Heat Exchangers
Heat Exchangers in Oil & Gas
What Is a Heat Exchanger
A heat exchanger transfers thermal energy (heat) between two or more fluids at different temperatures without allowing those fluids to mix. One fluid (the “hot” side) gives up heat; the other (the “cold” side) absorbs it. The temperature difference between the two streams is the driving force for heat transfer.
Heat exchangers rank among the most critical and widely deployed equipment in oil and gas processing. They appear at virtually every stage of the hydrocarbon value chain: wellhead production separators and glycol dehydration units upstream, pipeline compressor stations midstream, and crude distillation columns, hydrotreaters, and reformers downstream in refining.
Selecting the right heat exchanger type depends on operating temperature and pressure, fluid properties (corrosive, fouling, viscous, or multiphase), required heat duty, available plot space, maintenance requirements, and total cost of ownership. The sections below walk through the principal heat exchanger types in petroleum and process service, their classification systems, governing standards, and key design factors.
Shell-and-Tube Heat Exchanger: Cross-Section Diagram
Types of Heat Exchangers
Shell and Tube Heat Exchangers
Shell and tube heat exchangers are the most widely used type in the oil and gas industry, accounting for roughly 60-70% of all exchangers installed in refineries and petrochemical plants. Their popularity comes from sturdy construction, a broad operating envelope, and well-established design practices under TEMA and ASME standards.
Construction
A shell and tube exchanger consists of a cylindrical shell (the outer pressure vessel) containing a bundle of tubes. One fluid flows through the tubes (the “tube side”), while the other flows over the outside of the tubes within the shell (the “shell side”). The main components are described below.
| Component | Description |
|---|---|
| Shell | Outer cylindrical vessel, typically carbon steel or alloy steel. Diameters range from 150 mm (6 in.) for small units to over 3,000 mm (120 in.) for large refinery exchangers. |
| Tube bundle | A set of parallel tubes, typically 19.05 mm (3/4 in.) or 25.4 mm (1 in.) OD, arranged in triangular or square pitch. Tube lengths run from 2.4 m (8 ft) to 7.3 m (24 ft). |
| Tube sheets | Thick plates drilled with a hole pattern; tubes are expanded or welded into the holes. Tube sheets separate the tube-side and shell-side fluids. |
| Baffles | Plates perpendicular to the tubes that support the tubes against vibration and sagging, and direct shell-side fluid in a zigzag path across the bundle to improve heat transfer. The single segmental baffle with a 25% cut is the most common type. |
| Nozzles | Flanged connections on the shell and heads for fluid entry and exit. |
| Front and rear heads | End closures that contain the tube-side fluid and direct it through one or more tube passes. |
TEMA Head Types
The TEMA (Tubular Exchanger Manufacturers Association) standard classifies shell-and-tube exchangers with a three-letter designation representing the front end stationary head, the shell type, and the rear end head type. The most common configurations in oil and gas service are listed below.
| TEMA Code | Configuration | Typical Use |
|---|---|---|
| BEM | Bonnet front, single-pass shell, fixed tube sheet rear | Simplest and most economical. Suited to low thermal expansion differentials and minimal shell-side fouling, since the tube bundle cannot be removed. |
| BEU | Bonnet front, single-pass shell, U-tube rear | U-shaped tubes eliminate one tube sheet, reducing cost and naturally accommodating thermal expansion. The inner tube rows are difficult to clean mechanically, and individual tubes cannot be replaced. |
| AES | Channel with removable cover front, single-pass shell, floating head rear | The floating head allows the bundle to be withdrawn for cleaning and inspection. The workhorse for refinery services with heavy fouling (crude preheat, overhead condensers). |
| AEW | Channel front, single-pass shell, externally sealed floating tube sheet | Used in high-pressure services where a conventional floating head would be impractical. |
| BKU | Bonnet front, kettle-type shell, U-tube rear | The kettle shell provides disengagement space above the bundle for vapor separation. Used in thermosiphon reboilers and vaporizers. |
Advantages of Shell and Tube Exchangers
- Handle the widest range of temperatures (cryogenic to 600+ degC) and pressures (vacuum to 300+ bar)
- Capable of very large heat duties (up to hundreds of MW)
- Proven technology with extensive design codes (TEMA, ASME VIII)
- Can handle fouling fluids, multiphase flows, and high-viscosity fluids
- Many material options (carbon steel, stainless, duplex, nickel alloys, titanium, zirconium)
- Easily customized with different baffle types, tube patterns, and pass configurations
Limitations
- Large footprint compared to plate exchangers for equivalent duty
- Lower heat transfer coefficients than plate types, especially on the shell side
- Fixed tube sheet designs cannot accommodate large differential thermal expansion
- Higher metal weight per unit of heat transfer area
Plate Heat Exchangers
Plate heat exchangers (PHEs) use a stack of thin, corrugated metal plates to create a series of narrow channels through which hot and cold fluids flow in alternating passages. The corrugation pattern (typically chevron or herringbone) promotes turbulence and high heat transfer coefficients even at low flow velocities.
Types of Plate Heat Exchangers
Three principal configurations exist, each with different pressure/temperature envelopes and maintenance characteristics.
| Type | Sealing Method | Pressure / Temperature Limits | Key Characteristics | Standard |
|---|---|---|---|---|
| Gasketed (GPHE) | Elastomeric gaskets (NBR, EPDM, Viton) in a bolted frame | ~25-30 bar / ~180-200 degC (gasket-limited) | Easy to disassemble for cleaning and inspection; plates can be added or removed to adjust capacity | API 662 Part 1 |
| Welded | Laser-welded plates, eliminating gaskets on one or both fluid sides | ~40+ bar / ~350 degC | More compact than shell and tube at equivalent duty; cannot be disassembled as easily as gasketed types | API 662 Part 2 |
| Brazed | Vacuum-brazed with copper or nickel filler | ~30 bar / ~200 degC | Extremely compact, suited to small duties (HVAC, hydraulic oil cooling, utility water); not typically used in fouling or corrosive O&G services | — |
Advantages of Plate Heat Exchangers
- Very high heat transfer coefficients (3-5 times higher than shell and tube)
- Compact footprint: 80-90% less volume than an equivalent shell and tube unit
- Close temperature approach (as low as 1 degC) for better heat recovery
- True counter-current flow yields high thermal efficiency
- Lower fouling tendency due to turbulent flow in narrow channels
- Lower fluid inventory, which matters for expensive or hazardous fluids
Limitations
- Pressure and temperature limits lower than shell and tube
- Gaskets may not be compatible with all process fluids
- Not suitable for high-fouling or particulate-laden streams without adequate filtration
- Plate cracking can occur with certain aggressive chemicals
Plate Heat Exchanger: Schematic Diagram
Air-Cooled (Fin-Fan) Heat Exchangers
Air-cooled heat exchangers (ACHEs), commonly called fin-fan coolers or air coolers, reject process heat directly to the atmosphere using ambient air as the cooling medium. They eliminate the need for cooling water, making them the standard choice in arid locations, offshore platforms, and any facility where water is scarce or expensive to treat.
Construction
An air-cooled heat exchanger consists of finned tube bundles, header boxes, axial fans, a plenum chamber, and a structural steel support frame. The table below breaks down each component.
| Component | Function and Sizing |
|---|---|
| Tube bundles | Finned tubes (typically aluminum fins on carbon steel or alloy tubes) arranged in horizontal banks. The fins multiply the air-side surface area by a factor of 15 to 25, compensating for the poor heat transfer coefficient of air. |
| Headers (header boxes) | Boxes at each end of the tube bundle that distribute and collect the process fluid. Plug-type headers handle high pressure; cover-plate headers allow easier access. |
| Fans | Large-diameter axial fans (typically 3.7 m to 5.5 m / 12 ft to 18 ft) driven by electric motors through V-belts or gear drives. Fan power typically accounts for 70-80% of total ACHE operating cost. |
| Plenum chamber | The enclosed space between the fan and the tube bundle that ensures uniform air distribution across the full face of the bundle. |
| Structure | A structural steel frame supporting the tube bundles at an elevated position (typically 3-5 m above grade) to allow unobstructed air intake underneath. |
Draft Configurations
In a forced draft arrangement, the fans sit below the tube bundle and push air upward through the finned tubes. Fan maintenance is easier because the motors are near ground level, and the structural support is more straightforward. The drawbacks are less uniform air distribution and the possibility of hot air recirculation.
In an induced draft arrangement, the fans sit above the tube bundle and pull air through. Air distribution is more uniform, hot air recirculation risk drops, and process control is tighter. The tradeoff is that fan motors and bearings operate in the hot exit air stream, and the supporting structure costs more. API 661 generally favors induced draft for most oil and gas services.
Applications
Air coolers appear throughout oil and gas facilities as overhead condensers on distillation columns (crude unit, vacuum unit, FCC), product coolers for naphtha, kerosene, diesel, and gas oil, compressor aftercoolers and interstage coolers, lube oil and hydraulic oil coolers, and gas plant condensers and coolers.
Air-Cooled Heat Exchanger: Diagram
Double Pipe (Hairpin) Heat Exchangers
Double pipe heat exchangers are the simplest form of heat exchanger: one pipe sits concentrically inside another. The inner pipe carries one fluid, while the annular space between the two pipes carries the other. When multiple straight sections are connected by U-bends (return bends), the assembly becomes a hairpin heat exchanger.
Construction and Operation
The inner pipe is typically 25 mm to 100 mm (1 in. to 4 in.) in diameter and carries the higher-pressure or more corrosive fluid. The outer pipe ranges from 50 mm to 200 mm (2 in. to 8 in.). True counter-current flow is achievable, which yields the maximum thermal efficiency possible for a given set of terminal temperatures. Longitudinal fins can be added to the outer surface of the inner pipe to boost heat transfer area — particularly useful when one fluid has a much lower film coefficient than the other.
Advantages
- Simplest and least expensive design for small heat duties
- True counter-current flow configuration
- Easy to clean and maintain
- Handles high pressures on both the inner pipe and annulus side
- Modular: multiple hairpin sections connect in series or parallel
- Well suited to high-temperature or high-pressure applications with small flow rates
Limitations
- Low heat transfer area per unit volume, making large duties impractical
- Many connections (flanges, return bends) increase potential leak points
- Higher cost per unit area compared to shell and tube at large duties
- Generally not practical beyond approximately 50 m2 of heat transfer area
Typical Applications
Double pipe exchangers see frequent use as sampling coolers, seal oil coolers, lube oil coolers, high-pressure gas coolers, slurry heaters, and small process stream coolers where a shell and tube unit would be oversized.
TEMA Classification
The Tubular Exchanger Manufacturers Association (TEMA) provides a standardized nomenclature for shell-and-tube heat exchangers. Each exchanger is identified by a three-letter code denoting the front-end stationary head type, the shell type, and the rear-end head type.
Front End Stationary Head Types
| TEMA Letter | Type | Description |
|---|---|---|
| A | Channel with removable cover | Allows tube-side inspection without disconnecting piping. Most versatile. |
| B | Bonnet (integral cover) | Simpler, lower cost than A-type. Piping must be disconnected for tube access. |
| C | Channel integral with tube sheet | Used for high-pressure applications. Removable cover on channel side. |
| N | Channel integral with tube sheet | Fixed, no removable cover. Least expensive front end. |
| D | Special high-pressure closure | For very high-pressure services (e.g., HP amine, HP feed-effluent). |
Shell Types
| TEMA Letter | Type | Description |
|---|---|---|
| E | One-pass shell | Most common. Fluid enters one end, exits the other. |
| F | Two-pass shell (longitudinal baffle) | Higher thermal efficiency but prone to baffle leakage. |
| G | Split flow | Fluid enters center, splits, and exits both ends. Used for thermosiphon reboilers. |
| H | Double split flow | Two inlet nozzles, two outlet nozzles. For low pressure drop applications. |
| J | Divided flow | Single central inlet, two end outlets (or vice versa). Reduces shell-side pressure drop. |
| K | Kettle type | Enlarged shell for vapor disengagement. Used for reboilers and vaporizers. |
| X | Cross flow | Shell fluid flows across tubes without baffles. Lowest shell-side pressure drop. |
Rear End Head Types
| TEMA Letter | Type | Description |
|---|---|---|
| L | Fixed tube sheet (like A) | Tube sheet welded to shell. Low cost, compact. No bundle removal. |
| M | Fixed tube sheet (like B) | Similar to L, bonnet-type cover. |
| N | Fixed tube sheet (like N) | Fixed, integral tube sheet. |
| P | Outside packed floating head | Allows thermal expansion. Limited pressure and temperature. |
| S | Floating head with backing device | Most common floating head type. Bundle fully removable. |
| T | Pull-through floating head | Easiest bundle removal but largest shell diameter (clearance for floating head flange). |
| U | U-tube bundle | Tubes bent into U-shape. Eliminates one tube sheet. Lowest cost for removable bundle. |
| W | Externally sealed floating tube sheet | For services requiring no fluid leakage between shell and tube sides. |
TEMA Service Classes
TEMA defines three mechanical standards classes based on application severity. TEMA R (Refinery) is the most stringent, mandatory for petroleum refining, and requires thicker tube sheets, larger corrosion allowances, and heavier construction throughout. TEMA C (Commercial) addresses moderate-severity general commercial and process applications. TEMA B (Chemical) sits between R and C, covering chemical process services.
Comparison of Heat Exchanger Types
| Parameter | Shell and Tube | Plate (Gasketed) | Air-Cooled (Fin-Fan) | Double Pipe |
|---|---|---|---|---|
| Heat duty range | 10 kW to 500+ MW | 10 kW to 50 MW | 100 kW to 200 MW | 1 kW to 2 MW |
| Max. pressure | Up to 300+ bar | Up to 25-30 bar | Up to 200 bar (tube side) | Up to 600 bar |
| Max. temperature | -200 to 600+ degC | -30 to 200 degC (gasket) | -50 to 450 degC | -200 to 600 degC |
| Heat transfer coeff. | Moderate | Very high (3-5x S&T) | Low (air side limited) | Moderate |
| Footprint | Large | Very compact | Large (elevated structure) | Small per unit, many needed |
| Fouling resistance | Good (cleanable) | Moderate (narrow gaps) | Good (fin cleaning) | Good (inner pipe accessible) |
| Maintenance | Moderate (bundle pull) | Easy (open frame) | Moderate (fan, belts, fins) | Easy (disassemble pipes) |
| Relative capital cost | Medium | Low to medium | High | Low (per unit) |
| Cooling medium | Liquid or condensing vapor | Liquid | Ambient air | Liquid |
| Best suited for | All O&G services | Clean, low-P, low-T | No cooling water available | Small duties, high P |
Standards and Specifications
The following international standards govern design, fabrication, inspection, and testing of heat exchangers in oil and gas service:
| Standard | Full Title | Scope |
|---|---|---|
| TEMA | Standards of the Tubular Exchanger Manufacturers Association | Design, fabrication, and materials for shell-and-tube heat exchangers. Defines R/C/B service classes and three-letter type designation. |
| ASME Section VIII | ASME Boiler and Pressure Vessel Code, Section VIII | Pressure vessel design rules applicable to shells, heads, nozzles, and other pressure-containing components. Division 1 (most common) and Division 2 (alternative rules, higher allowable stresses). |
| API 660 | Shell-and-Tube Heat Exchangers | Minimum requirements for shell-and-tube exchangers in petroleum, petrochemical, and natural gas industries. References TEMA R class. |
| API 661 | Air-Cooled Heat Exchangers for General Refinery Service | Design, materials, fabrication, inspection, testing, and preparation for shipment of air-cooled heat exchangers. |
| API 662 | Plate Heat Exchangers for General Refinery Service | Part 1: Plate-and-frame (gasketed). Part 2: Welded and brazed plate types. |
| ASME B31.3 | Process Piping | Governs piping connections to and from heat exchangers, including nozzle loads and flexibility analysis. |
| HTRI / HTFS | Heat Transfer Research Inc. / Heat Transfer and Fluid Flow Service | Industry software and design methods for thermal-hydraulic rating and design of heat exchangers (not a standard per se, but widely used design tools). |
| API 614 | Lubrication, Shaft-Sealing and Oil-System Requirements | Relevant for lube oil cooler design within compressor and turbine oil systems. |
| NACE MR0175 / ISO 15156 | Materials for use in H2S-containing environments | Material selection requirements for heat exchangers in sour service. |
Materials Selection
Material selection for heat exchangers is driven by the process fluid (composition, temperature, pressure, corrosiveness, erosiveness), the external environment, the design life, and cost.
Carbon Steel (SA-516 Gr. 70, SA-106 Gr. B)
Carbon steel is the default material for shell-and-tube exchanger shells, channels, baffles, and tube sheets in non-corrosive services. SA-516 Gr. 70 is the most common plate material for shells and heads; SA-179 and SA-214 are standard tube materials. The usable temperature range runs from -29 degC to roughly 425 degC (creep becomes a concern above that). For cost, nothing else comes close.
Stainless Steels
| Grade | UNS | Characteristics and Typical Service |
|---|---|---|
| Type 304 | S30400 | Austenitic with good general corrosion resistance. Used in mildly corrosive services, food-grade applications, and cryogenic duties. |
| Type 316/316L | S31600/S31603 | 2-3% molybdenum addition gives superior pitting and crevice corrosion resistance over 304. Standard choice for seawater-cooled tube bundles, amine services, and moderately corrosive organic acids. |
| Type 321/347 | S32100/S34700 | Stabilized grades for service above 425 degC, resisting sensitization and intergranular corrosion. |
Duplex Stainless Steels
2205 Duplex (UNS S31803/S32205) provides roughly twice the yield strength of 316L, with excellent resistance to chloride stress corrosion cracking and pitting. It is widely used in offshore heat exchangers, seawater-cooled systems, and sour gas services. Super duplex grades (UNS S32750/S32760) push the alloy content higher for extreme chloride and sour environments such as FPSO seawater cooling and subsea applications.
Nickel Alloys
| Alloy | UNS | Characteristics and Typical Service |
|---|---|---|
| Alloy 625 | N06625 | Excellent high-temperature corrosion, oxidation, and pitting resistance. Used in flue gas heat recovery and high-temperature sour gas environments. |
| Alloy 825 | N08825 | Good resistance to sulfuric and phosphoric acids. Used in acid gas coolers and amine reboilers. |
| Alloy C-276 | N10276 | The most versatile corrosion-resistant nickel alloy. Handles the most aggressive environments (wet HCl, FGD systems). |
| Alloy 400 (Monel) | N04400 | Excellent hydrofluoric acid resistance. The standard material for HF alkylation unit heat exchangers. |
Titanium
Grade 2 (UNS R50400) is commercially pure titanium with outstanding resistance to seawater, wet chlorine, and brackish water. It is the go-to tube material for seawater-cooled condensers in coastal refineries and offshore platforms. Grade 12 (UNS R53400) adds enhanced crevice corrosion resistance in hot brines, used where seawater temperatures are elevated.
Material Selection Guidelines
| Service Condition | Recommended Material |
|---|---|
| General hydrocarbon (non-corrosive) | Carbon steel |
| Cooling water (fresh) | Carbon steel or admiralty brass (tubes) |
| Seawater cooling | Titanium Gr. 2, 90/10 Cu-Ni, or super duplex (tubes); carbon steel or coated CS (shell) |
| Amine service (MEA, DEA, MDEA) | Carbon steel (stress-relieved), SS 304/316 for reboiler tubes |
| Sour gas (H2S containing) | CS per NACE MR0175, duplex or nickel alloys for severe sour |
| High-temperature flue gas | Alloy 625, Alloy 800H/HT |
| HF alkylation | Monel 400 or carbon steel (depends on temperature) |
| Cryogenic (LNG, NGL) | SS 304/304L, 9% Ni steel, aluminum alloys |
| Naphthenic acid corrosion (high TAN crude) | SS 316/317 (Mo >= 2.5%), Alloy 625 cladding |
Applications in Oil and Gas
Heat exchangers are used across all sectors of the oil and gas industry.
Upstream (Exploration and Production)
Wellhead and production facilities rely on gas/liquid heat exchangers within production separators, gas-glycol contactors and reboilers in glycol dehydration units for removing water from natural gas, coolers that bring produced water to disposal or reinjection temperature, and wellhead choke heaters that prevent hydrate formation in high-pressure gas streams. On FPSO topsides, compact plate and air-cooled exchangers dominate because weight and deck space are at a premium.
Midstream (Transportation and Processing)
Gas transmission and processing plants use aftercoolers and interstage coolers at pipeline compressor stations, reboilers and condensers on every fractionation column in gas processing (demethanizers, deethanizers, depropanizers), cryogenic brazed aluminum plate-fin exchangers in NGL and LNG fractionation, lean/rich amine exchangers plus amine reboilers and overhead condensers in amine treating, and waste heat boilers, sulfur condensers, and reheaters in sulfur recovery units.
Downstream (Refining and Petrochemicals)
Refining operations involve the largest concentration of heat exchangers. In crude distillation, the preheat train alone can consist of 8-15 shell-and-tube exchangers recovering heat from product streams to preheat crude oil, supplemented by overhead condensers and product coolers. Vacuum distillation requires vacuum overhead condensers and pump-around coolers. Hydroprocessing units (hydrotreating, hydrocracking) operate feed/effluent heat exchangers at 300-450 degC and 100-200 bar, often using the Texas Tower (combined feed/effluent) design. FCC units use main fractionator overhead condensers, slurry oil coolers, and HCO/LCO product coolers. Reforming, delayed coking, and alkylation all have their own trains of feed/effluent exchangers, reboilers, condensers, and coolers. Across the plant, utility services include waste heat boilers for steam generation, boiler feedwater preheaters, and cooling water exchangers.
Key Takeaway: In a typical petroleum refinery, the crude preheat train is the single most important heat exchanger system. By recovering heat from hot product streams to preheat the incoming crude, the preheat train reduces the fired heater duty by 60-70%, saving enormous amounts of fuel and reducing emissions. Optimizing preheat train performance through fouling management and network design (pinch analysis) is one of the highest-value activities in refinery energy management.
Design Considerations
Designing a heat exchanger for oil and gas service means balancing thermal performance, hydraulic constraints, mechanical integrity, and economics.
Log Mean Temperature Difference (LMTD)
The LMTD is the effective driving force for heat transfer in a heat exchanger. It is calculated from the terminal temperatures of both fluid streams:
LMTD = (delta T1 - delta T2) / ln(delta T1 / delta T2)
Where delta T1 and delta T2 are the temperature differences between the hot and cold fluids at each end of the exchanger. For multi-pass and cross-flow arrangements, a correction factor F is applied to account for deviation from pure counter-current flow. The corrected mean temperature difference is:
Effective MTD = F x LMTD
The correction factor F depends on the number of shell and tube passes and on the dimensionless parameters R (heat capacity ratio) and P (thermal effectiveness). F values below 0.75 generally signal that additional shell passes or a different exchanger configuration is needed.
Overall Heat Transfer Coefficient (U)
The overall heat transfer coefficient combines the individual resistances to heat flow:
1/U = 1/h_i + R_fi + (r_o x ln(r_o/r_i))/k_w + R_fo + (A_o/A_i) x (1/h_o)
Where h_i and h_o are the tube-side and shell-side film coefficients, R_fi and R_fo are the tube-side and shell-side fouling resistances, k_w is the tube wall thermal conductivity, and r_i and r_o are the tube inner and outer radii.
Typical overall U values for common services:
| Service | U (W/m2K) |
|---|---|
| Water to water | 800-1500 |
| Gas to gas (high pressure) | 150-500 |
| Hydrocarbon liquid to water | 350-700 |
| Heavy oil to water | 50-300 |
| Condensing steam to water | 1500-4000 |
| Condensing hydrocarbon vapor to water | 300-700 |
| Gas to gas (low pressure) | 10-50 |
| Reboiler (steam to hydrocarbon) | 500-1000 |
Fouling Factors
Fouling is the deposition of unwanted material on heat transfer surfaces, reducing thermal performance and increasing pressure drop. TEMA provides recommended fouling resistance values (in m2K/W) for various services:
| Fluid | Fouling Resistance (m2K/W) |
|---|---|
| Clean river water | 0.00018 |
| Cooling tower water (treated) | 0.00035 |
| Seawater (below 50 degC) | 0.00009 |
| Crude oil (below 250 degC) | 0.00035 |
| Crude oil (above 250 degC) | 0.00053 |
| Light hydrocarbons (clean) | 0.00018 |
| Heavy hydrocarbons | 0.00035-0.00053 |
| Atmospheric tower overhead vapor | 0.00018 |
| Amine solutions | 0.00035 |
| Natural gas | 0.00009 |
| Steam (clean) | 0.00009 |
Excessive fouling in crude preheat trains remains a major operational headache. Typical crude preheat exchangers lose 20-40% of their clean heat transfer capability within 12-24 months as asphaltene, wax, and inorganic salts accumulate. The result is increased fired heater duty and higher energy costs.
Pressure Drop
Pressure drop through a heat exchanger must be carefully managed because it directly affects pumping and compression costs (more drop means more energy consumed), process performance (excessive drop can upset upstream equipment like distillation columns), and two-phase flow behavior (pressure drop causes flashing and shifts vapor/liquid equilibrium).
Typical allowable pressure drops:
- Liquids: 0.5-1.0 bar per exchanger (tube side and shell side)
- Gases and vapors: 0.07-0.35 bar (kept lower to minimize compression energy)
- Vacuum service: 0.01-0.05 bar to avoid breaking vacuum
Thermal Expansion
Differential thermal expansion between the shell and tubes is a critical mechanical concern. When tubes and shell operate at significantly different temperatures, the expansion mismatch can generate enormous stresses in tube sheets and tube-to-tube-sheet joints. Four common solutions address this problem: expansion joints (bellows) on the shell for fixed tube sheet designs, floating head designs (TEMA S, T, P, W types) that let the bundle expand freely, U-tube bundles that inherently accommodate differential expansion through bend flexibility, and matching tube and shell materials to minimize differential expansion in the first place.
Tube Vibration
Flow-induced tube vibration is a potentially destructive phenomenon in shell-and-tube exchangers. High shell-side crossflow velocities can excite tubes at their natural frequency, causing tube-to-baffle hole wear (fretting), tube-to-tube collision damage, and fatigue failure at the tube sheet.
Vibration analysis per TEMA guidelines and HTRI/HTFS methods is part of the standard design process. The main mitigation strategies are reducing unsupported tube spans (adding baffles or intermediate supports), detuning tube natural frequency by adjusting span lengths, installing impingement plates at shell nozzles to prevent direct jet impingement on tubes, and limiting shell-side crossflow velocity.
Related Articles
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- Oil & Gas Separators
- Compressors
- Up, Mid, Downstream Equipment Overview
Related quick answers: What Is a Separator? | What Is a Desalter?
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