Elevated Temperature Failure
Mechanisms in Ammonia Plant
Equipment – Reducing the
Risk of Failure
Ammonia plant equipment operates at elevated temperatures and is exposed to environments that can potentially result in life-limiting conditions or failure of the equipment. This paper discusses some of
these elevated-temperature failure mechanisms, causes of the elevated-temperature failure mecha-nisms, indicators of the mechamecha-nisms, types of equipment impacted, and ways to reduce the risk.
Michael W. Hester, P.E. Cherokee Nitrogen Company a Subsidiary of LSB Industries, Inc.
Daniel J. Benac, P.E.
Baker Engineering and Risk Consultants, Inc.
lthough elevated-temperature failure mechanisms are known, the condition of the equipment may be unknown or there may be unknown operating condi-tions that may lead to failure. Some of the ele-vated temperature failure mechanisms common to ammonia plant equipment discussed in this paper are: high temperature hydrogen attack (HTHA), metal dusting, nitriding, oxidation, stress relaxation cracking, overheating, and creep.
It is important to understand these elevated-temperature failure mechanisms, causes of the elevated-temperature failure mechanisms, indi-cators of the mechanism, and types of equip-ment impacted in order to reduce the risk of
failure by identifying and understanding the un-known.
Introduction
How do you know if equipment has been deteri-orated by exposure to elevated temperatures? This question is frequently asked by ammonia plant personnel who use piping, heat exchangers and pressure vessels that contain steam and gas mixtures containing hydrogen at elevated tem-peratures. Failures of gas-containing equipment can result in fires, explosions, fatal accidents, and loss of production. These days, plants can-not afford to be down and must operate under required process safety management (PSM) principles or strict regulatory requirements.
This paper discusses some of the elevated-temperature failure mechanisms, necessary safe-ty considerations, and controls used by plant de-signers and operators to reduce the risk of fail-ure of such equipment.
Elevated Temperature Failure
At ambient temperatures and in the absence of a corrosive environment, the life of a component in steady-state load conditions may be unlimited, provided that operating loads do not exceed the yield strength of the material. In contrast, the life of a metal component at elevated temperature when subjected to either steady or fluctuating stress may be limited. An elevated temperature is typically the temperature where the strength of a material begins to reduce.
When designing and operating equipment, it is important to identify the potential elevated tem-perature failure mechanisms. If the failure mechanisms for crack initiation and/or crack propagation are not properly identified and if the operating conditions are not monitored, the equipment life expectancy may be less.
Risk and Risk Reduction
Risk from failure is often considered using two separate terms - the likelihood that a failure will occur and the consequence of a failure [1]. Ele-vated-temperature failures often have a high consequence, meaning a business interruption or possible injury. A plant operator can enable risk reduction by identifying how a component could fail (the mechanism of failure), and assuring that proper controls are in place to reduce the likeli-hood of this failure mechanism. Some of these controls involve equipment material selection, detailed management of change (MOC) reviews, non-destructive inspections and testing, moni-toring actual operating temperatures, and safe operating limit alarms. Even so, elevated-temperature failures can still occur because some condition was not known.
High Temperature Hydrogen
Attack (HTHA) Phenomenon
During the development of the ammonia process in the early 1900’s, Carl Bosch and his team ob-served repeated failures of pilot plant reactors. We know today these failures had the typical features of hydrogen attack [2]. Beginning with research performed in the 1940’s, equipment exposed to hydrogen at elevated temperatures has been found to potentially degrade over time [3]. High-temperature exposure of carbon and low-alloy steels to high-pressure hydrogen leads to a special form of degradation known as high temperature hydrogen attack (HTHA). This phenomenon is not the same as hydrogen em-brittlement, which degrades toughness at low temperatures. HTHA leads to degradation of material properties at elevated operating tem-peratures.
Like hydrogen embrittlement, HTHA can result in sudden and catastrophic brittle failure. Sev-eral such historical events have occurred. Equipment in hydrogen service at pressures greater than 0.8 MPa (100 psig) and at tempera-tures of 230 °C (450 °F) or above are suscepti-ble to HTHA.
Figures 1, 2 and 3 show the risk of HTHA at an older ammonia plant in which equipment was made from carbon steel or other inappropriate materials.
Figure 1. Likely HTHA locations near the high temperature shift converter
Figure 2. Likely HTHA locations near the methanator
Figure 3. Likely HTHA locations near the am-monia converter
Table 1 shows operating conditions for an older ammonia plant where HTHA could occur.
Equipment Typical Temp (°C/°F) Typical Press (psig) H2 Partial Pressure (psia) Ammonia Converter Outlet 243-254 (470-490) 3200-3400 1600-1700 High Temp Shift Converter 349-365 (660-690) 215 105 to 110 Methanator Outlet 310 (590) 165 110 to 115
Table 1. Typical operating conditions
Under the influence of certain temperature con-ditions and hydrogen partial pressure, atomic hydrogen permeates the steel and reduces iron carbide (Fe3C) in the steel to form methane
(CH4). This process causes decarburization to
occur in the steel. The methane does not diffuse from the metal so its pressure may build and ex-ceed the cohesive strength of the metal, causing fissuring between grains, blisters and cracks. When fissuring occurs, the ductility of the metal is significantly and permanently reduced.
An example of fissuring can be seen in Figure 4. Often the heat affected zone (HAZ) of the weld experiences the worst HTHA due to the instabil-ity of the carbides at the HAZ. For this reason, the base metal and the HAZ should have HTHA inspections performed to determine whether or not attack has occurred.
Figure 4. Hydrogen-damaged carbon steel line at the heat affected zone (HAZ). The decarburi-zation and fissuring region is caused by hydro-gen depleting the iron carbides. Nital etch. (Original magnification 200x)
The severity of HTHA rises with increasing temperature and hydrogen partial pressure [4]. In some recent HTHA incidents, failures were reported to have occurred at welds that were not stress-relieved [5]. If the stress-relieved condi-tion is unknown, HTHA inspeccondi-tions should be performed.
HTHA Material Controls
To prevent elevated-temperature failures, the proper material for the intended operating con-ditions must be selected. The choice of material is based on the stress, temperature, and envi-ronment. The designer and user needs to know the stress condition, the pressure, the tempera-ture, the cyclic condition, the chemical envi-ronment, and the susceptibility of a material to metallurgical instability. Without this infor-mation, an incorrect selection can be made, re-sulting in a compromised failure mechanism. It is also important that the material is not al-tered, changed, or degraded during operation. For this reason, quality assurance controls and process monitoring should be in place to reduce the risk of failure. For HTHA, the operating limits for steels can be determined using the
op-erating temperature and hydrogen partial pres-sure, as originally discussed by Nelson in 1949 and in API Recommended Practice 941 [6]. Since the 1970’s, empirical data has been col-lected from operating plants and tests to estab-lish operating limits of carbon steel and low al-loy steel equipment in hydrogen service at elevated temperatures. API 941 provides guid-ance. For example, if the normal operating con-ditions are a temperature of 288 ºC (550 ºF) and 13.79 MPa (2,000 psig) hydrogen partial pres-sure as illustrated in Figure 5, the carbon steel in this case is not suitable for this service under those conditions.
Figure 5. Illustration of API 941 (Nelson) curve used for material selection for equipment ex-posed to hydrogen at elevated temperature
HTHA Operating Controls
To perform an assessment of HTHA susceptibil-ity, the operating conditions of the equipment must be known. “Typical” or “possible” design limits are not sufficient. A good HTHA as-sessment requires validation of data with pro-cess engineering involvement and actual field data. The key parameter is that the actual condi-tions to which the metal wall has been exposed must be known. Parameters considered in an evaluation are as follows:
Material of construction (Form U1 and vali-dated using Positive Material Identification PMI)
Stress relief (Yes or No) Lining (Yes or No)
Design operating temperature and pressure Actual operating temperature and pressure HAZ
Hydrogen percent in gas phase Hydrogen partial pressure API 941 curve location
Degrees above or below the API 941 curve at a specific hydrogen partial pressure To determine the actual conditions, the location of temperature and pressure measurements is important. The measurement location is vital because without the indicators in the proper place, the actual condition is not known.
Also, atypical operating conditions can also change the local metal wall temperatures. For example, fouling that could occur in a heat ex-changer could increase the actual metal wall temperature.
Plant operations should consider the following practices to reduce the risk of HTHA failures: 1. Consult with experienced individuals who
understand the HTHA phenomenon as well as the API 941 recommended practices.
2. Use actual operating temperatures for HTHA susceptibility, and validate that the actual operating temperatures and pressures are below the API 941 curve by a defined amount.
3. Place pressure and temperature indicators at locations that measure the actual operating conditions of equipment that could be sus-ceptible to HTHA.
4. Provide definite safe operating limits with necessary process alarms and a response plan for when those limits are exceeded. 5. Establish a safety factor approach such as
limiting the equipment operating tempera-ture to 50 ºF (28 ºC) below the API 941 curve.
6. Perform regular process hazard assessment of the operating conditions including chang-es in prchang-essure, temperaturchang-es, or composition of hydrogen.
7. Determine whether gradual increases in pro-cess production, temperature and pressure have occurred (“process creep”) that may af-fect the material.
8. Evaluate material or operating changes us-ing a management of change (MOC) pro-cess.
9. Evaluate whether temperature excursions have an effect on HTHA susceptibility. HTHA Inspection Practices
HTHA inspection requires special inspection techniques. Inspection methods used for surface corrosion and wall thinning are not adequate for detecting HTHA. HTHA is a subsurface phe-nomenon and not readily evident on the surface. The optimum method(s) and frequency of in-spection for HTHA should be determined for specific equipment.
Some of the accepted HTHA inspection practic-es include the following:
Advanced Ultrasonic Backscatter Techniques (AUBT) - Ultrasonic waves backscattered from within the metal are used to evaluate subsurface microstructural features and the depth of region affected.
Phased Array - Phased Array is an ultrasonic technique based on generating and receiving ul-trasound waves. Instead of a single transducer and beam, phased arrays use multiple ultrasonic elements and electronic time delays to create beams by constructive and destructive interfer-ence.
In-situ metallography - This method evaluates selected surfaces by polishing, etching, and rep-licating the microstructure using acetate tapes. It is limited to small locations and addresses on-ly the surface of the material.
Positive Material Identification (PMI) - PMI is a program that is used to verify that the material in use or intended to be used is the one speci-fied. During fabrication, installation, or mainte-nance activities, it is possible to use the wrong material. The practice of PMI has identified in-correct materials in hydrogen service [7]. While such mistakes are not a common occurrence, it
has happened often enough to warrant the use of a proactive PMI program. Do not depend on material certificates alone to validate that the material is correct.
HTHA Considerations for Lined Equipment For corrosion protection, vessels are sometimes clad, lined, or weld-overlaid to protect the ves-sel surface. This lining can provide protection provided hydrogen does not diffuse through the liner or migrate behind the lining or cladding. If hydrogen gets behind the liner, the vessel wall may be susceptible to HTHA.
Refractory lining is often used to insulate a pipe or vessel to limit the metal wall temperature. It is an effective way to reduce the effects of HTHA. The effectiveness of refractory lining is compromised if it degrades, cracks, or deterio-rates over time. When it is compromised, hot spots form that elevate the metal wall tempera-ture, which may exceed the HTHA operating limits of the equipment. Figure 6 illustrates how a hot spot from degraded refractory lining can increase the risk of HTHA for a carbon steel line.
Figure 6. Illustration of API 941 (Nelson) curve demonstrating the effect of damaged refractory
One way to monitor the condition of the refrac-tory is to perform regular infrared imaging of the equipment (shown in Figure 7).
Figure 7. Infrared image of refractory lined equipment (note hot spots in red)
To reduce the risk of HTHA failures and to de-termine if attack has occurred, the following in-spection practices should be considered:
1. Select inspection methods and establish in-spection frequencies that will detect the ini-tial stages of HTHA.
2. Assure written inspection procedures are in place and implemented to provide inspection guidelines and intervals.
3. Know the history of the equipment, and if unknown, make sure necessary HTHA in-spections are performed.
4. Perform base-line PMI on all equipment constructed of alloy materials, and ensure PMI covers all components.
5. Perform PMI at regular intervals, especially during installation of new equipment, weld-ing of equipment, and durweld-ing maintenance operations.
6. Assure that proper foundation support for re-fractory-lined equipment is present to reduce flexure of the refractory.
7. Perform regular infrared inspections on re-fractory-lined equipment, ensure the operat-ing limit is understood, and take appropriate actions if the limit is exceeded.
8. Document all findings in an inspection pro-gram and follow-up to ensure findings are appropriately acted upon.
Elevated-Temperature Surface
Interactions
Typical surface interactions in ammonia plant equipment include oxidation, metal dusting (carburization) and nitriding. If equipment sub-ject to these conditions is not properly moni-tored and regularly inspected, these surface at-tack mechanisms can lead to shutdown.
Oxidation
Oxidation of metals within gaseous environ-ments in the presence of oxygen has long been recognized as a severe limitation to the utiliza-tion of metals at high temperatures. The devel-opment of alloys for use at elevated tempera-tures, therefore, usually is aimed at improving oxidation resistance.
The amount of oxidation in carbon steels below 538 °C (1000 °F) is negligible. Above that temperature, the oxidation rate increases rapid-ly. The most important alloying element used to increase oxidation resistance is chromium. Re-sistance to oxidation increases with the chromi-um content.
A 300 Series stainless steel with about 18 per-cent chromium resists oxidation to about 704 to 760 °C (1300 to 1400 °F) [8]. For higher tem-peratures, the chromium oxide loses its protec-tive capability, so alloys with more nickel and aluminum are used to provide greater protec-tion. Generally, oxidation results in wall thin-ning, but intergranular attack of the surface can also occur. Figure 8 shows oxidation and inter-granular attack that occurred in a Type 316 stainless steel liner that was inadvertently ex-posed to hot syngas at elevated temperatures.
Figure 8. Oxidation and intergranular attack of a Type 316 stainless steel liner exposed to hot syngas (unetched)
Metal Dusting
Metal dusting, similar to oxidation attack, has been known to occur in ammonia plant equip-ment. Metal dusting is distinguished from con-ventional oxidation attack because it occurs ran-domly in localized areas and progresses more rapidly. An example of where metal dusting could occur is shown in Figure 9.
Figure 9. Likely locations where creep, oxida-tion and metal dusting could occur in the prima-ry and secondaprima-ry reformer regions
The cause of this highly accelerated and rapid attack is related to the high localized residual carburization that results in thinning or pitting. Metal dusting generally takes place at
tempera-tures from 480 to 815 °C (900 to 1500 °F), alt-hough it has occurred at temperatures as high as 1095 °C (2000 °F). It requires a strong reducing atmosphere such as those found with high CO concentrations [8]. Typical equipment exposed to possible metal dusting are tubing and piping from reformed gas [9].
Nitriding
Nitriding of equipment in ammonia converters has been known to occur [10]. The nitriding mechanism is as follows:
Attack occurs above 316 °C (600 °F). Adsorption of ammonia into the metal
sur-face.
Decomposition of ammonia to nitrogen and hydrogen.
Diffusion of the nitrogen into the steel to form a hard and brittle nitride layer.
Cracking of the layer when stressed. Ways to Mitigate Surface Interactions
Often, the surface kinetics are determined by the temperature, gas composition, and the alloy used. Because the process conditions often can-not be changed, the material or surface has to be changed. To reduce the risk of surface degrada-tion, the following can be considered:
1. For oxidation resistance, use more corro-sion-resistant materials with higher chromi-um and nickel content.
2. For nitriding resistance, use alloys with a higher nickel content to avoid the formation of brittle chromium and iron nitrides.
3. For metal dusting, sometimes a protective layer can be used, such as aluminum diffu-sion treatment. Also, consider using a high-er nickel or chromium alloy such as alloy 800 H/HT, alloy 617, alloy 601 or alloy 602.
Stress Relaxation Cracking
Austenitic stainless steels used to prevent corro-sion mechanisms (such as metal dusting) can embrittle and form cracks when exposed to
cer-tain elevated temperatures [11]. These cracks are called stress relaxation cracking. It occurs in austenitic alloys operating between 550 ºC to 750 ºC (1022 to 1382 °F) [12, 13]. This mecha-nism is also referred to as strain-age cracking, stress-induced cracking, reheat cracking, and stress-assisted grain boundary oxidation (SAGBO). The fracture is often brittle in ap-pearance and occurs in cold worked regions, frequently in the proximity of welds. The cracks are located along grain boundaries where fine precipitates can form at elevated tempera-tures, causing the grain boundary to lose ductili-ty and crack when strained. One such crack is shown in Figure 10.
Figure 10. An Alloy 800 tube showing cracks along the grain boundaries
Typically, stress relaxation cracking occurs at hardness above HV 200. Residual welding and applied stresses of welded structures that are highly constrained and exposed to these temper-atures are prone to failure. Also, modifications made to existing equipment are prone to fail suddenly if not carefully evaluated [14]. Be-cause these high nickel and chromium alloys have good corrosion resistance, sometimes it is overlooked that certain operating conditions can cause cracking.
To reduce the risk of stress relaxation cracking, the following should be considered:
1. Review new designs and modifications to consider if the changes will subject the ma-terial to stress relaxation cracking.
2. Validate that the proper heat treatment of material is provided during fabrication and that the material is not age-hardened.
3. Ensure that the material will not experience excursions due to improper cooling or ex-cessive thermal exposure.
4. Evaluate support and fixtures for welded structures to ensure that the structure is not too rigid and constrained.
5. Perform visual and non-destructive inspec-tion of rigid locainspec-tions.
6. Perform the proper post-weld stress relief on any repairs or modifications.
Overheating Failures
One of the most common causes of equipment failure is overheating which results in a stress or short term (rapid) creep rupture, sometimes in unexpected locations. Overheating caused by hot gas impingement occurred in a high temper-ature shift (HTS) vessel. The gas distributor in the top nozzle of the vessel had broken vanes, shown in Figure 11.
Figure 11. Location of broken distribution vane that caused impingement of hot gas on the shell
The intent of this design modification was to al-low for the gas to be diffused, instead of direct flow through an open-ended pipe. However,
when the vane failed, an unknown overheating condition occurred on the shell wall. The result-ing uneven distribution of gas caused hot gas to impinge on the shell wall. No issue was sus-pected until a routine internal inspection was performed. Figure 12 shows the result of the impingement.
Figure 12. Localized overheating on the inside of the HTS due to hot gas impingement
Elevated-temperature failures can be prevented by reducing the metal surface temperature using protective coatings, cooling methods, or by con-trolling deposit and scale formation. To protect components, they are often coated with a high-temperature or thermal barrier coating or refrac-tory material. The effectiveness of the coating can deteriorate with time.
An example of an overheat failure in a waste heat boiler is shown in Figure 13. The inadvert-ent loss of refractory protection caused the car-bon steel wall temperature to increase. As a re-sult, cracking occurred at the carbon steel manway, shown in Figure 14. Infrared thermog-raphy is a good method that can be used to mon-itor the condition of refractory.
Figure 13. Cracked waste heat boiler manway
Figure 14. Crack in the manway nozzle HAZ
Creep Failures in Components of
Steam Reformers
Stress produced at elevated temperature produc-es a condition of continuous strain called “creep.” By definition, creep is deformation as a function of time at constant load or stress. Af-ter a period of time, creep will Af-terminate in a stress-rupture fracture, also known as creep-rupture. Conditions under which creep and stress-rupture occur depend on the alloy, magni-tude of stress, and time. As such, creep failures can occur over a wide range of temperatures. Creep strength (i.e., the resistance to creep de-formation) of a metal is determined by a variety of factors such as composition, how the material is processed by melting and de-oxidation
prac-tice, grain size, heat treatment, and the actual magnitude of the stress. Typical components that experience creep failure are heater and fur-nace tubes, and reformer equipment and piping. In ammonia production, reformers are used to produce a hydrogen-rich synthesis gas from a mixture of steam and natural gas at high pres-sures and elevated temperatures. A typical re-former consists of a brick-lined combustion chamber that supplies heat to a series of tubes containing catalyst and the steam-gas feed mix-ture. The steam-gas mixture, preheated to 425 to 650 °C (800 to 1200 °F) is introduced to the tubes, which in turn heats the gas mixture to 705 to 1040 °C (1300 to 1900 °F) to form synthesis gas.
The cause of heater tube and other equipment failures varies, yet one of the most common causes is overheating, which results in a stress or creep rupture.
A reformer tube stress “creep” rupture failure is shown in Figure 15. The stress rupture fracture is identified by minimal bulging, axial crack ex-tension, internal cracking (Figure 16), and mi-crovoid formation (Figure 17).
Figure 15. Creep rupture of a reformer catalyst tube
Figure 16. Cross-section of a reformer tube showing the fissuring and cracking at the ID surface
Figure 17. Microstructure showing the coales-cence and alignment of microvoids and subsur-face fissuring at the ID sursubsur-face (unetched)
Although creep failures are known in radiant tubes, failures can occur when not expected. Since overheating can be a major contributor that causes stress rupture, the following question is often asked: How long will reformer heater
tubes last if they are subjected to an excursion?
Beginning with research performed in 1928 at the University of Michigan [15], tube lifetime has been researched to understand the factors
that influence high temperature tube strength. Even though the degradation phenomena that occur in tubes are now better understood, tube failure is still a concern to the plant operator. A stress rupture failure can be avoided if the heater tube’s estimated remaining life is known. API Standard 530, “Calculation of Heater Tube Thickness in Petroleum Refineries,” offers guidance on remaining tube life, heater tube de-sign, and wall thickness.
One way to predict the time for failure is to per-form a life assessment of the tube. Life assess-ment methods for time dependent failure mech-anisms are well established [16, 17]. The most common methods examine the in-situ micro-structure of the tube for changes. This approach is effective, provided there is historical data available on the condition of the tube, and a cor-relation to tube strength can be made.
Another approach is to conduct stress rupture tests [18] and compare the tested life values to the Larson Miller creep rupture curve, a sample of which is shown in Figure 18 [19].
Figure 18. HP material Larson-Miller curve
To reduce the risk of reformer tube failures due to overheating and creep, the following should be considered:
1. Monitor actual operating temperature and minimize localized hot spots.
2. Perform dimensioning to determine if de-formation (bulging) has occurred.
3. Perform microstructural analysis or stress rupture testing, comparing good material to material exposed to elevated temperatures. 4. Perform a life assessment.
SUMMARY
Failure of ammonia plant equipment can be pre-vented through good material selection, process controls, detailed reviews that consider elevat-ed-temperature failure mechanisms, and regular inspection of equipment. Because many of the elevated temperature failure mechanisms are now better understood and inspection methods are more reliable, elevated temperature failures in ammonia plant equipment can be avoided. When proper safety considerations and controls are established, the risk of elevated temperature failures is greatly reduced for ammonia plants. Failures still can occur due to unknown degra-dation of equipment and piping, but the likeli-hood can be reduced if the following are active-ly pursued:
1. Take into account the limitations and possi-ble elevated temperature failure mechanisms when selecting materials of construction. 2. Identify specific elevated temperature
mech-anisms and discuss during the management of change (MOC) process. The MOC pro-cess must consider whether changes will af-fect the materials and equipment.
3. Know and validate the actual operating con-ditions to determine whether a material is operating in a susceptible range for the spe-cific failure mechanism.
4. Select and use the proper inspection method for the specific failure mechanism.
5. Employ a proactive inspection program to ensure the proper material is in place, and whether a material has been altered or de-graded.
6. Understand how long a component may last, such as a radiant tube, by performing life
as-sessments to reduce the occurrence of sur-prise failures.
REFERENCES
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[14] D.J. Benac, D. B. Olson, and M. Urzen-dowski, “High-temperature Stress Relaxa-tion Cracking and Stress Ruptured Ob-served in a Coke Gasifier Failure” Journal of Failure Analysis and Prevention, June 2011, Vol. 11(3), pp. 251-264.
[15] The Timken Roller Bearing Company, “Digest for Steels for High Temperature Service, 6th Edition 1957.
[16] F.R. Larson and J. Miller, “A Time-Temperature Relationship for Rupture and Creep Stresses,” Trans. ASME, July 1952, p 765–775.
[17] D.J. Benac, “Failure Analysis and Life As-sessment of Structural Components,” Fail-ure Analysis and Prevention, ASM Hand-book, Vol. 11, 2002, pp. 228-242.
[18] D.J. Benac, Failure Avoidance Brief: Es-timating Heater Tube Life,” Practical Fail-ure Analysis, February 2009, Vol. 9(1), pp. 5-7.
[19] MetalTek, Data sheet for 25-35Nb, Dated February 7, 2002.
