IPE-TM-400 Heat Exchangers
Design and Specification of Heat Exchangers
IPE-TM-400-09
1. Table of Contents
2. Purpose
This procedure provides Inflection Point Engineering practice and guidelines for the design and specification of shell and tube and hairpin type exchangers.
3. General
Cross reference other documents on heat exchangers as necessary. The manual of the Tubular Exchanger Manufacturers Association (TEMA), Eighth Edition, 1999 and the Engineering Data Book of the Gas Processors Suppliers Association (GPSA), Volume 1, Section 9, contain useful general information on heat exchangers.
Reference Procedure for Inflection Point Engineering practice and guidelines for reboilers and steam generators.
4. Heat Transfer Theory
The theory of heat transfer is presented as a series of equations, which are used in engineering design to specify heat exchangers. Condensing vapors in multicomponent systems are covered by a combination of the equations in Sections 4.2 and 4.3.
4.1 Fundamental Equation for Convective Heat Transfer in a Heat Exchanger
Q = UATlm
| Where Q = Heat transferred, or duty of the exchanger, Btu/h |
|---|
| U = Overall heat transfer coefficient, Btu/h-ft²-F |
| A = Outside heat transfer surface, ft² |
| Tlm = Corrected log mean temperature difference, (°F) |
4.2 Sensible Heat
Use this equation to determine the sensible heat, from a fluid in the vapor or liquid phase, transferred from one side of the exchanger:
Q = WCP T
| Where W = fluid flow rate, lb/h |
|---|
| T = fluid temperature change, °F |
| Cp = fluid specific heat, Btu/lb-°F |
4.3 Latent Heat
Use this equation to determine the latent heat transferred from a condensing vapor or boiling liquid on one side of the exchanger:
Q = W H
where H = latent heat, Btu/lb
4.4 Overall Resistance
Heat transfer resistances are in English units of h-ft²-°F/Btu.
a. Equation
where R = overall resistance to heat transfer
rfs = film resistance of shell side fluid based on outside surface of tubes
rot = fouling resistance of shell side fluid on outside surface of tubes
rtw = resistance of tube wall referred to outside surface of tubes, including extended surface if present
rft = film resistance of tube side fluid based on inside surface of tubes
rit = fouling resistance of tube side fluid on inside surface of tubes
Ao = ratio of outside to inside surface area of tubes
Ai
b. Fluid Film Resistance
Determine the fluid film resistances, rfs and rft, from correlations involving the tube diameters, the fluid flow rate and the viscosity, thermal conductivity, and specific heat of the fluid. See Table 1 for some typical film resistances.
c. Fouling Resistance
The fouling resistance is the resistance to heat transfer across a surface due to deposits on the surface which have accumulated during service. Inflection Point Engineering, in general, uses TEMA fouling resistances. In TEMA and throughout this document, fouling resistances are in English units of h-ft²-°F/Btu.
An excellent discussion of fouling mechanisms in heat exchangers is given in TEMA, Section 10, pages 283 to 285. Values for the fouling resistances, rot and rit, may be known from previous operating experience or estimated from tables of typical fouling resistances found on pages 286 to 290 of TEMA.
Fouling resistance on the air side of air cooled coolers and condensers, while for the most part negligible, may be very high in areas where the air is contaminated with chemical vapors and dust. Fouling resistance of fresh water depends on the quality of the water and the treating methods used. The resistance varies from a low of 0.001 for treated fresh water to 0.01 for some polluted canal or river waters. Sea water resistance is usually very low, ranging from 0.001 to 0.0025. Fouling resistance of process fluids varies from about 0.001 for most clean oils and vapors to a high of 0.005 for heavy untreated fuel oils. Consider contaminants such as air, sulfur, and nitrogen, and components such as olefins and diolefins when deciding on a reasonable resistance. Keep in mind that a total resistance of 0.0045 applied to an exchanger with a high clean transfer rate of 100 (Btu/h-ft²-°F) reduces it to 69, but when applied to one with a low rate of 25 only reduces the overall coefficient to 22.5, as shown below.
The overall equation may be written in the following form:
If the overall clean coefficients on a gas oil cooler using brackish water are 100 and 25 Btu/h-ft²-°F, find the corresponding overall (dirty) coefficients.
| rot = 0.0025 | |
|---|---|
| (Ao/Ai)rit = 0.0020 | |
| Uc = 100 1/Uc = 0.01 Uc = 25 1/Uc = 0.04 | Uc = 100 1/Uc = 0.01 Uc = 25 1/Uc = 0.04 |
d. Tube Wall Resistance
Calculate the resistance of the tube wall for a bare tube, rtw, using the following equation:
where Do - tube OD, inches
twt = tube wall thickness, inches
km = thermal conductivity of tube metal, Btu/h-ft²-°F
4.5 Logarithmic Mean Temperature Difference
a. LMTD Calculation
Use this equation to find the log mean temperature difference (LMTD) for either true counterflow or co-current flow exchangers (only double pipe and multi-tube exchangers and exchangers with an equal number of passes on each side fall into this category):
where GTTD = the greater terminal temperature difference
LTTD = the lesser terminal temperature difference
Heat transferred - MMBtu/h
For exchangers with two or more tube passes and one shell pass, true counterflow is not experienced. Apply a correction factor to the calculated counterflow LMTD.
b. LMTD Correction Factor
Charts for determining LMTD correction factors for several types of shell and tube exchangers are given on pages 133-146 of TEMA. These charts are based on the following assumptions:
- The overall heat transfer coefficient is constant.
- Each pass has the same amount of heat transfer surface.
- The mass flow rate of each fluid is constant.
- The specific heat of each fluid is constant.
- There are no phase changes in any part of the exchanger.
- Heat losses are negligible.
- Each fluid stream may be characterized by a single temperature at any cross section in the exchanger.
It is not advisable to design an exchanger with a LMTD correction factor less than 0.80, both because it is not economically feasible and because in practice some of these assumptions are no longer valid at the lower correction factors. Increase the number of shells until the LMTD correction factor exceeds 0.80.
c. Weighted LMTD
A straight-line temperature-enthalpy relationship for both fluids was assumed when calculating a LMTD as shown previously. This is not always true, especially where there is condensation or vaporization involved. In this case calculate a weighted LMTD as shown below.
Use the following procedure to calculate weighted LMTD for an exchanger where phase changes are taking place. Start with the enthalpy profile, which is the enthalpy change or heat transferred versus temperature (shown below for an exchanger where a phase change is taking place on both the tube and shell sides). Split the profile into three zones as shown, determined by the dew points, the heat transferred, and LMTD for each zone as determined from the profile. Determine the weighted LMTD with the following equation:
Q1 + Q2 + Q3
| LMTD weighted = |
|---|
Temperature F
Heat transferred - MMBtu/h
Note that the vertical tie lines pass through the inflection point or dew point to simulate graphical integration of the area between the curves. If there is only a dewpoint on one side of the exchanger, such as in a condenser, and if the condensing curve is nearly linear, then there will be only be two zones. If the single condensing curve is very nonlinear, like the curves in the sketch above, arbitrarily choose a second tie line to split the curve into 3 zones.
5. General Considerations
Consider the following points when establishing exchanger arrangements during a process design:
5.1 Heat Utilization
The Design Engineer considers how to utilize the heat in a process stream requiring cooling. It may be possible to return heat to the process unit, to export heat to another process unit, or to use the heat for utilities (e.g., to generate steam or to heat up hot oil or boiler feed water).
It may also be possible to adjust process conditions to facilitate heat utilization. Use Pinch Technology to determine the optimum heat exchanger network for a given situation. For a description of the use of Pinch Technology and minimum energy requirements, refer see Procedure
5.2 Effect on Process
For any exchanger arrangement selected, consider the effects of:
- Contamination or a hazard occurring due to an internal or external exchanger leak
- Turndown, start-up and shutdown conditions
- Process conditions that have to be altered, e.g., for SOR to EOR or for changing recycle ratios
- For heat exportation, the shutdown of the unit receiving exported heat or the unit supplying exported heat
- Exchangers over- or under-performing
- Bottoms versus feed applications in fractionation trains with two or more shells in series
Examine and limit the number of shells in series to a maximum of four, since vaporizing a percentage of feed greater than the percentage of overhead product in the feed may be of minimal value because of possible extra reflux requirements. Also check the minimum vapor/liquid ratios in the stripping sections of certain processes, such as Hydrotreating.
- A column bottoms feeding a subsequent column
Removal of heat from the bottoms of the first column may be a poor choice unless it is required to reduce the amount of heat in the feed to the second column.
5.3 Specific Considerations for Heavy Oil Units
If the feed condition is two phase flow to the fired heater at the lowest temperature, and if more than one heater pass is required, special arrangements are necessary to ensure good distribution of both phases through each heater pass.
The design of the heat exchanger network for a heavy oil unit involves factors which are specific to the process and factors which are general. The following considerations are general in nature:
a. Combined Feed Heater
Specify a combined feed heater with one bank of exchangers per heater pass. Alternately, provide separate gas and liquid exchangers. Each heater pass then controls liquid flow. The combined feed heater, compared to the alternatives outlined below, simplifies start-up, shutdown, and purging. High vaporization situations generally require the combined feed heater, although percentage vaporization is less important at very high pressure.
b. Alternatives to Combined Feed Heater
Further alternatives to providing a combined feed heater include sending liquid to the heater and gas to the heat exchanger; or gas to the heater and liquid to the heat exchanger. The choice of which stream to pass through the heater depends on percent vaporization of the combined feed, the thermal stability of streams, the fouling tendency of streams, and start-up and shutdown considerations. In the first case, gas is exchanged against the hottest effluent. In the second case, liquid is exchanged against the hottest effluent. This allows the lowest heater outlet temperature since the other stream is at the maximum outlet temperature attainable by heat exchange.
6. Choice of Tube or Shell Side
The choice of tube or shell side depends on the process fluid. Different conditions may cause a conflict of choice in certain situations. Exercise good engineering judgment and consult the Process Specialist for a particular process.
6.1 Advantages of Tube Side for a Process Fluid, Heating, or Cooling Medium
a. Fouling Fluids
Put fouling fluids on the tube side for easier cleaning. The availability of chemical cleaning methods may make this choice a secondary consideration. Because of potential fouling problems, as a Inflection Point Engineering and industry practice, cooling water is usually put on the tube side of water cooled exchangers.
b. Suspended Solids
If suspended solids are present, use the tubeside to keep the solids in suspension and minimize cleaning. An example of this is cycle oil containing catalyst fines. Inflection Point Engineering recommends a velocity of 3.75 ft/s minimum and 7.0 ft/s maximum. For more information see Inflection Point Engineering Standard Specification 4-11.
c. High Operating or Design Temperature
It is usually more economical to put the process fluid with the highest temperature on the tube side.
d. High Operating or Design Pressure
It is usually more economical to put the process fluid with the highest pressure on the tube side. Only the channel, channel cover, and tube bundle then need to be designed for the higher pressure. High pressure internal to the tube minimizes tube thickness, facilitating tube closure into the tube sheet. Refer also to Sections 6.2.b and 6.2.c.
e. Corrosive Fluid
If a process fluid is corrosive and requires alloy materials for construction, it is often more economical to put the process fluid on the tube side.
6.2 Advantages of Shell Side for a Process Fluid, Heating, or Cooling Medium
a. Viscous Fluids
Put fluids having a viscosity greater than 2 centistokes on the shell side to directionally reduce the surface area requirement due to the creation of turbulent flow. The higher the viscosity, the more benefit obtained from having the viscous fluid on the shell side.
b. High Differential Pressure
Generally, when the design pressure differential between tube and shell side is 1000 psi or less, put the highest pressure fluid on the shell side. For higher design pressure differentials, examine each case individually; consult the Process Specialist for a particular process where necessary. The design pressure of the lower pressure side of an exchanger may be dictated by the ten-thirteenths rule.
c. High Operating or Design Pressure
The advantage of the shell side for the higher pressure process fluid is that, on tube failure, the tube tends to collapse and reduce the open area rather than blow out. The pressure surge accompanying a tube failure is better handled on the exchanger channel end rather than the shell end. When calculating the relieving loads for a tube failure case, Inflection Point Engineering does not assume that the shell side is the high pressure side.
d. Flow Rates
When both process fluids are single phase and the ratio of flow rates exceeds a factor of 2, the most economical exchanger design is with the largest flow on the shell side.
7. Types of Shell and Tube Exchangers
7.1 U-Tubes
The most common and cheapest form of shell and tube exchangers are exchangers with U-tube bundles. Specify these for certain process services such as hydrogen service. U-tube exchangers are good for most services (rft 0.002), but some fluids with a high fouling tendency, such as cooling water, may be inappropriate to put on the tube side. Some problems may develop with very high temperature profiles in small shells where undue stress develops in the hair pin bends.
7.2 Floating Head
Shell and tube exchangers with floating heads are the ultimate in exchangers and can handle just about every type service. They are expensive, but the tube side is easily cleaned by rodding. Design U-tube bundles and floating head units with anywhere from 2 to 6 passes on the tube side, which allows flexibility in choosing velocities and pressure drop on both sides of the exchanger. When calculating the MTD from the inlet and outlet streams, correct for the fact that these are not true countercurrent exchangers.
7.3 Fixed Tubesheet
Fixed tubesheet exchangers have limited refinery usage. They are low cost, and the shell side must be cleaned chemically. Because the tube bundle is not removable, inspection of the shell side is very difficult. Fixed tubesheet exchangers are normally used as vertical reboilers in services with clean fluid on the shell side. At normal temperatures, use an expansion joint in the shell to prevent pulling tubes out of the tubesheet.
7.4 Tubes
To use shell and tube exchangers with single pass tubes and shell, employ a floating head with a bellows between the floating head and the shell bonnet. (A disadvantage of single pass tubes is that a leak in the bellows may result in cross-leakage of streams.) Sometimes a packing gland is used instead of a bellows to take up the differential expansion between the tubes and the shell in non-hydrocarbon service. Single pass tubes have the advantage of utilizing low pressure drop, and are true countercurrent exchangers that do not have to have the MTD corrected as multipass tubeside units do.
7.5 Two Pass Shells
Two pass shells are sometimes used to reduce cost by reducing the number of shells required. In addition to low cost, the advantages of two pass shells are true countercurrent operation, higher velocity in a given shell size, and relatively low pressure drop on the shell side.
Accomplish the two passes with a horizontal baffle in the bundle, sealed by various means with the shell. This seal is the one weak point of this type of exchanger because heat leakage may occur at the horizontal baffle. The seal may leak due to poor installation, too high a temperature gradient (causing warping of the shell), or too high a pressure drop.
Take the last two items into account during design by keeping the temperature change per shell to less than 150°F and the pressure drop per shell below about 2 psi. Inflection Point Engineering does not normally recommend this type of exchanger unless the Owner is aware and sensitive to the maintenance requirements.
7.6 Double Pipe
Use double pipe exchangers in services where flow rates and duties are small and the cost is lower than a comparable shell and tube unit. Since double pipe exchangers may be fabricated from standard stock sections, they are obtainable on much shorter deliveries than the shell and tube types. They are true countercurrent exchangers and may come with extended surface, usually as longitudinal fins.
For dissimilar fluids such as hydrocarbon and water, put the low transfer rate fluid on the shell side to take advantage of the extended surface. Use bare tubes for similar fluids such as water/water or liquid hydrocarbon on both sides. Do not put fluids which have a fouling tendency on the shell side. Reference Section 10.3.
7.7 Multi-Tube
Multi-tube exchangers are true counterflow exchangers similar to double pipe type. Use multi-tube exchangers for intermediate duties where more surface and a temperature cross are desired. Reference Section 10.3.
8. Other Types of Heat Exchangers
For specific applications it may be more economic to use other types of heat exchangers than typical tubular types of exchangers. Review the appropriateness of the service for an alternative exchanger type in consultation with a Heat Exchanger Specialist. Typically, the fouling factors described for tubular exchangers do not apply to plate type exchangers. Some other types of heat exchangers are described below.
8.1 Plate and Frame Exchangers
Plate and frame type heat exchangers are typically used in non-hydrocarbon applications with low temperature (350F max.) and pressure (300 psig max.). The advantage of this design is that the higher turbulence creates higher heat transfer coefficients than tubular exchangers. This results in a more compact design and is generally less expensive. Also, the plates are less expensive to fabricate than tubular exchangers when dealing with high alloy materials such as stainless steels or titanium. Again this reduces the cost of this type of exchanger compared to tubular exchangers. However, there is a significant amount of gasketing required in these units which makes it unsuitable for flammable applications as well as high pressure, high temperature or hydrogen services. These exchangers have been used in water applications among others.
8.2 Welded Plate Exchangers
By welding the edges of the plates, the problem of external leakage from plate type heat exchangers can be solved. There are two types of welded plate heat exchangers. The pressed plate type is similar in size to a plate and frame type. The flow can be countercurrent or crossflow in these designs. Bolting heavy cover plates around the outside of the plates is often used to contain the pressure inside the plate bundle. These exchangers are suitable for use in many applications that are very clean as only some types of these exchangers can be opened for cleaning. For other types, only chemical cleaning is possible. These exchangers can be used for fractionator condensers and reboilers; however, Inflection Point Engineering only occasionally specifies this type of exchanger.
8.3 Packinox Welded Plate Exchangers
Plates are formed by explosive methods, which allow for much larger plate bundles. This is proprietary technology for Packinox. The plate bundle is placed in a pressure vessel pressurized with the recycle gas. Therefore, the bundle only has to hold differential pressure not full pressure. Applications are still limited to clean services. Use Packinox exchangers in Platformer, Aromatic units, Pacol, hydrotreating units with straight-run feed, and other applications for combined feed-effluent services. A strainer is normally required on the feed side.
8.4 Spiral Exchangers
Spiral exchangers are a variation of plate type exchangers except that the plate is formed into a continuous spiral path. This curved flow path creates turbulence that scrubs the surface of the plate. Spiral exchangers are used in slurry type services, such as FCC Main Column Bottoms. They can also be used as internal condensers in the top of fractionators. The pressure and temperature limits are about the same as for plate and frame exchangers.
8.5 Brazed Aluminum Exchangers
Brazed aluminum exchangers are excellent in refrigerant/cold box type applications. lly, the temperature limits for the process is <150F. These exchangers are special in that a single refrigerant can be used to exchange against up to a dozen other process streams in a single exchanger. Other multiple stream layouts are possible. Use only in very clean services. Also, corrosion of aluminum
is a concern in selecting acceptable applications. Mercury removal is required upstream for this reason. Brazed aluminum exchangers have been used in Oleflex units.
9. Exchanger Codes and Standards
9.1 ASME Section VIII
Design all exchangers in process service to the ASME Section VIII Code. This requirement is a part of TEMA.
9.2 ASME Section I
Design all exchangers in steam generator service to the ASME Section I Code. In some instances, where no direct firing is involved, design the exchangers according to the ASME Section VIII Code if requested in writing by the Owner.
9.3 TEMA
Design all tubular heat exchangers to TEMA and Inflection Point Engineering Standard Specifications 4-11 and 4-12.
a. TEMA Class R
lly, design all exchangers to TEMA Class R, Refinery Standards.
b. TEMA Class C
In some cases, use TEMA Class C for Commercial or General Applications if requested in writing by the Owner. Class C Standards permit the use of thinner tube sheets and other cost saving features, and may be acceptable for package units in refineries. Table 3 summarizes the major differences between Class C and Class R.
c. Type Designation
The TEMA type designation consists of a three letter code which designates the following:
| Letter No. | Letters Used | Designates |
|---|---|---|
| First Second Third | A, B, C, D, N E, F, G, H, J, K, X L, M, N, P, S, T, U, W | Front End Stationary Head Types Shell Types Rear End Head Types |
d. Common Types Used
Reference Equipment Design Manual DM-EQUIP-2073-401, “Tubular Heat Exchanger”.
Type designation AES (or T) is widely used in the refining and petrochemical industry because it allows easy access for inspection and cleaning of the tube side.
Use BEU when steam or boiler feedwater is on the tube side. B costs less than A, U costs less than S, and the tubes will seldom need cleaning for this service. Also use type designation BEU for hydrogen services since flanged joints are minimized.
Use type designation AEM (or N) for vertical reboilers since the fixed tubesheet costs less and the process (tube) side is easily cleaned. This may require a shell side expansion joint for hot oil or steam.
Use front end C type head for acid service or superheated steam. Use D type head for special high pressure design services above 1000 psig.
Only use types G, H or J in condensers and reboilers where the system requires a low pressure drop. Shell type F is generally discouraged, since it is difficult to maintain a good seal at the long internal baffle. Use shell type K for kettle reboilers.
Inflection Point Engineering seldom uses rear end heads P or W because these are used for non-hydrocarbon services. Rear end T type is similar to S, but S costs less because T requires a larger shell ID to allow a pull through feature.
9.4 Other Standards
Design Plate and Frame heat exchangers to API 662 / ISO 15547 Part 1 and use Project Specification 420. Welded plate exchangers use portions of API 662 / ISO 15547 Part 1 and are specified with Project Specification 420.
Design Spiral Plate heat exchangers to API 664 / ISO 12212 and use Project Specification 420.
Design brazed aluminum heat exchangers to the API 662 / ISO 15547 Part 2 and use Project Specification 420.
Design steam surface condensers to the standards of the HEI (Heat Exchanger Institute).
Process Exchangers
Consider these guidelines in the design and specification of process-to-process shell and tube exchangers:
10.1 Allowable Pressure Drop
a. General
For process-to-process shell and tube exchangers, use the following general guidelines for allowable pressure drop (Reference Table 2), as well as good engineering judgment and input from Process Specialists or project managers. Consult the Process Specialist to determine if any exchanger services in a specific unit have special allowable pressure drop requirements (allowable pressure drops are from the exchanger inlet nozzle to the exchanger outlet nozzle).
Note that the exchanger vendor will not necessarily use all the specified allowable pressure drop, but frequently uses only a portion of the allowable pressure drop in his design, which is not usually problematic. However, there may be exceptions where hydraulics are based upon the vendor using a specific pressure drop. In these cases add a special note to project specifications, to the effect that all or a minimum part of the allowable pressure drop must be used.
b. Limited Pressure Drop Available
Normal pressure drop for process fluid exchangers ranges from about 5 to 25 psi, depending on availability of pressure and properties of the system. Provide a minimum 5 psi per shell on each side if pressure drop is not available to meet the requirements in Table 2.
c. Manifolds Pressure Drop
The exchanger supplier does not supply manifolds. Include manifold pressure drop in the piping pressure drop when doing the hydraulics for a unit.
10.2 Approach Temperatures
In the case of a process stream being cooled, the approach temperature is the difference between the outlet temperature of the fluid and the inlet temperature of the heating or cooling medium. Where both streams are process streams, it is the smaller terminal temperature difference.
Compare the economics of incremental surface with fuel and cooling costs to arrive at the right approach temperature, taking into account the corrected LMTD.
10.3 Hair Pin Type Exchangers
Review the Equipment Section, 5.4, of the BEDQ, to check owner preference concerning the specification of hair pin type exchangers.
Hairpin type exchangers (double pipe, or multi-tube) are true countercurrent exchangers designed for services requiring less than 1100 square feet of surface area. Specify a temperature without using multiple shells, and depending on the surface area requirements as shown below. The Exchanger Specialist specifies exchanger services requiring less than 100 square feet surface as multitube hairpin type but add a note allowing the use of a double pipe, hair pin type. Specify services between 100 and 500 square feet as multi-tube hair pin type. Specify services between 500 and 1100 square feet as multi-tube hair pin type or shell and tube exchangers.
10.4 Design Conditions
Procedure describes the methods for establishing design pressure and temperature for heat exchangers.
10.5 Overall Heat Transfer Coefficient
Contact a heat exchanger specialist to obtain a value for the Overall Heat Transfer Coefficients (OHTC) for preliminary sizing of exchangers. OHTCs are in units of Btu/h-ft²-°F.
a. General
Most liquid-liquid and mixed-phase shell and tube heat exchangers have OHTCs between 50 and 70. Vertical single pass combined feed exchangers in processes with high hydrogen contents, such as Platforming, have OHTCs of about 40 to 45. Low pressure drop units, such as Pacol or Oleflex, using vertical exchangers have lower transfer rates. Gas-gas exchangers with low thermal conductivity gases such as air have OHTCs as low as 15.
b. Double Pipe
Double pipe exchangers with extended surface have transfer rates of about 1/3 of a shell and tube unit, based on extended surface.
10.6 Preliminary Sizing of Exchangers
When the surface area of the exchanger has been established using the OHTC, establish the exchanger size using the PC program Exchanger Sizing. Reference Equipment Design Manual .
10.7 Preparation of Project Specification 401
Documentation and guidance on how to prepare Project Specification 401 is contained in Equipment Design Manual DM-EQUIP-2073-401, “Tubular Heat Exchanger”.
This specification is prepared using the following tools:
T-401-03 Shell and Tube Exchanger Extra Notes.xls
10.8 Strength Welded Tubes
Some Inflection Point Engineering processes require strength welded tubes in certain heat exchanger services. Reference Procedure for lists of pertinent processes and details of how this is specified.
10.9 Graded Shell Materials of Construction
It is possible in some exchangers, for example Platforming Vertical Combined Feed exchangers, to use multiple materials of construction and thicknesses in the shell to reduce the cost of the exchanger. The stationary head and its cover, shell, baffles, shell cover and end flanges may be graded based the following hydrogen partial pressure and break point operating temperatures criteria:
Over the Tbreakpoint use 1¼ Cr - ½ Mo or 1 Cr - ½ Mo, and
Less than Tbreakpoint use Killed Carbon Steel.
For hydrogen partial pressure 200 psia, Tbreakpoint = 525°F.
For hydrogen partial pressure > 200 psia, Tbreakpoint = 475F.
Likewise, the cold end design temperature for graded shells is dependent on the hydrogen partial pressure:
For hydrogen partial pressure 200 psia, Tcold end design = 550F.
For hydrogen partial pressure > 200 psia, Tcold end design = 500F.
10.10 Governing Case Evaluation
It is necessary to evaluate all the various operating cases to determine the design case for the exchanger. The design case requires that the thermally and hydraulically governing operating cases be identified. The thermally governing case is the case that requires the greatest heat transfer surface area. This often is not the case with the largest duty. Similarly, the hydraulically governing case is the case that will cause the largest pressure drop. It is often not the case with the largest mass flow rate, as pressure drop also depends on density, viscosity, and the vapor mass fraction of the stream.
The hydraulic calculations will determine the hydraulically limiting case. The thermally governing case can be determined by using the exchanger sizing calculations for the various cases.
10.11 Reboilers
The use of reboilers, especially stabbed-in or thermosyphon types require special considerations. Hydraulics are very important and the elevations of the column and the heat exchanger are critical. Also, in low pressure systems, the variation in pressure within the reboiler can cause significant differences in the boiling point and vapor density of the process materials. It is necessary in these cases to provide isobaric properties at multiple pressures to allow for the design of this equipment. Refer to , and for additional guidance.
10.12 Isobaric Properties
For heat exchangers that have a change of phase, it is necessary to provide isobaric properties at three pressure levels that bracket the terminal conditions of the heat exchanger. This is not needed for steam.
11. Water Cooled Exchangers
Consider these guidelines in the design and specification of water cooled shell and tube exchangers:
11.1 High Process Inlet Temperature
To avoid excessive scaling on the water side, water cooled exchangers are generally not recommended when the process side inlet temperature is greater than the numbers shown below. Exceptions to the general guideline include when the process duty is very small and extra surface area has been specified to account for upset, intermittent service, or shutdown considerations.
Fresh Water - 400F (205C) maximum
Sea Water - 300F (150C) maximum
11.2 Process Rundown Temperatures
BEDQ, Section 7.1, Miscellaneous, gives Process Rundown temperatures for a particular project. For further information reference Procedure
11.3 Tube Side
Cooling water is usually put through the tube side. Reference Section 6.1.a.
11.4 Allowable Pressure Drop
Use the following guidelines for allowable pressure drop for water cooled shell and tube exchangers.
| Allowable Pressure Drop | Allowable Pressure Drop | Allowable Pressure Drop | Allowable Pressure Drop | |
|---|---|---|---|---|
| Tube Side | Tube Side | Shell Side | Shell Side | |
| No. of Shells | psi | kg/cm² | psi | kg/cm² |
| One Two | 10 15 | 0.7 1.0 | 5 10 | 0.35 0.7 |
Experience shows that the above pressure drops are approximately what is required to meet the Inflection Point Engineering criteria of a minimum cooling water velocity of 3.0 ft/s. Specify this velocity limitation in turn to minimize cooling water fouling and to effectively distribute the inhibitor chemicals used for treating cooling tower water. A lower pressure drop may be required where the system pressure is very low or when the exchangers are at high elevations. In this case, increase the water side fouling factor accordingly.
11.5 Minimum Approach Temperature
The minimum cold end approach is 7F. The water outlet temperature should not exceed 120F for fresh water, 115F for sea or brackish water, and 175F for tempered water in a closed loop system. The minimum approach temperature at the hot end should be10F.
11.6 Temperature Cross
When the cooling water circulation rate is substantially reduced, consider a temperature cross, with two shells in series, for shell and tube exchangers. This generally applies to exchangers with duties higher than 4.0 MMBtu/h and cooling water circulation rates greater than 500 gpm (250,000 lb/h). Example 1 shows how to optimize the outlet temperature of a water cooler.
Representing a temperature cross for shell and tube exchangers always implies the use of multiple shells in a series. Limit the number of shells to a maximum of two. Minimize the target LMTD correction factor "F" to 0.80. Consult the TEMA Manual for additional information on LMTD correction factors
11.7 Cooling Water Nozzle and Line Sizes
Use the following criteria to determine cooling water exchanger inlet/outlet nozzle and line sizes for different flow rates of cooling water:
| Cooling Water Flow Rate | Cooling Water Flow Rate | Criteria |
|---|---|---|
| (gpm) | up to (lb/h) | |
| 0-700 701-2800 2801-7000 7001+ | 347,520 1,390,060 3,475,150 3,475,150+ | Max. P/100' = 1.3 psi Max. velocity = 500 ft/min Max. velocity = 600 ft/min Max. velocity = 700 ft/min |
Application of these criteria results in the following line sizes for the different cooling water flow rates:
| Flow Rate (gpm) | Flow Rate up to (lb/h) | Line Size (inches) | Schedule No. | Wall Thickness (inches) |
|---|---|---|---|---|
| 0-5 6-17 18-34 35-115 116-235 236-700 701-1300 1301-2050 2051-3500 3501-4300 | 2,482 8,440 16,880 57,092 116,666 347,515 645,385 1,017,723 1,737,575 2,134,735 | 1 1½ 2 3 4 6 8 10 12 14 | 80 80 80 40 40 40 40 40 - - | - - - - - - - - 0.375 0.375 |
11.8 Design Conditions
Reference Section 10.4: Procedure describes the practice for establishing the design temperature for the cooling water side of the exchanger.
11.9 Hair Pin Type Exchangers
Reference Section 10.3. When the option of shell and tube or hair pin types are shown on the project specification, the inlet and outlet cooling water line sizes shall be consistent with the higher cooling water flow rate required for shell and tube type.
11.10 Metallurgy
The metallurgy of the water side of cooling water exchangers is typically carbon steel for treated cooling water. Frequently, though, the metallurgy is based upon the Owner's experience with his existing cooling water system. Request the Owner's preference for metallurgy in the Utility Information Section of the BEDQ. The Owner's preference may be overridden based upon process side metallurgy requirements. Refer to the Metallurgy Review Diagram for any special metallurgy requirements set by Inflection Point Engineering's Metallurgist.
11.11 Valves in Cooling Water Lines
As a practice Inflection Point Engineering provides a valve on the cooling water inlet line. Specify globe valves on the P&ID for throttling cooling water flow when the line size is NPS 4 or smaller; specify gate valves for line sizes NPS 6 and larger. If the Owner requests that a valve be added to the outlet line, add a thermal relief valve between the exchanger outlet nozzle and the outlet valve.
11.12 Preliminary Sizing of Exchangers
Reference Section 10.6: Process specific guidelines for each service provide typical OHTC values.
11.13 Preparation of Project Specification 401
a. Project Specifications
Reference Section 10.7: Prepare project specifications for water cooled exchangers using the mainframe hydraulic program which allows the user to specify the inlet and outlet temperature of the utility side of every exchanger.
b. Cooling Water Properties
The contractor/exchange vendor does not usually require the properties of the cooling water. Vendors have all the required properties for cooling water as part of their computer design programs. Provide only the molecular weight and the cooling water mass flow rate when indicating a cooling water stream on the exchanger project specification. The molecular weight is provided in the event the title (cooling water) is not included.
12. Computer Tools
The tools listed below are available for the purposes described.
| Tool | Purpose |
|---|---|
| Horizontal Thermosiphon Reboiler Hydraulic Calculations | |
| Calculate cooling water circulation rate, water properties and inlet/outlet line sizes. | |
| Heat Exchanger Tube Thickness Calculations | |
| VCFE Distributor Calculations | |
| Vertical Thermosiphon Reboiler Hydraulic Calculations |
Table 1 - Typical Film Resistances
Heating Medium | Film Resistance (h-ft²-°F/Btu) |
|---|---|
| Liquid Water Boiling Water Condensing Steam Liquid Light Hydrocarbon (Propane-Pentane) Boiling Light Hydrocarbon (Propane-Pentane) Condensing Light Hydrocarbon (Propane-Pentane) Liquid Kerosene Boiling Kerosene Condensing Kerosene Liquid Crude Oil Liquid Bunker 'C' Fuel Oil Natural Gas at 50 psig Natural Gas at 100 psig Natural Gas at 1000 psig Low Pressure Platforming Combined Feed or Reactor Products Moderate Pressure Unicracking Combined Feed or Reactor Products High Pressure Unicracking Combined Feed or Reactor Products | 0.0010 0.0008 0.0005 0.0030 0.0040 0.0060 0.0050 0.0080 0.0070 0.0100 0.0200 0.0180 0.0130 0.0050 0.0070 0.0040 0.0030 |
Table 2 - Allowable Pressure Drop Guidelines
| Allowable Pressure Drop | Allowable Pressure Drop | Allowable Pressure Drop | Allowable Pressure Drop | |
|---|---|---|---|---|
| Tube Side | Tube Side | Shell Side | Shell Side | |
| Service | psi | kg/cm² | psi | kg/cm² |
| General Service 1 Shell 2 Shells 3 Shells Additional Shells | 10 15 20 +5 | 0.7 1.0 1.4 +0.35 | 5 10 15 +5 | 0.35 0.7 1.0 +0.35 |
| Horizontal Combined Feed/Eff. 4-8 Shells in series <300 psig See Note (1) | 4 per shell | 0.28 per shell | 3 per shell | 0.21 per shell |
| Horizontal Combined Feed/Eff. 4-8 Shells in series >300 psig See Note (1) | 5 per shell | 0.35 per shell | 5 per shell | 0.35 per shell |
| Vertical Combined Feed/Eff. e.g. Platforming Packinox (Welded Plate) See Note (1) | 2.5 7.5* | 0.18 0.53* | 8 5** | 0.56 0.35** |
| Vacuum or Atmospheric | 10 | 0.7 | 0.5-1.0 | 0.035-0.07 |
Note (1): Consult the Process Specialist for a particular process for the current practice for each process.
* hot side - effluent
** cold side - combined feed
Table 3 - Major Differences Between TEMA Class R and TEMA Class C
| TEMA Section No. | TEMA Section No. | Class R | Class C |
|---|---|---|---|
| No. | Title | ||
| 1.1 | Scope of Standards | "Severe requirements for Petroleum Processing Applications" | "Moderate requirements for Commercial and General Applications" |
| 1.5 | Standard Corrosion Allowance | Carbon Steel - ⅛ inch | Carbon Steel - 1/16 inch |
| 3.13 | Min. Shell Thickness | Greater for R than for C in small sizes | Greater for R than for C in small sizes |
| 4.4 | Baffle Thickness | 1/16 inch greater for R than for C in small sizes | 1/16 inch greater for R than for C in small sizes |
| 4.7 | Tie Rod Diameter | 1/16 inch greater for R than for C in small sizes | 1/16 inch greater for R than for C in small sizes |
| 5.1 | Floating Head Cross-over Area | 1.3 times tube area of one pass minimum | 1.0 times tube area of one pass minimum |
| 5.3 | Floating Tubesheet Seal (not used in hydrocarbon service) | Design temp. 375°F max. Design press. 75-300 psig max. depends on diameter | Design press. 600 psig |
| 6.2 | Gasket Materials metal | Metal jacketed or solid metal | Composition material below 300 psig design press. |
| 6.5 | Gasket Joint Details | Requires confined gasketed joints | Allows confined or unconfined |
| 7.131 | Minimum Tubesheet Thickness | Tube OD minimum ¾ inch minimum | ¾ of tube OD for 1 inch and less; ⅞ inch for 1¼ inch OD tubes; 1 inch for 1½ inch OD tubes |
| 7.44 | Tube Hole Grooving | All tube holes shall have at least two grooves | Tube holes shall have at least two grooves for pressures >300 psig and/or temperatures >350°F |
| 7.511 | Tube-to-Tubesheet Joint | Expansion length smaller of 2 inch or tubesheet thickness minus ⅛ inch | Expansion length smaller of 2 tube diameters, 2 inch or tubesheet thickness minus ⅛ inch |
| 7.6 | Partition Grooves | Approximately 3/16 inch depth required | Approximately 3/16 inch depth required over 300 psi or other suitable means |
| 10.3 | Pipe Tap Connections | Minimum 6000 psi standard couplings or equivalent | Minimum 3000 psi standard couplings or equivalent |
| 11.1 | Minimum Bolt Size | ¾ inch | ½ inch |
Example 1 - Water Outlet Temperature for Coolers
- Process designs frequently require an outlet temperature of the hydrocarbon stream of 100F, while the maximum outlet temperature for cooling water is somewhat higher. Thus, if the higher water outlet temperature is permissible, a temperature cross results. Under some circumstances this temperature cross is quite satisfactory; under others it is not.
- A problem exists only when the total surface required is above that which is available in several double pipe sections, and below that where two shell and tube type units must be used from a consideration of physical size alone. In the former case, a condition of true counterflow exists which is not adversely effected by the temperature cross; in the later case the two shells required for size may handle the temperature cross.
- In most cases the surface required is such that it will fit nicely into one shell. Compare the additional equipment cost for two shells, with the annual additional water cost if only one shell is used. Obtain current cost information from a Cost Estimator or an Exchanger Specialist and the BEDQ. The following example shows a useful approach, illustrated by a Pentane Condenser:
Duty: 1.69 MMBtu/h Cooling Water Cost: $0.05/1000 gal
Process Inlet Temperature: 140°F Cooling Water Inlet Temperature: 90°F
Process Outlet Temperature: 100°F Cooling Water Outlet Temperature: 115°F
OHTC: 70 Btu/h-ft²-°F Heat Exchanger Cost: $20.00/ft²
| One Shell | Two Shells | |
|---|---|---|
| Cooling Water Temperatures | 90°F - 100°F | 90°F - 115°F |
| LMTD (Corrected) | 17.6 | 13.4 |
| Surface Area, ft² | 1,690,000 = 1370 17.6 x 70 | 1,690,000 = 1808 13.4 x 70 |
| Size of Shells, ft² | 1 x 1370 | 2 x 904 |
| Cost of Shells, $ | 27,430 | 36,160 |
| Differential Cost, $ | 8,730 | 8,730 |
| Cooling Water Flow Rate, gpm | 338 | 135 |
| Annual Cost 8000 h, $ | 8,112 | 3,245 |
| Differential Cost, $ | 4,867 | 4,867 |
On a simple payout basis, this takes 1.79 years to pay out. Since most Owners want to pay out incremental equipment in less than 2-3 years, the choice in this example shall probably be for two shells with a water outlet temperature of 115°F. If the payout policy and cooling water costs of a particular Owner are known, use them.
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