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3-Phase H-Calc
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violation of any rights of another person or entity.
Due to the inability to control the user inputs and future use, the user accepts all responsibility for the
calculated results and any equipment sold and manufactured based on those results.
This program is licensed to:
Sandstone Engineering
This program uses GPSA Engineering Data Book, 12th Edition, Design and Engineering Practices, and guidance
from publications by Manning, Thompson, and Svrcek to calculate 3-phase horizontal separator sizing.
User can input values into the Light Blue shaded cells. Program indicates acceptable checks with Green text or
shaded cells, and deficiencies with Red text.
This program was designed by Ryan K. Malone, P.E. for Sandstone Engineering and is licensed to customers for
a fee through a licensing agreement.
Version 1.0.1 - 101214 Developed by Sandstone Engineering, Ryan K. Malone, P.E.
3-Phase H-Calc
Project:
Client:
Job Number: Tag No:
General Notes:
Project Notes:
Rev.
1
2
3
4
5
Maximum Design Temp/Press °F psig °F psig
Operating Temp/Press °F psig °F psig
Atmospheric Temp/Press °F psig °F psig
Bulk Fluid Description
Fluid Flowrate
Oil API Gravity API API
Fluid Specific Gravity SG 1.076 SG SG SG 1.076 SG SG
Fluid Viscosity, μ
Gas MW
Compressibility/Density Correction, Z
Standard Fluid Flowrate #DIV/0! ft3/s #DIV/0! ft3/min - ft3/min #DIV/0! ft3/s #DIV/0! ft3/min - ft3/min
Actual Mass Flowrate #DIV/0! lb/s #DIV/0! lb/hr - lb/hr #DIV/0! lb/s #DIV/0! lb/hr - lb/hr
Fluid Density #DIV/0! lb/ft3- lb/ft3
- lb/ft3#DIV/0! lb/ft3
- lb/ft3- lb/ft3
Inlet Gas/Liquid Density at Operating Press and Temp, rm lb/ft3 lb/ft3
Inlet Liquid Density at Operating Press and Temp, rL #DIV/0! lb/ft3###### lb/ft3
Required Slug Capacity: BBL Required Slug Capacity: BBL
Direct Fired Allowable Liquid Level: % Allowable Liquid Level: %
Burner Tube: 3-Phase Liquid Retention Time: min 3-Phase Liquid Retention Time: min
Leff/D: Leff/D:
Burner Tube Nominal Diameter: NPS Burner Tube Nominal Diameter: NPS
Burner Tube Outside Diameter: #N/A in Burner Tube Outside Diameter: #N/A in
Burner Tube Total Length: ft Burner Tube Total Length: ft
Burner Tube Volume: #N/A ft3Burner Tube Volume: #N/A ft3
Mist Extractor: K Factor Pressure Adjustment: 100 100 K Factor Pressure Adjustment: 100 100
Flow Direction: Souders-Brown K Factor: Souders-Brown K Factor:
Pressure Adjusted K Factor: 0.30 ft/s Pressure Adjusted K Factor: 0.30 ft/s
Volume in Separator vL = #DIV/0! ft3vL = #DIV/0! ft3
Calculated Reqrd Vessel Inside Diameter D = #DIV/0! in D = #DIV/0! in
Approximate Reqrd Outside Diameter DO = #DIV/0! in DO = #DIV/0! in
Calculated Vessel Effective Length Leff = #DIV/0! ft Leff = #DIV/0! ft
Select Outside Diameter DO = in DO = in
Approximate Resulting Inside Diameter D = -0.25 in D = -0.25 in
Approximate Resulting Inside Diameter D = -0.02 ft D = -0.02 ft
Select Effective Length Leff = ft Leff = ft
Calculated Total Available Inside Area Atot = #N/A ft2Atot = AV = #N/A ft2
Verify Leff/D is between 3 and 5 Leff/D = 0.00 Leff/D = 0.00
Gas Capacity - Souders-Brown K Factor (Pressure Adjusted Lilly) KSB = #DIV/0! ft/s KSB = #DIV/0! ft/s
Gas Capacity - Souders-Brown K Factor KSB = #DIV/0! ft/s KSB = #DIV/0! ft/s
Maximum Gas Velocity Vmax = #DIV/0! ft/s Vmax = #DIV/0! ft/s
Min Reqrd Vessel Inside Area for Gas AG = #DIV/0! ft2AG = #DIV/0! ft2
Cross Sectional Area for Liquid Flow AL = #DIV/0! ft2AL = #DIV/0! ft2
Total Min Required Vessel Inside Area Amin = AG + AL #DIV/0! ft2Amin = AG + AL #DIV/0! ft2
Atot > Amin #N/A Atot > Amin #N/A
Dmin = #DIV/0! ft2Dmin = #DIV/0! ft2
Diameter Check D > Dmin #DIV/0! D > Dmin #DIV/0!
Liquid Phase Velocity Vliq = #DIV/0! ft/s Vliq = #DIV/0! ft/s
DEP Recommendation Check #DIV/0! #DIV/0!
Liquid Filled Fraction of Vessel M = #DIV/0! M = #DIV/0!
Liquid Level Depth to Diameter Ratio hD = #DIV/0! hD = #DIV/0!
Height to Top of Oil HL = #DIV/0! ft HL = #DIV/0! ft
Recommend 1.5ft minimum D-HL = #DIV/0! #DIV/0! D-HL = #DIV/0! #DIV/0!
Recommend 0.8 maximum HL/D = #DIV/0! #DIV/0! HL/D = #DIV/0! #DIV/0!
Water Volume Vw = - ft3Vw = - ft3
Water Area Aw = #DIV/0! ft2Aw = #DIV/0! ft2
Aw/Atot = #DIV/0! Aw/Atot = #DIV/0!
Ho/w/D = #DIV/0! Ho/w/D = #DIV/0!
Height to Top of Water Ho/w = #DIV/0! ft Ho/w = #DIV/0! ft
Actual Cross Sectional Area for Gas Flow AV = Atot - AL = #N/A ft2AV = Atot - AL = #N/A ft2
#N/A #N/A
Description
Vliq < 0.049 ft/s
Date
0.30 0.30
By
Case 1 - (Enter Case Description)
Oil Oil WaterGas
Assumptions:
3-Phase Horizontal Separator
Water
Input Data:
Case 2 - (Enter Case Description)
Checked Approved
Gas
#DIV/0! #DIV/0!
Liquid Phase Capacity - Retention Time:
Gas Capacity:
Vessel Specification:
Water Gas OilGas Oil Water
MSCFD/BPD
cP
Case 1 - (Enter Case Description) Case 2 - (Enter Case Description)
Fluid Calculations:
YOUR LOGO HERE
Version 1.0.1
Developed by Sandstone Engineering, Ryan K. Malone, P.E.
3-Phase H-Calc
Superficial Gas Velocity Vg =qg/AV = #DIV/0! ft/s Vg =qg/AV = #DIV/0! ft/s
#DIV/0! #DIV/0!
Gas Retention Time trg = #DIV/0! s trg = #DIV/0! s
Velocity of Oil Drop Falling in Gas Phase Vod = #DIV/0! ft/s Vod = #DIV/0! ft/s
Assume a drag coefficient CD1 = 1000.00 CD1 = 1000.00
Diameter of smallest oil drop that will fall dod = #DIV/0! μm dod = #DIV/0! μm
#DIV/0! in #DIV/0! in
Re = #DIV/0! Re = #DIV/0!
Iterate CD1 until CD1 = CD2 (+/- 0.02) CD2 = #DIV/0! CD2 = #DIV/0!
Velocity of Water Drop Vwd = #DIV/0! ft/s Vwd = #DIV/0! ft/s
Assume a drag coefficient CD1 = 1000.00 CD1 =
Diameter of smallest water drop that dwd = #DIV/0! μm dwd = #DIV/0! μm
will settle #DIV/0! in #DIV/0! in
Re = #DIV/0! Re = #DIV/0!
Iterate CD1 until CD1 = CD2 (+/- 0.02) CD2 = #DIV/0! CD2 = #DIV/0!
Velocity of Oil Drop Rising in Water Phase Vod = #DIV/0! ft/s Vod = #DIV/0! ft/s
Assume a drag coefficient CD1 = 1000.00 CD1 = 1000.00
Diameter of smallest oil drop that will rise dod = #DIV/0! μm dod = #DIV/0! μm
#DIV/0! in #DIV/0! in
Re = #DIV/0! Re = #DIV/0!
Iterate CD1 until CD1 = CD2 (+/- 0.02) CD2 = #DIV/0! CD2 = #DIV/0!
Height of Oil Weir How = #DIV/0! ft How = #DIV/0! ft
Height of Water Weir Hww = #DIV/0! ft Hww = #DIV/0! ft
Length, Option 1: L1 = 0.0 ft L1 = 0.0 ft
Length, Option 2: L2 = 0.0 ft L2 = 0.0 ft
Select next largest standard size: L = ft L = ft
Inlet Nozzle Allowable Erosional Velocity Ve = #DIV/0! ft/s Ve = #DIV/0! ft/s
A1 = #DIV/0! in2/1000bbl/day A1 = #DIV/0! in2/1000bbl/day
Minimum Allowable Inlet Nozzle Cross Sectional Area A = #DIV/0! in2A = #DIV/0! in2
Minimum Inlet Inside Diameter di = #DIV/0! in di = #DIV/0! in
Slug Flow Inlet Nozzle Allowable Erosional Velocity Ves = #DIV/0! ft/s Ves = #DIV/0! ft/s
Slug Flow Min Allow Inlet Nozzle Cross Sectional Area As = #DIV/0! in2As = #DIV/0! in2
Slug Flow Minimum Inlet Inside Diameter dis = #DIV/0! in dis = #DIV/0! in
Recommended Inlet Nozzle Inside Diameter di = #DIV/0! in di = #DIV/0! in
Recommended Inlet Nozzle Min Nom Size diNPS = #DIV/0! NPS diNPS = #DIV/0! NPS
Resulting Inlet Nozzle Mixture Velocity vm,in = #DIV/0! ft/s vm,in = #DIV/0! ft/s
Resulting Inlet Nozzle Feed Momentum ρmv2m,in = #DIV/0! lb/ft-s2
ρmv2m,in = #DIV/0! lb/ft-s2
Select Inlet Device, Allowable Momentum ρmv2m,in = Select Inlet Devicelb/ft-s2
ρmv2m,in = Select Inlet Devicelb/ft-s2
Select Feed Inlet Nozzle Nom Diameter diNPS = NPS diNPS = NPS
Resulting Inlet Nozzle Mixture Velocity vm,in = #DIV/0! ft/s vm,in = #DIV/0! ft/s
Resulting Inlet Nozzle Feed Momentum ρmv2m,in = #DIV/0! lb/ft-s2
ρmv2m,in = #DIV/0! lb/ft-s2
Momentum Criteria Check
Superficial Gas Velocity in Feed Nozzle vG,in = #DIV/0! ft/s vG,in = #DIV/0! ft/s
Superficial Liquid Velocity in Feed Nozzle vL,in = #DIV/0! ft/s vL,in = #DIV/0! ft/s
Gas Froude Number (see 'Flow Map' tab) FrG = #DIV/0! FrG = #DIV/0!
Liquid Froude Number ('Flow Map' tab) FrL = #DIV/0! FrL = #DIV/0!
Minimum Gas Outlet Nozzle ID dgo = #DIV/0! in dgo = #DIV/0! in
Resulting Gas Outlet Nozzle Nominal dgoNPS = #DIV/0! NPS dgoNPS = #DIV/0! NPS
Select Gas Oulet Nozzle Nom Diameter doNPS = NPS doNPS = NPS
Resulting Gas Outlet Nozzle Velocity #DIV/0! #DIV/0!
Resulting Gas Outlet Nozzle Momentum #DIV/0! #DIV/0!
Recommended Allowable Momentum 3025 3025
Gas Outlet Momentum Criteria Check
Minimum Water Outlet Nozzle ID dwo = 0.00 in dwo = 0.00 in
Minimum Water Outlet Nominal Pipe Size dwoNPS = #N/A NPS dwoNPS = #N/A NPS
Minimum Oil Outlet Nozzle ID doo = 0.00 in doo = 0.00 in
Minimum Oil Outlet Nominal Pipe Size dooNPS = #N/A NPS dooNPS = #N/A NPS
Mist Extractor Velocity Vmistex = #DIV/0! ft/s Vmistex = #DIV/0! ft/s
Minimum Mist Extractor OD Mod = #DIV/0! in Mod = #DIV/0! in
Outside Diameter (in) -6 6 12 -6 6 12
Seam to Seam Length (ft) -2 2 4 -2 2 4
Approximate Wall Thickness (in) 0.063 0.063 0.063 0.063 0.063 0.063
Approximate Shell Weight (1,000lb) 0.01 0.01 0.03 0.01 0.01 0.03
Approximate Head Weight (1,000lb) 0.000 0.001 0.003 0.000 0.001 0.003
Approximate Vessel Weight (1,000 lb) 0.11 0.11 0.14 0.11 0.11 0.14
Relative Cost/1000 0.00 0.00 0.02 0.00 0.00 0.02
#DIV/0! #DIV/0!
#DIV/0! #DIV/0!
0
0
0.063
0.00
0.000
0.10
0.00
Calculated
Design Optimization:
0
0
0.063
0.00
0.000
0.10
0.00
Possible Alternatives Calculated Possible Alternatives
Nozzle Dimensions:
Gas Capacity - Oil Drop in Gas Phase
Liquid Capacity - Water Drop in Oil Phase
Liquid Phase Capacity: Oil Drop in Water Phase
Weir and Bucket Heights:
Separator Dimensions:
Version 1.0.1
Developed by Sandstone Engineering, Ryan K. Malone, P.E.
ASME VIII, Div. 1 Design OptimizationProject:
Client:
Job Number: By:
Date: Checked By:
Revision: Revision Date:
General Notes:
Project Notes:
MAWP, P (psi) 500 f (x) 0.55 Input Vessel MAWP Shows Objective Function Results
O.D. (in.) 24 Input Vessel Outside Diameter
C.A. (in.) 0.0625 Input Vessel Corrosion Allowance
Design Variables and Constraint Functions
Thickness, t (in.) 0.360 Optimized Vessel Wall Thickness
Yield Strength, S (ksi) 20.00 Optimized Yield Strength
Joint Efficiency, E 1.00 Optimized Joint Efficiency
Thickness Weight, tw 0.70 g 1(x) -10 Input Manufacturers Relative Cost for Material Weight
Material Grade Weight, Sw 0.15 g 2(x) 0.00E+00 Input Manufacturers Relative Cost for Material Grade
Joint Efficiency Weight, Ew 0.15 g 3(x) -0.3 Input Manufacturers Relative Cost for NDT/NDE
g 4(x) 0
Total Weight 1.00 g 5(x) -0.172 Weight Inputs Must Total to 1.00
2. Select the Solver command from the Analysis box under the Data tab.
3. Make sure the objective function is set to cell E11 (Green Cell), if it is not, click on the green cell (E11)
4. Make sure the "Min" box is selected, if not select "Min"
5. Make sure the "Make Unconstrained Variables Non-Negative" check box is selected
6. Make sure the GRG Nonlinear Solving Method is selected
7. Click "Solve"
8. Make sure "Keep Solver Solution" check box is selected, and click OK
9. The resulting output provides the most efficient thickness, material, and NDE combination based on the input weights assigned by the manufacturer
Weight Function Constraints
Yellow = Spreadsheet Input Cells Blue = Spreadsheet Calculation Cells
1. Load the Excel 2013 Solver Add-in: Click File tab, then click Options. Click Add-Ins, and then in the Manage box, select Excel Add-Ins. Click Go. In the Add-Ins available
box, select the Solver Add-In check box and click OK. If Solver Add-Ins is not listed in the Add-Ins available box, click Browse to locate the add-in. If you get prompted that
the Solver add-in is not currently installed on your computer, click Yes to install it. After you load the Solver add-in, the Solver command is available in the Analysis group
on the Data tab.
Design Variables Equations
These calculations run a GRG nonlinear solver to minimize an objective function with given constraints to determine the most efficient vessel design
Design Parameters Objective Function
𝑓 𝑥 = 𝑡 ∗ 𝑡𝑤 +𝑆
20∗ 𝑆𝑤 + 𝐸 ∗ 𝐸𝑤
𝑡 =𝑃 ∗ 𝑅0
𝑆 ∗ 𝐸 + 0.40 ∗ 𝑃10.0 ≤ 𝑆 ≤ 20.0
0.70 ≤ 𝐸 ≤ 1.0
𝑡 ≥ 0.188
Version 1.0 - 090114 Developed by Sandstone Engineering, Ryan K. Malone, P.E.
Project:
Client:
Job Number: Tag No:
General Notes:
Project Notes:
Rev.
FrL = #DIV/0!
FrL = #DIV/0!
Case 1: FrG = #DIV/0!
Case 2: FrG = #DIV/0!
Note:
Description By Checked Approved Date
3-Phase Horizontal Separator
Two-Phase Flow Map for Horizontal Feed Pipes Two-Phase Flow Map for Vertical Feed Pipes
Case 1:
Case 2:
The flow maps are only applicable to very long pipes with equilibrium two-phase flow. However, if the feed pipe is longer than ten pipe diameters, the flow maps still
give a fair indication of the prevailing flow regime for a given set of conditions.
Hydrocarbon/Water Separators
Above 35º API hydrocarbon
Below 35º API hydrocarbon
100ºF and above
80ºF
60ºF
15-20 min at 80ºF
10-15 min at 90ºF
5-10 min at 100+ºF
Typical Liquid Retention Times
Table 7-4
Electrostatic Treater
Free-Water Knockouts
8 - 24 hr
0.5 - 4 hr
0.5 - 4 hr
15 - 120 min
25-30 min at 60ºF
20-25 min at 70ºF
Typical Liquid Phase
Retention TimeType of Treater
Gun Barrels or Wash Tanks
Vertical Heater-Treater
Horizontal Heater-Treater
5 - 10
10 - 20
20 - 30
Type of Separation
FIG. 7-22
Typical Retention Times for Liquid-Liquid Separation
Retention Time,
minutes
3 - 5