Essential Chemical Engineering Interview Questions Part – 8
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.
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.
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
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).
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.
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.
Can Condensate Control In A Reboiler Cause Water Hammer Problems?
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
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.
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.
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.
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.
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.
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
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.
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
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.
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