The Effect of Liquid Viscosity in Two-Phase Vertical Flow

Hagedorn, A.R.; Brown, Kermit E.

doi:10.2118/733-pa

Cited by 43 publications

(11 citation statements)

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“…The cross-sectional area to flow used in most common systems analysis computations [4][5][6][7][8] (and the correction of the water velocity above) are based on the hydraulic or effective diameter concept for fluid flow in an annulus. The area for tubular flow in the casing below the end of tubing or in the tubing (A p ) appearing in Eq.…”

Section: Mathematical Modelmentioning

confidence: 99%

Determination of Multilayer Reservoir Inflow Profiles Using Pulsed Neutron Logs

Poe

Butsch

England³

2005

All Days

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper addresses the development and validation of a production logging analysis methodology and associated formation inflow interpretation model for wells that have their production tubing string setting depth below the top of at least the shallowest completed interval in the well. This type of completion technique is commonly utilized in wells that produce formation liquids and in which the tubing is lowered in the well below the top of the shallowest (and possibly additional deeper) completed interval(s) in order to assist in unloading the well of the produced liquids. When this is done, conventional production logging tools and techniques can not be used to measure the inflow profile of the completed intervals that are shallower than the tubing setting depth in the well without raising the tubing above the shallowest completed interval, which can alter the inflow profile of the well.This paper specifically considers the development of a reliable means of performing an equivalent inflow performance analysis, analogous to that which would be obtained with conventional production logging analyses if those inflow profile evaluation techniques could be used in wells with this type of completion. The liquid holdup of the multiphase flow in the well is determined from the Inelastic Ratio measurements of a Pulsed Neutron log and the annular water velocity is directly obtained from the analysis of water flow measurements in the annulus of the well.

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Section: Mathematical Modelmentioning

confidence: 99%

Determination of Multilayer Reservoir Inflow Profiles Using Pulsed Neutron Logs

Poe

Butsch

England³

2005

All Days

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“…Correlations that consider the slip but not the flow patterns. Examples include Gray (1978) and Brown (1964 and1965), etc. 3.…”

Section: Introductionmentioning

confidence: 99%

Development of an expert system for selection of multiphase flow correlations

El-Moniem

El-Banbi

2018

J Petrol Explor Prod Technol

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Our target was to develop an expert system to help petroleum engineers in selecting the most suitable multiphase flow correlation in the absence of measured flowing pressure. A large database of pressure points was collected and analyzed using many multiphase flow correlations. The expert system was developed with a set of rules to identify the best correlation for variety of well, flow, and PVT conditions. The expert system is based on the idea of clustering the data and finding the best multiphase flow correlation(s) for each cluster. The error associated with the selected correlation is also quantified for every correlation in each data sub-cluster so the engineer would expect the accuracy of pressure drop prediction when utilizing this approach. Over the entire database, if one multiphase flow correlation is selected, the overall mean absolute percent error ranges between 12.7 and 57.5%, while the range of errors for best correlation(s) in different data sub-clusters range from 0.01 to 3% for most cases with accurate PVT. The expert system was validated by a new set of data. It succeeded in identifying the best correlation(s) 70% of the times, and the calculated pressure was more accurate than using one correlation by a factor of 2. Use of the expert system in the validation database gave a mean absolute percent error of 8.8%. This represents approximately one-third of the error value when any single correlation is used over the entire validation dataset. (Error for using single correlation ranges from more than 21 to 29%.) Keywords

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“…Using data primarily from Hagedorn and Brown [3], Orkiszewski correlated T with superficial mixture velocity v m , liquid viscosity \i L , and pipe diameter d. For oil as the continuous liquid phase, T is determined from equation (1) if v m < 10 ft/sec and from equation (2) discontinuities between flow patterns. The purpose of this work is to examine the discontinuities inherent in the Orkiszewski liquid distribution coefficient equations, and suggest alternative equations that eliminate the discontinuities.…”

Section: Introductionmentioning

confidence: 99%

Discontinuities in the Orkiszewski Correlation for Predicting Pressure Gradients in Wells

Brill

1989

Journal of Energy Resources Technology

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The Orkiszewski correlation is used extensively in the petroleum industry for predicting pressure gradients when gas and liquid flow simultaneously in wells. Unfortunately,, the correlation contains a parameter called the liquid distribution coefficient, T, that can be discontinuous at a superficial mixture velocity of 10 ft/sec. The liquid distribution coefficient is used to predict both the elevation and friction components of the pressure gradient for slug flow. The accepted trial and error method for integrating the pressure gradient to obtain pressure loss in wells can fail to converge when pressure gradients are discontinuous. Examples of discontinuities in T for oil as the continuous phase are presented for several liquid viscosities ranging from 0.3 to 200 cp and for pipe diameters of 1.049, 2.441 and 6.049 in. It was found that a constraint recommended for T when mixture velocity < 10 ft/sec was essentially useless. It was also found that a constraint for velocities > 10 ft/sec could actually increase the magnitude of pressure gradient discontinuity. Convergence of pressure loss calculations when the discontinuity was encountered was possible only if the convergence tolerance was temporarily relaxed. IntroductionThe Orkiszewski method [1] for prediction of two-phase pressure gradients in vertical pipe is primarily a modification of the Griffith and Wallis correlation [2] for the slug flow region. The modification was to develop a liquid distribution coefficient, T, to account for the distribution of the liquid in the slugs, in the films around the gas bubbles, and as entrained droplets in the gas bubbles. Orkiszewski applied the liquid distribution coefficient to the equation for mixture density proposed by Griffith and Wallis and also used it in a new equation for friction pressure gradient. This work supposedly extended the Griffith and Wallis correlation into the high velocity range of slug flow and resulted in more accurate predictions of friction loss and mixture density.Using data primarily from Hagedorn and Brown [3], Orkiszewski correlated T with superficial mixture velocity v m , liquid viscosity \i L , and pipe diameter d. For oil as the continuous liquid phase, T is determined from equation (1) if v m < 10 ft/sec and from equation (2) if v m > 10 ft/sec. Similar equations were developed for the case

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The Effect of Liquid Viscosity in Two-Phase Vertical Flow

Cited by 43 publications

References 0 publications

Determination of Multilayer Reservoir Inflow Profiles Using Pulsed Neutron Logs

Determination of Multilayer Reservoir Inflow Profiles Using Pulsed Neutron Logs

Development of an expert system for selection of multiphase flow correlations

Discontinuities in the Orkiszewski Correlation for Predicting Pressure Gradients in Wells

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