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During the manufacture of PAINT, solvents are added to MAKE the paint thinner so that it can be applied to various SURFACES. Once the paint is applied, the solvents evaporate and the RESINS and pigments that make up the paint for a thin, solid layer on the surface.

During the manufacture of paint, solvents are added to make the paint thinner so that it can be applied to various surfaces. Once the paint is applied, the solvents evaporate and the resins and pigments that make up the paint for a thin, solid layer on the surface.

Typically, organic solvents can be SPLIT up in the following classes: Oxygenated, HYDROCARBON, and Halogenated. Oxygenated solvents include alcohols, GLYCOL ethers, ketones, esters, and glycol ETHER esters. Hydrocarbon solvents include aliphatics and aromatics. Halogenated solvents include those that are chlorinated primarily.

Typically, organic solvents can be split up in the following classes: Oxygenated, Hydrocarbon, and Halogenated. Oxygenated solvents include alcohols, glycol ethers, ketones, esters, and glycol ether esters. Hydrocarbon solvents include aliphatics and aromatics. Halogenated solvents include those that are chlorinated primarily.

Electrolysis (which MEANS splitting using electricity) of water is the method for producing hydrogen from water. The safest way to commercially store it would be to use a palladium "sponge", because palladium ADSORBS several hundred times it's own volume in hydrogen. One would need to produce a compound with a very HIGH surface AREA, which has a thin COATING of palladium. This type of material is commonly used as a catalyst in chemical processes.

Electrolysis (which means splitting using electricity) of water is the method for producing hydrogen from water. The safest way to commercially store it would be to use a palladium "sponge", because palladium adsorbs several hundred times it's own volume in hydrogen. One would need to produce a compound with a very high surface area, which has a thin coating of palladium. This type of material is commonly used as a catalyst in chemical processes.

According to the US Solvent COUNCIL, "A solvent is a liquid which has the ability to dissolve, suspend, or extract other MATERIALS WITHOUT chemical change to the material or solvent. Solvents make it possible to process, APPLY, clean, or separate materials.

According to the US Solvent Council, "A solvent is a liquid which has the ability to dissolve, suspend, or extract other materials without chemical change to the material or solvent. Solvents make it possible to process, apply, clean, or separate materials.

This is easily DONE. Just expose HYDROGEN peroxide to air. The oxygen in the air will oxidize the hydrogen peroxide into its component gases. It happens far too SLOWLY for industrial or most other purposes (an ENZYME catalyst can be used to speed up the process). However, neither hydrogen nor oxygen is produced in this manner in INDUSTRY. The enzyme catalyst is called "catalase".

This is easily done. Just expose hydrogen peroxide to air. The oxygen in the air will oxidize the hydrogen peroxide into its component gases. It happens far too slowly for industrial or most other purposes (an enzyme catalyst can be used to speed up the process). However, neither hydrogen nor oxygen is produced in this manner in industry. The enzyme catalyst is called "catalase".

About 60% of total surfactant market is composed of the DETERGENT and cleaning products marketplace. These types of compounds are SOLD in LARGE volumes at low prices.

About 60% of total surfactant market is composed of the detergent and cleaning products marketplace. These types of compounds are sold in large volumes at low prices.

The first production scale PLA (polylactic acid) facility was built by Cargill Dow in The BLAIR, NEBRASKA, and USA. The facility is designed to consume 40,000 BUSHELS of corn per DAY and produce 300 million lb/year of PLA.

The first production scale PLA (polylactic acid) facility was built by Cargill Dow in The Blair, Nebraska, and USA. The facility is designed to consume 40,000 bushels of corn per day and produce 300 million lb/year of PLA.

A catalytic converter is a device that uses a catalyst to CONVERT three harmful compounds in automobile exhaust gas into harmless compounds. The three harmful compounds are:

• Hydrocarbons (in the FORM of unburned gasoline)
• Carbon monoxide (formed by the combustion of gasoline)
• NITROGEN oxides (created when the heat in the engine forces nitrogen in the AIR to combine with oxygen).

Carbon monoxide is a poison for any air-breathing animal. Nitrogen oxides lead to smog and acid rain, and hydrocarbons produce smog. In a catalytic converter, the catalyst (in the form of platinum and palladium) is coated onto a ceramic honeycomb or ceramic beads that are housed in a muffler-like package attached to the exhaust PIPE. The catalyst helps to convert carbon monoxide into carbon dioxide. It converts the hydrocarbons into carbon dioxide and water. It also converts the nitrogen oxides back into nitrogen and oxygen.

A catalytic converter is a device that uses a catalyst to convert three harmful compounds in automobile exhaust gas into harmless compounds. The three harmful compounds are:

Carbon monoxide is a poison for any air-breathing animal. Nitrogen oxides lead to smog and acid rain, and hydrocarbons produce smog. In a catalytic converter, the catalyst (in the form of platinum and palladium) is coated onto a ceramic honeycomb or ceramic beads that are housed in a muffler-like package attached to the exhaust pipe. The catalyst helps to convert carbon monoxide into carbon dioxide. It converts the hydrocarbons into carbon dioxide and water. It also converts the nitrogen oxides back into nitrogen and oxygen.

Silicon is well known for its chemical inertness, (i.e. it tends not to react with many other chemicals). DEPENDING on what type of silicon you are dealing with, this may or may not be easy to solve. If the silicon is from a lubricant, it is probably the graphitic form, which is soluble in a strong combination of nitric, and hydrofluoric acids, NEITHER of which I would recommend for you to use...nor hydrofluoric acid is not easy to come by. If it is silicon from an acidic form (probably any other form other than a lubricant), you should try AMMONIA. In either CASE, leave your acetone at home...it will NEVER work! UPDATE: An ammonia solution worked very well in this case.

Silicon is well known for its chemical inertness, (i.e. it tends not to react with many other chemicals). Depending on what type of silicon you are dealing with, this may or may not be easy to solve. If the silicon is from a lubricant, it is probably the graphitic form, which is soluble in a strong combination of nitric, and hydrofluoric acids, neither of which I would recommend for you to use...nor hydrofluoric acid is not easy to come by. If it is silicon from an acidic form (probably any other form other than a lubricant), you should try ammonia. In either case, leave your acetone at home...it will NEVER work! UPDATE: An ammonia solution worked very well in this case.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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

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.

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.

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

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

 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

 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

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.

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.

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.

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.

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).

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).

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

Examining the following factors should allow for a reasonable evaluation of cooling towers:

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

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).

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.

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.

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.

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.

Four (4) main factors to consider include moisture content, temperature, particle SIZE (and shape), and time at REST.

1. An increase in moisture content will generally make solids more "sticky". Some solids will absorb moisture from the air, which is why nitrogen is often used as a carrier gas (among other reasons).
2. For some solids, their ability to flow can be adversely impacted by temperature or even the length of time that the particles are exposed to a specific temperature. For example, soybean meal flows NICELY at 90 °F but start to form large bridges at 100 °F.
3. Generally, the finer a bulk solid becomes, the more COHESIVE the particles. Round particles are generally easier to handle than "stringy" or oddly shaped particles. As particles rest in a bin, they can COMPACT together from their own weight. This can create strong bonds between the particles.
4. Often times, re-initiating flow can break these bonds and the solids will flow as normal, but this can depend on the load at given locations in the bin.

Four (4) main factors to consider include moisture content, temperature, particle size (and shape), and time at rest.

The saltation VELOCITY is defined as the actual gas velocity (in a horizontal pipe run) at which the particles of a homogeneous SOLID FLOW will start to fall out of the gas stream.

In designing, the saltation velocity is used as a basis for choosing the design gas velocity in a pneumatic conveying system. Usually, the saltation gas velocity is multiplied by a factor, which is dependent on the NATURE of the solids, to arrive at a design gas velocity.
For example, the saltation velocity factor for fine particles may be about 2.5 while the factor COULD be as high as five for course particles such as soybeans could.

The saltation velocity is defined as the actual gas velocity (in a horizontal pipe run) at which the particles of a homogeneous solid flow will start to fall out of the gas stream.

In designing, the saltation velocity is used as a basis for choosing the design gas velocity in a pneumatic conveying system. Usually, the saltation gas velocity is multiplied by a factor, which is dependent on the nature of the solids, to arrive at a design gas velocity.
For example, the saltation velocity factor for fine particles may be about 2.5 while the factor could be as high as five for course particles such as soybeans could.