Gas Conditioning and Processing, Vol. 4, Gas and Liquid Sweetening, Campbell Petroleum Series, 1982
Chemical Engineer’s Handbook, Perry & Chilton, Fifth Edition
Gas Purification, Kohl & Riesenfeld, Fourth Edition 1985 Gulf Publishing Company Acid and Sour Gas Treating Processes, 1985, Gulf Publishing
Gas Conditioning Conference Proceedings, 1954-1992 Linde Molecular Sieves, Union Carbide
Gas Treating, Gas/SPEC Dow
Corporate Engineering Process, Gas Section Reference, Files,
GR1020, GR1180, GR1559, GR1800, GR1802, GR1820, GR1870, GR7047 Sulfur Recovery, Paskall & Sames, 1988, Western Research
Oil & Gas Journal, Dec 1, 1980, pg 135-138 “Liquid – Liquid contractors need careful attention”
“Considerations For Mercury in LNG Operations” by W. W. Bodie, A. Attari – Institute of Gas Technology R. Serauskas – Gas Developments Corporation
“Mercury-LNG’s Problems” – by J. E. Leeper – Hyrocarbon Processing – November, 1980
“Causes and Remedies of The Corrosion of Cryogenic Exchangers By Mercury” by Tewfik Hasni – February, 1978
Phillips Metallurgist – Hisham Hashim
Calgon – HGR Sulfur Impregnated Activated Carbon
Pinion (Alcoa/NUCON) – Mersorb Activated Carbon Adsorbent
4 FLUID FLOW A. Misc.
1. Absolute pressure of atmosphere at height ‘H’ above sea level:
P = P1 (1-0.00000687H)n n = 5.256 Where: P1 = pressure at sea level, psia
Density: W = W1(1-0.00000687H)n n = 4.256 Where: W1 = density of air at sea level
P = e[2.6876 – 0.0000368 (H)]
psia
Where H is height, ft above sea level Borger- 13.2 psia: Woods Cross- 12.4 psia 2. Acoustic Velocity Va = 80.53 √ (P/ρ)
where: P = psia
ρ = density lb/ft3 Va = ft/sec
For perfect gas:
Va = √ (gc*k*R*T/M) Where: gc = 32/17 k = Cp/Cv R = 1546 T = °R M = mol wt.
3. Vortex Breaker
Vortex Breaker is needed if flow is greater than 1.9 ft/sec.
B. NGL Expander Plants
1. Flowrate through an expander can generally be controlled from 0 to 150% of the design value. Expanders adiabatic efficiency will generally be within 4 percentage points of the design between 75 and 125% of design flowrate. (#/hr)
2. Preliminary Piping Sizing
For preliminary liquid piping sizing, the following table may be used as a guide:
Liquid Service Pressure Drop Velocity
(Psi/100 FT) (FT/Sec)
High Viscosity to 200 CP
Pump Suction 0.5 – 1.0 0.25 – 0.5
Pump Discharge 10.0 – 1.0 1.0 – 1.5
** Water with high CO2, seawater, etc requires lower maximum velocities, linings, or special material.
For preliminary vapor piping sizing, the following table may be used as a guide.
Vapor
1. Initial maximum fluid velocities for line sizing:
Most liquids: 10 ft/s
All vapors: 50 ft/s
Raw sea water: 11.5 ft/s (CuNi piping)
Gravity drains 1.5 ft/s
Steam condensate 1.0 ft/s
2. Fluid velocity for vapor and two-phase flows should not exceed the erosional
velocity. Estimate erosional velocity from Ve = 100/√ρ where Ve = erosional velocity in ft/s and ρ = fluid density in lb/ft3.
Limiting Velocities – Liquids: (Another source)
Normal limiting velocities (highest normal design velocities) in process lines are given by the following formula:
ρ
=100 V
Where: V is limiting design velocity in ft/sec
ρ is density in lb/ft3 at system T&P
Erosion velocity (velocity at which erosion of process line is expected) for clear liquids is given by the following formula:
ρ
=150 Ve
Where: Ve is the erosion velocity in ft/sec ρ is density in lb/ft3 at system T&P
3. Compressible gases (i.e. HC, air, steam) can be treated as incompressible when the pressure loss for the segment in question is less than 10% of the inlet pressure.
Maximum Operable Velocities:
When rating existing liquid and/or gas piping systems, it is sometimes desirable to determine the limiting fluid velocity for the system. This may be estimated as follows:
For erosive or corrosive liquids = 0.5 x um
b. For gases:
Turbulent flow average limiting velocity
m
um=148.7 kZT (2/3 sonic velocity) Where; um = Average limiting velocity, ft/sec
Note: Economic factors such as pressure loss usually necessitate operating at lower than limiting velocity.
4. Friction Factor – Project Life:
Piping friction factor increases with operating time. As a result, the piping head loss
a. 25 to 30 years for clean gases and light hydrocarbons.
b. 15 to 25 years for most middle distillates.
b. 10 to 15 years for residues.
While sizing pipelines and pumping facilities, this aspect should be duly considered.
5. Piping Noise:
Liquid velocities above 20 to 30 ft/sec can cause noise. As a rule, a velocity head less than 1.3 psi avoids excessive noise.
D. Physical Fan Laws
1. The following relations are characteristic of fans operating in a given system with constant air density:
a. With constant fan size and varying fan speed:
(1) Volume (CFM) varies directly as the fan speed.
1
(2) Static Pressure Varies directly as the square of the RPM.
2
3) Horsepower absorbed by the fan varies directly as the cube of the fan speed.
3
b. With varying fan sizes at the same speed:
(1) Volume (CFM) varies directly as the cube of the fan speed.
3
(2) Static Pressure Varies directly as the square of the fan speed
2
(3) Horsepower absorbed by the fan varies directly as the fifth power of size.
2. The following relations are characteristic of a fan of a given size delivering a constant mass of air of varying density. (Density varies directly as absolute temperature and inversely as the atmospheric pressure.):
a. Volume, fan speed, and total pressure vary inversely as the density.
b. Horsepower absorbed by the fan varies inversely as the square of the density.
3. Fan Horsepower varies directly as the product of the volume (ACFM) and the total pressure (inches W.G.) divided by the constant 6370 times the total aerodynamic efficiency.
Actual Fan Horsepower = ACFM x Total Pressure
6370 X Total Aerodynamic Efficiency E. Control Valves
1. Pumped Circuit
Allocating Pressure Drops to Control Valves:
In a pumped circuit, the pressure drop allocated to the control valve should be 33% of all other friction losses in the system at pump rated flow (exclusive of the valve pressure drop itself) or 15 psi whichever is greater.
Valid for < 750 GPM & < 150 psi pump delta p Valid for > 300 GPM & 150 to 275 psi pump delta p
If outside these ranges, pressure drop allocated may be 25% of system dynamic losses at pump rated head, or 15 psi whichever is greater.
In both cases above, use no more than 90% of valve's Cv.
2. Compressor discharge and suction lines
The pressure drop allocated to a control valve in the suction or discharge line of a centrifugal compressor should be 5% of the suction absolute pressure, or 50% of the system dynamic losses (exclusive of the control valve) at the compressor rated point, whichever is larger. Also, no more than 90% of the valve Cv should be used.
3. Pressure motivated systems
In a system where tank pressure moves liquid from one vessel to another, the pressure drop should be 10% of the lower terminal vessel pressure, or 50% of the system dynamic losses, whichever is greater.
The above rule also applies to vapor, but in addition, the assigned Delta P should not exceed 42% of the upstream pressure to avoid critical flow problems through the valve.
4. Steam and flashing water
Valves in steam lines to turbines, reboilers, and process vessels, should be allocated 10% of the design absolute pressure of the system or 5 psi, whichever is greater. The valve should be sized for twice the normal flow rate since steam usage rates can vary widely, especially during start-up.
For valves handling a flashing mixture, the allocated pressure drop should be equal to 0.9 times the difference in between the absolute inlet pressure and the absolute
saturation pressure if flowing temperature is more than 5° F below the saturation temperature. If less than 5° F below the saturation temperature, the pressure drop should not be greater than 0.06 times the absolute inlet pressure.
F. Two Phase Flow:
For the seven types of two phase flow patterns in pipes, some guidelines on liquid and vapor superficial velocities (LSV and GSV respectively) which can be used to make initial predictions on the type of flow pattern are given below.
1. Horizontal Pipes:
a. In DISPERSED FLOW PATTERN, nearly all the liquid is entrained as spray by the gas. This occurs at GSV > 200 ft/sec.
b. In ANNULAR FLOW PATTERN, liquid forms a film around the inside wall of pipe and gas flows at a high velocity as a central core. This occurs at GSV > 20 ft.sec.
c. In BUBBLE FLOW PATTERN, bubbles of gas move along at about the same velocity as the liquid. This occurs at LSV of 5 to 15 ft/sec, and GSV of 1 to 10 ft/sec.
d. In STRATIFIED FLOW PATTERN, liquid flows along the bottom of the pipe and gas flows over the smooth liquid gas interface. This normally occurs for LSV< 0.5 ft/sec, and GSV of 2 to 10 ft/sec.
e. In WAVE FLOW PATTERN, the interface is disturbed by waves moving in the direction of flow; otherwise it is similar to stratified flow pattern. This occurs for LSV < 1 ft/sec and GSV of about 15 ft/sec.
f. In SLUG FLOW PATTERN, waves are picked up periodically in the gas stream and form a slug which moves at much greater velocity than average liquid
velocity. Slugs can cause severe vibration due to impact on fittings such as return bends.
g. In PLUG FLOW PATTERN, alternate plugs of liquid and gas move along the pipe. This occurs at LSV < 2 ft/sec and GSV < 3 ft/sec.
2. Upflow Vertical Pipes:
a. For dispersed flow, GSV > 70 ft/sec.
b. For annular flow, LSV < 2 ft/sec. and GSV > 30 ft/sec.
c. For bubble flow, GSV < 2 ft/sec.
d. Stratified flow does not occur.
e. For wave flow, the SV’s are unpredictable.
f. For slug flow, GSV = 2 to 30 ft/sec.
g. For plug flow, GSV = 2 to 30 ft/sec.