Relief Valve Standard API Effective Orifice Area

Relief Valve Standard API Effective Orifice Area

API has generated the standard API Effective Orifice Area with corresponding designation letter (following table). Besides, standard effective orifice area, it also has a series of corresponding inlet size, outlet size combination for various pressure classes of flanged relief valves. All these information are tabulated in API Std 526 Flanged Steel Pressure Relief Valves.

API Relief Valve Standard Effective Discharge Orifice Areas
Designation	in2	cm2
D	0.110	0.71
E	0.196	1.26
F	0.307	1.98
G	0.503	3.24
H	0.785	5.06
J	1.287	8.30
K	1.838	11.85
L	2.853	18.40
M	3.600	23.23
N	4.340	28.00
P	6.380	41.16
Q	11.050	71.29
R	16.000	103.22
T	26.000	167.74

One shall remember above effective areas are valid only when used with the sizing equations contained in API RP 520 Part I - Sizing, Selection & Installation of Pressure-Relieving Devices in Refinery.

Related Articles

• What is Capacity Correction Factor (CCF) due to Back pressure for PSV ?
• PSV Constant Back Pressure Correction Factor (Kb) for Vapor & Gas
• Several Impact of Backpressure on Conventional PRV
• How Back Pressure Affect Conventional PSV Set Pressure Subject to It Vent
• Back Pressure Affect Conventional PSV Set Pressure : Case Study #1 - Bonnect Vent to ATM
• Back Pressure Affect Conventional PSV Set Pressure : Case Study #2 - Non-Bonnect Vent

HC Gas Heat capacity ratio (Approx.)

Heat capacity ratio (or Isentropic exponent, k) is the ratio of specific heat capacity at constant pressure (C_P) to specific heat capacity at constant volume (C_V). It is commonly used in critical pressure ratio estimation, compression head estimation, etc. Following is a approximate k factor of Hydrocarbon gases. It may be used when only HC gas molecular weight (MW) and temperature (T) is available.

Source : GPSA

Other Interesting Article

• Conversion from Weight Fraction to Mole Fraction
• Unit Conversion in Energy in LNG Sector
• Wobbe Index

Typical Efficiency for Compressor

Compressor efficiency is very much subject to compressor type, design, etc. It possibly range from 50% to 90%. Each compressor from different manufacturer may have different efficiency. Following are some typical compressor efficiency may be used during design phase. It shall be decided by compressor manufacturer.

Centrifugal : 75-80%
Note : nowadays several manufacturers may have some compressor efficiency upto 84%.

Centrifugal : 75-85%

Reciprocating :
- 65% with Compression ratio of 1.5
- 75% with Compression ratio of 2.0
- 80-85% with Compression ratio of 3-6

Rotary : 70%

Other Interesting Articles

• Determine Interstage Pressure for Multi-stages Centrifugal Compressor
• Pressure Head Increases for Fan and Blower
• Simple Method For Compressor Settle Out Using HYSYS
• Adjusted Method For Compressor Settle Out (with Vapor & Liquid) Using HYSYS

Why CO2 with present of water is corrosive ?

Carbon dioxide (chemical formula: CO₂ ) is a chemical compound composed of two oxygen atoms covalently bonded to a single carbon atom. It is a gas at standard temperature and pressure and present in oil and gas fluid. CO₂ by itself is not corrosive, however, with the present of free water (H₂O), it becomes corrosive and poses a thread to many oil and gas facilities.

CO₂ with present of free water would lead to generation of Carbonic acid (H₂CO₃).

CO₂ + H₂O ==> H₂CO₃ ==> H⁺ + HCO₃^2-

When Carbonic Acid contact with steel (Fe), reaction occur.

2Fe + H₂CO₃ ==> Fe₂CO₃ + H₂

With minimum level of Oxygen would aggregate the corrosion :
Corrosion without Acid Carbonic :

4Fe + 3O₂ + 6H₂O ==> 4Fe(OH)₃

and Corrosion with Acid Carbonic :

Fe + 2H₂CO₃ ==> Fe(HCO₃)₂ + H₂

2Fe(HCO₃)₂ + 1/2 O₂ ==> Fe₂O₃ + 4CO₂ + 2H₂O

Carbonic acid is weak acid would reduce the pH of fluid and this further aggregate the corrosion.

Other Interesting Article

• What is Carbon Dioxide ?
• CO2 Corrosion in Oil & Gas

Relationship Between MOP & MAOP

Maximum Operating Pressure (MOP)
A maximum pressure at any expected normal operating scenario.

Maximum Allowable Operating Pressure (MAOP)
A maximum pressure that allowable by any equipment and device to operate satisfactory without affecting it performance. Example, a conventional direct spring loaded pressure relief valve allow MOP is 90% of set pressure whilst a pilot operated pressure relief valve may allow upto 97-98% of set pressure.

For Design Pressure & MAWP, read in "Relationship Between Design Pressure & Maximum Allowable Working Pressure (MAWP)".

MOP <= MAOP < Design Pressure <= MAWP

Other Interesting Articles

• Definition of Terms Related to PRESSURE

Determine Interstage Pressure for Multi-stages Centrifugal Compressor

How to determine interstage pressure for multi-stages centrifugal compressor ?

For a n-stages centrifugal compressor system with inlet and outlet pressure of P₀ and P_n, the compression ratio (r) should be about the same in each stage.

r = (P_n/P₀)^(1/n)

P₁ = r.P₀
P₂ = r.P1
P₃ = r.P2
.
.
.
P_n = r.Pn-1

Pressure Head Increases for Fan and Blower

What is pressure head increases for a fan and/or a blower ?



Fans are used to increase pressure head by about 3%, 12" water (300mm H2O)

Blowers are used to increase pressure head to lower than 2.75 barg (40 psig)

Relationship Between Design Pressure & Maximum Allowable Working Pressure (MAWP)

Maximum Allowable Working Pressure (MAWP)

Maximum gauge pressure permissible at the top of a completed vessel in its normal operating position at the designated coincident temperature specified for that pressure. MAWP is the least of the values for the internal or external pressure as determined by the vessel design rules for each element of the vessel using actual nominal thickness, exclusive of additional metal thickness allowed for corrosion and loadings other than pressure. The MAWP is the basis for the pressure setting of the pressure-relief devices that protect the vessel.

Design pressure

A pressure with coincident design temperature, used to determine the minimum permissible thickness or physical characteristic of each component, as determined by the design rules of the pressure-design code. The design pressure is selected by the designer to provide a suitable margin above the most severe pressure expected during normal operation at a coincident temperature. The design pressure is equal to or less than the Maximum Allowable Working Pressure (MAWP).

Design Pressure <= MAWP

Note :
Design pressure is normally the Pressure Relief Valve (RV) set pressure of a vessel. This pressure at coincident temperature is used to determine the minimum wall thickness. A calculated thickness is 9 mm based on a design pressure @ coincident temperature. However, with a standard material thickness of 10 mm. The MAWP would be calculated pressure based on this thickness.

Absolute & Relative Roughness for Piping Material

What is absolute & Relative roughness for piping material ?

Pipe absolute roughness
Pipe absolute roughness (e) tabulated are taken from from several sources. These values are for new pipes and typically for new design purpose. For aged pipes or debottlenecking purpose, higher roughness are expected.

Piping Material	Absolute roughness (Micron)	Source
drawn brass	1.5	(1,2)
drawn copper	1.5	(1,2)
commercial steel	45	(1,2)
wrought iron	45	(1,2)
asphalted cast iron	120	(1,2)
galvanized iron	150	(1,2)
cast iron	260	(1,2)
wood stave	200 to 900	(1,2)
concrete	300 to 3000	(1,2)
riveted steel	900 to 9000	(1,2)
Rubber (smooth)	6 to 70	(3)
Rubber (wire-reinforce)	300 to 4000	(3)
Stainless Steel / Titanium / Cu-Ni	45.7	(4)
Carbon steel (CS) non-corroded - General	45.7	(4)
Carbon steel (CS) non-corroded - Relief system	150	(4)
Carbon steel (CS) corroded	457	(4)
Fiberglass	5	(5)
PVC	1.5	(6)
Copper	1.5	(6)
Aluminum	1.5	(6)
RedBrass	1.5	(6)

* 1m = 1,000 mm = 1,000,000 micron ; 1 mm = 1,000 micron

Pipe Relative roughness
Relative pipe roughness is the ratio of absolute roughness (e) by and pipe diameter (D) :

Relative Pipe Roughness = e/D

(1) Binder, R.C. (1973), Fluid Mechanics, Prentice-Hall, Inc. (Englewood Cliffs, NJ).
(2) GPSA & Crane Technical Paper No. 410M
(3) Darby, R. (2001), Fluid Mechanics for Chemical Engineers, Vol 2, Marcel Dekker, (NY)
(4) BP GP 44-80
(5) Fiberglass Pipe Handbook, SPI Composites Institute
(6) Enginereed Software’s PIPE-FLO software www.engineered-software.com

What is event scheduler in HYSYS Dynamic simulation ?

What is event scheduler in HYSYS Dynamic simulation ?

Event scheduler is a useful tool for Dynamic simulation in HYSYS. It helps you to schedule your event in dynamic simulation. Dynamic simulation normally helps engineer to simulate different scenario (especially upset scenario) and testing functionality of control logic, etc.

For example, to simulate the start up of the plant, In the beginning, you need to open Valve-1, then 1 hr later, you need to close Valve-1, and start compressor and open Valve-2. These activities in sequence can be carried out manually when our integrator reaches our expected time. On the other hand, we may automate these activities using event scheduler in order to simplify work.

The structure of event scheduler in HYSYS as follow :

Schedule-->Sequence--->Event--->Action

Action is final layer to help us to do our expected work, such as specify variable, set controller mode etc. You should also specify the condition to do the action, such as elapsed time or even logic.

Pyrophoric Fire

"Pyrophoric" material is any material can be ignited or burned spontaneously in air when it is scratched, or struck, cracked, etc.

Typical component is Sulfur in Carbon steel vessel. Ferum (Fe) in carbon steel vessel reacts with Sulfur present in fluid and formed iron sulfide (FeS) which is a pyrophoric material that oxidizes exothermically when exposed to air.

Refinery, LNG production and gas treatment plant may expose to sulfur. Iron sulfide scale may appeared in Carbon steel vessel. It is typically a conversion of iron oxide, Fe2O3 (rust) to iron sulfide (FeS) in an oxygen-free atmosphere where hydrogen sulfide gas is present.

In Oxygen-free environment (during normal operation) :
Fe2O3 + 3H2S ==> 2FeS + 3H2O + S

When expose to Oxygen (during maintenance) :
FeS + 3O2 ==> 2Fe2O3 + 4S + Heat
FeS + 7O2 ==> 2Fe2O3 + 4SO2 + Heat

Heat is dissipated quickly and white smoke of SO2 gas released and followed by pyrophoric fires. This process is quick and exothermic oxidation.

Wobbe Index

Wobbe Index (WI) is used to compare the combustion energy output of different composition fuel gases. Wobbe index is used to define interchangeability of fuel. Two fuels with identical Wobbe Index at given pressure and valve setting (orifice size), the energy output will be identical. The variation in WI is typically upto 5% (but maximum could be 10% for some manufacturer).

Wobbe Index (WI) is define as

WI = HHV / Sqrt (SG)

where
Sqrt = Square root of
HHV = High Heating Value (Btu/Scf)*
SG = Specific Gravity (MWgas / 28.96)

* Some may use Lower Heating Value to define WI


Other Interesting Article :
i) Conversion from Weight Fraction to Mole Fraction
ii)Unit Conversion in Energy in LNG Sector

Gas liquid Separator Sizing Using GPSA (11ed)

A gas liquid separator is used for bulk separation and mist eliminator i.e. vane type, mesh type, cyclone type) are used to promote liquid drop coalescence and separation from gas. Souder-Brown equation has been widely used in Oil and gas industry to size a gas liquid separator with and without mist eliminator.

where

ρ_l = Liquid density, kg/m³ (or lb/ft³)
ρ_g = Vapor density, kg/m³ (or lb/ft³)

Generally the K factor as proposed in GPSA 11ed has been used by many engineers. Following figure tabulate the K factor may be used for horizontal, vertical, vertical scrubber and others separator for special services.

Reference :
i) Why Droplet Still Fall at Terminal Velocity ?
ii) Two Suction Nozzles on Drum for Two Pumps Operation...

Why Droplet Still Fall at Terminal Velocity ?

Force balance Equation for terminal velocity of a freely falling droplet or particle

Force balance : Drag force + Buoyancy force = Gravity force

Lets take the case of freely falling droplet in a gas liquid separator, gas is flowing upwards and droplet is falling down now my, fundamental doubt is

1. When all the force acting on the droplet get balanced (cancel out together), how the droplet can still fall ?
2. Terminal velocity by definition is relative velocity of gas and droplet ?

A metal ball is held and once release in the air...

FORCE BALANCE
Drag force + Buoyancy force + External force + Gravity force = 0
Upward direction, Fd + Fb + Fe +(-Fg) = 0
==> Fd + Fb + Fe = Fg

Event at 0- second...
When the ball is at static condition (metal ball is held),
==> Fd is function of velocity and . As velocity is zero ==> Fd = 0
==> Fb is function of relative density between ambient and ball. Ball density (say metal ball is approx. 3000 kg/m3) relative to air (~1.3 kg/m3), it is almost negligible. ==> Fb=0

==> Thus, Fe= Fg, V=0 m/s


Event at 0+ second...
When the ball is just released (o+ second),
==> Fe = 0
==> Fb negligible. ==> Fb=0
==> Fg maintain with no change
==> Fd is function begin to increasing...

Net Force (Fg > Fd) will drive the ball downward. Ball velocity begin to increase.


Event at t second...
When the ball velocity increase upto terminal velocity (relative velocity between ball and gas),
==> Fe = 0
==> Fb negligible. ==> Fb=0
==> Fg maintain with no change
==> Fd increase upto terminal velocity

Terminal velocity
Ball velocity is increased upto a velocity where Fg = Fd, this velocity is called terminal velocity. At this velocity, net force = 0 as Fd = Fg ==> No further increase in velocity. Constant velocity.

Metal ball vs Droplet

Ball as compare to droplet, same principle applied. The differences area the droplet shape may change from time to time and drag coefficient (C_d) will change from time to time. From engineering perspective, the change (too small) is negligible.

Reference :
i) Gas liquid Separator Sizing Using GPSA
ii) Two Suction Nozzles on Drum for Two Pumps Operation...

How to Set Hot Pump Non-return Valve bypass Flowrate ?

Can someone suggest the flow rate through the Restriction Orifice (RO) on a pump warm-up bypass line for the standby pump, maybe a certain percentage of the rated flow of the running pump ?

Above question could be tackled in simple or difficult way. However lets start to understand the purpose, how it is implemented and how to set the flow.

Purpose
The main purpose of the bypass line is to maintain a minimum temperature different between the pump (and associate piping ) and the pump suction fluid temperature to avoid temperature shock in the event of standby pump is started-up automatically.

How it is implemented ?
The bypass can be a fixed RO, non-return valve with hole or a globe valve. It generally install across the standby pump discharge non-return valve.

How much flow ?
The bypass flow rate should be sufficient to cater for :

i) pump and associate piping heat-up from minimum ambient to normal suction temperature within a reasonable time i.e. 2 hours
ii) heat leakage via insulation during normal operation

Generally above calculation are time consuming.

Tips
Experience based approach may be taken where setting the RO / NRV hole size as 6-8 mm or install a one (1) in globe valve.

Reference :
i) Why bypass Non-Return Valve (NRV) ?

Do i Normally Calculate Thermal Relief Load ?

Authority reserve the right to ask for calculation for thermal relief. If you or your company have done sufficient research and can be submitted to authority as supporting document, then don't waste your time to calculate it. Otherwise, you better get ready when authority ask for it...

In many event, a simple and smallest PSV i.e. DN 20 × DN 25 (NPS ¾ × NPS 1) would be sufficient for thermal relief.

Somehow if there is doubt the provided PSV is not adequate, it shall be calculated according to using Hydraulic expansion method may be used.

If the liquid being relieved potentially flash or form solids while it passes through the PSV, hydraulic expansion with two phase relief method may be used. Details refer to :

• J. C. LEUNG, "Size Safety Relief Valves for Flashing Liquids", Chemical Engineering Progress, February 1992, pp. 70-75
• J. C. LEUNG, and F. N. NAZARIO, "Two-Phase Flashing Flow Methods and Comparison", Journal of Loss Prevention Process Industries, Volume 3, Number 2, 1990, pp. 253-260
• L. L. SIMPSON, "Estimate Two-Phase Flow in Safety Devices", Chemical Engineering, August 1991, pp. 98-102

Reference :
i) API Std 521 section 5.14.2., 5.14.3
ii) Thermal Relief of Non-Flashing Liquid in Pipe
iii) When Do i need a PSV for Thermal Relief on Piping ?
iv) Simple Flow Chart to Determine Requirement of Thermal Relief

When Do i need a PSV for Thermal Relief on Piping ?

Generally PSV not required for piping... however...API STD 521 2007 Addendum May 2008, section 5.14.1 (c) stated that hydraulic expansion due to solar heating on "long pipelines" shall be assessed and checked if a pressure relief valve (PSV) is required. What is "long pipelines" ? Difficult...

This section allows that a PSV may not required for thermal relief if proper administrative procedures and addition of signs stipulating the proper venting and draining procedures when shut-down and block-in are implemented. These action are acceptable and considered do not compromise the safety of personnel or equipment.

System under consideration for thermal relief consists of piping only (does not contain pressure vessels or heat exchangers), a pressure-relief device might not be required to protect piping from thermal expansion if :

1. piping is always contains a pocket of non-condensing vapour, such that it can never become liquid-full (even it is heated and compressed); OR
2. piping is in continuous use (i.e., not batch or semi-continuous use) and drained after being blocked-in using well supervised procedures or permits; OR
3. fluid temperature is greater than the maximum temperature expected from solar heating (the pipe temperature direct under solar heating can reached approximately 60 °C to 70 °C, it can be as high as 85 °C for certain area i.e. Middle east) and there are no other heat sources such as heat tracing; OR
4. the estimated pressure rise from thermal expansion is within the design limits of the equipment or piping.

Conversion from Weight Fraction to Mole Fraction

A mixture consist of n component, e₁, e₂, e₃,...e_n with molecular weight MW₁, MW₂, MW₃, ... MW_n. Each component mass are M₁, M₂, M₃, ... M_n.

MASS FRACTION
Mass fraction of component-1, X₁ = M₁/M_T [Eq. 1-1]
Mass fraction of component-2, X₂ = M₂/M_T [Eq. 1-2]
Mass fraction of component-3, X₃ = M₃/M_T [Eq. 1-3]
_.
.
Mass fraction of component-i, X_i = M_i/M_T [Eq. 1-i]
.
_.
.
Mass fraction of component-n, X_n = M_n/M_T [Eq. 1-n]
.

Total mass in mixtures, M_T = M₁ + M₂ + M₃ +...+ M_n [Eq. 2]

Number of MOLE
Component-1 number of mole, N₁ = M₁/MW₁ [Eq. 3-1]
Component-2 number of mole, N₂ = M₂/MW₂ [Eq. 3-2]
Component-3 number of mole, N₃ = M₃/MW₃ [Eq. 3-3]
_.
.
Component-n number of mole, N_n = M_n/MW_n [Eq. 3-n]

Total number of mole,
N_T = N₁ + N₂ + N₃ +...+ N_n [Eq. 4]
N_T = [M₁/MW₁ + M₂/MW₂ + M₃/MW₃ +...+ M_n/MW_n] [Eq. 5]

MOLE FRACTION
For component-1,

Y₁ = N₁ / N_T
Y₁ = (M₁/MW₁) / N_T

From [Eq. 1-1],
X₁ = M₁/M_T
M₁ = X₁* MT
Y₁ = (X₁*M_T/MW₁) / N_T

Mole Fraction of component-1,
Y₁ = (M₁/MW₁) / N_T [Eq. 6-1a]
Y₁ = (X₁*M_T/MW₁) / N_T [Eq. 6-1b]

Mole Fraction of component-2,
Y₂ = (M₂/MW₂) / N_T [Eq. 6-2a]
Y₂ = (X₂*M_T/MW₂) / N_T [Eq. 6-2b]

Mole Fraction of component-3,
Y₃ = (M₃/MW₃) / N_T [Eq. 6-3b]
Y₃ = (X₃*M_T/MW₃) / N_T [Eq. 6-3b]
.
.
.

Mole Fraction of component-n,
Y_n = (M_n/MW_n) / N_T [Eq. 6-na]
Y_n = (X_n*M_T/MW_n) / N_T [Eq. 6-nb]

PSV Capacity Correction Factor (Kw) Due to Back Pressure in Liquid Service

Capacity Correction Factor (Kw) Due to Back Pressure in Liquid Service

Conventional & Pilot Operated Pressure Relief Valves

- No special correction.

Balanced-Bellows Pressure Relief Valves

Note:

The curve above represents values recommended by various manufacturers. This curve may be used when the manufacturer is not known. Otherwise, the manufacturer should be consulted for the applicable correction factor.

Related Articles

• What is Capacity Correction Factor (CCF) due to Back pressure for PSV ?
• PSV Constant Back Pressure Correction Factor (Kb) for Vapor & Gas
• Several Impact of Backpressure on Conventional PRV
• How Back Pressure Affect Conventional PSV Set Pressure Subject to It Vent
• Back Pressure Affect Conventional PSV Set Pressure : Case Study #1 - Bonnect Vent to ATM
• Back Pressure Affect Conventional PSV Set Pressure : Case Study #2 - Non-Bonnect Vent

PSV Constant Back Pressure Correction Factor (Kb) for Vapor & Gas

Constant Back Pressure Correction Factor (Kb)

For Conventional Pressure Relief Valves (Vapors and Gases Only)

Note: This chart is typical and suitable for use only when the make of the valve or the actual critical flow pressure point for the vapor or gas is unknown; otherwise, the valve manufacturer should be consulted for specific data. This correction factor should be used only in the sizing of conventional (nonbalanced) pressure relief valves that have their spring setting adjusted to compensate for the superimposed back pressure. It should not be used to size balanced-type valves.

For Balanced-Bellows Pressure Relief Valve (Vapors and Gases Only)

Notes:

1. The curves above represent a compromise of the values recommended by a number of relief valve manufacturers and may be used when the make of the valve or the critical flow pressure point for the vapor or gas is unknown. When the make of the valve is known, the manufacturer should be consulted for the correction factor. These curves are for set pressures of 50 psig and above. They are limited to back pressure below critical flow pressure for a given set pressure. For set pressures below 50 psig or for subcritical flow, the manufacturer must be consulted for values of Kb.

2. See paragraph 3.3.3. in API Rp 520 Part 1

3. For 21% overpressure, Kb equals 1.0 up to PB/PS = 50%.


Related Articles

• What is Capacity Correction Factor (CCF) due to Back pressure for PSV ?

What is Capacity Correction Factor (CCF) due to Back pressure for PSV ?

What is capacity correction factor, Kb in orifice area calculation in PSV. How do we calculate this value ?

* PSV - Pressure Relief Valve

Back pressure will tend to produce a closing force on the unbalanced portion of the disc. This force may result in a reduction in lift and an associated reduction in flow capacity. Capacity correction factors, called back pressure correction factors, are provided by manufacturers to account for this reduction in flow.

For preliminary PSV sizing, figures in API RP 520 Part 1 can be referred.

Reference :
i) API RP 520 Part 1

Related Articles

• PSV Constant Back Pressure Correction Factor (Kb) for Vapor & Gas
• Several Impact of Backpressure on Conventional PRV
• How Back Pressure Affect Conventional PSV Set Pressure Subject to It Vent
• Back Pressure Affect Conventional PSV Set Pressure : Case Study #1 - Bonnect Vent to ATM
• Back Pressure Affect Conventional PSV Set Pressure : Case Study #2 - Non-Bonnect Vent

Relationship Between Motor Poles Number with Speed

Display problem ? Click HERE

The following formula relates speed of the electric motor to number poles :

S = k x Hz x 60 / Number of Poles

where:

• S = Motor speed
  
• k = 2 for alternating current (AC electricity)
• Hz = 60 for 60-Hertz electricity i.e. electricity moves (oscillates) at 60-waves per second
• "Poles" are the positive and negative electromagnetic fields in the motor

Standard electric motor speeds at 60-Hz electricity.

• 2-pole motor = 3,600 RPM
• 4-pole motor = 1,800 RPM
• 6-pole motor = 1,200 RPM
• 8-pole motor = 900 RPM

Standard electric motor speeds at 50-Hz electricity.

• 2-pole motor = 3,000 RPM
• 4-pole motor = 1,500 RPM
• 6-pole motor = 1,000 RPM
• 8-pole motor = 750 RPM

Understand Reverse & Direct Acting Valves

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What is direct and a reverse acting valve ?

The following clarified the different features between direct and reverse acting valve.

Direct acting valve
Air to close -- Spring to open --- Failed Open (FO)
(increasing air pressure pushes down diaphragm and extends actuator stem)

Reverse acting valve
Air to open -- Spring to close --- Failed Close (FC)
(increasing air pressure pushes up diaphragm and retracts actuator stem)

Unit Conversion in Energy in LNG Sector

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Following are useful unit conversion for energy in LNG sector

1 bcm = 1000 mcm

1 mcm/d = 0.4 bcm / year

1 m³ LNG (at -161^oC) = c.600 m³ gas (at 15^oC)

1Mt LNG = c. 1.35 bcm gas

1 MBtu = 10 Therm = 0.293 MWh

1m³ gas = c. 11kWh

1,000 m³ = 35.31 MBtu

1 bcf/d = c. 10.34 bcm/year

1 bcf = c. 1TBtu

1 barrel oil = 5.8 MBtu

Oil parity price for gas = $17.24/MBtu when oil price = $100/barrel

Two Suction Nozzles on Drum for Two Pumps Operation

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Is it advisable to have 2 dedicated suction nozzles on a drum for 2 pumps operation? Do I have to consider the nozzle spacings to prevent suction interference ? What're the pitfall for operating 2 pumps from 2 suction nozzles?

Additional information :

• The drum is gas liquid separator
• Operational cases - 1 pump running, spare pump running and 2 pumps running
• Two nozzles are 4"
  

Instead of having two different nozzles of 4" size you can have one single nozzle of 6" size. This will avoid no. of fittings in the suction line which will improve NPSHA. The 6" line should go up to the suction of both the pumps. Even if only one pump is running the suction velocity will be less than during both the pumps running. This will further reduce frictional head loss in the suction line improving the NPSHA.

by Dhirajkumar

If this is Gas liquid separator, then location of outlet nozzle should be kept furthest away from inlet nozzle to allow sufficient retention for bubble rising. So, please check the suitability of pump nozzle location to avoid/ minimize bubble getting into pump suction line.

Two pumps running... one pump stop instantaneously. The forward flow stop and then would create a wave return back to the vessel itself. This may create some level of liquid movement in the vessel and increase opportunity of vapor getting into second running pump... above is my guess... Make sure you have vortex breaker to minimize vapor getting into pump suction nozzle.

by JoeWong

Reference :
i) Vortex Breaker to Avoid Vapor Entrainment
ii) Estimate Minimum Submergence to Avoid Vapor Entrainment
iii) Damages by Cavitation
iv) How Pump Cavitation Sound and Looks Like ?

Different Between Shut Off Pressure & Differential Pressure for Actuator Sizing

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In PCV & SDV, in that there are two terms
a. Shut off pressure
b. Maximum differential pressure for Actuator sizing

The system sequence is
Vessel A ( Oper.Pres.= 4.5 barg)
-----> PCV( Press. Drop=4 bar)
-----> SDV
-----> Vessel B (oper. Pres.=0.5 barg)

Vessel A design pressure = 12.0 barg
Vessel B design pressure = 4.0 barg
* PCV - Pressure control valve
** SDV - Shutdown Valve

Please suggest the values for the both terms for the PCV & SDV to fill.


a. Specify shut off pressure for valve tightness purpose... Worst case is design pressure-ATM = 12 bar.

b. Specify maximum differential pressure for actuator design. Large Differential Pressure across control valve, large torque required and larger the actuator (& cost). Actuator also increase with line size. In order to reduce cost, normally you put a small bypass for pressurization purpose...
by JoeWong

Reference :
i) Requirements of SDV Bypass Pressurization Line

Blowdown Valve Status After Depressuring

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What should the Blowdown valve (BDV) status be after depressuring ? After reaching the isolated vessel pressure of 50% of design pressure or 100 psi (according to API Std 521), should the BDV be closed or keep in open position ? If in open position, the vessel pressure will be equalized with the flare system pressure. Any associated problem ?

BDV would be in open position (Fail safe position) to ensure evacuation of Hydrocarbon inventory... To equalize the vessel pressure with the flare system pressure would take very long. Normally, an operator would take action to initiate the closure of the BDV for last few bar.

by JoeWong