line sizing-mustang.pdf

DG-PPG-0110
Document No.
Process Plants Process Design
Guidelines: Hydraulics and Line Sizing
Department Guidelines
Rev. 0
REVISION and APPROVALS
Rev. Date Description By Approved
0 01JUL04 Initial Issue JAP EP
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Document is valid only at time of printing. See myMustang® for latest revision.
DG-PPG-0110_Process Plants Process Design Guidelines Hydraulics and Line Sizing Page 1 of 20

DG-PPG-0110
Document No.
MUSTANG
Process Plants Process Design Guidelines:
Hydraulics and Line Sizing Rev. 0
TABLE OF CONTENTS
1.0 SCOPE..........................................................................................................................................3
2.0 HYDRAULICS CALCULATION....................................................................................................3
2.1 Pressure Drop Criteria.......................................................................................................3
2.2 Equivalent Length of Valves and Fitting ............................................................................3
2.3 Flow Regimes of Vapor-Liquid Mixed Phase Flow............................................................3
3.0 LINE SIZING CRITERIA ...............................................................................................................3
4.0 PRELIMINARY ESTIMATE OF EQUIVALENT LENGTH ............................................................4
4.1 Pump Discharge and Compressor Circuit .........................................................................4
4.2 Reboiler Inlet or Return Lines............................................................................................5
4.3 Pump Suction Line from Drums or Tower Bottoms ...........................................................5
5.0 SPECIAL HYDRAULICS CALCULATIONS.................................................................................5
5.1 Thermosyphon Reboiler Circuits .......................................................................................5
5.2 Kettle Reboiler Circuits......................................................................................................6
5.3 Pump NPSH and Pump Hydraulics Calculations ..............................................................6
5.4 Vacuum Tower Transfer Line Sizing .................................................................................6
APPENDICES...........................................................................................................................................8
Appendix A: References ..............................................................................................................8
Appendix B: Tables......................................................................................................................9
Table 1 - Liquid Flow Line Sizing Criteria....................................................................................10
Table 2 - Vapor and Gas Flow Line Sizing Criteria .....................................................................11
Table 3 - Two Phase Flow Line Sizing Criteria ...........................................................................12
Appendix C: Figures...................................................................................................................14
Figure 1 - Baker Chart, Flow Regimes of Two Phase Flow in Horizontal Pipes .........................15
Figure 2 - Aziz Chart, Flow Regimes of Two Phase Up-Flow in Vertical Pipes ..........................16
Figure 3 - Thermosyphon Reboiler Circuit Hydraulic Calculations..............................................17
Figure 4 - Kettle Type Reboiler Circuit Hydraulic Calculations....................................................19

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1.0 SCOPE
This section outlines the general guidelines for hydraulic calculation of piping systems. It is
intended to provide a consistent approach to hydraulic calculations as performed by Process
Engineers / Technical Professionals, but not to cover every special case one may encounter.
Guidelines for calculating pressure drop through equipment such as trays, packings and
reactors are included in other guidelines.
2.0 HYDRAULICS CALCULATION
Mustang has several line sizing programs available in myMustang®. Refer to the Sizing page
within the Process portal. Regardless of the program or method selected, there are
independent variables to consider.
2.1 Pressure Drop Criteria
Absolute Roughness Factor: use 0.00015 ft for commercial steel pipe. For non-steel
pipe, use factors given in the Fluid Flow section of the GPSA Engineering Data Book [2].
Pipe Age Factor: use 1.2 unless noted otherwise in the design basis for a specific
project.
For vapor-liquid mixed phase, the Hughmark "in-place” density may be used, where
available as an option, for calculating static head.
2.2 Equivalent Length of Valves and Fitting
Use the table shown as Figure 17-4 in the GPSA Engineering Data Book [2].
Spreadsheet templates which use average L/D ratios and yield essentially the same
equivalent lengths may also be used. Optionally, Crane No. 410 [1] provides equations
for calculating valve and fitting losses as velocity head equivalents.
2.3 Flow Regimes of Vapor-Liquid Mixed Phase Flow
• Horizontal flow: Use Baker chart shown in Figure 1.
• Vertical flow: Use the Aziz Chart, Figure 2, via Reference 2. This figure is
considered to be conservative and valid for pressure up to 150 psig, which covers
the range of concern.
3.0 LINE SIZING CRITERIA
Tables 1, 2, and 3 in Appendix B give some typical "rules of thumb" for line sizing. Although
these rules are applicable to most situations, they may not be suitable in all cases. For critical
circuits, hydraulics should be checked in detail to confirm the available pressure drop regardless
of whether the lines meet rules-of-thumb criteria. In addition, the optimum line size is
determined by balancing the capital cost of the piping system against the operating cost of
pumps and/or compressors. To minimize initial investment, special attention should be given to
expensive lines, for example:

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• Alloy pipe
• Carbon steel pipe larger than 12”
• Piping system involving many valves and fitting such as dryers
• Lines longer than 500 ft
In corrosive and erosive environments, however, the line shall be sized based on maximum
velocity considerations to provide satisfactory service life. When a new or unfamiliar service is
encountered, the Process Design Manager shall be consulted for line sizing criteria as well as
its material selection.
4.0 PRELIMINARY ESTIMATE OF EQUIVALENT LENGTH
The following data can be used for preliminary estimates of equivalent length when detail piping
information, such as isometrics, is not available.
4.1 Pump Discharge and Compressor Circuit
Piping Size, inches
On-site
L eq./L straight
Off-site
L eq./L straight
1-1/2 1.30 1.09
2 1.41 1.14
3 1.57 1.18
4 1.74 1.23
6 2.12 1.36
8 2.43 1.42
10 2.82 1.55
12 3.15 1.65
14 3.41 1.74
16 3.75 1.83
18 4.14 1.92
20 4.51 2.06
24 5.19 2.24
These typically conservative equivalent length ratios (to be used for budget estimates)
only are estimated based on the following assumptions:
• For on-site systems: each 100 feet of piping having one fully open gate valve, one
swing check valve, one hard tee and four long radius elbows.
• For offsite systems: each 100 feet of piping with one fully open gate valve and four
long radius elbows.

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4.2 Reboiler Inlet or Return Lines
Pipe Size, inches Typical Equivalent Length, ft
4 100
6 120
8 140
10 160
12 180
14 200
16 220
18 250
20 280
24 330
30 420
If the reboiler is spring supported, the equivalent length can be substantially reduced.
4.3 Pump Suction Line from Drums or Tower Bottoms
Pipe Size, inches Typical Equivalent Length, ft
through 6" 300
8" – 12” 400
14" and larger 250 pipe diameters + 150
Notes:
• If a permanent strainer is installed in the pump suction line, add 200 ft of equivalent
length to calculate the pressure drop through the strainer. If a temporary strainer is
used, the Process Engineer / Technical Professional should clarify with client if it will
stay in place during normal operation.
• The equivalent length for pump suction taken from a tower side draw-off can be
substantially higher than those shown above.
5.0 SPECIAL HYDRAULICS CALCULATIONS
5.1 Thermosyphon Reboiler Circuits
The worksheet shown on Figure 3 should be used to analyze the reboiler circuit
hydraulics for thermosyphon reboilers. Design considerations for the thermosyphon
reboiler system are as follows:
• Do not use the usual age factor of 1.2 for line friction loss. Instead, use a safety
factor of 2 for line friction loss and allowable total reboiler pressure drop when using
homogenous mixed phase density and a safety factor of 1.5 when using Hughmark
in-place density, whichever is more conservative. The criteria may be relaxed for
revamp projects or those systems having high densities in the reboiler return line
such as a deethanizer tower reboiler.

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MUSTANG
• Use the percent vaporization specified in the reboiler data sheet. Recirculating
thermosyphon reboilers are generally designed for 30 wt% vaporization.
Once-through thermosyphon reboilers can have up to 50 wt% vaporization.
• Process Engineer / Technical Professional should check the actual operating
pressure of the reboiler if the mean temperature difference between the heating
medium and circulation fluid is sensitive to pressure variation. The pressure of the
boiling medium in the thermosyphon reboiler is equal to the tower operating pressure
plus riser losses including static head based on in-place density.
• The reboiler return line should be sized to avoid slugging problems. However, this
may not always be possible without an excessive elevation of skirt height, especially
for light ends towers operated at high pressure. It is generally recognized that towers
operated above a certain operating pressure (subject to engineering judgment), slug
flow may not exist or is not detrimental to a reboiler/tower operation.
5.2 Kettle Reboiler Circuits
The worksheet shown on Figure 4 should be used for hydraulic calculations associated
with kettle reboiler circuits. Design considerations for the kettle reboiler system are as
follows:
• Use a safety factor of 1.5 for line friction loss and allowable total reboiler pressure
drop.
• If the product from the kettle reboiler flows to a pump suction, the elevation of kettle
should also satisfy pump NPSH requirement.
• If the product from the kettle reboiler flows to a heat exchanger first, free drain from
the kettle to exchanger is preferred. This is not a mandatory requirement if the
product is of multi-component mixtures with wide boiling ranges. However, the pipe
length and elevation rise shall be minimized.
5.3 Pump NPSH and Pump Hydraulics Calculations
Refer to “Pumps" [3] for calculation guidelines and procedures.
5.4 Vacuum Tower Transfer Line Sizing
Transfer lines in crude vacuum units are typically very large and are constructed of
expensive alloy material. It is imperative that the process designer perform a detailed
hydraulic calculation to select the smallest line size.
The maximum velocity should be limited to 90% of sonic velocity. It usually occurs at the
inlet nozzle to the vacuum tower. Sonic velocity is expressed as:
VS = 68.1(kP/ρ)1/2
VS sonic velocity, ft/s
k the specific heat ratio, Cp/Cv
P the absolute pressure, psia
ρ the homogeneous mixed phase density, lb/ft3
The total pressure drop from the heater outlet to the tower inlet is limited by the heater
outlet temperature, which is typically 25°F higher than the flash zone temperature and

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should generally be limited to 780°F maximum due to the concern of excessive cracking
and coking.
The design of the transfer line may proceed as follows:
• Starting at the flash zone condition, run a series of adiabatic flashes on the vacuum
tower charge, with a pressure increment of approximately 25% of the downstream
absolute pressure.
• Select the transfer line size based on the sonic velocity limitation stated above.
• Divide the line into several segments. Calculate or estimate the equivalent length of
each segment.
Start from the tower inlet nozzle, calculate the pressure drop in each line segment
using the following equation:
100
)
100
/
(
144
2
V
∆P
2
1
2
2 L
P
g
V
frict
avg
×
∆
+
×
−
=
ρ
Acceleration Loss Friction Pressure Drop
∆P total pressure drop, psi
V1 upstream velocity, ft/s
V2 downstream velocity, ft/s
(∆P/100)frict friction pressure drop, psi/100 ft
L total equivalent length, ft
g 32.2 ft/s2
Pavg average mixed phase density, lb/ft3
The acceleration loss in vacuum service can be a significant part of the total
pressure drop and should not be neglected. Since the amount of flashing depends
on the pressure, the above calculations are iterative.
• The pressure drop between the heater outlet and flash zone (typically 3 psi) is the
sum of the pressure drops for all line segments. The heater outlet temperature can
then be obtained from the pressure-temperature relationship which is generated from
the adiabatic flashes in step (a).
• If the calculated heater outlet temperature exceeds the allowable maximum, a larger
transfer line is selected and steps a. through d. are repeated until the temperature
limitation is satisfied. It should be noted that this rarely occurs unless the transfer
line is unusually long or the flash zone temperature already approaches the
maximum allowable temperature.
• If the calculated heater outlet temperature is more than 10°F lower than the
allowable maximum, a reduction in the line size between the tower and furnace may
be justified. The Process Engineer / Technical Professional should check the sonic
velocity criteria at the point of line size reduction.

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APPENDICES
Appendix A: References
[1] “Flow of Fluids through Valves, Fittings, and Pipe,” Crane Technical Paper No. 410,
1988.
[2] “Fluid Flow and Piping,” GPSA Engineering Data Book, 10th ed., 1987, Section 17,
Volume II.
[3] “Process Plants Process Design Guidelines: Pumps”, Mustang Department Guidelines,
DG-PPG-0107.
[4] KYPIPE User's Manual.
[5] "Centrifugal Compressor Inlet Piping - A Practical Guide," Elliott Compressor, Reprint No.
117.

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Appendix B: Tables
Table No. Title
1 Liquid Flow Line Sizing Criteria
2 Vapor and Gas Flow Line Sizing Criteria
3 Two Phase Flow Line Sizing Criteria

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Table 1 - Liquid Flow Line Sizing Criteria
Typical
Pressure Maximum
Drop Velocity
Service psi/100 ft ft/s Remarks
1. Pump suction (General Service)
a) Liquid at boiling point or 0.5 max. 3 (4" & smaller) 3.0 ft/s max. for vacuum tower bottoms
less than 50°F below it 5 (6”-10") pump regardless of sizes.
6 (12" & larger)
b) Sub-cooled liquids 2.0 max. 8 Higher than 8 ft/s is acceptable if there is
(50°F below boiling point) substantial length of straight pipe
(5 times of pipe dia.) just ahead of the pump
suction.
2. Side stream draw-off 0.2 max. (Note 1)
3. Liquid to non-pumped reboiler 0.2 (Note 1) The allowable pressure drop (psi/100ft)
can be higher if larger elevation difference
is available.
4. Gravity flow (in waste water 0.5 max. 2.5 ft/s min. The available liquid head
treating unit, etc.) should be at least two times the friction
loss calculated based on piping layout.
5. Pump discharge (Gen. Service) 4.0 max. 15 (Note 2)
6. Cooling water
Short lead 2.0 max. 15 The velocity should be above
Long header 1.0 max. 15 3 ft/s to prevent excessive fouling.
7. Corrosive liquids
Sulfuric acid service 3.0 (C.S.) (Note 3)
in Alky Unit 6.0 (316 S.S.)
“ 8.0 (Alloy 20)
Rich amine (liquid phase) 5.0 (C.S.) (Note 4)
Lean amine 7.0 (C.S.)
Caustic (lower than 140°F) 5.0 (C.S.)
8. Erosive liquids
FCC slurry 7 3 ft/s min. to prevent settling of catalyst
fines.
9. High available delta P 5.0 max 20 Should consider erosion and possible
vaporization.
10. Sea water in concrete 10.0
lined pipe

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Table 2 - Vapor and Gas Flow Line Sizing Criteria
Typical
Pressure Maximum
Drop Velocity
1. Column overhead and condenser rundown
For tower operated under high vacuum
10 mmHg abs. 0.01 100/(ρ)
1/2
condition, calculation based on piping
50 mmHg abs. 0.05 or 300 ft/s layout is required. Typically, the pressure
380 mmHg abs. 0.1 whichever is drop between tower and ejector in crude
Atmospheric - 50 psig 0.2 lower. vacuum column overhead is 1-2 mmHg.
50 psig - 150 psig 0.4 Higher ∆P/100 ft may be used for towers
150 psig + 0.6 operated at high pressure and line
pressure drop only constitutes ≤ 0.5% of
operating pressure.
2. Oil vapors
10 mmHg abs. 0.01 100/(ρg)
1/2
or
50 mmHg abs. 0.06 300 ft/s
380 mmHg abs. 0.2 whichever is
Atmospheric - 50 psig 0.5 lower.
50 psig - 150 psig 1.5
150 psig + 2.5
3. Steam
0 - 50 psig headers 0.5 100/( ρg)
1/2
or
laterals 1.5 300 ft/s
150 psig headers 1.0 whichever is
laterals 2.5 lower.
300 psig+ headers 2.5
laterals 4.0
4. Condensing Steam Turbine 450 Calculation based on exhaust piping
layout is required. Typically, the
pressure drop between turbine and
first condenser is 0.2 psi for air
cooled condenser and 0.1 psi for
water cooled condenser. In many
cases, the line size is governed by
velocity limitation.
5. Kettle Reboiler Return 0.1 - 0.2
6. Compressor Suction
Reciprocating (Note 5) For multistage compressors, the usual
allowable interstage pressure drop
Centrifugal (Note 6) exclusive of pulsation dampers
Is the larger of 5 to 7 psi or 1% of
system absolute pressure for a single
exchanger, separator and associated
piping. Increase the pressure drop if
there is additional equipment.
7. FCC Reactor Vapor 0.2 max. 100 Higher velocity results in excessive
to Fractionator erosion from catalyst fines.
8. Column Hot Vapor Bypass 0.5 Typically, the flowrate of hot vapor
bypass ranges from 10 to 15% of gross
column overhead vapor flowrate.
Process Engineer to confirm the
flowrate based on heat transfer calculation.

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Table 3 - Two Phase Flow Line Sizing Criteria
Typical
Pressure Maximum
Drop Velocity
1. Thermosiphon Reboiler Return 0.1-0.2 Can be higher if large elevation
difference is available. See Section
5.1 for other considerations.
2. Other Two-Phase Lines
10 mmHg abs. 0.01 Max. velocity Except crude vacuum tower
50 mmHg abs. 0.06 is 100/(ρmix)
1/2
transfer line where the
380 mmHg abs. 0.02 or 300 ft/s maximum velocity is
Atmospheric - 50 psig 0.5 whichever is discussed in Section 5.4.
50 - 150 psig 1.5 lower. ρmix is
150 psig + 2.5 the homogeneous
mixed density
in lb/ft
3
.

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Notes for Tables 1, 2, and 3:
1) Saturated liquid draw-off from vessel should be adequately sized to avoid vaporization and vortexing
at the draw-off nozzle. The maximum allowable velocity is calculated as
Vmax = 3.858 (hmin)½
or hmin = (Vmax / 3.858)2
Vmax : maximum allowable velocity through the draw-off nozzle, ft/s
hmin : the liquid static head above the centerline of draw-off nozzle, ft
Equation for Vmax is valid only when the liquid head is at least one-half of the nozzle diameter above
the top edge of draw-off nozzle. The depth of draw-off sump should be a minimum of 1½ times the
nozzle diameter. See Mustang Process Design Guidelines, Section B, Towers.
The line should turn down immediately and should be a minimum of 6 ft vertical drop before being
swaged down to calculated line sizes.
2) Process engineer should confirm the total pressure drop based on actual piping or plot layouts
especially if high ∆P/100 ft is used to size long lines.
3) Typically, the acid strength ranges from 93% to 99% in the Alky unit. Selection of piping materials
depends on factors including size, velocity, flow turbulence and temperature. Consult with a Sr. level
Process Engineer about the material selection and allowable velocity criteria. For further details, see
Mustang Process Design Guidelines, Section M, Materials of Construction.
4) Stainless steel pipe is commonly used in areas where acid gas is flashed out of rich amine solution.
However, for long runs, heavy wall carbon steel pipe may be used in lieu of stainless steel.
5) The line size and piping layout may be dictated by the compressor acoustic analog study.
6) If inlet and discharge nozzles are oriented normal to compressor shaft and there are three diameters
of straight pipe just ahead of compressor inlet, the maximum velocity in the inlet is
Vmax = (995 T/M)1/2
Vmax : maximum allowable velocity in the suction of centrifugal compressor, ft/s
T : inlet temperature, OR
M : gas molecular weight
Vmax will be lower if the inlet line has less than three pipe diameters of straight run pipe. A review of
inlet piping systems as related to compressor performance is presented in Reference 5.
7) In general, the vapor-liquid mixed phase line should be sized to avoid the slug flow. Wherever this
becomes impractical and results in excessive pressure drop, a Sr. level Process Engineer should be
consulted.

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Appendix C: Figures
Figure No. Title
1 Baker Chart, Flow Regimes of Two Phase Flow in Horizontal Pipes (1 page)
2 Aziz Chart, Flow Regimes of Two Phase Up-Flow in Vertical Pipes (1 page)
3 Thermosyphon Reboiler Circuit Hydraulic Calculations (2 pages)
4 Kettle Type Reboiler Circuit Hydraulic Calculations (2 pages)

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Figure 1 - Baker Chart, Flow Regimes of Two Phase Flow in Horizontal Pipes

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Figure 2 - Aziz Chart, Flow Regimes of Two Phase Up-Flow in Vertical Pipes

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Figure 3 - Thermosyphon Reboiler Circuit Hydraulic Calculations
OPERATING COMMONS - INLET OPERATING CONDITIONS - OUTLET
Temperature. o
F _________ Temperature. o
F ___________
Pressure, psig _________ Pressure, psig ___________
Liquid density. ρ1, @T. lb/ft3
_________ Avg. L/V mixed density, ρ2 @T&P, lb/ft3
___________
Flow, Liq- lb/h _________ Inplace density, ρ3 @T&P. lb/ft3
___________
Flow. Liq., lb/h ___________
Flow. Vap., lb/h ___________
LINE FRICTION LOSS - INLET LINE
FRICTION LOSS - OUTLET
Line size, in _________ Line size. In ___________
∆P per 100 ft. psi _________ ∆P per 100 ft, psi ___________
Equiv. length. ft _________ Equiv. length. Ft ___________
Friction loss (fil), psi _________ Friction loss (fol). Psi ___________
Tower nozzle loss (fin). psi _________ Tower nozzle loss (fon). Psi ___________
Total inlet press. drop fi=fil+fin. Psi _______ Total outlet press. drop fo=fol+fon. Psi ___________

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CALCULATE RESISTANCE TO FLOW
A. RESISTANCE CALCULATION BASED ON AVG. MIXED DENSITY (NOTE 2)
1. ∆P (reboiler) allowed * safety factor (______), psi ________
2. Total line friction loss (fi+fo) * safety factor (______), psi ________
3. Static head in return line, Ft = h2 ________
4. Static head in return line, psi = h2 * ρ2 / 144 ________
5. Total resistance to flow (Pr1), psi = #1 + #2 + #4 ________
B. RESISTANCE CALCULATION BASED ON IN-PLACE DENSITY (NOTE 2)
CALCULATE DRIVING FORCE
1. Required driving head (h3) based on avg. density, ft = (2.31 * Pr1) / ( ρ1 / 62.37) ________
2. Required driving head (h4) based on in-place density, ft = (2.31 * Pr2) / (ρ1 / 62.37) ________
3. Actual driving head available (h1), ft ________
4. If h1 is > h3 and h4. it is O.K. ________
Notes:
1. It should be confirmed with the equipment engineer that the ∆P allowed for reboiler shall be from
inlet nozzle flange to outlet nozzle flange, including static head.
2. For a new unit, use a safety factor of 2.0 based on average mixed density, and 1.5 based on in-
place density.

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Figure 4 - Kettle Type Reboiler Circuit Hydraulic Calculations
OPERATING CONDITIONS - INLET OPERATING CONDITIONS - OUTLET
Temperature, o
F ________ Temperature, o
F ________
Pressure, psig ________ Pressure, psig ________
Liquid density, ρ1, @T. lb/ft3
________ Vapor density. ρ2, @T. lb/ft3
________
Flow, Liquid lb/h ________ Flow, Vapor lb/h ________
LINE FRICTION LOSS INLET LINE FRICTION
LOSS - OUTLET
Line size, In. ________ Line size, In. ________
∆P per 100 ft, psi ________ ∆P per 100 ft, psi ________
Equiv. Length, ft ________ Equiv. Length, ft ________
Friction loss (fil), psi ________ Friction loss (fol), psi ________
Tower nozzle loss (fin), psi ________ Tower nozzle loss (fon), psi ________
Total inlet press. drop fi = fil+fin, psi ________ Total inlet press. drop fo = fol+fon, psi ________

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CALCULATE RESISTANCE TO FLOW (NOTE 2)
CALCULATE DRIVING FORCE
1. Required driving head (h), ft = (2.31 * Pr) / ( ρ1 / 62.37) ________
2. Actual driving head available (h1), ft ________
3. If h1 is > h, it is O.K. ________
Notes:
1. It should be confirmed with equipment engineer that ∆P allowed for reboiler shall be from inlet
nozzle flange to outlet nozzle flange.
2. For new unit, use safety factor of 1.5

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