# Flow regime calculator

Flow Regime maps are useful tools for getting an overview over which flow regimes we can expect for a particular set of input data.

In horizontal wells, there may be stratified or wavy stratified flow in addition to many of the regimes observed in vertical wells. Two-phase flow regimes have often been presented as plots, or maps, with the phase velocities or functions of them on each axis.

The gas phase is distributed in the liquid phase as variable-size, deformable bubbles moving upward with zigzag motions. The wall of the pipe is always contacted by the liquid phase. Most of the gas is in the form of large bullet-shaped bubbles that have a diameter almost reaching the pipe diameter. The gas bubbles velocity is greater than that of the liquid. If a change from a continuous liquid phase to a continuous gas phase occurs, the continuity of the liquid in the slug between successive Taylor bubbles is destroyed repeatedly by a high local gas concentration in the slug.

This flow regime may not occur in small-diameter pipes. During annular, the liquid phase flows regularly as an annular film on the wall with gas flowing as a central core. Some of this liquid is entrained as droplets in this gas core mist flow. The following video demonstrates common liquid-air flow regimes that can be established in pipes at various liquid and air flow rates and various angles of pipe inclination:. Your email address will not be published.

Bookmark the permalink. Leave a Reply Cancel reply Your email address will not be published. Follow us on Facebook :.The primary purpose of a multiphase flow correlations is to predict the liquid holdup and hence the flowing mixture density and the frictional pressure gradient. This article details the most widely used correlations for the prediction of the Vertical Lift Performance.

The oil and water are lumped together as one equivalent fluid. They are therefore more correctly termed two-phase flow correlations. Depending on the particular correlation, flow regimes are identified and specialized holdup and friction gradient calculations are applied for each flow regime.

There is no universal rule for selecting the best flow correlation for a given application. When an outflow performance simulator is used, it is recommended that a Correlation Comparison always be carried out. By inspecting the predicted flow regimes and pressure results, the User can select the correlation that best models the physical situation. Note: Fancher Brown no slip and Duns and Ros Modified can serve as quality check boundaries for downhole measurements.

It uses the same methodology as the standard Beggs and Brill, with the exception that the holdup used is not the horizontal holdup described above, but simply the no-slip holdup, without deviation correction. It also uses the same methodology as the standard Beggs and Brill, with the following changes:.

The Petroleum Experts correlation combines the best features of existing correlations. It uses the Gould et al flow map and the Hagedorn Brown correlation in slug flow, and Duns and Ros for mist flow. In the transition regime, a combination of slug and mist results is used. It provides more accurate prediction of minimum load-up rates. The Petroleum Experts 3 includes the features of the PE2 correlation plus original work for viscous, volatile and foamy oils.

The Petroleum Experts 4 is an advanced mechanistic model suitable for any angled wells including downhill flow suitable for any fluid including Retrograde Condensate. It is especially good correlation for pipeline pressure drop calculations and instability calculations detecting the conditions at which instability will occur.

The Petroleum Experts 5 mechanistic correlation is an advancement on the PE4 mechanistic correlation. PE4 showed some instabilities just like other mechanistic models that limited its use across the board.

**Flow Regimes**

PE5 reduces the instabilities through a calculation that does not use flow regime maps as a starting point. PE5 is capable of modeling any fluid type over any well or pipe trajectory. This correlation accounts for fluid density changes for incline and decline trajectories.

The stability of the well can also be verified with the use of PE5 when calculating the gradient traverse, allowing for liquid loading, slug frequency, etc.

Orkiszewski developed a pressure drop prediction method based on a new flow pattern map and a combination of features from existing correlations. He combined the work of Griffith for bubble flow and that of Griffith and Wallis for slug flow together with the Duns and Ros correlation for mist flow.

In addition, new friction and density correlations for slug flow based on a liquid distribution parameter were developed. The data of Hagedorn was used to develop a correlation with tubing size, superficial mixture velocity, and liquid viscosity. Orkiszewski correlation often gives a good match to measured data. However, its formulation includes a discontinuity in its calculation method.If you need a quick calculation, but you are not still familiar how to use the calculator, you can order calculation service from the calculator developer.

Order calculation service. Velocity of fluid in pipe is not uniform across section area. Therefore a mean velocity is used and it is calculated by the continuity equation for the steady flow as:. Calculate pipe diameter for known flow rate and velocity. Calculate flow velocity for known pipe diameter and flow rate. Convert from volumetric to mass flow rate. Calculate volumetric flow rate of ideal gas at different conditions of pressure and temperature.

Pipe diameter can be calculated when volumetric flow rate and velocity is known as:. If the velocity of fluid inside the pipe is small, streamlines will be in straight parallel lines. As the velocity of fluid inside the pipe gradually increase, streamlines will continue to be straight and parallel with the pipe wall until velocity is reached when the streamlines will waver and suddenly break into diffused patterns. The velocity at which this occurs is called "critical velocity".

At velocities higher than "critical", the streamlines are dispersed at random throughout the pipe. The regime of flow when velocity is lower than "critical" is called laminar flow or viscous or streamline flow. At laminar regime of flow the velocity is highest on the pipe axis, and on the wall the velocity is equal to zero. When the velocity is greater than "critical", the regime of flow is turbulent. In turbulent regime of flow there is irregular random motion of fluid particles in directions transverse to the direction on main flow.

Velocity change in turbulent flow is more uniform than in laminar. In the turbulent regime of flow, there is always a thin layer of fluid at pipe wall which is moving in laminar flow.

That layer is known as the boundary layer or laminar sub-layer. To determine flow regime use Reynolds number calculator. The nature of flow in pipe, by the work of Osborne Reynolds, is depending on the pipe diameter, the density and viscosity of the flowing fluid and the velocity of the flow. Dimensionless Reynolds number is used, and is combination of these four variables and may be considered to be ratio of dynamic forces of mass flow to the shear stress due to viscosity.

Reynolds number is:. Calculate Reynolds number with this easy to use calculator. Determine if flow is laminar or turbulent. Applicable for liquids and gases.Flow of fluid in the reservoir flows in different ways at different times. This is often a function of the shape and size of the reservoir. In this section, the basic flow regimes are categorized in terms of which time region they occur, and what kind of wellbore vertical or horizontal was used to drill into the formation. The following are typical derivative and pressure-time plots with the different time categories marked:.

Specific flow regimes that occur within each of the flow regime categories are listed below for both vertical and horizontal wells :.

When a producing well is shut-in at the surface, flow into the wellbore at sandface continues after shut-in. This type of flow regime is referred to as afterflow or wellbore storage, and can affect the analysis of the pressure data. Wellbore storage is typically controlled by the compressibility of the fluid in the wellbore. For a gas-filled wellbore, compressibility is high, and wellbore storage effects will occur over a longer period of time. For a liquid-filled wellbore, compressibility is much lower, and wellbore storage effects will dissipate more quickly.

In some cases, typically in oil wells, both gas and liquid are present within the wellbore and the liquid level changes after shut-in. In these cases, wellbore storage is also affected by the changing liquid level, as well as compressibility. Wellbore storage can be minimized by using a downhole shut-in. This operation reduces the wellbore volume and consequently the wellbore fills more quickly allowing one to see reservoir-dominated flow faster.

This kind of operation is typically used to conduct a Closed Chamber Test CCT analysis to reduce the amount of time needed to gather data to see reservoir effects.

Bilinear fracture flow occurs in hydraulically fractured wells when the conductivity of the fracture is finite. In this flow regime, two types of linear flow occur: one from the matrix to the fracture, and one from the fracture to the wellbore. This is usually evident in long fractures which are hard to prop open effectivelyor in natural fractures which contain fracture-fill minerals.

In multi-fractured horizontal wells MFHWswhen the conductivity of the fracture is finite, and the fracture length is greater than its height, bilinear flow can be observed. It occurs when two linear flows exist: one within the fracture towards the welland one within the formation towards the fracture.

This is identical to bilinear flow in a fractured vertical well. Once the fractures have interfered with each other, compound linear flow may be observed. It is defined by flow from an outer zone towards the region stimulated by the fractures.

This can be observed in fields where well spacing is sparse. However, with close well spacing, it will not be observed before interference from adjacent producing wells occurs. Identical to linear flow in a hydraulically fractured vertical well, this flow regime occurs when there is linear flow towards the fractures of a multi-fractured horizontal well MFHW and the transients within the fractures have stabilized.

This linear flow regime is expected to be the dominant flow regime, as demonstrated from production analysis results Nobakht, This flow regime, depicted below, was initially proposed when hydraulic fracturing was first attempted on horizontal wells in the mid s.Register to enable "Calculate" button. Department of Agriculture has worked for decades developing equations and conducting experiments to determine reliable models for predicting peak discharge from storm events. Relying upon extensive research, Technical Release 55 TR SCS, presents a methodical and reliable approach to predicting peak discharge due to a hr storm event.

TR is valid for watersheds that have a time of concentration from 0. Such watersheds are considered small. Our calculation uses the equations and graphs coded into equations in TR chapters 1 thru 4 to solve for peak discharge. Chapter 5 titled Tabular Hydrograph Method also solves for peak discharge but models more complicated watersheds - watersheds that have several main channels requiring channel hydrograph routing techniques.

Though the TR document mentions specific units all English for its equations, our calculation allows a variety of input and output units English and metric. We have tried to make the calculation useful for the international community. Our calculation allows you to use other units that may be more convenient.

### FLOW REGIMES IN HORIZONTAL AND VERTICAL PIPES

Our calculation allows the user to divide a watershed into a maximum of five sub-regions represented by different curve numbers. Then, the overall curve number and total area are computed. Alternatively, if there are more than five sub-regions, you may compute the overall curve number by hand and enter that value into our calculation.

Table of curve numbers as a function of land use. Overall curve number is computed from:. After decades of research, SCS indicates that there are typically three distinct runoff patterns in a watershed - sheet flow, shallow concentrated flow, and channel flow. Sheet flow occurs in the upper reaches of a watershed and persists for a maximum of ft.

After flowing in sheets, water then typically becomes less sheet-like and more concentrated. Following shallow concentrated flow, water typically collects in natural or man-made channels. Each of the flow patterns requires a unique mathematical expression:.

For channel flow, our calculation allows you to input the type of channel and the cross-section dimensions. Channel flow information is used for computing channel travel time. SCS states that bank full dimensions for open channels or full flow conditions for culverts should be used for this calculation. The diagrams below indicate the types of channels that are coded into our calculation.

The hydraulic radius R is calculated by our program, but is provided below for your information. R is used in the Manning equation to determine flow velocity and then travel time.

If your channel does not match one of the four types shown below, our program can still be used to compute travel time: You should compute R by hand for your channel, then select "Circular Culvert" and enter 4R for the culvert diameter.

The hydrologic soil group refers to the infiltration potential of the soil after prolonged wetting. Sand, loamy sand, or sandy loam. Silt loam or loam. Infiltration rate 0. Sandy clay loam. Clay loam, silty clay loam, sandy clay, silty clay, or clay.

## Sizing Calculator

Infiltration rate 0 to 0. The peak discharge calculation is only valid for T c between 0. If overall CN is input, runoff will be computed.On your 'Flow regime Calculator" Spreadsheet, i wonder if there's an error in calculating the gas and liquid Froude numbers.

It's this last ratio that seems incorrect. Is it supposed to equal the void fraction "alpha" or what? Your help would be much appreciated. The program has been quite useful. Pls reply to me at kirsner kirsner. Post a Comment. This Excel spreadsheet plots a flow regime map for the two-phase flow of liquid and gas in horizontal and vertical pipes. Additionally, some flow regimes are undesirable such as slug flow, which can damage pipes through excessive vibration.

The spreadsheet will then plot the location of the flow on a flow regime map for horizontal and vertical pipes. The spreadsheet uses the flow regime maps digitized from Shell DEP Mandhane et al published a map for two-phase horizontal flow Hewitt and Roberts published a map for two-phase vertical flow Taitel and Dukel published a map for two-phase horizontal flow.

There are, however, inconsistencies in the definition of flow regimes in these different maps. For example, some maps give different flow regimes at the same conditions. The horizontal and vertical maps given in Shell DEP Therefore, engineers can compare potential flow regimes in horizontal and vertical pipes.

Email This BlogThis! Labels: excelflow regime maptwo-phase. Newer Post Older Post Home. Subscribe to: Post Comments Atom.Flow regimes describe the nature of fluid flow. There are two basic flow regimes for flow of a single-phase fluid: laminar flow and turbulent flow.

Laminar flow is characterized by little mixing of the flowing fluid and a parabolic velocity profile. Turbulent flow involves complete mixing of the fluid and a more uniform velocity profile. Reynolds numbers between 2, and 4, are in a transition zone, and thus the flow may be either laminar or turbulent.

Two-phase flow of liquid and gas is a very complex physical process. Nevertheless, as gas exploration and production have moved into remote offshore, arctic, and desert areas, the number of two-phase pipelines has increased. To determine whether two-phase flow will exist in a pipeline, the expected flowing pressure and temperature ranges in the line must be plotted on a phase. However, as the pressure drops it becomes a two-phase mixture through part of the pipeline. On the other hand, composition A will flow as a single-phase dense fluid or gas through the entire length of the line.

Composition C will flow as a liquid throughout the entire length of the line.

In most production situations the fluid coming out of the well bore will be in two-phase flow. Once an initial separation is made, the gas coming off the separator can be considered to be single-phase gas flow even though it will have some entrained liquids.

The liquid coming off the separator is assumed to be in single-phase liquid flow even though it will contain some gas after it has taken a pressure drop through a liquid control valve. Other than well flowlines, the most common two-phase pipelines exist in remote locations, especially offshore, where gas and oil that have been separated and metered are combined for flow in a common line to a central separation facility.

When a gas-liquid mixture enters a pipeline, the two phases tend to separate with the heavier liquid gravitating to the bottom. This figure shows typical flow patterns in horizontal two-phase pipe flow. The type of flow pattern depends primarily on the superficial velocities as well as the system geometry and physical properties of the mixture.

At very low gas-liquid ratios, the gas tends to from small bubbles that rise to the top of the pipe. As the gas-liquid ratio increases, the bubbles become larger and eventually combine to form plugs. Further increases in the gas-liquid ratio cause the plugs to become longer, until finally the gas and liquid phases flow in separate layers; this is stratified flow.

As the gas flow rate is increased, the gas-liquid interface in stratified flow becomes wavy. These waves become higher with increasing gas-liquid ratios, until the crest of the waves touches the top of the pipe to form lugs of liquid which are pushed along by the gas behind them. These slugs can be several hundred feet long in some cases.

Further increases in the gas-liquid ratio may impart a centrifugal motion to the liquid an result in annular flow. The two-phase flow patterns in vertical flow are somewhat different from those occurring in horizontal or slightly inclined flow. Vertical two phase flow geometries can be classified as bubble, slug-annular, transition, and annular-mist, depending on the gas-liquid ratio.

All four flow regimes could conceivably exist in the same pipe. One example is a deep well producing light oil from a reservoir that is near its bubble point.

At the bottom of the hole, with little free gas present, flow would be in the bubble regime. As the fluid moves up the well, the other regimes would be encountered because gas continually comes out of solution as the pressure continually decreases.

Normally flow is in the slug regime and rarely in mist, except for condensate reservoirs or steam-stimulated wells. Bubble Flow: The gas-liquid ratio is small. The gas is present as small bubbles, randomly distributedwhose diameters also vary randomly. The bubbles move at different velocities depending upon their respective diameters.

The liquid moves up the pipe at a fairly uniform velocity, and except for its density, the gas phase has little effect on the pressure gradient. Slug Flow: In this regime the gas phase is more pronounced.

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