NorCraft Software
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ISO-5167: 2003 Orifice Calculations
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(Free of Charge - Adobe Reader Required) |
Programs AGA (AGA-3) and
The programs let you calculate the following orifice-types:
- Gas Orifice
- Liquid Orifice
- Restriction Orifice - Gas
- Restriction Orifice - Liquid
For gas-calculations you have to enter specific gas gravity, temperature and pressure. You can also give mole-fractions of N2, CO2 and H2S for sour gas calculations.
The AGA-8 equation is used for calculating Z-factor (compressibility factor) for natural gases, and the Redlich-Kwong equation of state for air and nitrogen.
For oil-calculations you have to enter specific oil gravity, temperature and pressure. It is also recommended to give molecular weight of oil. For water-calculations the input requirements are salinity, temperature, and pressure.
NOTE: It is assumed that all dissolved solids for water are expressed as equivalent sodium chloride concentration.
The results are an orifice specification sheet giving the necessary data for design of an orifice or evaluating an existing orifice.
The results will contain a few factors that you should know:
The velocity of approach factor is defined as:
Ev = 1/(Sqrt(1-Beta^4))
The flow coefficient, Alpha, is defined as:
Alpha = Ev * Cd
and orifice to pipe diameter ratio is given as:
Beta = OD/PID
The basic flow equation is:
Qv = Fn*(Fc+Fsl)*Y1*Fpb*Ftb*Ftf*Fgr*Fpv*Sqrt(Pf1*hw)
where
Fn = Numeric conversion factor
Cd = Discharge coefficient = (Fc + Fsl)
Fc = Orifice calculation factor
Fsl= Slope factor
Y1 = Expansion factor based on upstream tap
Fpb= Pressure base factor, set to 1.0 (14.73 psia)
Ftb= Temperature base factor, set to 1.0 (60 deg F)
Ftf= Flowing temperature factor
Fgr= Specific gravity factor
Fpv= Super-compressibility factor
Pf1= Absolute flowing pressure based on upstream tap
hw = Orifice differential pressure, in H2O at 60 deg F
The above equation is often simplified to:
Qv = C' * Sqrt(Pf1*hw)
where C' is called the Composite orifice flow factor.
For other factors and the factors for pipe taps you are advised to consult the standard
The basic flow equation is:
Qm = C*E*Eps*Pi/4*OD^2*Sqrt(2*dP*Roh)
where
Qm = Mass flow rate (kg/s)
C = Discharge coefficient = Alpha/E
E = Velocity of approach factor = 1/(Sqrt(1-Beta^4))
Eps = Expansion factor due to pressure drop
Pi = 3.14159
OD = Orifice diameter at actual flowing conditions
dP = Differential pressure across orifice
Roh = Density of flowing fluid measured at upstream tap
For other factors consult the standard
WatGas calculates Water-Natural gas phase behavior, and includes the following types of calculations:
- Hydrate formation calculations
- Water content predictions of natural gases
- Inhibitor quantities (methanol/glycols) to avoid hydrate problems in pipelines
The program handles gases with known compositions and non-compositional gases (only gas gravity is needed). Note that the compositional model is more reliable than the non-compositional model, although they give similar results.
Almost all gases contain some water vapor. When leaving the producing formation, gas is saturated with water vapor, which is in equilibrium with reservoir liquid water at temperatures and pressures prevailing there.
Knowing the water content of natural gases is essential to the design and operation of production, dehydration and transmission systems. Water may condense in production and gathering systems. This may result in hydrate formation and plugging of flow systems and damage to internals of production equipment.
Condensed water may form water slugs, which will tend to decrease flow efficiency and increase the pressure drop in a line. Presence of free water in pipeline systems may also cause corrosion. If carbon dioxide and/or hydrogen sulfide are present, the gases may form carbonic acid and sulphurous acid respectively if dissolved in water.
Oil properties are calculated based on a black-oil model. In fluid-property terms the black-oil model employs 2 pseudo-components:
1) "OIL" defined as produced oil at stock tank conditions
2) "GAS" defined as produced separator gas
The basic assumption is that gas may dissolve in the oil phase, but oil will not dissolve in the gas phase. For mixtures of heavy oil and light components this is a reasonable assumption, but is a misleading assumption for mixtures of light and intermediate components.
The following fluids are included:
Gases:
- Natural gas
- Nitrogen
- Air
Liquids:
- Oil
- Water
- Methanol/Water mixtures
- Monoethylene glycol/Water mixtures
- Diethylene glycol/Water mixtures
- Triethylene glycol/Water mixtures
GOWProp will let you choose between SI-units (metric) or Customary units.
The gas property routine calculates:
- Molecular weight
- Density
- Compressibility
- Gas formation volume factor
- Z-factor (gas deviation factor)
- Viscosity
- Thermal conductivity
- Specific heat
- Ideal isentropic coefficient, Cp/Cv
- Real isentropic coefficient, k
- Pseudo Critical properties
- Pseudo Reduced properties
The liquid property routine calculates:
- API gravity (for oil only)
- Density
- Compressibility
- Formation volume factor (oil and water only)
- Solution gas-liquid ratio (oil and water only)
- Bubble point pressure (oil only)
- Viscosity
- Thermal conductivity
- Surface tension
- Specific heat
- Pseudo Critical properties
- Pseudo Reduced properties