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Technical Interview Q & A PDF






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. 

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 d irectly 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. 

82. What is a good source of information for the design of pressure vessels?

Pressure Vessel Handbook Author = Eugene F. Megyesy Publisher = Pressure Vessel Handbook Publ., Inc. P.O. Box 35365 Tulsa, OK 74153 Page 18 tells you how to calculate a pressure vessel’s wall thickness; page 176 tells how to calculate an API Std. 650 Storage tank wall thickness. The rest of the book is a goldmine for young engineers – especially CHE’s involved in vessel design. It also gives all the information you require for supports, nozzles, head design, piping, ladders, platforms, etc. 

83. What is the method of determining maximum differential pressure during hydro testing of shell and tube heat exchangers? 

Mr. Richard Lee of Plumlee International Consulting usually heat exchangers have two sets of test pressures per side, one for strength tests, and the other for “operating” or “leak” tests. The strength tests are set by the design code and if you have the original design data sheets for your equipment then the information should be shown on these. If you do not then you will have to do the calculations yourself, the exact method will depend upon which design code you use, the most common one being TEMA (which uses the ANSI/ASME pressure vessel code for reference in this area). 

Most shell and tube exchangers are designed such that each side of the unit will withstand the full design pressure, with only atmospheric pressure on the other side. In order to save money, some larger units will have the tube-sheets especially designed to withstand only a much lower differential pressure (requiring both sides to be tested simultaneously). This important information should be shall quite clearly on the design sheets and on the vessel nameplate (assuming that either are available). If the only need is to check that a gasket has been properly installed then it can be permissible to perform a lower pressure test based on the operating pressure. The acceptability of this lower pressure test will often depend upon the consequences of a leak. 

84. Are there any general rules that should be considered when designing a slurry piping system?

The following are items to consider when designing a piping system that will transport slurries:

1) Whenever possible, piping should be designed to be self-draining

2) Manual draining should be installed to drain sections of the piping when self-draining is not possible

3) Blow-out or rod-out connections should be provided to clear lines in places where plugging is likely or could occur

4) Access flanges should be provided at T-connections

5) Manifolds should have flanged rather than capped connections to allow for easy access

6) Clean-out connections should be provided on BOTH sides of main line valves so that flushing can take place in either direction

7) Break flanges should be provided every 20 feet of horizontal pipe or after every two changes in direction

85. How are vessel lined with glass or how are they coated?

First, the glass mixture is smelted for form the proper recipe based on temperature and pressure requirements of the vessel. Then the glass is ground into tiny particles and suspended in a liquid medium called a slip. This mixture is then spayed onto the surface to be coated. The vessel is then heated to about 800 0C to bond the glass to the steel (usually carbon steel). The vessel is then slowly cooled. 

86. At what temperature is glass fused to steel in the making of glass-lined equipment?

The borosilicate glass is typically fused to carbon steel at a temperature of about 800 0C.

87. What are some typical applications for glass-lined reactors?

Glass-lined equipment gives superior protection to all mineral acids at all concentration and temperatures. One exception is hydrofluoric acid. They are also used is high-purity processes where cleanliness is very important. Using glass-lined equipment help eliminate the possibility of metal contamination. A third application is in polymerization. Metallic vessels sometimes tend to allow the polymer to stick to the walls of the vessels while glass-lined vessels have good anti-stick properties. 

88. Is there any way to slow coke formation in ethylene furnaces? 

Westaim Corporation has a commercial process for applying a special coating to the tubes used in ethylene furnaces. Westaim claims that coke buildup is reduced to one-forth to one-tenth of the normal rate. The coating consists of a combination of metal, ceramic powder, and a polymer. Once the coating is applied, the tubes are then heat-treated and reacted with an unspecified gas. Welds cannot be coated with this process. 

89. What information is needed to specify a mixer?

1. Specific Gravity

2. Fluid Viscosity

3. Phase to be dispersed

4. Solid-liquid systems

The settling velocities of the 10, 50, and 90 percent weight fractions of the particle size distribution should be available. 5. For gas systems, the standard and actual flow rates will be needed. 

90. How can viscosity affect the design of a mixer?

For Newtonian fluids, which will have a constant viscosity at all impeller speeds, most design correlations will perform satisfactorily for viscosities up to 5,000 cP. Above 5,000 cP, estimating errors from 20% to 50% can result in the sizing of the agitator.

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