Wednesday, June 24, 2026

The Tube failure characterization (CCPS GPREH2 trim) closed with the nine ISO 23251:2008 aspects that bear on the likely failure mode.¹ The following evaluation criteria are recommended to help determine the effects that those aspects may have on the potential for developing tube failures during the multidisciplinary review:

• Corrosion / degradation potential
• Tube characteristics and velocities
• Shell characteristics and velocities
• Low temperature potential
• Tube versus baffle relative hardness
• Inspection technique, inspection frequency, points evaluated, and follow-up procedures

Corrosion / degradation potential. The potential for corrosion or degradation is one of the more important evaluation criteria when characterizing the tube failure. The compatibility of the tube material with both the shell side and tube side fluids is important to determine the potential for corrosion. In addition to fluid compatibility, the potential for stress corrosion cracking, electrolytic attack for systems with dissimilar metals, erosion, cavitation, abnormal fouling, and thermal stresses caused by large temperature differences/thermal cycling should be considered. This analysis should be performed by a corrosion engineer or metallurgist familiar with the potential damage mechanisms in the heat exchanger service.

The primary metallurgical and corrosion concern in regards to the guillotine break case are for those process environments/tube material combinations that could lead to stress corrosion cracking. The potential for stress corrosion cracking is especially pertinent in heat exchanger tube failures as stress corrosion cracking is the combination of stresses and corrosive environments that promote the failure, which may be present in the heat exchangers, and may not be identified based simply on fluid compatibility or mechanical stresses. Some common examples of potential stress corrosion cracking combinations are for brass in ammonia service (i.e. “season cracking”), carbon steel in liquefied ammonia service (Loginow²), carbon steel in strong alkali service (i.e. “caustic embrittlement”), stainless steel in chloride service, and high strength steels in hydrogen service (i.e. “hydrogen embrittlement”). Various guidelines published by the National Association of Corrosion Engineers (NACE), including NACE MR0103³, “Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments,” as well as other guidelines such as API RP 571⁴, “Damage Mechanisms in the Refining Industry,” provide good background information on the potential mechanisms.

Stress corrosion cracking tests, such as a slow strain rate test (ASTM G129-00:2006⁵), are recommended to help establish the potential for stress corrosion cracking in environments where the compatibility of all combinations of materials and environments has not been established or where there is wide variability in the results (e.g., small changes in metal composition can have significant effects on the potential for stress corrosion cracking (Cottis⁶). Any system having the potential for stress corrosion cracking should be considered to have the potential for a guillotine break.

The potential for electrolytic attack for systems with dissimilar metals is something usually accounted for in the mechanical design of the exchanger; however, with some exchangers changing service over their lifetimes, a review of the galvanic corrosion is recommended.

Erosion can occur for systems containing solids or high viscosity fluids. Many exchanger manufacturers have velocity limits to reduce the potential for erosion in the tubes, especially at the entrances or the bend in a U-tube type exchanger, where additional shear stresses are encountered. The highest velocities in the bundle are located where the fluid passes around the inlet nozzle impingement plate and also where the fluid immediately enters into the bundle perimeter just beyond the impingement plate. The Tubular Exchanger Manufacturers Association (TEMA) provides procedures for calculating the shellside and bundle entrance velocities. The highest shellside velocities inside the exchanger are typically at the inlet of the bundle, and TEMA provides guidelines to minimize the potential for erosion by limiting the velocity momentum term throughout the bundle to the following criterion:⁷

ρu² ≤ 5,950 kg/(m·s²) [ 4,000 lb_m/(ft·s²) ]

Any system having the potential for erosion should be considered to have the potential for a guillotine break. Cavitation is a special case of erosion, caused by the localized collapse of bubbles or void spaces that create shock waves that can erode the tube wall. Any system operating near the bubblepoint, where small changes in pressure such as those encountered with potential energy effects can result in the formation and collapse of bubbles, should be considered to have the potential for a guillotine break.

Tube characteristics and velocities. The velocity through a tube has a direct impact on the potential for tube vibration. There are additional characteristics that need evaluation to determine whether this vibration can result in fatigue and failure, such as whether the vibrations are close to the natural frequencies of the vibration modes for the tubes, and these evaluations are complex; nonetheless, some guidance can be recommended. A velocity greater than 50% of the speed of sound of the fluid can result in acoustically induced fatigue; therefore, a guillotine break should be considered for these cases. In addition, the relative thickness of the tube to the inner diameter is a factor in the potential for tube vibration fatigue. One of the main reasons the guillotine break is not considered for normally constructed piping is that the thickness to inner diameter ratio is relatively high (approximately 0.15 for typical schedules of piping less than 2″ NPS).

Shell characteristics and velocities. The baffle type, placement, and spacing have a direct effect on the shell side velocities and on the potential for tube vibration. Two criteria can be evaluated for the shell side characteristics. The first criterion is the unsupported tube length, the maximum allowable values of which are provided in the Tubular Exchanger Manufacturers Association, Inc. (TEMA⁷) standards and in Perry’s Section 11⁸. The unsupported tube length is the length of the tube between two connection points, typically baffles or the tubesheet. Note the unsupported tube length can be set at the baffle spacing with the specification of “no tubes in window” in the construction of the heat exchanger, thus allowing each baffle to provide a connection point for each tube. There is some evidence of vibrations occurring at unsupported lengths of approximately 70% of the maximum allowable unsupported length; therefore, if any unsupported tube length is greater than this value, the potential for tube vibration should be considered.

The second criterion is the relative velocity between the baffle window (i.e. that portion of the baffle cut out to allow flow around the baffle) and the cross-flow (i.e., the area where flow is approximately normal to the tube direction). In general, the ratio of these velocities should be in the range of 0.8 to 1.2 (Mukherjee⁹). A ratio outside of this range indicates significant changes in velocities as the shell side fluid travels between the baffle window and the cross-flow regime, which results in a repeated acceleration and deceleration of the shellside fluid that can lead to tube vibration induced by the shell side flow (Halle et al.¹⁰). Note that when determining the velocities through the baffle window or the cross-flow area, some of the space is occupied by the tubes; therefore, the superficial velocity should be based on the actual area available for shellside flow by accounting for the space occupied by the tubes and may need to be adjusted based on the pitch of the tubes.

Heat exchanger tube vibration analyses should be performed to determine the susceptibility of the tubes to flow induced and acoustical vibration and the cracking and damage that may occur as a result. Methods as presented in the eighth edition of the Standards of the Tubular Exchanger Manufacturers Association (TEMA⁷) supplemented by the methods presented by the Heat Transfer Research Institute (HTRI¹¹) should be considered for performing these analyses.

Low temperature potential. Many metals experience a ductile-to-brittle transition at lower temperatures, where the material becomes brittle and is much more likely to catastrophically fail due to stresses. This transition temperature is a common basis for the minimum design metal temperature for the material. The temperatures of most fluids decrease when undergoing a rapid depressurization, and for high pressure compressible fluids this temperature change can be significant. In some instances, the temperature change can result in temperatures that are below the minimum design metal temperature. If an isenthalpic flash of the high pressure side fluid to the low pressure side minimum operating pressure results in a temperature less than the minimum design metal temperature of the tube material, then there is the potential for any type of leak to progress to a catastrophic failure due to the embrittlement of the tubes.

Tube versus baffle relative hardness. The relative hardness of the tube and baffle material can provide an indication of the potential for baffle to chafe or cut the tube. Hardness values are specific to the type of metal and the processing that metal has undergone, and there are many testing methodologies available to determine relative hardness, the Rockwell test being the most common. If the baffle material is harder than the tube material, then the potential for baffle chafing is high and a guillotine failure should be considered.

Inspection. The inspection program is an important element in the justification for considering tube failures, as identifying all of the potential failure mechanisms is difficult and the inspection results provide an indication of the mechanical integrity of the equipment after the equipment has been placed in service.

For high pressure differential exchangers that have not been provided with relief capacity for a full guillotine break based on a consideration of risk, an inspection program specifically targeting damage mechanisms that could lead to a guillotine break should be implemented. Any inspection findings that indicate vibration damage at the baffle joints or evidence of cracking would suggest that additional measures be taken for overpressure protection of the low-pressure side.

Selection of a tube bundle inspection technique depends on the tube material and on defect types expected. In general, inspection techniques suggested for the damage mechanisms of most interest for the tube rupture (guillotine break) scenario are those that can detect flaws or defects due to environmental cracking or fretting and cracking damage at locations where the tubes meet the crossflow baffles. The non-destructive testing (NDT) techniques available for inspection of tube bundles include conventional eddy current, full saturation eddy current, remote field eddy current, magnetic flux leakage, ultrasonic IRIS (internal rotary inspection system), and laser optics. Each of the NDT techniques has its advantages and limitations. For example, conventional eddy current is very sensitive to pits and cracks, yet limited to non-ferromagnetic materials. IRIS is accurate in measuring wall thickness, yet will miss small defects such as pinholes and cracks. Optical techniques are limited to ID defects. NDT techniques are continually evolving and obtaining guidance of a knowledgeable NDT contractor is extremely important. Proper selection of the NDT techniques is a key to suitable inspection of heat exchangers.

Note that the quality of the results from eddy current and other testing techniques is very dependent on the operator of the equipment. Operators should be sufficiently trained and have demonstrated their ability to locate defects on sample tubes that have known defects in them.

The inspection program should have a regular frequency commensurate with the risks involved, and should include evaluations for actual wall thicknesses, corrosion rates, and other signs of corrosion or degradation. For example, if the relief system is designed for the tube leak and the consequences of having an undersized relief system in the event of a guillotine break were high, the inspection interval may need to be relatively short to ensure any corrosion or degradation of the tubes is identified and addressed. In addition, the inspection program should have specific actions to take in the event corrosion or degradation is identified. Refer to API RP 580¹² and RP 581¹³ for more information.

Blog series information. This blog is part of a series on the proposed updates to the CCPS Guidelines 2nd edition §3.3 Venting Requirements for Nonreacting Cases that were removed during final editing. See the general CCPS Guidelines for Pressure Relief and Effluent Handling 2nd Edition review for more information.

 

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[1] AIChE Center for Chemical Process Safety. “CCPS Guidelines for Pressure Relief and Effluent Handling Systems”. 2nd Edition, 2017; New Jersey: John Wiley & Sons, Inc.

[2] Loginow AW. “Stress-Corrosion Cracking of Steel in Liquefied Ammonia Service – A Recapitulation.” ASME National Board Bulletin, January 1989.

[3] NACE MR0103, Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments. NACE International, 2007, Houston, TX. (current ANSI/NACE MR0103-2012 / ISO 17945:2015)

[4] API RP 571, Damage Mechanisms Affecting Fixed Equipment in the Refining Industry. American Petroleum Institute, 2003, Washington, DC. (current 3rd ed. 2020)

[5] ASTM G129-00:2006, Standard Practice for Slow Strain Rate Testing to Evaluate the Susceptibility of Metallic Materials to Environmentally Assisted Cracking. ASTM International, West Conshohocken, PA. (Current G129-21.)

[6] Cottis RA. “Guides to Good Practice in Corrosion Control – Stress Corrosion Cracking.” National Physical Laboratory (UK DTI), Corrosion and Protection Centre, University of Manchester.1982.

[7] Standards of the Tubular Exchanger Manufacturers Association (TEMA). TEMA, Tarrytown, NY. 1999. (current 9th ed. 2007)

[8] Shilling RL et al. “Heat-Transfer Equipment”. In Perry RH and Green DW. Perry’s Chemical Engineers’ Handbook, 1997; McGraw-Hill, New York, NY. §11.

[9] Mukherjee R. “Effectively Design Shell-and-Tube Heat Exchangers.” Chemical Engineering Progress, 94(2), 1998, 21–38.

[10] Halle H, Chenoweth JM, Wambsganss MW. “Shellside Flow-Induced Tube Vibration in Typical Heat Exchanger Configurations: Overview of a Research Program.” Argonne National Laboratory, 1986, NTIS DE86005549.

[11] Heat Transfer Research, Inc. (HTRI), Navasota, TX. Proprietary tube-vibration analysis methods.

[12] API RP 580, Risk-Based Inspection. American Petroleum Institute, Washington, DC. (current 4th ed. 2023)

[13] API RP 581, Risk-Based Inspection Methodology. American Petroleum Institute, Washington, DC. 2000. (current 4th ed. 2025)

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