Friday, July 27, 2012

Kilang Minyak Blok Diagram

Pas lagi senggang, iseng belajar tentang Crude Refinery Configuration deh,, and ini salah satu contohnya. Crude refinery configuration itu bisa macem-macem, tergantung concern dari masing-masing perusahaan yang ingin dikedepankan. Dan juga dengan mempertimbangkan kondisi bahan baku dan produk yang diinginkan (bisa Mogas, Jet-E1, Gas Oil dll). Dibawah ini salah satu contoh Kilang Minyak Blok Diagram yang mungkin bisa buat belajar bersama.


Refinery (kilang minyak) terdiri dari beberapa unit proses. Diantaranya akan dijelaskan secara singkat sebagai berikut :

1.      Crude Distillation Unit (CDU)
Crude Distillation Unit (CDU) adalah unit yang berfungsi untuk pemisahan awal fraksi minyak mentah berdasarkan range titik didih masing-masing komponen. Feed berupa Crude Oil (minyak mentah) mula-mula diumpankan ke dalam Atmospheric Distillation Column untuk dipisahkan antara Fuel Gas (FG), Naphtha, Kerosene, Light Gas Oil, Heavy Gas Oil, dan Atmospheric Bottom Product (ABP) berdasarkan perbedaan titik didihnya. Produk atas berupa FG akan dikirim menuju FG system yang mencakup amine treating dan LPG Recovery. Side cut berupa Naphtha kemudian akan diolah lebih lanjut di Unit NHT. Kerosene dan Light Gas Oil kemudian akan diolah di unit Hydro Desulfurization (HDS) unit. Heavy Gas Oil dipisahkan dan akan diolah di Unit Fluidized Catalytic Cracking (FCC) sebagai feed. Sedangkan ABP kemudian dimasukkan sebagai feed Vacuum Distillation Unit (VDU).
2.      Vacuum Distillation Unit (VDU)
Vacuum Distillation Unit berfungsi sebagai unit pemisah sama seperti Atmospheric Distillation Unit, hanya saja yang berbeda adalah tekanan operasi Kolom Destillasinya dibuat vakum. Unit ini berfungsi untuk memisahkan fraksi Light Vacuum Gas Oil (LVGO), Medium Vacuum Gas Oil (MVGO), Heavy Vacuum Gas Oil (HVGO), dan Residue. Side cut produk berupa LVGO dan MVGO selanjutnya akan diolah lebih lanjut di Unit FCC, dan HVGO akan menjadi salah satu feed Hydrocracker Unit, sedangkan bottom product berupa Residue dibagi 2, sebagian diolah di Unit Delayed Coker, dan sebagian diolah ke Unit Asphalt Blowing.

3.      Naphtha Hydrotreating Unit (NHT)
Naphtha Hydrotreating Unit (NHT) berfungsi untuk menghilangkan dan atau mengurangi kadar sulphur, nitrogen, metal dan contaminant lain yang ada di Naphtha. Naphtha yang sudah dihilangkan kontaminannya (Sweet Naphtha) kemudian dipisahkan di Splitter untuk dipisahkan antara FG, Light Naphtha (LN) dan Heavy Naphtha (HN). Produk atas berupa FG kemudian akan dikirim ke FG system dan Light Naphtha dikirim langsung ke Gasoline Pool sebagai campuran Mogas Blending. Sedangkan produk bawah berupa Heavy Naphtha diolah lebih lanjut pada Unit Reformer.

4.      Hydro Desulfurization Unit (HDS)
Hydro Desulfurization Unit (HDS) berfungsi untuk menghilangkan dan atau mengurangi kadar sulphur dan contaminant lain yang ada pada feed Hydrocarbon. Terdapat 2 Unit HDS, HDS-1 untuk feed Kerosene dan HDS-2  untuk feed Light Gas Oil (LGO), Light Coker Gas Oil (LCGO) dan Light Cycle Oil (LCO). Untuk HDS-1, produknya berupa Kerosene dengan kadar sulfur max 0.2 %wt. Sedangkan untuk HDS-2 produknya adalah Gas Oil dengan kadar sulfur max 50 ppm. FG dari HDS-1 dan HDS-2  kemudian akan dikirim ke FG system.

5.      Fluidized Catalytic Cracking Unit (FCC)
Fluidized Catalytic Cracking Unit (FCC) merupakan Unit proses yang berfungsi untuk mengubah Hydrocarbon (HC) rantai panjang menjadi HC rantai pendek dengan bantuan katalis dalam Reactor Fluidized.
Di dalam unit FCC, juga include Unit HDS untuk menghilangkan contaminant sulfur dan metal sebelum masuk ke dalam reactor, agar katalis tidak teracuni. Produk atas berupa FG dikirim ke FG system, FCC Gasoline (yang merupakan produk utama) dikirim ke Gasoline Pool untuk menjadi Mogas Blending component. Sidecut berupa Light Cycle oil (LCO) dikirim ke HDS-2 sebagai feed dan Heavy Cycle Oil (HCO) dikirim ke Unit Hydrocracker sebagai feed. Sedangkan produk bawah berupa Heavy Fuel Oil (HFO) dikirim ke FO Tank sebagai produk akhir.

6.      Hydrocracker Unit
Hydrocracker Unit merupakan unit proses yang berfungsi untuk memotong HC rantai panjang menjadi HC rantai pendek dengan bantuan gas Hidrogen. Feednya berupa HVGO, HCO, dan Heavy Coker Gas Oil (HCGO). Produk atas berupa FG dikirim ke FG system dan Hydrocracked Gasoline dikirim ke Gasoline pool. Sedangkan produk bawah berupa LCGO dikirim ke Gas Oil Tank.

7.      Delayed Coker
Delayed Coker merupakan unit proses yang berfungsi untuk memotong HC rantai panjang menjadi HC rantai pendek. Feed berupa residue, produk bawah VDU, yang banyak mengandung wax dan asphalt. Di Unit ini dihasilkan produk atas berupa FG yang akan dikirim ke FG system, Coker Naphtha yang dikirim ke Unit Reformer, Side cut produk berupa Light Coker Gas Oil (LCGO) dikirim ke HDS-2 sebagai feed, Heavy Coker Gas Oil (HCGO) dikirim ke Unit Hydrocracker sebagai feed. Produk samping dari Unit ini adalah terbentuknya coke.

8.      Asphalt Blowing Unit
Asphalt Blowing Unit menghasilkan asphalt dari bahan baku Reisdue VDU.

9.      Reformer Unit
Reformer Unit adalah unit yang berfungsi untuk merubah senyawa HC non-aromatic menjadi senyawa HC aromatic. Termasuk di dalam Unit ini adalah Coke NHT dimana feednya berupa Coker Naphtha. Umpan Reformer berasal dari produk bawah NHT unit yaitu HN, Coker Naphtha. Produk dari Unit ini adalah FG dan Refformate. FG sebagai produk atas akan dikirim ke FG system sedangkan Refformate sebagai produk bawah akan dikirim menuju Gasoline Pool sebagi Mogas Blending Component.

10.      Sulfur Plant
Unit ini berfungsi untuk menrecovery sulfur dari Gas Plant.
Hehe...cuma itu dulu yg saya tahu,,kl ada yang salah mohon dimaafkan :)



Thursday, July 19, 2012

Gasoline and Driving Performance Explanation

Most country in this world very depend on fuel oil for their industrial or transportation activities. One of the most important fuel is Gasoline. Here is short hystory of Gasoline :

In May 1876, Nicolaus Otto built the first practical four-stroke-cycle internal combustion engine powered by a liquid fuel. By 1884, he concluded development of his engine with the invention of the first magneto ignition system for low-voltage ignition. The liquid fuel used by Otto became known as gasoline in the United States; elsewhere it may be known as gasolina, petrol, essence, or benzin (not to be confused with the chemical compound benzene).



Many people know about Gasoline just as a fuel engine or fuel car, only few people know and understand that Gasoline keep an amazing secret to be learn. And you know what ? here is the secret :

1. Because gasoline almost always performs well, drivers forget what a sophisticated product it is.   
    More thought would reveal a demanding set of performance expectations:
  • An engine that starts easily when cold, warms up rapidly, and runs smoothly under all conditions.
  • An engine that delivers adequate power without knocking.
  • A vehicle that provides good fuel economy and generates low emissions.
  • A gasoline that does not add to engine deposits or contaminate or corrode a vehicle’s fuel system.
2. Volatility

Driveability describes how an engine starts, warms up, and runs. It is the assessment of a vehicle’s response to the use of its accelerator relative to what a driver expects. Driveability problems include hard starting, backfiring, rough idling, poor throttle response, and stalling (at idle, under load, or when decelerating).The key gasoline characteristic for good driveability is volatility – a gasoline’s tendency to vaporize. Volatility is important because liquids and solids don’t burn; only vapors burn. When a liquid appears to be burning, actually it is the invisible vapor above its surface that is burning. This rule holds true in the combustion chamber of an engine; gasoline must be vaporized before it can burn. For winter weather, gasoline blenders formulate gasoline to vaporize easily. Gasoline that vaporizes easily allows a cold engine to start quickly and warm up smoothly. Warm-weather gasoline is blended to vaporize less easily to prevent engine vapor lock and other hot fuel handling problems and to control evaporative emissions that contribute to air pollution.

It is important to note that there is no single best volatility for gasoline. Volatility must be adjusted for the altitude and seasonal temperature of the location where the gasoline will be used. Later, this chapter will explain how gasoline specifications address this requirement. Three properties are used to measure gasoline volatility in the United States: vapor pressure, distillation profile, and vapor-liquid ratio. A fourth property, driveability index, is calculated from the distillation profile. Instead of a vapor-liquid ratio, a vapor lock index is used outside the U.S. to control hot fuel handling problems.

3. Vapour Pressure

With respect to gasoline, vapor pressure (VP) is the single most important property for cold-start and warm-up driveability. (Cold-start means that the engine is at ambient temperature, not that the ambient temperature is cold.) When gasoline vapor pressure is low, an engine may have to be cranked a long time before it starts. When vapor pressure is extremely low, an engine may not start at all. Engines with port fuel injection (see page 66) appear to start more readily with low vapor pressure fuel than do carbureted engines. Vapor pressure varies with the season; the normal range is 48.2 kPa to 103 kPa (7 psi to 15 psi). Higher values of vapor pressure generally result in better cold-start performance, but lower values are better to prevent vapor lock and other hot fuel handling problems.

4. Distillation profile

Gasoline is a mixture of hundreds of hydrocarbons, many of which have different boiling points. Thus gasoline boils, or distills, over a range of temperatures, unlike a pure compound; water, for instance, boils at a single temperature. A distillation profile, or distillation curve, is the set of increasing temperatures at which gasoline evaporates for a fixed series of increasing volume percentages (5 percent, 10 percent, 20 percent, 30 percent and so on) under specific conditions (see page 48). Alternatively, the profile may be the set of increasing evaporation volume percentages for a fixed series of increasing temperatures. Figure 1.1 shows the 2008 U.S. average distillation profiles of conventional summer and winter gasolines. A distillation profile is also shown for a summer reformulated gasoline (RFG) containing ethanol.

Various ranges of a distillation profile correlate with specific aspects of gasoline performance.
Front-end volatility is adjusted to provide:
  • Easy cold starting.
  • Easy hot starting.
  • Freedom from vapor lock or other hot fuel handling problems.
  • Low evaporation and running-loss emissions.
Midrange volatility is adjusted to provide:
  • Rapid warm-up and smooth running.
  • Good short-trip fuel economy.
  • Good power and acceleration.
  • Protection against carburetor icing and hot-stalling.
Tail-end volatility is adjusted to provide:
  • Good fuel economy after engine warm-up.
  • Freedom from engine deposits.
  • Minimal fuel dilution of crankcase oil.
  • Minimal volatile organic compound (VOC) exhaust emissions

5. Vapor Lock and Hot Fuel Handling Problems

Vapor lock and hot fuel handling problems occur when excessive gasoline vapor accumulates somewhere in the fuel system of a vehicle and reduces or interrupts the fuel supply to the engine. This may take place in the fuel pump, the fuel line, the carburetor, or the fuel injector. When the fuel supply is reduced, the air-fuel ratio becomes too fuel-lean (too much air for the amount of fuel), which may cause loss of power, surging, or back firing. When the fuel supply is interrupted, the engine stops and may be difficult to restart until the fuel system has cooled and the vapor has recondensed. After a hot soak (engine shutdown), it may be difficult to start the engine if too much vapor has formed in the fuel system. Overheated fuel or overly volatile fuel is the main cause of vapor lock. Fuel temperature depends on several factors: the ambient temperature, how hard the vehicle is working, how well the fuel system is isolated from the heat of the engine, and how effectively the fuel system is cooled.

6. Carburetor Icing

Carburetor icing occurs when intake air is chilled below the freezing point of water by evaporation of gasoline in the carburetor. Ice forms on the throttle blade and in the venturi and can interrupt carburetion, causing an engine to stall. Icing can be acute when the air is moist (70 percent or higher relative humidity) and the ambient temperature is between 2°C and 13°C (35°F and 55°F). These weather conditions are common during the fall, winter, and spring in many parts of the U.S., and they can last well into the summer in some coastal regions. Carburetor icing is not a problem when the intake air temperature is below freezing because the air is too dry. The extent of carburetor icing does not depend on weather alone. It also involves carburetor and vehicle design and the mechanical condition of the engine, in particular, those components that affect warm-up time, such as thermostats, automatic chokes, intake air heaters, and heat risers. Icing also involves gasoline volatility. The 70 percent evaporated temperature in the distillation profile is a good index  to measure the tendency of a gasoline to cause carburetor icing; the lower this temperature, the more severe the icing. Carburetor icing is not as big a problem as it used to be. For emission control reasons, most carbureted engines built since the late 1960s have been equipped with intake air-heating systems that generally eliminate carburetor icing. Today the problem is minimal because fuel-injected vehicles have replaced most carbureted vehicles.

Source : Chevron

Friday, July 6, 2012

Pyrophoric Ignition Hazards in Typical Refinery Operations


A pyrophoric material is a liquid or solid that, even in small quantities and without an external ignition source, can ignite within 5 minutes after coming in contact with air.

In oil and petrochemical industry, this only partially defines the concern. We also need to be concerned with the fact the pyrophoric material can create heat which can ignite residual hydrocarbons associated with the equipment containing the pyrophoric material.
  • Example pyrophoric materials include alkali metals and many organometallic compounds such as alkylmagnesiums, alkylzincs, and of course pyrophoric iron sulfide.  Nickle carbonyl in some catalysts.
          Pyrophoric compound + oxygen (typically air)  --->  Oxide of the compound + heat
  • Sometimes with several intermediate reaction steps
  • Can be very reactive or very slow to react
  • Can vary with conditions, humidity, temperature, particle size, degree of disbursement in air, etc.

Conditions required to form pyrophoric iron sulfide
  • H2S concentration > 1% (can form at lower concentrations but typically not in concentrations that are a concern)
  • Iron scale or rust (FeS)
  • Less than a 1:1 ratio of oxygen to H2S (some oxygen is required to form the rust but if insufficient oxygen is present the reaction with H2S cannot go to completion)



Pyrophorics have been known to form in refinery equipment such as :
  • Crude oil tanks
  • Asphalt tanks
  • Sour water tanks
  • Vessels in sour service such as coke drums, distillation columns, inlet separators, pig  receiver / launchers
  • Reactors
  • API Separators
  • Marine tankers and barges
  • Portable tanks and tote bins
Mitigation methods :
  1. Most effective method is chemical neutralization before opening the equipment; potassium permanganate solution (typically around a 1% solution, circulate and check for color)
  2. Keeping the deposits and scale wet until it can be safely removed to a remote area and allowed to dry
  3. Maintain a constant air ventilation to ensure there is plenty of oxygen to allow the reaction to go to completion, preventing the formation of the pyrophoric intermediates
  4. Replace components that contain sulfur compounds
  5. Use nitrogen or other inert gases to keep oxygen out (obviously difficult and adds hazards of its own)
  6. Quickly move scale and potential pyrophoric deposits to a remote
  7. area and monitor in case ignition does occur
Source :
Doug Jeffries
Chief Fire Protection Engineer , Chevron




Wednesday, July 4, 2012

Pump Cavitation & NPSH

Both cavitation and NPSH are terms very frequently encountered by chemical engineers during their entire career either as a design or operations engineer. Most fresh chemical engineers have some idea of these terms but are not fully conversant with the concept. Many a times there are also a lot of misconceptions about the actual meaning of these frequently encountered terms. My blog entry is a humble attempt to bring forth some explanation regarding these often misunderstood or partially understood concepts of cavitation and NPSH.
Let me begin with cavitation. A dictionary definition for cavitation is as follows:

“The sudden formation and collapse of low-pressure bubbles in liquids by means of mechanical forces, such as those resulting from rotation of a marine propeller”.
In context with centrifugal pumps it can be said to be a phenomena where vapor bubbles form and move across the vane of the pump impeller. As these vapor bubbles move along the impeller vane, the pressure around the bubbles begins to increase. When a point is reached where the pressure on the outside of the bubble is greater than the pressure inside the bubble, the bubble collapses. The bubble collapse is not by “explosion” but by “implosion”. This collapse occurs simultaneously for hundreds of bubbles moving across the impeller vane at practically the same point on the impeller vane. The figure below should illustrate this phenomenon.




The phenomenon of the formation and subsequent collapse of these vapor bubbles, known as cavitation, has several effects on a centrifugal pump. First, the collapsing bubbles make a distinctive noise which is akin to a rattling sound, or a sound like the pump is pumping gravel. This can be a nuisance in an extreme situation where a cavitating pump is operating where people are working. This physical symptom is usually the area of least concern with cavitation, however. Of far greater concern is the effect of cavitation on the hydraulic performance and the mechanical integrity of the pump. A cavitating pump causes its hydraulic performance to drop off from its expected performance as illustrated in the figure below:

Effect of Cavitation on the performance of a Centrifugal Pump

A much more serious effect is the mechanical damage that can be caused by excessive vibration in the pump. This vibration is due to the uneven loading of the impeller as the mixture of vapor and liquid passes through it, and to the local shock wave that occurs as each bubble collapses.

The shock waves can physically damage the impeller, causing the removal of material from the surface of the impeller. The amount of material removed varies, depending on the extent of the cavitation and the impeller material. Ferrous-based materials such as ductile iron are more susceptible to cavitation shock waves compared to stainless steels which are not only superior in corrosion resistance but work harden against the hammer like impact of the collapsing bubbles. If the impeller material is more corrosion resistant but softer, ordinary bronze, for example, the damage that cavitation causes is similar to a peening operation, in which a piece of relatively soft bronze is repeatedly struck with a small ball peen hammer.

As long as the cavitation persists, this removal of material can continue. Pits can be formed gradually on the impeller vanes and, in the extreme, the removal of material can actually cause a hole to be eaten clear through an impeller vane, as illustrated in the figure below:

Material loss from impeller vane due to cavitation.

This removal of material from the impeller has the obvious effect of upsetting the dynamic balance of the rotating component.
It is very important to remember that excessive vibration from cavitation can occur even without the material loss from the impeller described above. This is true because the vibration from cavitation is caused by the uneven loading of the impeller due to the shock waves produced by the collapsing vapor bubbles.
One of the most common and visible effects of cavitation is the failure of the pump’s seal and/or bearings. What causes the formation of the vapor bubbles in the first place, without which the cavitation would not have a chance to occur? To a layman, the most obvious way to create vapor bubbles that is, to make a liquid boil is by raising the temperature of the liquid. However, this is not what occurs in a cavitating pump because, in the higher flow range where cavitation is likely to occur, the temperature of a liquid as it moves through a centrifugal pump remains very nearly constant.
Another way to make a liquid boil, without increasing its temperature, is if the pressure of the liquid is allowed to decrease. This physical property of liquids is known as vapor pressure.
Every liquid has a characteristic vapor pressure that varies with temperature, as the table below shows for water. Many handbooks carry this data for various liquids.
For any liquid, as temperature goes up, vapor pressure increases. One way to interpret the vapor pressure data for a liquid is that it shows the temperature at which the liquid boils when it is at a certain pressure. For example, from Table 2.3, we see that at 14.7 psia (atmospheric pressure at sea level), water boils at 212°F (100°C).
If the water is subjected to a pressure of 90 psia, the liquid does not boil until it reaches a temperature of 320°F (160°C). This is the principle upon which a pressure cooker is based. With the pressure cooker operating at a pressure above atmospheric pressure, the liquid boils at a much higher temperature than it would in an open pot on the stove, so the food in the pressure cooker cooks faster.
If a liquid is at a certain temperature in a pressurized container and the pressure in the container is allowed to drop below the vapor pressure of the liquid at that particular temperature. the liquid boils. As an example (using Table below), if water at 300°F (148.9°C) is in a vessel which is maintained at a pressure of 100 psia, the water is in a liquid state, i.e., is not boiling. However, if the pressure in the vessel is allowed to drop, when it goes below 67 psia (the vapor pressure at 300°F), the liquid begins to boil.

In analyzing a pump operating in a system to determine if cavitation is likely, there are two aspects of NPSH to consider: NPSHa and NPSHr
NPSHa
Net positive suction head available (NPSHa) is the suction head present at the pump suction over and above the vapor pressure of the liquid. NPSHa is a function of the suction system and is independent of the type of pump in the system. It should be calculated by the engineer or pump user, and supplied to the pump manufacturer as part of the application criteria or pump specification. The general formula for calculating NPSHa is:
NPSHa = P ± H – Hf – Hvp         ……………………………..(1)
 where:
P =absolute pressure on the surface of the liquid in the suction vessel, expressed in feet (meter) of liquid
H = static distance from the surface of the liquid in the supply vessel to the centerline of the pump impeller, in feet (meter); the term is positive if the pump has a static suction head, and negative if the pump has a static suction lift. For the purpose of NPSHa calculations, both the static suction head and the static suction lift should be considered at the “minimum operating liquid level” of the suction vessel. In other words, the NPSHa should be calculated with the minimum static head or the maximum static lift as the case maybe. The term “minimum operating liquid level” although is quite debatable since many engineering professionals as well as engineering companies differ on it’s definition.  It would suffice to say that the minimum static head or maximum static lift may differ on a case-to-case and operating philosophy basis and the engineer performing the NPSHa calculations would require doing a careful analysis of this value before using it in his or her calculation. 
Hf = friction loss in the suction line, including all piping, valves, fittings, filters, etc., expressed in feet (meter) of liquid; this term varies with flow, so NPSHa must be calculated based on a particular flow rate
Hvp= vapor pressure of the liquid at the pumping temperature, expressed in feet (meter) of liquid
In a new pump application, NPSHa (and the static term H in the above formula) must be given to the manufacturer with reference to some known datum point such as the elevation of the pump mounting base. This is because the location of the pump impeller centerline elevation is generally not known when the NPSHa calculations are made. It is important that the datum point of reference be mentioned in the specification, as well as the calculated value of NPSHa.
New engineers often get confused when the suction vessel is not a vented vessel to atmosphere and there is absence of data about the maximum operating pressure in the vapor space of the vessel. A way out is that if the vessel is provided with a relief device in the vapor space of the vessel, the set pressure of the relief device may be used as the maximum vessel pressure for the purpose of NPSHa calculations.
NPSHr
Net positive suction head required (NPSHr) is the suction head required at the impeller centerline over and above the vapor pressure of the liquid. NPSHr is strictly a function of the pump inlet design, and is independent of the suction piping system. The pump requires a pressure at the suction flange greater than the vapor pressure of the liquid because merely getting the liquid to the pump suction flange in a liquid state is not sufficient. The liquid experiences pressure losses when it first enters the pump, before it gets to the point on the impeller vane where pressure begins to increase. These losses are caused by frictional effects as the liquid passes through the pump suction nozzle, moves across the impeller inlet, and changes direction to begin to flow along the impeller vanes.
NPSHr is established by the manufacturer using a special test, and the value of NPSHr is shown on the pump curve as a function of pump capacity.
It is important to note that the NPSHr increases with higher flow rate due to the increased amount of friction loss inside the pump inlet before the liquid reaches the pump impeller. In certain cases the NPSHr also increases with the flow remaining unchanged but the impeller diameter reduced.
For a pump to operate free of cavitation, NPSHa must be greater than NPSHr. In determining the acceptability of a particular pump operating in a particular system with regard to NPSH, the NPSHa for the system must be calculated by the engineer, and then the NPSHr for the pump to be used must be examined at the same flow rate by looking at this information on the pump curve. This comparison should be made at all possible operation points of the pump, with the worst case usually being at the maximum expected flow, also called the runout flow.
Safe Margin NPSHa vs. NPSHr
An often-asked question is: “What is a safe margin to maintain between NPSHa and NPSHr?” Unfortunately, like so many questions related to pumps, the answer must begin with “That depends.…” For the majority of pumping applications, it is good practice to have a reasonable margin between the available and required NPSH.
When considering the margin that should be maintained between NPSHa and NPSHr for a particular application, the questions to ask include:
a. How conservatively was NPSHa calculated for the system, and for what percentage of the pump’s duty cycle is this low value of NPSHa actually present?
b. What is the pump impeller material, and how resistant is it to cavitation damage?
c. Does the pump system make use of a gas blanket that may become dissolved in the liquid and subsequently liberated in the low pressure area of the impeller inlet?
Depending on the answers to these questions, the recommended minimum margin between calculated NPSHa and NPSHr can range from 0 to 35%. A rule of thumb often used in industry is that NPSHa should exceed NPSHr by a minimum of 3 feet (1 meter).
The safe margin between NPSHa and NPSHr needs to be critically evaluated and established when the liquid pumped is close to its boiling point (saturated liquid) or when vey high pumping flow rates are required. 
Remedies for Cavitation
From the discussion till now it is obvious that the higher the value of NPSHa or greater the difference between NPSHa and the NPSHr lesser the possibility of cavitation. For a given value of NPSHr at the pump rated flow the endeavor of any engineer would be to increase the value of NPSHa as given by the equation 1. Pump system modifications that can increase the NPSHa by manipulating the four terms in the right hand side of equation 1 can be described as follows:

1.  Increase the static suction ‘head’ or decrease the static suction ‘lift’ absolute value. This can be done by having the pump operate at a higher suction vessel level or by changing the pump location to a lower elevation.   
2.  Decrease the value of friction losses (Hf) in equation 1. This can be done in several ways:
     a. Make the suction pipe shorter by locating the pump close to the vessel.
     b. Increasing the size of the suction pipe to reduce friction losses.
     c. Reducing the number of fittings and valves in the suction pipe to reduce friction losses
     d. Using a suction filter / strainer which gives the minimum pressure drop (low differential 
         pressure) at clogged conditions while still protecting the pump from ingress of solids / particles.
3. Decrease the pumping temperature of the liquid. This option has to be evaluated with respect to the process requirements of the fluid being pumped.
4. Increase the pressure in the vapor space of the suction vessel by providing a pressure blanket using inert gas or any other compatible gas which will increase the value of ‘P’ in equation 1. This option requires a very careful evaluation since this may prove detrimental to the pump performance in terms of increased cavitation if the blanket gas has good solubility in the liquid and can be liberated at the lower pressure area at the inlet of the pump.
The topic of pump cavitation and NPSH can be discussed even more extensively. However, the endeavor of this brief refresher is to provide an insight to the younger generation of chemical engineers on the fundamentals of cavitation and NPSH.

Reference
 “Pump Characteristics and Applications” by Michael Volk, 2nd Edition.

Prepared by: Ankur Srivastava