200+ TOP CHEMICAL ENGINEERING Interview Questions and Answers
CHEMICAL Engineering Interview Questions :-
1. Is there any way to remove residual product left in pipes after a batch operation?
OEG Company in Osaka, Japan commercialized a device called Pushkun that runs through pipes and “pushes” out left over product. The system is particularly valuable in batch operations where product recovery is chief concern. The manufacturer claims that at one installation, the system paid for itself in four months through product recovery. System costs depend on the scale of the system, but are typically around $10,000 US (1998).
2. What particle sizes are electrostatic precipitators used to remove?
A. Duprey conducted testing on an electrostatic precipitator in a pulp mill. The results were published in a National Air Pollution Control Administration report called “Compilation of air Pollutant Emission Factors”.
3. What are flameless oxidizers?
Flameless oxidizers are used to treat volatile organic compounds (VOC) and liquid organic streams. Traditionally, these types of streams were combusted to break down the molecules. The disadvantage of this treatment method was the formation of NOx. Flameless oxidizers use electrically heated ceramic packing and a high velocity introduction system to initiate the destruction of the organic compounds into carbon dioxide and water. Once this oxidation reaction begins, it continues via self-perpetuation. Capital cost for such systems are usually about 25% less than traditional combustion systems and capacities can range from 250 to 40,000 SCFM (standard cubic feet per minute). Thermatrix Inc. is the pioneer for this technology. Visit their website below.
4. Are there any special considerations to be taken into account for combusting ammonia?
The heat of combustion of ammonia is 8,000 Btu per pound. There is no reason why it cannot be combusted with or without auxiliary fuel. However, ammonia combustion does result in a flue gas having a high concentration of NOx and the design of a combustion chamber for ammonia requires special conditions to mitigate or reduce the level of NOx emissions.
5. What are some common causes of control valve noise?
If you have excessive pressure drop across the control valve and the downstream pressure is low enough to cause the liquid to flash, a great deal of noise in the control valve can result. Excessive damage can be done as well. This is a common problem at low flows. Review the design information on the valve and the process to see if low flow may be the problem. If the valve is incorrectly sized the noise will be apparent from the day of installation. If flows have recently been changed, the valve may have been designed correctly at the time, but is too large for current operation.
6. How much water is lost through a commercial cooling tower system with a throughput of about 600 GPM?
This question depends on many factors. It sounds like the tower is small. A rule of thumb suggests that the tower will see an evaporation loss of about 0.1% of the circulation flowrate for each Fahrenheit degree of cooling. Other losses include drift losses (probably very small for your tower) and blow down. Blow down is simply a purge of tower water to prohibit the buildup of solids.
7. What is the difference between CFM (cubic feet per minute) and SCFM (standard cubic feet per minute)?
CFM and SCFM are both measures of flow rate. CFM might refer to either the flow rate of a gas or a liquid, whereas SCFM refers only to the flow rate of a gas. The same mass flow rate of a gas (i.e., lbs/minute) is equivalent to various volumetric flow rates (i.e., CFM) depending upon the gas pressure and temperature. Thus, when gas flow rates are specified, it is very important to specify at what pressure and temperature the gas was measured. When the gas flow rate is specified as SCFM, it means that the flow rate was measured at a set of standard pressure and temperature conditions.
In the USA, the most common set of standard conditions used in industry is 60 degrees Fahrenheit and one atmosphere of pressure. Note that we have stressed most common, because there are other standard conditions that may be used. It is always best to spell out what standard conditions are being used (i.e., 1200 SCFM at 60 degrees F and 1 atmosphere pressure). When gas flows are expressed simply as CFM, the reader is can only speculate as to what gas temperature and pressure apply to that flow rate … and, because of that, the CFM flow rate cannot be converted to a mass flow rate
8. What is the maximum recommended velocity for steam in a plant pipe network?
High-pressure steam should be limited to about 150 ft/s and low-pressure steam should be limited to about 100 ft/s.
9. What is the maximum recommend pipe velocity for dry and wet gases?
For dry gases, you should design for a velocity of about 100 ft/s while wet gases should be limited to about 60 ft/s.
10. How instrument air is continually supplied in process plant?
The instrument air supply is guaranteed by dedicated air supply with -40 oC dew point. Apart from this there is about 20 to 30 minutes of back up provided for emergencies like power failure, instrument air-generation failure, etc.
11. How can you keep our seawater used for heat rejection clean before entering our heat exchangers?
Seawater is used as a cooling agent in condensers and coolers. Intermittent injection of chlorine gas is used to eliminate marine growth. The system is a once through type. The band screens before the suction of the pumps are supposed to eliminate scales and other suspended materials. The band screens are not properly functioning. Cooling water flow is about 2.6 million gallons per hour.
The prescreening and mobile screens are not a sufficient protection for the recirculating water. This is a very common problem. In clean salt water the biological grow in the cooling water pipes is the main problem (mussels, barnacle, algae, etc.). After the life cycle is finished they die and blocking the condenser tubes. To solve this debris problems use self-cleaning Debris Filters (DF) directly installed in front of the waterbox of the heat exchangers.
12. What are some guidelines for designing for liquid and gas velocities in process plant piping?
For normal process plant design liquid pump discharges, look for velocities in the range 5-7 ft/sec. probably not a bad idea to keep design vapor velocities below 125 ft/sec. These guidelines might be applied by an engineering company for design. If you are looking at plant operation, it is common to find velocities in the 9-12 ft/sec range. Erosion problems can also complicate the answer to this question. Erosion is highly dependent on the nature of the fluid. For example, 98% H2SO4 is not corrosive to carbon steel pipe, however it very erosive at “normal design” velocities. Design criteria for 98% H2SO4 might be 0.70 ft/sec MAXIMUM. However, it is also well known that if the same 98% H2SO4 has a little emulsified hydrocarbon, it is substantially less erosive.
13. Is it advisable to cool a fin fan by spraying demineralized water on it?
Fin fan has carbon steel tubes with aluminum fins RESPONSE In a similar service, the fin fan suffered external corrosion when spraying it with demin water. The salt and oxygen in the air corrodes the air-cooler.
The gas is piped normally from an outside cylinder storage facility to a process control panel at approximately 60 psig. The panel-output chlorine pressure is 15 psig and a flow rate of approximately 0.03 scfm. Occasionally the flow control devices in the process panel are contaminated by what appears to be liquid chlorine. It seems that temperature variations in the iron transport pipe may have some influence on the liquid formation.
The condensation temperature of gaseous chlorine at 65 psig is 54 deg F. Thus, if your transport line is long, it is quite likely that ambient temperatures lower than 54 deg F could result in cooling the line enough to cause condensation of the chlorine gas. If you lower the transport pressure to 25 psig, the condensation temperature would be 24 deg F …, which should significantly lower the likelihood of cold ambient temperature causing the gas to condense.
14. What is a good method of steam tracing large vessels?
One common approach to heat tracing projects is a “platecoil” concept. If you are unfamiliar with this type of equipment, you should visit one of the links below. Depending on your tank(s) or application, the platecoil can easily steam trace (or heat-up) your process. The method of application is simple and routinely done by sub-contractors. New heat-tracing cements have made this method even more efficient and less costly than what we had in the past. The platecoils can be pre-formed to fit your tank’s cylindrical shell or elliptical heads. Flat surfaces are very easy.
Platecoils are a quick, low-cost, and safe installation. Most platecoils are found in stock, off-the-shelf in stainless construction. I have used them to winterize tanks as well as to reduce viscosities in heavy polyols and other high molecular weight compounds while processing or during storage. One of the best features of this type of tracing is that it is not invasive — depending on the application, you may be able to install the platecoils while the tank is operating. Still another interesting feature is that you can use them as an assembly inside of tanks — as internal heaters. You can use steam, Dowtherm, hot oil or process streams inside the coils. You can easily insulate over them to conserve heat or to protect personnel. Another resource would be a publication by Spirax Sarco (link below). This book contains a lot of information on steam tracing, best practices, traps, regulating valves.
15. How can you control the pH level in our cooling water with respect to ammonia contamination?
A cooling tower in a urea manufacturing facility is experiencing very high ammonia levels (200 to 300 ppm) in the cooling water. The ammonia level fluctuates with wind direction.
RESPONSE if your cooling water has 200-300 ppm of ammonia, you have a problem, which must be solved. You may have a water-cooled process heat exchanger, which has a tube leak that is leaking ammonia into your cooling water. Or the ambient air in your urea plant has a significant ammonia content (from various fugitive leak sources such as piping flanges, control valve packing glands, pump and compressor seals, etc.) and when the wind blows that ambient air into the cooling tower, the ammonia is absorbed in the cooling water.
In either event, you have an unhealthy situation, which must be corrected. Contacting a company that is specialized in these types of water treatment problems may be a wise decision (Ex/ Nalco).
16. We have some pieces of metals that have been “powder coated”, how does that work?
Powder coatings are similar to paint, but they are usually much more durable. Rather than adding a solvent to the pigments and resins in paint, as is typically the case, powder coatings are applied to the surface in a fine granular form. They are typically sprayed on so that they stick to the surface. Once the surface has been sufficiently spray coated, the piece is baked at high temperatures, and the pigment and resins pieces melt and form a durable, color layer.
17. What industries require filtered compressed air?
Almost every chemical process, power plant food processing etc. plant has some type of air-operated device… from control valves to air operated pumps… and all have an air compressor delivering filtered air.
18. What are some good tank mixing rules of thumb?
For fluid with viscosities under 10,000 Cp, baffles are highly recommended. There should be four baffles, 90 degrees apart. The baffles should be 1/12th the tank diameter in width and should be spaced off the wall by 1/5th the baffle width. The off- wall spacing helps to eliminate dead zones. If baffles are used, the mixer should be mounted in the vertical position in the center of the tank. If baffles are not used, the mixer should be mounted on an angle, ~15 degrees to the right and positioned off center. This breaks up the symmetry of the tank and simulates baffles although not nearly as good as baffles.
The purpose of baffles is to prevent solid body rotation all points in the tank are moving at the same angular velocity and no top to bottom turnover. The formation of a large central vortex is a characteristic of solid body rotation. However, small vortices that travel around the fluid surface, collapse, and reform are more a function of the level of agitation.
19. What is a good source of equations for calculating discharge flowrates from accidental releases?
If you are interested in the calculation of discharge flow rates from accidental releases, read the online technical article “Source Terms for Accidental Discharge Flow” at the website below. It provides the equations used for a variety of common types of accidental gas or liquid releases and explains how to use them.
20. What is the definition of “good” cooling tower water?
Generally speaking, cooling tower water should have a pH between 6 and 8, a chloride content no more than 750 ppm, a sulfate content (SO4) below 1200 ppm, and a sodium bicarbonate (NaHCO3) content below 200 ppm. Additionally, cooling tower water should not be heated past 120 °F to avoid plating out of treatment chemicals in process coolers.
In addition, if free chlorine is used for biological growth control, it should be added intermittently with a free residual not to exceed 1 ppm and this should be maintained for short periods.
21. When specifying a cooling tower, should I look up historic wet bulb temperatures for my area or should I take measurements?
If this is a new installation, look up historical wet bulb temperatures for area and be sure to report them to the cooling tower manufacturer as “ambient wet bulb temperatures”. The manufacturer will adjust this temperature accordingly to estimate an “entering wet bulb temperature”.
If you have an existing tower that is to be replaced, take several wet bulb temperature measurements near the air inlet during the hottest months. Report this as the “entering wet bulb temperature” to the tower manufacturer.
The difference between the ambient and the entering wet bulb temperatures is to account for wet recirculation from the tower exit back to the tower entrance. The entering wet bulb temperature always higher than the ambient wet bulb temperature.
22. IS there a rule of thumb to estimate the footprint of a cooling tower during design phase?
Over the years, this one has seemed to stand the test of time:
Every million Btu/h of tower capacity will require approximately 1000 ft2 of cooling tower basin area.
23. What could be a possible cause for sudden foaming in a cooling tower?
Assuming that no other changes have been made, especially to the water treatment chemicals, the most common outcome to this mystery is a leaking heat exchanger.
Begin a systematic check of all of the heat exchangers that use the cooling tower water and inspect them thoroughly for leaks. Even small amounts of some chemicals can cause big foaming problems in the tower. In addition, not all of these components will set off a conductivity alarm.
24. What factors should be compared when evaluating cooling tower bids?
Examining the following factors should allow for a reasonable evaluation of cooling towers:
- Purchased cost
- Installed cost
- Fan energy consumption
- Pump energy consumption
- Water use
- Water treatment costs
- Expected maintenance costs
- Worker safety requirements
- Environmental safety
- Expected service life
25. For a heat exchanger, will the overall heat transfer coefficient increase along with an increase in LMTD (log mean temperature difference) around the unit?
The overall heat transfer coefficient is generally weakly dependent on temperature. As the temperatures of the fluids change, the degree to which the overall heat transfer coefficient will be affected depends on the sensitivity of the fluid’s viscosity to temperature. If both fluids are water, for example, the overall heat transfer coefficient will not vary much with temperature because water’s viscosity does not change dramatically with temperature. If, however, one of the fluids is oil which may have a viscosity of 1000 cP at 50 °F and 5 cP at 400 °F, then indeed the overall heat transfer coefficient would be much better at higher temperatures since the oil side would be limiting. Realize that the overall heat transfer coefficient is dictated by the local heat transfer coefficients and the wall resistances of the heat exchanger. The local heat transfer coefficients are dictated by the fluid’s physical properties and the velocity of the fluid through the exchanger. So, for a given heat exchanger, fluid flow rates, and characteristics of each fluid….the area of the exchanger and the overall heat transfer coefficients are fixed (theoretically anyway….as the overall heat transfer coefficient does vary slightly along the length of the exchanger with temperature as I’ve noted and the U-value will decrease over time with fouling).
26. What is condensate lift?
This is a term that is usually used to indicate how much pressure is required to ‘lift’ condensate from a steam trap or other device to it’s destination at a condensate return line or condensate vessel. The first image below shows a situation where a properly sized control valve is used on a steam heater. During nominal operation, the utility steam undergoes a nominal 10-25 psi pressure loss through the valve. For typical utility steam (150 psi or higher), this can leave a pressure at the steam trap exit that is often adequate to lift the condensate to its destination. For example, if the steam losses 20 psi through the valve and another 15 psi through the heater and piping, that can leave up to 265 ft of head to push the condensate to the header. In this case, there is little need for a condensate pump. On the other hand, if the control is too large, it will only be a few percent open during normal operation and the steam can undergo a pressure loss of 50-75 psi or even higher! In addition to supplying terrible control for the heater, it also reduces the available head for condensate lift. In this case, or if the steam supply pressure is relatively low, it may be necessary follow the steam trap with a separation vessel and a condensate pump to push the condensate to the return line.
27. What type of heat exchangers are most commonly used for a large-scale plant-cooling loop using seawater as the utility?
Commonly known as a “secondary cooling loop” or SECOOL, a closed loop water system is circulated through a processing plant near a sea. Process heat is transferred into the closed loop water and then this water is circulated through heat exchangers to transfer (reject) the heat to seawater. This is a hallmark plate and frame heat exchanger application. The higher heat transfer coefficients that are available in plate and frames exchangers (PHEs) will minimize the installed cost because the material of construction of choice it Grade 1 Titanium (higher U-value means lower area). To combat pluggage the narrow passages in the exchangers, the seawater is typically run through large automatic backflush strainers designed especially for seawater. Periodically, these strainers will reverse flow and “blowdown” debris to clear the strainer. This method has been used for many years with great success.
28. Can condensate control in a reboiler cause water hammer problems?
This topic was recently discussed in our online forum. The short answer to this specific question is…”not very often”. It is very common to control reboilers on distillation columns via this method. This is not to say that this control method is the best for any heat exchanger using steam for heating. For example, if there is an appreciable degree of subcooling of the condensate, the incoming steam can experience “collapse” (or thermal water hammer) when it is exposed to the cool condensate. In reboilers, the process fluid is simply being vaporized so little or no subcooling of the condensate takes place. This makes for a good opportunity for condensate level control in a vertically oriented shell and tube reboiler. The level controller is typically placed on a vessel that is installed in conjunction with the shell side of the reboiler. This will allow for full condensate drainage (if necessary) and there is no need to weld on the shell of the exchanger. (See graphic below) Reference: Cheresources Message Board
29. Why is a vacuum breaker used on shell and tube heat exchangers that are utilizing steam as the heating utility?
Vacuum breakers are often installed on the shell side (steam side) of shell and tube exchangers to allow air to enter the shell in case of vacuum conditions developing inside the shell. For an exchanger such as this, the shell side should already be rated for full vacuum so the vacuum breaker is not a pressure (vacuum) relief device. Development of vacuum in the shell could allow condensate to build in the unit and water hammer may result.
30. What is a barometric condenser?
Single-stage or multi-stage steam-jet-ejectors are often used to create a vacuum in a process vessel. The exhaust from such ejector systems will contain steam (and perhaps other condensable vapors) as well as non-condensable vapors. Such exhaust streams can be routed into a “barometric condenser” which is a vertical vessel where the exhaust streams are cooled and condensed by direct contact with downward flowing cold water injected into the top of the vessel. The vessel is installed so that its bottom is at least 34 feet (10.4 meters) above the ground, and the effluent cooling water and condensed vapors flow through a 34-foot length of vertical pipe called a “barometric leg” into small tank called a “hotwell”. The “barometric leg” allows the effluent coolant and condensed vapors to exit no matter what the vacuum is in the process vessel. Such a system is called a “barometric condenser”. The non-condensable vapors are withdrawn from the top of the condenser by using a vacuum pump or perhaps a small steam ejector. The effluent coolant and condensed vapors are removed from the hotwell with a pump.
31. What is the best way to control an oversized, horizontally oriented shell and tube steam heater?
A used shell and tube heat exchanger is to be used in steam heating duty. The heat exchanger is larger than necessary and the control scheme to be employed is being investigated. The steam to be used will be 65 psia-saturated steams. The process fluid is a liquid brine fluid. ANSWERS Two opinions were offered on this topic: A. The actual pressure in the heater, while the steam is condensing is dependent on the condensing rate and the overall dirty U. Tubes can be plugged to reduce the amount of heat transfer area, as long as the process side (tube) velocity does not get too high. Calculate the needed area and then the required steam flow rate. An orifice can be sized to control the steam flow rate; however, at reduced loads the condenser may experience partial vacuum conditions so be sure that the shell is rated for full vacuum. When this partial vacuum condition does occur, choked flow will be experienced through the steam control valve. The Cv trim value would need to be sized such that the choked flow does not exceed what is needed. This is tricky and requires several trim size change outs.
32. Is it ever advantageous to use shells in series even though it may not be necessary?
Usually you design for the least number of shells for an item. However, there are times when it is more economical to add a shell in series to the minimum configuration. This will be when there is a relatively low flow in the shell side and the shell stream has the lowest heat transfer coefficient. This happens when the baffle spacing is close to the minimum. The minimum for TEMA is (Shell I.D. /5). Then adding a shell in series gives a higher velocity and heat transfer because of the smaller flow area in the smaller exchangers that are required.
33. What is some good advice for specifying allowable pressure drops in shell and tube exchangers for heavy hydrocarbons?
Frequently process engineers specify 5 or 10 PSI for allowable pressure drop inside heat exchanger tubing. For heavy liquids that have fouling characteristics, this is usually not enough. There are cases where the fouling excludes using tabulators and using more than the customary tube pressure drop is cost effective. This is especially true if there is a relatively higher heat transfer coefficient on the outside of the tubing. The following example illustrates how Allowable pressure drop can have a big effect on the surface calculation. A propane chiller was cooling a gas treating liquid that had an average viscosity Of 7.5 cP. The effect on the calculated surface was as follows: Allowable tube pressure drop Exchanger surface 5 PSI 4012 Sq. Ft. 25 PSI 2104 Sq. Ft. 50 PSI 1419 Sq. Ft. You can see that using 25-PSI pressure drop reduced the surface by nearly one-half. This would result in a price reduction for the heat exchanger of approximately 40%. This savings offset the cost of the pumping power
34. What is a good approximation for the heat transfer coefficient of hydrocarbons inside 3/4″ tubes?
Use the following equation to estimate the heat transfer coefficient when liquid is flowing inside 3/4 inch tubing: Hio = 150./sqrt(avg. viscosity) Where: Hio (BTU/ft2-hr-0F Viscosity (cP) this is limited to a maximum viscosity of 3 cP
35. What is a good relation to use for calculating tube bundle diameters?
The following are equations for one tube pass bundle diameter when the tube count is known or desired: 30 Deg. DS = 1.052 x pitch x SQRT(count) + tube O.D. 90 Deg. DS = 1.13 x pitch x SQRT(count) + tube O.D. Where: Count = Number of tubes DS = Bundle diameter in inches Pitch = Tube spacing in inches
36. What effect does choking a vertical thermosiphon have on the heat transfer rate?
Choking down on the channel outlet nozzle and piping reduces the circulation rate through a heat exchanger. Since the tubeside heat-transfer rate depends on velocity, the heat transfer is lower at reduced recirculation rates. A rule of thumb says that the inside flow area of the channel outlet nozzle and piping should be the same as the flow area inside the tubing. Shell Oil in an experimental study showed that a ratio of 0.7 in nozzle flow area/tube flow area reduced the heat flux by 10%. A ratio of 0.4 cut the heat flux almost in half.
37. How can one quickly estimate the additional pressure drop to be introduced with more tube passes?
When the calculated pressure drop inside the tubes is underutilized, the estimated pressure drop with increased number of tube passes is new tube DP = DP x (NPASS/OPASS)3 Where NPASS = New number of tube passes. OPASS = Old number of tube passes this would be a good estimate if advantage is not taken of the increase in heat transfer. Since the increased number of tube passes gives a higher velocity and increases the calculated heat transfer coefficient, the number of tubes to be used will decrease. Fewer tubes increase the new pressure drop. For a better estimate of the new pressure drop, add 25% if the heat transfer is all sensible heat. Source: Gulley Computer Associates
38. Can large temperature differences in vaporizers cause operational problems?
Large temperature differences in heat exchangers where liquid is vaporized are a warning flag. When the temperature differences reach a certain value, the cooler liquid can no longer reach the heating surface because of a vapor film. This is called film boiling. In this condition, the heat transfer deteriorates because of the lower thermal conductivity of the vapor. If a design analysis shows that the temperature difference is close to causing film boiling, the vaporizer should be started with the boiling side full of relatively cooler liquid. This way, you do not start flashing the liquid. The liquid is slowly heated up to a more stable condition. If the vaporizer is steam heated, the steam pressure should be reduced which will reduce the temperature difference. With steam heating, take a close look at the design if the MTD is over 90 0F this is close to the critical temperature difference where film boiling will start.
39. When should one be concerned with the tube wall temperature on the cooling waterside of a shell and tube exchanger?
When designing heat exchangers where hot process streams are cooled with cooling water, check the tube wall temperature. Hewitt says that where calcium carbonate may deposit heat, transfer surface temperatures above 140 0F should be avoided. Corrosion effects should also be considered at hot tube wall temperatures. As a rough rule of thumb, make this check if the inlet process temperature is above 200 0F for light hydrocarbon liquids and 300-400 0F for heavy hydrocarbons. Consider using Aircoolers to bring the process fluid temperature down before it enters the water-cooled exchanger.
40. When an expansion is joint needed on the shell side of a shell and tube heat exchanger?
A fixed tube sheet exchanger does not have provision for expansion of the tubing when there is a difference in metal temperature between the shell and tubing. When this temperature difference reaches a certain point, an expansion joint in the shell is required to relieve the stress. It takes a much lower metal temperature difference when the tube metal temperature is hotter than the shell metal temperature to require an expansion joint. Typically, an all steel exchanger can take a maximum of approximately 40-0F metal temperature difference when the tube side is the hottest. When the shell side is the hottest, the maximum is typically 150 0F. Usually if an expansion joint is required, it is because the maximum allowable tube Compressive stress has been exceeded. According to the TEMA procedure for evaluating this stress, the compressive stress is a strong function of the unsupported tube span. This is normally twice the baffle spacing. Source: Gulley Computer Associates
41. What kind of concerns is associated with temperature pinch points in condensers?
Be extra careful when condensers are designed with a small pinch point. A pinch point is the smallest temperature difference on a temperature vs heat content plot that shows both streams. If the actual pressure is less than the process design operating pressure, there can be a significant loss of heat transfer. This is especially true of fluids that have a relative flat vapor pressure plot like ammonia or propane. For example: If an ammonia condenser is designed for 247 PSIA operating pressure and the actual pressure is 5 PSI less and the pinch point is 8 0F, there can be a 16% drop in heat transfer. Source: Gulley Computer Associates.
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