Top Listed Chemical Engineering Interview Questions Part – 5

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:

1) Purchased cost
2) Installed cost
3) Fan energy consumption
4) Pump energy consumption
5) Water use
6) Water treatment costs
7) Expected maintenance costs
8) Worker safety requirements
9) Environmental safety
10) 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

42. What factors go into designing the vapor space of kettle type reboiler?

The size of the kettle is determined by several factors. One factor is to provide enough space to slow the vapor velocity down enough for nearly all the liquid droplets to fall back down by gravity to the boiling surface. The amount of entrainment separation to design for depends on the nature of the vapor destination. A distillation tower with a large disengaging space, low tower efficiency, and high reflux rate does not require as much kettle vapor space as normal.

Normally the vapor outlet is centered over the bundle. Then the vapor comes from two different directions as it approaches the outlet nozzle. Only in rare cases are these two vapor streams equal in quantity. A simplification that has been extensively used is to assume the highest vapor flow is 60% of the total. In one case, where this would cause an undersized vapor space is when there is a much larger temperature difference at one end of the kettle then the other. The minimum height of the vapor space is typically 8 inches. It is higher for high heat flux kettles. Source: Gulley Computer Associates

43. Is there a quick rule-of-thumb to estimate a gas side heat-transfer rate inside the tubes of a shell and tube heat exchanger?

If you need to estimate a gas heat transfer rate or see if a program is getting a reasonable gas rate, use the following: h = 75 X Sq. Root(Op. pressure/100) The operating pressure is expressed as absolute. This is for inside the tubes. The rate will be lower for the shell side or if there is more than one exchanger. Source: Gulley Computer Associates

44. What are some good strategies for curing tube vibration in shell and tube exchangers?

Most flow-induced vibration occurs with the tubes that pass through the baffle window of the inlet zone. The unsupported lengths in the end zones are normally longer than, those in the rest of the bundle. For 3/4 inch tubes, the unsupported length can be 4 to 5 feet.

The cure for removable bundles, where the vibration is not severe, is to stiffen the bundle. This can be done by inserting metal slats or rods between the tubes.

Normally this only needs to be done with the first few tube rows. Another solution is to add a shell nozzle opposite the inlet to cut the inlet fluid velocity in half. For non-removable bundles, this is the best solution. Adding a distributor belt on the shell would be a very good solution if it were not so expensive. Source: Gulley Computer Associates

45. What are some of the consequences of an undersized kettle type reboiler?

The effect will be a decrease in the boiling coefficient. A boiling coefficient depends on a nucleate boiling component and a two-phase component that depends on the recirculation rate. An undersized kettle will not have enough space at the sides of the bundle for good recirculation. Another effect is high entrainment or even a two-phase mixture going back to the tower. Source: Gulley Computer Associates

46. Are some heat transfer services more prone to tube vibration that others for a shell and tube exchanger?

Bundle vibration can cause leaks due to tubes being cut at the baffle holes or tubes being loosened at the tubesheet joint. There are services that are more likely to cause bundle vibration than others are. The most likely service to cause vibration is a single-phase gas operating at a pressure of 100 to 300 PSI. This is especially true if the baffle spacing is greater than 18 inches and single segmental.

Source: Gulley Computer Associates

47. Are there any alternatives to scraping a shell and tube if a capacity increase will make the pressure drop across the exchanger too large?

When an increase in capacity will cause excessive pressure drop, you may not have to junk the heat exchangers. A relatively inexpensive alteration is to reduce the number of tube passes. Other possibilities are arranging the exchangers in parallel or using lowfins or other special tubing. Source: Gulley Computer Associates

48. What is a good method of minimizing shell side pressure drop in a shell and tube exchanger?

When shell pressure drop is critical and impingement protection is required, use rods or tube protectors in top rows instead of a plate. These create less pressure drop and better distribution than an impingement plate. An impengement plate causes an abrupt 90-degree turn of the shell stream, which causes extra pressure drop. Source: Gulley Computer Associates

49. Is there a difference in MTD (Mean Temperature Difference) between “E” and “J” (Divided Flow) type shell and tube heat exchangers?

Divided flow (shell type J) does not have the same correction as the usual flow pattern (shell type E). Thermal design program make this correction factor mistake. True, there is very little difference at correction factors above 0.90. However, there is a difference at lower values.

For example, Equal outlet temperatures Shell type “E” correction Fn = 0.805 Shell type “J” correction Fn = 0.775 Cold outlet 5F higher than hot outlet Shell type “E” correction Fn = 0.765 Shell type “J” correction Fn = 0.65 Contact us if you do not have MTD correction factor charts for divided flow. TEMA has one chart for a single shell but it gives high values for the above examples and it is hard to read in this range. Source: Gulley Computer Associates

50. How is plate heat exchangers used in an ammonia refrigeration system?

Plate heat exchangers are widely used in ammonia refrigeration systems, and they can be much smaller than the equivalent tubular exchanger can. They work best flooded. A flooded exchanger system needs a way to separate the liquid from the vapor. A typical system has a vessel, which acts as knockout drum, accumulator, and header tank in one, along with the heat exchanger.

Liquid ammonia flows from the vessel to the exchanger, and liquid/vapor is returned to the middle of the drum. Vapor is removed from the top of the drum. The liquid/vapor mixture from the exchanger has a lower density than the liquid entering the exchanger, so gravity provides the driving force to circulate the refrigerant.

51. Is there a handy way to determine if a horizontal pipe is running full if the flow rate is known?

If Q/d2.5 is greater than or equal to about 10.2, then the pipe is said to full. In this case, Q is in GPM (U.S. Imperial gallons per minute) and d is in inches. Reference: Pocket Guide to Chemical Engineering, ISBN: 0884153118

52. What are some factors to consider when trying choosing between a dry screw compressor and an oil-flooded screw compressor?

Screw compressors utilize a pair of “meshing” helical screws to compress gases. These types of compressors a generally appropriate for a flow range of 85-170 m3/h (3000-6000 acfm) and discharge pressures in the range of 2070-2760 kPa (300-400 psig). As the name implies, dry screw compressor run dry while oil-flooded compressors use oil for bearing lubrication as well as to seal the compression chamber.

The oil also carries the heat from the compression away from the compressor. This heat is typically rejected to an external heat exchanger. Some factors to consider when choosing between the two types of screw compressors include

Is the process gas compatible with the oil? If the answer is no, use dry type Does the process gas have to be oil free? If the answer is yes, use dry type is efficiency the top priority. If the answer is yes, use oil-flooded type Are you looking to minimize shaft-seal leakage. If the answer is yes, use oil-flooded type Are there any liquids in the incoming gas. If the answer is yes, use oil-flooded type Does the gas contain small particulate matter? If the answer is yes, use dry type these and other guidelines can help in choosing between the two types of screw compressors.

53. Under what circumstances are vortex flowmeters the most accurate?

The accuracy of vortex flowmeters can be within 1% so long as they’re being operating within their recommended flow range, have a steady stream, and you have 10 pipe diameters of straight pipe behind the in front of the flowmeters. Outside of these parameters, these flowmeters are not accurate.

54. What are the advantages and disadvantages of using gear pumps?

Gear pumps are a type of positive displacement pump that are appropriate for pumping relatively high pressures and low capacities. Advantages include the ability to handle a wide range of viscosities, less sensitivity to cavitation (than centrifugal style pumps), relatively simple to maintain and rebuild.

Disadvantages can include a limited array of materials of construction due to tight tolerances required, high shear placed on the liquid, and the fluid must be free of abrasives. Also, note that gear pumps must be controlled via the motor speed. Throttling the discharge is not an acceptable means of control.

55. How can one estimate how the friction factor changes in heat exchanger tubes with a change in temperature?

Seider and Tate recommended the following for determine friction factors inside heat exchanger tubes with varying temperatures: First, determine the average, bulk mean temperature in the processing line. For example if the fluid enters the line at 300 °C and leaves at 280 °C, use 290 °C to determine the physical properties and friction factors.

As for corrections: Laminar Flow If the liquid is cooling, the friction factor obtained from the mean temperature and bulk properties is divided by (bulk viscosity/wall viscosity)0.23 and for heating, it’s divided by (bulk viscosity/wall viscosity)0.38. Here, the bulk and wall viscosity are determined at the mean temperature over the length of the line.

Turbulent Flow If the liquid is cooling, the friction factor obtained from the mean temperature and bulk properties is divided by (bulk viscosity/wall viscosity)0.11 and for heating, it’s divided by (bulk viscosity/wall viscosity)0.17.

56. What type of pump may be appropriate for a liquid near saturation, a low flow rate, and very limited NPSHa (net positive suction head available)?

This application is nearly perfect for a turbine regenerative type of pump. Factors that immediately identify your application and pump type are the small flowrate, low NPSHa, and high temperature. The regenerative turbine was specifically developed for these conditions and one more: high discharge pressures. The high discharge pressure may not be necessary, but the regenerative turbine can give you an NPSHr of 0.5 feet with ease. They are particularly suited to saturated boiler feed water and your application is similar, albeit not in pressure. You can visit the site below to learn more about these types of pumps.

57. What type of flow measurement devices is best for slurries?

Any device that restricts the flow to perform measurements is not recommended for slurries. These devices include orifices and dampeners. These devices can lead to liquid/solid separation and they can lead to excessive erosion. Instead, measuring devices that do not restrict the flow should be used. One example of such a device is the magnetic flow meter.

58. Should slurry pipes be sloped during horizontal runs?

If possible, slurry lines should indeed be sloped. Generally, to slope the pipes 1/2 inches for every 10 feet of pipe is recommended.

59. What is the best way to configure a bypass line in slurry services?

Bypass lines should be placed ABOVE the control valve so that the slurry cannot settle out and build up in the line during bypass.

60. What types of valves are recommended for slurry services?

Typically straight-through diaphragm, clamp or pinch, and full-port ball valves with cavity fillers are the preferred type of slurry valves. In general, gate, needle, and globe valves are NOT recommended for slurry services.

61. What is a good estimate for the absolute roughness for epoxy lined carbon steel pipe?

The specific roughness for welded, seamless steel is .0002 ft. PVC has a specific roughness of 0.000005 ft. You may also want to consider using the Hazen-Williams formula, which lists a coefficient of 130-140 for cement-lined cast iron piping. You need to decide which is more conservative for your application.

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62. How can you determine the largest impeller that a pump can handle?

The motor amperage should be measured in the field with the pump discharge valve wide open. Subtract about 10% from the pumps maximum rated amperage. Then the maximum impeller size can be determined from A2 = A1 (d2/d1)3 A2 = Maximum amperage minus 10% A1 = Current operating amperage d2 = Maximum impeller diameter d1 = Current impeller diameter

63. What is the significance of the minimum flow required by a pump?

The minimum flow that a pump requires describes the flow below which the pump will experience what is called “shutoff”. At shutoff, most of the pump’s horsepower or work is converted to heat that can vaporize the fluid and cause cavitations that will severely damage the pump. The minimum flow of a pump is particularly important in the design of boiler feed pumps where the fluid is near its boiling point.

64. How can you estimate the efficiency of a pump?

The following method, developed by M.W. Kellogg, gives results within 3.5% of most manufacturers’ curves. Eff % = 80-0.2855H+3.78×10-4HF-2.23×10-7HF2+5.39×10-4H2-6.39×10-7H2F+4.0×10-10H2F2 H = Developed head, ft F = Flow in GPM (gallons per minute) Applicable for heads from 50 to 300 ft and flows from 100 to 1000 GPM

65. How can you quickly estimate the horsepower of a pump?

Try this handy little equation: Horsepower = (GPM)(Delivered Pressure) / 1715 (Efficiency) GPM = Gallon per minute of flow Delivered pressure = Discharge minus suction pressure, psi Efficiency = Fractional pump efficiency

66. What are the affinity laws associated with dynamics pumps?

1. Capacity varies directly with impeller diameter and speed. 2. Head varies directly with the square of impeller diameter and speed. 3. Horsepower varies directly with the cube of impeller diameter and speed.

67. How can you estimate a gas flow based on two pressure measurements?

You can use the Weymouth equation to estimate the gas flow. Below is the equation. The compressibility should be evaluated at Pavg shown below. Nomenclature is as follows: Q = flow rate, Million Cubic Feet per Day (MCFD) Tb = base Temperature, degrees Rankin Pb = base pressure, psia G = gas specific gravity (reference air=1) L = line length, miles T = gas temperature, degrees Rankin Z = gas compressibility factor D = pipe inside diameter, in. E = Efficiency factor E=1 for new pipes with no bends E=0.95 for pipe less than a year old E=0.92 for average operating conditions E=0.85 for unfavorable operating conditions

68. What is a quick way to calculate frictional pressure drops in carbon steel pipe?

The relationship shown below is valid for Reynolds numbers in the range of 2100 to 106. For smooth tubes, a constant of 23,000 should be used rather than 20,000.

69. What is screen analysis and what are its applications in the chemical industry?

A screen analysis is the one passes solids through various sizes of screen mesh. This is done to get a particle size distribution. A group of solids is first passes through fine mesh and the amount that passes is noted, then a little larger mesh and the amount recorded and so on.

70. What is a good device to use for obtaining viscosity data for a non-Newtonian fluid?

Consider a rotational viscometer. It will measure the shear rate applied and the subsequent viscosity at the same time. You can also vary the temperature and time the stresses are applied for the truly “fun” non-Newtonian fluids. According to Cole-Parmer, “The rotational viscometer measures viscosity by determining the viscous resistance of the fluid.

This measurement is obtained by immersing a spindle into the test fluid. The viscometer measures the additional torque required for the spindle to overcome viscous resistance and regain constant speed. This value is then converted to centipoises and displayed on the instrument’s LCD readout.” When testing a tomato sauce sample, the following results were observed: “A sample of tomato sauce was analyzed to determine the product’s viscosity profile.

The test was conducted at a temperature of 25°C. An up/down speed ramp was performed from 10 to 100 RPM, giving a viscosity range of from 3,800 to 632.5 cP, over shear rates from 3.4 to 34.0 reciprocal seconds. The test data obtained for tomato sauce shows that this product exhibits a marked shear thinning viscosity profile over the test conditions.

71. What are some common methods for helium leak testing a vacuum system?

It is common to have a location in the suction line of the pump to detect the helium. Then, the helium source is passed over the flanges and other possible sources of leakage. This is done while monitoring the detector at the pump suction for detectable amount of helium. Alternatively, if your system can take pressure as well as vacuum you can try pressuring it up and looking for the leaks that way. As yet another alternative, you can install an IR unit to the suction of the pump and spray isopropyl alcohol on the flanges.

72. What is a common source of error in determining the percent spent caustic in refinery applications?

In titrations, a common error made is that the technicians stop at the phenolphthalein endpoint (which is incorrect) rather than the methyl orange endpoint (which is correct). Stopping the titration too soon can cause the results to be grossly under-reported. Equation (1): 2NaOH + H2S -> Na2S + 2H20 Equation (2): Na2S + H2S -> 2NaSH Overall Equation: NaOH + H2S -> NaSH + H2O

73. What is a good method of analyzing powders for composition?

A method known as Fourier transform-infrared (FT-IR) spectroscopy is often used for this purpose. FT-IR sends light beams of varying wavelength through the sample and the reflected light is analyzed by spectroscopy to find the absorption of each wavelength. The measured wavelengths are compared with a reference laser and the sample composition can be calculated. Analect Instruments Inc. specializes in FT-IR measurement.

74. What are some common problems associated with bellow expansion joints?

Bellow expansion joints have gained a reputation for being “weak” points in piping. Usually they are used to remove piping stresses from equipment or to allow for minor piping moments. If they are used properly, expansion joints can save equipment and/or equipment welds from stresses generated from piping forces.

The two most common complaints about bellows are

1. They tend to build up dirt

2. They are “weak” point in piping (as noted earlier).

To overcome these issues, manufacturers can began installing drains in the bellows to allow for the period purging of material. Additionally, bellow manufacturers have placed much emphasis on installation advice and showing their customers how to protect the bellow from unnecessary damage. One such method is the use of tie rods between the end flanges to avoid pressure thrust movements (beyond the bellow’s design conditions) which are often the cause of bellow failures

75. Are there any methods of preventing cracking of carbon steel welds in refining environments?

Where carbon steel is an appropriate material of construction, NACE (National Association of Corrosion Engineers) has issued the following standard: NACE RP0472, “Methods and controls to prevent in-service environmental cracking of carbon-steel weldments in corrosive petroleum refining environments”.

For welds where hardness testing is required, RP0472 give the following guidelines:

A. Testing shall be taken with a portable Brinell hardness tester. Test technique guidelines are given in an appendix in the standard.

B. Testing shall be done on the process side whenever possible.

C. For vessel or tank butt welds, one test per 10 feet of seam with a minimum of one location per seam is required. One test shall be done on each nozzle flange-to-neck and nozzle neck-to-shell (or neck-to-head) weld.

D. A percentage of helping welds shall be tested (5 percent minimum is suggested).

E. Testing of fillet welds should be done when feasible (with the testing frequency similar to the butt welds).

F. Each welding procedure used shall be tested. G. Welds that exceed 200 Brinell shall be heat treated or removed.

76. What is a common failure mechanism for above ground atmospheric storage tanks?

Tanks constructed prior to the 1950’s are notorious for failing along the shell-to-bottom seam or on the side seam. The principle reason for this is that these tanks were constructed before there were established procedures and codes for such a tank (Ex/ API-650 “Welded Steel Tanks for Oil Storage”). One of the key features of these codes and procedures was to make sure that tanks were designed to fail along the shell-to-seam such that the liquid remained largely contained.

77. How does a tank-blanketing valve operate?

Tank Blanketing Valves provide an effective means of preventing and controlling fires in flammable liquid storage tanks. Vapors cannot be ignited in the absence of an adequate supply of oxygen. In most instances, this oxygen is provided by air drawn into the tank from the atmosphere during tank emptying operations.

Tank Blanketing Valves are installed with their inlet connected to a supply of pressurized inert gas (usually Nitrogen), and their outlet piped into the tank’s vapor space. When the tank pressure drops below a predetermined level, the blanketing valve opens and allows a flow of inert gas into the vapor space. The blanketing valve reseals when pressure in the tank has returned to an acceptable level.

78. How can one determine if a particular solid can be fluidized as in a fluidized bed?

Mr. Alex C. Hoffmann of the Stratingh Institute for Chemistry and Chemical Engineering states: “Whether a material can be fluidized at all is the question: if it is fine or sticky, the bed will be cohesive. It will then tend to form channels through which the aeration gas will escape rather than being dispersed through the interstices supporting the particles. In the other extreme: if the particles are too large and heavy the bed will not fluidize well either, but tend to be very turbulent and form a spout.”

He goes on to present classification of fluidization by Geldart by use of the chart shown below. On this chart, the x-axis is the average particle diameter and the y-axis is the bulk density of the bed.

79. What are some guidelines for sizing a PSV for a fire scenario on a vessel in a refinery service?

Sizing a PSV on your vessel is a matter of calculating how much heat is inputted from the fire. API-520 uses Q = FA0.82 where Q is BTU/hr, F is the insulation factor (commonly taken as 1.0 but can be less than 1.0 if your insulation will remain effective during the fire and not be dislodged by fire hoses) and finally, A is the external area in ft2. The vapor load is then the total heat input from the fire divided by the liquid’s latent heat (BTU/lb).

As a fluid approaches its critical pressure, the latent heat as it boils decreases so the relieving flow rate increases. At the critical point, the latent heat goes to 0. Some companies simply use a minimum 50 BTU/lb latent heat others look at de-pressuring equipment, etc. One point is the protection, or potential lack of it, provided by a PSV during a fire.

The boiling liquid in the vessel from the fire helps keep the metal ‘cool’ so it retains its strength. Once the liquid is gone or the flame impinges on the wall not in contact with liquid, the metal can quickly reach a temperature where it has insufficient strength to withstand the internal pressure and you have a BLEVE. Not something, you want to be around. As an added point to the information above, if 50 Btu/lb is not your company’s minimum standard for latent heat, here is an alternative to calculate the latent heat:

80. Are there flow velocity restrictions to avoid static charge build up in pipelines?

There is an Australian standard “AS1020 (1984) – Control of undesirable Static Electricity”

In it, there is a table for flammable hydrocarbons as follows:

Pipe Size (mm) Max Velocity (m/s)
10 8
25 4.9
50 3.5
100 2.5
200 1.8
400 1.3
600+ 1.0

This is based on pure hydrocarbons, and there is a correction, which can be applied for fluids of different conductivity. Methanol has a higher polarity than hydrocarbons and hence is more conductive. The resistivity of diesel is 1013 ohm-m vs 108 for methanol. In addition to this, normal piping design guidelines should however be followed, such as appropriate earthing, and ensuring exit velocities into tanks of 1 m/s.

81. How can I evaluate the thermal relief requirements for double block-in of 98% sulfuric acid?

API RP520 gives equations to calculate relief requirements. For thermal relief, a very simple formula requires the heat input and the coefficient of thermal expansion of the liquid. The heat input could be a problem. If you are concerned about sulfuric in a line that is part of a heat exchanger system, then the heat is simply the design capacity of the heat exchanger. If it were a pipeline in the sun, then you would have to calculate the amount of heat that the sun can put into the pipe. You can get the coefficient of thermal expansion from your supplier or any book on sulfuric.

You can also calculate it by taking the specific gravity at two different temperatures and divide the SG difference by the temperature difference. Coefficient of expansion has the units of 1/0F. Now for the easy part, if you are at all concerned, just put in a 3/4? x 1? thermal relief valve and do not worry about doing any calculations. However, I do not believe sulfuric has any problems in pipelines unless it is a very long one and directly in the sun. In addition, I would make it a standard procedure to drain the line if it will sit dead headed for any significant period. Just a small bleed will be enough.