Proceedings of the 5th International Conference on Integrity-Reliability-Failure, Porto/Portugal 24-28 July 2016

Editors J.F. Silva Gomes and S.A. Meguid

Publ. INEGI/FEUP (2016)

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PAPER REF: 6270

DETERMINATION OF THE ROOT CAUSES OF THE PREMATURE

DEGRADATION OF A REBOILER

Filipe Nascimento(*)

, Paula Gorjão Ferreira, Celso Araújo

Instituto de Soldadura e Qualidade (ISQ), Porto Salvo, Oeiras, Portugal (*)Email: fmnascimento@isq.pt

ABSTRACT

This work focuses on the determination of the root causes of the premature degradation of a

reboiler based on a material characterization methodology. The results were supported by

historical data of the component. An evaluation of the component was also performed to

suggest corrective measures to minimize or even to avoid the problem in the future.

Keywords: Reboiler, sulfidation, thinning, petroleum industry.

INTRODUCTION

In petroleum refining industry the materials are in contact with a variety of corrosion agents

that can affect their performance. It has been identified a high number of corrosion problems

and protection measures are taken into account in the design stage of a factory. However, in

certain cases it is hard to predict if a certain part will corrode and the determination of the root

causes is important in order to protect and prevent failure of the part in a working factory.

A compilation of the usual problems that can occur in petrochemical industry have been

carried out which includes mechanical, metallurgical and corrosion problems that can occur

(API, 2011). Jahromi and Janghorban tried to determine the corrosion causes of the corrosion

of aircoolers in an oil refinery. It was reported that there is a decrease in the crude oil quality

with the increase of sulfur and salt content and that the desalter did not have the capacity to

remove the sulfur and salt content. The author identified that the observed corrosion was

probably due to hydrogen chloride and sulfide corrosion. Ghasemi (Ghasemi, 2011) studied

the effects of sulfidation and erosion on carbon steel tubes used in petroleum refining

industries.

Some authors have focused their studies in the effects of different environments on the

materials properties of steel. Otero et al. (Otero, 1995) have studied the effect of different

aggressive environments in steels and suggested a mechanism of the coating stability and

conditions for coating according to the tested conditions. Otero et al. (Otero, 1996) have also

proposed surface treatments to carbon steels P5 and P22 to increase its resistance to oxidation

and sulfidation phenomena. Zhou et al. (Zhou, 2013) have studied the effects of hydrogen

permeation in an H2S environment in API-X52 pipeline steels. Zhou et al. (Zhou, 2014) have

also tested the variation of the hydrogen permeation in different solutions. Lee et al. (Lee,

1996) studied the effectiveness of Nb-Al-Si to sulfidation. The authors observed the

formation of a bilayer, an outer layer of Al3S2 and an inner layer of NbS2, and confirmed that

the inner layer was very likely responsible for the higher resistance to sulfidation. Qu et al.

(Qu, 2006) evaluated the interaction naphthenic acid corrosion and sulphidic corrosion on

different steels tested in synthetic refining media. The high variety of problems in this

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industry has ranged a high variety of research areas due to its need to solve these impending

problems.

This case study focuses on a reboiler working in a debutanizer unit whose tube bundle had

been considered not to be threatened by a critical damage mechanism under normal working

conditions. However, after a short working period leakage was detected. It was observed that

the leakage was related to high corrosion of the tubes at a specific location of the tube bundle,

mainly on the top tubes, where an accumulation of scale was also observed. This paper

presents the root causes that lead to the damage mechanism and suggests some changes to

avoid this problem. The methodology for the determination of the root cause, focusing on the

metallurgical and chemical analysis of the corroded tubes and its scale products, was

implemented to identify the corrosion mechanism associated to the tube bundle of a reboiler

type Kettle.

PROBLEM DESCRIPTION

The present paper presents a failure analysis of a tube related to a leakage found in a tube

bandle installed inside of a reboiler type Kettle (Fig .1). This reboiler belongs to a debutanizer

unit, which has a fractional distillation column used to separate butane from natural gas

during the refining process. “Reboilers are used to generate a flux of vapor to feed, in general,

a tower.” (Hewitt, 2011) Reboilers type Kettle are widely used in petroleum and chemical

industries which operation consists of the entrance of a liquid, that comes from a column, into

the shell in which there is a horizontal tube bundle. The liquid will boil when in contact with

the outside surface of this tube bundle and vapour will flow back to the column.

Fig. 1 - Schematic of a Kettle reboiler (Hewitt, 2011)

The present case study focus on the replacement of a tube bundle of a reboiler due to leakage

detected during a hydro-test. A visual analysis was performed on the replaced tube bundle and

it was found that, top half of the bundle, starting from tube sheet to half of the length, where

the leakage took place, was found jammed with tube external corrosion scales and slug and

further inspection revealed that tubes in that location were thinned with 90% metal loss.

Tubesheet

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BACKGROUND HISTORY

The historical composition of the inlet / outlet streams was checked for presence of any

corrosive components which might be the cause for corrosion. Primarily the deviations in the

levels of the chemical compounds like H2S, RSH and chlorides were checked. The following

observations were made:

- the average H2S content of sour gas remained at an average of 5.5 mole % against

design composition (design case) of 7.1 mole %;

- the RSH (mercaptans) in natural gas liquids (NGL) have shown an increasing trend

reaching a value of 870 ppm against the design composition (design case) of 900 ppm;

- the condensate sample was analysed for RSH content and found to have 544 ppm

against the design composition of 1330 ppm;

- it was also confirmed that there were multiple low level excursions resulting in to

unsubmergence and overheating of tubes up to 250-260 deg C.

RESULTS

Characterization of the corroded tubes

According to the design, the tubes of the tube bundle are made of SA334 grade 6 steel (Table

1) with a diameter of 25.4mm and 2.67mm in thickness. A set of tubes comprised of degraded

tubes (from the top half of the tube bundle) and non-degraded (from the bottom half of the

tube bundle) were received. It was confirmed that the tubes had signs of thickness loss

(Fig.2).

Table 1 - Chemical composition of the SA334 grade 6 steel

Chemical composition (%)

C Mn P S Si

0.3max 0.20–1.06 0.025 (max) 0.025 (max) 0.10 (min)

Fig. 2 - An example of the received tubes with no visible thickness loss, on the left-hand side, and one with

visible thickness loss, indicated by arrows, on the right hand-side.

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Table 2 presents the results of the diameter measurements carried for three of the tubes. On

the basis of the diameter design value (25.4mm), the results clearly show a loss of thickness

from the outside surface in two of them (tubes 1 and 2).

Table 2 - Values of the outer diameter (in mm), measured by a caliper and their locations.

Section / Position

Tube a/0o a/90o b/0o b/90o c/0o c/90o

1 21.62 21.60 21.65 21.68 21.38 21.44

2 21.50 21.49 21.34 21.94 21.61 21.60

3 25.50 25.58 25.61 25.43 25.52 25.51

Metallographic analysis

Samples from tube 1 and 3 were prepared for metallographic analysis. As shown in Fig.3,

tube 1 presents a significant thickness reduction associated with an irregular outer surface

profile as a consequence of a corrosion degradation mechanism, whereas tube 3 presents a

smoother profile without a visible degradation mechanism. Values of thickness of these two

tubes are shown in Table 3. It can be verified that the corroded tube (tube 1) presents an

average thickness loss of 1.8 to 2mm when compare to the design thickness value (2.67 mm).

With respect to tube 3, the measured values where similar or even higher than the design one.

These tubes show a similar microstructure of ferrite and pearlite (Fig.4 a). Tube 1 (Fig.4 b)

shows some small corrosion pits in the outer surface

Table 3 - Thickness measurement of the tubes in different locations

Tube Position/Thickness (mm)

1 2 3o 4 5 6 7 8

1 0.73 0.89 0.76 0.92 0.82 0.86 0.83 0.63

3 2.82 2.87 2.86 2.75 2.71 2.77 2.69 2.84

a b

c

c

b a

0o 0

o

90o

90o

1 2

3

4 5

6

7

8

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Fig. 3 - Profile of a transversal section of: a) tube 1 and b) tube 3.

Fig. 4 - Micrographs of the tube: a) representative image of the tubes microstructure and b) irregular surface

profile in the outer tube diameter.

Hardness testing

Vickers Hardness test were performed on a Shimadzu HSV-20 durometer, according to ISO

6507-1:2005, in the metallographically prepared cross sections of tubes 1 and 3. Average

values of 140HV for tube 1 and 130HV for tube 3 were obtained and they are within the

ASTM SA334 grade 6 specification, which established hardness values lower than 190HV.

(a) (b)

(a) (b)

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X-ray diffraction (XRD) of scales

Fig. 5 - Analysis of the received deposits with the identification of hematite (in grey) and pyrite (in green).

XRD analysis of scales was performed on a Rigaku Miniflex equipment. This test was

performed to identify the composition of the scales found on the surface of the tube bundle

tubes. The analysis allowed the identification of iron sulfide (FeS2) and iron oxide (Fe2O3) in

crystalline phase (Figure 5).

Scanning Electron Microscopy (SEM) coupled with Electron Dispersive Spectroscopy

(EDS)

Fig. 6 - Analysis in a deposit inside a crack near the surface showing a high content in sulfur: a) identification of

the crack and b) EDS analysis

The cross section of tube 1 prepared for metallography was analysed with a Scanning

Electron Microscope (SEM) JEOL JSM-6500F coupled with an Oxford Instruments EDS

analyzer. An EDS analysis on an unidentified deposit inside the crack showing a very high

content in sulfur (S) and iron (Fe). The MEV imaging has shown the presence of several pits

on the outer surface of the tube with the propagation of small cracks inside the tube (Figure

6).

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CONCLUSION

The analysis performed in the tubes showed that the corrosion of the analysed reboiler tubes

is typical of high temperature known as sulfidation, characterized by the thinning of the tubes

together with the presence of sulphur on the outer surface and in the inside of the cracks

nucleated from the outer surface. Furthermore, the corrosion scales are composed by iron

sulphide amongst other compounds, which are typical features related to the sulfidation

damage mechanism.

It was identified that the core of the increased corrosion rate by sulfidation is related to the

increase of mercaptans on the system. The specific location for the corrosion phenomenon, as

referred for the top half of the tubes of the tube bundle, was due to the multiple low level

liquid excursions resulting into unsubmergence and overheating of tubes up to 250-260 deg C.

Overheating up to 250 - 260 deg C creates the possibility of getting RSH converted

catalytically into H2S and corrodes the tubes at much faster rate than expected. The damaged

identified is a consequence of the tubes exposure to the vaporized liquid due to

unsubmergence of the top half of the bundle as a result of an insufficient height of the weir

plate, leading to overheating and concentration of sulphur compounds on the outer surfaces.

There is a possible relationship between the accumulation of scale and corrosion occurring

only in half tube length. Assuming that such correlation exists, then one can expect that the

liquid outside the tubes will clean up the scale only on half the tube length and hence

decrease/avoid corrosion in that part of the bundle. This situation occurs due to the flow

pattern of the liquid on the shell side and the position of the inlet nozzle, which creates a

stagnant zone of fluid on the part of the bundle closer to the tubesheet. The scale will then

accumulate on the stagnant zone, creating corrosion on that part of the bundle.

In order to minimize or even prevent the reoccurrence of sulfidation on the outer surface of

the tubes the following recommendations were drawn:

• guarantee that the reboiler tubes should be always submerged, completely washed by

the liquid by:

� increasing the height of the weir plate to guarantee adequate volume of liquid

inside of the reboiler along with the installation of an automatic control for

temperature and liquid level;

• upgrading to a higher chromium alloy can also be considered to increase the resistance

to sulfidation.

REFERENCES

[1]-American Petroleum Institute. Damage Mechanisms Affecting Fixed Equipment in the

Refining Industry. API Recommended Practise 571, 2011.

[2]-Ghasemi H. High temperature sulfidation of carbon steel heater tubes in gas condensate

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[3]-Hewitt, GF. Reboilers. 2011, DOI: 10.1615/AtoZ.r.reboilers – Retrieved March 04, 2016,

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