai Guoping. "Phase States of Hydrocarbons in Chinese Marine Carbonate Strata and Controlling Factors for Their Formation." Energy Exploration & Exploitation 30, no. 5 (October 2012): 753–73. http://dx.doi.org/10.1260/0144-5987.30.5.753.

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Chinese marine strata were mainly deposited before the Mesozoic. In the Tarim, Sichuan and Ordos Basins, the marine source rocks are made of sapropelic dark shale, and calcareous shale, and they contain type II kerogen. Because of different burial and geothermal histories, the three basins exhibit different hydrocarbon generation histories and preservation status. In the Tarim Basin, both oil and gas exist, but the Sichuan and Ordos Basins host mainly gas. The Tarim Basin experienced a high heat flow history in the Early Paleozoic. For instance, heat flow in the Late Cambrian varied between 65–75 mW/m2, but it declined thereafter and averages 43.5mW/m2 in the current time. Thus, the basin is a “warm to cold basin”. The Sichuan Basin experienced an increasing heat flow through the Early Paleozoic to Early Permian, and peaked in the latest Early Permian with heat flows of 71–77 mW/m2. Then, the heat flow declined stepwise to the current value of 53.2 mW/m2. Thus, it is a generally a high heat flow “warm basin”. The Ordos Basin has a low heat flow for most of its history (45–55 mW/m2), but experienced a heating event in the Cretaceous, with the heat flow rising to 70–80 mW/m2. Thus, this basin is a “cold to warm basin”. The Tarim Basin experienced three events of hydrocarbon accumulations. Oil accumulation formed in the late stage of Caledonian Orogeny. The generation and accumulation of oil continued in the Northern and Central Tarim (Tabei and Tazhong) till the late Hercynian Orogeny, during which, the accumulated oil cracked into gas in the Hetianhe area and Eastern Tarim (Tadong). In the Himalaya Orogeny, oil cracking occurred in the entire basin, part of the oil in the Tabei and Tazhong areas and most of the oil in the Hetianhe and Tadong areas are converted into gas. In the Sichuan Basin, another triple-episode generation and accumulation history is exhibited. In the Indosinian Orogeny, oil accumulation formed, but in the Yanshanian Orogeny, part of the oil in the eastern Sichuan Basin and most of the oil in the northeastern part was cracked into gas. In the Himalayan Orogeny, oil in the entire basin was converted into gas. The Ordos Basin experienced a double-episode generation and accumulation history, oil accumulation happened in the early Yanshanian stage, and cracked in the late stage. In general, multiple phases of heat flow history and tectonic reworking caused multiple episodes of hydrocarbon generation, oil to gas cracking, and accumulation and reworking. The phases and compositions of oil and gas are mainly controlled by thermal and burial histories, and hardly influenced by kerogen types and source rock types.

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38

Matsunaga, T., A. Mialdun, K. Nishino, and V. Shevtsova. "Measurements of gas/oil free surface deformation caused by parallel gas flow." Physics of Fluids 24, no. 6 (June 2012): 062101. http://dx.doi.org/10.1063/1.4727908.

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39

Duan, Jimiao, Songsheng Deng, Shuo Xu, Huishu Liu, Ming Chen, and Jing Gong. "The effect of gas flow rate on the wax deposition in oil-gas stratified pipe flow." Journal of Petroleum Science and Engineering 162 (March 2018): 539–47. http://dx.doi.org/10.1016/j.petrol.2017.10.058.

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40

Wu, Haojiang, Fangde Zhou, and Yuyuan Wu. "Intelligent identification system of flow regime of oil–gas–water multiphase flow." International Journal of Multiphase Flow 27, no. 3 (March 2001): 459–75. http://dx.doi.org/10.1016/s0301-9322(00)00022-7.

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41

Zhao, Wang, Zhang, Xie, Liu, and Cao. "Bubble Motion and Interfacial Phenomena during Bubbles Crossing Liquid–Liquid Interfaces." Processes 7, no. 10 (October 10, 2019): 719. http://dx.doi.org/10.3390/pr7100719.

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In metallurgical and chemical engineering processes, the gas–liquid–liquid multiphase flow phenomenon is often encountered. The movement of bubbles in the liquid, and the influence of bubbles on the liquid–liquid interface, have been the focus of extensive research. In the present work, an air–water–oil system was used to explore the movement of bubbles and the phenomenon that occurs when bubbles pass through an interface with various oil viscosities at various gas flow rates. The results show that bubble movement is greatly influenced by the viscosity of the oil at low gas flow rates. The type of phase entrainment and the jet height was changed when increasing the gas flow rate. The stability of the water–oil interface was enhanced with increasing viscosity of the oil phase.

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42

Ismail, Issham, Shahir Misnan, Ahmad Shamsul Izwan Ismail, and Rahmat Mohsin. "Flow Pattern Map of Malaysian Crude Oil and Water Two-Phase Flow in a Pipe System." Advanced Materials Research 931-932 (May 2014): 1243–47. http://dx.doi.org/10.4028/www.scientific.net/amr.931-932.1243.

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Water produced along with the crude oil during production and transported together in a pipeline is a common occurrence in a petroleum production system. Understanding the behavior of crude oil-water flow in a pipe is crucial to engineering applications such as design and operation of flow lines and wells, and separation systems. Presently, there was no two phase flow study done on the Malaysian waxy crude oil-water. Therefore, a research work was conducted at the Malaysia Petroleum Resources Corporation Institute for Oil and Gas, Universiti Teknologi Malaysia to study the flow pattern of the Malaysian waxy crude oil-water flowing in a closed-loop system at the ambient condition through a 5.08 cm ID stainless steel horizontal pipeline. The research works comprised fluid characterization and flow pattern observation using a video camera camcorder. Five flow patterns have been identified, namely stratified wavy flow, stratified wavy with semi dispersed flow at interface and oil film, dispersion of water in oil and oil continuous with emulsion, dispersion of oil in water with water continuous, and the newly found semi dispersed flow with semi emulsion at interface and thin oil film. The experimental results could be used as a platform to understand better a more complex case of gas, oil, and water flow in a pipeline, which is of utmost importance in designing optimum surface facilities.

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43

Spedding, P. L., G. F. Donnelly, and J. S. Cole. "Three Phase Oil-Water-Gas Horizontal Co-Current Flow." Chemical Engineering Research and Design 83, no. 4 (April 2005): 401–11. http://dx.doi.org/10.1205/cherd.02154.

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44

Ersoy, G., C. Sarica, E. Al-Safran, and H. Q. Zhang. "Three-phase gas-oil-water flow in undulating pipeline." Journal of Petroleum Science and Engineering 156 (July 2017): 468–83. http://dx.doi.org/10.1016/j.petrol.2017.06.027.

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45

Li, Yi, Wuqiang Yang, Cheng-gang Xie, Songming Huang, Zhipeng Wu, Dimitrios Tsamakis, and Chris Lenn. "Gas/oil/water flow measurement by electrical capacitance tomography." Measurement Science and Technology 24, no. 7 (June 12, 2013): 074001. http://dx.doi.org/10.1088/0957-0233/24/7/074001.

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46

Lu, Guang-yao, Jing Wang, and Zhi-hai Jia. "Experimental and Numerical Investigations on Horizontal Oil-Gas Flow." Journal of Hydrodynamics 19, no. 6 (December 2007): 683–89. http://dx.doi.org/10.1016/s1001-6058(08)60004-9.

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47

Sergiyenko, S. I. "HEAT FLOW ANOMALIES IN OIL- AND GAS-BEARING STRUCTURES." International Geology Review 30, no. 2 (February 1988): 227–36. http://dx.doi.org/10.1080/00206818809466004.

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48

Cole, P., and P. A. Collins. "Simulation of gas and oil flow in hydrocarbon reservoirs." Quarterly Journal of Engineering Geology and Hydrogeology 19, no. 2 (May 1986): 121–32. http://dx.doi.org/10.1144/gsl.qjeg.1986.019.02.05.

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49

Piela, K., R. Delfos, G. Ooms, J. Westerweel, and R. V. A. Oliemans. "Dispersed oil-water-gas flow through a horizontal pipe." AIChE Journal 55, no. 5 (May 2009): 1090–102. http://dx.doi.org/10.1002/aic.11742.

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50

Al-Hadhrami, Luai M., S. M. Shaahid, Lukman O. Tunde, and A. Al-Sarkhi. "Experimental Study on the Flow Regimes and Pressure Gradients of Air-Oil-Water Three-Phase Flow in Horizontal Pipes." Scientific World Journal 2014 (2014): 1–11. http://dx.doi.org/10.1155/2014/810527.

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An experimental investigation has been carried out to study the flow regimes and pressure gradients of air-oil-water three-phase flows in 2.25 ID horizontal pipe at different flow conditions. The effects of water cuts, liquid and gas velocities on flow patterns and pressure gradients have been studied. The experiments have been conducted at 20°C using low viscosity Safrasol D80 oil, tap water and air. Superficial water and oil velocities were varied from 0.3 m/s to 3 m/s and air velocity varied from 0.29 m/s to 52.5 m/s to cover wide range of flow patterns. The experiments were performed for 10% to 90% water cuts. The flow patterns were observed and recorded using high speed video camera while the pressure drops were measured using pressure transducers and U-tube manometers. The flow patterns show strong dependence on water fraction, gas velocities, and liquid velocities. The observed flow patterns are stratified (smooth and wavy), elongated bubble, slug, dispersed bubble, and annular flow patterns. The pressure gradients have been found to increase with the increase in gas flow rates. Also, for a given superficial gas velocity, the pressure gradients increased with the increase in the superficial liquid velocity. The pressure gradient first increases and then decreases with increasing water cut. In general, phase inversion was observed with increase in the water cut. The experimental results have been compared with the existing unified Model and a good agreement has been noticed.

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