Role of DSS in Refinery

7/27/2019 Role of DSS in Refinery

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The role of duplex stainless steels

in oil refinery heat exchanger applications


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Contents Page

Introduction 1

Corrosion and Fouling 2

Crude oil Feedstocks 2

Refinery Process Overview 3

Critical Refinery Applications 4

Crude Units 4

Supporting Process 6

Utilities 7

Material selection Guide 8

Heat Exchanger Materials of Construction 8

Selection Criteria for Duplex Stainless Steels

in Heat Exchangers 9

Summary 13

Further Reading 13

Reference Deliveries 14

Crude Oil Treating 14

Hydrotreating 15

Gas Cleaning 17

Waste Water Treatment 18

Cooling Water 19

Other Areas 20

Recommendations are for guidance only, and the suitability of a mate-rial for a specific application can be confirmed only when we know theactual service conditions. Continuous development may necessitate

changes in technical data without notice.

Sandvik Steel has a quality system approved by internationally recognisedbodies and holds an ASME Quality System Certificate as Material Organization.Approval to ISO 9001 is also held, as well as product approvals from TV, JISand other organizations.

We make

qualityhappen


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1

Introduction

The oil refinery represents an environmentwithin which a large variety of different

applications put a large number of

demands upon the materials used in its

construction. One critical operation within

this environment is that of the recovery of

heat from processes that can then be used

as a source of energy elsewhere in the ope-rations. The severe conditions within

which heat exchangers operate often dicta-

te the use of corrosion resistant materials

to reduce the need for maintenance, pre-vent contamination of refinery products by

corrosion products and allows the potential

to minimise heat loss caused by fouling of

equipment.

In the past, the use of AISI 300 series

austenitic stainless steels has been limited

by their inherent susceptibility to stress

corrosion cracking in chloride bearing

environments and the high cost induced by

the addition of the large quantity of nickel

that can provide protection against thisform of failure.

There now exists, however; in the form ofthe duplex alloys, Sandvik SAF 2304, SAF

2205 and SAF 2507, a family of stainless

steels that provide the optimum combina-

tion of corrosion resistance, mechanicalproperties and fabricability, to solve many

of the problems experienced in todays oil

refineries. The super duplex material, SAF

2507 can be used even in seawater cooled

exchangers up to extremely high tempera-

tures with and without chlorination. Due tothe efficient use of critical alloying ele-

ments such as chromium, molybdenum and

most notably; nitrogen these materials offer

a cost effective alternative to carbon steels,

copper base alloys, brasses and bronzes.

Duplex alloys can bridge the cost gap be-tween these traditional materials and the

expensive, nickel based and titanium alter-

natives while still giving the performance

level of the latter.

One of the great attractions of the duplex

family of alloys is its compatibility with

the other groups of alloys with respect to

fabrication. Physical properties such as the

coefficient of thermal expansion makes

retubing of carbon steel exchangers possi-ble with minimum modification. Also

expansion only joining into lowerstrength tubesheet materials such as CuNi

and Al-bronze is possible.


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Crude oil consists of hydrocarbons with small amounts

of organic and inorganic non-hydrocarbons. Crudes

can be classified according to the type of hydrocarbons

which make up their composition : i.e.

Paraffinic

Napthenic

Aromatic

Crude oils are also classified by their specific gravity,

the API classification being one of the most widely

used. This is based on a non-linear relationship to clas-

sify crudes by weight on a linear scaled hydrometer.

2

1415

Sp. gravity(60F)131.5API=

Corrosion and Fouling

Crude Oil Feedstocks

Reducing corrosion and fouling is a high priority in the

oil refining industry. These two factors can in many

cases reduce onstream time, increase maintenance and

therefore lower operating efficiency. In these times of

strong competition within the industry and in the spirit

of increased efficiency, in line with stiffening environ-

mental legislation, retrofitting operations in refineries

often involve the addition of new or improved heat

transfer equipment. Such investment can be difficult to

justify if the new equipment is still subject to corrosion

and fouling. Often chemical treatments such as chlori-

nation are employed to reduce fouling by biological

growth in cooling water. In addition to preventing such

build-up, these treatments can also increase the corro-

sivity of the cooling water by increasing the severity of

an already corrosive environment. There is therefore a

demand for cost effective solutions to the potential

problems that can be encountered in heat transfer equ-

ipment. This demand can be satisfied in many cases by

the specification and installation of duplex stainless

steels in critical applications.

An increase in API results in a decrease in gravity

meaning that a crude oil of 10 API would be a very

heavy oil.

While the nature of the crude is important from the

point of view of the processing, the hydrocarbons

themselves are not corrosive. The components of the

feedstock that can present corrosion problems during

refinery processes are those additional compounds that

are produced from a reservoir along with the crude, and

chemical addition used during processing.

Non-hydrocarbon compounds

Sulphur : 0.04% - 5% by weight in the

form of either S or H2S.

Oxygen : up to 0.5% by weight in the form

of organic acids.

Nitrogen : up to 0.25% by weight contained

in neutral nitrogen compounds.

Inorganic compounds

Water :

Inorganic salts : NaCl, MgCl2, CaCl2

Metals : up to 1000 ppm Ni, Va, Cu,

Zn, Fe

Corrosive additives and products

Neutralising agents : NaOH, NH4

Acids : Napthenic from Nitrogen con-

taining crudes, Polythionic from

reaction of water with iron sul-

phides, Hydrochloric through

hydrolysis of chlorides in

produced waters.

Deposits : Ammonium Chloride,

Ammonium Bisulphide.


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3

Fig 1. Simplified flow diagram of refinery processes.

Refining Process Overview

The object of the oil refining process is to separate the

crude feedstock into its useable constituents such as

heavy oil, asphalt, wax, kerosene and gasoline. Since

these constituents have different boiling points the pri-

mary separation can be achieved by distillation. The

lighter fractions such as naphtha and gasoline may be

removed by distillation at atmospheric pressure (hence

the term atmospheric distillation) but the heavier frac-

tions must be distilled under a vacuum in order to achi-

eve the required separation. Even after vacuum distilla-

tion, heavy bottoms exist which must be cracked using

catalysts. While simple in principal, the oil refining

process is a complex one which consists of many sta-

ges. During the different stages of the process the non-

hydrocarbon compounds and additives can cause

extensive corrosion problems throughout, either by

their original nature or due to chemical reactions with-

in the process which can result in corrosive products.

REFINERY PROCESSES

Crude Oil treatment

Crude stabilisation to prevent bumping when light

fractions boil off, and desalting carried out to control

corrosion problems that may occur later in the pro-

cess.

Distillation

Crude, vacuum, and downstream conversion unit dis-

tillation which separate molecules by their boiling

points.

Hydrotreating

Desulphurisation of distillate fractions with hydrogen

by catalytic reaction at elevated pressures.

CrackingThermal, fluid catalytic and hydrocracking are all

mehthods by which hydrocarbon molecules are re-

duced in size in order to produce molecules with lower

boiling points.

CRUDE DESALTER

ISOMERIZATION

HYDROTREATER/REFORMER

HYDROTREATERS

CRACKERS

LUBE PLANT

COKER

AROMATICSEXTRACTION

POLYMERISATION

ALKYLATION

ETHERS

GAS PLANT

COKE

ASPHALT

LUBES

HEATING OILS

DIESEL

JET FUEL

AROMATICS

GASOLINE

LPG

GAS

LIGHT NAPTHA

HEAVY NAPTHA

LIGHT GAS OIL

HEAVY GAS OIL

LUBES

ASPHALT

RESID

GAS FROM OTHER UNITS

CRUDE OIL

CRUDEDISTILLATION


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Waste water

Steam from stripper

Water

Desalted oil

Crude oil

Alkylation

Production of petroleum from light olefin containing

fractions using sulphuric or hydrofluoric acid catalysts.

Polymerisation

Light olefins are polymerised to petroleum using a

phosphoric acid containing catalyst.

Supporting Processes

Amine Unit

Amines are used to absorb hydrogen sulphide which is

then fed to the sulphur plant.

Sulphur plant

Sulphur is removed from acid gases (hydrogen

sulphide and carbon dioxide) by partial oxidation

with air.

Sour Water Stripper

Ammonia and hydrogen sulphide is removed from sour

water.

Hydrogen Plant

Natural gas and steam react catalytically to form

carbon dioxide and hydrogen. Carbon dioxide is

removed and the hydrogen is used in the hydrocracker

and hydrotreaters.

The following are critical applications in the oil refin-

ery where corrosion resistant alloys may be used to

solve specific problems :

CRUDE UNITS

Crude Oil treatmentCrude feedstocks contain traces of brine which are pro-

duced from the reservoir along with the hydrocarbon

reserves. The brines consist of Na, Mg and Ca chlori-

des. The most dangerous of these are MgCl2 and CaCl2since they can hydrolyse on heating generating hydro-

chloric acid which can condense in the overhead units

of the distillation column. NaCl is less of a hazard

since it is more stable and does not hydrolyse.

Desalting is therefore carried out prior to distillation in

order to control problems that may occur later in the

process.

4

Critical Refinery Applications

Distillation

In the distillation process crude oil is heated up to

around 300C by way of a fired heater and pump

around exchangers containing hot, distilled hydrocar-

bons. Corrosion can occur in the overhead unit of the

atmospheric column due to salts and hydrogen sulphi-

de contained in condensing water.

Subsequent to desalting, sodium hydroxide may be

added to the feedstock prior to distillation in order to

form the more stable NaCl from the traces of MgCl2and CaCl2 that may remain.

Fig 2. Crude oil desalter.

Case story 1: Crude Oil Desalter Feed Water Heater

In 1969 a German refinery decided to install the

Sandvik duplex stainless steel 3RE60 after experien-

cing rapid corrosion rates in the carbon steel feed

water heater. In fact the carbon steel unit required

retubing 12-18 months after commissioning. Even the

ferritic alloy AISI 410 failed rapidly due to pitting.

3RE60 was in service for 17 years before excessive

corrosion of the carbon steel shell dictated that the

whole unit be replaced. The unit was re-designed and

replaced with 3 exchangers fabricated from Sandvik

SAF 2205, the duplex material that superseded 3RE60.

Service Conditions: Tube side: Waste water with 700-

900 ppm chloride, pH 6

Temp : Inlet 190C

Outlet 75C

Shell side: Feed water with 2 ppm

chloride, pH 7.1

Temp : Inlet 35C

Outlet 145C

For further info see references 1 - 7


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The environment can be exacerbated by the presence

of a hydrochloric acid dewpoint. One method of pre-

venting corrosion in the overhead units is to neutralise

the condensed waters by injecting ammonia. This in

itself can present problems if solid deposits of ammo-

nium chloride form in heat exchangers under which

crevice corrosion can occur. Overhead corrosion is an

area of ongoing research and the applicability of

duplex stainless steels is still uncertain. Good perfor-

mance of certain stainless grades has been reported

although some failures have also been experienced

with lower alloy duplex stainless steels due to general

corrosion by hydrochloric acid. The super duplex alloy

SAF 2507 may provide a good alternative to Ti

although further information and application exper-

ience would be required to confirm this.

Pump around feed preheaters are also subjected to the

risk of the phenomena, commonly referred to as underdeposit corrosion, when brines entrained in the feed-

stock lie on tube surfaces under tenacious hydrocar-

bons.

These two conditions represent two extremely severe

environments for heat exchangers and result in fre-

quent retubing of carbon steels units. Tube lifetimes of

under six months for these materials are not uncom-

mon.

Fig 3. Crude oil distillation.

Case story 2: Atmospheric Distillation Feed

Effluent Exchangers

In 1993 a refinery in the UK installed the superduplex

grade Sandvik SAF 2507 to solve problems caused by

fouling of carbon steel tubes on the shell side.

Chloride containing water entrained in the crude be-

came trapped under deposits of hydrocarbon that

formed on the outside of the tubes causing under

deposit corrosion. Carbon steel tube lifetimes were

DistillationColumn

FiredHeater

Overhead

Gases

Crude Oil

5

limited to approximately 6 months. 6 different bundles

were retubed using the existing carbon steel tubesheets

by carrying out a dissimilar weld using Sandvik

25.10.4.L consumables.

Service Conditions: Tube side : Distilled hydrocarbon

fractions

Temp : Inlet 188Outlet 196C

Shell side : Crude oil feedstock with

produced water

Temp : Inlet 149C

Outlet 157C

Hydrotreating

Hydrodesulphurisation is the first upgrading step after

atmospheric distillation. The process may also be

referred to as hydrofining. The main objective of the

operation is to remove sulphur in the form of H2S by

reaction with hydrogen and can, in addition, remove

nitrogen and other impurities.

Typically hydrocarbon feed, together with hydrogen

gas is preheated to a reaction temperature of between

350 - 400C in feed effluent heat exchangers and a fur-

nace. The mixture is then passed through a down flow

fixed bed catalytic reactor, exchanges heat with the

reactor charge and is cooled to around 40C. The efflu-

ent is then flashed in high and low pressure separators.Hydrogen is recycled and H2S and other impurities are

removed by amine or caustic washing. Hydrogen sul-

phide is the main aggressive product of this process

but is often accompanied by ammonia and ammonium

chlorides.

One problem related specially to Reactor Effluent Air

Coolers (REAC) tubed with carbon steel in hydrotreat-

ing equipment is due to solid ammonium hydrosul-

phide. These solids can cause the erosion of tube ends

leading to leakage. Although further work is required

to establish firm limit SAF 2205 can be used up to

moderate leels of ammonium hydrosulphide which

would otherwise cause erosion in carbon steels.

If heat exchangers operate at temperatures above

140C, iron sulphides can precipitate on tube surfaces.

If, during shutdowns these sulphides come into contact

with moisture, polythionic acids can form which have

caused problems with intergranular corrosion and

cracking in sensitised austenitic steels. These problems

are restricted to shutdown periods since polythionic

acid is only stable at temperatures below about 30C.


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Fig 4. Hydocracker/HDS.

Case story 3 : Hydrodesulphurisation

Feed/Effluent Exchanger

Hydrogen sulphides and ammonium hydrosulphide are

aggressive to carbon steels and so 300 series stainless

steels have been tried as a solution to problems found

in these applications. Due to the chloride content

stress corrosion cracking has been a common mode of

failure in these cases. In one such case in Sweden 321

failed for precisely that reason in 1981 and was repla-

ced with Sandvik 3RE60. This early 18% Cr duplex

has recorded more than 15 years service experience in

hydrotreating applications. 3RE60 has now been suc-

ceeded by SAF 2205 as the workhorse duplex stain-

less steel, and SAF 2205 itself has notched up many

years of successful duty. In the Swedish case men-tioned above, the change from 321 to duplex also

enabled reduction of the tube wall thickness from

14BWG to 16BWG by taking advantage of the higher

yield strengths of these materials.

Service conditions : Tube side : Reactor effluent with

0.1% H2S and

10 ppm Cl

Temp : Inlet 350C

Outlet 200C

Shell side : Feed with 10-20 ppmH2S and 10 ppm Cl

Temp : Inlet 70C

Outlet 230C

For further info see references 8 - 14.

SUPPORTING PROCESSES

Sour gas cleaning

Sour gases such as CO2 and H2S are removed from

process gases by absorption in various solvents. The

most commonly used are aqueous amines (MEA or

DEA), sulphinol and potassium carbonate solutions.

After the absorption of the gases at high pressure, the

rich absorbents are regenerated by stripping off the

gases at lower pressure with steam.

These plants involve several heat exchangers exposed

to severe corrosion conditions, for example rich/lean

exchangers, regenerator reboilers, reclaimers, overhead

condensers. Carbon steel can fail due to general corro-

sion and also severe cracking can occur in welded and

bent areas.

Case story 4 : Gas Cleaning

In a Canadian refinery the carbon steel condenser fail-

ed and corrosion testing was initiated to select an

alternative material. Of the tested materials 304L fail-

ed due to pitting and stress corrosion cracking whereas

SAF 2205 performed well together with other higher

alloyed materials. SAF 2205 was supplied in the form

of U bends with the tightest radii solution annealed.

This was an interesting fabrication since the high

strength duplex material was expanded directly into a

304 tubesheet. Further information is available on the

parameters necessary to successfully perform this

potentially tricky operation. SAF 2205 has been in

service since 1987.

Service Conditions : Tube side : Steam

Shell side : Amines, CO2,

cyanides controlled by

polysulphide addition,

NH3 and H2S


6

FeedFeed preheater

Fired heater

Reactor

EffluentAir cooler

Cooler


9/24

and SAF 2507 were selected for the feed/bottoms

exchanger and condenser respectively. Since this was a

new installation the optimum materials solution could

be selected from the outset. The presence of chloride

bearing water on the cooling side and ammonia and

hydrogen sulphide on the process side meant that the

material alternatives were limited. Of the candidate

materials the duplex stainless steels offered the opti-

mum, cost effective solution. Tubes were supplied in

U bends of which the tightest radii were supplied with

the bend area solution annealed using an electric

resistance method of heat treatment.

Service Conditions :

Condenser :

SAF 2507 Tube side : Cooling water

containing 300 ppm Cl

Temp: Inlet 23C Outlet 28C

Shell side : Sour gas containing

8% NH4, 7% H2S

Temp: 115C

Feed/bottoms exchanger :

SAF 2205 Tube side : Sour water containing

180 ppm Cl, 3000

ppm NH4, 7000 ppm

H2S

Temp: Inlet 60C

Outlet 80CShell side : Stripper bottoms con-

taining 180 ppm Cl,

100 ppm NH4, 140 ppm

H2S, pH 8.17

Temp : Inlet 120C

Outlet 100C

.


UTILITIESCooling water

Cooling waters can vary in chloride content from virtu-

ally nil in de-ionised and fresh water up to 1.5% in

seawater. Water sources may also be polluted with sul-

phides, ammonia and carbon dioxide amongst others

as well as carrying entrained solids. All these factors

adjust the corrosivity of the water dictating that careful

consideration must be given to which materials may be

used in each case. Cu based materials and brasses, for

example, may corrode rapidly in polluted water and

some of the limiting parameters are given below.

Fig 5. Amine plant.

1. Sour gas in 7. Regenerator (stripper)

2. Absorber 8. Condenser

3. Rich amine 9. Accumulator (reflux drum)

4. Rich/lean heat 10. Sour Gas (CO2, H2S)

exchanger 11. Reboiler5. Lean amine 12. Steam

6. Sweet gas out

Waste water treatment

In sour water strippers, various pollutants are removed

from the water stream. Many of the pollutants, such as

chlorides, hydrogen sulphide, ammonia and carbon

dioxide are aggressive to carbon steels and copper

based alloys and brasses.

Fig 6. Waste water treatment.

Case story 6 : Sulphurous Sour Water Stripper

Feed/Bottoms Exchanger and

Condenser

Owing to the tightening of EEC limits on the sulphur

content of diesel fuel, a UK refinery installed a new

sour water stripper. Sandvik duplex steels SAF 2205

7

9

8

7

65

4

3

2

1

10

11

12

Condenser

Cooler

Stripper

Sour water

Strippedsour water


10/24

The nature of cooling, and entrained waters and the

effects of the various constituents on the corrosivity

towards duplex stainless steels are given in the subse-

quent section.

Case story 7 : Vacuum Distillation Surface Seawater

Cooled Condensers

In 1995 a Japanese refinery specified Sandvik SAF

2507 for use in seawater cooled condensers to combat

problems caused by the seawater cooling medium. A

standard 25% Cr duplex stainless steel had failed due

to pitting corrosion. SAF 2507 was specified on the

basis of its improved resistance to localised corrosion.

SAF 2507 has also been used in the same application

in Singapore to replace admiralty brass where sand

entrained in the seawater led to failure by erosion cor-

rosion at flowrates as low as 1.5 m/s.

Service Conditions : Tube side : Seawater

Temp : Inlet 24C

Outlet 35C

Shell side : Hydrocarbons +

3% H2, 5.4% N2,

0.5% CO2, 11% H2S.

Temp : Inlet 55C

Outlet 127C


HEAT EXCHANGER MATERIALS OF

CONSTRUCTION

In the refinery, the standard materials of construction

are carbon or low alloy steels. In the applications

described above, unacceptable corrosion rates can be

experienced in these types of materials if optimum pro-cess control cannot be maintained. Thus, alternative

materials are often utilised. The common candidates

for selection of heat exchanger construction materials,

giving resistance to corrosion by chloride containing or

fresh waters with varying pH are :

Copper based alloys

Brasses and bronzes

Nickel based alloys

Titanium

Stainless steels

8

Materials Selection Guide

Each of the material groups possess their own set of

advantages and disadvantages and an operating win-

dow within which they may give acceptable perform-

ance. The following comments serve to give a general

overview of the limitations of each group with regard

to application and corrosion resistance in the refinery

environment. The next section will give a more

expanded selection guide for the use duplex stainless

steels and demonstrate the broadest operating window

of all.

Copper based alloys

Copper based alloys have found wide application in

seawater and condenser type applications, mainly in

the form of the 90/10 and 70/30 CuNi types. They are

characterised by good thermal conductivity, good cor-

rosion resistance in chloride bearing environments and

relative ease of fabrication. In contrast to stainless

steels, Cu based materials rely upon their intrinsic

noble behaviour for their resistance to corrosion. They

are further protected by the insoluble corrosion pro-

ducts which form on the surface although the forma-

tion of this can be hampered by low pH solutions. The

main limitation of these materials is their sensitivity to

erosion corrosion under flowing conditions, when the

protective coating is removed, and generally it is

recommended that 90/10 CuNi and 70/30 CuNi should

not be used if the fluid velocity exceeds 2.5 and 3.5

m/s respectively.

It must also be noted that these velocity limits refer to

fluids that are free of solids. If the fluid contains an

abraident such as sand, that is commonly present in

seawater cooling streams for instance, then the velocity

restrictions must be significantly altered.

CuNi alloys are also susceptible to crevice corrosion

under salt plugs if fluid flowrates drop below 0.9 m/s.

This results in a rather narrow design envelope for

these materials when considering them for heatexchanger applications.

Cu based alloys are particularly sensitive to sulphide

attack and corrosion rates increase noticeably when the

sulphur content of cooling waters exceeds 0.007 mg/l

or when the process side H2S contents are high.

The lifetime of equipment manufactured in CuNi mate-

rials is questioned by the susceptibility to dealloying of

the nickel under conditions when high temperatures,

low velocities and high salt contents are experienced.


11/24

9

Brasses and bronzes

As with the CuNi alloys, brasses and bronzes are sus-

ceptible to erosion corrosion in fast flowing fluids. The

upper operational limit is, in the case of admiralty

brass and aluminium bronze materials, 2.4 m/s.

In case study number 7, admiralty brass tubes failed at

flow rates as low as 1.5 m/s due to the presence of

sand in the water stream.

While being more tolerant to corrosion by H2S than

the CuNis, brasses and bronzes are likely to suffer

from stress corrosion cracking by ammonia if the pH

rises above 7.2.

Again, in common with CuNi alloys, brasses and

bronzes may be prone to dealloying, of the zinc rich

phase (particularly if the material contains greater than15% zinc) under conditions giving rise to high dis-

solved salt contents, extremes in pH and high CO2contents.

Titanium

Out of the materials discussed, titanium exhibits the

highest alround corrosion resistance, and although sus-

ceptible to crevice corrosion in certain extremely seve-

re environments, is often the most attractive choice of

material to combat the variety of situations that may be

experienced in refinery heat exchangers.

Titanium, however is not without its own set of prob-

lems. Two cases where titanium is unfit for use are eit-

her when fluorides are present as a contaminant in pro-

cess fluids or cooling waters, or in handling methanol.

The main disadvantages of using titanium are often

related to the practicalities of fabricating heat ex-

changers or the retubing of existing bundles and

operations thereafter.

Titanium is an unsuitable material for retubing of ex-

isting heat exchangers, especially those that have been

retubed numerous times before. The reason for this is

that titanium is unsuitable for dissimilar welding into

tubesheets of; for example, admiralty brass or CuNi,

but then neither is it suitable for gross expanding into

enlarged holes. If the clearance of the holes to the

tubes is large then titanium is liable to split on expan-

sion, particularly at the seam in the case of seam weld-

ed tubing. This obviously makes repair expensive.

Vibrational damage of thin walled Titanium tubing

can manifest itself in the form of fatigue failure or fret-

ting if the correct baffle configuration is not incorpora-

ted into the exchanger design.

Another difficulty is related to the exceptional noble

behaviour imparted by the passive film of titanium. If

coupled to less noble materials galvanic corrosion can

take place. In the case of differing tubesheet material

this situation can be handled by applying cathodic pro-

tection to the tubesheet, but this action gives rise to the

risk of cathodic charging with hydrogen of the titanium

(this may also be the case if the tubesheet corrodes in

the absence of CP). Under these circumstances titani-

um can precipitate extremely brittle hydrides that will

damage the integrity of the equipment and possibly

lead to failure.

SELECTION CRITERIA FOR DUPLEX

STAINLESS STEELS IN HEAT

EXCHANGERS

Considerations

The process overview illustrates the location of a vari-

ety of tubular heat exchangers in certain critical appli-

cations as well as highlighting a variety of corrosive

constituents that must be taken into account when

selecting the correct duplex stainless steel. This of

course is also true in any refinery heat exchangerapplication.

Duplex stainless steels may be used in most corrosive

environments within the temperature range of approxi-

mately -50 to 300 C.

When considering which duplex stainless steel to use

in a particular heat exchanger application, the main

concern is resistance of the material to localised pitting

corrosion.

The parameters affecting the pitting tendency of agiven stainless steel can be defined as :

temperature

chloride content

oxidant content

pH

sulphide content

inhibiting ion content

flow rate

Brief consideration of these parameters enables further

simplification for grade selection;


12/24

To predict whether pitting corrosion will occur within

a given set of environmental parameters it is necessary

to relate the Critical Pitting Temperature (CPT) of the

material in that environment to the Maximum Tube

wall Temperature (MTT) that will be experienced in

the exchanger. The MTT can be calculated using the

following relation :

Fig 7. Temperature drop through a tube wall from a

hot to cold medium.

Where: U = overall heat transfer coefficient

h = individual heat transfer coefficient

R = overall heat resistance (1/U)r = individual heat resistance (1/h)

o/i = outside/inside of tube

f = fouling

w = tube wall

T(h) = temperature of hot fluid

T(c) = temperature of cold fluid

MTT = Maximum Tube wall Temperature

10

1 1 1 1 1 1U h(o) h(f,o) h(w) h(f,i) h(i)= + + + +

r(o) r(f,o) r(w) r(f,i) r(i) R

R

r(o)+r(f,o)MTT =

1

U= + + + + =

T(h) T(c)T(h)

(1)

(2)

(3)

The presence of sulphides is known to promote pitting

corrosion in stainless steels especially at low pH, BUT;

are not able to initiate pitting by themselves.

Furthermore their presence has the effect of lowering

the corrosion potential and therefore at temperatures

below the CPT actually can behave as a corrosion

inhibitor to materials exhibiting passive behaviour.

Hydrogen sulphide also has a low solubility in water at

atmospheric pressures and while being aggressive to

carbon steels, requires a high partial pressure to reach

contents required to contribute to the corrosivity of an

electrolyte when considering passive materials.

Many species present in cooling and process waters,

such as hydroxides, carbonates, sulphates, nitrates and

phosphates have an inhibiting effect on pitting.

Oxygen is the most common oxidant found in natural

waters. Its content varies between 0 - 9 ppm between

boiling and 20C. The corrosivity of the waters drops

considerably when the oxygen content drops clearly

below 1 ppm. This suggests that as cooling water

approaches its boiling point the probability of localised

corrosion drops together with the oxygen content.

Chlorine is another oxidant which is commonly added

to seawater exchangers to mitigate against biofouling.

Its effect is to considerably increase the electrochem-

ical potential and thus increase the severity of the envi-ronment. Only materials with an exceptionally high

resistance to pitting should be used in systems contain-

ing chlorinated seawater.

The pitting resistance is impaired by stagnant solu-

tions. High flowrates of chloride containing water in

tubular heat exchangers will keep the surfaces clean

both from deleterious species at pitting sites and from

fouling which could otherwise reduce heat transfer. As

a general rule flowrates below 1 m/s should be avoi-

ded.

The following 4 factors are the most critical in asses-

sing the probability of pitting attack :

high electrochemical potential

high chloride content

low pH

high temperature

Temp

Hot Fluid Cold Fluid

Tube Wall

MTT

T(h)

T(c)

r(o) r(f,o) r(w) r(f,i) r(i)

1/U

(C)


13/24

11

Thus, if the MTT is maintained below the CPT of the

material in a given set of conditions then the risk of

localised corrosion may be disregarded. Should some

of the required information not be available, a reliable,

but conservative, estimation can also be made simply

by using the temperature of the warmest corrosive

fluids on the shell or tube side.

Many years of experience have enabled Sandvik to for-

mulate a method of laboratory testing for pitting resist-

ance that has correlated well to working conditions

when compared with practical experiences.

Critical Pitting Temperature Curves

A rapid method of testing for the critical temperatures

at which localised pitting corrosion takes place has

been developed by Sandvik and utilises a potentiostat

that simulates the oxidising nature of chloride contain-

ing process fluids and cooling waters. The applied

potential maintains the constant oxidising power of the

solution in which the materials are tested. With a con-

stant potential applied, the temperature of the solution

is increased by 5C increments until localised corro-

sion is determined. This is defined as the temperature

at which the current density measured on the surface of

the sample rises above a value of 10 (A/cm2). The

method has been substantiated by comparing the

results of the testing with data collected from real heat

exchanger applications.

The following step by step method may be used for

guidance :

1. Define chloride content and MTT.

2. Define pH, presence of oxidising species and

species that may act as inhibitors.

3. Estimate oxidising character of the solution pref-erably by measuring the corrosion potential.

4. Check the diagrams and judge the applicability

of the steels under consideration. Remember

results from testing are likely to be conservative.

Fig 8. Critical pitting temperatures (CPT) for SAF 2507 and

SAF 2205 in various concentrations of sodium chloride at+600 mV vs SCE, neutral pH.

Fig 9. Critical pitting temperatures (CPT) for SAF 2507 andSAF 2205 in 3% NaCl solutions with varying pH at +600mV SCE.

Fig 10. Critical pitting temperatures (CPT) for SAF 2205

and SAF 2304 in various concentrations of sodium chlorideat +300 mV vs SCE, neutral pH.

25 Cr Duplex

SAF 2507

6878

5 10 15 20 25

Cl,%

CPT,C (F), 600 mV SCE

40(105)

50(120)

60(140)

70(160)

80(175)

90(195)

100(210)

NaCl, weight-%

SAF 2205

3 6 9 12 15

5

40(105)

60(140)

80(175)

100(210)

CPT, C (F), 600 mV SCE

1 pH4 3 2

SAF 2205

50(120)

70(160)

90(195)

SAF 25076Mo + N

25 Cr Duplex

6939b

SAF 2205

AISI 304L

SAF 2304

AISI 316L

Pitting

No pitting

CPT, C (F), 300 mV SCE

0(32)

20(68)

40(105)

60

(140)

80(175)

100(210)

Cl, weight-%

6941b

0.01 0.02 0.05 0.10 0.20 0.50 1.0 2.0


14/24

904L

40(105)

60(140)

80(175)

100(210)

120(250)

20(68)

HCOOH, weight-%

304L

316L

SAF 2507

SAF 2304

80 1000 20 40 60

Boilingpoint cur

ve

Temperature, C (F)6825b

12

General Corrosion

In certain areas of the refinery, reducing acids such as

sulphuric acid may be used in conjunction with cata-

lysts during processing. Organic acids such as acetic

acid may also form under certain process conditions.

The MTT approach may also be adopted when predic-

ting the performance of a duplex stainless steel in these

environments. The curves shown below illustrate the

temperature and acid concentration range within which

duplex stainless steels can be used while resisting

general corrosion at rates greater than 1 mm/y.

Stress Corrosion Cracking

Fig 11. SCC resistance for SAF 2507, SAF 2205 and SAF2304 in oxygen-bearing neutral chloride solutions.

Fig 12. Isocorrosion diagram for SAF 2507, SAF 2205 and

SAF 2304 in sulphuric acid (0.1 mm/year).

Fig 13. Isocorrosion diagram for SAF 2507 and SAF 2205

in hydrochloric acid (0.1 mm/year).

Fig 14. Isocorrosion diagram for SAF 2507 and SAF 2304in formic acid.

Fig 15. Corrosion rate of SAF 2507 and SAF 2205 in boil-

ing mixtures of 50% acetic acid and varying proportions offormic acid. Test time 1+3+3 days.

SAF 2304

N08028/Sanicro 28

SAF 2205

AISI 304/304L

AISI 316/316L

Temperature,C (F)

0

(32)

50(120)

100(210)

150(300)

200(390)

250(480)

300(570)

0.0001 0.001 0.01 0.1 1 10Cl, weight-%

SCC

No SCC

6877b

904L

SAF 2507No cracking

SAF 2205

Boiling point curve

SAF 2507

Temperature, C (F)

40(105)

60(140)

80

(175)

100(210)

120(250) 6946b

AISI 316L

20(68) 1 2 3

HCl, weight-%0 4 5

904L6Mo+N

40(105)

60(140)

80(175)

100(210)

120

(250)

Temperature, C (F)

80 10 20 40 60

140(285)

20(68)

904LAISI316L

AISI316L

694

Boiling point curve

SAF 2507

SAF

2205

SAF 2507

SAF 2205SAF

2304

SA

230

orros on ra e, mm year

0

0.05(2)

0.10(4)

0.15(6)

0.20(8)

0.25(10)

5 10 15 25HCOOH, weight-%

0 20

50% acetic

AISI 317L

AISI

SAF2507No attack

N08028Sanicro 28

SAF 2205

6Mo+N

30

6757b


15/24

13

Practical Aspects to Selecting Materials

While it has proved effective to select materials for

heat exchanger applications based on arbitrary labora-

tory test results, it is also necessary to consider certain

aspects of operating heat exchangers that cannot be

suitably represented in the laboratory testing.

The most important consideration is perhaps the poten-

tial for the build up of deposits in or on the tubes. Such

deposits may emanate from the process side, for exam-

ple from tenacious hydrocarbons and process slurries,

or from ammonium chloride deposits as described in

crude overhead condensers. Cooling water sources

may contain sand or sediment that can lie in horizon-

tally mounted exchangers when operated at low flow-

rates. Due consideration must be given to the possibili-

ty of crevices forming under these deposits which may

lead to corrosion taking place at temperatures lower

than the CPT of the selected material. It may notalways be necessary to specify a higher alloy duplex in

these cases but instead measures can be taken to remo-

ve the deposits periodically, or prevent them building

up in the first place. Ammonium chloride deposits are

easily removed by water washing, sediment in cooling

water may be filtered out, or exchangers operated at

higher flowrates so as to prevent the deposits building

up.

Probably; two of the most potent tools in selecting

material for the upgrading of heat exchangers are :

1. Previous experience with other materials.

What has been the mode of failure of the previously

installed unit and where have the problems occurred?

This information can be gathered during inspection.

What material solutions have been used successfully

elsewhere?

2. Reference data from plants world-wide where

duplex alloys have a proven track record over a periodof time.

These two items of information, used in combination

with the exchanger operating parameters, technical

data sheets and corrosion tables will enable effective

Hyrocarbons plus :

Water

Chlorides

Ammonia compounds

Hydrogen sulphide

Carbon dioxide

Acid Species

Varying pH

Individually or in combination many of these com-

pounds are known to have resulted in the premature

failure of Cu based alloys, brasses, bronzes and

austenitic stainless steels by corrosion.

Duplex Stainless Steels offer excellent resistance to

attack by all of the above corrosive compounds.

Laboratory produced diagrams can give good gui-

dance for materials selection based on the most criti-

cal data.

Case studies show also the excellent performance of

Duplex Stainless Steels in practical applications.

These case studies are further supported by the refer-

ences that follow this summary.

In seawater cooling applications CuNi, brasses and

bronzes are susceptible to erosion corrosion at high

flowrates. Sand entrainment in the water source can

have particularly serious consequences even at relati-

vely low fluid flowrates (ref. Case study 7).

Due to attractive fabrication properties and durability

Duplex Stainless Steels offer significant advantagesover Titanium when considering the retubing of

existing heat exchangers.

Summary

The refinery process environments described in thisbrochure can generally be characterised as follows :

Further Reading

1.White R A and Ehmke E F, Materials Selection for

Refineries and Associated Facilities, 1991, National

Association of Corrosion Engineers.

2.The Role of Stainless Steels in Industrial Heat

Exchangers, 1977, American Iron and Steel

Institute.

3.Performance of Tubular Alloy Heat Exchangers in

Seawater Service in the Chemical Process

Industries, 1987, Materials Technology Institute

of the Chemical Process Industries, Inc.

4.Corrosion Handbook for Stainless Steels, 1994,

AB Sandvik Steel.

5.Duplex Stainless Steels fighting corrosion

worldwide, 1994, AB Sandvik Steel.


16/24

4. Crude oil desalting, feed water heater

Country Japan

Size and quantity 19.05 x 1.65 x 6100 mm, 1420 m

Service conditions Tube side waste water ph 7.6

Temp inlet 105C

outlet 50C

Pressure 0.85 MPa

Shell side Feed water

Temp inlet 20C

outlet 90C

Pressure 1.8 MPa

Previous experience Carbon steel failed after 6-12 months

due to general corrosion.

Sandvik 3RE60 In service without problems between

1975 and last reference update in 1987.

3. Syncrude stabilisation

Country Germany

Size and quantity 25 x 2.5 mm, 848 m

Service conditions Tube side Cooling water

Temp inlet 25C

outlet 35C

Pressure 10 bar

Shell s ide Hydrocarbons

Temp inlet 63C

outlet 40C

Pressure 17 bar

Previous experience Not known.

Sandvik SAF 2304 Installed in 1987.

2. Crude stabilisation unit - flash gas compressor

intercooler

Country Australia

Size and quantity 25.4 x 1.65 x 12, 192 mm, 5000 m

Service conditions Tube side 15% mole fraction CO22-5 ppm HCl, 2 ppm

H2S, traces of mercap-

tans and water vapour

Temp inlet 105C

Pressure 17.2 bar

Shell side Tubes were aluminium

finned and air cooled.

Previous experience New plant.

Sandvik SAF 2205 Installed in 1982.

14

Reference Deliveries

1. Crude de-ethaniser (stabilisation) overhead condenser

Country United Kingdom

Size and quantity 19.05 x 1.65 mm

Service conditions Tube side Overhead gases,

9% CO2, 500 ppm

Temp inlet 34C

outlet 24C

Pressure 30 bar

Shell side Crude oil feed

Temp inlet 11C

outlet 20C

Pressure 16 bar

Previous experience CrMo steel failing regularly due to

under deposit corrosion on the

shell side.

Sandvik SAF 2205 Supplied in U-bends in 1994. Tightest

bend radii solution annealed using

the electrical resistance method.

Crude Oil Treating


17/24

15

7. Crude Oil Heaters

Country Germany

Size and quantity 25 x 2.5 mm, 15040 m

Service conditions Tube side Crude oil

Temp inlet 20C

outlet 60C

Pressure 25 bar

Shell side Steam from prefrac-

tionator

Temp inlet 150C

outlet 90C

Pressure 10 bar

Previous experience New installation.

Sandvik SAF 2205 Four exchangers installed 1983.

8. Desulphurisation

Country Germany

Size and quantity 20 x 2.0 x 10200 mm - 10870 mm,

2000 m

Service conditions Tube side Gasoil and hydrogen

Temp inlet 125C

outlet 70 - 80C

Pressure 3.7 MPa

Shell side Water containing 120

ppm Cl, 200 ppm sul-

phates, 3.5 mg/l zinc and

5 mg/l solids.

Previous experience Carbon steel failed after 18 months

due to general corrosion on both

process and water sides.

Sandvik 3RE60 7 years service recorded at last update.

6. Desalter / sour water exchanger

Country Spain


Service conditions Tube side Desalter effluent water

containing max 6000

ppm Cl

Temp inlet 125C

outlet 60C

Shell side Waster water to be strip-

ped with max 1000 ppm

Cl, max 5000 ppm H2S,

approx 300 ppm NH3

Temp inlet 40Coutlet 90C


Sandvik SAF 2205 Installed 1984.

5. Desalter / sour water exchanger

Country USA


Service conditions 3 different exchangers

Tube side waste water from

desalter

Temp max 138C

Shell side Treated water from sour

water stripper containing

(NH4)2SO4, Na2SO4

(3000 ppm SO42)

pH 9.0 - 9.5

Temp max 96C

Previous experience Carbon steel (13BWG) failed in less

than one year. Admiralty brass showed

a corrosion rate of 5 mils/year.

Sandvik 3RE60 10 years service with no corrosion

reported.

Hydrotreating


18/24

16

11. Hydrocracker effluent air cooler in atmospheric

residuum desulphurisation unit

Country Canada

Size and quantity 25.4 x 3.05 mm, 16000 m

Service conditions Tube side H2 pp 1880 psi, H2S pp

59 psi, NH3 pp 7.4 psi

and steam.

Temp inlet max 262C

Pressure total 2480 psiShell side Air


Sandvik SAF 2304 Delivered 1986.

12. Desulphurisation

Country Iraq


Service conditions Tube side Process gas

Temp inlet 385C

outlet 190C

Pressure 19.4 bar

Shell side Boiler feed water

Temp inlet 105C

outlet 199C

Previous experience Unknown.

Sandvik SAF 2205 Installed 1986.

10. Reactor effluent exchanger


Size and quantity 19.05 x 2.11 and 1.65 mm, 9300 m

Service conditions Tube side Pre-treated effluent.Hydrocarbons containing

approx 10 ppm Cl and

traces of H2S.

Temp inlet 38C

outlet 278C

Pressure 0.85 MPa

Shell side Reactor effluent.

Hydrocarbons with FeS

deposits forming on tube

surfaces.

Temp inlet max 354C

Previous experience General corrosion of carbon steel in

the lower tubes. Pitting of AISI 321

in the upper tubes. Alkaline wash

during shutdowns to prevent poly-

thionic acid attack, together with

NaHCO3 and N2 purging.

Sandvik SAF 2205 Installed in 1983. Tubes delivered

from stock.

9. Feed / effluent exchanger in a catalytic

hydrodesulphuriser

Country Singapore

Size and quantity 19.05 x 2.11, 2500 m

Service conditions Tube side Reactor effluent contain-

ing traces of chlorides.

Temp inlet 345C

outlet 230C

Pressure 2.9 MPa

Shell side Feed (light virgin

naptha)

Temp inlet 135C

outlet 315C

Pressure 3.3 MPa.

Previous experience AISI 321 failed due to stress corrosion

cracking.

Sandvik 3RE60 7 years service recorded.

Reference deliveries


19/24

17

15. Overhead condenser in recovery section

Country Brazil

Size and quantity 19.05 x 1.65 x 4880 - 6100 mm,

1880 m

Service conditions Tube side Water containing

chlorides

Temp 45C

Shell side 98% H2S

Temp 120C

Previous experience Carbon steel failed after 3 months.


16. Overhead condenser in DEA washing unit.

Country Netherlands


Service conditions Tube side Gas containing H2S,

water, CO2, NH4 and

traces of DEA, oxygen

and acetonitril

Temp inlet 95 - 105C

Shell side Brackish water with

1000 - 1200 ppm Cl

Previous experience Galvanised carbon steel failed after

9-12 months due to pitting corrosion.

Aluminium brass had a service life of

2 years but were attacked by DEA and

ammonia.

Sandvik 3RE60 Installed 1972.

14. Hydrotreating

Country Netherlands


Service conditions Tube side Reactor product contain-

ing 2-3% H2S and

ammonia

Temp inlet 380C

outlet 250C

Pressure 60 bar

Shell side Hydrocarbons

Temp inlet 125C

outlet 300C

Pressure 1.8 MPa

Previous experience AISI failed due to stress corrosion

cracking.

Sandvik SAF 2205 Three exchangers installed in 1983.

Tube wall reduced to 16 BWG from

the 14 BWG austenitic tubes used

previously.

13. Hydrodesulphurisation

Country France


Service conditions Tube side Steam

Temp inlet 340C

outlet 300C

Pressure 22 bar MPa

Shell side Gasoil, H2O, NH4HS

Temp inlet 140C

outlet 170C

Pressure 19.5 bar

Previous experience C-steel, A179, lasted 3 years.

Sandvik SAF 2205 Exchanger installed 1987.

Gas Cleaning


20/24

19. Feed / effluent exchanger

Country Finland

Size and quantity 19.05 x 1.65 mm x 4880 mm, 250 m

Service conditions Tube side Untreated water with

5000 ppm H2S, 90 ppm

mercaptans, 10 - 30

ppm Cl; pH 7.

Temp inlet 30C

outlet 100C

Pressure 1.0 MPaShell side Treated water with

ppm H2S, 15 ppm mer-

captans, 25 ppm thio-

sulphate; pH 9-11.

Temp inlet 150C

outlet 60C

Pressure 1.0 MPa

Previous experience AISI 430 was attacked by pitting after

6 months, 316L had a lifetime of less

than 6 months due to stress corrosion

cracking.


20. Feed / effluent exchanger

Country Japan

Size and quantity 19.05 x 1.65 mm x 6000 mm, 1320 m

Service conditions Tube side Untreated water from

topping unit.

Temp inlet 95C

outlet 110C

Pressure 0.75 MPa

Shell side Water from stripper

Temp inlet 130C

outlet 115C

Pressure 1.1 MPa

Previous experience New application.

Sandvik 3RE60 Commissioned 1974.

18. Lean DEA cooler

Country Australia

Size and quantity 19.05 x 1.65, 259 m

Service conditions Tube side Recirculating cooling

water with

600 -1000 ppm Cl

Temp inlet 30C

outlet 34C

Pressure 6.2 bar

Shell side 25% DEA solution in

H2O

Temp inlet 79C

outlet 45C

Pressure 13 bar


Sandvik SAF 2205 Commissioned 1983.

17. Lean amine condenser

Country Australia


Service conditions Tube side Recirculating cooling

water with 600 - 1000

ppm Cl inhibited with

chromates

Temp inlet 30C

outlet 33C

Pressure 6.2 bar

Shell side H2S and H2O

Temp inlet 114C

outlet 46C

Pressure 6 bar


Sandvik SAF 2205 Commissioned 1983.


18

Waste Water Treatment


21/24

24. Heat exchanger

Country Finland


Service conditions Tube side Brackish seawater.

Shell side Butane, deposits contain-

ing 1-3% inorganic

fluorides

Temp inlet 80C

outlet 30C

Previous experience Titanium tubes were used but failed

on the process side due to the fluor-

ides after only 3 months. SAF 2507

offered the ideal solution due to its

excellent resistance to both media.

Sandvik SAF 2507 Delivered 1990, process temperature

raised from 40 to 80 C at that time.

23. Vacuum distillation overhead condenser



Service conditions Tube side Seawater.

Temp inlet 20C

outlet 40C

Shell side Hydrocarbons

Temp inlet 240C

outlet 100C

Previous experience Formerly tubed with admiralty brass

but corrosion rates were unaccept-

ably high. SAF 2507 expanded

directly into admiralty brass

tubesheet.


21. Stripper feed / bottom exchanger

Country USA


Service conditions Tube side Water containing

Cl, 34 ppm CO2 and

44 ppm H2S

Temp inlet 35C

outlet 102C

Pressure 4 bar

Shell side Stripped condensate

Temp inlet 122C

outlet 59C

Previous experience Not known.

Sandvik SAF 2304 Tubes in service for a year before the

unit was decommissioned. Tubes still

in good condition at that time.

Cooling Water

19

22. Stripper Reboiler

Country Taiwan

Size and quantity 19.05 x 1.24 mm, 221 tubes

Service conditions Tube side Low pressure steam

Av. temp 141C

Shell side Reboiling water pH 9.3,

22.924 mg/l H2S,

140 mg/l NH3,

268 mg/l Cl

Av. temp 127C

Previous experience 316L failed after 18 months due to

SCC.

Sandvik SAF 2507 Delivered beginning 1997.


22/24

27. Aromatics



Service conditions Tube side Hydrocarbons

Temp max 340C

Pressure 0.75 MPa

Shell side Thermex heat transfer

fluid

Temp inlet 400Coutlet 300C

Previous experience 5% Cr steel failing regularly every

18 months. Suspected corrosion due

to polythionic acid attack during

shutdowns.

Sandvik SAF 2304 Delivered in 1992. tubes still in

excellent condition.

28. Paraxylene

Country Indonesia

Size and quantity 25.4 x 2.11mm supplied in U-bends

Service conditions Tube side Steam

Temp max 390C

Shell side Sulfoline, hydrocarbons

and traces of water

Previous experience Unknown.

Sandvik SAF 2507 Delivered in 1995.

20

26. Reactor effluent cooler

Country Australia


Service conditions Tube side Hydrocarbons,

1.7% H2S and traces of

ammonia

Temp inlet 138C

outlet 40C

Pressure 62 bar

Shell side Seawater

Temp inlet 27C

outlet 37C

Pressure 2.8 bar



Other Areas


25. Seawater condenser

Country Germany

Size and quantity 25 x 1.65 mm

Service conditions Tube side Seawater

Temp inlet 28C

outlet 45C

Shell side Dichloromethane,

dichloroethane

Temp inlet 200C

outlet 100C

Previous experience UNS S31803 failed due to pitting

after 3 years of service.

Sandvik SAF 2507 First unit commissioned in 1989,

second unit delivered 1990.


23/24

21

29. Splitter tower overhead condenser

Country USA

Size and quantity 19.05 x 2.11 mm AW x 6400 m

Service conditions Tube side Cooling water

250 ppm Cl

Shell side Propane

Temp 38-43C

Previous experience Corrosion problem due to low velocity

fouling on tube side causing under

deposit corrosion on carbon steel tubes.

Carbon steel lasted less than 2 years.

Sandvik SAF 2507 In service Dec. 1995.


24/24

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SingaporePhone 265 22 77, Fax 264 11 78

Slovak Republic

SANDVIK SLOVAKIA s.r.o.BratislavaPhone 07-531 24 97, Fax 07-531 24 87

South Africa

SANDVIK (Pty) Ltd.BenoniPhone 011-914-3400,Fax 011-914 48 34

South KoreaSANDVIK KOREA Ltd.SeoulPhone 02-785 17 61/8, Fax 02-784 35 95

SpainSANDVIK ESPANOLA S.A.Martorelles, BarcelonaPhone 93-571 75 00, Fax 93-571 75 55

Sweden

SANDVIK STLFRSLJNINGS ABStockholmPhone 08-793 05 00, Fax 08-793 05 29

SwitzerlandSANDVIK AGSpreitenbachPhone 056-417 61 11, Fax 056-401 54 80

TaiwanSANDVIK TAIWAN Ltd .Taipei HsienPhone 02-22 99 34 27, Fax 02-22 99 78 49

Thailand

SANDVIK THAILAND Ltd.BangkokPhone 02-379 46 61, Fax 02-379 46 41

TurkeySANDVIK End.Mam.San ve Tic. A.S.

KartalPhone 216-309 15 15, Fax 216-377 00 26

United Kingdom

SANDVIK STEEL U.K.Halesowen,West MidlandsPhone 0121-504 51 00, Fax 0121-504 51 51

U.S.A.SANDVIK STEEL Co.Tube and Wire DivisionsScranton, PAPhone 717-587-5191, Fax 717-586 17 22

Strip DivisionBenton Harbor,MIPhone 616-926-72 41, Fax 616-926 27 18

Venezuela

SANDVIK VENEZUELA C.A.

CaracasPhone 02-945 09 22, Fax 02-941 72 09

VietnamnSANDVIK SOUTH EAST ASIA Pte.Ltd.Ho Chi Minh CityPhone 08-846 57 50, Fax 08-823 00 14

Zambia

SANDVIK (ZAMBIA) Ltd.NdolaPhone 02-65 09 29, Fax 02-65 01 76

Zimbabwe

SANDVIK (PRIVATE) Ltd.HararePhone 4-62 10 95, Fax 4-62 10 99

inSwed

enonchlorinefreepaper.Sanmedia/SandvikensTryckeri

S-1541-ENG,O t b 1997 AB Sandvik Steel SE 811 81 Sandviken Sweden Phone: 46 26 26 30 00

Documents

Role of DSS in Refinery