High-Viscosity Oil-Gas Flow in Vertical Pipe

Akhiyarov, Denis; Zhang, Hongquan; Sarica, Cem

doi:10.2523/20617-ms

Cited by 4 publications

(6 citation statements)

References 20 publications

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“…At low gas flow rate, liquid film falls downward and is picked up by the upcoming slug. This phenomenon is the reason that causes positive frictional pressure gradient, which is against ordinary expectation but is confirmed in the current experiments and previous Akhiyarov et al (2010) experimental study.…”

Section: Fig 7: Horizontal Stratified Gas-liquid Flow With Oil In Wasupporting

confidence: 82%

“…This system was previously used by Vuong (2009), Akhiyarov (2010 and Sridhar (2011). This facility consists of three main systemsoil, water and gas systems, and three auxiliary systems -instrumentation air, glycol temperature control and data acquisition systems.…”

Section: Multiphase Flow Loopmentioning

confidence: 99%

“…Vertical oil/gas two-phase flow data were collected by Akhiyarov (2010) for his Masters' study using the same flow loop, with the same fluids and similar test conditions. Horizontal oil/gas two-phase data were acquired in the current study.…”

Section: Comparison With Two-phase Flowmentioning

confidence: 99%

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Experimental Study of High-Viscosity Oil/Water/Gas Three-Phase Flow in Horizontal and Upward Vertical Pipes

et al. 2012

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The objective of this project is to measure and observe high-viscosity oil/water/gas three-phase flows in horizontal and upward vertical pipes, and compare the experimental results with existing models to identify the gaps. In this study, oil with viscosities between 0.15 and 0.57 Pa·s (150 and 570 cP) corresponding to temperatures from 37.8 to 15.6 °C (100 to 60 °F), filtered tap water and natural gas at 2.59 MPa (375 psig) pressure are used as the three phases. Superficial oil and water velocities range from 0.1 to 1.0 m/s and superficial gas velocity varies from 1.0 to 5.0 m/s. The internal diameter of the pipe is 5.25-cm (2.067 in). The experimental measurements include pressure gradient and liquid holdup. The flow pattern and slug characteristics are observed and the images are recorded with a high speed video camera system through a high pressure sapphire window. The experimental results are compared with the predictions of Zhang and Sarica (2006) unified model, and the discrepancies are identified.

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Section: Fig 7: Horizontal Stratified Gas-liquid Flow With Oil In Wasupporting

confidence: 82%

Section: Multiphase Flow Loopmentioning

confidence: 99%

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Experimental Study of High-Viscosity Oil/Water/Gas Three-Phase Flow in Horizontal and Upward Vertical Pipes

et al. 2012

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“…We did not include in this study the limited number of reports for downward concurrent gas-liquid flows in vertical pipes (Barnea et al, 1982;Julia et al, 2013;Kim et al, 2004) because conditions that draw gas bubbles or slugs down with liquid flows are less common in industrial applications than upward flow conditions. Although most of the co-current upward flow studies used air with water, eight studies report co-current experiments in vertical pipes with hydrocarbon liquids or glycerol-water solutions (Akhiyarov et al, 2010;Alruhaimani, 2015;Da Hlaing et al, 2007;Furukawa & Fukano, 2001;Oddie et al, 2003;Omebere-Iyari et al, 2007;Schmidt et al, 2008;Szalinski et al, 2010). Three studies report experiments with nitrogen gas instead of air (Oddie et al, 2003;Omebere-Iyari et al, 2007;Schmidt et al, 2008).…”

Section: Co-current Upward Flow In Vertical Pipesmentioning

confidence: 99%

“…In another study Schmidt et al(2008) investigated the effect of liquid viscosity on upward vertical gas-liquid flows in a tube with 54.5 mm inner diameter and mixtures of nitrogen and solutions of polyvinylpyrrolidone in water with dynamic viscosities in the range of 900-7000 mPa s. They observed a decrease in the gas holdup with increasing the liquid viscosity from 1 to 480 mPa s. They also compared the flow map for liquid viscosity of 1600 mPa s with the air-water flow map of and concluded that the transition to annular regime occurred at lower gas superficial velocities in the viscous liquid. Akhiyarov et al (2010) conducted experiments on gas-oil flows in vertical pipes with internal diameter of 52.5 mm and oil viscosities of 100-500 mPa s to assess the performance of the available mechanistic models to predict the pressure gradient and liquid holdup. No comparison was reported on the effect of liquid viscosity on the liquid holdup and flow regimes.…”

Section: Effect Of Pipe Deviationmentioning

confidence: 99%

The experimental study of counter-current two-phase flows in annuli

Wu¹

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Counter-current two-phase gas-liquid flows in annuli occur in many industrial applications, including coal seam gas (CSG) production. In CSG wells, gas is typically produced through counter-current gas-water flow in an annulus. Yet, the models used by CSG companies were designed for conventional wells, wherein co-current upward gas-liquid flow occurs in pipes. Accurately predicting the ensuing flow regimes and counter-current flow limitation (CCFL) is important because they are intrinsically linked to flow characteristics, and dictate operating conditions. The CCFL describes the onset of co-current upward or downward flow due to high gas (gas flooding) or liquid (liquid flooding) rates, respectively. There are currently no experimental publications on counter-current gas-liquid flow regimes in annuli, prohibiting predictive models from being validated. I collated 3,947 flow regime results from 35 experimental studies of counter-current flows in pipes and co-current flows in pipes and annuli, and confirmed that flow configuration, channel geometry, and fluid properties can significantly influence flow regimes (Chapter 2). This thesis aims to experimentally characterise flow regimes and the CCFL during counter-current two-phase flows in an annulus. These findings will allow predictive models of counter-current flow regimes in annuli to be validated.To study counter-current flow regimes in an annulus (Chapter 3), I designed and built an experimental apparatus using acrylic pipes with annulus diameters of 170 mm and 70 mm (170/70 annulus). Flow regimes and the CCFL were documented for air-water at standard conditions using combinations of superficial gas velocities within 0.014-5.794 m/s and superficial liquid velocities within 0.004-0.240 m/s. Differential pressure data were recorded over 1 m and used to infer void fractions, and to quantitatively assess the flows using fast Fourier transform (FFT). High-speed video images were captured at 4,000 frames/s. An apparatus with annulus diameters of 44 mm and 19 mm was also assembled to investigate the impact of annulus size.My observations confirm the 170/70 annulus is a large annulus in which stable slug flow regime cannot develop due to Rayleigh-Taylor instability. Subsequently, the flow regimes in this system are described as homogeneous and heterogeneous instead of bubble and slug-churn regimes.Churn-annular flow was observed, but, the CCFL was reached before a fully annular regime could develop. Existing empirical correlations for the CCFL only considered gas flooding and performed poorly when assessed against my experimental results. So, I developed an empirical correlation for the CCFL that also incorporated liquid flooding. Liquid flooding was detected using a novel experimental technique developed in Chapter 5. Essentially, a water barrel beneath the annulus, used for water re-circulation, was dual-purposed as a vertical separator. The proposed correlation for CCFL ii in an annulus is * 1/2 + 1.7 * 1/2 = 0.56, where * and * are the dimensionless gas and liquid s...

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Study on the Pressure Drop Variation and Prediction Model of Heavy Oil Gas-Liquid Two-Phase Flow

Shi¹,

Li²,

Yang³

et al. 2021

Geofluids

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To explore the pressure drop variation with the viscosity of heavy oil gas-liquid two-phase flow, experiments with different viscosity gas-liquid two-phase flows are carried out. The experimental results show that the total pressure drop increases with increasing liquid viscosity when the superficial gas and liquid flow rates are the same. The liquid superficial velocity is 0.52 m/s, and the superficial gas velocity is 12 m/s in the vertical and inclined pipes, as there is a negative friction pressure drop when the superficial gas and liquid velocities are small. Additionally, the increased range of the total pressure drop decreases with increasing liquid viscosity. Considering the heavy oil gas-liquid two-phase flow, a prediction model of the pressure drop in high-viscosity liquid-gas two-phase flow is established. The new model is verified by experimental data and compared with existing models. The new model has the smallest error, basically within 15%. Based on the prediction of the wellbore pressure distribution of four wells in the BeiA oilfield, the new model prediction results are closer to the measured results, and the error is the smallest. The new model can be used to predict pressure drops in high-viscosity gas-liquid two-phase flow.

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High-Viscosity Oil-Gas Flow in Vertical Pipe

Cited by 4 publications

References 20 publications

Experimental Study of High-Viscosity Oil/Water/Gas Three-Phase Flow in Horizontal and Upward Vertical Pipes

Experimental Study of High-Viscosity Oil/Water/Gas Three-Phase Flow in Horizontal and Upward Vertical Pipes

The experimental study of counter-current two-phase flows in annuli

Study on the Pressure Drop Variation and Prediction Model of Heavy Oil Gas-Liquid Two-Phase Flow

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