Wellbore Configuration

Wellbore Types

There are 3 different wellbore configurations available in Virtuwell. They have different required information and can vary dramatically in terms of results. The three available configurations are:

 

Vertical Wellbore

A vertical wellbore is one that deviates only slightly, if at all, from the vertical. As a result, a vertical wellbore can be described very simply in F.A.S.T. Virtuwell™ by few variables. The variables are:

The flow in a vertical wellbore originates from the MPP and all pressure drop calculations are calculated from Sandface (MPP) to wellhead.

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Horizontal Wellbore

A horizontal wellbore in F.A.S.T. Virtuwell™ consists of three (3) parts: the vertical section, the deviated section and the horizontal section. The vertical section is similar to a vertical well and is defined by a Casing ID and the Kick Off Point (KOP). The deviated section is similar to an inclined pipe (in that it is assumed to be straight) and is defined by the Casing ID and the measured depth (MD) and total vertical depth (TVD) of the Heel. The horizontal section is defined by the casing ID as well as the measured depth (MD) of the Toe. Note that the casing IDs for the vertical, deviated and horizontal sections can all be different.

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The flow in a horizontal wellbore is considered to originate between the measured depth (MD) of the Heel and the measured depth (MD) of the Toe in F.A.S.T. Virtuwell™. The total flow is divided so that it enters at ten (10) equally spaced points in the horizontal portion of the wellbore. The Datum is a user-defined measured depth or true vertical depth located in the horizontal section of the wellbore. All pressure drop calculations are done between the Datum and the wellhead.

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General Wellbore

For certain applications it might be deemed necessary to have a wellbore that is able to deviate more than once. For these cases, the facility for making a complex wellbore has been provided.

A complex wellbore can have more than one size of casing, multiple zones of perforations and percentage of flow per group of performations can be defined.

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Tubing Data

All required tubing data can be entered using this table.

Preset Sizes

A set of defined sizes are available by pressing on the T button located on the right side of the data entry table.

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A specific size can then be selected from a color coded table that appears.

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Casing Data

The Casing ID is the Inside Diameter of the wellbore casing. This value is used to calculate the area of flow when production is through the casing or along with the Tubing OD to calculate the area of flow when production is directed through the annulus. This value will also be required when flow is through the tubing if the Mid-Point of Perforations(MPP) or the Datum is below the End of Tubing Depth (EOT).

For horizontal wellbores, three casing ID’s, one for each of the Vertical, Deviated and Horizontal sections of the wellbore are requested.

The casing ID is also used to represent the inside diameter of the wellbore in the event of an openhole completion. There is no differentiation made between flow through openhole and flow through casing.

Note: In the petroleum industry the nominal casing size refers to the outside diameter of the casing. The ID depends on the OD and the weight (linear density) of the casing.

Preset Sizes

A set of defined sizes are available by pressing on the C button located on the right side of the data entry table.

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A specific size can then be selected from a color coded table that appears.

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Perforation Data

Enter in required information about perforations using this section. Perforations are a method of making holes through the casing opposite a producing formation to allow oil or gas to flow into a well.

 

Fluid Flow Path

This section defines the conduit through which the fluids are being produced. In the Wellbore and SF/WH AOF pages, the optional flow paths are through the tubing, through the annulus, through both, or through the casing only (no tubing). In the Gas AOF/TPC and Oil AOF/TPC pages, the options are restricted to flow through the tubing or the annulus. Flow through casing only can be approximated by setting the tubing diameter to the desired casing diameter.

In a vertical well, flow within the wellbore originates at the Mid-Point of Perforations (MPP) and ends at the Wellhead. As a result, the pressure drop is calculated from the MPP to the Wellhead. In a horizontal well, the total flow is divided so that it enters at ten (10) equally spaced points in the horizontal portion of the wellbore. The pressure drop is then calculated from the specified Datum to the Wellhead.

Flow Path - Tubing

With this option selected, fluid flow to surface is through the inside of the tubing. For this case there are three flow paths to consider.

1. When the End of Tubing Depth (EOT) is equal to Mid-Point of Perforations (MPP), flow is directly into the tubing. For this case, the parameters Tubing OD and Casing ID, are not used in the calculations. These parameters may still be input for completeness of presentation.

2. When the EOT is above MPP, flow will be within the casing until it reaches the end of the tubing. After this point, flow will be through the tubing as per case 1 above. Casing ID is required for this calculation.

3. When the EOT is below the MPP, flow will be down the annulus to the EOT where it will enter the tubing and flow up the tubing to surface. Tubing OD and Casing ID are required for this calculation.

The three cases are shown in the following diagram.

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Flow Path – Casing Only

With this option selected, fluid flow to surface is through the inside of the casing. For this option, there is no tubing in the wellbore and so no tubing information may be entered.

Flow Path – Both (Casing and Tubing)

In this case, flow is via the inside of the tubing as well as the tubing/casing annulus. This case represents both ‘strings’ producing from the same interval. The flow rates in the tubing and the annulus are split in such a way that the wellhead pressures on the tubing and annulus are equal.

te-abcamber3.jpg Note #1: As a result of instabilities in multi-phase calculations, this option may not always converge. However, convergence may be obtained manually by varying the flow through the annulus and the tubing until similar wellhead and sandface pressures are achieved. If the calculation does converge, there is no guarantee that the results are representative as VirtuWell assumes that you have the same fluid mixture and flow regime in both areas and this is not usually the case.

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te-abcamber3.jpg Note #2: Wells equipped with packers, where the tubing and annulus produce independently from separate completion intervals, should be modeled as separate cases or files, producing through the tubing or through the annulus as appropriate.

Flow Path – Annulus

With this option selected, fluid flow to surface is through the annulus between the casing and the tubing. For this case there are two (2) flow paths to consider.

1. When the Mid-Point of Perforations (MPP) is above the End of Tubing Depth (EOT), all flow is directed through the annulus. For this case, the parameter Tubing ID is not used in the calculations. These parameters may still be input for completeness of presentation.

2. When the MPP is below the EOT, flow is through the casing until the EOT, and then flow is through the annulus. Tubing ID is not required for these calculations.

The two cases are shown below.

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Choke Settings

This section helps to add a choke in the wellbore. We activate it by using the check box next to "Use Choke":

The properties of the choke can be then defined by clicking on "Settings". This will bring up the choke dialog:

The choke size can be defined by either using 1/64 in or in (mm). The set depth is required and needs to be part of the tubing section. The choke cannot be placed in the casing section In case that it is needed to model a choke set in a casing, a tubing section needs to be defined using the casing dimensions for calculation purposes.

The adiabatic index (k), choke discharge coefficient and Joule-Thomson coefficient are optional variables. They can be defined but are otherwise internally calculated.

 

Wellbore Properties

This section contains of 4 elements:

Wellhead Temperature

This is the temperature at the wellhead, and is used to calculate the temperature gradient within the wellbore. This has an effect on fluid density and viscosity, however the calculated pressure drops are not very sensitive to small changes of this parameter.

Note: The wellhead temperature can be very different during flow or shut in. Usually the wellhead temperature will be higher during flow than during shut in, due to the flow of warmer fluids from the reservoir. A reasonable estimate of flowing wellhead temperature is sufficient in most cases, however care must be taken when specifying the wellhead temperature during shut in. Measured wellhead temperatures can vary significantly depending on the time of day (or night) or time of year (summer or winter). These potentially large swings in temperature (150°F is not unusual) only affect the wellhead and approximately 10 feet (3 m) into the ground. Below this depth, the ground and wellbore fluids are virtually unaffected.

Rather than using a wellhead temperature, it is better to use the mean ground temperature for static calculations.

UNITS: °F (°C)

DEFAULT: none

Sandface Temperature

This is the temperature at the sandface, and is used to calculate the temperature gradient within the wellbore. This has an effect on fluid density and viscosity, however the calculated pressure drops are not very sensitive to small changes in temperature. A reasonable estimate of reservoir temperature is sufficient in most cases. No distinction is made between flowing and shut in temperatures.

UNITS: °F (°C)

DEFAULT: none

Roughness

This is defined as the distance from the peaks to the valleys in pipe wall irregularities. Roughness is used in the calculation of pressure drop due to friction. For clean, new pipe the roughness is determined by the method of manufacture and is usually between 0.00055 to 0.0019 inches (0.01397mm to 0.04826mm)(Cullender and Binckley, 1950, Smith et al. 1954, Smith et al. 1956). For new pipe or tubing used in gas wells the roughness has been found to be in the order of 0.00060 or 0.00065 inches (0.01524 mm to 0.01651 mm).

Roughness can be used to tune the correlations to measured conditions in a similar way to the Flow Efficiency. Changes in roughness only affect the friction component of the calculations while the Flow Efficiency is applied to the friction and hydrostatic components of pressure loss. Roughness does not affect the calculations for static conditions. In this case, a match between measured and calculated pressures may be obtained by adjusting the fluid gravity or temperatures, as appropriate.

te-abcamber3.jpg NOTE: Roughness must be between 0 and 0.01 inches (0.254 mm). 0 corresponds to a frictionless pipe.

UNITS: in (mm)

DEFAULT: 0.0006 inches (0.01524 mm)

Tuning Factor

This parameter allows the user to adjust computed pressure drops to match field test results. This should only be used as a last resort after all other sources of differences have been identified (liquid loading, incorrect fluid properties used, etc).

UNITS: %

DEFAULT: 100%