Correlation
Year
Cat
Lockhart & Martinelli
1949 b
Poettmann & Carpenter Baxendall & Thomas
1952 a
Fancher & Brown Hagedorn & Brown
type of study laboratory, experimental
orientation
pipe sizes
validity oil, gas cond. pipelines
Horizontal
.06-1
field data
Vertical
2, 2.5, 3
oil wells
1961 a 1963 a
field data field, experimental
Vertical Vertical
2.5, 3, 3.5 2
1963 b
field, experimental
Vertical
1, 1.25, 1.5
oil wells oil wells oil, gas cond. wells
Gray
b
Vertical
< 3.5
gas cond. condensate wells
Gray Modified
b
Vertical
< 3.5
gas cond. condensate wells
Duns & Ros
1963 c
laboratory, experimental
Vertical/ Deviated
1.5, 2, 2.5, 3
Orkiszewski
1967 c
field, experimental
Vertical
1, 1.5, 2, 3
Beggs & Brill Revised
1975 c
laboratory, experimental
all
1, 1.5
Beggs & Brill Original
1973 c
laboratory, experimental
all
1, 1.5
oil, gas cond. wells, pipelines
Mukherjee & Brill
1979 c
laboratory, experimental
all
1.5
oil, gas cond. wells, pipelines
Govier, Aziz& Forgasi
1972 c, m
theoretical
Vertical/ Deviated
-
gas cond. wells
all
-
all
-
Vertical
-
NoSlip theoretical, experimental theoretical, experimental
OLGA-S
2005 c
Ansari
1989 c
BJA for Condensates
1988 c, m
theoretical, experimental
Horizontal/ Inclined
-
1955 b
field, experimental
Horizontal/ Inclined
-
1955,6 b 8
field, experimental
Horizontal/ Inclined
-
Dukler AGA & Flanigan Dukler AGA & Flanigan (Eaton holdup)
theoretical tuned to field data
Horizontal/ Inclined Horizontal/ Inclined Vertical/ Deviated
Oliemans
1976 c, m
Xiao
1990 c, m
Kaya
1999 c, m
theoretical
Zhang (TUFFP Unified)
2002 c, m
theoretical
all
-
Petalas & Aziz
2000 c, m
theoretical
all
-
Hasan & Kabir
1986 c, m
theoretical
Vertical/ Deviated
Other Correlations
-
5
oil, gas cond. wells oil, gas cond. wells oil, gas cond. wells, pipelines
oil, gas cond. wells, pipelines oil, gas cond. wells, pipelines oil, gas cond. wells gas cond. condensate pipelines oil, gas cond. pipelines oil, gas cond. pipelines oil, gas cond. pipelines oil, gas cond. pipelines oil, gas cond. wells oil, gas cond. wells, pipelines oil, gas cond. wells, pipelines oil, gas cond. wells
Category "a": No slip, no flow pattern consideration. The mixture density is calculated based on the input GLR. Gas and li factor. No distinction made for flow patterns
Category "b": Slip considered, no flow pattern considered. A correlation is required for both liquid holdup and friction facto provided to predict the portion of pipe occupied by liquid at any location. The same correlations used for liquid holdup and
Category "c": Slip considered, flow patten considered. Not only are correlations used to predict liquid holdup and friction f is established, the appropriate holdup and friction factor correlations are determined. The method used to calculate the ac Category "m": Mechanistic model solves the combined mommentum equation for both phases
Remarks based on data from a number of investigators using a variety of luids 2-3" tubing; GLR < 1500 scf/stb; QL > 420 BPD Tuned Poetmann Carpenter to match Lake Maracaibo field data Extended Peottmann Carpenter for higher GLR, lower rate wells data from 1500' experimental well. Used wide range of liquid viscosities valid for velocities < 50 ft/s; d < 3.5"; LGR < 5 bbl/mmscfd as above but uses actual reynolds number (Gray assumes 1 million) developed from large no. lab datapoints used field data and Hagedorn Brown data. New method for slug flow only mainly applicable to inclined flowlines. Tends to overestimate pressure loss & holdup for low loading cases 2 revisions: 1) an extra flow regime of froth flow is considered which assumes a no-slip holdup, (2) the friction factor is changed from the standard smooth pipe model, to utilise a single phase friction factor based on the average fluid velocity. mainly applicable to inclined flowlines; used higher viscosity test fluids than Beggs & Brill Revised Orkiszewski extensions of Griffith Wallace data assumes homogeneous gas-liquid mixture. Uses mixture fluid properties and single phase friction factor correlation Revised annually. Based on extensive research performed on the Sintef flowloop in Norway. Considered by many to be the most accurate and generalized model Generalized mechanistic model for upwards vertical flow in wells. Good performance in comparative studies Revised Taitel Duker model for stratified flow in pipelines tends to overestimate pressure loss same as above, but with Eaton correlation for holdup based on a limited amount of data from a 30-in, 100-km pipeline operating at pressures of 1500 psi or higher generalized mechanistic model generalized mechanistic model generalized mechanistic model generalized mechanistic model tuned mechanistic model mainly for directional wells
n the input GLR. Gas and liquid assumed to travel at the same velocity. Correlation is only for a 2-phase friction
uid holdup and friction factor. Because the liquid and gas can travel at different velocities, a method must be s used for liquid holdup and flow pattern are used for all flow patterns
liquid holdup and friction factor, but methods to predict which flow patterns exist are necessary. Once flow pattern hod used to calculate the acceleration pressure gradient also depends on flow pattern
