glossary(some basic definitions)

8/10/2019 Glossary(Some Basic Definitions)

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http://www.fekete.com/SAN/WebHelp/virtuwell/webhelp/c-te-glossary.htm

Glossary

Absolute Open Flow (AOF)

The Absolute Open Flow potential of a well is the rate at which the well would produce against zero sandface

backpressure. Flow into a well depends on both the reservoir characteristics and the wellbore flowing pressure. Therelationship of inflow rate to bottomhole flowing pressure is called the IPR (Inflow Performance Relationship). For gas

wells, this may also be called the AOF curve. F.A.S.T. VirtuWell presents this relationship in the form of a

pressure versus flow rate graph. From this graph, the wells flow potential can be determined at various flowing

sandface pressures. As well, the operating point (flow rate and pressure) of a particular wellbore configuration can be

determined from the intersection of the AOF curve and the Tubing Performance Curve (TPC).

F.A.S.T. VirtuWell uses the simplified analysis approach to determine AOFs. This approach is based on the

following equation:

where:

q = flow rate at standard conditions (MMcfd, 10^3 m^3/d)

P = shut-in pressure (in the case of a Sandface AOF, this is the static reservoir pressure (psia, kPaA)

Pf= flowing pressure (psia, kPaA)

C = a coefficient which describes the position of the stabilized deliverability line (MMcfd/(psi^2)n, 10^3

m^3/d/(kPa^2)n)

N = an exponent to describe the inverse of the slope of the stabilized deliverability line (n varies

between 1.0 for completely laminar flow and 0.5 for fully turbulent flow.)

This equation applies to both sandface and wellhead AOFs. If a sandface AOF is being calculated, all components

of the equation refer to the sandface and vice-versa with wellhead AOF calculations. The Gas AOF/TPC pagerequires sandface AOFs for its calculations. If only a wellhead AOF is known, a sandface AOF may be calculated

using the SF/WH AOF page. Care must be taken here when dealing with multi-phase flow as instabilities can occur.

NOTE: In order to represent a reservoir which is depleting due to pressure loss, several AOF curves may be drawn on

the Gas AOF/TPC page. Each successive AOF curve will have a consistent n and C with a declining reservoir

pressure. In order to model rate decline caused by wellbore liquid problems, the reservoir pressure and n may be

kept constant, and the AOF or C varied to account for the effects of liquids.

For oil wells, there is no AOF, so instead a similar concept is used. AOFP (absolute open flow potential) represents

the maximum value of oil flow as the pressure approaches zero. This is analogous to AOF (absolute open flow) with

a gas well.

UNITS: MMcfd (10 3 m 3 /d) DEFAULT: None

Angle

Deviation of the wellbore with respect to the vertical. It is calculated based on the change in length of the TVD and

MD for the corresponding pipe segment.

UNITS: Degrees DEFAULT: None


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AOF Equation Exponent, n

This is the exponent found in the Absolute Open Flow (AOF) equation.

It describes the inverse of the slope of the stabilized deliverability line. "n" varies between 1.0 for completely laminar

flow and 0.5 for fully turbulent flow.

It is generally accepted that "n" at wellhead is less than or equal to "n" at sandface. This condition is enforced when

the SF/WH AOF module is converting an equation from sandface to wellhead or vice versa in single phase flow.

However, in multiphase flow situations, the interaction of friction and hydrostatic pressure effects is much more

complicated, and this relationship of wellhead to sandface "n" is not enforced. However, to conform to standard

practice, the limits of 1.0 and 0.5 are honoured. Thus in a multiphase flow test, it is possible for the wellhead "n" to

be larger than the sandface "n"

The procedure for calculating the wellhead AOF curve, and the wellhead AOF equation, is described below for a

multiphase situation:

1. Draw the sandface AOF curve from the given data

2. Divide into 100 equally spaced rate points

3. For each of these, convert the sandface press ure to a wellhead pressure using the specified tubular configuration

and fluid properties.

4. Draw the calculated wellhead AOF curve by joining these calculated points. For single phas e flow, the curve will look

very sim ilar to the sandface curve, but for multiphase flow, the calculated wellhead points could form a curve with a

region that represents UNSTABLE rates. This unstable region is characterized by a maximum or discontinuities or

the limiting liquid lifting rate determined from the Turner Correlation. Any calculated points to the left of this are

considered to be in uns table flow (and the well will eventually kill itself), and the curve is generally drawn as a

dashed line to indicate this.

5. From the calculated shut-in wellhead pressure (assuming a static column of gas in the wellbore) and the calculated

wellhead pressures in the STABLE portion of the wellhead curve, the wellhead AOF equation (AOF and "n") is

determined. These values are copied onto the Option line and plotted as a continuous sim plified AOF equation. Theuser can modify this generic option curve at will.

6. The conversion of a wellhead AOF curve to a sandface AOF curve follows the same procedure, but it is much more

prone to irregularities. For example, sometimes the calculated flowing pressure can be higher than the specified

reservoir press ure when the combination of specified rates and tubulars is unrealis tic. It is very hard to guard

agains t situations like this in a computer program with a wide range of applications. The user is warned to ensure

that the calculated AOF curve is meaningful, and if not, to over-ride with a specified curve using the "option" entry.

UNITS: None DEFAULT: None LIMITS: 0.5 < n < 1.0

Bubble Point Pressure

The Bubble Point Pressure is defined as the pressure at which the oil is saturated with gas. Above this pressure the

oil is undersaturated, and the oil acts as a single phase liquid. At and below this pressure the oil is saturated, and

any lowering of the pressure causes gas to be liberated resulting in two phase flow.

The Bubble Point affects the Inflow Performance Relationship Curve (IPR) curve. Above this pressure, the IPR is a

straight line, of slope equal to the inverse of productivity index. Below the bubble point pressure, the IPR is a curve

based on "Vogels" equation. The straight line and the curve are tangential at the bubble point pressure, where they

meet.

UNITS: psia (kPaA) DEFAULT: None


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C, Sandface Coefficient

This is the coefficient found in the Absolute Open Flow (AOF) equation.

It describes the position of the stabilized deliverability line. Wellhead and sandface C values for a given system are

usually different.

NOTE: Care must be taken when converting C from field to metric units or vice-versa. This is because the units of

C are dependent on n. In order to avoid these problems, both n and C should be entered before changing units.

UNITS: MMcfd/(psia^2 )^n (10^3 m^3 /d/(kPaA^2

)^n)

DEFAULT: None

Casing

Casing lines are set and cemented in wellbores to protect the borehole from problematic formations and from

colapsing.

Casing ID

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 IDs, 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.

UNITS: in (mm) DEFAULT: None

Casing ODCasing OD is the outside diameter of the casing. This value is not used in any calculations but will

appear on printed reports.


Choke


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A choke is an element of restriction which is commonly installed in wells or production operations to control pressur

and flow rate. The size of a choke is referred to its diameter size.

UNITS: 1/64 in , in (mm) DEFAULT: None

Compressibility, Oil (Co)

The compressibility of any substance is the change in volume per unit volume per unit change in pressure. The oil

compressibility is a source of energy for fluid flow in a reservoir. In an undersaturated reservoir it is a dominant drive

mechanism, but for a saturated reservoir it is over-shadowed by the much larger gas compressibility effects. The oil

compressibility is a component in the calculation of total compressibility, which is the value used in the

determination of skin effect, dimensionless time and all material balance considerations in the fluid flow calculations.

There is a significant discontinuity at the bubble point pressure. Above this pressure, the oil is a single phase liquid

(consisting of oil and dissolved gas). The compressibility of this liquid can be measured in the laboratory, and it is a

weak function of pressure. At and below the bubble point pressure, if the pressure is decreased, gas comes out of

solution and contributes to the compressibility of the system. This apparent oil compressibility is calculated by

including a "dRs / dp" component, to account for the change in solution gas-oil ratio with pressure.

The correlations that can be used to calculate the Oil Compressibility are:

1. Vazquez and Beggs: Generally applicable

2. Hanafy et al: Egyptian oil

3. Petrosky and Farshad: Gulf of Mexico oil

4. De Ghetto et al: Heavy oil (10 22.3 API) and Extra Heavy oil (API < 10)

UNITS: 1/psi (1/kPaA) DEFAULT: User selectable correlation

Condensate Gas Ratio (CGR)

This is the condensate to gas ratio produced at surface. It is typically known from direct measurements. If the daily

condensate rate is known, it must be divided by the daily gas rate to obtain the Condensate-Gas Ratio. The CGR is

used to calculate the Recombined Gas Gravity and the Recombined Gas Rate which are used in the wellbore

pressure drop calculations.


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NOTE: See also condensate properties

UNITS: bbl/MMcf (m 3/10 3 m 3) DEFAULT: None

Datum (MD)

The datum is a reference point for calculations. Calculations are either done from the sandface to the datum or fromthe datum to the wellhead.

This is the user-defined Measured Depth (MD) in a well. In the wellbore, the pressure drop is calculated from the

specified Datum to the wellhead. The user may define the Datum to be located at any point in the horizontal section

that allows the flexibility to calculate the pressure drop from any desired location.

UNITS: ft (m) DEFAULT: None

Density

Is the mass per unit volume of a substance. The density ( ) as applied to hydrostatic pressure difference

calculations:

The method for calculating depends on whether the flow is compressible or incompressible (multiphase or single-

phase). It follows that:

For a single-phase liquid, calculating the densi ty is easy, and is simply the liquid density.

For a single-phase gas, varies with pressure (since gas is compressible), and the calculation mus t be donesequentially, in sm all s teps, to allow the dens ity to vary with pressure.

For multiphase flow, the calculations become even more complicated because is calculated from the in-situ

mixture density, which in turn is calculated from the "liquid holdup". The liquid holdup, or in-s itu liquid volume

fraction, is obtained from one of the multiphase flow correlations, and it depends on several parameters including

the gas and liquid rates, and the pipe diam eter. Note that this is in contrast to the way densi ty is calculated for the

friction pressure loss .

UNITS: lb/ft^3, API (kg/m^3) DEFAULT: None

Density, Condensate

Condensate Density is the specific gravity in API of condensate at stock tank conditions. It ranges from 60 API to 40

API. The API Gravity is readily obtained from any laboratory oil analysis. It is a fixed property of the condensate.

In F.A.S.T. VirtuWell, this variable is used to calculate the Recombined Gas Gravity and the Recombined Gas

Rate which are then used in single-phase pressure drop calculations.

NOTE: The conversion from API Gravity (field units) to Stock Tank Oil Density (metric units) is:

Stock Tank Density (kg/m^3) = 1000 * (141.5 / (API + 131.5))

UNITS: API (kg/m 3) DEFAULT: None


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Density, Gas

The density of a gas varies with the in-situ conditions of pressure and temperature along a pipe. The gas density is

calculated from the "real gas" law :

where:

G = Gas Gravity

P = Pressure (psia)

z = supercompressibility factor

T = temperature (R)

The gas density is used in calculating the pressure drops caused by friction and by hydrostatic head.

UNITS: lb/ft 3 (kg/m^3 ) DEFAULT: Defining Equation

Density, Mixture

The mixture density is a measure of the in-situ density of the mixture. This density can be calculated by considering

that the phases flow at the same velocity (no-slip condition) or at different velocities (slip condition). If just the term

mixture density is used, it is usually referred to the slip mixture density.

Density, No-Slip Mixture

The "no-slip" density is the density that is calculated with the assumption that both phases are moving

at the same in-situ velocity. The no-slip density is therefore defined as follows:

where:

CL= no-slip liquid volume fraction (liquid holdup)

CG= no-slip gas volume fractionCL= input liquid volume fraction

G= gas density

L= liquid density

NS= no-slip density of the mixture

NOTE: The no-slip density is defined in terms of input volume fractions (CL), whereas the mixture

density is defined in terms of in-situ volume fractions (EL).



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Density, Slip Mixture

The "slip" density is the density that is calculated with the assumption that both phases are moving at

different in-situ velocities. The slip density is therefore defined as follows:

where:

EL= in-situ liquid volume fraction (liquid holdup) with slip

EG= in-situ gas volume fraction with slip

m= mixture density with slip

L= liquid density

G= gas density

NOTE: The mixture density is defined in terms of in-situ volume fractions (E L), whereas the no-slip

density is defined in terms of input volume fractions (CL).


Density (in-situ), Oil

The in-situ oil density should not be confused with the API Gravity (Stock Tank Oil Density). The in-situ oil density

varies with pressure and temperature, but more so with the amount of dissolved gas contained in the oil (Solution

Gas-Oil Ratio), whereas the API gravity is a fixed property of the particular oil, independent of operating conditions.

The in-situ oil density is obtained by multiplying the density at stock tank conditions by the Formation Volume

Factor at the in-situ pressure and temperature conditions. Thus:

Oil density (in-situ) = Oil Density (Stock Tank Conditions) * Oil Formation Volume Factor

The oil density affects the Hydrostatic Pressure Loss and the Friction Pressure Loss.

UNITS: lb/ft^3 (kg/m^3

)

DEFAULT: Vasquez and Beggs correlation

Density (stock tank), Oil

The stock tank density is the measure of the mas per unit volume of the crude at the standard pressure and

temperature. The oil density is commonly reported using the API (American Petroleum Institute) gravity scale. The

conversion from API Gravity (field units) to Stock Tank Oil Density (metric units) is:


UNITS: API (kg/m 3) DEFAULT: None

Depth, Total Vertical (TVD)


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This is the total vertical depth from the wellhead to a given point. In other words, a depth that is independent of the

orientation of tubing in the wellbore. The following picture demonstrates the difference between TVD and MD.


Elevation

This is the elevation of the pipe over which the pressure drop is calculated. A positive elevation represents flow uphill.

A negative elevation represents downhill flow. An elevation of zero (0) represents a horizontal pipe.


Erosional Velocity

Erosion in pipe flows is referred to the removal of solids from the pipe wall. As the velocity increases, solids or

droplets in the stream can be accelerated until the point where they can cause damage to the walls. The onset

velocity for this condition is known as erosional velocity. Therefore, erosion can occur when the fluid velocity through

a pipe is greater than the calculated erosional velocity.

Ve= Ce/ ( NS)1/2

where:

Ve= erosion velocity, ft/s

Ce= erosion velocity constant

Common range for Ce: 100 300

UNITS: ft/s (m/s) DEFAULT: Ce= 300


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No-Slip Mixture Density

where:

CL- input liquid volume fraction

CG- input gas volume fraction

NS- no-slip mixture density

L- liquid density

G- gas density

UNITS: lb/ft 3 (kg/m^3) DEFAULT: None

Input Liquid/Gas Volume Fraction

where:

QL- liquid rate at prevailing pressure and temperature

QGBG- gas rate at prevailing pressure and temperature

VSL- superficial liquid velocity

VSG- superficial gas velocity

Vm- mixture velocity

UNITS: Unitless DEFAULT: None

Flow, %

This is the amount of the total flow that enters a particular set of perforations (weighting factor).

UNITS: Percent (%) DEFAULT: 100%


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Flow Efficiency

Flow efficiency is a tuning parameter used to match calculated pressures to measured pressures. These two often

differ as most calculations involve unknowns, approximations, assumptions, or measurement errors. When measured

pressures are available for comparison with calculated values, the Flow Efficiency can be used to obtain a match

between the two.

If measured pressures are not available for comparison, then the default value (100%) should be used.

Flow Efficiency adjusts the correlation such that decreasing the flow efficiency increases the pressure loss.Efficiencies greater than 100% are possible. Low efficiencies could be a result of roughness caused by factors such

as corrosion, scale, sulfur or calcium deposition and restrictions. Restrictions in a wellbore may be caused by

downhole equipment, profiles, etc. Low efficiencies could also be the result of liquid loading. Flow efficiencies less

than 50% or greater than 150% should be treated with caution.

The flow efficiency is applied to both the hydrostatic and friction components of the pressure loss equation. Under

static (no-flow) conditions the flow efficiency is not applied to the correlations. In this case, a match between

measured and calculated pressures may be obtained by adjusting the fluid gravity or temperatures, as appropriate.

F.A.S.T. VirtuWell divides the whole length of pipe into many segments (see Pressure Loss Calculation

Procedure). The flow efficiency is applied to each segment and affects the inlet/outlet pressure of that segment, and

hence the in situ fluid densities. Therefore, a simple one step application of the flow efficiency to the pressure loss

over the whole length of pipe will not produce the same results as those of F.A.S.T. VirtuWell.

UNITS: Percent (%) DEFAULT: 100%

Formation Volume Factor, Oil (Bo)

This is defined as the ratio of the volume of oil at operating conditions to that at stock tank conditions. This factor is

used to convert the flow rate and the density of oil (both normally reported at stock tank conditions) to in-situ

conditions. Thus,

Oil Flow Rate (in-situ Barrels) = Oil Flow Rate (Stock Tank Barrels) * Oil Formation Volume Factorand:

Oil density (in-situ) = Oil Density (Stock Tank Conditions) * Oil Formation Volume Factor

In the equations used in F.A.S.T. VirtuWell the oil rate and the oil density should be expressed at in-situ

conditions, because the equations apply to the pressure and temperature conditions inside the pipe. However, the oi

flow rate is generally measured at the surface, in stock tank barrels. Therefore, this rate is multiplied by the oil

formation volume factor to convert it to in-situ conditions. Similarly, it is the in-situ density that counts, and that is

obtained from the API Gravity (Stock Tank Oil Density) and the Formation Volume Factor

Below the bubble point pressure, the oil formation volume factor increases with pressure. This is because more gas

goes into solution as the pressure is increased and this causes the oil to swell. Above the bubble point pressure, the

oil formation volume factor decreases as the pressure is increased, because there is no more gas available to go into

solution, and the oil is being compressed.

The value of the oil formation volume factor is generally between 1 and 2 RB/STB (m^3/m^3). It is readily obtained

from laboratory PVT measurements, or it may be calculated from correlations such as "Vasquez and Beggs".

In the correlations that are being used to calculate the oil formation volume factor, the Solution Gas-Oil Ratio is the

most significant variable.

UNITS: Bbl/Bbl (m^3 /m^3

)

DEFAULTS: "Vasquez and Beggs" correlations


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Friction Factor, Multiphase

This is obtained from multi-phase flow correlations (for example, see Beggs and Brill under multi-phase flow

correlations). This correlation depends, in part, on the gas and liquid flow rates, but also on the standard Fanning

(single phase) friction factor charts. When evaluating the Fanning friction factor, there are many ways of calculating

the Reynolds number depending on how the density, viscosity and velocity of the two-phase mixture are defined. For

example. in the Beggs and Brill calculation of Reynolds number, these mixture properties are calculated by prorating

the property of each individual phase in the ratio of the "input" volume fraction and not of the "in-situ" volume fraction.

UNITS: Unitless DEFAULTS: None

Friction Factor, Single phase

This is obtained from the Chen (1979) equation which represents the Fanning friction factor chart. It depends on the

Reynolds number which is a function of the fluid density, viscosity, velocity and pipe diameter. It is valid for single

phase gas or liquid flow, as their very different properties are taken into account in the definition of Reynolds number.

UNITS: Unitless DEFAULTS: None

Friction Pressure Loss

In pipe flow, the friction pressure loss is the component of pressure loss caused by viscous shear effects. The friction

pressure loss is ALWAYS positive IN THE DIRECTION OF FLOW. It is combined with the hydrostatic pressure

difference (which may be positive or negative depending on the whether the flow is uphill or downhill) to give the total

pressure loss.


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The friction pressure loss is calculated from the Fanning friction factor equation as follows:

where:

= pressure loss due to friction

f = Fanning friction factor

= in-situ density

v^2 = the square of the in-situ velocity

L = length of pipe segment

g = acceleration of gravity

D = pipe internal diameter

In the above equation, the variables f, and v 2 require special discussion depending on whether it is single or

multiphase flow.

UNITS: psia (kPaA) DEFAULT: 0

Gas-Oil Ratio (GOR)

This is the gas to oil ratio produced at surface. It is typically known from direct measurements. If the daily gas rate is

known, it must be divided by the daily oil rate to obtain the Gas-Oil Ratio.

UNITS: scf/bbl (m 3 /m 3 ) DEFAULT: 0

Gas Compressibility Factor, zThe compressibility factor (z), of a natural gas is a measure of its deviation from ideal gas behavior. Its value is

usually between 0.8 and 1.2, but it can be as low as 0.3 and as high as 2.0. It is used in the calculation of gas

density, and in converting gas volumes and rates from standard conditions to reservoir conditions (and vice-versa).

References:

Dranchuck, P.M., R. A. Purvis and D. B. Robinson (1974). Computer Calculation of Natural Gas Compressibility

Factors Using the Standing and Katz Correlations, Inst. Of Pet. Tech., IP-74-008.

UNITS: Unitless DEFAULTS: B.W.R. equation of state

Gas Rate

This is the daily gas rate. It is typically known from direct measurements. If the gas-oil ratio (GOR) is known, it must

be multiplied by the daily oil rate in order to calculate the daily gas rate. The rate must be at standard conditions

(14.65 psia, 60 F / 101.325 Pa, 15 C).

F.A.S.T. VirtuWell treats all flow within the vertical wellbore as originating from the MPP (Mid Point Perforations).

In a horizontal well, the flow is divided so that it enters at ten (10) equally spaced points in the horizontal portion of

the wellbore.


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Even though the gas flow rate is quoted at Standard Conditions, all calculations in F.A.S.T. VirtuWell use the

volumetric flow rate at the "in-situ" conditions of pressure and temperature at which the pipe segment is operating.

Also, when both gas and oil are flowing in a pipe or wellbore, the gas flow rate is continuously adjusted to account fo

"gas coming out of solution from the oil".

UNITS: MMcfd (10 3 m^3 /d) DEFAULT: 0

Gas, CO2Molar Concentration of Carbon Dioxide in the gas stream. It has an effect on the calculation of compressibility (z-

factor) and viscosity. The concentration of CO2must be between 0% and 80% to be within the limits of the

correlations for the z-factor, and between the limits of 0 and 15% for the viscosity correlations. For values outside of

this range F.A.S.T. VirtuWell will still complete the calculations, however results should be used with caution.

When the parameter name is displayed in yellow this a warning that the entered value is outside the range.

Properties of Carbon Dioxide:

Molecular weight: 44.01 kg/kmol

Appearance: colorless gasMelting point: -56.6C

Boiling point: -78C

UNITS: Percent (%) DEFAULT: 0

Gas, H2S

Molar Concentration of Hydrogen Sulfide in the gas stream. It has an effect on the calculation of compressibility (z-

factor) and viscosity. The concentration of H2S must be between 0% and 80% to be within the limits of thecorrelations for the z-factor and between the limits of 0 and 15% for the viscosity correlations. For values outside of

this range F.A.S.T. VirtuWell will still complete the calculations, however results should be used with caution.


Properties of Hydrogen Sulfide:


Appearance: colorless gas

Melting point: -85.6C

Boiling point: -60.3C

Liquid Density: 993 kg/m^3


Gas, N2

Molar Concentration of Nitrogen in the gas stream. It has an effect on the calculation of compressibility (z-factor) and

viscosity. The concentration of Nitrogen must be between 0% and 15% to be within the limits of the correlations. For

values outside of this range F.A.S.T. VirtuWell will st ill complete the calculations, however results should be used

with caution.


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Properties of Nitrogen:


Appearance: colorless gas

Melting point: -209.9C

Boiling point: -195.8 C

Liquid Density: 805 kg/m


Gas, C3H8

Molar Concentration of Propane in the gas stream. It has an effect on the calculation of compressibility (z-factor),

viscosity and hydrates formation. The concentration of Propane must be between 0% and 10% to be within the limits

of the correlations. For values outside of this range F.A.S.T. VirtuWell will st ill complete the calculations, however

results should be used with caution.


Properties of Propane:

Molecular weight: kg/kmol

Appearance:

Melting point: C

Boiling point: C

Liquid Density: kg/m


Gravity, API (Stock Tank Oil Density)

API Gravity is the specific gravity (density) of oil at stock tank conditions. It ranges from 60 API (condensate) to 45

API (light oil) to 20 API (medium density) to 10 API (heavy oil). The API Gravity is readily obtained from any

laboratory oil analysis. It is a fixed property of the oil, and is independent of the operating pressure or temperature,

unlike the in-situ oil density that is very dependent on operating pressure and temperature conditions.

In F.A.S.T. VirtuWell, this variable is the primary variable used for calculating the oil properties at the required

pressures and temperatures. API Gravity affects four variables namely oil viscosity, solution gas-oil ratio, oil

formation volume factor and in-situ oil density.

The primary effect of API Gravity is on the in-situ oil density. The density affects the friction pressure drop to some

extent, but it affects the hydrostatic pressure drop DIRECTLY. The conversion from API Gravity (field units) to Stock

Tank Oil Density (metric units) is:


The API Gravity must be between 16 API and 58 API to be within the range of the correlations. When the

parameter name is displayed in yellow this a warning that the entered value is outside the range.

UNITS: API (kg/m^3 ) DEFAULT: None LIMITS: 16 API < G < 58 API


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Gravity, Condensate

API Gravity is the specific gravity (density) of condensate at stock tank conditions. It ranges from 60 API to 40 AP

The API Gravity is readily obtained from any laboratory oil analysis. It is a fixed property of the condensate. The

conversion from API Gravity (field units) to Stock Tank Oil Density (metric units) is:


In F.A.S.T. VirtuWell, this variable is used to calculate the Recombined Gas Gravity and the Recombined Gas

Rate which are then used in single-phase pressure drop calculations.

UNITS: API (kg/m^3 ) DEFAULT: None

Gravity, Gas

Gas Gravity is the molar mass (molecular weight) of the natural gas divided by the molar mass of air (28.94).

Gas Gravity = (Molar Mass of Gas) / (Molar Mass of Air)

The Gas Gravity is readily obtained from any laboratory gas analysis. It ranges from 0.55 for dry sweet gas (mostly

methane) to approximately 1.5 for wet, sour gas (includes CO2and H2S concentration). When the parameter name

is displayed in yellow this a warning that the entered value is outside the range.

The following table shows some gas gravities of some common gasses.

Gas type Molar Mass

(g/mol)

Gas Gravity of Pure Gas

Air 28.97 1.00

Methane 16.04 0.55

Nitrogen (N2) 28.01 0.97

Carbon Dioxide (CO2) 44.01 1.52

Hydrogen Sulfide (H2S) 34.08 1.18

In F.A.S.T. VirtuWell, Gas Gravity affects three variables namely compressibility (z-factor), Gas viscosity and gas

density. The effects on supercompressibility and viscosity are not very significant. However, the effect on density is

significant in two ways: It affects the friction pressure drop to some extent, but it affects the hydrostatic pressuredrop directly i.e. doubling the Gas Gravity doubles the density and therefore doubles the hydrostatic pressure drop

UNITS: Unitless DEFAULT: None LIMITS: 0.5 < G < 1.5

Gravity, Recombined Gas

This is the Gas Gravity used for pressure drop calculations in gas-condensate systems. It is a function of

Condensate-Gas Ratio, Condensate Gravity, Gas Gravity, Separator Temperature and Separator Pressure.


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The calculated Recombined Gas Gravity can be found on the printout when a gas-condensate system is being

modeled.

Gravity, Water

Specific Gravity is defined as the density of the liquid divided by the density of water at standard conditions (62.3

lb/ft3, 1000 kg/m^3). The gravity of pure water is therefore 1.0. Often oilfield waters are saline and have a specific

gravity slightly greater than 1.0.The primary effect of water gravity is on the density of water, which in turn affects the hydrostatic pressure difference

UNITS: Unitless DEFAULT: 1.0

Heel (MD or TVD)

This is the MD or TVD depth from the wellhead to the heel of the horizontal well (i.e.: where the horizontal portion of

the well begins). The measured and total vertical depth of the heel are used to determine the angle of the deviated

portion of the well from vertical.

UNITS: ft (m) DEFAULT: 0

Hydrates, Natural Gas

Hydrates are solid (icy) chemical compounds formed of gas trapped in a crystalline structure of water molecules.

They represent a problem in production operations since they tend to block pipelines.

Hydrostatic Pressure Difference

The hydrostatic pressure difference is the component of pressure loss (or gain) attributed to the earths gravitational

effect. It is of importance only when there are differences in elevation from the inlet end to the outlet end of a pipe

segment. This pressure difference can be positive or negative depending on the reference point (inlet higher vertically

than outlet, or outlet higher than inlet). UNDER ALL CIRCUMSTANCES, irrespective of what sign convention is used,

the contribution of the hydrostatic pressure calculation must be such that it will tend to make the pressure at the

vertically-lower end higher than that at the upper end.

The hydrostatic pressure difference is calculated as follows:

where:

= the hydrostatic pressure difference

= the vertical elevation change

= the in-situ density of the fluid or mixture

g = acceleration of gravity

gc= conversion factor

In the equation above, the problem is really determining an appropriate value for Rho, as discussed below:


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For a single phase liquid, this is easy, and equals the liquid density.

For a single phase gas, varies with pressure, and the calculation mus t be done sequentially in small steps to

allow the density to vary with pressure.

For multi-phase flow, is calculated from the in-situ mixture density, which in turn is calculated from the "liquid

holdup". The liquid holdup is obtained from multi-phase flow correlations, such as Beggs and Brill, and depends on

the gas and liquid rates, pipe diameter, etc...

For a horizontal pipe segment, = 0, and there is NO hydrostatic pressure loss.

See Also: Pressure Loss Correlations


Inflow Performance Relationship (IPR)

Flow into a well depends on both the reservoir characteristics and the sandface flowing pressure. The relationship of

inflow rate to bottomhole flowing pressure is called the IPR (Inflow Performance Relationship). F.A.S.T. Virtuwell

presents this relationship in the form of a pressure versus flow rate graph. From this graph, the wells flow potential

can be determined at various flowing sandface pressures. As well, the operating point (flow rate and pressure) of aparticular wellbore configuration can be determined from the intersection of the IPR curve and the Tubing

Performance Curve (TPC).

Straight Line IPR

In calculating oil well production, it is assumed that producing rates are proportional to the pressure

drawdown. Using this assumption, a wells behaviour can be described by its productivity index as

follows:

PI = q / (Pe- Pw f)

where:

PI = Productivity index

q = flow rate

Pe= Reservoir pressure at external boundary

Pw f= flowing bottomhole pressure

This relationship was developed from Darcys law for the steady state radial flow of a single,

incompressible liquid.

Vogel IPR

The pressure can drop below the bubble point pressure. As a result, the gas comes out of solution

from the oil and a progressive deterioration of the inflow performance relationship is found. In thefollowing picture, a straight line IPR and one with reduced performance due to resistance are

presented.


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The IPR for water is a straight line, whose slope is the inverse of the Productivity Index. The IPR for oil

is a straight line above the Bubble Point Pressure, and a curve below that. The curve is generated

using Vogels (1968) equation. Vogels IPR equation can be written as follows:

Reservoir Pressure Below the Bubble Point Pressure

for pw f/pb


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We can also write this as:

where:

Bg= gas formation volume factor

CG= input gas volume fraction

CL= input liquid volume fraction

QG= gas flow rate (at standard conditions)

QL= liquid flow rate (at prevailing pressure and temperature)

Vsg= superficial gas velocity

Vsl= superficial liquid velocityVm= mixture velocity (Vsl+ Vsg)

NOTE: QLis the liquid rate at the prevailing pressure and temperature. Similarly, QGBgis the gas rate at the

prevailing pressure and temperature.

The input volume fractions, CLand CG, are known quantities, and are often used as correlating variables in empirical

multiphase correlations. These values are also called no-slip holdups.


In-Situ Volume Fraction (Liquid Holdup)

The in-situ volume fraction, EL(or HL), is often the value that is estimated by multiphase correlations. Because of

"slip" between phases, the "holdup" (EL) can be significantly different from the input liquid fraction (CL). For example,

a single-phase gas can percolate through a wellbore containing water. In this situation CL= 0 (single-phase gas is

being produced), but EL> 0 (the wellbore contains water). The in-situ volume fraction is defined as follows:


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where:

AL= cross-sectional area occupied by the liquid phase

A = total cross-sect ional area of the pipe


Interfacial/Surface Tension

Measure of the imbalance of molecular forces between two different fluids at their zone of contact (interface).

Commonly, the term interfacial tension is used for liquid-liquid mixtures while surface tension is used in gas-liquid

cases.

UNITS: dynes/cm DEFAULT: None

Interfacial Tension, Dead Oil

The dead oil interfacial tension at temperatures of 68 F and 100 F is given by:

where:

= interfacial tension at 68 F (dynes/cm)= interfacial tension at 100 F (dynes/cm)

API = gravity of stock tank oil (API)

If the temperature is greater than 100 F, the value at 100 F is used. If the temperature is less than 68 F, the value at

68 F is used. For intermediate temperatures, linear interpolation is used.

As pressure is increased and gas goes into solution, the gas/oil interfacial tension is reduced. The dead oil interfacia

tension is corrected for this by multiplying by a correction factor.

where:

p = pressure (psia)

The interfacial tension becomes zero at miscibility pressure, and for most systems this will be at any pressure

greater than about 5000 psia. Once the correction factor becomes zero (at about 3977 psia), 1 dyne/cm is used for

calculations.



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Joule-Thomson Coefficient

The Joule-Thomson coefficient relates, at constant enthalpy, the change in temperature per unit of change in

pressure.

where:

= Joule-Thomson coefficient

= Partial derivative of temperature with respect to pressure at constant enthalpy

V = Volume

Cp = Heat capacity at constant pressure

= Thermal expansion coefficient

T = Temperature

which can be expressed in differences (considering isenthalpic conditions) as:

where:

= change in temperature

= change in pressure

UNITS: F/psia (C/kPa) DEFAULT: None

Kick Off Point (KOP)

This is the depth from the wellhead to the Kick Off Point of the horizontal well (i.e.: where the well begins to deviate

away from vertical).

UNITS: ft (m) DEFAULT: 0

Liquid Holdup Effect

When two or more phases are present in a pipe, they tend to flow at different in-situ velocities. These in-situ

velocities depend on the density and viscosity of the phase. Usually the phase that is less dense will flow faster than

the other. This causes a "slip" or holdup effect, which means that the in-situ volume fractions of each phase (under

flowing conditions) will differ from the input volume fractions of the pipe.

Measured Depth (MD)

This is the user-defined measured depth (MD) in a well. The MD is a scalar quantity that represents the sum of all

horizontal, vertical and deviated lengths. To demonstrate the difference between measured depth and Total Vertical

Depth (TVD) see the picture below.


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.

UNITS: Feet (m) DEFAULT: None

Multiphase Flow

Multiphase flow is the simultaneous flow of two or more phases through a pipe. Due to the difference in density and

viscosity between the phases, the resulting flow is more complex than single phase flow. The phases present

different configurations depending on the flowing conditions, fluid properties and pipe inclination. These configurations

are known as flow patterns and the pressure gradient can change significantly from one to another.

Pipe

Pipe ID

Pipe ID is the Inside Diameter of the pipe. This value is used to calculate the area of flow through the

pipe.

In the petroleum industry the nominal pipe size refers to the average diameter of the pipe. The inside

diameter (ID) and the outside diameter (OD) depend on the weight (linear density) of the pipe.


Pipe OD

Pipe OD is the Outside Diameter of the pipe. The area of the annuli can be calculated using the tubing

OD and the casing ID.



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Pipe Length

This is the length of the pipe over which the pressure drop is calculated. A length equal to the elevation

represents a vertical pipe.


Plugged Back Total Depth (PBTD)

Plugged Back Total Depth (PBTD) defines the total vertical well depth, relative to the wellhead. This depth is not used

for any calculations but may be entered for completeness of presentation.


Perforations, Bottom

This is the bottom of a perforated zone. This is measured from the wellhead to the perforation by measured depth.


Perforations, Mid Point (MPP)

A perforation is a method of making holes through the casing opposite a producing formation to allow the oil or gas to

flow into a well.

MPP is the depth from the wellhead to the Mid-Point of the Perforated interval. F.A.S.T. VirtuWell treats all flow

within the vertical wellbore as originating from this depth. When a "wellhead pressure" is converted to a "sandfacepressure" calculations are in fact done from the wellhead to MPP. The reverse is also true, when a "sandface

pressure" is converted to a "wellhead pressure" calculations are done from 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 calculated from the specified datum to the Wellhead.


Perforations, Top

Top - This is the top of a perforated zone. This is measured from the wellhead to the perforation by measured depth.


Pressure, Inlet

This is the pressure at the inlet to the pipe. It can be measured directly and used to calculate an outlet pressure, or

it can be calculated from a known outlet pressure. All pressures are in absolute (not gauge).

NOTE: If all necessary information has been entered and no inlet pressure has been calculated, parts of the


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information may be invalid. For example, the outlet pressure may be too low to compensate for the pressure drop in

the pipe and may cause the inlet pressure to be less than 0 which is physically impossible. For such a situation

the inlet pressure will be left blank.


Pressure, Liquid Lift

This is the pressure at which the minimum gas rate to lift water or condensate calculated. All pressures are in

absolute (not gauge).

HINT: As pressure increases, so does the minimum gas rate to lift water or condensate. Therefore, to determine the

minimum gas rate to lift water or condensate in a wellbore, it is recommended that the highest pressure in the

wellbore be used. This is typically the flowing sandface pressure. In his original work, Turner (1969) recommends tha

the wellhead pressure be used. In our research also supported by Lea Jr. (1983) we have found that generally, the

sandface pressure and not the wellhead pressure should be used to calculate the minimum gas rate to lift liquids.


Pressure, Outlet

This is the pressure at the outlet of the pipe. It can be measured directly and used to calculate the pressure at the

inlet to the pipe, or it can be calculated from a known inlet pressure. All pressures are in absolute (not gauge).

NOTE: If all necessary information has been entered and no outlet pressure has been calculated, parts of the

information may be invalid. For example, the inlet pressure may be too low to support the pressure drop in the pipe

and may cause the outlet pressure to be less than 0 which is physically impossible. For such a situation the outlet

pressure will be left blank.


Pressure, Reservoir

The stabilized shut-in pressure in the reservoir. This pressure is used to construct the Inflow Performance

Relationship (IPR) in the case of an oil well and the Absolute Open Flow (AOF) in the case of a gas well. On both

curves, the reservoir pressure corresponds to a flow rate of zero. For a well that is recently on production, the current

reservoir pressure may be taken to equal the initial pressure of the reservoir. For a well that has been on production

for a long time, the current reservoir pressure is less than the initial reservoir pressure. It may be determined from a

buildup test by extrapolating the shut-in pressures and taking into account the reservoir shape.


Pressure, Sandface

This is the pressure at the sandface (MPP) for a vertical well or at the Datum for a horizontal well. It is a flowing

pressure if the well is flowing and a shut-in pressure if the well is not flowing. It can be measured directly and used to

calculate a wellhead pressure, or it can be calculated from a known wellhead pressure. All pressures are in absolute

(not gauge).


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Pressure, Separator

The separator pressure is the pressure in the separator or at wellhead. It is used in the recombination calculations to

calculate the vapour equivalent of the condensate, the recombined gas rate and the recombined gas gravity.

UNITS: psia (kPaA) DEFAULT: 100 psia


Pressure, Shut In

This is the shut-in pressure at the wellhead or the sandface. This corresponds to the pressure when there is no flow

through the wellhead.


Pressure, Test

Often, an AOF is not available for a well. However, test flow rates and the corresponding flowing pressures are easily

obtainable. The SF/WH AOF page in F.A.S.T. Virtuwell will calculate an AOF given a test rate and pressure (either

at sandface or at the wellhead). Also necessary is the shut-in pressure of the well (from a Static Gradient) and a

value for n. The flowing test pressure must be in absolute (not gauge).


Pressure, Wellhead

This is the pressure at the wellhead. It is flowing pressure if the well is flowing and a shut-in pressure if the well is not

flowing. It is typically known from direct measurements or can be calculated from sandface. If known, it is used to

calculate the sandface pressure as well as to construct tubing performance curves. All pressures are in absolute (not

gauge).

NOTE: If all necessary information has been entered and no wellhead pressure has been calculated, parts of the

information may be invalid. For example, the sandface pressure may be too low to support the pressure drop in the

well and may cause the wellhead pressure to be less than 0 which is physically impossible. For such a situation

the wellhead pressure will be left blank.


Productivity Index (PI)

The Productivity Index is the flow rate per unit pressure drop. For example, if a well flows at 1000 STBD with a

flowing Sandface Pressure of 1500 psi, and the average reservoir pressure is 2000 psi, then the productivity index is

given by:


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P.I. = 1000 / (2000 - 1500) = 2 STBD/psi

The productivity index serves as an indication of the production potential of a well. For a well in an under-saturated

reservoir, the flow rate of the well can be estimated very simply from the productivity index as follows:

Flow Rate (STBD) = P.I. * Drawdown

where

Drawdown = Reservoir Pressure Flowing Sandface Pressure

For wells in saturated reservoirs or for gas wells, the relationship is not as straight forward, and the simple

relationship described above does not apply. Instead, for oil wells, we have to use the Inflow Performance

Relationship (IPR) formulation and for gas wells the Absolute Open Flow (AOF) deliverability equation.

UNITS: stbd/psi (sm^3/kPa) DEFAULT: 0

Rate, Oil

This is the daily oil or condensate rate. It is typically known from direct measurements. If the Gas-Oil Ratio or

condensate-gas ratio is available, it must be multiplied by the known daily gas rate to calculate the daily oil orcondensate rate. The oil rate is at stock tank conditions.

F.A.S.T. VirtuWell treats all flow within the vertical wellbore as originating from the MPP (Mid Point Perforations).


of the wellbore.

UNITS: bbl/d (m 3 /d) DEFAULT: 0

Rate, Recombined Gas

This is the Gas Rate used for pressure drop calculations in gas-condensate systems. It is a function of Condensate-

Gas Ratio, Condensate Gravity, Gas Gravity, Separator Temperature and Separator Pressure.

Rate, Test

Often, an AOF is not available for a well. However, test flow rates and the corresponding flowing pressures are easily

obtainable. The SF/WH AOF page in F.A.S.T. Virtuwell will calculate an AOF given a test rate and pressure (either

at sandface or at the wellhead). Also necessary is the shut-in pressure of the well (from a Static Gradient) and a

value for n. The gas rate must be at standard conditions (14.65 psia, 60 F / 101.325 Pa, 15 C).

In order to enter a test rate and pressure on the SF/WH AOF page, the Test Rate/Pressure radio button must be

selected.

Recombination

Most gas-condensate wells are in reality single-phase in the reservoir and in the majority of the wellbore. The

condensation of condensate from the gas takes place either at the separator or very near the wellhead. The

recombination is a calculation procedure which takes the volume of condensate, vapourizes it, adds it to the gas

volume to obtain the raw gas as it existed in the reservoir and the wellbore. For calculation purposes, this program

treats the wellbore calculations as single-phase calculations using the recombined gas gravity and the recombined

gas rate.


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where:

GRec= specific gravity of reservoir gas (recombined gas gravity)

G = specific gravity of separator gas (measured)

CGR = stock-tank-condensate/separator gas ratio, STB/MMscf

= oil specific gravity (not API gravity)

Qpa= additional gas production (vapour evolved at stock tank), scf/STB

Veq= vapor equivalent of stock tank liquid, scf/STB

where:

p = separator pressure (wellhead pressure), psia

T = separator temperature (wellhead temperature), F

= oil API gravity, API

The total wellstream gas flow rate, representing all gas and liquid produced at the surface can be calculated as

follows:

where:

qRec= total wellstream gas flow rate (recombined gas rate), MMscfd

qMeas= measured gas flow rate from separator, MMscfd

Reference:

Lee, John and Wattenbarger, Robert A.: Gas Reservoir Engineering, Society of Petroleum Engineers Inc.,

Richardson, TX, 1996, 11-15.

Recombined Rate Factor

This is the Recombined Gas Rate divided by the original gas rate. It can be found on the printouts when a gas-

condensate system is being modeled.

Roughness

This is defined as the distance from the peaks to the valleys in pipe wall irregularities. Roughness is used in the


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calculation of pressure drop due to friction. For clean, new pipe the roughness is determined by the method ofmanufacture 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 must be between 0 and 0.01 inches (0.254 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 fluidgravity or temperatures, as appropriate.

UNITS: in (mm) DEFAULT: 0.0006 in (0.01524 mm)

Solution Gas-Oil Ratio

This is the amount of gas dissolved in the oil at any pressure. It increases approximately linearly with pressure. It is

a function of the oil and gas composition. A heavy oil contains less dissolved gas than a light oil. In general, the

solution gas-oil ratio varies from 0 (dead oil) to approximately 2000 SCF/Bbl (very light oil). The solution gas-oil ratio

increases with pressure until the bubble point pressure is reached, after which it is a constant, and the oil is said to

be under-saturated.

The solution gas-oil ratio has a significant influence on the oil formation volume factor and the oil viscosity.

When a mixture of gas and oil is flowing in a pipe or wellbore, the actual quantity of "free gas" that is flowing

increases as the pressure of the gas-oil system decreases. This is due to gas "coming out of solution from the oil"

and becoming free gas, thus increasing the gas flow rate, and decreasing the oil flow rate. In the F.A.S.T.

VirtuWell program, the solution gas-oil ratio is used for accounting for the changes in the in-situ gas rate along the

pipe or wellbore.

The solution gas-oil ratio is readily obtained from laboratory PVT measurements, or as is done in the F.A.S.T.

VirtuWell program, it may be calculated from correlations such as "Vasquez and Beggs".

UNITS: SCF/Bbl (m 3 /m^3 ) DEFAULT: "Vasquez and Beggs" correlations

Static Conditions

Under single-phase conditions, pressures calculated for static (no flow) cases will be dependent only on the fluids

gravity and temperature. Multi-phase systems at static conditions make the assumption that only one fluid is

present. If the system contains gas, at static conditions it is assumed that the only fluid present is gas. Thus a

multi-phase static system containing gas will give the same results as a single-phase gas system. In an oil/water

system at static conditions (zero flow rates), the program will not calculate a pressure drop. In order to simulate

static conditions in this case, one fluid must be chosen preferentially over the other and modeled in a single-phase

system.

The Flow Efficiency and Roughness are not applied to static conditions. In this case, a match between measured

and calculated pressures may be obtained by adjusting the dominant fluid gravity or temperatures for the case being

considered.

Surface Tension

The surface tension (interfacial tension) between the gas and liquid phases has very little effect on two-phase

pressure drop calculations. However a value is required for use in calculating certain dimensionless numbers used in


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some of the pressure drop correlations. Empirical relationships for estimating the gas/oil interfacial tension and thegas/water interfacial tension were presented by Baker and Swerdloff, Hough and by Beggs.

Surface Tension, Gas/Water

The gas/water interfacial tension at temperatures of 74 F and 280 F is given by:

where:

= interfacial tension at 74 F (dynes/cm)

= interfacial tension at 280 F (dynes/cm)

p = pressure (psia)

If the temperature is greater than 280 F, the value at 280 F is used. If the temperature is less than 74 F, the value at

74 F is used. For intermediate temperatures, linear interpolation is used.


Temperature Gradient

A straight line temperature gradient is assumed for all calculations. This is considered to be a very reasonable

assumption in most circumstances.

Temperature, Inlet

This is the temperature at the inlet to the pipe. It is used in conjunction with the outlet temperature to calculate the

average temperature within the pipe. This has an effect on fluid density and viscosity, however the calculated

pressure drops are not very sensitive to small changes of this parameter. No distinction is made between flowing and

shut in temperatures.

UNITS: F ( C) DEFAULT: None

Temperature, Liquid Lift

This is the fluid temperature used when the minimum gas rate to lift water or condensate is being calculated.


Temperature, Outlet


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This is the temperature at the outlet of the pipe. It is used in conjunction with the Inlet Temperature to calculate the

average temperature within the pipe. This has an effect on fluid density and viscosity, however the calculated

pressure drops are not very sensitive to small changes of this parameter. No distinction is made between flowing and

shut in temperatures.


Temperature, ReservoirThe reservoir temperature (sometimes referred to as the formation temperature) increases with reservoir depth.

Locations around the world have different geothermal gradients.

Along with oil gravity, the reservoir temperature is probably the most significant variable in characterizing the PVT

and fluid properties of oil (surprisingly, the Hanafy et al correlation is independent of reservoir temperature).


Temperature, SandfaceThis 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.


Temperature, SeparatorThe separator temperature is the temperature in the separator or at wellhead. It is used in the recombination

calculations to calculate the vapour equivalent of the condensate, the recombined gas rate and the recombined gas

gravity.

UNITS: F (C) DEFAULT: 100 F

Temperature, Wellhead

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 (150F 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.


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Toe (MD)

This is the measured depth from the wellhead to the toe (end) of the horizontal well. The length of the horizontal

portion of the wellbore is the difference between the measured depth of the toe and the measured depth of the heel.

UNITS: Feet (m) DEFAULT: 0

Tubing Depth (EOT)

Tubing Depth defines the End of Tubing (EOT), relative to the wellhead. Tubing depth is required for flow through the

tubing, annulus or both options. It is ignored when flow is defined through the casing. As the F.A.S.T. VirtuWell

Wellbore module assumes wellbore flow originates at the Mid-Point of Perforations (MPP), flow from MPP to EOT wil

be through the casing if Tubing Depth is < MPP, and through the annulus if Tubing Depth > MPP. 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. As a result, where the tubing depth and the datum are positioned will affect the flow path of the fluid to the

wellhead.

UNITS: Feet (m)DEFAULT: None

Tubing ID

This is the inside diameter of the tubing used in the wellbore. This value is used to calculate the area of flow when

production is directed through the tubing. Complex tubing can be entered in the common wellbore problem tab.

NOTE: In the petroleum industry, the nominal tubing size refers to the outside diameter NOT the inside diameter. The

ID depends on the Tubing OD (outside diameter) and the weight (linear density) of the tubing.For Example:

2-3/8" tubing, (grade J-55, weight 4.70 lb/ft) has 1.995" ID and 2.375" OD.



UNITS: Inches (mm) DEFAULT: None

Tubing LengthLength of individual pieces of tubing in the wellbore.

Tubing OD

The Tubing OD is the Outer Diameter of the tubing used in the wellbore. This value is used along with the Casing ID

to calculate the area of flow when production is directed through the annulus. Complex tubing can be entered in the

common wellbore problem tab.

NOTE: In the petroleum industry, the nominal tubing size refers to the outside diameter of the tubing. The Tubing ID

(inside diameter) depends on the OD and the weight (linear density) of the tubing.


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UNITS: Inches (mm) DEFAULT: None

Tubing Performance Curve

For a given set of conditions (tubing size and flowing wellhead pressure), a Tubing Performance Curve (TPC) is a plot

of the flowing sandface pressure, required to sustain flow up the tubing, as a function of flow rate. This curve will not

change through the life of the well. It is not at all dependent upon well performance; it depends only upon the gas-

liquid ratio, tubular configuration (depth, diameter), wellhead pressures, etc. Tubing Performance Curves are

applicable for both oil and gas wells, for both vertical and horizontal wellbores.

F.A.S.T. Virtuwell allows the plotting of Tubing Performance Curves in conjunction with both Absolute Open Flow

(AOF) curves and Oil Inflow Performance Relationship (IPR) curves. The intersection of the AOF or IPR curve with a

TPC signifies the operating point of the particular wellbore/reservoir combination. Since both the Gas AOF/TPC and

the Oil IPR/TPC pages allow up to four (4) TPCs to be plotted at any one time, it is quite simple to investigate the

effect of various tubing diameters, gas-liquid ratios and flowing wellhead pressures on the operating point of a

particular wellbore/reservoir combination.

On the Gas AOF/TPC page, the minimum gas rate required to lift l iquids is calculated in conjunction with each

Tubing Performance Curve. It is represented on the tubing performance curve by a circle listing the number identifying

the tubing performance curve. To the right of the liquid lift rate, the tubing performance curve is a solid green line. Tothe left, it is a dotted red line. The solid green line represents stable flow, i.e. the wellbore will lift liquids

continuously. The dotted red line represents unstable flow. If the Tubing Performance Curve is a dotted red line over

the entire range of flow rates represented, the circled number is placed in the middle of the curve solely for

identification. The calculated liquid lift rates for each tubing performance curve are tabulated under Liquid Lift.

V2

This is the square of the velocity (V). The velocity is obtained by dividing the volumetric flow rate by the pipe cross-

sectional area. In multi-phase flow this is termed the "superficial velocity".

For a single phase liquid, V equals the liquid velocity.For a single phase gas, V varies with pressure, and the calculation must be done sequentially in small steps to allow

the velocity to vary with pressure.

For multi-phase flow, V is the superficial mixture velocity, which is calculated by prorating the superficial velocity of

each individual phase in the ratio of the "input" volume fraction and NOT of the "in-situ" volume fraction.

Velocity, Mixture

Mixture Velocity is another parameter often used in multiphase flow correlations. The mixture velocity is given by:

where:

Vm= mixture velocity

Vsl= superficial liquid velocity

Vsg= superficial gas velocity

Velocity, Superficial


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The superficial velocity of each phase is defined as the volumetric flow rate of the phase divided by the cross-

sectional area of the pipe (as though that phase alone was flowing through the pipe). Therefore:

and

where:


D = inside diameter of pipe

QG= measured gas flow rate (at standard conditions)

QL= liquid flow rate (at prevailing pressure and temperature)

Vsg= superficial gas velocityVSL= superficial liquid velocity

Since the liquid phase accounts for both oil and water:

and the gas phase accounts for the solution gas going in and out of the oil as a function of pressure:

( )

the superficial velocities can be rewritten as:

where: Qo= oil flow rate (at stock tank conditions)

Qw = water flow rate in (at stock tank conditions)

QG= gas flow rate (at standard conditions of 14.65psia and 60F)

QL= liquid flow rate (oil and water at prevailing pressure and temperature)

Bo= oil formation volume factor

Bw = water formation volume factor


Rs= solution gas/oil ratio

WC = water of condensation (water content of natural gas, Bbl/MMscf)

The oil, water and gas formation volume factors (Bo, Bw and Bg) are used to convert the flow rates from standard (or


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stock tank) conditions to the prevailing pressure and temperature conditions in the pipe.

Since the actual cross-sectional area occupied by each phase is less than the cross-sectional area of the entire pip

the superficial velocity is always less than the true in-situ velocity of each phase.

Vertical Flow Performance (VFP) Table

The vertical flow performance table of a well contains a set of tubing performance curves at different flowing

conditions. The curves are calculated based on specified ranges of flow rates, pressures, water fractions and gasfractions. The available parameters that can be selected are summarized in the following table:

FLOW RATE PRESSURE WATER FRACTION GAS FRACTION

Oil Tubing Head (THP) Water-Oil Ratio (WOR) Gas-Oil Ratio (GOR)

Gas Bottomhole (BHP) Water Cut (WCT) Gas-Liquid Ratio (GLR)

Water Water-Gas Ratio (WGR) Oil-Gas Ratio (OGR)

In order to create a vertical flow performance table, one of the pressures (either THP or BHP) needs to be selected

and the other pressure is solved covering all the possible combinations of the specified parameters. The resulting

file(s) can be used in simulation models to perform forecastings by doing interpolations on the generated data.

Viscosity, Gas

The viscosity of a fluid refers to the resistance to flow. It causes the pressure to drop in the direction of flow. It is

used in the calculation of the "friction pressure drop". For gas, the viscosity varies with gas gravity, temperature and

pressure. Usually it is not measured, but is obtained from the Carr, Kobayashi and Burrows correlations, which

include corrections for H2S, CO2and N2. For sour gases, this correlation is preferred to the Lee, Gonzalez and

Eakin formulation (which does NOT account for H2S, CO2and N2).

Viscosity enters into the definition of Reynolds Number, which is used to obtain the friction factor from the Fanning

friction factor charts.

Typically, gas viscosity is in the range of 0.015 to 0.03 centipoise (cp).

UNITS: cp (mPa.s) DEFAULT: Carr, Kobayashi and Burrows Correlations

Viscosity, Mixture

The mixture viscosity is a measure of the in-situ viscosity of the mixture and can be defined in several different ways.

In general, unless otherwise specified, mis defined as follows.

where:

EL= in-situ liquid volume fraction (liquid holdup)

EG= in-situ gas volume fraction

m= mixture viscosity

L= liquid viscosity

G= gas viscosity


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NOTE: The mixture viscosity is defined in terms of in-situ volume fractions (E L), whereas the no-slip viscosity is

defined in terms of input volume fractions (CL).

UNITS: cp (mPa.s) DEFAULT: None

Viscosity, No-Slip Mixture

The "no-slip" viscosity is the viscosity that is calculated with the assumption that both phases are moving at the

same in-situ velocity. There are several definitions of "no-slip" viscosity. In general, unless otherwise specified, NS

is defined as follows.

where:

CL= input liquid volume fraction

CG= input gas volume fraction

NS=no-slip viscosity

L= liquid viscosity

G= gas viscosity

UNITS: cp (mPa.s) DEFAULT: None

Viscosity, Oil

This is the value of the oil viscosity at in-situ conditions. It is a very strong function of temperature, API Gravity

(Stock Tank Oil Density) and Solution Gas-Oil Ratio.

Below the bubble point pressure, the amount of gas dissolved in the oil increases as the pressure is increased. This

causes the in-situ oil viscosity to decrease significantly. Above the bubble point pressure, oil viscosity increases

minimally with increasing pressure.

The oil viscosity can be measured as a function of pressure in most PVT laboratory measurements. In the F.A.S.T.

VirtuWell program it is calculated from the correlation of "Beggs and Robinson" at the appropriate pressure and

temperature. These correlations are very sensitive to solution gas-oil ratio and to oil gravity. The oil viscosity can vary

from 10 000 cp for a heavy oil to less than 1 cp for a light oil.

The oil viscosity has a very strong effect on the friction pressure loss, but no effect on the hydrostatic pressure loss.

UNITS: cp (mPa.s) DEFAULT: "Beggs and Robinson" correlation

Water Cut

This is the water produced at surface as a percentage of the total liquids produced at surface. It is typically known

from direct measurements. If the daily water rate is known, it must be divided by the daily total liquid rate (oil +

water) to obtain the water cut.


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If IPR information has been given, the water cut is calculated from the instantaneous (and varying) oil/water rates

obtained from their respective IPRs to construct the Tubing Performance Curves.

UNITS: % DEFAULT: 0

Water Rate

This is the daily water rate. It is typically known from direct measurements. If the water cut or Water-gas ratio isknown, it must be multiplied with the daily total liquid or gas rate to calculate the daily water rate. The water rate is

at stock tank conditions.

F.A.S.T. VirtuWelltm treats all flow within the vertical wellbore as originating from the MPP (Mid Point Perforations).


of the wellbore.

References:

Carr, N. L., R. Kobayashi and D. B. Burrows (1954). Viscosity of Hydrocarbon Gases under Pressure, Tans., AIME,

201, 264-272.

UNITS: Bbl/d (m 3 /d) DEFAULT: 0

Copyright 2013 Fekete Associates Inc

glossary(some basic definitions)

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