refinery piping fires

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2ND INTERNATIONAL SYMPOSIUM ON

THE MECHANICAL INTEGRITY OF PROCESS PIPING

January 30 - February 1, 1996 Houston, Texas U.S.A.

Refinery Piping Fires Resulting from Variations in Chemical Composition of

Piping Materials

Richard B. Setterlund, P.E.

Metallurgical Consultants, Inc.

P. O. Box 88046

Houston, TX 77288-0046

Abstract

A number of refinery fires in recent years are traceable to variations in the chemical composition of piping

materials. These fires are typically more destructive than those due to other causes and can take place

without warning. Some, but not all, were the result of the inadvertent use of carbon steel in alloy steel

piping systems. Others were the result of alloy welds in carbon steel systems while still others were due

to variations in residual elements leading to anomalous corrosion behavior. Recommendations are given

on areas of refinery units where the greatest need for close control of material composition exists.

Key Terms: Positive Material Identification, Refinery Fires, Piping Systems, Wet H2S service,

Sulfidation, HF Alkylation

Introduction

This paper is directed to failures in petroleum refinery piping systems that have caused serious fires. Many

refinery services involve highly flammable hydrocarbon liquid and gasses under conditions of high pressure

and/or temperature and while hydrocarbons alone are not corrosive, impurities such as sulfur components

or chemical agents added during processing can cause loss of metal which generally occurs in a uniform

manner. The combination of flammable contents and uniform metal wastage suggests the possibility of a

massive release of hydrocarbons due to failure of thinned piping. However, this rarely occurs due to the

combination of knowledge of the corrosiveness of various systems and by closely monitoring the wall

thickness of piping.

Despite these safeguards, a number of "catastrophic-type" failures have occurred in refinery piping because

one or more components had less resistance to corrosion or environmental deterioration than the balanceof the piping system. Five examples are given, all from refinery failures investigated by our firm.

Examples

Example 1

The first example is the failure of a slurry recycle line in a delayed coker unit in Canada in 1984. The line

in question was specified to be NPS 6,1 schedule 40 ASTM A 3352 grade P5 (UNS K41545) seamless



pipe having a nominal composition of 5-percent chromium and 1/2-percent molybdenum. The line

contained oil with sulfur compounds and coke particles at a temperature of 705 EF (374 EC) and a

pressure of 240 psig (1.66 MPa).

The fire was traced to the rupture of a 16-in. (406-mm) long section of carbon steel, shown in Figure 1,

that had been welded into the line approximately five years previously. The carbon steel section had athickness of only 0.090 to 0.125 in. (2.3 to 3.2 mm) prior to the failure while the adjacent pipe was

between 0.250 and 0.260 in. (6.4 to 6.6 mm) thick. The thin pipe had split longitudinally showering the

unit with hot oil and causing a fire to spread through the unit resulting in a half dozen additional pipe failures.

Figure 2 is a longitudinal metallographic section of one of the girth welds at the end of the carbon steel

section illustrating the abrupt change in wall thickness between the carbon steel section and the adjacent

5-percent chromium steel pipe and weld.

This failure was followed a number of years later by a similar failure in another coker unit in Louisiana. This

second failure was also due to the inadvertent use of a carbon steel piping component in a 5-percent

chromium, 1/2-percent molybdenum alloy steel line and also resulted in a devastating fire. In this case,however, the carbon steel component was not from a modification but from the original construction

approximately 16 years earlier.

The unit was subjected to a item by item verification of every alloy piping component prior to being placed

back in service. The oil company expected that there would be about one component per each five or six

feet of run but found that there was approximately one component for each foot of piping. Even more

disconcerting was the finding of an approximate 1.5% error rate in the piping components. Many errors

were relatively innocuous such as chemical compositions being slightly off, higher-alloys being used, or

welded pipe in systems calling for seamless, however, at least one deeply-corroded carbon steel

component was detected.

Partly as a result of these findings, the American Petroleum Institute3 has undertaken the establishment of

an industry-wide document on positive material identification (PMI). The document, RP 578,4 is now in

its initial draft and is based on PMI practices currently in use by a number of major oil companies.

Example 2

The second example is of the failure of a recycle hydrogen line in a Gulf Coast hydrocracker unit in 1994.

The failure was in a section of NPS 6 carbon steel pipe that had been welded into a 1-1/4 Cr - 1/2 Mo

(UNS K11597) hydrogen recycle line. The line contained hydrogen at a temperature of 600EF (315

EC)at a hydrogen partial pressure of 2000 psi (13.8 MPa). The total pressure was 2400 psig (16.5 MPa).

Chromium-molybdenum alloy steel is required for this application to prevent high temperature hydrogen

attack as described in API Publication 941.5

Following the fire, a section of pipe was found to be "missing" from the pipe rack. Fragments, such as

shown in Figure 3, were recovered. The fracture surfaces were flat and brittle appearing.



The failure was the result of high temperature hydrogen attack. The microstructure near the outside surface

of the pipe in Figure 4 shows hydrogen attack in its initial form. The iron carbides in the pearlite grains are

being reduced by dissolved hydrogen producing methane gas pressure in the grain boundaries producing

fissures. At the midwall of the pipe, shown in Figure 5, about one-half the carbides had been reduced

producing many cracks. Near the inside nearly all the carbides had been decomposed leaving a network of cracked grain boundaries. See Figure 6.

Investigation revealed that the failed line had been installed twelve years previously during emergency

repairs to the unit following a fire. The line containing hydrogen gas and hydrocarbons was not considered

corrosive and no ultrasonic testing had been done. Over the years the soundness of the carbon steel pipe

deteriorated due to hydrogen attack; increasing the number of internal cracks and pressure from these

cracks added to the pressure inside the pipe produced stresses sufficient to blow the pipe apart. The

explosion and resulting fire from this line had caused failures of other piping in the unit resulting in an intense

fire.

Example 3

In both previous examples, the failures were due to carbon steel components inadvertently installed in

chromium-molybdenum alloy piping systems. This is probably the most common materials error; however,

serious fires can result from the use of chromium-molybdenum filler metal in carbon steel pipe. A recent

fire was due to a welding error in a valve shop during rework of a high pressure carbon steel pressure

letdown valve from a hydrocracker unit. Five percent chromium, one-half percent alloy steel weld filler

metal was used to join carbon steel piping components.

The service conditions for the pressure letdown valve consisted of light hydrocarbons, hydrogen sulfide andmoisture at a temperature of 130EF (54EC) and a pressure of 2714 psig (18.7 MPa). The weld failed

by sulfide-stress cracking (SSC) after approximately 1-1/2 years service. The weld broke open producing

a horizontal V-shaped torch fire pattern which produced secondary flammable liquid fires in downstream

piping and equipment. The failed weld had a chromium content of approximately 4% with approximately

0.5% molybdenum. The weld root had a hardness of HRC 296 and the weld cap had a hardness of HRC

34. The cracking was confined to the hard weld deposit.

Refinery welds for carbon steel in wet H2S service are required to have a maximum hardness of 200 HB7

per NACE RP04728 to prevent SSC. This hardness limit is equivalent to less than HRC 20 on the

Rockwell hardness scale and could have been met without a postweld heat treatment (PWHT) had carbonsteel filler metal been used for the weld. The 5 Cr - 1/2 Mo filler metal that was used is hard in the as-

welded condition and even if its use had been allowed it would have been required to be PWHT by the

refinery piping code.



Example 4

The first three examples all were the result of the wrong material being used and could have been prevented

by a PMI program. The final two examples, however, show that similar type fractures can occur due to

compositional differences in material of the same classification.

The failure was in a NPS 4 schedule 80 ASTM A 539 grade B carbon steel line at the outlet of a

hydrodesulfurizer (HDS) charge heater. The line carried heavy naphtha with 0.06 percent sulfur at a

temperature of 610EF (321EC) and a pressure of 450 psig (3.1 MPa). The failure was in a short section

of pipe welded between two 90-degree ells as shown in Figure 7. It was believed that this section had

been added in the field in order to correct an interference problem.

Figure 8 shows the components from the failed line. It was determined that all components other than the

section that failed were silicon-killed carbon steel having between 0.15 and 0.30 percent silicon. The

silicon content of the part that failed was only 0.016 weight percent. Both met the ASTM A 53 grade Bspecification for carbon steel pipe which has no minimum silicon requirement.

The average wall thickness of the piece that failed was only 0.05 in. (1.3 mm) while the five silicon-killed

components had average wall thicknesses of 0.18 to 0.26 in.(4.6 to 6.6 mm) as shown in Figure 9. These

components had been thinned below the minimum wall thickness for new pipe but were above the pipe

retirement thickness shown in the API guide for inspection of refinery equipment then in force.10

Figure 10 shows a longitudinal section of a weld between the failed pipe and adjacent ell.

Field experiences have shown that the silicon content of carbon steel can have a significant effect on therate of sulfidation in hot oil service.11, 12 A failure very similar to that of Example 4 was reported to have

occurred in the feed line to a vacuum heater in a crude unit.13

Example 5

The final example, like the first example given, involved a field splice piece or "pup piece." The pup piece

was believed to have been added in the field to adjust the elevation of the inlet piping to the depropanizer

column in an HF Alkylation Unit. The depropanizer feed line was NPS 3 schedule 80 pipe having an

original nominal wall thickness of 0.216 in. (5.49 mm). It contained mostly C3 to C5 hydrocarbons along

with 0.52 percent HF and a trace of moisture at a temperature of 120E

F (48.9EC).

The 6 in. (15 cm) pup section was thinned to less than 0.05 in. (1.3 mm) wall thickness and failed. Wall

thickness measurements on the balance of the piping showed thicknesses between 0.13 and 0.20 in. (3.3

and 5.1 mm) as shown in Figure 11. The as-received sample is shown in

Figure 12. Note the uniformity of the thinning. Shortly after removal from the line, the failed section had

a rusty color as opposed to the adjacent pipe which retained a metallic color.



Chemical analyses of the corroded pup piece and the adjacent pipe showed that both conformed to the

requirements for ASTM A 53 grade B pipe and that the two samples had similar compositions. The failed

section had been deoxidized with aluminum while the adjacent pipe was semi-killed steel. Also, the pup

piece had a somewhat higher level of residual alloying elements.

ASTM A 53Adjacent Pipe Pup Piece grade B

Carbon, % 0.24 0.24 0.30 max.

Manganese, % 0.73 0.99 1.20 max.

Phosphorus, % 0.006 0.007 0.05 max.

Sulfur, % 0.026 0.024 0.06 max.

Silicon, % 0.03 0.04 -

Aluminum, % N.D. 0.02 -

Copper, % 0.01 0.01 -

Nickel, % 0.02 0.09 -Chromium, % 0.02 0.06 -

Molybdenum, % 0.02 0.07 -

(Cu+Ni+Cr), % 0.05 0.16 -

Carbon steel has good resistance to anhydrous hydrogen fluoride (HF) at temperatures up to approximately

160EF (71EC). The corrosion resistance is the result of the formation of a protective iron fluoride scale

that protects the metal from corrosion. The scale restricts the outward diffusion of iron and inward diffusion

of fluoride and the maintenance of an adherent and continuous scale is needed to keep the metal loss at a

minimum. Chromium and silicon which both reduce the rate of corrosion of carbon steel by hot H2S canincrease the rate of corrosion by hot HF.14, 15 Also, chromium, nickel, and copper have all been shown

to be detrimental to the corrosion resistance of steel to hot HF since they affect the formation of the

protective iron fluoride film.16

A recommended maximum combined content of (Cr+Ni+Cu) of 0.2 percent has been proposed for HF

service.17 The failed pup piece met the 0.2 percent combined limit illustrating that composition limits may

not be the proper criterion. The problem was not that the failed section of pipe was "bad" but rather that

it was a short section welded into "better" pipe. Had the piping system been constructed of piping with a

higher impurity level, the loss of wall thickness would have been detected and the piping replaced before

there was a risk of a fire.

Summary

The common factor in the five examples is the unexpected complete failure of a piping component resulting

in a large release of flammable contents. All took place without warning while the units were under normal

operating conditions and, in the five cases presented, the release of hydrocarbon resulted in a major fire.



Examples 1 and 2 were cases where carbon steel components were installed in low alloy steel lines. Errors

of this type are now unlikely to occur during new construction since major contractors, as well as most

refiners have strict PMI programs in force. Older units are most likely to contain material errors due to

construction before PMI programs were universally employed and, due to their age, are more likely to have

material errors due to greater amounts of maintenance welding during unit turnarounds, modifications, and

repairs. Individual alloy and carbon steel piping components can easily be segregated by field analyses prior to construction; however, once fabricated and insulated, verification becomes difficult.

The use of incorrect welding materials can also result in serious problems as shown by Example 3. This

can be overcome by quality control procedures during construction followed by PMI of alloy steel welds

to ensure that the correct filler metal is used. Field hardness testing of all welds in wet H2S environments

are recommended to ensure that errors have not produced welds that are susceptible to sulfide-stress

cracking.

Based on Examples 1, 2, and 3 and others mentioned, the following services demand use of a rigorous PMI

program.

1. Hot sulfur-bearing piping systems where chromium-molybdenum or other alloy steels are

needed for sulfidation resistance.

2. Hot hydrogen-bearing piping systems requiring chromium-molybdenum or other alloy

steels to prevent decarburization or fissuring.

3. Piping containing water and sulfide requiring control of hardness and/or stress to prevent

sulfide stress cracking.

The effect of residual elements on corrosion shown by Examples 4 and 5 represent problems that are more

difficult to control. This is due to the fact that residual elements may not be at a high enough level to be

measured by field analyses. Work is continuing on methods to separate silicon-killed steels (>0.1% Si)

from semi-killed steels (<0.1% Si), but at the present time there is no simple and reliable method to do this.

It should be noted, however, that the presence of silicon generally becomes critical only in sulfiding

conditions over approximately 550 EF (288 EC).

Corrosion by hot hydrogen fluoride is another service condition where field analyses are not appropriate

since very small amounts of alloying elements can produce a large change in the corrosion rate. This

problem is now under study by an NACE Task Group.

(18)

In most HF Alkylation units corrosion is not a problem since careful control of the moisture content can keep the corrosion rates of both high and low

impurity steels at very low levels. In those cases where a significant rate of metal loss is found it may be

necessary to make a component-by component check to ensure that the least corrosion resistant

component is located.



References

1. NPS 6 refers to six-inch nominal pipe size. This pipe has an outside diameter of 6.625 inches

(168.3 mm).

2. ASTM A 335 "Standard Specification for Seamless Ferritic Alloy-Steel Pipe for High

Temperature," Annual Book of ASTM Standards, Volume 01.01.

3. American Petroleum Institute, 1220 L. Street N.W. Washington, D.C. 20005.

4. API RP 578 "Recommend Practice for Positive Materials Identification (PMI)" (Issue Pending).

5. API Publication 941 "Steels for Hydrogen Service at Elevated Temperature and Pressures in

Petroleum Refineries and Petrochemical Plants," Fourth Edition (1990).

6. Hardness Rockwell C per ASTM E 18 "Rockwell Hardness and Rockwell Superficial Hardness

of Metallic Materials."

7. Hardness Brinell per ASTM E 103 "Rapid Indentation Hardness Testing of Metallic Materials."

8. NACE RP0472 "Methods and Controls to Prevent In-Service Environmental Cracking of Carbon

Steel Weldments in Corrosive Petroleum Refining Environments."

9. ASTM A 53 "Pipe, Steel, Black and Hot-Dipped Zinc Coated, Welded and Seamless."

10. Guide for Inspection of Refinery Equipment, Second Edition (1974), American Petroleum Institute,

Chapter XI pp. 21-24.

11. API Publication 943 "High-Temperature Crude Oil Corrosivity Studies," (1974) p. 23.

12. R. B. Setterlund, "Selecting Process Piping Materials," Hydrocarbon Processing, August 1991, pp.

93-100.

13. R. P. Buhrow, "Know Areas of Vulnerability, Safety Guidelines," Hydrocarbon Processing, August

1986, pp. 19-102.

14. Corrosion Engineering, Fontana and Greene, 2nd Edition (1978) p. 257.

15. G. Trabonellie, et al, Materials Performance, Vol. 24, June (1985) p. 33.

16. T. F. Degnan, "Materials of Construction for Hydrofluoric Acid and Hydrogen Fluoride," Process

Industries Corrosion, NACE (1986) p. 277.

17. H. H. Hashim and W. L. Valerioti, "Effect of Residual copper, Nickel and Chromium on the

Corrosion Resistance of Carbon Steel in Hydrofluoric Acid Alkylation Service," paper 623, Corrosion/93

(1993).

18. NACE Task Group T-8-20, "Materials Considerations for HF Alkylation Units."



Figure 1

Drawing showing location of failed carbon steel pup piece in Example 1.

Figure 2

Section through weld showing the difference in wall thickness between carbon

steel pup piece at right and 5% Cr - 1/2% Mo pipe at left.



Figure 3

Fractured carbon steel pipe from hydrogen recycle line in Example 2.

600X

Figure 4 Nital Etch

Microstructure showing onset of hydrogen attack.



600X

Figure 5 Nital Etch

Microstructure showing hydrogen attack in

advanced stage.

600X

Figure 6 Nital Etch

Microstructure showing hydrogen attack in final

stage.



Figure 7

View of failed piping after fire in Example 4. A pup section between the arrows had

failed.



Figure 8

Failed sections reassembled in laboratory.



Figure 9

Silicon contents and averaged wall thickness measurements of

NPS 4 schedule 80 pipe components.



Figure 10

Weld area between failed pup section at right and 90-degree ell at left.



Figure 11

Wall thickness readings made after failure of pup piece in HF

Alkylation Depropanizer Column feed line in Example 5.

.20".20"

.20"

SCH 40 ELL

.19"

.19"

.14"

.14"

.14"

.15"

.14"

SCH 40-45

6" PUP PIECE THINNED TO LESS

THAN .05" AND THEN FAILED

.19"

.15"

.15"

.14"

.14"

.15"

.22" MIN

.24" MIN

.14"

.15"

.16"

.15"

.16"

.16"

.16".16"

.19"

.13"

.13"



Figure 12

Samples from HF alkylation feed line.

The failed pup piece is at the top and the adjacent pipe at

the bottom.

refinery piping fires

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