Slugging Flow in Horizontal and Vertical Upward

Two phase gas liquid flow is commonly occur in any oil & gas production and processing system. Several flow patterns can occur in two phase gas liquid flow. There are Bubble flow (with minimum vapor bubble), Plug flow, Stratified flow, Wavy flow, Slug flow, Annular flow and Mist/Dispersed flow (with minimum liquid droplet). Previous post "Problems Caused by Two Phase Gas-Liquid Flow" has discussed about obvious and non-obvious location where two phase gas liquid can present. Problem caused by two phase gas liquid flow such as Impingement erosion, Splashing erosion, Cavitation erosion, Flashing erosion, Flow induced vibration, Surge / hammer, Noise, Decrease process performance and Phase separation possibly lead to severe consequence. Minimizing / prevention of two phase gas liquid becoming important during design phase.

As discussed in "Some Measures To Prevent Problem Caused by Two Phase Gas Liquid Flow", the destructive level of two phase gas liquid flow varies with flow pattern. One shall try to design their system to avoid Slugging flow and/or plugging as slugging/plugging can lead severe vibration and erosion. The destructive level reduce from slugging flow to stratified flow, and minimum at annular, mist and bubble flow. So a process engineer shall design their system to move away from slugging flow.  

Slugging flow in Horizontal pipe

Slugging flow can occur in horizontal pipe and vertical pipe. However, the flow pattern may be slightly difference. You may view slugging flow in horizontal pipe in below video clip.

Slugging flow in horizontal pipe

For slugging flow in horizontal pipe, trapped vapor is main stay at the top of pipe, flowing at high velocity pushing liquid slug move forward. Liquid slug right in front of trapped vapor is accelerated by the vapor flow. As slug velocity is increased and couple with gravity force acting on the slug, liquid slug becomes unstable. Liquid slug will destroy and liquid slug is dropped to bottom of pipe.Trapped vapor at the back of liquid slug loss resistance (due to liquid slug) is accelerated at high velocity. As the vapor is moving at high velocity where it is exceeded the inception velocity, liquid at the bottom of pipe is moving upward to the top of pipe, close the vapor gap and form another liquid slug. This process of slug formation, accelerates by vapor flow and slug destroy due to gravity force and weak surface tension will repeat continuously. The repeated cycle will generate severe vibration, noise and erosion to the pipe.

Below is a video clip for slugging flow in vertical upward pipe.

Slugging flow in Vertical upward pipe

Slugging flow in Vertical upward pipe

The vapor is trapped in the liquid flow and flow upward together. Large trapped vapor is sometime called Taylor bubbles flowing upward and liquid is separating Taylor bubbles. Between two Taylor bubbles, smaller bubbles are following upward as well. These bubble is rather unstable. They may coalesce to form larger bubble and join the large Taylor bubble or they may destroy due to liquid movement. As the Taylor bubble moving upward, liquid is moving at lower speed between Taylor bubble and pipe wall will tends to entrain vapor to form smaller bubble.

Special thanks to fernandoagf1 & tmccorkle6719

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Some Measures To Prevent Problem Caused by Two Phase Gas Liquid Flow

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Previous post "Problems Caused by Two Phase Gas-Liquid Flow" has discussed about obvious and non-obvious location where two phase gas liquid can present. Problem caused by two phase gas liquid flow such as Impingement erosion, Splashing erosion, Cavitation erosion, Flashing erosion, Flow induced vibration, Surge / hammer, Noise, Decrease process performance and Phase separation possibly lead to severe consequence. Minimizing / prevention of two phase gas liquid becoming important during design phase.

Prevention Principle

In minimizing / prevention of  two phase gas liquid flow, one may follow below principles :

• Avoid two phase gas liquid present in process design / simulation
• Promote phase separation once two phase is present
• Avoid destructive flow pattern e.g. Slugging flow
• Proper piping arrangement
• Improvement of mechanical integrity

Details Measures

ELIMINATE - Avoid two phase gas liquid present in process design / simulation

Process engineer may take extra effort to avoid present of two phase gas liquid during process design. Several methods such as locate level control valve downstream of filter coalescing separator so that saturated fluid is always in liquid form before it is entering filter coalescing separator, provision of flash drum prior to flash off hydrocarbon vapor before feed the solvent to plate frame heat exchanger, provision of condensate flash drum for recovered steam condensate before it is return back to boiler, etc. These are the measures can be considered by process engineer during design phase to avoid possibility of two phase flow in the system.

SEPARATION - Promote phase separation once two phase is present

Completely avoid present of two phase flow may not be possible. Saturated liquid flowing pipe, pressure drop (and ambient heating) along pipe may lead to liquid vaporization. Saturated vapor flowing in pipe, pressure drop (and ambient cooling) along pipe may results condensation. Mixing of hot saturated fluid with cool fluid can shift the equilibrium and results two phase vapor liquid flow after the mixing. Thus, avoidance of two phase gas liquid flow entirely may not be possible.Once it is present, one way is to remove of the phase from the other phase. Following measures may be considered :

Vapor flow with condensation

• Superheat vapor before it is transferred
• Provide insulation to minimize heat loss to ambient
• Provide heat tracing to compensate heat loss to ambient and avoid condensation
• Provide liquid trap along the pipe to remove liquid from vapor
• Minimize pipe length to minimize frictional loss
• Use low surface roughness material (e.g. Stainless steel) for transferring fluid
• Provision of intermediate vessel to remove liquid

Liquid flow with vaporization

• Subcooled liquid by cooling or pressurize prior to transferred
• Provide insulation to minimize heat input from ambient
• Provide vapor trap along the pipe to remove vapor from liquid
• Minimize pipe length to minimize frictional loss
• Use low surface roughness material (e.g. Stainless steel) for transferring fluid
• Provision of intermediate vessel to remove vapor

AVOIDANCE - Avoid Destructive Flow Pattern

The destructive level of two phase gas liquid flow varies with flow pattern. One shall try to design their system to avoid Slugging flow and/or plugging as slugging/plugging can lead severe vibration and erosion. The destructive level reduce from slugging flow to stratified flow, and minimum at annular, mist and bubble flow. So a process engineer shall design their system to move away from slugging flow. Proper pipe size selection and operation control may be considered to avoid destructive flow pattern.

DESIGN - Proper Piping Arrangement

Good piping arrangement may be considered to minimize the impact of two phase gas liquid flow.

• Avoid / Minimize pocketed line
• Avoid / Minimize vertical lift
• Provide low point drains / traps
  
• Slope away liquid from source
• Design piping to avoid liquid accumulation and promote auto-draining

STRENGTH - Improvement of mechanical integrity

Once all above measures are implemented and present of two phase gas liquid flow including slugging flow, the mechanical integrity of the piping and support system shall be improved :

• Use high and reasonable tensile strength material for piping and/or equipment
• Provision of piping support improved mechanical strength
• Increase design margin to minimize any uncertainties in design
• Conduct transient analysis and/or CFD to identify localize high stress area and strengthen weak point

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Problems Caused by Two Phase Gas-Liquid Flow

Two phase gas liquid flow is commonly occur in any oil & gas production and processing system. Several flow patterns can occur in two phase gas liquid flow. There are Bubble flow (with minimum vapor bubble), Plug flow, Stratified flow, Wavy flow, Slug flow, Annular flow and Mist/Dispersed flow (with minimum liquid droplet). See following images.

Obvious Location
Present of two phase gas liquid may be obvious and be easily identified during development phase. Typical example are Full-Well-Stream (FWS) production which possibly producing hydrocarbon in gas and liquid form. Formation water, condensed water, mercury, and injected chemical (e.g. corrosion inhibitor, hydrate inhibitor, etc) in liquid form, wax in slurry form and sand in solid form may also present in the FWS, which typically result complicated multiphase form. Partial stabilized condensate travel long distance experience high pressure drop lead to vaporization. Vapor travel long distance experience ambient and J-T (isenthalpic process) cooling lead to condensation. Hot saturated vapor is cooled by air cooler or heat exchanger results condensation, vapor or liquid passing through turbine experience isentropic process, etc. These streams are obvious and can be easily identified in process simulation. Generally example are :

• Full Well Stream (FWS)
• Partial stabilized condensate with long pipeline
• Saturated vapor with long pipeline
• Liquid stream from separator passing a level control valve
• Downstream of Air cooler / Heat exchanger
• Turbine outlet
• Hot fluid mix with cool fluid continuously

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Non-obvious Location
There are certain stream may be not so obvious and may not be easily identified in process simulation. Hot saturated vapor flow in long pipe experience heat loss to ambient and frictional loss, condensation begin and two phase flow (i.e. mist flow, annular flow). Cold saturated or partial subcooled liquid experience frictional loss due to fittings, piping, etc and ambient heating results vaporization and two phase flow (i.e. bubble flow, wavy flow, slugging flow). Hot stream mix with cold stream may results equilibrium change and lead to two phase. Typical area is flare collection system. Hydrocarbon in process vessel at pressure once it is drained to drain collection header may flash and lead to vaporization. Generally example are :

• Saturated vapor within plant (condensation)
• Cooled or subcooled liquid within plant (vaporization)
• Flare collection
• Hydrocarbon drain collection

Problems
Two phase gas liquid flow can cause several destructive problems. There are :

• Impingement erosion
• Splashing erosion
• Cavitation erosion
• Flashing erosion
• Flow induced vibration
• Surge / hammer
• Noise
• Decrease process performance
• Phase separation

Impingement, Splashing, Cavitation & Flashing Erosion

Two phase gas liquid flow can lead to impingement, cavitation & flashing erosion. Two phase gas liquid flowing fluid where heavy phase is accelerated with light phase and induced high momentum and shearing stress on surface. Slugging flow in vapor-liquid system with large slug hammering on surface induce high momentum with medium velocity and high mass flux. Mist flow with droplet accelerate at vapor velocity induce high momentum with high velocity and low mass flux. Both induce high shear stress on the surface and increase material removal rate.

Flow Induced Vibration

High velocity compressible fluid in pipe is moving in turbulence pattern. Turbulence flow will induced vibration on pipe. Once the flow induced vibration frequency meeting the natural frequency of pipe support, resonance occur can lead to severe movement of pipe support. Present of two phase gas liquid flow can generate different level of frequency and increase possibility of resonances.

Surge & Hammer

Two phase gas liquid slugging and high velocity gas moving liquid at similar speed, severe vibration can occur when liquid slug is knocking/splashing on the pipe wall, especially at bend and elbow. Hot steam mix with cold condensate at the collection header results sudden steam vapor collapse. The collapse vapor results sudden lower pressure will lead sudden replacement of surrounding condensate. Sudden movement of condensate can results significant movement of condensate as well as piping and pipe support. Under designed pipe support may fail due to severe vibration.

Quick opening of valve for incompressible, multiphase and gas/vapor will results sudden change in momentum (0 to +mv) and subsequently instantaneous peak force acting on the piping. This phenomena is commonly occurs in control valve (CV), Blowdown valve (BDV) and pressure relief device i.e. pressure relief valve (PRV) and rupture disc (RD). The instantaneous peak force acting on the piping may potentially lead to piping failure.

Noise

Above phenomenon such as Impingement, Splashing, Cavitation & Flashing Erosion, Flow Induced Vibration and Surge & Hammer may also generate noise which potentially exceeded the allowable noise limit.

Affect process performance

In oil and gas production, condensate-produced water bulk separation occur in slug catcher / inlet receiver follow by a Condensate separator. Some process design may include a filter coalescing separator to promote water droplet coalescing (using coalescing element) and separation before it is sent to Condensate stabilization. Condensate at saturation point from Condensate separator feeding to Filter Coalescing separator will experience frictional drop and potential lead to vaporization. Vapor will accumulate in the filter coalescing separator and seriously affect Coalescing activity in Filter Coalescing Separator.

Plate heat exchanger (PHE) is used in Solvent e.g. Amine, MEG, TEG, etc regeneration to recover heat from lean solvent stream and promote energy saving. Hydrocarbon and / or vapor bubble under carry from Solvent Absorber to PHE potentially accumulate in the PHE and seriously affect the heat transfer in PHE.

Phase Separation - Mal-Distribution
Air cooler used for fluid cooling is widely used in Oil & Gas and Petrochemical plant. Hot fluid is fed to a Inlet header box, distribute fluid into tubes (normally finned) where cooling take place and cooled fluid is collected in the Outlet header box. If hot two phase gas liquid fluid feeding to the inlet header box, liquid with higher momentum tends to flow preferential path (straight) compare to vapor with lower momentum. The lead to serious vapor-liquid mal-distribution. Fluid (vapor dominant) feed to tube closer to inlet possibly over cooled whilst fluid (liquid dominant) feed to tube further from inlet possibly under cooled. For large duty air cooling system, fluid may further distribute into multiple header boxes and multiple unit air cooler, this will further create mal-distribution of fluid.

Knowing the problems caused by two phase gas liquid flow, identification of potential two phase gas liquid becoming an important activity during design phase. Process engineer shall take extra care during design phase and provide necessary prevention measures to minimize / avoid occurrence of two phase flow.

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How to Increase Mass Flow Across RO When Choked Flow Already Occured ?

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Restriction orifice (RO) is widely used to in Oil and Gas, Refinery and Petrochemical chemical plant. Simple search on internet lead you to plenty of articles related to functionality, calculation and specification of restriction orifice. "Restrcition Orifice Used in Many Applications in Different Manners" brought out a few applications of RO in the industries. Earlier post "A refresh to Process Engineer on few phenomenons in restriction orifice" has summarized a few concepts that a process engineer may needs to understand for restriction orifice :

• Restriction orifice is used to limit flow to required or expected flowrate with the available differential pressure across.
• Vena contracta (VC) present just short distance downstream of restriction orifice
• Maximum velocity and minimum pressure at vena contracta (VC)
• Choked flow occurred when velocity at vena contracta (VC) reach sonic velocity (Ma=1). The corresponding downstream pressure (P2) at choked condition called critical pressure (Pc).
• Increase in upstream pressure (P1) will increase mass flow passing the restriction orifice but velocity at VC still maintaining at Ma=1

A young engineer asked... If compressible fluid composition and upstream pressure are fixed and choked flow already occurred, should there be other way to increase the mass flow passing the RO ?

For compressible fluid, mass flow passing through an fixed bore size RO is a function of

1. composition ( k, MW, ...)
2. driving force (Differential pressure) across RO (P1-P2)
3. density (function of P1, MW, z, T1)
   

If composition and upstream pressure (P1) are fixed,

1. composition (and therefore k, MW...) remain unchanged
2. reducing P2 lead to higher P1-P2 which will result higher mass flow passing RO. Mass flow increase will continue until until P2 reach critical pressure of fluid (Pc). Sonic velocity (Mach no =1) occurred at vena contrata, some distance downstream of RO. When P2 lower than Pc, further reduction of P2 will not result any mass flow increase.
3. reduce upstream temperature (T1) will results higher density and higher mass flow passing RO.
   

Thus, one of the way to increase mass flow through RO when gas composition and upstream pressure are fixed and choked flow already occurred is dropping upstream temperature (T1).

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FAYF - Fluid Flow

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Chemical Engineering has shared a FAYF related FLUID FLOW. This FAYF is infact has been released in previous month, however, CE share with CE FREE subscriber again this month.

Fluid Type
In this FAYF, it starts with definition of fluid type such as :
i) Newtonian
ii) Power law
iii) Bingham plastic

where

Newtonian fluid
A fluid is known to be Newtonian when shear stresses associated with flow are directly proportional to the shear rate of the fluid.

Power law fluid
A structural fluid has a structure that forms in the undeformed state, but then breaks down as shear rate increases. Such a fluid exhibits “power law” behavior at intermediate shear rates

Bingham plastic fluid
A plastic is a material that exhibits a yield stress, meaning that it behaves as a solid below the stress level and as a fluid above the stress level

This one-page fact sheet summarizes information pertinent to laminar and turbulent pipe flow for the various types of fluids commonly encountered in the CPI...

Ref. :
1. Darby, R., Take the Mystery Out of Non-Newtonian Fluids, Chem. Eng., March 2001, pp. 66–73.
2. Churchil, S. W., Friction Factor Equation Spans all Fluid- Flow Regimes, Chem. Eng., November 1997, p. 91.
3. Darby, R., and Chang, H. D., A Generalized Correlation for Friction Loss in Drag-reducing Polymer Solutions, AIChE J., 30, p. 274, 1984.
4. Darby, R., and Chang, H. D., A Friction Factor Equation for Bingham Plastics, Slurries and Suspensions for all Fluid Flow Regimes, Chem. Eng., December 28, 1981, pp. 59–61.
5. Darby, R., “Fluid Mechanics for Chemical Engineers,” Vol. 2, Marcel Dekker, New York, N.Y., 2001.

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*This FAYF is only available FREE to Chemical Engineering Magazine registered user. Login required. Subscribe FREE CE, click here.
** Download immediately as article available FREE within short period only. Do not wait.
*** Found lost link or unable to download, may contact me...

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Condensate Pump Recirculation Valve Selection

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Condensate Pump Recirculation Valve Selection
Power plant condenser receives exhaust steam from the low pressure turbine and condenses it to liquid for reuse. Condenser back pressure range from 1.0 to 4.5 Hg absolute (3.4 to 15.2 kPa) with higher pressures possible when the cooling water temperature is elevated by using an air-cooled steam condenser. Condensate is collected in the bottom of the condenser in the hot well. The condensate feed pump supplies the subcooled water to the feedwater heaters.

As with most centrifugal pumps, the condensate pump is subject to overheating and cavitation if used at a flow under a minimum value recommendation by the pump manufacturer. When the flow required by the deaerator level control loop falls below this minimum recommended value, additional flow is recirculated back to the condenser by opening a valve installed in a bypass line thus maintaining the minimum flow through the pump at all time. There are problems associate with this valve and its selection. Read more...

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• Steam in FIRE...

Several Precautions for BFW Pump Recirculation Valve

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High pressure feedwater pumps are subject to overheating and subsequently very rapid damage if used at low flow as compared to the rated capacity. The minimum flow required for pump protection is specified by the pump manufacturer. It is never less than 15% and can sometimes be 40% or more. When the flow required by the boiler is below this limit, the feedwater pump flow demand is artificially increased by discharging to the deaerator or sometimes to the condenser through a recirculation valve. The recirculation valve is required to operate either on-off within a selected range of values of flow to the boiler, or in modulating service. In this case, the flow through the control valve is equal to the difference between the pump minimum flow and the actual flow to the boiler. Modulating service avoids the waste of energy since the recirculated flow is kept at the minimum acceptable value, but it is more severe in terms of valve service.

Several precautions may have to be taken while selecting this type of recirculation valve :

1. Cavitation
2. Pressure drop distribution
3. Axial / Radial design
4. Shut-off/ Wire drawing
5. Clogging
6. Vibration
7. Failure position

Read more...

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Why Control Valve Operate Around 60-70% Opening ?

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Control valve capacity (Cv) for particular application is determined by the use of recognized valve sizing equations. This valve equation can be found in several handbooks i.e. Fisher, Masoneilan, etc as discussed in "Useful Documents Related to Control Valve".This article presented a simple idea why a control valve is normally operate at around 60-70% valve opening and it associated impact such as increase signal dead band effect and affect optimum controller settings-wider proportional band and faster reset. It recommended a new way to overcome the impacts by introducing VARIMAX. Read more...

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• Steam in FIRE...

Relate NORMAL to STANDARD Volumetric Flow

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In gas processing industry, gas flow has been referred to STANDARD (i.e. Sm3/hr, MMSCFD, etc) and NORMAL condition (i.e. Nm3/h). Vendor catalog in many event can be in Sm3/h or Nm3/h.

What is the useful factor to convert Nm3/h to Sm3/h or vice versa ?

Definition
As discussed in "Avoid Confusion In "Standard" Flow Definition", definition is one of the most important factors to avoid discrepancies. First far most important task is to provide a correct definition of STANDARD and NORMAL condition. In "general",

NORMAL condition : 1.01325 bara @ 0 degC
STANDARD condition : 1.01325 bara @ 15 degC

Conversion
From this post,

Q₂ = (z₂/z₁) x (T₂/T₁) x (P₁/P₂) x Q_{1 .....[1]}

where
Q₁ & Q₂ are Volumetric Flow in m3/h for condition 1 & 2
P₁ & P₂ are Pressure in bar abs for condition 1 & 2
T₁ & T₂ are Temperature in K for condition 1 & 2
z₁ & z₂ are compressibility factor for condition 1 & 2

Condition 1 : 1.01325 bara @ 0 degC (NORMAL Contractor manual)
Condition 2 : 1.01325 bara @ 15 degC (STANDARD)
Assume z₁ = z₂ = 1
Q₁ = 1 Nm3/h

From [1],
==> Q₂ = (z₂/z₁) x (T₂/T₁) x (P₁/P₂) x Q₁
==> Q₂ = (288.15 / 273.15) x 1
==> Q₂ = 1.055 Sm3/h

Therefore,

1 Nm3 = 1.055 Sm3

when
NORMAL condition : 1.01325 bara @ 0 degC
STANDARD condition : 1.01325 bara @ 15 degC

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Avoid Confusion In "Standard" Flow Definition

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A contractor engineer has sized an air receiver with 1000 Sm3/h and client engineer has rechecked the air receiver size. It was found that the basic parameters such as flowrate, operating pressure and temperature, etc are same, however air receiver size calculated by contractor engineer is different than client engineer. After several round of discussion, they found both engineers calculation method are same.

What is the factor cause the difference ?

Different Defintion
A detail analysis on both calculations found that the definition of "Standard" condition are different between the contractor engineer and client engineer. Contractor engineer has used 1.01325 bara @ 0 degC (stated in contractor design manual) whilst client engineer has used 1.01325 @ 25 degC (stated in client common requirement manual). Above situation is pretty common discrepancies in design and engineering. Although both engineers talk about the same thing, "Normal" condition, the results may not be the same due the differences in definition. Thus, it is a good engineering practice to write down the defintion clearly in the calculation note or in a common design basis document.

Following are a list of "Standard" condition for several organizations :

In SI Unit :

• EPA - 1.01325 bara @ 25 degC
• NIST - 1.01325 bara @ 20 degC
• IUPAC - 1.0 bara @ 0 degC
• ISA - 1.01325 @ 15 degC
• SATP - 1.0 @ 25 degC
• CAGI - 1.0 bara @ 20 degC
• SPE - 1.0 bara @ 15 degC
• SHELL - 1.01325 @ 25 degC
• EXXON - 1.01325 @ 15 degC

In US custom :

• SPE - 14.696 psia @ 60 degF
  
• OSHA - 14.696 psia @ 60 degF
• OPEC - 14.73 psia @ 60 degF
• ISO 2314 - 14.696 psia @ 59 degF
• ISO 3977-2 - 14.696 psia @ 59 degF
• U.S. Army - 14.503 psia @ 59 degF

Source : Wikipedia


SI & US Custom
Another factor may also cause the descrepancies is the reference unit. The defintion in SI unit may NOT same as US custom unit eventhough within an organization. For example, SPE defined Standard condition as

• 1.0 bara @ 15 degC in SI unit
• 14.696 psia @ 60 degF in US custom unit

The temperature are not identical 60 degF is equivalent to approximately 15.56 degC, not exactly same as 15 degC. Thus, it is always advisable to make correct unit reference in the calculation and/or Design basis document.

Conversion between two different "Normal" condition
Let take above example, 1000 Sm3/h as defined by contractor. What is the equivalent flow (Sm3/hr) for client engineer ?

Contractor manual : 1.01325 bara @ 0 degC
Client manual : 1.01325 @ 25 degC

Equation for conversion can be taken from discussion in "Relate Normal to Actual Volumtric Flow"

Q₂ = (z₂/z₁) x (T₂/T₁) x (P₁/P₂) x Q_{1 .....[1]}

where
Q₁ & Q₂ are Volumetric Flow in m3/h for condition 1 & 2
P₁ & P₂ are Pressure in bar abs for condition 1 & 2
T₁ & T₂ are Temperature in K for condition 1 & 2
z₁ & z₂ are compressibility factor for condition 1 & 2

Condition 1 : 1.01325 bara @ 0 degC (Contractor manual)
Condition 2 : 1.01325 bara @ 25 degC (Client manual)
Assume z₁ = z₂ = 1
Q₁ = 1000 Nm3/h @ Condition 1

From [1],
==> Q₂ = (z₂/z₁) x (T₂/T₁) x (P₁/P₂) x Q₁
==> Q₂ = (298.15 / 273.15) x 1000
==> Q₂ = 1091.525 m3/h

The equivalent flow for 1000 Sm3/h @ condition 1 = 1091.525 Sm3/h @ Condition 2. Client engineer shall use 1091.525 Sm3/h in his/her calculation.

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Check Valve Types and Selection

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Check valves or Non-return valves (NRV) are normally installed in piping to avoid back flow. Rotating equipment such as pump, compressor, etc will always be equipped with NRV(s) on the discharge to avoid back flow when rotating equipment is shut. Back flow creates severe surging to the rotating equipment and potentially damage the equipment. In certain process system, NRV will be employed to avoid contamination, overheating, etc due to back flow.

Check valves or Non-return valves (NRV) is basically an automatic valve open to allow forward flow and close to against reverse flow. In principle, it split into four basic types. There are swing, dual-plate, tilting disc and lifting type. Wrong selection of check valve type can leads to operability problem, leakage and continual maintenance issue.

Lift Check valves
- higher pressure drop is expected.
- equipped with small return spring to facilitate valve closure on reverse flow
- two type of seat. hard seat for for high differential pressure sealing and resilient seat for low differential pressure sealing
- shortest travel length. Fastest response.
- excellent performance for low and/or pulsating flows
- not good for fluid with particles
- Body install horizontal with disc / piston vertically
- Small check valve range from 1/2" to 2" lift piston type check valve
- Prefer operate in full open position

Minimum Recommended Line Velocity, Vmin (ft/s) = 12 SQRT (v)

where
v = Specific Volume of the Fluid (ft3/lb)

Lift Check Valve

Swing Check Valve
- Tight sealing / shut-off
- Low pressure drop
- Susceptible to water hammer
- Not good for low flow and/or pulsating flow
- Vertical (upward flow) & horizontal installation
- Easiest check valve to maintain
- Prefer operate in full open position

Swing check valves should be sized such that the flow velocity in the line is sufficient to hold the disc in the fully open position.

Minimum Recommended Line Velocity, Vmin (ft/s) = 75 SQRT(v)

where
v = Specific Volume of the Fluid (ft3/lb)

Swing Check Valve

Dual plate Check valve
The characteristic of dual plate check valve is pretty same as swing check valve.
- low pressure drop
- Not good for low flow and/or pulsating flow
- Vertical (upward flow) & horizontal installation
- Faster opening and closure compare to swing check valve
- Susceptible to water hammer (lesser than Swing check valve)
- Prefer operate in full open position

Dual Plate Check Valve

Tilting Disc Check Valves
- Fast opening and closing without damage to disc and seat
- Stable at low and pulsating flows
- Moderate pressure drop. Lower than lifting check valve but higher than swing check valve
- Vertical (upward) & horizontal installation
- Moderate tight sealing
- Prefer operate in full open position

Minimum Recommended Line Velocity, Vmin (ft/s) = 24 sqrt (v)

where
v = Specific Volume of the Fluid (ft3/lb)

Tilting Disc Check Valve

Selection Consideration
There are four (4) main criteria shall be considered for the selection of check valve type :

• non-slam characteristic
• pressure loss
• cost
• application

Comparative rating for each type of check valve have been provided for these criteria (specifically first two technical criteria). These rating will be plotted on a Check Valve Comparative Selection Chart and together budget for final selection. Read more in "Design and Selection of Check Valve".

Related Post

• Several Strategies To Minimize Relief Capacity in Back-Flow Scenario
• How to predict Check Valve Slam ?
• How to Select a Check Valve (NRV) Quantitatively ?
• Why Redundant NRV in Series within a Line ?
• Why bypass Non-Return Valve (NRV) ?
• Potential Problem associate with Double NRV in Series within a Line
• Basis & Tips on Setting Centrifugal Pump "Warming" Recycle Flow

Basis & Tips on Setting Centrifugal Pump "Warming" Recycle Flow

Display problem ? Click HERE

Earlier post "Why bypass Non-Return Valve (NRV) ?" discussed the purpose of providing manual block valve across Non-Return Valve (NRV) on centrifugal pump discharge. Typical the purpose covers :

• Pump priming
• Pump warming
  
• NRV downstream section draining

Recommended :
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Now the question is focus on pump warming. What is the basis of setting this recycle flow rate ? Lets first define 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

• fixed restriction orifice (RO) or;
  
• non-return valve (NRV) with hole or;
  
• globe valve

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

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

Tips

Generally above calculation are time consuming. 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.

Related Post

• Removal of Specific Heat ratio (k) in the Mach No. & Critical Pressure Calculation
• Two Useful Equations For Flow Conversion between Air - Vapor & Actual - Standard
• Potential Problem associate with Double NRV in Series within a Line
• Restrcition Orifice Used in Many Applications in Different Manners
• A refresh to Process Engineer on few phenomenons in restriction orifice
• Why Restriction Orifice is some distance from Blowdown valve ?