Practical Considerations in the Analysis of Gas-Condensate Well Tests

1999 ◽  
Vol 2 (03) ◽  
pp. 288-295 ◽  
Author(s):  
R. Raghavan ◽  
Wei Chun Chu ◽  
J.R. Jones
Keyword(s):  
Multiphase Flow ◽  
Gas Phase ◽  
Relative Permeability ◽  
Single Phase ◽  
Gas Condensate ◽  
Dew Point ◽  
Pressure Measurements ◽  
Two Phase ◽  
Molar Density ◽  
Condensate System

Summary Several pressure buildup tests are analyzed with a view to evaluate the potential of the ideas given in the literature. A broad range of tests is examined to demonstrate the characteristics of responses in wells producing below the dew point. Methods to obtain quantitative information that is consistent for different tests are outlined. The specific contributions of this article are as follows. First, in this article we examine field data, second, we look at multiple rates, third, we examine unfractured and fractured wells, fourth, we look at wells that have been produced for a short time and those produced for a long time, fifth, we consider both depletion-type and cycling scenarios, and, sixth we tie pressure data to relative permeability and PVT data. Many of these issues are addressed for the first time. Introduction Because of the extraordinary success of the diffusivity equation in enabling us to analyze pressure measurements and the conveniences derived there from, the analysis of pressure responses subject to the influences of multiphase flow is, at best, provided as only a perfunctory treatment in the literature. Single-phase flow is the paradigm in this area of reservoir engineering. The reluctance in shifting from this paradigm may be partially attributed to the perception that relative-permeability measurements are not reliable enough for us to analyze the rapid changes in pressure that occur over a very short period of time. The other principal reason is that a simple method needs to be devised to relate the relative permeability to pressure, although studies have suggested procedures to address this issue.1,2 In this article we provide information for those interested in using multiphase-flow concepts for analyzing pressure-buildup tests in wells producing gas-condensate reservoirs. This class of tests was chosen for a number of reasons besides the fact that the gas-condensate system provides an opportunity to combine both single-phase and two-phase flow concepts. Since we consider multiphase flow under multiple-rate conditions, there are very few theoretical ideas to guide us. The simulations of Jones et al.2,3 provide us with a starting point. These works merely examine a single buildup following a single drawdown with the well flowing at a constant rate or a constant pressure. Since no theoretical evaluations of multirate tests are available, we have conducted a number of simulations using a compositional model to ensure that the explanations we provide are plausible. We do not concentrate on the synthetic situations, however, because the same information may be conveyed by the field-case illustrations. In the following, we examine five tests to demonstrate important features of buildup responses in gas-condensate reservoirs. Four of these tests are in "depletion" systems and the fifth one discusses buildup tests in a pressure-maintenance project. Background The depletion tests we consider presume that the results of a constant-composition-expansion (CCE) test on a representative sample are available. An equation of state, tuned to this sample, provides information on molar density and viscosity. In addition, we assume that appropriate relative-permeability measurements are available. Using this information, we proceed to analyze buildup tests using the concepts suggested by Jones, Vo, and Raghavan.3 The buildup tests for the pressure-maintenance system are evaluated using the single-phase analog because information on the in-situ composition (pressure-maintenance project) is unavailable to us. These tests are analyzed by the composite-reservoir formulation.4Figs. 1 and 2 present the pertinent CCE and relative-permeability information used in this work. We consider a wide range of mixtures with the maximum liquid dropout in the range of 0.07 to 0.35. Mixtures 1, 2, and 3 are for depletion experiments, and mix 4 applies to the test for the well in the pressure-maintenance project. Justification for the use of relative-permeability curves is based on the fact that these curves are also used in matching performance and making production forecasts. As expected, the relative permeability to oil is negligibly small until the liquid saturation becomes quite large. Table 1 presents properties that are needed to analyze the buildup tests. Our primary focus in all of the following is to obtain a consistent interpretation of multiple buildup tests after the wellbore pressure has fallen below the dew-point pressure. Theoretical Considerations We use single-phase and two-phase analogs to analyze pressure measurements. Our focus will be the interpretation of buildup measurements. The single-phase analog given by $$m(p)={\int {p {wf, s}}^{p {ws}}}\,{\rho {g}\over \mu {{\rm g}}}\,{\rm d}p,\eqno ({\rm 1})$$ is essentially identical to the analog commonly used for dry-gas systems. Here, ? is the molar density, ? is the viscosity, pwf, s is the pressure at the time of shut-in, pws is the shut-in pressure, and the subscript g refers to the gas phase. This analog takes advantage of the unique character of the condensate system, namely that, under normal circumstances, the condensate is immobile over substantial portions of the reservoir. Thus, if the variation in the relative permeability for the gas phase is negligibly small over the region where liquid is immobile, then this analog should be useful whenever this region of the reservoir begins to influence the well response. (In all of the following, we assume that water is immobile.)

Flow Structures and Frictional Characteristics on Two-Phase Flow in Microchannels in PEM Fuel Cells

2005 ◽  
Author(s):  
Eon Soo Lee ◽  
Carlos H. Hidrovo ◽  
Julie E. Steinbrenner ◽  
Fu-Min Wang ◽  
Sebastien Vigneron ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Gas Phase ◽  
Single Phase ◽  
Film Flow ◽  
Two Phase Flow ◽  
Water Injection ◽  
Injection Rate ◽  
Flow Structures ◽  
Phase Flow ◽  
Two Phase

This experimental paper presents a study of gas-liquid two phase flow in rectangular channels of 500μm × 45μm and 23.7mm long with different wall conditions of hydrophilic and hydrophobic surface, in order to investigate the flow structures and the corresponding friction factors of simulated microchannels of PEMFC. The main flow in the channel is air and liquid water is injected at a single or several discrete locations in one side wall of the channel. The flow structure of liquid water in hydrophilic wall conditioned channel starts from wavy flow, develops to stable stratified film flow, and then transits to unstable fluctuating film flow, as the pressure drop and the flow velocity of air increase from around 10 kPa to over 100 kPa. The flow structure in hydrophobic channel develops from the slug flow to slug-and-film flow with increasing pressure drop and flow velocity. The pressure drop for single phase flow is measured for a base line study, and the fRe product is in close agreement with the theoretical value (fRe = 85) of the conventional laminar flow of aspect ratio 1:11. At the low range of water injection rate, the gas phase fRe product of the two phase flow based on the whole channel area was not substantially affected by the water introduction. However, as the water injection rate increases up to 100 μL/min, the gas phase fRe product based on the whole channel area deviates highly from the single phase theoretical value. The gas phase fRe product with the actual gas phase area corrected by the liquid phase film thickness agrees with the single phase theoretical value.

Experimental Determination of Relative Permeabilities for a Rich Gas/Condensate System Using Live Fluid

2009 ◽  
Vol 12 (02) ◽  
pp. 263-269 ◽  
Author(s):  
Jeffrey F. App ◽  
Jon E. Burger
Keyword(s):  
Steady State ◽  
Capillary Number ◽  
Single Phase ◽  
Gas Condensate ◽  
Relative Permeabilities ◽  
State Process ◽  
Reservoir Fluid ◽  
Condensate System ◽  
The Impact ◽  
Model Fluids

Summary Measurement of gas and condensate relative permeabilities typically is performed through steady-state linear coreflood experiments using model fluids. This study addresses experimental measurement of relative permeabilities for a rich-gas/condensate reservoir using a live, single-phase reservoir fluid. Using a live, single-phase reservoir fluid eliminates the difficulties in designing a relatively simple model fluid that replicates the complicated thermodynamic and transport properties of a near-critical fluid. Two-phase-flow tests were performed across a range of pressures and flow rates to simulate reservoir conditions from initial production through depletion. A single-phase multirate experiment was also performed to assess inertial, or non-Darcy, effects. Correlations were developed to represent both the gas and condensate relative permeabilities as a function of capillary number. A nearly 20-fold increase in gas relative permeability was observed from the low- to high-capillary-number flow regime. Compositional simulations were performed to assess the impact of the experimental results for vertical- and horizontal-well geometries. Introduction Well-deliverability estimates for gas/condensate systems require accurate prediction of both gas and condensate effective permeability. This is particularly important within the near-wellbore region where the pressures often fall below dewpoint causing retrograde condensation. Within this region, pressure gradients in both flowing phases are large and the interfacial tension between the gas and condensate is low. This results in relative permeabilities that are rate sensitive. Under these conditions, both capillary number and non-Darcy effects must be considered in modeling of gas/condensate flows. The relative permeabilities increase with increasing capillary number and are reduced by inertial, or non-Darcy, flow effects. Gas and condensate relative permeabilities are typically determined by steady-state linear coreflood experiments. Numerous experimental studies have been performed demonstrating an improvement in both gas and condensate relative permeability at high velocities and at low interfacial tension (Henderson et al. 1998; Henderson et al. 1997; Ali et al. 1997). These studies used model fluids to represent the reservoir fluid, which generally represented leaner gas/condensate systems. Chen et al. (1995) performed similar experiments using a recombined gas/condensate system from a North Sea field. Proper recombination with surface gas and condensate samples, however, assumes that the correct condensate/gas ratio is known. Using single-phase downhole samples obtained at pressures above the dewpoint eliminates this uncertainty. Fevang and Whitson (1996) have shown that krg for a steady state process is a function of the krg/kro ratio, where the krg/kro ratio is a function of pressure. The dependency of krg on both the capillary number (Nc) and the krg/kro ratio for a pseudosteady-state process has been demonstrated experimentally by Whitson et al. (1999) and Mott et al. (1999). These studies used either model fluids or recombined reservoir fluids with krg/kro ratios primarily within the range of 1 to 90. The lower krg/kro ratios represent richer fluids, while the higher krg/kro ratios represent leaner fluids. The fluids studied in this paper, however, are significantly richer, with krg/kro ratios in the range of 0.05 to 0.15 on the basis of fluid compositions at initial reservoir conditions. Non-Darcy or inertial effects reduce relative permeabilities. This has been demonstrated through linear coreflood experiments by several investigators (Lombard et al. 2000; Henderson et al. 2000; Mott et al. 2000). Multirate non-Darcy single-phase experiments were performed as part of this study because of the anticipated high flow rates from this reservoir. The objectives of this study were (1) to experimentally measure gas and condensate relative permeabilities for a rich gas/condensate system using a live, single-phase reservoir fluid; (2) assess the magnitude of inertial effects through the measurement of the non-Darcy coefficient; and (3) evaluate the impact of the capillary-number-dependent relative permeabilities and non-Darcy effects on the performance of vertical and horizontal wells.

Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method

1998 ◽  
Vol 1 (02) ◽  
pp. 134-140 ◽  
Author(s):  
G.D. Henderson ◽  
A. Danesh ◽  
D.H. Tehrani ◽  
S. Al-Shaidi ◽  
J.M. Peden
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Flow Rate ◽  
Rate Effect ◽  
Gas Condensate ◽  
Dew Point ◽  
Gas Condensate Reservoirs ◽  
Steady State Method ◽  
Wide Range ◽  
Permeability Rate

Abstract High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate to gas ratio's (CGR), with the velocity and interfacial tension (IFT) being varied between tests in order to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements was also investigated, as was the repeatability of the data. A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative permeability rate effect was still evident as the IFT increased by an order of magnitude, with the relative permeability of the gas phase reducing more than the condensate phase. The influence of end effects was shown to be negligible at the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so called laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability should decrease with increasing flow rate. A generalised correlation between relative permeability, velocity and IFT has been proposed, which should be more appropriate for condensing fluids than the conventional correlation. The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs. This study will be particularly applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity. The findings provide previously unreported data on relative permeability and recovery of gas condensate fluids at realistic conditions. Introduction During the production of gas condensate reservoirs, the reservoir pressure will be gradually reduced to below the dew-point, giving rise to retrograde condensation. In the vicinity of producing wells where the rate of pressure reduction is greatest, the increase in the condensate saturation from zero is accompanied by a reduction in relative permeability of gas, due to the loss of pore space available to gas flow. It is the perceived effect of this local condensate accumulation on the near wellbore gas and condensate mobility that is one of the main areas of interest for reservoir engineers. The availability of accurate relative permeability data applicable to flow in the wellbore region impacts the management of gas condensate reservoirs.

scholarly journals PREDICTION OF CONDENSATE BANKING WITH RELATIVE PERMEABILITY TO OIL – GAS AND SATURATION IN A GAS CONDENSATE RESERVOIR

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Relative Permeability ◽  
Comparative Method ◽  
Economic Value ◽  
Gas Condensate ◽  
Dew Point ◽  
Efficient Production ◽  
Retrograde Condensation ◽  
Condensate Reservoir ◽  
Compositional Simulator ◽  
Point Pressure

Gas condensate fields are quite lucrative fields because of the highly economic value of condensates. However, the development of these fields is often difficult due to retrograde condensation resulting to condensate banking in the immediate vicinity of the wellbore. In many cases, adequate characterization and prediction of condensate banks are often difficult leading to poor technical decisions in the management of such fields. This study will present a simulation performed with Eclipse300 compositional simulator on a gas condensate reservoir with three case study wells- a gas injector (INJ1) and two producers (PROD1 and PROD2) to predict condensate banking. Rock and fluid properties at laboratory condition were simulated to reservoir conditions and a comparative method of analysis was used to efficiently diagnose the presence of condensate banks in the affected grid-blocks. Relative Permeability to Condensate and gas and saturation curves shows condensate banks region. The result shows that PROD2 was greatly affected by condensate banking while PROD1 remained unaffected during the investigation. Other factors were analyzed and the results reveal that the nature and composition of condensates can significantly affect condensate banking in the immediate vicinity of the wellbore. Also, it was observed that efficient production from condensate reservoir requires the pressure to be kept above dew point pressure so as to minimize the effect and the tendency of retrograde condensation. Keywords: Condensate Banking, Phase Production, Relative Permeability, Relative Saturation, Retrograde Condensation

Studying the impact of carbon dioxide on phase transitions of gas-condensate systems and dispersion of retrograde condensate

2021 ◽  
pp. 17-22
Author(s):  
N.N. Hamidov ◽  
◽  
◽  
Keyword(s):  
Carbon Dioxide ◽  
Phase Transitions ◽  
Gas Phase ◽  
Development Process ◽  
Gas Condensate ◽  
Critical Parameters ◽  
Physico Chemical ◽  
Retrograde Condensation ◽  
Condensate System ◽  
The Impact

The paper studies the effect of carbon dioxide on the phase transitions within gas-condensate systems and defines its role on the evaporation of retrograde condensate isolated in formation due to the decreasing pressure during development process. Based on the experiments carried out by special methodology in рVT bomb, the essence of various impact of carbon dioxide amount in the content of gas-condensate mixture on the physico-chemical and thermo-dynamic parameters of the system depending on the temperature interval revealed. As a result of experiments, it was defined that the increase of carbon dioxide within gas-condensate mixture raises the content of dispersed condensate in gas phase. Moreover, the increase of CO2 in gas phase leads to the growth of gas amount dissolved in a unit volume of condensate as well. It is shown that the effect of carbon dioxide on the pressure of retrograde condensation within gas-condensate system cannot be definitely estimated. The pressure of retrograde condensation within such mixtures may be different in various temperature diapasons due to the change of the features and critical parameters of the system.

Parameters for Computing Pressure Gradients and the Equilibrium Saturation of Gas-Condensate Fluids Flowing in Sandstones

1974 ◽  
Vol 14 (03) ◽  
pp. 203-215 ◽  
Author(s):  
Jerry D. Ham ◽  
James P. Brill ◽  
C. Kenneth Eilerts
Keyword(s):  
Turbulent Flow ◽  
Pressure Gradient ◽  
Gas Phase ◽  
Gas Condensate ◽  
Darcy Flow ◽  
Pressure Gradients ◽  
Two Phase ◽  
Darcy Equation ◽  
Liquid Saturation ◽  
Gas Ratio

Abstract Data obtained by flowing two-phase fluids through sandstone cores were used to develop empirical equations for computing the pressure gradients and liquid saturations that will occur during the recovery of gas-condensate fluids like those in the Gulf Coast area. Equilibrium saturation may be computed for a given pressure, velocity, and liquid/gas ratio of flow. For this purpose, the minimum liquid flow saturation at high pressures, S, was developed for characterizing a core and a fluid. The effects of saturation on the mobility for Darcy flow and on the coefficient for non-Darcy flow are considered in an equation with parameters in addition to the Klinkenberg and Forchheimer coefficients. All parameters for these equations may be determined parameters for these equations may be determined either by routine measurements or by correlations. Introduction Fluid properties required for computing the transient flow of gas-condensate fluids and data obtained to meet this need were discussed at the 1966 SPE-AIME Fall Meeting. In the following year Dranchuk and Kolada described a means of analyzing laboratory data for nonlinear parameters pertaining to flow of gases. Gewers and Nichol pertaining to flow of gases. Gewers and Nichol investigated the effect of liquid saturation on the non-Darcy-flow term of the pressure-gradient equation. Modine and Fields used this kind of information to simulate turbulent flow in gas wells. An equation is needed for computing a more realistic value of the pressure gradient for flowing two-phase fluids than is possible with the Darcy equation. An equation is needed to compute as a boundary condition the liquid saturation possible in the porous medium near flowing wells. This paper describes two such equations that give effect paper describes two such equations that give effect to pressure, fluid velocity, liquid/gas ratio, and saturation. Seven parameters each required for the pressure-gradient and saturation equations may be pressure-gradient and saturation equations may be calculated by means of correlation equations that utilize routinely measured core properties. Concepts and Equations The Darcy equation was modified to include the Klindenberg effect "slip flow" and the Forchheimer coefficient to represent "inertial" or "turbulent" flow of gases in dry porous media,(1) By controlling the velocity (u) and pressure (p), measuring the gradient (dp/dx) and the viscosity [mu(p)], and calculating the density [p(p)], the properties k, b, and beta were determined for properties k, b, and beta were determined for representative cores by least-squares methods. As a step in the modification of Eq. 1 to obtain an equation applicable to the flow of two-phase fluids, mobility, A, for a two-phase fluid must replace the ratio of a known permeability to a viscosity, for the gas phase(2) The quantities k and mu(p) are to have the same* significance as in Eq. 1, except that mu(p) is the viscosity of a single-phase saturated gas. Relationships of liquid- and gas-phase mobilities, lambda and lambda, to fluid mobility, lambda, have been described in Appendix C of a previous publication. Briefly, lambda = lambda + lambda = f(S, p, F, u) k/mu(p). Now mu(p) is the viscosity of the flowing fluid mu under steady-state conditions only when F = 0.

A Two-Phase Flow Model for Reserves Estimation in Tight-Oil and Gas-Condensate Reservoirs Using Scaling Principles

2021 ◽  
pp. 1-18
Author(s):  
L. M. Ruiz Maraggi ◽  
L. W. Lake ◽  
M. P. Walsh
Keyword(s):  
Gas Flow ◽  
Single Phase ◽  
Oil And Gas ◽  
Two Phase Flow ◽  
Gas Condensate ◽  
Tight Oil ◽  
Phase Flow ◽  
Reservoir Pressure ◽  
Single Phase Flow ◽  
Two Phase

Summary A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multiphase flow, which exist once the reservoir pressure falls below the bubble/dewpoint. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. In addition, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight-oil wells in the Wolfcamp Formation of west Texas. First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudopressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells. The results of this research are the following: First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors (URFs) for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the pressure/volume/temperature (PVT) properties, which shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two-phase and single-phase solutions under boundary-dominated flow (BDF) conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells because they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubblepoint. Finally, the application of the two-phase model provides a better fit when compared with the single-phasesolution. The present model requires very little computation time to forecast production because it only uses two fitting parameters. It provides more realistic estimates of URFs and EURs, when compared with single-phase flow solutions, because it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight-oil and gas condensate wells.

Gas Phase Distribution Effects on Heat Transfer in Upward Vertical Bubbly Channel Flows

2016 ◽  
Author(s):  
Haden Hinkle ◽  
Deify Law
Keyword(s):  
Heat Transfer ◽  
Gas Phase ◽  
Bubble Size ◽  
Single Phase ◽  
Volume Fraction ◽  
Phase Distribution ◽  
Vertical Channel ◽  
Channel Flows ◽  
Two Phase ◽  
Ansys Fluent

Two-phase (non-boiling) flows have been shown to increase heat transfer in channel flows as compared with single-phase flows. The present work explores the effects of gas phase distribution such as volume fraction and bubble size on the heat transfer in upward vertical channel flows. A two-dimensional (2D) channel flow of 10 cm wide by 100 cm high is studied numerically. Numerical simulations are performed using the commercial computational fluid dynamics (CFD) code ANSYS FLUENT. The bubble size is characterized by the Eötvös number. The volume fraction and the Eötvö number are varied parametrically to investigate their effects on Nusselt number of the two-phase flows. All simulations are compared with a single-phase flow condition.

scholarly journals 3D simulation of gas-laden liquid flows in centrifugal pumps and the assessment of two-fluid CFD methods

2020 ◽  
Vol 3 (3) ◽  
pp. 186-207 ◽  
Author(s):  
Markus Hundshagen ◽  
Michael Mansour ◽  
Dominique Thévenin ◽  
Romuald Skoda
Keyword(s):  
Gas Phase ◽  
Spatial Resolution ◽  
Single Phase ◽  
High Spatial Resolution ◽  
Fluid Model ◽  
Phase Flow ◽  
Two Phase ◽  
Two Fluid Model ◽  
Liquid Flows ◽  
Two Fluid

Abstract An assessment of a two-fluid model assuming a continuous liquid and a dispersed gas phase for 3D computational fluid dynamics (CFD) simulations of gas/liquid flow in a centrifugal research pump is performed. A monodisperse two-fluid model, in conjunction with a statistical eddy-viscosity turbulence model, is utilized. By a comprehensive measurement database, a thorough assessment of model inaccuracies is enabled. The results on a horizontal diffuser flow reveal that the turbulence model is one main limitation of simulation accuracy for gas/liquid flows. Regarding pump flows, distinctions of single-phase and two-phase flow in a closed and semi-open impeller are figured out. Even single-phase flow simulations reveal challenging requirements on a high spatial resolution, e.g., of the rounded blade trailing edge and the tip clearance gap flow. In two-phase pump operation, gas accumulations lead to coherent gas pockets that are predicted partly at wrong locations within the blade channel. At best, a qualitative prediction of gas accumulations and the head drop towards increasing inlet gas volume fractions (IGVF) can be obtained. One main limitation of two-fluid methods for pump flow is figured out in terms of the violation of the dilute, disperse phase assumption due to locally high disperse phase loading within coherent gas accumulations. In these circumstances, bubble population models do not appear beneficial compared to a monodisperse bubble distribution. Volume-of-Fluid (VOF) methods may be utilized to capture the phase interface at large accumulated gas cavities, requiring a high spatial resolution. Thus, a hybrid model, i.e., a dispersed phase two-fluid model including polydispersity for flow regions with a dilute gas phase, should be combined with an interphase capturing model, e.g., in terms of VOF. This hybrid model, together with scale-resolving turbulence models, seems to be indispensable for a quantitative two-phase pump performance prediction.

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