hydraulics & line sizing

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 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




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:




• 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.




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.




• 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




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/(1442

V∆P

21

22 LPgV

frictavg ×∆+×

−=

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.




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.




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




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




Table 2 - Vapor and Gas Flow Line Sizing Criteria


Service psi/100 ft ft/s Remarks 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.




Table 3 - Two Phase Flow Line Sizing Criteria


Service psi/100 ft ft/s Remarks 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/ft3.




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.




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)




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




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




Figure 3 - Thermosyphon Reboiler Circuit Hydraulic Calculations OPERATING COMMONS - INLET OPERATING CONDITIONS - OUTLET Temperature. oF _________ Temperature. oF ___________ 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 ___________




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)

6. ∆P (reboiler) allowed * safety factor (______), psi ________ 7. Total line friction loss (fi+fo) * safety factor (______), psi ________ 8. Static head in return line, Ft = h2 ________ 9. Static head in return line, psi = h2 * ρ3 / 144 ________

10. Total resistance to flow (Pr2), psi = #6 + #7 + #9 ________

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.




Figure 4 - Kettle Type Reboiler Circuit Hydraulic Calculations OPERATING CONDITIONS - INLET OPERATING CONDITIONS - OUTLET Temperature, oF ________ Temperature, oF ________ 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 ________





CALCULATE RESISTANCE TO FLOW (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 ________

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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