Gas & Liquid Heaters Fundamentals

1. Types of Process Heaters

Process heaters in gas processing and pipeline operations fall into two fundamental categories based on how combustion heat is transferred to the process fluid: indirect-fired heaters, where a heat transfer medium separates the flame from the process stream, and direct-fired heaters, where combustion gases contact heat transfer surfaces directly exposed to the process fluid on the opposite side. The choice between these categories—and among the many equipment configurations within each—depends on temperature requirements, fluid properties, safety considerations, and thermal efficiency targets.

Indirect-Fired Heaters

Indirect-fired heaters use an intermediate heat transfer medium (typically water, glycol, or a heat transfer oil) between the combustion source and the process stream. The fire tube is submerged in the bath medium, and the process fluid flows through a coil also submerged in the bath. This double-barrier arrangement provides inherent safety advantages by preventing direct contact between the flame and potentially flammable process fluids. Common indirect-fired configurations include:

• Water bath heaters: The most common type in pipeline operations, using water as the bath medium. Limited to bath temperatures below 200°F to prevent boiling. Used extensively for gas heating ahead of pressure regulators and metering stations
• Glycol bath heaters: Use a water-glycol mixture as the bath medium, allowing operation at temperatures below freezing without bath solidification. Common in cold-climate installations where ambient temperatures drop below 32°F
• Heat medium (hot oil) systems: Use a thermal fluid (synthetic or mineral oil) as the heat transfer medium, enabling operation at temperatures up to 600–750°F without pressurization. Preferred for high-temperature applications with multiple heat users

Direct-Fired Heaters

Direct-fired heaters expose the process tubes directly to radiant and convective heat from the combustion gases. The process fluid flows through tubes arranged in a radiant section (firebox) surrounding the burner and a convection section where flue gases transfer residual heat before exhausting through the stack. Direct-fired configurations include:

• Cabin (box) heaters: Rectangular firebox with horizontal or vertical tube passes along the walls. Common for glycol regeneration reboilers, amine regeneration reboilers, and process furnaces in gas plants
• Cylindrical heaters: Vertical cylindrical firebox with helical or vertical tube coils. Used for high-duty applications where compact footprint is important
• Process furnaces: Large-scale direct-fired heaters for feed preheat, reactor charge heating, or high-temperature processing. Designed per API 560 with detailed radiant and convection section analysis

Application Selection Guide

Selecting the appropriate heater type requires evaluating multiple factors simultaneously. The following table summarizes common gas processing and pipeline heating applications with their typical heater selections:

Selection Criteria

The decision between indirect and direct firing involves several trade-offs that must be weighed against project-specific requirements:

• Temperature requirement: Indirect-fired water bath heaters are limited to approximately 190°F process outlet temperature. Applications requiring higher temperatures must use hot oil systems or direct-fired heaters
• Fluid properties and safety: Flammable, toxic, or high-pressure process fluids strongly favor indirect firing because the bath medium provides a secondary containment barrier. Direct-fired heaters require tube rupture analysis and emergency procedures for flammable service
• Thermal efficiency: Direct-fired heaters achieve 75–90% thermal efficiency, compared to 70–85% for indirect-fired units. The efficiency advantage grows at higher temperatures where stack losses from indirect units increase
• Maintenance and reliability: Indirect-fired heaters are simpler to maintain and have fewer failure modes. Bath medium level, quality, and corrosion inhibition are the primary maintenance concerns. Direct-fired heaters require tube inspection, refractory maintenance, and burner tuning

2. Indirect-Fired Bath Heaters

Indirect-fired bath heaters are the workhorses of pipeline and gas processing heating applications. Their inherent safety—provided by the bath medium barrier between flame and process fluid—makes them the default choice for heating flammable gases and liquids in field installations. The fundamental design consists of a horizontal pressure vessel containing the bath medium, with a U-tube fire tube submerged in the bath for combustion heat input and one or more process coils submerged in the bath for heat transfer to the process fluid.

Water Bath Heaters

Water bath heaters use treated water as the bath medium and are the most widely deployed heater type in natural gas pipeline operations. The bath water temperature is maintained between 140–190°F, providing process outlet temperatures of 80–150°F depending on the approach temperature and coil design. Key design considerations include:

• Bath temperature control: The bath temperature must be maintained below 200°F to prevent localized boiling on the fire tube surface, which causes scale deposition, tube hot spots, and accelerated corrosion. Most designs target a maximum bath temperature of 180–190°F with high-temperature shutdown set at 195°F
• Water treatment: The bath water must be treated with corrosion inhibitors (typically oxygen scavengers and pH adjusters) to prevent internal corrosion of the vessel shell and fire tube. Untreated water causes pitting corrosion and scale buildup that degrades heat transfer
• Freeze protection: In cold climates, ethylene glycol or propylene glycol is added to the bath water (typically 40–60% concentration) to prevent freezing during shutdowns. The glycol concentration must be checked seasonally as water evaporation increases the glycol fraction over time

Fire Tube Design

The fire tube is the critical heat transfer element in any bath heater, and its design directly determines heater capacity, efficiency, and service life. The fire tube is typically a U-tube configuration with the burner mounted on one leg and the combustion gases exhausting through the other leg to the stack. Proper fire tube design requires careful attention to heat flux limits, tube material, and draft characteristics.

Heat flux is the most critical fire tube design parameter. Exceeding the recommended heat flux limits causes localized overheating on the fire tube surface, which leads to scale deposition from the bath water, accelerated oxidation of the tube metal, and eventual tube failure. The average heat flux is calculated as the total heat release divided by the total outer surface area of the fire tube, but the maximum local heat flux at the burner end may be 1.5–2.0 times the average value. Designs must ensure that the peak local flux remains below the recommended limits.

Process Coil Design

The process coil transfers heat from the bath medium to the process fluid. Coils are typically constructed from carbon steel pipe (2–4 inch diameter) wound in a helical or serpentine configuration and submerged in the bath medium. Key design parameters include:

• Tube material: Carbon steel (ASTM A106 Grade B) for standard gas service. Stainless steel or alloy materials for corrosive service (wet CO₂, H₂S service)
• Tube diameter: Selected based on process flow rate and allowable pressure drop. Common sizes are 2-inch, 3-inch, and 4-inch NPS for gas service; 2-inch and 3-inch for liquid service
• Coil length: Determined by the required heat transfer area, which depends on the duty, the overall heat transfer coefficient, and the log-mean temperature difference between the bath and the process fluid
• Design pressure: Process coils are designed for the full pipeline operating pressure (up to 1,480 psig for ANSI 600 class) or higher, as they are pressure-containing equipment

Bath Circulation

Effective bath circulation is essential for uniform heat distribution and prevention of localized overheating. In most bath heaters, natural convection drives the circulation pattern: the bath medium heated by the fire tube rises, flows across the process coils (transferring heat to the process fluid), cools, and descends back toward the fire tube. This natural circulation is adequate for heaters up to approximately 3–5 MMBTU/hr. Larger units may require mechanical circulation (pumps or agitators) to maintain uniform bath temperature.

Burner Selection

Bath heater burners are selected based on heat release requirement, available fuel gas pressure, and emission requirements:

• Natural draft burners: The most common type for field bath heaters, using stack draft to draw combustion air into the burner. Simple, reliable, and require no external power. Limited to approximately 5–10 MMBTU/hr per burner and 25–30% excess air
• Forced draft burners: Use a combustion air blower to provide controlled air supply. Allow lower excess air (10–15%), higher turndown ratio (10:1 vs. 3:1 for natural draft), and better combustion control. Required for larger heaters and installations with emission limits for NO_x and CO

Safety Controls

Bath heaters require a comprehensive safety control system to prevent hazardous conditions. The minimum safety instrumentation required by API 12K and industry practice includes:

3. Line Heaters for Hydrate Prevention

Line heaters are specialized indirect-fired bath heaters designed specifically to heat natural gas upstream of pressure-reducing devices (chokes, regulators, control valves) to prevent hydrate formation caused by the Joule-Thomson cooling effect. When high-pressure gas expands across a pressure-reduction device, its temperature drops in proportion to the pressure drop. If the gas temperature falls below the hydrate formation temperature at the downstream pressure, solid gas hydrates (ice-like crystalline compounds of water and natural gas) form and can plug the pipeline, instrument lines, and control equipment.

Joule-Thomson Cooling Effect

The temperature drop experienced by natural gas during pressure reduction is described by the Joule-Thomson (JT) coefficient, which varies with gas composition, pressure, and temperature. For typical pipeline-quality natural gas, the JT coefficient ranges from 5–8°F per 100 psi of pressure drop at common operating conditions. This means a 500 psi pressure reduction can cool the gas by 25–40°F—often enough to bring the gas below its hydrate formation temperature if the inlet temperature is not sufficiently elevated.

Where ΔT_JT is the temperature drop (°F), μ_JT is the Joule-Thomson coefficient (°F/psi), and ΔP is the pressure drop (psi). The required heater outlet temperature is determined by adding the JT temperature drop to the required minimum downstream temperature (which must exceed the hydrate formation temperature at the downstream pressure with an adequate safety margin, typically 10–15°F).

Sizing Methodology

Line heater sizing involves determining the heat duty required to raise the gas temperature from the inlet condition to the required outlet temperature. The basic duty calculation is:

Where Q is the heat duty (BTU/hr), ṁ is the mass flow rate (lb/hr), C_p is the specific heat capacity of the gas at average conditions (BTU/lb-°F), T_out is the required outlet temperature (°F), and T_in is the inlet gas temperature (°F). The heater must be sized for the maximum flow rate and worst-case (coldest) inlet temperature conditions to ensure adequate heating under all operating scenarios.

Common Configurations

Line heaters are available in several configurations, each suited to different flow rates, pressures, and installation requirements:

• Coil-in-shell: The most common configuration for gas line heating. A helical or serpentine process coil is submerged in a water or glycol bath within a horizontal cylindrical vessel. The fire tube provides heat input from one end. Standard sizes range from 0.25 to 10 MMBTU/hr. Process coils are designed for full pipeline pressure (up to 1,480 psig ANSI 600 class)
• U-tube (hairpin): Process gas flows through a U-tube bundle submerged in the bath. This arrangement provides better tube-side velocity control and easier cleaning access than helical coils. Preferred for applications with particulate-laden gas or potential for wax deposition
• Integral choke heater: Combines the heater and pressure-reducing choke in a single vessel. The gas is heated in the first coil pass, reduced in pressure through an integral choke bean, and may pass through a second coil for additional heating or temperature stabilization. This configuration minimizes piping and footprint at remote wellhead or pipeline locations

Operating Considerations

Line heaters in pipeline service operate in remote, often unmanned locations and must be designed for reliable, low-maintenance operation:

• Fuel gas supply: Line heaters typically use a small side-stream of pipeline gas as fuel, taken from downstream of the pressure regulator. Fuel gas conditioning (filtering, pressure regulation) must be provided to ensure clean, consistent fuel supply to the burner
• Condensate management: Gas cooling in the inlet piping upstream of the heater and heating within the process coil may produce hydrocarbon condensate. A liquid drain or knockout section should be provided to prevent liquid slugs from reaching downstream equipment
• Seasonal adjustment: Heater duty requirements vary significantly with ambient temperature. Summer operation may require reduced firing or complete bypass, while winter operation demands full capacity. Automatic temperature control with a process outlet thermostat is essential for efficient year-round operation
• Bath level monitoring: Water evaporation from the bath (particularly in hot climates or high-duty operation) gradually reduces the bath level. Automatic makeup water systems or regular manual replenishment schedules must be established to maintain adequate fire tube submergence

Fuel Gas Consumption Estimation

For preliminary fuel gas consumption estimates, the heater fuel requirement can be calculated from the process duty and the heater thermal efficiency:

Where F is the fuel gas consumption (SCF/hr), Q is the process heat duty (BTU/hr), η is the heater thermal efficiency (typically 0.78–0.85 for natural draft bath heaters), and HHV is the higher heating value of the fuel gas (typically 1,000–1,050 BTU/SCF for pipeline-quality natural gas). This calculation provides the design fuel consumption rate used for fuel gas system sizing and operating cost estimation.

4. Heat Medium Systems (Hot Oil)

Heat medium systems—commonly called hot oil systems—use a circulating thermal fluid to transport heat from a central fired heater to multiple process heat exchangers distributed throughout a gas processing facility. This approach is preferred over individual fired heaters at each heat load when high temperatures are required, when multiple heat users are present, or when safety considerations prohibit direct firing at the point of use. The central heater fires on fuel gas and heats the circulating thermal fluid, which is pumped through a closed loop to the various heat exchangers where it transfers heat to the process streams before returning to the heater for reheating.

When Hot Oil Systems Are Preferred

Hot oil systems offer distinct advantages over individual fired heaters in several scenarios commonly encountered in gas processing plants:

• High temperature applications (above 300°F): Water bath heaters cannot reach these temperatures without pressurization, and direct-fired heaters at each load point create multiple fire hazards. Hot oil systems operate at atmospheric pressure up to 600–750°F depending on the thermal fluid, providing high-temperature heat safely
• Multiple remote heat loads: When a plant has several reboilers, preheaters, and heat tracing circuits requiring heat at different locations, a single central fired heater with a hot oil distribution loop is more economical and easier to maintain than individual fired heaters at each location
• Hazardous process areas: Hot oil eliminates fired equipment from hazardous classified areas by locating the single fired heater in a non-hazardous zone and distributing heat via piping. This simplifies electrical classification and reduces fire risk
• Precise temperature control: Individual heat exchangers on the hot oil loop can be independently controlled with bypass valves, providing precise temperature regulation at each process load without affecting other users on the circuit

Common Heat Transfer Fluids

The selection of heat transfer fluid is one of the most important design decisions for a hot oil system. The fluid must be chemically stable at the operating temperature, have acceptable heat transfer properties, be compatible with system materials, and have manageable safety and environmental characteristics:

System Components

A complete hot oil system consists of several major components that must be properly designed and integrated for reliable operation:

• Fired heater: The central heat source, typically a direct-fired cabin or cylindrical heater designed per API 560. The heater must be sized for the total connected heat load plus 10–15% margin for future loads, heat losses in piping, and fouling allowance. Fire tube or process tube heat flux must not exceed the thermal fluid manufacturer's recommended maximum film temperature
• Circulation pump: Centrifugal pumps designed for high-temperature service with appropriate mechanical seals, bearing cooling, and NPSH considerations. The pump must provide sufficient flow to maintain adequate velocity (6–10 ft/s minimum) in all heat exchanger tubes to prevent film overheating. Standby pump capacity (100% spare) is standard practice for critical heating services
• Expansion tank: A vented or nitrogen-blanketed vessel located at the highest point in the system to accommodate thermal expansion of the fluid (8–15% volume increase from ambient to operating temperature), maintain pump suction head, and provide a liquid seal for the system. The tank is typically sized for 25–30% of the total system volume
• Heat exchangers: Shell-and-tube or plate-type exchangers at each process heat load. The hot oil flows on the tube side (for easier cleaning) or shell side depending on pressure and fouling considerations. Each exchanger has independent temperature control via a three-way bypass valve or a throttling valve on the hot oil supply

Fluid Degradation and Monitoring

All thermal fluids degrade over time through thermal cracking and oxidation. Degradation produces light-end (low-boiling) cracking products that lower the fluid flash point and increase vapor pressure, and heavy-end (high-boiling) polymerization products that increase viscosity and promote fouling. Monitoring fluid condition is essential to prevent safety hazards and maintain system performance:

• Flash point testing: A decreasing flash point indicates accumulation of light-end cracking products. When the flash point drops more than 50°F below the fresh fluid value, the light ends should be removed by venting through the expansion tank or by a light-ends removal system
• Viscosity measurement: Increasing viscosity indicates heavy-end accumulation. A viscosity increase of more than 30% above the fresh fluid value warrants partial fluid replacement or filtration to remove polymeric degradation products
• Total acid number (TAN): Oxidation products increase the acid number. Elevated TAN accelerates corrosion of carbon steel system components and indicates the need for nitrogen blanketing of the expansion tank to exclude oxygen
• Carbon residue (Ramsbottom or Conradson): Measures the coking tendency of the fluid. An increase above 1.0% indicates significant degradation and potential for fouling of heater tubes and heat exchanger surfaces

Pump Sizing and System Hydraulics

The circulation pump must provide adequate flow and head to maintain the required velocity in all heat exchangers while overcoming friction losses in the piping network. Key hydraulic considerations include:

• Minimum tube velocity: 6–10 ft/s in heater tubes and heat exchanger tubes to ensure turbulent flow and prevent local film overheating. Low velocity at partial load can cause tube coking
• System pressure drop: Total system pressure drop including heater coil, all heat exchangers, piping friction, valves, and fittings. The pump must overcome this pressure drop at the design flow rate
• NPSH requirements: Hot oil pumps operate with fluids at elevated temperatures and relatively low vapor pressure margins. The expansion tank elevation must provide adequate NPSH above the pump suction to prevent cavitation. Typical NPSH available should exceed NPSH required by at least 3–5 ft
• Viscosity effects: At startup (cold fluid), viscosity may be 5–20 times higher than at operating temperature, significantly increasing pressure drop and pump power requirement. The pump motor must be sized for cold-start conditions unless a separate startup heater or dilution procedure is used

5. Thermal Design and Safety

The thermal design of process heaters involves calculating heat transfer rates, selecting materials, sizing heat transfer surfaces, and ensuring that the equipment operates safely under all conditions including startup, normal operation, upset, and emergency shutdown. Proper thermal design requires understanding the heat transfer mechanisms at work, the limitations of materials at elevated temperatures, and the safety systems required to prevent equipment failure, fire, and explosion.

Heat Transfer Calculations

Heat transfer in process heaters involves convection on both the fire side and the process side, with conduction through the tube wall. The overall heat transfer rate is governed by the general equation:

Where Q is the heat duty (BTU/hr), U is the overall heat transfer coefficient (BTU/hr-ft²-°F), A is the heat transfer area (ft²), and ΔT_lm is the log-mean temperature difference (°F). The overall heat transfer coefficient accounts for the combined resistance of the fire-side film, tube wall conduction, and process-side film, plus any fouling resistances on either side:

Fouling Factors

Fouling resistance is a critical design parameter that accounts for the degradation of heat transfer surfaces over time due to scale deposition, corrosion products, coking, and biological growth. Design fouling factors must be selected based on the specific service conditions and cleaning frequency:

• Fire-side fouling: Soot and ash deposition on fire tube surfaces, typically 0.001–0.003 hr-ft²-°F/BTU. Higher values for heavy fuel firing or poor combustion conditions
• Bath-side fouling: Scale and corrosion product deposition from the bath medium, typically 0.001–0.002 hr-ft²-°F/BTU for treated water, 0.002–0.004 for untreated water
• Process gas fouling: Generally low (0.001) for clean, dry gas. Higher (0.002–0.005) for gas containing wax, scale, or corrosion products
• Hot oil fouling: 0.001–0.003 depending on fluid condition and temperature. Increases significantly as the fluid degrades and deposits carbon on heat transfer surfaces

Material Selection for Fire Tubes

Fire tube material selection is driven by the operating temperature, the corrosive environment (combustion products on the outside, bath medium on the inside), and the required service life. Common materials include:

Thermal Stress Considerations

Fire tubes and process tubes experience significant thermal stresses due to temperature gradients through the tube wall and differential expansion between fixed and moving parts. Thermal stress management includes:

• Fire tube expansion: The fire tube operates at significantly higher temperature than the vessel shell, causing differential thermal expansion. U-tube fire tubes accommodate this expansion through flexure of the U-bend. Straight fire tubes require expansion joints or floating tube sheets
• Startup and shutdown stresses: Rapid temperature changes create transient thermal stresses that exceed steady-state values. Controlled heating rates (typically 50–100°F/hr for the first hour) minimize thermal shock. Cold startup on a hot fire tube or sudden quench of a hot tube can cause cracking at weld joints
• Local hot spots: Scale deposition, flame impingement, or low fluid velocity create local temperature excursions that can exceed the tube material's creep limit, leading to bulging, cracking, or catastrophic rupture. Regular inspection by IR thermography during operation can identify developing hot spots before failure occurs

Safety Systems

Process heater safety systems are designed to prevent three primary hazards: fire/explosion from uncontrolled combustion, tube rupture from overtemperature or overpressure, and personnel exposure to hot surfaces or flammable releases. The safety system requirements vary by heater type and are specified in API 560 (for direct-fired heaters), API 12K (for production heating equipment), and NFPA 85 (for burner management systems):

• Pressure relief: All pressure-containing components (process coils, bath vessels, hot oil piping) require ASME-rated pressure relief devices. The relief device must be sized for the maximum credible overpressure scenario, including fire case (external fire exposure), blocked outlet, thermal expansion of trapped liquids, and tube rupture
• High-temperature shutdown: Automatic fuel shutoff on high process outlet temperature, high fire tube temperature (for direct-fired heaters), and high bath temperature (for indirect-fired heaters). The shutdown setpoints must be below the temperature limits of the weakest component in the system
• Flame arrestors: Required on fuel gas supply lines to fired equipment to prevent flame propagation back into the fuel gas system. The arrestor must be rated for the maximum fuel gas pressure and flow rate and must be inspected regularly for plugging
• Ventilation requirements: Enclosed heater shelters and buildings must provide adequate ventilation to prevent accumulation of combustible gas from leaks or burner malfunction. Combustible gas detection with alarm and shutdown capability is required in enclosed spaces containing fired equipment
• Snuffing steam or nitrogen: Direct-fired heaters should have provision for injecting steam or nitrogen into the firebox to extinguish fires in the event of a tube rupture releasing flammable process fluid into the combustion chamber

Efficiency Improvement

Heater thermal efficiency—the fraction of fuel energy transferred to the process fluid—is a significant operating cost factor, particularly for larger heaters operating continuously. Typical improvements include:

The most cost-effective improvement for existing heaters is typically combustion optimization through excess air reduction. Reducing excess air from 30% to 15% (typical for natural draft to forced draft conversion) reduces stack losses and can improve efficiency by 2–3 percentage points. Stack temperature monitoring and periodic combustion analysis (O₂, CO, CO₂ in flue gas) provide the data needed for ongoing optimization.

Emissions Considerations

Fired heaters are significant sources of criteria air pollutants, and their emissions must be quantified for permitting and compliance purposes. The primary emissions from natural gas-fired heaters include:

• NO_x (nitrogen oxides): Formed from high-temperature combustion of nitrogen in the combustion air. NO_x emissions increase exponentially with flame temperature. Low-NO_x burners reduce NO_x by 50–80% compared to conventional burners by staging combustion air and reducing peak flame temperatures
• CO (carbon monoxide): Indicator of incomplete combustion, typically resulting from insufficient excess air, poor fuel-air mixing, or flame impingement on cold surfaces. CO emissions should be below 50 ppm (corrected to 3% O₂) for properly tuned burners
• Particulate matter: Negligible for clean natural gas firing. Significant for heaters burning field gas with entrained liquids or solids, or for emergency liquid fuel firing
• VOC (volatile organic compounds): Generally negligible for natural gas combustion. May be significant if uncombusted fuel gas bypasses the flame zone during startup, shutdown, or malfunction events

References

1. API Standard 560 — Fired Heaters for General Refinery Service
2. API Specification 12K — Indirect-Type Oilfield Heaters
3. GPSA, Section 8 — Fired Equipment
4. NFPA 85 — Boiler and Combustion Systems Hazards Code
5. ASME Boiler and Pressure Vessel Code, Section VIII, Division 1
6. API Recommended Practice 535 — Burners for Fired Heaters in General Refinery Service