Introduction
This is one of the most recommended and used equations for this type of flow, being able to estimate with high precision flow and pressure drop values if pipe roughness is known with correctness. It has been used for comparison among the different flow equations as a reference basis because it is fundamental to the definition of the corresponding application ranges and errors.
Similar to the Colebrook Equation, the AGA Equation uses a slightly modified transmission factor in order to obtain a value for the pressure drop using the General Flow Equation. The transmission value for the AGA equation is the following: F=4\log_{10}\biggr(\frac{3.7D}{k}\biggr)
F=4\log_{10}\biggr(\frac{3.7D}{k}\biggr)
This equation is also known as the Von Karman equation for rough pipe flow.
πΉ β Transmission Factor
π β Pipe Roughness
π· β Internal Diameter (in)
Q=C_Q(4\log_{10}3.7D-4\log_{10}k )(\frac{T_b}{P_b})D^{2.67}\biggr[ \frac{P_1^2-e^sP_2^2}{GT_fL_eZ} \biggr]^{0.5}
Q=C_Q(4\log_{10}3.7D-4\log_{10}k )(\frac{T_b}{P_b})D^{2.67}\biggr[ \frac{P_1^2-e^sP_2^2}{GT_fL_eZ} \biggr]^{0.5}
π β Flow Rate (FT3/day)
πΆπ β 38.774
ππ βTemperature Base (Β°R)
ππ β Pressure Base (psia)
ππ β Gas Flowing Temperature (Β°R)
π· β Internal Diameter (in)
π β Pipe Roughness
π1 β Upstream Pressure (psig)
π2 β Downstream Pressure (psig)
πΊ β Gas Specific Gravity
π β Compressibility Factor
Le β Pipe Segment Length including Expansion (mi)
ππ β Gas Flowing Temperature (Β°R)
s=\frac{C_S\triangle HG}{T_fZ}
s=\frac{C_S\triangle HG}{T_fZ}
π β Elevation adjustment parameter
πΆπ β 0.0375
π β Compressibility Factor
ππ β Gas Flowing Temperature (Β°R)
βπ»πΊ β Change in Elevation (ft)
L_e=\frac{(e^s-1)}{s}
L_e=\frac{(e^s-1)}{s}
πΏπ β Pipe Segment Length including Expansion (mi)
π β Elevation adjustment parameter
V=0.75\frac{Q_h}{D^2P_{avg}}
V=0.75\frac{Q_h}{D^2P_{avg}}
π β Velocity (ft/sec)
πβ β Volumetric flow rate (scf/hr)
π· β Internal Diameter (in)
πππ£π β Average Pipeline Pressure (psia)
For Small Pressure Drop P2 > 0.8 P1:
P_{avg}=\frac{(P_1-P_2)}{2}
P_{avg}=\frac{(P_1-P_2)}{2}
For Large Pressure Drop:
P_{avg}=\frac{2}{3}\biggr[ P_1+P_2-\frac{P_1P_1}{P_1+P_2} \biggr]
P_{avg}=\frac{2}{3}\biggr[ P_1+P_2-\frac{P_1P_1}{P_1+P_2} \biggr]
Case Guide
Part 1: Create Case
- Select the AGA Fully Turbulent Flow application in the Hydraulics module.
- To create a new case, click the βAdd Caseβ button.
- Enter Case Name, Location, Date and any necessary notes.
- Fill out all required parameters.
- Make sure the values you are inputting are in the correct units.
- Click the CALCULATE button to overview results
Input Parameters
- Temperature base(Β°F)
- Pressure base(psia)
- Gas Flowing Temperature(Β°F)
- Gas Specific Gravity
- Compressibility Factor
- Pipeline Efficiency Factor
- Upstream Pressure(psig)
- Downstream Pressure(psig)
- Flow Rate(MSCFH)
- Internal Pipe Diameter(in)
- Length of Pipeline(mi)
- Upstream Elevation(ft)
- Downstream Elevation(ft)
Downstream Pressure
Flow Rate
Internal Pipe Diameter
Upstream Pressure
Part 2: Outputs/Reports
- If you need to modify an input parameter, click the CALCULATE button after the change.
- To SAVE, fill out all required case details then click the SAVE button.
- To rename an existing file, click the SAVE As button. Provide all case info then click SAVE.
- To generate a REPORT, click the REPORT button.
- The user may export the Case/Report by clicking the Export to Excel icon.
- To delete a case, click the DELETE icon near the top of the widget.
Results
- Downstream Pressure(psig)
- Flow Rate(ft/sec.)
- Internal Pipe Diameter(in)
- Upstream Pressure(psig)
- Transmission Factor
- Velocity(ft/sec.)
- Erosional Velocity(ft/sec.)
- Sonic Velocity(ft/sec.)
Downstream Pressure
Flow Rate
Internal Pipe Diameter
Upstream Pressure
References
- McAllister, E. W., βPipeline Rules of Thumbβ Gulf Professional Publishing, Seventh Edition
- Menon, Shahi E., βGas Pipeline Hydraulicsβ, Systek Technologies, Inc.
- Carroll, Landon and Hudkins, Weston R., βAdvanced Pipeline Designβ
- American Gas Association (AGA), βReference: Eq-17-18, Section 17, GPSAβ, Engineering Data Book, Eleventh Edition
FAQ
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Purging is a process of removing gas from the pipeline. Controlled purging of gases from pipelines by direct displacement with other gases that have been safely practiced for many years with the recognition that some flammable mixture is present. Purging of gases from pipelines by direct displacement with another gas also has been similarly practiced. It works both ways; however, there will always be an atmosphere of type of a mixture. This is due to the densities of the gases. Check Out
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Pipe erosion begins when velocity exceeds the value of C/SQRT(Ο) in ft/s, where Ο = gas density (in lb./ft3) and C = empirical constant (in lb./s/ft2) (starting erosional velocity). We used C=100 as API RP 14E (1984). However, this value can be changed based on the internal conditions of the pipeline. Check Out
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The maximum possible velocity of a compressible fluid in a pipe is called sonic velocity. Oilfield liquids are semi-compressible, due to dissolved gases. Check Out