GPSA ENGINEERING DATABOOK ERRATA
(2004 SI Edition)
PAGE DESCRIPTION
3-1 Figure 3-1, Change units for LTB
4-18 Figure 4-24, Missing text
4-22 Figure 4-32, Change 0.082 to 0.82
5-18 Equation 5-27, Corrected
6-23 Figure 6-26, Missing text
7-1 Figure 7-1, Change figure reference
7-4 Figure 7-5, Correct equation
7-14 Figure 7-21, Correct figure title
12-1 Figure 12-1, Change figure reference for k
12-12 Figure 12-13, Replaced
12-13 Figure 12-14, Replaced
12-16 Figure 12-17, Missing text
13-8 Figure 13-10, Missing text
13-15 Example 13-3, Change figure reference
18-16 Figure 18-14, Missing text
19-2 Figure 19-1, Missing text
20-21 Example 20-10, Change 1.68 to 16.8
21-7 Figure 21-5, Correct viscosity for MDEA
21-26 Desorex text, Correct units
23-26 Change CO2 in text
23-36 Example 23-11, Change text
24-40 Figure 24-37, Missing text
25-10 Methane-Ethane Binary, Change x-axis scale
SECTION 3
Measurement
The information presented in this section provides sufficient
information for determining flow quantities with a reasonable
degree of accuracy, but not necessarily to the accuracy desired
for custody transfer. Agreement of acceptable accuracy for cus-
tody transfer should be between the parties involved, and sup-
plemental information and procedures may be required, such
as the API Manual of Petroleum Measurement Standards or
corresponding ISO standards.
C = Pitot tube flow coefficient
C` = the product of multiplying all orifice correction
factors
CNT = volume indicated by the number of pulses or
counts
Cpl = liquid pressure correction factor. Correction for
the change in volume resulting from application
of pressure. Proportional to the liquid compressi-
bility factor, which depends upon both relative
density and temperature.
Cps = correction factor for effect of pressure on steel.
See API Manual of Petroleum Measurement
Standards, Chapter 12, Section 2
Cg = gravity correction factor for orifice well tester to
change from a gas relative density of 0.6
Ctl = liquid temperature correction factor. Proportional
to the thermal coefficient which varies with den-
sity and temperature
Cts = correction factor for effect of temperature on steel
Cu = velocity of sound in the gas non-flowing
condition.
d = orifice diameter, mm
D = internal pipe diameter of orifice meter
run or prover section, mm
DL = Minimum downstream meter tube length, mm
Dp = the difference between the flowing pressure and
the equilibrium vapor pressure of the liquid.
Du = diameter of the meter bore.
R = flowing fluid density, kg/m3
e = orifice edge thickness, mm
E = orifice plate thickness, mm
Em = modulus of elasticity for steel [(206.8)(10
6)] kPa
F = liquid compressibility factor
Fa = orifice thermal expansion factor. Corrects for the
metallic expansion or contraction of the orifice
plate. Generally ignored between –20°C and 50°C
Fg = relative density factor applied to change from a
relative density of 1.0 (air) to the relative density
of the flowing gas
Fgt = gravity-temperature factor for liquids
Fc = orifice calculation factor
Fn = numeric conversion factor
Fna = units conversion factor for pitot tubes
Fpb = pressure base factor applied to change the base
pressure from 101.55 kPa (abs)
Fpm = pressure factor applied to meter volumes to cor-
rect to standard pressure. See API Manual of
Petroleum Measurement Standards, Chapter 12,
Section 2
Fpv = supercompressibility factor required to correct
for deviation from the ideal gas laws = @@@@ 1�Z
Fs = steam factor
Fsl = orifice slope factor
Ftb = temperature base factor. To change the tempera-
ture base from 15°C to another desired base
Ftf = flowing temperature factor to change from the
assumed flowing temperature of 15°C to the ac-
tual flowing temperature
Ftm = temperature correction factor applied to displace-
ment meter volumes to correct to standard tem-
perature. See API Manual of Petroleum
Measurement Standards, Chapter 12, Section 2
G,G1 = specific gravity at 15°C
Gf = specific gravity at flowing temperature
H = pressure, mm of mercury
hm = differential pressure measured across the orifice
plate in mm of mercury at 15°C
hw = differential pressure measured across the orifice
plate in mm of water at 15°C
@@@@@ hwPf = pressure extension. The square root of the differen-
tial pressure times the square root of the abso-
lute static pressure
k = ratio of the specific heat at constant pressure to
the specific heat at constant volume
K = a numerical constant. Pulses generated per unit
volume through a turbine, positive displacement,
coriolis or ultrasonic meter
Key = Fn (Fc + Fsl) = orifice factor
L = distance between upstream and downstream
transducer.
LTB = Length of tube bundle, in flow conditioner, mm
(See Fig. 3-3)
MF = meter factor, a number obtained by dividing the
actual volume of liquid passed through the meter
during proving by the volume registered by the
meter
P = pressure, kPa (abs)
FIG. 3-1
Nomenclature
3-1
Fig. 4-23 gives relative controller gain, integral time, and
derivative time for the various control mode combinations for
quarter-decay response as related to ultimate controller gain
setting, Ku, and ultimate period Pu. Gain settings are also
shown in units of proportional band, PB.
Fig. 4-24 shows some typical settings for various types of
process controllers.
Example 4-2 — An example using the Ziegler-Nichols method
is given below:
For a certain temperature control system, the ultimate sen-
sitivity Ku was found to be 1.5 kPa per °C, and the ultimate
period Pu was found to be two minutes. A three mode PID con-
troller is required.
Using Fig. 4-24:
Proportional gain Kp:
Kp = 0.6 Ku = 0.6 (1.5 kPa/°C) = 0.9 kPa/°C
Integral time constant Ti:
Ti = Pu/2, Ti = 2/2 = 1.0 minute
Derivative time constant Td:
Td = Pu/8, Td = 2/8 = 0.25 minutes
Control Mode Considerations
The process control engineer has the responsibility for
matching the many and variable characteristics of the process
to be controlled with the most effective control hardware avail-
able.6 Fig. 4-25 provides guidelines for choosing the mode of
control for various types of applications based upon the proc-
ess reaction rate and size and speed of load changes.
Special considerations should be made in applying a “split-
range” controller. A common example is a column temperature
controller on a cryogenic demethanizer. In this system the first
half (0-50%) of the controller output actuates the “free” heat ex-
change with the incoming feed, and the second half (50-100%) of
the controller output actuates the supplemental heat from the hot
oil system. Adaptive gain control may be required since the heat-
ing value of the hot oil is much greater than that of the gas used
in the heat exchange.
EMBEDDED ADVANCED CONTROL
Embedded advanced control will usually give an improved
plant performance over that achievable with traditional tech-
niques. By introducing Embedded Advanced Control, a high
level of reliability and security is provided to maximize control
system uptime. Since embedded advanced control tools have
direct access to controller I/O, they may access process meas-
urements and actuators with no communication jitter or delay.
This allows use of these tools on the fastest processes.
CONTROL VALVES
Selecting the proper control valve for each application in-
volves many factors. The valve body design, actuator style, and
plug characteristic are critical items for selection.Proper valve
sizing is necessary for accurate, efficient, economical process
control. In areas where personnel will be affected, noise pre-
diction and control becomes a significant factor.
Engineering application guidelines, nomographs, and equa-
tions presented in the following pages may be used to deter-
mine the correct control valve configuration, size and flow
characteristics, and to predict noise levels for most applica-
tions. The material presented here may also be used to evalu-
ate the performance of valves installed in existing plants.
The equations given in this section are used to calculate the
flow coefficient (Cv or Cg) required for a valve to pass the re-
FIG. 4-22
Typical Responses Obtained When Determining Ultimate
Gain and Ultimate Period
Mode Kp or PB(%) Ti Td
(P) 0.5 Ku 2(PBu) max. zero
(PI) 0.45 Ku 2.2(PBu) Pu/1.2 zero
(PD) 0.6 Ku 1.65(PBu) max. Pu/8.0
(PID) 0.6 Ku 1.65(PBu) Pu/2.0 Pu/8.0
FIG. 4-23
Ziegler-Nichols Settings for 1/4 Decay Response1
4-18
Process Gain PB(%)
Integral Derivative
Ti (sec) min/repeat Td (sec)
Flow 0.6-0.8 167-125 3.0-1.8 0.05-0.03 0.0
Pressure 5.0 20.0 120-60 2.0-1.0 0.0
T
Level
emp. 1.0-2.0
0.8-1.2
100-50
125-83
120-30
600-300
2.0-0.5
10.0-5.0
6.0-12
0.6-1.2
FIG. 4-24
Typical Controller Settings
with the listed Cv should then be used in the chosen siz-
ing equation to calculate a revised, required Cv. This it-
eration process continues until the calculated Cv and
equals the manufactuer’s listed Cv.
4. For a new valve selection a valve size is typically chosen
such that the maximum, calculated Cv is close to 75% to
85% of valve travel.This allows for process variability while
maintaining flow capability. The minimum, calculated Cv
should typically occur at or about 10% of valve travel.
5. Fp is the Piping Geometry Factor. It corrects the sizing
equations for the effects of fittings such as reducers and
expanders that are attached to the valve body ends. Fp
values can be determined via test or calculated per the
ANSI/ISA S75.01 standard. If the valve has no such fit-
tings attached, e.g., the nominal value size and nominal
pipe size are the same, then Fp = 1.0. Refer to the full
standard for the Fp calculations in cases where fittings
do exist.
Other valve configurations, such as ball and butterfly valves,
can be sized in a similar manner using the unique Xc and Cv
values derived by the manufacturers.
Valve
Style
Body Size,
mm
Flow Characteristic
raeniLegatnecrePlauqE
Globe
Cv Xc FL Cv Xc FL
25 8 0.74 0.88 17 0.61 0.84
38 17 0.69 0.84 30 0.70 0.82
50 25 0.70 0.85 62 0.68 0.77
63 49 0.66 0.84 84 0.71 0.81
75 66 0.66 0.82 118 0.70 0.82
100 125 0.67 0.82 181 0.74 0.82
150 239 0.74 0.85 367 0.78 0.84
200 268 0.60 0.85 526 0.74 0.87
Ball
25 16 0.53 0.86 – – –
50 59 0.53 0.81 – – –
75 120 0.50 0.80 – – –
100 195 0.52 0.80 – – –
150 340 0.52 0.80 – – –
200 518 0.54 0.82 – – –
250 1000 0.47 0.80 – – –
300 1530 0.49 0.78 – – –
Butterfly
50 60 0.37 0.69 – – –
75 111 0.40 0.69 – – –
100 238 0.40 0.69 – – –
150 635 0.40 0.69 – – –
200 1020 0.40 0.69 – – –
250 1430 0.40 0.69 – – –
300 2220 0.40 0.69 – – –
350 2840 0.40 0.69 – – –
400 3870 0.40 0.69 – – –
*At approximately 70% of valve travel. Maximum valve capacity may be estimated using the values given in this
figure in conjunction with Fig. 4-29. For a more detailed analysis of capacity capabilities of a given valve at other
percentages of travel, consult the valve manufacturer’s data.
FIG. 4-32
Typical Cv, Xc� and FL Values for Valves*
4-22
Spherical Radiation Intensity Formula:
I �
�Wf �NHV �E
14.4 P �R2
Eq 5-20
This equation has been found to be accurate for distances as
close to the flame as one flame length.
Equation 5-20 is valid so long as the proper value of fraction
of heat radiated, E, is inserted. Classically, E has been consid-
ered a fuel property alone. Brzustowski et al.10 experimentally
observed a dependence of E on jet exit velocity. Other authors
have presented models that consider the carbon particle con-
centration in the flame. The fraction of heat radiated is a func-
tion of many variables including gas composition, tip diameter,
flare burner design, flowrate and velocity, flame temperature,
air-fuel mixing, and steam or air injection; therefore a flare
supplier should be consulted to determine the specific values
for a given application. A list of vendor recommended fraction
of heat radiated values for the most frequently flared gases is
shown in Fig. 5.20.
To calculate the intensity of radiation at different locations,
it is necessary to determine the length of the flame and its
angle in relation to the stack (see Fig. 5-21). A convenient ex-
pression to estimate length of flame, Lf, is shown below, based
on information from equipment suppliers.
Lf � �0.12 �d @@@$Pw1400 Eq 5-21
or from API 521
Lf � 2.14 � Qr u 10
6 0.474 Eq 5-22
For conventional (open pipe) flares, an estimate of total flare
pressure drop is 1.5 velocity heads based on nominal flare tip
diameter. The pressure drop equivalent to 1 velocity head is
given by:
$Pw �
�0.102 R V2
2
�
R V2
19.62
Eq 5-23
$Pw is the pressure drop at the tip in mm of water. After de-
termining tip diameter, d, using Eq 5-23, and the maximum
required relieving capacity, flame length for conditions other
than maximum flow can be calculated using Eq 5-21 and Eq
5-22.
Common practice is to use tip velocities of up to Mach 0.5
for short term emergency flows and Mach 0.2 for maximum
continuous flowing.
d � � @@@@@@@@@ 3.23 u 10
5 u WP2 u M u ¤¥¦ Z u Tk u MW³´µ
0.5 u1000 Eq 5-24
Sonic velocity of a gas is given by:
a � @@@@k RoMW T Eq 5-25
The center of the flame is assumed to be located at a distance
equal to 1/3 the length of the flame from the tip.
The angle of the flame results from the vectorial addition of
the velocity of the wind and the gas exit velocity.
Q � tan
1
¤
¥
¦
Vw
Vex
³
´
µ
Eq 5-26
Vex � 168@@$PW1400 Eq 5-27
Note: API gives a greater lean angle
The coordinates of the flame center with respect to the tip
are:
Xc � �Lf � 3 �sin Q Eq 5-28
Yc � �Lf �3 �cos Q Eq 5-29
The distance from any point on the ground level to the center
of the flame is:
R � @@@@@@@@@@@@@@@ �X
Xc 2 � �Hs � Yc 2 Eq 5-30
Q
Lf
yC
XC
d
HS + YC R
X - XC
X
HS
WIND
Courtesy American Petroleum Institute
FIG. 5-21
Dimensional References for Sizing a Flare Stack
Carbon Monoxide 0.075
Hydrogen 0.075
Hydrogen Sulfide 0.070
Ammonia 0.070
Methane 0.10
Propane 0.11
Butane 0.12
Ethylene 0.12
Propylene 0.13
The maximum value of E for any gas is 0.13.
FIG. 5-20
Fraction of Heat Radiated Values for Flared Gases
5-18
6-23
Diam.
of
Sphere
Depth of Liquid, meters
meters 0.5 1 2 4 6 8 10 12 14 16 18 20 25 30 35 40 45 50
0.5 0.065 –
1 0.262 0.524 –
2 0.654 2.094 4.189 –
4 1.440 5.236 16.755 33.510 –
6 2.225 8.378 29.322 83.776 113.097 –
8 3.011 11.519 41.888 134.041 226.194 268.082 –
10 3.796 14.661 54.454 184.307 339.292 469.144 523.598 –
12 4.581 17.802 67.021 234.572 452.389 670.206 837.757 904.778 –
14 5.367 20.944 79.587 284.837 565.486 871.268 1 151.916 1 357.167 1 436.754 –
16 6.152 24.086 92.153 335.103 678.583 1 072.329 1 466.075 1 809.556 2 052.505 2 144.66 –
18 6.938 27.227 104.720 385.368 791.681 1 273.391 1 780.234 2 261.945 2 668.257 2 948.91 3 053.63 –
20 7.723 30.369 117.286 435.634 904.778 1 474.453 2 094.393 2 714.334 3 284.009 3 753.15 4 071.50 4 188.79 –
25 9.687 38.223 148.702 561.297 1 187.521 1 977.107 2 879.791 3 845.306 4 823.388 5 763.77 6 616.19 7 330.38 8 181.22 –
30 11.650 46.077 180.118 686.961 1 470.264 2 479.762 3 665.188 4 976.279 6 362.767 7 774.39 9 160.88 10 471.97 13 089.96 14 137.16 –
35 13.614 53.931 211.534 812.625 1 753.007 2 982.416 4 450.586 6 107.251 7 902.146 9 785.01 11 705.56 13 613.56 17 988.69 21 205.73 22 449.28 –
40 15.577 61.785 242.950 938.288 2 035.750 3 485.071 5 235.983 7 238.223 9 441.525 11 795.62 14 250.25 16 755.15 22 907.43 28 274.31 32 070.40 33 510.29 –
45 17.541 69.639 274.366 1 063.952 2 318.493 3 987.725 6 021.381 8 369.196 10 980.904 13 806.24 16 794.94 19 896.74 27 816.16 35 342.89 41 691.52 46 076.65 47 712.90 –
50 19.504 77.493 305.781 1 189.615 2 601.237 4 490.379 6 806.778 9 500.168 12 520.283 15 816.86 19 339.63 23 038.33 32 724.90 42 411.47 51 312.64 58 643.01 63 617.20 65 449.79
FIG. 6-26
Partial Volumes of Spheres — Cubic Meters
Tank Width,
m
Tank Length, m
1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0
0.5 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00
1.0 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00
1.5 1.50 3.00 4.50 6.00 7.50 9.00 10.50 12.00
2.0 2.00 4.00 6.00 8.00 10.00 12.00 14.00 16.00
2.5 2.50 5.00 7.50 10.00 12.50 15.00 17.50 20.00
3.0 3.00 6.00 9.00 12.00 15.00 18.00 21.00 24.00
3.5 3.50 7.00 10.50 14.00 17.50 21.00 24.50 28.00
4.0 4.00 8.00 12.00 16.00 20.00 24.00 28.00 32.00
4.5 4.50 9.00 13.50 18.00 22.50 27.00 31.50 36.00
5.0 5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00
5.5 5.50 11.00 16.50 22.00 27.50 33.00 38.50 44.00
6.0 6.00 12.00 18.00 24.00 30.00 36.00 42.00 48.00
6.5 6.50 13.00 19.50 26.00 32.50 39.00 45.50 52.00
7.0 7.00 14.00 21.00 28.00 35.00 42.00 49.00 56.00
7.5 7.50 15.00 22.50 30.00 37.50 45.00 52.50 60.00
8.0 8.00 16.00 24.00 32.00 40.00 48.00 56.00 64.00
8.5 8.50 17.00 25.50 34.00 42.50 51.00 59.50 68.00
9.0 9.00 18.00 27.00 36.00 45.00 54.00 63.00 72.00
9.5 9.50 19.00 28.50 38.00 47.50 57.00 66.50 76.00
10.0 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00
10.5 10.50 21.00 31.50 42.00 52.50 63.00 73.50 84.00
11.0 11.00 22.00 33.00 44.00 55.00 66.00 77.00 88.00
11.5 11.50 23.00 34.50 46.00 57.50 69.00 80.50 92.00
12.0 12.00 24.00 36.00 48.00 60.00 72.00 84.00 96.00
1 cu meter = 264.172 U.S. gal.
= 219.9692 Imperial gallons
= 6.2898 bbls (42 U.S. gals)
FIG. 6-27
Approximate Contents (Cubic Meters) of Rectangular Tanks Per Meter of Liquid*
SECTION 7
Separation Equipment
PRINCIPLES OF SEPARATION
Three principles used to achieve physical separation of gas
and liquids or solids are momentum, gravity settling, and coa-
lescing. Any separator may employ one or more of these prin-
ciples, but the fluid phases must be "immiscible" and have dif-
ferent densities for separation to occur.
A = area, m2
Ap = particle or droplet cross sectional area, m
2
C = empirical constant for separator sizing, m/h
C* = empirical constant for liquid-liquid separators,
(m3 u mPa u s)/(m2 u day)
C` = drag coefficient of particle, dimensionless (Fig. 7-3)
Di = separator inlet nozzle diameter, mm
Dp = droplet diameter, m
Dv = inside diameter of vessel, mm
Gm = maximum allowable gas mass-velocity necessary
for particles of size Dp to drop or settle out of gas,
kg/(h u m2)
g = acceleration due to gravity, 9.81 m/s2
Hl = width of liquid interface area, m
J = gas momentum, kg/(m u s2)
K = empirical constant for separator sizing, m/s
KCR = proportionality constant from Fig. 7-5 for use in
Eq 7-5, dimensionless
L = seam to seam length of vessel, mm
Ll = length of liquid interface, mm
M = mass flow, kg/s
Mp = mass of droplet or particle, kg
MW = molecular mass, kg/(kg mole)
P = system pressure, kPa(abs)
Q = estimated gas flow capacity, (Sm3/day)/m2
of filter area
QA = actual gas flow rate, m
3/s
R = gas constant, 8.31 [kPa(abs) u m3]/[K u kg mole]
Re = Reynolds number, dimensionless
Shl = relative density of heavy liquid, water = 1.0
Sll = relative density of light liquid, water = 1.0
T = system temperature, K
t = retention time, minutes
U = volume of settling section, m3
Vt = critical or terminal gas velocity necessary for
particles of size Dp to drop or settle out of gas, m/s
W = total liquid flow rate, m3/day
Wcl = flow rate of light condensate liquid, m
3/day
Z = compressibility factor, dimensionless
Greek:
Rg = gas phase density, kg/m3
Rl � liquid phase density, droplet or particle, kg/m3
M = viscosity of continuous phase, mPa u s
Filter Separators: A filter separator usually has two com-
partments. The first compartment contains filter-coalescing
elements. As the gas flows through the elements, the liquid
particles coalesce into larger droplets and when the drop-
lets reach sufficient size, the gas flow causes them to flow
out of the filter elements into the center core. The particles
are then carried into the second compartment of the vessel
(containing a vane-type or knitted wire mesh mist extrac-
tor) where the larger droplets are removed. A lower barrel
or boot may be used for surge or storage of the removed
liquid.
Flash Tank: A vessel used to separat