This section provides design and operating guidelines that apply to specific service classes, including treated cooling water, untreated sea water, closed loop water cooling, low temperature process steam generators, high temperature waste heat steam generators, reboilers, crude unit heat exchangers, and FCC flue gas coolers.
300 Service Considerations Abstract This section provides design and operating guidelines that apply to specific service classes, including treated cooling water, untreated sea water, closed loop water cooling, low temperature process steam generators, high temperature waste heat steam generators, reboilers, crude unit heat exchangers, and FCC flue gas coolers Chevron Corporation Contents Page 310 Treated Cooling Water 300-2 320 Untreated Sea Water 300-4 330 Closed Loop Water Cooling 300-5 340 Moderate Temperature Process Steam Generators 300-5 350 Very High Temperature Waste Heat Steam Generators 300-8 351 Components 352 Field Modifications 360 Reboilers 300-11 370 Condensers 300-20 380 Crude Unit Heat Exchangers 300-20 390 FCC Flue Gas Coolers 300-24 300-1 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual 310 Treated Cooling Water Heat exchangers in treated cooling water service should be designed and operated consistent with the water treatment The temperature limits and thermal resistance of corrosion inhibitor films affect the design and operating limits of cooling water exchangers Cooling tower water is normally acidified to suppress alkaline scaling, and concentrated (“cycled”) close to but not exceeding the solubility limit of the least soluble salt at the maximum design tube wall temperature Chlorination is normally used to suppress biological fouling These procedures eliminate natural causes of water fouling Corrosion inhibitors are added to cooling tower water to provide a protective barrier between the oxygen saturated water and carbon steel components of the system Corrosion inhibitor films are effective in piping and on the tube side of heat exchangers Movement of tubes in baffle holes prevents effective film formation on the outside (shell side) of baffled tubes Where shell side water is used, tube material should be selected to resist oxygenated water Thermal resistance of corrosion inhibitor films is significant and should be included in heat exchanger design Recommended design resistance for corrosion inhibitor films is given in Figure 300-1 Figure 300-1 is based on HTRI data obtained in member plants, and includes the effects of imperfect control in the commercial environment Fig 300-1 Asymptotic Fouling Resistance for Cooling Water Corrosion Inhibitor Films December 1989 300-2 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations The temperature limits of corrosion inhibitor films are more important than their thermal resistance The protective films break down between 160°F and 220°F and result in rapid fouling and loss of corrosion protection The interface temperature between the metal and the inhibitor film should be kept below 160°F throughout the exchanger Figure 300-2 expresses this criterion in a plot of maximum process temperature versus the process-side heat transfer coefficient for various water-side velocities The curves are based on 120°F bulk water Fig 300-2 Corrosion Inhibitor Stability Limits for Treated Cooling Tower Water The shell side heat transfer coefficients for liquid hydrocarbons from Figure 200-4 are superimposed on Figure 300-2 for convenience Cooling liquid hydrocarbons at economic velocities is not a problem in the usual temperature range Condenser design within the inhibitor stability limits is difficult when condensing temperatures are over 200°F, since the condensing heat transfer coefficients in inlet regions are usually between 500 and 1000 Btu/hr⋅°F⋅ft2 Air cooled condensers are preferred in those cases Figure 300-2 can also be used to evaluate the effect of throttling water to control condenser duty Throttling reduces water velocity, increases water temperature, and is likely to exceed inhibitor stability limits if the condensing-side temperature is over 160°F Bypassing part of the process fluid around the condenser is a better way to control a water cooled condenser Corrosion inhibitor film resistance at economic liquid velocity is not large enough to justify the use of all alloy cooling water systems without corrosion inhibitors Chevron Corporation 300-3 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual 320 Untreated Sea Water Heat exchangers using untreated sea water should be designed and operated to avoid inorganic fouling, and to avoid or accommodate biological fouling By operating exchangers near economic velocities and suppressing water vaporization, inorganic fouling can usually be avoided Periodic cleaning is usually required to accommodate biological fouling Solubility of calcium sulfate usually limits the applications of sea water cooling Calcium sulfate hemi-hydrate determines the limits in nonboiling applications; it precipitates at surfaces over 310°F Calcium sulfate anhydrite determines the limits where subcooled boiling occurs; it precipitates on boiling surfaces over 230°F Alkaline scaling (e.g., CaCO3 or Mg(OH)2 precipitation) may occur in some coastal waters where the pH exceeds about 7.6 Acidification of such water is necessary to make it suitable for cooling purposes Particulates not cause fouling unless velocities are less than about half the economic velocity Biological fouling can be prevented by chlorination or by maintaining surfaces over 120°F Chlorination is not always environmentally acceptable or practical Maintaining heat transfer surfaces over 120°F has been used in subsea natural convection crude oil coolers needed to protect nonmetallic subsea production hoses Keeping tube surface temperatures over 120°F is not practical in most cases Biological fouling occurs spontaneously in natural sea water between 32°F and 120°F Particulates make up a major portion of the deposit and are bonded to each other and to the tube by biological material Observed average fouling rates for titanium and 90-10 Cu-Ni tubes in sea water are shown in Figure 300-3 Fig 300-3 Average Observed Biological Fouling Rates for Titanium and Cu-Ni Tubes in Sea Water December 1989 300-4 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations The lower average fouling rate for 90-10 Cu-Ni tubes reflects the tubes periodic sloughing of deposit from itself Copper slowly dissolves in sea water (corrodes) through the deposit and is toxic to lower forms of aquatic life Copper corrosion and toxicity, however, are not sufficient to break the bond at the deposit-metal interface Titanium is immune to corrosion, is not toxic, and therefore, is generally recommended for sea water service Larvae and small marine creatures pass through line filters (screens) and can grow large enough to block heat exchanger tubes Back flushing lines once a shift eliminates this possibility 330 Closed Loop Water Cooling Closed loop water cooling is used where the coolant temperatures must be maintained over a certain temperature to avoid solidifying the process stream (“tempered water cooling”), or for high process temperature applications that would exceed the temperature limits of treated cooling tower water or sea water discussed above Closed loop water is usually boiler quality and either inhibited with chromate or nitrogen blanketed Chromate is effective if tube temperatures are below the water boiling point If tube temperature could exceed the water boiling point, nitrogen blanketing without inhibitor is recommended Heavy oils may freeze or become immobile at temperatures above normal coolant temperature Cooling such fluids is usually accomplished with “tempered water cooling,” as illustrated in Figure 300-4 The coolant temperature should be controlled about 10°F above the freezing/pour point temperature of the stock being cooled Fig 300-4 Typical Tempered Water Cooling System 340 Moderate Temperature Process Steam Generators This section applies to steam generators heated by process fluids with temperatures less than 1000°F Chevron Corporation 300-5 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual Many process steam generators operate by natural circulation from an elevated steam drum Circulation is driven by the density difference between the liquid in the downcomer and the two-phase mixture in the riser (external to the exchanger) A typical steam generator is shown in Figure 300-5 Design guidelines for this type of steam generator are listed below The steam/water riser to the steam drum should operate in annular or churn flow Fig 300-5 • Side-to-side flow with 90 degree tube layout is used for good circulation at low pressure drop • Target vaporization is usually 5% of total circulation and is obtained by appropriate pipe sizes and drum elevation • Blowdown is from the steam drum near the vapor-liquid interface where water is most concentrated • Heat flux should be 2000 Btu/hr⋅ft2 or higher to assure nucleate boiling throughout the bundle • A support plate at the steam/water outlet is usually required to avoid tube vibration Typical Conventional E-Shell Steam Generator A single steam generator and steam drum are sometimes combined in a kettle-type steam generator as shown in Figure 300-6 The bundle is elevated relative to the lower part of the shell to provide a minimum bundle-to-shell gap equal to about 10% of the bundle diameter Cutouts in the lower part of the full tube support plates are required to facilitate free axial flow of water along the bottom of the bundle Circulation is driven by the density difference between the liquid at the sides of the bundle and the two-phase mixture in the central part of the bundle (internal circulation) Blowdown is from the bottom of the shell near the tubesheet Liquid level is maintained a minimum of inches above the top tube, plus a control allowance The kettle should be sized to provide December 1989 300-6 Chevron Corporation Heat Exchanger and Cooling Tower Manual Fig 300-6 300 Service Considerations Typical Kettle Steam Generator adequate vaporliquid disengaging space between the normal operating liquid level and the top of the kettle Horizontal mass velocity of steam approaching the steam outlet nozzle(s) in the disengaging space (Figure 300-7) should not exceed the following criteria: Fig 300-7 Operating Pressure, psig Mass Velocity, lb/hr⋅ft2 15 1900 40 2900 60 3400 150 4800 300 6400 600 8500 Steam Disengaging Velocity Chevron Corporation 300-7 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual The above criteria provide adequate steam quality for most process uses (e.g., stripping steam), but are not adequate for steam turbines Knockout vessels are occasionally provided immediately upstream of turbines This arrangement removes condensate formed in the piping as well as that entrained from the steam generator U-tube construction described above is acceptable if the difference between process inlet and outlet temperature is less than 200°F Otherwise excessive thermal stresses develop in the tubesheet Thin, stayed fixed tubesheets are used when thermal stresses would otherwise be too high Stayed tubesheets depend on the tubes to contain the shell side pressure Stayed tubesheets are governed by the rules in Section I of the ASME Code 350 Very High Temperature Waste Heat Steam Generators High temperature waste heat steam generators are services where the heating gas is over 1000°F and can cause rapid failure of pressure containing parts that are not continuously water wetted High temperature in-shell steam generation is discussed below for horizontal units, and in Section 390 for vertical units This manual does not address tube side steam generation Figure 300-8 is a schematic of a high temperature horizontal shell side steam generator Fig 300-8 Typical High Temperature Steam Generator This type of unit is used in hydrogen, ammonia and sulfur plants Inlet gas temperatures range from about 1500°F to 3000°F The bypass pipe shown in Figure 300-8 is required in hydrogen and ammonia plants to control downstream temperature Bypass is not used in sulfur plants Shell side circulation is driven by the density difference between the fluid in the annular gap (mostly liquid) and the lighter two-phase mixture in the bundle (internal circulation) For best circulation, 90 degree square tube layout is used The annular gap should be about 10% of the bundle diameter December 1989 300-8 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations Operation is limited by “dryout” just downstream of inlet tube ferrules near the center of the bundle When dryout occurs, the tube temperature jumps to within a few hundred degrees of process inlet temperature, and the tube may fail within minutes in very high temperature units In lower temperature units, local dryout causes local deposition of solids, restricted water circulation, more extensive dryout, and eventual tube failure a few months after initial dryout Dryout heat flux in submerged bundles increases with process gas temperature and pressure, and with the ratio of heat transfer surface area to peripheral inflow/outflow area Appendix E provides methods to evaluate thermally induced dryout, and calculate maximum recommended heat flux Water concentration is maximum at the same location where dryout is most likely to occur (central tubes near ends of ferrules) Blowdown should be located close to this region Higher quality water is required in horizontal shell side steam generators with internal circulation than with external circulation because the maximum percentage of vapor is higher Within the recommended operating range (without dryout), water is about 25% more concentrated than in systems designed for a maximum of 5% vaporization 351 Components Tubesheets Thin stayed tubesheets are required to avoid excessive thermal stresses They should be designed in accordance with ASME Boiler and Pressure Vessel Code, Section I Tubesheet thickness is governed by the largest unstayed area, which is usually the annular space between the bundle and the shell Tube-to-Tubesheet Joints Tube ends should be rolled and strength-welded to the tubesheet Roll 95% of the tubesheet thickness to minimize the crevice between the tubes and the tubesheet Rolling at or beyond the tubesheet thickness may damage the tube Tube Supports Tube support spacing and thickness should conform to TEMA rules Bolt the tube supports to clips on the shell to avoid cracking due to pressure dilation of the shell Provide peripheral cut-outs on the tube supports so axial flow in the annulus is unrestricted Tubesheet Refractory The purpose of tubesheet refractory is to protect the tubesheet from high tube side temperatures Only about inch of refractory is useful for insulation More thickness is needed to keep the refractory in place when it cracks See Insulation and Refractory Manual for recommendations Chevron Corporation 300-9 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual Ferrules The purpose of ferrules is to protect the tubesheet and seal welds from high temperatures, and to provide a hole through the hot tubesheet refractory Ferrules are usually high alumina ceramic or an alloy, such as Inconel Metal ferrules are preferred, if temperatures allow, because they can be made thinner than ceramic, and thus reduce the geometry discontinuity between the downstream end of the ferrule and the tube I.D Wall thickness of ceramic ferrules should be at least 1/8 inch to facilitate their manufacture Both ceramic and metal ferrules should be wrapped with 1/32 inch thick ceramic paper insulation, glued in place About inch of the outlet end of metal ferrules should be expanded to the tube I.D dimension before insertion into the tube This snug fit keeps the ferrule in place during installation of the refractory and keeps the paper insulation in place during operation Downcomers and Risers A single downcomer is usually sufficient Multiple risers are usually required, and should be sized for annular or churn flow Consider the axial steam production profile along the unit in selecting riser locations for horizontal units; i.e., put one riser near the hot tubesheet and shift the others toward the hot end as appropriate Equations for calculating the axial steam production profile are given in Appendix F Internal vs External Bypass An internal bypass is preferred to an external bypass because internal bypasses are cheaper and more reliable If the internal bypass is uninsulated, the surface area should be included in the dryout heat flux calculations If dryout is a problem, provide an insulated internal sleeve, welded on one end only, for the first feet Check the thermal stress between the bypass pipe and nearby tubes If thermal stress is a problem, the insulated sleeve can be extended for the full length Dryout Sensors If it is necessary to operate a steam generating bundle close to the dryout limit, it may be advantageous to install dryout sensors Local dryout usually results in mechanical failure before reduction in thermal performance is noticed When dryout occurs, the tube temperature jumps from very near the water/steam temperature to near the tube side fluid temperature This large temperature change can be easily detected by a thermocouple A dryout sensor consists of a thermocouple tack welded to the tube O.D in the high heat flux region downstream of the ferrule, with the lead being taken out through a high pressure fitting in the shell This can only be done during manufacture or retubing Several dryout sensors are usually installed in areas most prone to dryout Piping and Instrumentation Section I of the ASME Code defines instrumentation and piping requirements December 1989 300-10 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations 352 Field Modifications Where thermally induced dryout is a problem, the dryout heat flux can be increased by judicious removal or plugging of tubes as indicated in Figure 300-9 Either tube removal or tube plugging provides a low resistance path for vapor free water to flood the central region of the bundle Both have been done successfully Tube removal requires new tubesheets and added stay rods Consult the Engineering Analysis Division of ETD for the design of bundle modifications to avoid dryout Fig 300-9 Modifications to Increase Dryout Heat Flux 360 Reboilers Reboilers are designed in many configurations, including vertical tube side boiling thermosiphons, horizontal shell side boiling thermosiphons, submerged horizontal shell side boiling with internal natural circulation, and horizontal tube side boiling with pumped circulation Vertical tube side boiling thermosiphons and submerged horizontal shell side boiling with internal natural circulation are the two most common configurations Vertical tube side boiling thermosiphons are normally designed using the HTRI RTF computer program This is a mature program that rigorously simulates thermal and hydraulic performance and flags inappropriate operating conditions, including choked flow, mist flow, hydraulic resonance, and excessive subcooled boiling zones Horizontal shell side boiling is more efficient than vertical tube side thermosiphon boiling, but rigorous integrated thermal and hydraulic simulation methods are not currently available Horizontal reboilers may be sized and thermally evaluated using the simple methods given later in this section, or with the HTRI RKH computer program In either case, independent design/evaluation of the external circulation is required Chevron Corporation 300-11 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual General Guidelines The following guidelines apply to all reboiler configurations The boiling regime should always be nucleate This is assured if the heat flux is maintained at 2000 Btu/hr⋅ft2 or higher everywhere in the exchanger Sensible heating medium should be routed cocurrent to the boiling fluid to facilitate control without fouling Control by bypassing heat medium results in a temperature pinch and nil heat transfer near the heat medium outlet, which should correspond to the high velocity two-phase boiling outlet Heat medium inlet near the boiling fluid inlet promotes nucleate boiling in this region and avoids a stagnant zone on the boiling side where particulate fouling may otherwise occur Steam heated reboilers should be controlled by throttling steam pressure and should have a downstream condensate receiving vessel to keep the reboiler drained of condensate, and a vent for noncondensables Otherwise, steam side corrosion at the condensate interface and boiling side fouling in the nil heat transfer condensate flooded region are likely Specific configuration guidelines are given below Vertical Tube Side Boiling Vertical thermosiphons have single shell and tube passes with expansion provisions (packed joint or bellows) between the floating head and shell cover Tube diameter is usually inch or larger, and tube lengths are usually limited to to 10 feet for good circulation Shell side geometry is typical of TEMA “E” shells with 45 degree tube layout and 20% cut segmental baffles Baffle spacing is 20 to 50% for sensible heat mediums, and as needed for vibration control in steam heated units A vent near the top tubesheet is needed for steam heated units to prevent accumulation of CO2 and carbonic acid corrosion of the tubes Tubes are flush with the top tubesheet (instead of the usual 1/8 inch protrusion) to facilitate drainage Target vaporization is 30 weight percent maximum Figure 300-10 shows the typical configuration for steam heated and oil heated vertical thermosiphon reboilers Four alignment bars around the bellows permit axial movement only and protect the bellows from non-axial loads during assembly, disassembly and handling The flow area of the process outlet line should be 100 to 150% of the total tube side flow area The size of the process inlet line may be estimated by: (Dpi)2/Q = to 11 Dpi is the inlet pipe I.D in inches and Q is the heat duty in millions of Btu/hr A packed tail pipe, instead of a bellows, may be used for noncorrosive, nontoxic heat media below 300°F A packed tail pipe is illustrated for a split ring floating head (Type “S”) in Figure 400-1 of Section 410 Horizontal Shell Side Boiling Most horizontal reboilers have internal circulation with up-flow through a 90 degree square layout bundle and down-flow in an annular space around the bundle December 1989 300-12 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations Fig 300-10 Typical Vertical Thermosiphon Reboilers Chevron Corporation 300-13 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual Internal circulation is independent of external circulation provided that external circulation is adequate to keep the bundle flooded The annular gap around the bundle should be at least 10% of the bundle diameter Full tube support plates are used with cutouts top and bottom to facilitate axial flow within the exchanger When vapor-liquid separation in the reboiler is desired, a kettle-type shell is used The bundle is located near the bottom of the shell with a gap at the bottom equal to about 10% of the bundle diameter There is a much larger space above the bundle to effect vapor-liquid separation Full tube support plates are used with cutouts at the bottom for unrestricted axial flow of liquid A kettle reboiler provides one theoretical distillation stage Horizontal reboilers are sometimes inserted directly into the bottoms compartment of a column without a shell This is practical for very small reboilers Horizontal shell side reboilers with circulation driven by the difference in fluid density between the inlet and outlet piping have no advantage over horizontal reboilers with internal circulation The boiling-side pressure drop is much higher than for internal circulation Horizontal shell side reboilers have been used when surplus exchangers designed for other services were available that were large enough for adequate circulation and small enough to assure nucleate boiling throughout the bundle Horizontal Forced Flow Tube Side Boiling Forced flow boiling is rare It is used for boiling light components from viscous mixtures and for polymerizing fluids where higher fluid shear is needed than can be provided by natural circulation Sizing Shell Side Boilers This section presents a simple graphical method to size or evaluate shell side reboilers The graphs are based on the equations in Appendix D They apply to horizontal shell side hydrocarbon reboilers with internal circulation (i.e., with annular gap between bundle and shell, in kettles, and for stab-in reboilers without shells) Figure 300-11 is a plot the of maximum recommended heat flux (qref), boiling heat transfer coefficient (href), and tube wall-to-boiling fluid temperature difference ([Twall - Tsat]ref) versus bundle diameter, with hydrocarbon critical pressure as a parameter This graph applies directly to pure component boiling at a reduced pressure of 0.029 (near atmospheric pressure for hydrocarbons) with isothermal heat medium The heat flux curves include a factor of 0.7 to account for correlation inaccuracies and an additional 0.8 factor for operating flexibility; 3/4 inch tubes on inch 90 degree square layout is assumed Figure 300-12 is a plot of correction factors for heat flux, boiling coefficient, and temperature difference to extend Figure 300-11 to all pressures Figures 300-11 and 300-12 define the minimum required heat transfer area for a given heat duty, or the maximum recommended heat duty for a given bundle, for isothermal heat media (e.g., steam heated) To determine the minimum heat transfer area for a particular heat duty, simply divide the duty by the heat flux from Figure 300-11 and by the pressure correction factor (Fqp) from Figure 300-12 To December 1989 300-14 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations Fig 300-11 Reference Boiling Parameters determine the maximum recommended heat duty for a particular bundle, multiply the heat transfer area by the heat flux from Figure 300-11 and by the pressure correction factor (Fqp) from Figure 300-12 These procedures are for operation at 56% (0.7×0.8×100) of incipient dryout heat flux Fig 300-12 Pressure Corrections Chevron Corporation 300-15 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual Heat transfer coefficients and temperature differences have to be considered to select or evaluate appropriate heat medium temperatures Fouling can be compensated for by raising the heat medium temperature However, the capacity of the reboiler is still limited by the surface area and the maximum recommended heat flux Figure 300-13 presents correction factors for heat flux and the boiling heat transfer coefficient when sensible (nonisothermal) heat media are used Fqsh is the ratio of maximum to average heat flux along the sensible heat medium flow path Fhsh corrects the boiling coefficient for the lower average heat flux The equations for Fqsh and Fhsh are given below Fqsh = (1-e-N)/N where: N = U × A/(M × Cp), dimensionless U = Overall heat transfer coefficient A = Heat transfer area M = Mass flow rate of heat medium Cp = Specific heat of heat medium Fhsh = Fqsh2/3 This correction results in a maximum heat flux (at the heat medium inlet) equal to 56% of incipient dryout heat flux Fig 300-13 Corrections for Sensible Heat Medium Figure 300-14 is a boiling range (dew point to—bubble point) correction factor, Fhc, for multicomponent boiling mixtures that applies to the boiling heat transfer coefficient December 1989 300-16 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations Fig 300-14 Correction for Multi-Component Mixtures Correction for Multi-Component Mixtures If the feed to the reboiler is subcooled, the following additional correction to the boiling coefficient is needed Fhsc = (1 - Qsc/Qt)2/3 where Qsc and Qt are subcooled duty and total duty, respectively The maximum recommended heat flux is: qdmax = qref × Fqp × Fqsh The corresponding boiling heat transfer coefficient is: hb = href × Fhp × Fhsc × Fhsh × Fhc The tube wall to boiling fluid temperature difference is: (Twall - Tsat) = (Twall - Tsat)ref × Ftp × qdmax/hb The required heat medium temperature depends on the heat medium heat transfer coefficient, hi, inside the tubes and on the tube wall resistance, rw The overall clean heat transfer coefficient is Uc = 1/[1/hb + rw + (1/hi)(0.75/0.56)] where (0.75/0.56) is the ratio of tube O.D to I.D Chevron Corporation 300-17 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual The required mean temperature difference (MTD) between the heat medium and the boiling fluid is: MTD = qdmax/Uc If steam is the heat medium, MTD is the temperature difference between the steam and the boiling fluid, Tstm - Tsat The heat medium is selected to provide a temperature driving force greater than or equal to that indicated above However, the reboiler should not be operated above the recommended maximum heat flux For 3/4 inch tube O.D (dto) on inch square pitch, there is one tube per square inch of bundle cross-sectional area Ignoring tie rods and pull holes, the cross-sectional area of the bundle in square inches is numerically equal to the number of tube holes in the tubesheet (nt) The bundle diameter can be approximated as Db = (4nt/π)0.5 inches and the heat transfer surface per unit length as A/L = nt ⋅πdto/12 ft2/ft Example Consider boiling normal pentane using steam heat Duty Q = 14.8 × 106 Btu/hr Pentane properties: Operating pressure P = 100 psia Critical pressure Pc = 489 psia Reduced pressure Pr = P/Pc = 0.20 Saturation temperature Tsat = 220°F Assume bundle diameter, Db = 20 inches Number of tubes nt = π(20)2/4 = 314 Area/length A/L = 314 π(0.75/12) = 61.7 ft2/ft From Figure 300-11, qref = 16,000 Btu/hr⋅ft2 From Figure 300-12, Fqp = 1.5 Maximum design heat flux qdmax = 1.5(16,000) = 24,000 Btu/hr⋅ft2 Required area A = Q/qdmax = 14.8 × 106/24000 = 617 ft2 Required length L = A/(A/L) = 617/61.7 = 10 ft Many combinations of bundle diameter and length would work Even integer lengths from 10 to 20 feet are standard Since the above calculated length is reasonable, the assumed bundle diameter is OK From Figure 300-11, href = 1000 Btu/hr⋅°F⋅ft2 December 1989 300-18 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations From Figure 300-12, Fhp = 2.5 The boiling coefficient hb = 2.5(1000) = 2500 Btu/hr⋅°F⋅ft2 The steam side coefficient (Section 216) hi = 1000 Btu/hr⋅°F⋅ft2 Tube wall resistance (Section 212): rw = 0.75 × ln(0.75/0.56)/(30 × × 12) = 0.0003 hr⋅°F⋅ft2/Btu The overall clean coefficient (Section 212): Uc = 1/[1/2500+.0003+(1/1000)(0.75/0.56)] = 491 Btu/hr⋅°F⋅ft2 The required steam temperature is 220 + 24000/491 = 268.9°F corresponding to a steam pressure of 41.1 psia The steam temperature required to achieve 125% of design duty is 220 + 1.25(24000/491) = 281°F, corresponding to a steam pressure of 50.0 psia Operating at higher duties would risk partial dryout and plugging of the bundle The nearest available steam pressure that exceeds the required steam pressure would normally be selected, and throttled as needed to control duty The minimum heat flux to assure nucleate boiling is about 2000 Btu/hr⋅ft⋅2 Operation below this heat flux may result in fouling and plugging the bundle The allowable turndown for the above example is 12:1 External Circulation Internal circulation through and around the bundle is independent of external circulation between the reboiler and the column, provided that sufficient liquid flows from the column to keep the bundle flooded The piping is usually sized to limit vaporization to about 30% of the total external natural circulation The piping should be designed to minimize elbows and horizontal runs The liquid feed line is usually sized for a liquid velocity about one third the economic velocity for pumped liquid The exit pipe is usually sized so the flow regime is annular but near the transition to slug flow, at maximum duty operation This maximizes external circulation Larger exit piping can cause slug flow with reduced static differential head and reduced circulation Smaller exit pipes can cause excessive friction losses and reduced circulation Detailed analysis is required to assure satisfactory circulation The following rules of thumb may be used for initial estimates Inlet line: Dpi2 = to 11 Outlet Line: Dpo5/Q2=1800 to 2500 Where Dpi and Dpo are in inches and Q is in millions of Btu/hr The HTRI RKH computer program may also be used to rate or design horizontal reboilers The current version is not rigorous and should be used with caution Chevron Corporation 300-19 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual 370 Condensers Condensers are normally designed using the HTRI CST computer program for shell and tube exchangers and the HTRI ACE computer program for air coolers At very low pressures, vacuum equipment performance significantly affects condenser design Vacuum systems are usually designed as a package by vendors that specialize in this type of equipment Condenser configuration is usually dictated by the coolant Air-cooled condensers are horizontal with in-tube condensation Water-cooled condensers normally have the water tube side to be consistent with water treating practice Viscous coolants (e.g., crude oil) should be in the shell for best heat transfer Condensing side pressure drop may govern the condenser configuration at low pressures Pressure drop in condensers is typically 10% of the absolute pressure or psi, whichever is less A single down-flow shell side pass over a horizontal bundle (e.g., TEMA X shell) provides the lowest pressure drop The effect of pressure drop on the condensing temperature profile should be considered Wide condensing range mixtures should be kept well mixed along the condensing path Separation of liquid and vapor reduces heat transfer coefficients and temperature driving force Considerable pressure drop is required to keep phases mixed in horizontal shell side condensers with side-to-side flow Single pass down-flow through either the shell side or the tube side requires the least pressure drop to keep phases mixed Divided horizontal flow in the shell (e.g., TEMA J shell) or horizontal in-tube condensation are next best Pure component condensation coefficients (e.g., steam) are usually very high and insensitive to configuration and flow regime Condensate receiver vessels below the condenser are usually provided to keep the condenser well drained of condensate and maintain good performance Condensate receiver vessels and most condensers should have vents at high points to remove noncondensables Noncondensable accumulation in the condenser reduces heat transfer and may cause corrosion in some services (e.g., steam) Vertical down-flow in-tube partial condensers not require periodic venting Subcooling the condensate, when required, is usually best accomplished in a separate bundle where reasonable flow at the heat transfer surface can be obtained Subcooling is also practical in single pass down-flow in-tube partial condensers where reasonable condensate flow in contact with the heat transfer surface occurs 380 Crude Unit Heat Exchangers Several interrelated crude unit heat exchanger problems are addressed in this section Crude-preheat-exchanger fouling is a problem in some crude units Crude side fouling control in the crude-residuum exchanger affects residuum fouling control Corrosion control in the atmospheric overhead condenser may affect the performance of the condenser as well as the desalter water exchanger and the crude preheat exchangers December 1989 300-20 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations Crude Preheat Exchangers Crude preheat exchangers are subject to salt-precipitation fouling, filming amine fouling, and particulate fouling Chemical reaction fouling of natural crude oil components occurs at temperatures (600+ °F) above those encountered in crude preheat exchangers Crude preheat exchanger fouling can be prevented by maintaining adequate velocities to keep particles moving, preventing salt-precipitation conditions in the heat exchangers, and avoiding film forming and water-oil stabilizing additives in the crude oil Figure 300-15 and the associated notes give the criteria to prevent crude oil fouling Fig 300-15 Crude Oil Fouling Control Notes: Maintain exchanger velocities at half the economic velocity or higher This is equivalent to maintaining shell and tube side friction pressure gradients over 0.2 psi/ft (axial) and 0.1 psi/ft, respectively Design heat exchangers upstream of the desalter with tube wall temperatures less than or equal to 350°F Maintain back pressure on the exchangers upstream of the desalter over the vapor pressure of water-saturated crude oil at the maximum tube wall temperature (350°F) Inject desalter water into cold crude oil at a minimum rate of liquid volume percent of crude oil flow rate More is preferred Maintain aqueous phase pH in the exchangers and desalter between 5.5 and 6.5 This may require acid injection into cold crude for some very alkaline crudes Careful design of injection and mixing equipment is required Maintain flash drum bottoms temperature at least 10°F above the water boiling point at flash drum pressure Avoid film forming and water oil stabilizing additives in crude oil feed and desalting water Caustic injection, if any, should be downstream of the last preheat exchanger Crude-Residuum Exchangers Residuum exchangers are subject to chemical reaction fouling (“coking”) and particulate fouling Residuum fouling can be prevented by operating exchangers near the economic velocity and controlling tube surface temperatures below the threshold of chemical reaction fouling Figure 300-16 illustrates the normal method of controlling residuum fouling The heat transfer coefficient on the crude side is usually higher than on the residuum side The tube wall temperature is therefore closer to the crude tempera- Chevron Corporation 300-21 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual Fig 300-16 Residuum Fouling Control ture than to the residuum temperature Quenching the residuum to 650°F results in a maximum tube wall temperature less than 600°F, if there is no crude fouling The threshold fouling temperature of residuum varies with crude source and flash zone temperature Normal pump overdesign (125% of design flow) is usually adequate to compensate for crude variations The optimum operating temperature is just below the threshold temperature for fouling If crude-side fouling is allowed to occur, the residuum would have to be reduced another 50°F or so to prevent residuum-side fouling Atmospheric Overhead Condenser Crude unit overhead condensers usually exchange heat with viscous crude oil The crude oil should be on the shell side with a 45 degree tube layout This arrangement results a seven-fold improvement in thermal performance relative to viscous oil in the tubes (See Figure 200-4 in Section 213.) Atmospheric overhead exchange is subject to fouling on the condensing side by saltprecipitation fouling (NH4Cl) and particulate fouling (from condenser corrosion products) Condenser-side fouling can be eliminated with saturation water recycle shown in Figure 300-17 Saturation water recycle is consistent with good corrosion control as discussed in the Corrosion Prevention Manual Vertical single pass down-flow condensers are preferred to obtain high condenserside heat transfer with low pressure drop An expansion bellows is provided between the floating head and the shell cover Filming amines are commonly injected into crude unit overhead systems They are present in the naphtha and are dispersed to other distillate streams via the top reflux, and to the desalter water exchanger and to crude feed via the net overhead water The presence of filming amine can significantly affect thermal performance of downstream exchangers Filming amine fouling occurs rapidly and then levels out (i.e., is asymptotic) at moderate temperatures The observed amine films are mostly particulates bound December 1989 300-22 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations Fig 300-17 Fouling (and Corrosion) Control in Crude Unit Atmospheric Overhead Condensers together by the amine Above the amine decomposition temperature (usually 300°F to 400°F), nonasymptotic filming amine fouling has been observed Moderate temperature asymptotic filming amine fouling is shown in Figure 300-18 for amine contaminated desalter water and crude oil Where it occurs, filming amine fouling is usually the dominant thermal resistance in heat exchangers Fig 300-18 Filming Amine Fouling Resistance for Hydrocarbon and Water Streams below 350°F Chevron Corporation 300-23 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual 390 FCC Flue Gas Coolers Flue gas coolers in Fluid Catalytic Crackers (FCCs) cool particle-laden flue gas from the regenerator The flue gas flows downward in a single tube pass Natural circulation steam generation occurs in the shell Rapid gas-side fouling has been a problem in some units Dryout on the steam-side near the top of the exchanger has also been a problem in a few units Flue gas from single stage cyclones contain enough large particles to keep the small particles scrubbed off the tubes at gas velocities of about 100 ft/s With two-stage cyclones, about 200 ft/s is required too keep tubes clean Several FCC units have two-stage cyclones and flue gas coolers that operate at about 100 ft/s Flue gas cooler duty falls at a rate of about 30% per shift This fouling can be controlled by injecting walnut shells into the cooler twice a shift The shells scrub the fine solids off the tubes before burning to extinction Without fouling control, these coolers quickly become about half plugged and remain in that condition until mechanically cleaned Steam side dryout problems in a few units have been associated with poor hydraulic design Figure 300-19 illustrates the configuration designed to keep all steam-side components water wetted Fig 300-19 FCC Flue Gas Cooler December 1989 300-24 Chevron Corporation Heat Exchanger and Cooling Tower Manual 300 Service Considerations The donut baffle near the top of the cooler is located and sized so that inertia of the liquid flowing up through the donut hole is sufficient to impact on the top tubesheet The peripheral weir encourages liquid hold-up above the donut baffle The high velocity jet over the weir keeps the outer annular region well mixed (a vent is not required) Tube ferrule ends are located so that the high heat flux zone just downstream of the ferrules is in a well-wetted region These units have been designed to operate with flue gas temperature up to 1400°F Engineering Analysis Division of ETD can assist in developing specific designs Chevron Corporation 300-25 December 1989 ... Exchanger and Cooling Tower Manual 300 Service Considerations Fig 300-10 Typical Vertical Thermosiphon Reboilers Chevron Corporation 300-13 December 1989 300 Service Considerations Heat Exchanger and...300 Service Considerations Heat Exchanger and Cooling Tower Manual 310 Treated Cooling Water Heat exchangers in treated cooling water service should be designed and... cooling water systems without corrosion inhibitors Chevron Corporation 300-3 December 1989 300 Service Considerations Heat Exchanger and Cooling Tower Manual 320 Untreated Sea Water Heat exchangers