Have you ever taught of applying Flow-Delta protection strategy in pump minimum flow protection?

All centrifugal compressor potentially surge when the flow rate crosses the surge point and potentially leads to catastrophic failure. Hence, anti-surge control is always implemented to safeguard a centrifugal compressor. Flow-Delta anti-surge protection strategy (Fig. 1) is on of the anti-surge control widely applied in centrifugal compressor as anti-surge protection strategy.

Fig. 1 Typical Flow-Delta anti-surge protection strategy

Centrifugal pump may subject to cavitation when the flow rate reach it minimum allowable flow where severe internal recirculation occurred and potentially damage the pump impeller. A process engineer shall always implements minimum flow protection strategy for centrifugal pump to avoid the potential damage. Typical centrifugal pump minimum flow control strategies are:

(i) A restriction orifice on pump discharge recycle line
(ii) A flow meter on pump discharge with control valve on recycle line
(iii) Use Automatic Recirculation Valves (ARC) valve

Is it feasible applying Flow-Delta protection strategy in pump minimum flow protection?

Yes. Above strategy is feasible A paper written by S. Mirsky (from CCC) described in brief the implementation of the above strategy.

Fig. 2 : Minimum flow protection strategy for centrifugal pump

Source : Pump Control Strategies Benefits from Compressor Know-How (HP,Feb 2005)

Figure above shows application of Flow-Delta anti-surge protection strategy for centrifugal pump minimum flow protection in Offshore Seawater injection system.

Reference :
S, Mirsky, << Pump Control Strategies Benefits from Compressor Know-How >>, Hydrocarbon Processing, Feb 2005

JoeWong

Is Stainless Steel SS316 resist to CAVITATION ?

RECALL...
As everybody aware that Stainless Steel (i.e. SS316) is "soft" compare to other material e.g Cast Iron, Duplex stainless steel, etc.

Why is stainless steel so good against cavitation ?
Wouldn't the imploding bubbles erode Stainless steel which is rather "soft" ?



This main due to work-hardening property of Stainless Steel. As one hammering a SS316 strip, you may notice that the surface work-hardens and difficult to change the shape.

Similar phenomenon occurs when fluid bubbles imploding and impacting on the surface of stainless steel. Implosion of bubble causing the Stainless steel work-hardens, and increase resistance to further cavitation.

As per expert advice (Pump Magazine), SS316 resists cavitation about 10-15 times better than cast iron whilst CA6NM (modified SS316) is roughly 2-3 times more resistant to cavitation as compared to SS 316.

Amazing !!!

JoeWong

Good documents on CRA & Corrosion control

Some good documents on CRA & Corrosion control found today...particularlly useful for those involve in Oil & Gas (O&G) and Exploration &amp;amp; Production (E&P) ...


“Performance of Duplex Stainless Steels in Hydrogen Sulphide Containing Environments”, Paper 207, Duplex Stainless Steels 1997, Maastricht, 21-23 October 1997. SMITH L.M. and FOWLER C.

“Control of Corrosion in Oil and Gas Production Tubing,” British Corrosion Journal, Volume 34, Number 4, 1999, P247 (Bengough Award for a paper with a strong industry overview given for this paper in year 2000). SMITH L.M.

“A Guideline To The Successful Use Of Duplex Stainless Steels For Flowlines”, Plenary Lecture, Duplex 2000, Houston TX, USA, 29 Feb - 1 March 2000. SMITH L.M, CELANT M. and POURBAIX A.

JoeWong

Additional snapshot…….some articles good for young engineer and experience engineer as refresher…

The following two snapshots show PUMP CAVITATION is BAD !!!

Snapshot below : Two identical impellers with the impeller on the left has been subjected to cavitation. Metal has worn away at the edge and in the eye of the impeller. A hole has actually been worn through the impeller at the 1:00 O'Clock position and a crescent is completely gone at 9: O’clock position.

Can you imagine the consequence if operator is standing around this area when it happen….

DO NOT UNDER-ESTIMATE THE CONSEQUENCE OF CAVITATION !!!

REFRESHER CORNER
Following are some document links…

Detecting Cavitation in Centrifugal Pumps
A research paper studied online detection and monitoring of cavitation in centrifugal pump. Useful for plant operator in predicting the performance of pump and to avoid catastrophic failure of centrifugal pump…

Protect Your Pump
GOOD SELECTION – PROPER INSTALLATION – REGULAR MAINTENANCE
There are many opportunities to protect your pump. The best pump protection is selecting the right pump for the application. The next best pump protection is proper installation. And the easiest pump protection is regular maintenance…

Inlet conditions check-list
A good article for plant operator and start-up profession. Inadequate inlet conditions can cause serious malfunctions in the best designed pump. Surprisingly the simplest of things can cause the most severe problems or go unnoticed to the unfamiliar or untrained eye. REVIEW THIS CHECK-LIST BEFORE OPERATION OF ANY SYSTEM……

Pump training
A good brief for new engineer and refresh for experienced engineer……

Pump cavitation caused by entrained gas
A case study presents troubleshooting an FCC main fractionator revamp including the LCO pump around (PA) pump that was cavitating due to entrained gas. Pump cavitation and column flooding caused reduced column removal, decreased column capacity, degraded fractionation, lower-than-design unit capacity and high endpoint gasoline. The short-term remedy and longer-term modification to correct the root cause are discussed.

JoeWong

What are the conditions causing pump cavitation ?

Five main conditions may result pump cavitation and potentially damage pump impeller, chamber and bearing. Understanding of factors causing and affecting these conditions is rather important as it assist in troubleshooting pump cavitation problem. They are :

• Vaporization
• Gas and/or non-condensable fluid entrainment
• Internal recirculation
• Flow turbulence
• The Vane Passing Syndrome

Vaporization .
Pump fluid vaporizes when operating pressure drop below its vapor pressure at specific flowing temperature. A process engineer must always keep this in mind and always to ensure pump fluid will be vaporized at minimum operating pressure along fluid path from suction vessel/tank to pump chamber at worst flowing temperature. Net Positive Suction Head (NPSH) is a parameter used to measure possibility of cavitation. A process engineer must always ensure NPSH available must always higher than NPSHr.

NPSHa > NPSHr

Obviously in order to maintain above requirement, a process engineer may aim to INCREASE NPSHa and / or DECREASE NPSHr.

Increase NPSHa
Now we shall further look into the possibility of increasing NPSHa :

Net Positive Suction Head (NPSH) available define as follow :

Process engineer should target to increase Suction static head & Operating head (pressure) and decrease fluid vapor pressure @ flowing temperature and frictional head.

As discussed earlier, there are few ways to increase NPSHa :

a) Increase suction line size to reduce friction head loss. Generally flow velocity is less than 1 m/s

b) Rearrange and /or redesign suction pipe work to minimise bends, valves and fittings

c) Raise suction vessel

d) Increase & maintain pressure in suction vessel

e) Reduce fluid vapor pressure i.e. subcool fluid In additional, process may pay consider the following :

f) Install a booster pump (if necessary)

g) Do not installed over-capacity pump (after suction line size is fixed)

h) Injecting a cooler fluid at the suction vessel (if practical) i) Insulate piping to avoid solar heating

j) Avoid recirculation line directly feed to pump suction line as pumping may raise fluid temperature

k) Use 45° elbows instead of 90° elbows to reduce friction

l) Do not select overly fine screens or intake filters and choose cleanable screen m) Avoid pocket at pump suction line

n) Ensure correct gasket installed at pump suction and tie flange to minimize air ingress

o) Use eccentric type reducer instead of concentric type

Sometime pump cavitation will only occur after the pump is operated for some period. Process engineer may look into the following factors :

- pipe liner has collapsed or solid / corroded material built-up and blocking suction strainer

- Tank vents blocked causing pressure dropped. Vent can be blocked frozen ice in cold weather, bird & insert, etc

- A bigger pump has been installed on existing system cause high line loss

- Install globe valve instead of gate valve at pump suction

- gasket protruding into the pipe

- Increased pump speed especially variable speed drive pump

Decrease NPSHr
AS discussed earlier, NPSHr is very much subject to design and construction of a pump and upto manufacturer. Nevertheless, Process engineer may advise to consider and include in the process design with the follow choices :

- Use a double suction pump where NPSHr can be reduced by almost 25%
- Use low speed pump
- Use pump with large impeller eye opening
- Install Inducer (inducers can cut NPSHr by almost 50%)
- Installer smaller pump by adopting 3 x 50% instead of 2 x 100%. Normally smaller pump may required lower NPSHr

Process engineer is advised to take some margin on the NPSH. The margin of 1 m is recommended for vaporization case.

Gas entrainment
Gas entrainment from suction vessel into pump fluid has an adverse effect on the pump impeller. Entrained gas will form bubbles in the flowing fluid and the bubbles will collapse as they pass from the eye of the pump to the higher pressure side of the impeller. Collapse of entrained gas as compare to bubble formed due to vaporization, it has lower impact to the pump impeller. The main effect is entrained gas is capacity loss.

There are number of ways may result gas entrained into pumping fluid :

• Through the packing stuffing box. This occurs in any packed pump that lifts liquid, pumps from a condenser, evaporator, or any piece of equipment that runs in vacuum
• Valves located above the water line
• Through leaking flanges
• Pulling air through a vortexing fluid
• If a bypass line has been installed too close to the suction, it will increase the temperature of the incoming fluid
• Any time the suction inlet pipe looses fluid. This can occur when the level gets too low, or there is a false reading on the gauge because the float is stuck on a corroded rod.
  

Internal recirculation
Internal recirculation occurs at leading edge of the impeller, close to the outside diameter, working its way back to the middle of the vane. Similar condition occurs at pump suction eye as well. Fluid recirculates will results its velocity increase and subsequent pressure drop until it vaporizes. Bubbles may collapse quickly at the surrounding higher pressure region within pump impeller.

Flow turbulence
Flow turbulence is always occurred of the pump suction with impeller impacting the incoming fluid. Change of incoming fluid will change velocity and it operating pressure and results short term cavitation.

The Vane Passing Syndrome
Vane passing syndrome and causing cavitation occurred when the OD of the impeller passes too close to the pump cutwater. The velocity of the liquid increases as it flows through this small passage, high velocity lowering the fluid pressure and causing local vaporization. The bubbles then collapse at the higher pressure region just beyond the cutwater. This phenomenon occurred at the center of the impeller vane.

JoeWong

Pump Cavitation Phenomenon & How to avoid

Cavitation is the formation and collapse of vapor bubbles in a liquid.

Following are some examples of impeller damage by cavitation.

Bubble formation occurs at a point where the fluid operating pressure is lower than fluid vapor pressure, and bubble collapse or implosion occurs at a point where the pressure is increased to the vapor pressure. In general, cavitation occur at pump suction with lowest possible operating pressure. Figure P1 below shows a typical pressure profile in a centrifugal pump. As pumping fluid passing pump, operating pressure drop due to frictional lose (Entrance loss (path A-C). Once the liquid enters pump chamber, it will experience serious turbulence cause by impeller. Major Turbulence Friction Entrance Loss is expected along path C-D. Once the fluid reach point D, impeller generated large centrifugal force and acting on the liquid. The energy is transferred from pump impeller to liquid and increase liquid velocity and operating pressure. As the liquid is leaving the pump exit chamber, fluid velocity is reduced (expansion) velocity head is converted to pressure head base on Bernoulli principle (by Daniel Bernoulli) . This will further increase the fluid operating pressure (path D-E)


Figure P2 below shows as fluid B with low vapor pressure below lowest operating pressure in pump, NO cavitation occur. However, fluid A with high vapor pressure, as the operating pressure lower than fluid vapor pressure bubble form. Once fluid passing the impeller, operating pressure increased will cause bubble collapse (sometime called implosion) once the operating pressure above the vapor pressure. Above phenomenon occur in a very short time and it cause several things happen at once : · Bubbles collapsed when they pass into the higher regions of pressure, causing noise and vibration· Loss in capacity. · No longer build the same head (pressure) · Efficiency drops· Damage to many of the components i.e. chamber, impeller, etc.

One shall understand that pump chamber and impeller design will serious affect the entrance friction loss and turbulence loss caused by impeller. Refer to figure P3 below. Pump A having high entrance friction loss and turbulence loss results cavitation occurred. However, pump B shows low entrance friction loss and turbulence loss, operating pressure is always above vapor pressure and NO cavitation will occur.

Thus Process engineer must always ensure the operating pressure along the pump always higher than fluid vapor pressure. Generally Net positive suction head (NPSH) is used to check if cavitation will occur. Process engineer must always ensure available Net positive suction head (NPSHa )is always higher than pump required Net positive suction head (NPSHr).

Golden Rule ==>

NPSHa > NPSHr

The following chart illustrate the relationship between NPSHa & HPSHr

As NPSHr is subject physical construction of pump (by manufacturer), it is not much a Process Engineer can do other than specifying the requirement and selection of correct pump. However, Process engineer can put extra effort to increase NPSHa.

There are few ways to increase NPSHa :

a) Increase suction line size to reduce friction head loss. Generally a flow velocity less than 1 m/s

b) Rearrange and /or redesign suction pipe work to minimise bends, valves and fittings

c) Raise suction vessel

d) Increase & maintain pressure in suction vessel

e) Reduce fluid vapor pressure i.e. subcool fluid

From process perspective, step (a) to (c) are common apply to raise NPSHa as they can be implemented easily. As for step (d) & (e), they involve new equipment & control devices and directly increase CAPEX and OPEX of a project. Generally not advisable to apply unless all efforts are implemented.

(There are other factors & phenomenons causing pump cavitation e.g. gas entrainment, recirculation, etc...will discuss next day...to be continued)

JoeWong

Unified Numbering System for Metals and Alloys

What are the differences between Duplex Stainless Steel, Medium Alloy Duplex, 22% Cr, SAF 2205 and UNS 31803 ?

Infact, all refer to same metal. Duplex Stainless Steel and Medium Alloy Duplex is general (layman) term and commonly used across discipline. Material specialist like to call it 22% Cr. SAF 2205 is the trade name where procurement people like put it in purchase order. Different terms used sometime may results confusion and miscommunication. Thus, Unified Numbering System (UNS) has been created for standardization and easy administration. This system is widely use in North American included Canada.

“The Unified Numbering System for Metals and Alloys (UNS) provides a means of correlating many internationally used metal and alloy numbering systems administered by societies, trade associations, and those individual users and producers of metals and alloys. It provides the uniformity necessary for efficient indexing, record keeping, data storage and retrieval, and cross-referencing.”

Above was extracted from book <<Metals & Alloys in the Unified Numbering Systems >>. This book (in CD) provides information on :

• UNS number
• Description
• Common trade names and alloy designations
• Cross-reference organization
• Cross-reference specifications
• Chemical composition

The UNS is managed jointly by the American Society for Testing and Materials (ASTM) and the Society of Automotive Engineers (SAE).

The UNS number (for "Unified Numbering System for Metals and Alloys") is a systematic approach where each metal is designated by a LETTER followed by five NUMBERS. The number is unique and composition-based of commercial materials. It is used for material reference but it does not guarantee any performance specifications and/or exact composition.

Following are overview of common commercial metals / alloys using UNS system :

• Axxxxx - Aluminium Alloys
• Cxxxxx - Copper Alloys, including Brass and Bronze
• Fxxxxx - Iron, including Ductile Irons and Cast Irons
• Gxxxxx - Carbon and Alloy Steels
• Hxxxxx - Steels - AISI H Steels
• Jxxxxx - Steels - Cast
• Kxxxxx - Steels, including Maraging, Stainless, HSLA, Iron-Base Superalloys
• L5xxxx - Lead Alloys, including Babbit Alloys and Solders
• M1xxxx - Magnesium Alloys
• Nxxxxx - Nickel Alloys
• Rxxxxx - Refractory Alloys
• R03xxx- Molybdenum Alloys
• R04xxx- Niobium (Columbium) Alloys
• R05xxx- Tantalum Alloys
• R3xxxx- Cobalt Alloys
• R5xxxx- Titanium Alloys
• R6xxxx- Zirconium Alloys
• Sxxxxx - Stainless Steels, including Precipitation Hardening and Iron-Based Superalloys
• Txxxxx - Tool Steels
• Zxxxxx - Zinc Alloys
  
  
  Typical examples :

More photos for CSCC

Additional CSCC photos...

CSCC occured on insulated vessel

CSCC occured on insulated vessel

JoeWong

Snapshot of Metal Cracks Due to Chloride Stress Corrosion Cracking

Some snapshot of metal cracks as a results of Chloride Stress Corrosion Cracking…...

Inter granular SCC of an Inconel heat exchanger tube
Source : Corrosion Doctor

Trans granular SCC of 316 stainless steel chemical processing piping system
Source : Corrosion Doctor

Inter granular SCC of a pipe
Source : The National Physical Laboratory

JoeWong

Chloride Stress Corrosion Cracking of SS304, SS316, DSS & Super DSS and Use correct MOC for seawater service

Chloride stress - corrosion cracking (CSCC) is initiation and propagation of cracks in a metal or alloy under tensile stresses and a corrosive environment contains Chloride compounds. Once the crack is initiated, it will propagate rapidly and potentially lead to catastrophic failure.

Factors that influence the rate and severity of cracking include

· chloride content
· oxygen content
· temperature
· stress level
· pH value of an aqueous solution

It has been established that oxygen is required for chloride cracking to occur. However, recent findings showed that CSCC can occur in Duplex Stainless Steel (DSS) at high chloride concentration and NO oxygen environments (HSE report 129).

The severity of cracking increases with temperature. Figure below shows several Stainless Steel materials increases it susceptibility to CSCC as temperature is increased.

Source : Sandvik Material Technology

SAF 2205 (UNS 31803) = Duplex Stainless Steel
SAF 2507 (UNS 32750) = Super Duplex Stainless Steel

CASE STUDIES

Hot gas (Shell) is cooled by seawater (Tube) from 220 degC to 180 degC in a Shell & Tube heat exchanger. Seawater is being heated from 30 degC to 35 degC and return to sea. The Shell and Tube material of construction are Carbon steel (CS) and Duplex Stainless Steel (DSS) respectively. After 2 months in operation, cracks occurred at the tube (DSS) and leads to major platform shutdown. Investigation found crack was caused by CSCC at tube. Why a CSCC occurred at DSS tube although the seawater temperature only 35 degC maximum ?

One shall understand that although the inlet and outlet temperature are below 150 degC, thermal designer may design the heat exchanger with high heat flux in order to reduce the heat exchanger area and this result tube skin temperature exceed 150 degC. Condition with Seawater which contains ~20,000 mg/l Chloride, high in dissolved oxygen, slightly acidic and skin temperature exceeded 150 degC is perfect combination for CSCC to occur for DSS. One shall check skin temperature profile especially for low flow condition or specify better material i.e. Super DSS for above service.

Comments are Welcome !

JoeWong

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CHEMICAL & PROCESS ENGINEERING CORNER

JoeWong

tji1126@gmail.com