SURVEY REVEALS NATURE OF CORROSION IN HF ALKY UNITS

J.D. Dobis
BP Oil Co.
Marcus Hook, Pa.

D.R. Clarida
Conoco Inc.
Ponca City, Okla.

J.P. Richert
Saudi Aramco/Mobil
Yanbu, Saudi Arabia

The results of a National Association of Corrosion Engineers survey of 62 HF alkylation units reveal relatively low incidence of service-related cracking of carbon steel.

Hydrogen blistering, however, is prevalent, especially in the main acid circuit and overhead condensers.

Based on these and other survey results, several recommendations are made to enable refiners to monitor and reduce corrosion in these special units.

SURVEY

The HF alkylation process has been in commercial use since World War II, when it was developed to help supply the demand for high-octane aviation fuel. Since then, carbon steels have remained the primary construction material for HF alkylation units.

Refiners should be aware, however, that the reaction between HF and carbon steel can impact the safety and reliability of HF units. For example, HF acid can promote the formation of hydrogen blisters in carbon steel pressure vessels, and has been likened to wet H,S in its propensity to induce various forms of hydrogen-induced cracking (HIC).2-4

To better understand corrosion and materials problems associated with HF alkylation units, the National Association of Corrosion Engineers (NACE) international group committee on refining industry corrosion established a special task group. One of the task group's activities was to survey plant practices and experiences.

Some of the survey's goals were:

• To identify common construction and maintenance practices

• To find common problem areas

• To assess the extent of blistering and cracking problems in pressure vessels.

Sixty-two units, representing about half the world's operating HF alkylation units built between 1942 and 1992, participated in the survey.5 Of these units, 37 were licensed by Phillips Petroleum Co., 24 by UOP, and one was a nonlicensed petrochemical process. Many of the process licensers' recommended practices are reflected in the survey results.6

To help identify recent trends, the survey was organized to compare original construction practices with those related to new construction and revamps.

CONSTRUCTION MATERIALS

Carbon steel, of course, is the most commonly used material for pressure vessels and piping. The most popular grade is ASTM SA516, especially for new construction and revamps. Pressure-vessel grades SA201 and SA212 are discontinued specifications that have been replaced by SA515 and SA516.

The predominant plate specifications, for both original and new or revamp construction, are listed in Table 1 (15058 bytes). The most common grades of fittings are:

• A105, used by 56% of the 80 responses

• A234 WPB, by 25%

• A181, by 13%

• A350, by 5%

• Other, by 1 %.

Survey results indicate an increasing trend toward the use of HIC-resistant steels for new construction and revamps. This is an attempt to minimize cracking and blistering problems associated with HIC.7

In the original construction of HF units, HIC-resistant steel was used by only 9% of the respondents. For newly constructed or revamped units, however, this figure increased to nearly 50%.

Two-thirds of the applications of HIC-resistant steel were in the main acid circuit. The remaining third were in the fractionation section, typically exchanger shells in overhead condenser service.

The survey results also indicate that, in certain services, carbon steel provides inadequate service life. A total of 31 locations reported that 55 vessels were upgraded to Monel or Monel-clad construction. Almost half the vessels upgraded were located in the acid relief gas/neutralization circuit, as shown in Table 2 (20112 bytes).

PWHT

Carbon steel is given a post-weld heat treatment (PWHT) to relieve residual welding stresses and to help soften hard weld deposits and heat-affected zones (HAZs). Hard microstructures are prone to embrittlement and cracking as a result of hydrogen absorption from the corrosion reaction of carbon steel with HF.

Hardness restrictions are an important means of preventing hydrogen stress cracking (HSC). Nearly 70% of the survey responses indicated use of HB 200 as a weld hardness limit. This limit is set forth in NACE Recommended Practice RP0472-87.8

Relief of residual stresses by PWHT also is generally accepted as a means of improving resistance to another form of hydrogen-induced damage known as stress-oriented hydrogen-induced cracking (SOHIC).

Many consider the incremental cost of PWHT to be justified as a form of insurance. The survey indicated that industry use of PWHT has increased, particularly in the case of piping welds.

Fig. 1 (29565 bytes) and Fig. 2 (27957 bytes) summarize the application of PWHT in original and new service.

SMALL-DIAMETER PIPING

The use of threaded vs. socket-welded pipe is an interesting issue that has strong industry support on both sides. The proponents of threaded pipe are concerned about the buildup of iron fluoride scale in the crevice of the socket. It is felt that this scale buildup can result in a strong wedging action that can lead to failure of the joint.

On the other hand, supporters of socket-welded pipe claim that the improved mechanical integrity leads to higher reliability. A threaded joint is more prone to fatigue cracking than a socket-welded joint. An additional concern arises from the reduction in wall thickness in the threaded area.

About 75% of the units surveyed use threaded pipe, typically 1-in. diameter or less. Only about 20% of these users indicated that they seal-weld the connection. Teflon tape is used by more than 80% of the respondents to seal threaded joints that are not welded.

Some 42% of the survey respondents indicated that socket welds are not used in their facilities. Where socket-welded pipe is used, reported size limitations ranged as high as 2 in. In most units, butt welds are required for piping sizes greater than about 1.5-2 in.

Nearly half of all respondents indicated the use of gas tungsten-arc welding for single-side welding of pipe. This method can produce high-quality, slag-free welds that drastically reduce the likelihood of pinhole leaks.

CONSTRUCTION INSPECTION

A trend toward increasing levels of inspection during new vessel construction was noted. About 80% of new vessels were fully radiographed, as opposed to little more than half of the original vessels.

Furthermore, there has been a dramatic increase in the use of magnetic-particle testing (MT) during new construction. The survey indicated that only about 4% of original vessels were inspected by MT during construction, compared to nearly half of new vessels.

As a result of the extensive, industry-wide use of MT inspection-particularly wet fluorescent magnetic particle testing-preservice inspection by these techniques is an important consideration in eliminating, or at least documenting, manufacturing discontinuities that may appear in future turnaround inspections.

BOLTING

The subject of flange bolting materials, specifically A193-B7 vs. B7M, has been widely debated within the industry. The B7M bolting is produced to a maximum specified hardness of HB 235, while the B7 bolts have no hardness control. On average, B7M studs, therefore, have slightly lower minimum yield and tensile strengths than B7 and are more resistant to hydrogen embrittlement.

Proponents of B7 bolts claim that, because of the lower strength of B7M bolts, they must be loaded to a higher percentage of their yield stress, which tends to increase susceptibility to hydrogen embrittlement. Because of their greater strength, B7 bolts reduce the risk of bolt stretching, thereby enabling better gasket seating.

Interestingly, only 14% of survey respondents indicated that any attempt had been made to control bolt loading by controlling torque.

The use of B7M studs is favored by slightly more than half of the respondents. Only 21 of the 39 units that use B7M material confirm their hardness by testing.

In a few cases, the use of more than one bolting material was reported for a single unit. Alloy bolting was among the few examples in which materials of construction other than steel or Monel were used. And, although no information about performance was given, the survey cited four applications of Hastelloy C-276 bolting and two reports of Alloy 20 bolting.

It is important to note that Monel bolts-especially high-strength Monel K-500-can experience stress corrosion cracking even in the presence of trace HF. Of the 24 sites responding to the question, 5 reported cracking problems with Monel bolts in flanges.

GASKETS

The overwhelming majority of gaskets used were Monel spiral-wound gaskets. Polyfluorinated tetra ethylene (PFTE) filler material is preferred over graphite by about 2 to 1.

BLOCK VALVES

Plug valves were cited as the preferred block valve design by 59% of respondents. Gate valves are preferred by 36% of respondents, and ball valves by 5%. No other types of valves were reported as preferred.

As for combinations of valve body and trim materials, 48% of respondents chose steel with Alloy 400, 32% chose solid Alloy 400, and 20% chose Alloy 400 with soft seat. The use of Hastelloy C-276 trim was mentioned for two units, and none chose steel with soft seat.

MAINTENANCE PRACTICES

As a general rule, maintenance practices are a reflection of licenser recommendations and individual company experience. The survey was designed to cover known areas of concern within the industry:

• Hot taps. The use, of hot taps on in-service piping is not practiced widely in HF alkylation units. The survey indicated that 72% of the respondents have never used hot taps, while another 14% have stopped the practice. The remaining 14% of respondents still use hot taps.

• Leak clamps. The practice of controlling HF acid leaks with leak clamps is used by some 65% of respondents. Of the 48 units responding on this issue, 60% permitted "re-pumps" of the clamps.

• Flange-face corrosion. Corrosion of carbon steel flange faces is a serious problem that affects nearly all HF unit operators. To help combat this problem, the use of Teflon inner rings has gained widespread usage on gaskets to help seal the flange face.

About one third of respondents indicated that damaged flange faces have been rebuilt with Monel overlay. Most refiners do not post-weld heat treat flange faces built up with Monel. Of those reporting Monel overlay of pressure-vessel flanges, only about 15% of respondents used PWHT for pressure-vessel flange repair.

• Equipment cleaning, Maintenance activities during planned turnarounds often are adversely impacted by the presence of iron fluoride scale, which forms in all HF alkylation units. This is particularly true in the case of heat-exchanger bundles, which can be difficult or even impossible to extract from the shell.

  Because of these difficulties, acid cleaning has become a common industry practice. Out of 59 responses, 75% reported using acid cleaning for turnaround preparations. The acid most commonly used, by 75% of those who clean with acid, was HCI. The remaining 25% were split equally between citric and sulfuric acid solutions.

  Neutralization is a common practice to enable equipment to be entered safely, regardless of whether acid cleaning was used. Usually, some form of ammonia or soda ash is used for neutralization. Only about 6% of respondents reported not using a neutralization procedure, as is shown in Fig. 3 (26928 bytes).

• Exchanger testing. An unusually high number of units reported using water to pressure-test heat exchangers following a turnaround. Many refiners, however, prefer to avoid using water, in order to reduce risks from corrosion when a unit is returned to service. Inert gas and alkylate are used widely, as are kerosine, diesel, and natural gas.

• Pump seals. Various types of pump seals are used in critical service; however, no clear preference was indicated by the survey results. Although nearly half the respondents indicated that the service life of seals in critical pumps was less than I year, it was not possible to correlate seal life with seal type.

The pump-seal life results were:

• 0-6 months, 12%

• 6-12 months, 36%

• 12-24 months, 34%

• 24-48 months, 16%

• Other, 2%.

Respondents reported using five seal types in critical pumps:

• Double seal, 27%

• Single seal, 27%

• Tandem seal, 20%

• Single seal with barrier fluid, 17%

• Bellows seal, 9%.

INSPECTION RESULTS

Of the 62 units participating in the survey, the respondents identified some 1,338 pressure vessels in HF or trace-HF service. The majority of these vessels (78%) were reported to have been inspected, to some degree, after being in service. Of those vessels that were not inspected, many were in units that had been commissioned only recently,

Most respondents reported the use of multiple inspection techniques; however, widespread use of magnetic particle methods was indicated. Where wet fluorescent magnetic particle testing was performed, sand or grit blasting was the preferred method of surface preparation. There are some refiners, however, who prefer not to use magnetic techniques because they require the removal of the protective fluoride scale.

CRACKING, BLISTERING

The survey was designed to reveal the types of defects found. Of the 1,044 vessels inspected, 128 (12%) were reported to have blistering, but no cracking. Another 44 vessels (5%) were reported to have cracking, but no blistering. A summary of the vessel inspection results is shown in Table 3 (15069 bytes).

Not all of the defects reported as cracks were attributed to HF-related cracking. For example, of the 44 vessels reported to have cracks, 11 were from a single unit, and the cracks were described as shallow and attributable to fabrication defects.

There were, however, several more notable cases of cracking. In four instances, HIC damage was associated with tray-ring weld toes, or welds where attachments had been removed.

A total of 11 vessels (1%) were identified as having cracks, the depth of which exceeded the corrosion allowance. A detailed accounting of these vessels is shown in Table 4 (22650 bytes).

In one vessel, weld porosity initiated a crack in a manway nozzle that had not been post-weld heat treated. The crack propagated 360 around and through the vessel wall to the reinforcing pad.

In another vessel, evidence of Sohic was verified by metallurgical analysis of the crown of a large surface-breaking blister. The blister was found in a 2-year-old, post-weld heat treated Isostripper overhead receiver constructed from A516-70.

Only one vessel was reported to have developed a leak as a result of blistering or cracking. The leak occurred after 6 years of service in a main fractionator section that had not been post-weld heat treated. Cracking initiated at the toe of a tray-support ring weld and propagated almost 180 around the 25 mm-thick portion of the vessel.

The cracked portion of the vessel was made from a grade of steel similar in composition and mechanical properties to ASTM A516-60, with a carbon equivalent of 0.44. Results of metallurgical analysis revealed high HAZ hardness.

The survey results clearly point to the predominance of blistering, which was reported by 62% of respondents. In addition, 16% reported HIC, 13% reported fabrication defects, 4% reported Sohic, and 5% reported other types of defects.

The predominance of blistering lends support to the industry's trend toward using cleaner HIC-resistant steels, although the long-term operating performance of these steels has not been proven yet.

For all the vessels reported to have some type of defect, age did not appear to be a factor. The vessel ages at which defects were found were:

• 6-10 years, 18%

• 11-15 years, 18%

• 16-20 years, 15%

• 20 years, 22%.

There did not appear to be vessels in any particular service that were free from defects. Vessels in the acid and depropanizer circuits, however, showed the most defects (primarily blisters).

These results are summarized in Table 5 (24364 bytes).

AREAS OF VULNERABILITY

Many common areas of vulnerability have been identified in HF units. The results of the survey include some 200 cases of corrosion, blistering, fouling, etc. It is important to warn against drawing specific conclusions from this information because operating conditions vary between units and, in many cases, corrosion problems are the direct result of improper operation.

Except as noted, most of the following problem areas refer to examples of unacceptably high corrosion rates:

• Acid relief system. These systems have experienced excessive corrosion both in the tower/scrubber and in the so-called nonacid relief header or downstream flare line. Remedial actions have included partial or complete renewal of the scrubber with carbon steel, or with solid or clad Monel.

• Depropanizer. The primary locations for problems in depropanizers were feed piping and tower sections at and above the feed inlet feed/bottoms exchangers, and overhead condensers. In some cases, remedial action included use of Monel piping and Monel lining of the feed section of the column.

• Isostripper and main fractionator. The main trouble spots were identified as the feed piping and tower top at and above the feed inlet line. Both corrosion and fouling predominate. Additional problems include accelerated tray corrosion and corrosion of the overhead line and overhead condensers.

• Acid regeneration/acid rerun. The most common areas of deterioration were the tower and overhead piping. In some cases, high corrosion rates of Monel have been experienced. Some respondents mentioned replacement of carbon steel overhead piping on a regular basis-sometimes at every shutdown. Drain piping from the bottom of the tower also has shown high corrosion rates.

• Propane/butane rundown systems. Consistently good operation of fluoride-removal systems should protect downstream components from corrosion. It is not always possible, however, to ensure the absence of trace amounts of water and HF in these systems and corrosion may occur at very high rates. Corrosion of piping and condensers, both upstream and downstream of fluoride-removal systems, has been found. In some cases, carbon steel was replaced by Monel.

• Scaling and plugging. Scaling of process equipment is a common problem in the industry. Plugging of both the inlet and outlet piping of safety relief valves is a serious concern. Shell-side fouling of heat exchangers can create bundle extraction problems. Services particularly prone to fouling were reported in the propane circuit, including depropanizer feed/effluent exchangers, overhead condensers, and depropanizer air coolers. Also mentioned were the feed/isobutane exchangers and propane product condenser.

• Casting quality. The quality of castings intended for HF service is a greater concern than for those used in other services. This concern underscores the need to maintain a high level of quality control for new castings.

  Because HF attacks sand and silica-containing inclusions, these types of discontinuities can lead to service-induced leaks. Furthermore, HF can readily channel through interconnected porosity. When porosity is exposed to HF-containing streams, it is susceptible to the wedging action of iron fluoride corrosion products. Castings that pass conventional pressure tests may begin to weep or leak soon after exposure to HF acid service.

• Pump casings and valve body leaks. Two thirds of respondents reported valve leaks resulting from casting defects. Six locations reported seven or more defective valves, as shown in Fig. 4 (29162 bytes). Leaks were reported in both steel and Monel valves.

The incidence of pump-casing leaks appears to be lower, although nearly half the units indicated problems with casing leaks. Four units reported five or more leaking casings. Most pump-casing leaks have occurred in carbon steel, of which the overwhelming majority of pump casings in a typical unit are made.

RECOMMENDATIONS

The survey results indicate several recommendations to help refiners monitor and reduce corrosion in HF alkylation units:

• Inspect vessels throughout the HF unit to monitor for evidence of hydrogen-related damage.

• Use low-strength, low-hardenability carbon steels for pressure vessels.

• Use post-weld heat treat fabricated components to minimize hard microstructures and reduce residual stress.

• Use magnetic particle testing, particularly wet fluorescent type, to inspect new equipment before it goes into service, and to identify fabrication anomalies.

• Use more stringent manufacturing, inspection, and testing standards for cast valve bodies and pump casings, which are susceptible to higher incidences of leaks in HF units.

ADDITIONAL INFORMATION

For more information, readers should refer to the detailed report of survey results presented at Corrosion/94.5 On the general subject of HF alkylation, including safety, materials, and inspection requirements, refer to API RP 751.9 Additional information is available on the compatibility of materials in anhydrous HF acid.10

REFERENCES

1. Frey, F.E., "Chemical and Metallurgical Engineering, 50, November 1943, pp. 126-28.

2. National Association of Corrosion Engineers technical committee Report 59-14, Summary of Questionnaire on Corrosion in HE Alkylation Units, Corrosion, Vol. 15, May 1959, pp. 237t-40t.

3. Schuyler, R.L. III, Materials Performance, Vol. 18, No. 8, 1979, pp. 916.

4. Merrick, R.D., and Bullen, M.L., "Prevention of Cracking in Wet H2S Environments," Corrosion/89, Paper No. 269.

5. Rhodes, Anne K., and Bell, Laura, "World crude capacity remains flat as conversion capability rises again," Oil & Gas Journal, Dec. 20, 1993, pp, 41-9-1.

6. Dobis, J.D., Clarida, D.R., and Richert, J.P., "A Survey of Plant Practices and Experience in HE Alkylation Units," Corrosion/94, Paper No. 511.

7. NACE Publication 8X194, "Materials and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Service," 1994.

8. NACE Standard RP0472-87, "Methods and Controls to Prevent In-Service Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments," 1994.

9. API Recommended Practice RP 751, "Safe Operation of Hydrofluoric Acid Alkylation Units," 1992.

10. NACE Publication 5A-171, "Receiving, Handling and Storing Hydrofluoric Acid," 1994 revision.

THE AUTHORS

J.D. Dobis is a senior reliability specialist at BP Oil Co.'s Marcus Hook, Pa. refinery. He has 15 years' experience with corrosion in the refining and chemical process industries. He has a BS degree in materials engineering from Rensselaer Polytechnic Institute and an MS in metallurgical engineering from the University of Illinois. He is a licensed professional engineer, a National Association of Corrosion Engineers corrosion specialist, and a fellow of the Institute of Corrosion.