In the name of Allah

Corrosion Problems in Austenitic Stainless Steel Systemns and its Protection

By

Nasir Hussain

DHDS Unit

Pak Arab Refinery

Contents:

1. Introduction

2. Minimum pressurization temperature

3. What happens when MPT is not established during pressurization

4. Temperature Embrittlement

5. Hydrogen Diffusion or Hydrogen Embrittlement

6. Brittle fracture

7. Wet H2S corrosion

8. Types of corrosions in hydrotreating unit.

9. Protection of Austenitic Stainless steam

10. Summary

1. Introduction:

A Distillate DHDS unit reactor is constructed of 1¼ Cr - ½ Mo base metal, with a

lining of stainless steel Type 347. This choice of alloys gives the high strength of the base metal

and the excellent corrosion resistance of the inner lining. It is not only subject to severe

pressure and temperature but also to a specific corrosive environment caused by gases like

H2S, NH3 and H2 resulting from the hydrotreating reaction.

Since corrosion cracking of austenitic stainless steel can lead to failure of the equipment

involved, it is of the utmost importance that this equipment be properly protected to prevent

corrosive environments from occurring.

Austenitic stainless steels are those of the "300 series," the compositions of which are nominally

18 percent chromium and 8 percent nickel. The most common types used in the petroleum

industry are Types 304, 316, 321 and 347. Because of their inherent high temperature strength

properties and high corrosion resistance, they are particularly suitable for use in hydrocracking

units in areas of moderate and high temperature, and where substantial resistance to hydrogen

sulfide corrosion is required, such as in heater tubes, reactor, reactor combined feed

exchangers and piping. Types 321 and 347 are stabilized to minimize intergranular carbide

precipitation and are preferred because they are more resistant to the intergranular corrosion

cracking caused by polythionic acid attack, which can occur particularly during downtime

periods when exposed to air and moisture. Since these stabilized grades are not completely

immune to intergranular corrosion cracking, special handling procedures are recommended for

the protection of these materials as well as the unstabilized grades.

To avoid any corrosion effects on the ASS, there are some recommendations of the designer

which must be followed.

One of these recommendations is to establish temperature before pressurization to the reaction

pressure, which is called minimum pressurization temperature.

2. MPT:

A primary concern for end-users is the definition of the Minimum Pressurizing

Temperature (MPT) of the equipment. This temperature is the lowest temperature at which the

vessel can be re-pressurized after shutdown and insures no risk of brittle failure of the

containment body. The MPT is defined by fracture mechanics

It is very important to establish minimum pressurization temperature, in

order to ensure the safety of the reactors during start ups and reactor cool down. It is advisable

to use a lower temperature for full pressure, which is more economic. A reasonable threshold

value of reactor’s skin temperatures is recommended by the vendor for pressurization, which is

93C at 10.95 Kg/cm2 system pressure. The establishment of minimum pressurization

temperature accommodated the potential of temper embrittlement and hydrogen embrittlement.

What happens when MPT is not established?

During start ups or shut downs, there is If MPT procedure is not followed this will result in

temperature embrittlement, Brittle fracture and Hydrogen assisted embrittlement will start

causing failure of the material.

3. Temperature Embrittlement:

Temper embrittlement is the reduction in toughness due to a

metallurgical change that can occur in some low alloy steels as a result of long term exposure in

the temperature range of about 343 C to 577 C. This change causes an upward shift in the

ductile-to-brittle transition temperature. Although the loss of toughness is not evident at

operating temperature, equipment that is temper embrittled may be susceptible to brittle fracture

during start-up and shutdown.

Appearance or Morphology of Damage

a) Temper embrittlement is a metallurgical change that is not readily apparent and can be

confirmed through impact testing. Damage due to temper embrittlement may result in

catastrophic brittle fracture.

b) Temper embrittlement can be identified by an upward shift in the ductile-to-brittle transition

temperature, as compared to the non-embrittled or de-embrittled material. Another important

characteristic of temper embrittlement is that there is no effect on the upper shelf energy.

Prevention / Mitigation

a) Existing Materials

i) Temper embrittlement cannot be prevented if the material contains critical levels of the

embrittling impurity elements and is exposed in the embrittling temperature range.

ii) To minimize the possibility of brittle fracture during startup and shutdown, many refiners use a

pressurization sequence to limit system pressure to about 25 percent of the maximum design

pressure for temperatures below a Minimum Pressurization Temperature (MPT). Note that MPT

is not a single point but rather a pressure-temperature envelope which defines safe operating

conditions to minimize the likelihood of brittle fracture.

iii) MPT’s generally range from 171oC for the earliest, most highly temper embrittled steels,

down to 52oC or lower for newer, temper embrittlement resistant steels (as required to also

minimize effects of hydrogen embrittlement).

iv) If weld repairs are required, the effects of temper embrittlement can be temporarily reversed

(deembrittled) by heating at 1150°F (620°C) for two hours per inch of thickness, and rapidly

cooling to room temperature. It is important to note that re-embrittlement will occur over time if

the material is re-exposed to the embrittling temperature range.

4. Hydrogen Embrittlement:

A loss in ductility of high strength steels due to the penetration of

atomic hydrogen can lead to brittle cracking. Hydrogen Embrittlement (HE) can occur during

manufacturing, welding, or from services that can charge hydrogen into the steel in an aqueous,

corrosive, or a gaseous environment. Hydrogen Embrittlement and hydrogen attack results

when atomic hydrogen penetrates onto the grain boundaries of steel producing micro cracks,

blistering and loss of ductility. The atomic hydrogen combines into molecules, cannot escape,

resulting in blistering and laminations.

Critical Factors

a) Three conditions must be satisfied:

Hydrogen must be present at a critical concentration within the steel/alloy.

The strength level and microstructure of the steel/alloy must be susceptible to

embrittlement.

A stress above the threshold for HE must be present from residual stresses and/or

applied stresses.

b) The hydrogen can come from:

Welding – if wet electrodes or high moisture content flux weld electrodes are used,

hydrogen can be charged into the steel (delayed cracking).

Cleaning and pickling in acid solutions.

Service in high temperature hydrogen gas atmospheres, molecular hydrogen dissociates

to form atomic hydrogen that can diffuse into the steel.

Wet H2S services or HF acid services in which atomic hydrogen diffuses into the steel.

(Cyanides, arsenic and FeS can act as hydrogen recombination poisons that diminish

the hydrogen gas reaction and allows for greater charging rates.)

Manufacturing – melting practices or manufacturing processes particularly where

components are plated (hydrogen flaking).

c) The effect is pronounced at temperatures from ambient to about 300°F (149°C). Effects

decrease with increasing temperature.

d) HE affects static properties to a much greater extent than impact properties. If the hydrogen

is present and a sufficient stress is applied, failure can occur quickly.

e) The amount of trapped hydrogen depends on the environment, surface reactions and the

presence of hydrogen traps in the metal such as imperfections, inclusions and pre-existing flaws

or cracks.

f) The amount of hydrogen needed to have a measurable effect on the mechanical properties

varies with the strength level, microstructure and heat treatment for the alloy. In some cases,

thresholds of critical hydrogen concentrations have been established.

h) Thick wall components are more vulnerable due to increased thermal stress and high

restraint and take longer for hydrogen to diffuse out.

i) In general, as strength increases, susceptibility to H E increases. Certain microstructures,

such as untempered martensite and pearlite, are more susceptible at the same strength level

than tempered martensite.

Affected Units or Equipment

a) Services where HE is a concern include carbon steel piping and vessels in wet H2S services

in FCC, hydroprocessing, amine, sour water services and HF alkylation units. However, mild

steel used for vessels and piping in most refining, fossil utility and process applications have low

hardness and are usually not susceptible to HE except at weldments, particularly the HAZ, if

suitable PWHT is not performed.

b) Storage spheres are often made of slightly higher strength steels and are more susceptible

than most other refinery equipment.

c) Bolts and springs made of high strength steel are very prone to HE. (Alloys that have a

tensile strength above 150 ksi can absorb hydrogen during electroplating and crack.)

d) Cr-Mo reactors, drums and exchanger shells on hydroprocessing units and catalytic

reforming units are susceptible if the weld heat-affected zone hardness exceeds 235 BHN.

Appearance or Morphology of Damage

a) Cracking due to HE can initiate sub-surface, but in most cases is surface breaking

b) HE occurs at locations of high residual or tri-axial stresses (notches, restraint) and where the

microstructure is conducive, such as in weld HAZ’s.

c) On a macro-scale, there is often little evidence, although some materials will appear to have

brittle fracture surfaces. On a microscale, the material will contain less ductile fracture surface,

but must often be compared to a fracture without the presence of hydrogen.

d) In higher strength steels, cracking is often intergranular.

Hydrogen embrittlement is a cause of concern for high-strength reactor steels during

shutdown conditions. At typical hydropocessing temperatures and hydrogen partial pressures,

hydrogen diffuses easily throughout the reactor wall, and hydrogen concentration level reaches

about 6-7 ppm maximum. When the reactor is cooled down to rapidly to permit the diluted

hydrogen to diffuse out of the steel, delayed hydrogen cracking may occur. Embrittlement

usually takes place below 150°C.

5. Brittle Fracture

Brittle fracture is the sudden rapid fracture under stress (residual or applied)

where the material exhibits little or no evidence of ductility or plastic deformation.

Affected Materials

Carbon steels and low alloy steels are of prime concern, particularly older steels, 300,400

Series SS are also susceptible.

Critical Factors

a) For a material containing a flaw, brittle fracture can occur when the critical combination of

three factors is fulfilled:

i) The materials’ fracture toughness (resistance to crack like flaws)

ii) The size, shape and stress concentration effect of a flaw;

iii) The amount of residual and applied stresses on the flaw.

b) Susceptibility to brittle fracture may be increased by the presence of embrittling phases.

c) Steel cleanliness and grain size have a significant influence on toughness and resistance to

brittle fracture.

d) Thicker material sections also have a lower resistance to brittle fracture due to higher

constraint which increases triaxial stresses at the crack tip.

e) In most cases, brittle fracture occurs only at temperatures below the ductile-to-brittle

transition temperature, the point at which the toughness of the material drops off sharply.

Affected Units or Equipment

a) Equipment manufactured to the ASME Boiler and Pressure Vessel Code, Section VIII,

Division 1, prior to the December 1987 Addenda, were made with limited restrictions on notch

toughness for vessels operating at cold temperatures. However, this does not mean that all

vessels fabricated prior to this date will be subject to brittle fracture. Many designers specified

supplemental impact tests on equipment that was intended to be in cold service.

b) Most processes run at elevated temperature so the main concern is for brittle fracture during

startup, shutdown, or hydrotest/tightness testing. Thick wall equipment on any unit should be

considered.

c) Brittle fracture can occur during ambient temperature hydrotesting due to high stresses and

low toughness at the testing temperature.

Appearance or Morphology of Damage

a) Cracks will typically be straight, non-branching, and largely devoid of any associated plastic

deformation (although fine shear lips may be found along the free edge of the fracture, or

localized necking around the crack.

b) Microscopically, the fracture surface will be composed largely of cleavage, with limited

intergranular cracking and very little micro void coalescence.

Prevention / Mitigation

a) For new equipment, brittle fracture is best prevented by using materials specifically designed

for low temperature.

b) Brittle fracture is an “event” driven damage mechanism. For existing materials, where the

right combination of stress, material toughness and flaw size govern the probability of the event,

an engineering study can be performed in accordance with API RP 579, Section 3, Level 1 or 2.

c) Preventative measures to minimize the potential for brittle fracture in existing equipment are

limited to controlling the operating conditions (pressure, temperature), minimizing pressure at

ambient temperatures during startup and shutdown, and periodic inspection at high stress

locations.

d) Some reduction in the likelihood of a brittle fracture may be achieved by:

i) Performing a post weld heat treatment (PWHT) on the vessel if it was not originally done

during manufacturing; or if the vessel has been weld repaired/modified while in service without

the subsequent PWHT.

ii) Perform a “warm” pre-stress hydrotest followed by a lower temperature hydrotest to extend

the Minimum Safe Operating Temperature (MSOT) envelope.

iii) Pre- heat the vessel prior to pressurization.

6. Wet H2S Damage (Blistering/HIC/SOHIC/SSC)

Description of Damage:

This section describes four types of damage that result in blistering and/or cracking of carbon

steel and low alloy steels in wet H2S environments.

a) Hydrogen Blistering

Hydrogen blisters may form as surface bulges on the ID, the OD or within the wall thickness of a

pipe or pressure vessel. The blister results from hydrogen atoms that form during the sulfide

corrosion process on the surface of the steel, that diffuse into the steel, and collect at a

discontinuity in the steel such as an inclusion or lamination. The hydrogen atoms combine to

form hydrogen molecules that are too large to diffuse out and the pressure builds to the point

where local deformation occurs, forming a blister.

Blistering, results from hydrogen generated by corrosion, not hydrogen gas from the process

stream.

b) Hydrogen Induced Cracking (HIC)

Hydrogen blisters can form at many different depths from the surface of the steel, in the middle

of the plate or near a weld. In some cases, neighboring or adjacent blisters that are at slightly

different depths (planes) may develop cracks that link them together. Interconnecting cracks

between the blisters often have a stair step appearance, and so HIC is sometimes referred to as

“stepwise cracking”

c) Stress Oriented Hydrogen Induced Cracking (SOHIC) SOHIC is similar to HIC but is a

potentially more damaging form of cracking which appears as arrays of cracks stacked on top of

each other. The result is a through-thickness crack that is perpendicular to the surface and is

driven by high levels of stress (residual or applied). They usually appear in the base metal

adjacent to the weld heat affected zones where they initiate from HIC damage or other cracks or

defects including sulfide stress cracks.

d) Sulfide Stress Corrosion Cracking (SSC)

Sulfide Stress Cracking (SSC) is defined as cracking of metal under the combined action of

tensile stress and corrosion in the presence of water and H2S. SSC is a form of hydrogen stress

cracking resulting from absorption of atomic hydrogen that is produced by the sulfide corrosion

process on the metal surface.

SSC can initiate on the surface of steels in highly localized zones of high hardness in the weld

metal and heat affected zones. Zones of high hardness can sometimes be found in weld cover

passes and attachment welds which are not tempered (softened) by subsequent passes. PWHT

is beneficial in reducing the hardness and residual stresses that render steel susceptible to

SSC. High strength steels are also susceptible to SSC but these are only used in limited

applications in the refining industry.

Affected Materials

Carbon steel and low alloy steels.

Critical Factors

a) The most important variables that affect and differentiate the various forms of wet H2S

damage are environmental conditions (pH, H2S level, contaminants, temperature), material

properties (hardness, microstructure, strength) and tensile stress level (applied or residual).

b) All of these damage mechanisms are related to the absorption and permeation of hydrogen in

steels.

i) pH

Hydrogen permeation or diffusion rates have been found to be minimal at pH 7 and increase

at both higher and lower pH. The presence of hydrogen cyanide (HCN) in the water phase

significantly increases permeation in alkaline (high pH) sour water.

Conditions which are known to promote blistering, HIC, SOHIC and SSC are those

containing free water (in liquid phase) and:

>50 wppm dissolved H2S in the free water, or

Free water with pH <4 and some dissolved H2S present, or

Free water with pH >7.6 and 20 wppm dissolved hydrogen cyanide (HCN) in the water and

some dissolved H2S present, or

>0.0003 MPa (0.05 psia) partial pressure of H2S in the gas phase associated with the

aqueous.

Increasing levels of ammonia may push the pH higher into the range where cracking can

occur.

ii) H2S

Hydrogen permeation increases with increasing H2S partial pressure due to a concurrent

increase in the H2S concentration in the water phase.

An arbitrary value of 50 wppm H2S in the water phase is often used as the defining

concentration where wet H2S damage becomes a problem. However, there are cases where

cracking has occurred at lower concentrations or during upset conditions where wet H2S was

not ordinarily anticipated. The presence of as little as 1 wppm of H2S in the water has been

found to be sufficient to cause hydrogen charging of the steel.

Susceptibility to SSC increases with increasing H2S partial pressures above about 0.05 psi

(0.0003 Mpa) .

iii) Temperature

Blistering, HIC, and SOHIC damage have been found to occur between ambient and

150 C or higher.

SSC generally occurs below about 180oF (82oC). However, equipment operating above this

temperature are susceptible to SSC if there is an aqueous phase with H2S as outlined below.

Some susceptible equipment can fail even during short sour water excursions such as those

encountered during equipment shutdowns

Hydrogen charging potential increases with increasing temperature if the aqueous phase is

not eliminated by elevated temperature. Elevated temperature promotes dissociation of H2S

(thereby producing more monatomic hydrogen), together with an increase in the diffusion rates

of hydrogen in metals, resulting in increased level of hydrogen charging. However, the SSC

cracking potential is maximized at near-ambient temperature. This distinction is important

because metals can become charged during high-temperature exposure and subsequently

crack during excursions to lower temperatures

iv) Hardness

Hardness is primarily an issue with SSC. Typical low-strength carbon steels used in refinery

applications should be controlled to produce weld hardness <200 HB in accordance with NACE

RP0472. These steels are not generally susceptible to SSC unless localized zones of hardness

above 237 HB are present.

the time to failure by SSC decreases as material strength, applied tensile stress, and

environmental charging potential increase.

Blistering, HIC and SOHIC damage are not related to steel hardness.

November 2009 API Recommended Practice 571 5-57

v) Steelmaking

Blistering and HIC damage are strongly affected by the presence of inclusions and

laminations which provide sites for diffusing hydrogen to accumulate.

Steel chemistry and manufacturing methods also affect susceptibility and can be tailored to

produce the HIC resistant steels outlined in NACE Publication 8X194.

Improving steel cleanliness and processing to minimize blistering and HIC damage may still

leave the steel susceptible to SOHIC.

the disadvantage is that an absence of visual blistering may leave a false sense of security

that H2S damage is not active yet subsurface SOHIC damage may be present.

HIC is often found in so-called “dirty” steels with high levels of inclusions or other internal

discontinuities from the steel-making process.

vi) PWHT

Blistering and HIC damage develop without applied or residual stress so that PWHT will not

prevent them from occurring.

High local stresses or notch-like discontinuities such as shallow sulfide stress cracks can

serveas initiation sites for SOHIC. PWHT is highly effective in preventing or eliminating SSC by

reduction of both hardness and residual stress.

SOHIC is driven by localized stresses so that PWHT is also somewhat effective in reducing

SOHIC damage.

Affected Units or Equipment

a) Blistering, HIC, SOHIC and SSC damage can occur throughout the refinery wherever there is

a wet H2S environment present.

b) In hydroprocessing units, increasing concentration of ammonium bisulfide above 2%

increases the potential for blistering, HIC and SOHIC.

c) Cyanides significantly increase the probability and severity of blistering, HIC and SOHIC

damage. This is especially true for the vapor recovery sections of the fluid catalytic cracking and

delayed coking units.

Typical locations include fractionator overhead drums, fractionation towers, absorber and

stripper towers, compressor interstage separators and knockout drums and various heat

exchangers, condensers, and coolers. Sour water stripper and amine regenerator overhead

systems are especially prone to wet H2S damage because of generally high ammonia bisulfide

concentrations and cyanides.

d) SSC is most likely found in hard weld and heat affected zones and in high strength

components including bolts, relief valve springs, 400 Series SS valve trim, compressor shafts,

sleeves and springs.

Appearance or Morphology of Damage

Hydrogen blisters appear as bulges on the ID or OD surface of the steel and can be

found anywhere in the shell plate or head of a pressure vessel. Blistering has been

found on rare occasions in pipe and very rarely in the middle of a weld.

HIC damage can occur wherever blistering or subsurface laminations are present.

In pressure-containing equipment, SOHIC and SSC damage is most often associated

with the weldments.

SSC can also be found at any location where zones of high hardness are found in

vessels or in high strength steel components.

7. Types of Corrosion attacks on Austenitic stainless Steel

Since corrosion cracking of austenitic stainless steel can lead to failure of the equipment

involved, it is of the utmost importance that this equipment be properly protected to prevent

corrosive environments from occurring.

Austenitic stainless steels are those of the "300 series," the compositions of which are nominally

18 percent chromium and 8 percent nickel. The most common types used in the petroleum

industry are Types 304, 316, 321 and 347. Because of their inherent high temperature strength

properties and high corrosion resistance, they are particularly suitable for use in hydrocracking

units in areas of moderate and high temperature, and where substantial resistance to hydrogen

sulfide corrosion is required, such as in heater tubes, reactor, reactor combined feed

exchangers and piping. Types 321 and 347 are stabilized to minimize intergranular carbide

precipitation and are preferred because they are more resistant to the intergranular corrosion

cracking caused by polythionic acid attack, which can occur particularly during downtime

periods when exposed to air and moisture. Since these stabilized grades are not completely

immune to intergranular corrosion cracking, special handling procedures are recommended for

the protection of these materials as well as the unstabilized grades.

Chloride Attack

The presence of halides (chlorides are usually the most serious offenders) along with an

aqueous phase and tensile stresses can result in stress corrosion cracking of austenitic

stainless steels. This type of cracking is predominantly trans-granular and is somewhat

dependent on time, temperature and chloride concentration.

Therefore, precautions should be taken to minimize the amount of chloride in the process

material that will come in contact with austenitic stainless steel equipment. Under normal

shutdown period conditions, chloride cracking is not likely to be a problem as long as chlorides

are not allowed to accumulate and concentrate in hot equipment, and as long as precautions

are taken to limit the chloride content to low levels in any flushing, purging or neutralizing agents

used in the system.

2. Polythionic Acid Attack

Once a unit has been placed on stream, even if the sulfur content of the feed stock is low, all

items made of austenitic stainless steel should be considered to contain a layer of iron sulfide

scale. Even though these layers of scale in many cases may be very thin, they represent a

potential hazard to the underlying steel. The action of water and oxygen on this sulfide scale

forms weak sulfurous type acids, commonly referred to as polythionic acids, which can attack

austenitic stainless steels and cause intergranular corrosion and cracking. These stainless

steels are vulnerable to this type of corrosion, particularly in areas of residual tensile stresses

and in areas where intergranular carbides may exist, such as the heat-affected zones adjacent

to welds. Therefore, special precautions should be taken to protect austenitic stainless steel

from this corrosive environment.

8. Protection of Austenitic Stainless Steel:

Protection against polythionic acid attack can be accomplished by preventing the corrosive

environment from forming or by providing an agent that will neutralize any corrosive acids as

they are formed:

b. Preventing the Formation of Polythionic Acids

Since these acids are formed by the action of water and oxygen with hydrogen sulfide or sulfide

scale, elimination of either liquid phase water or oxygen will prevent these acids from being

formed. Since there will usually be an equilibrium amount of water vapor present during the

normal operation of a unit, during shutdown periods this water vapor can be prevented from

condensing by maintaining the temperature of the austenitic stainless steel equipment above

the dew point of water.

Under normal operations (other than a startup immediately following a catalyst regeneration,

where there may be significant amounts of oxygen present before purging), there should be

essentially no oxygen present in the system. The only other time any significant amount of

oxygen might enter the system would be during a shutdown period when the system is

depressured and the equipment is opened and exposed to air. Under these conditions a

suitable purge of nitrogen should be established through the equipment involved to prevent any

air from entering the system, and maintained until the system is again closed. If possible, the

equipment should be blinded or blanked-off during this period and kept under a slight positive

pressure of nitrogen.

3. Purging & Neutralizing

Whenever austenitic stainless steel cannot be adequately protected by maintaining

temperatures above the dew point of water or by an adequate nitrogen purge, a protective

neutralizing environment should be established in this equipment prior to exposure to air. An

effective neutralizing environment can be provided by purging with and maintaining an

ammoniated nitrogen blanket, or by washing with a dilute soda ash solution.

a. Purging Nitrogen

Nitrogen used for the purging and protection of austenitic stainless steels should be dry and the

oxygen content should be limited to a maximum of 1000 mol-ppm. The oxygen content of the

nitrogen used should be specified by the supplier, since the analysis for oxygen in this low

concentration range requires elaborate analytical equipment which may not normally be

available in the refinery laboratory. If the only nitrogen available has an oxygen content in

excess of 1000 mol-ppm, or if the oxygen content is unknown, then as a safeguard,

ammoniated nitrogen should be used where possible. However, for this case, catalyst safety

considerations might be necessary.

b. Ammoniated Nitrogen

To prepare ammoniated nitrogen for use in purging or blanketing an austenitic stainless steel

system, sufficient ammonia is added to the nitrogen to provide a minimum concentration of 5000

mol-ppm of ammonia. Whenever ammonia is added to the reactor system, the ammonia content

of the recycle gas should be checked frequently. It is expected that the catalyst will absorb a

considerable amount of ammonia, and, therefore, additional ammonia makeup will be required

to maintain the 5000-ppm ammonia concentration until the system reaches equilibrium. One

convenient method of adding ammonia to the system, especially when the system is at high

pressure, is to use a high pressure "blow case." With this type of arrangement liquid ammonia is

pressured into the blow case at low pressure from the ammonia cylinder, and then the blow

case is isolated. High pressure gas from the discharge of the recycle gas compressor is then

used to pressure up the blow case and to force the ammonia into the system at a location of

lower pressure.

All personnel working in the unit should be familiar with the toxic nature of ammonia, and must

follow proper safety precautions in working with the system when it contains ammonia. For

example, workers opening flanges or manways in a system containing ammonia should be

equipped with fresh air masks or other oxygen breathing equipment.

In order to preserve the activity of the catalyst in the reactors, ammonia is not to be passed over

the catalyst when it is in its oxidized form, that is, whenever the catalyst is either fresh or freshly

regenerated. When dealing with platinum type catalysts, ammonia should be excluded

regardless of the state of the catalyst.

Brass and most other copper alloys are subject to corrosion attack from ammonia. Therefore,

arrangements should be made to isolate this equipment from the system before admitting any

ammonia.

c. Soda Ash Solutions

Aqueous neutralizing solutions of soda ash (Na2CO3) should be prepared in the range of 2 to 5

wt%. Preheating the water to about 40°C will facilitate dissolving all the soda ash. In this range a

sufficiently high level of alkalinity will be provided to affect neutralization of any reasonable

amount of polythionic acids which may be formed. To avoid exposing the austenitic stainless

steel equipment to a concentration of chlorides, the chloride content of the soda ash used to

prepare the solution should be limited to a maximum of 500 wt-ppm, while the chloride content

of the water should not exceed 50 wt-ppm. As added protection 8against chloride attack from

the small amount of chloride present in the neutralizing solution, 0.5 wt% of sodium nitrate

should

be added to the soda ash solution. Sodium nitrate concentrations much above 0.5 wt% should

not be used, however, in order to avoid the possibility of stress corrosion cracking of carbon

steel piping and equipment in the system.

d. Soda Ash Neutralization Techniques

Whenever a soda ash solution is used for neutralizing and protecting austenitic stainless steel,

the piping or piece of equipment involved should be filled completely full with the solution.

The equipment should then be allowed to soak for a minimum of two hours before the soda ash

solution is drained and the equipment is exposed to the air. If there are any pockets of unvented

high areas in the equipment that cannot be reached by filling with the soda ash solution, then

the solution should be vigorously circulated through the equipment to assure thorough contact

of all austenitic stainless steel surfaces. This circulation should be continued for a minimum

period of two hours before draining and exposing the equipment to air. For extremely large

surfaces, such as reactor or large vessel walls and internals, where filling with soda ash solution

is impossible because of foundation load limitations, it is recommended to wash the areas very

thoroughly by means of a high pressure hose equipped with a spray nozzle. This type of

washing will have to be done after the vessel has been opened to allow entry. Until the soda

ash washing has been completed, the vessel should be maintained under a nitrogen blanket to

prevent the entry of air.

e. Soda Ash Protective Film

In all cases of flushing or washing with soda ash solution, after the solution is drained from the

equipment, the surfaces should be allowed to dry so that a film or fine deposit of soda ash

remains on all surfaces for added protection against polythionic acid formation. Therefore, after

draining the soda ash solution, do not rinse the system with steam or water.

For large accessible surfaces, such as vessels or reactor walls and internals, the excess dried

soda ash can be removed just prior to startup with a brush or dry cloths; do not use wet cloths

and do not flush with steam or water. The small amount of soda ash remaining on the reactor

surfaces, even if it were all deposited on the catalyst, would not have any significant effect on

the activity of all but the platinum-type catalysts under consideration in this paper.

4. Hydrotesting New Austenitic Stainless Steel

When conducting hydrostatic tests on new austenitic stainless steel equipment, the water used

should have a chloride content not exceeding 50 wt-ppm, in order to reduce the possibility of

concentrating chlorides in pockets or dead areas of the system. If chlorides were allowed to

accumulate and concentrate (such as during subsequent heating operations) in such areas,

stress corrosion cracking could result. If the only water available has a chloride content in

excess of 50 wt-ppm, then 0.5 wt% of sodium nitrate should be used.

5. Hydrotesting Used Austenitic Stainless Steel

Whenever a piece of equipment has been used for the processing of hydrocarbons in

hydrocracking service, it must be assumed that some degree of sulfide scale can be present.

Therefore, even if this sulfide scale is so slight that it is difficult to detect, the possibility of

polythionic acid formation with resulting intergranular corrosion cracking exists. Even if the

equipment has been cleaned by mechanical means, burning or acidizing, it is difficult to assure

that no traces of sulfide scale remain. Therefore, any hydrostatic testing (and any cleaning by

hydroblasting) operations on used equipment should be conducted using the dilute soda ash

solution specified for neutralizing this equipment. Here again, a protective film of dried soda ash

should be allowed to remain on the surfaces of the equipment while it is exposed to the air.

6. Reactor Charge Heater Tubes

a. Maintaining Small Fires

The austenitic stainless steel tubes in a combined feed heater(1010-H1) can best be protected

by maintaining a balanced set of small fires (or pilots, as applicable) in the heater box at all

times, even when there is no circulation of process material through the tubes. These small fires

should be adjusted to keep the tubes warm and dry, to maintain the environment inside the

tubes above the dew point of water. As a general rule, about 205°C, as measured by

thermocouples placed in the hip sections of the heater and directly below any convection coils

that may exist, will usually be sufficient for this purpose. The dew point, however, should be

determined for each specific condition involved and the temperature should be adjusted as

necessary. It is important during these periods of heater operation that the heater firing be kept

under strict control and that the firing pattern be properly established to provide good heat

distribution. Sufficient thermocouples are installed throughout the hip sections of the heater to

provide a good measurement of the firebox temperatures and to monitor the distribution of heat

in the firebox. These thermocouples are located below any convection bank in the heater, and

are connected to a continuous recorder provided with high and low alarm points. The low alarm

point is set at about 150°C and the high alarm point at about 230°C. Stack temperatures should

never be used to control firebox temperatures.

b. To Shut Down Fires

If it should be necessary for any reason to shut down the fires in combined feed heater (1010-

H1) containing austenitic stainless steel tubes, then this should be done only when it is

absolutely certain that the environment within the tubes does not contain both oxygen and water

(or water vapor). As a result of the operation of the reactor effluent water wash facilities in units

so equipped, there will normally be an equilibrium amount of water present in the entire reactor

circuit both during normal operation and during or after a period of in situ catalyst regeneration.

If the heater fires must be shut down during a period of normal operation, it is required only that

no oxygen is present, which is usually the case during normal processing periods. As the heater

tubes cool there will be small amounts of water condensing inside the tubes; however, this

water should not be harmful in the absence of oxygen.

If the heater must be cooled down and it is suspected that trace quantities of oxygen might be

present, then before cooling the heater the system should be depressured completely, but do

not evacuate. Evacuation at this point is perhaps possible, but not recommended because it

introduces the possibility of allowing air to enter the system. Continue to maintain the 205°C

firebox temperatures while depressuring and purging. After the system has been depressured,

pressure with nitrogen to any convenient pressure level. Repeat this depressuring/pressuring

procedure as many times as required to reduce the oxygen concentration, by dilution, to as

much below 100 mol-ppm as is possible and reasonable. Then the fires can be shut down and

the heater allowed to cool.

c. Neutralization

If neutralization is necessary, such as when a tube or tubes are cut out of the coil, or any time

when exposure to air at temperatures below the dew point of water cannot be avoided, the

tubes should be filled with soda ash solution and allowed to soak for a minimum of two hours.

With vertical coils, where it is not possible to completely fill the unvented upper return bends, it

is necessary instead to vigorously circulate the soda ash solution through the tubes for a

minimum of two hours to assure contact of all surfaces. After draining the soda ash solution, do

not flush with steam or water but instead allow a film of protective soda ash to remain in the

tubes.

d. Exterior Surfaces

Whenever heater fires must be shut down and the tubes are allowed to cool, it is recommended

that the exterior tube surfaces be protected, especially in heaters where high sulfur content fuel

gas is employed. As a result of the sulfur in the fuel, a sulfide scale can build up on the exterior

tube surfaces as well as on the inside tube surfaces. If moisture is allowed to condense on the

tubes as the heater box is cooled, the action of oxygen and moisture on the scale can form

polythionic acids which can attack the austenitic stainless steel tube surfaces and lead to

intergranular stress corrosion cracking. There are two recommended procedures that can be

followed to prevent this from occurring:

First, it is possible to prevent any moisture from condensing on the tubes, and thus prevent the

formation of polythionic acids, by purging the firebox with copious amounts of dry air. Normal

instrument air is prepared by processing through a set of driers where the dew point is reduced

to a sufficiently low level to prevent condensation from occurring at ambient conditions. This air

can be effectively used to maintain a dry air blanket in the heater box both during cooling and

throughout the entire period the fires are out. In order to minimize the consumption of instrument

air, and to prevent moist air from entering the heater box, the stack damper, all burner air

registers, and all doors and ports in the heater box should be kept closed.

Second, an alternate method of protecting the tubes from polythionic acid attack is to cover the

exterior tube surfaces with a protective film of soda ash, which will act to neutralize any

polythionic acids as they are formed. The neutralizing soda ash should be the same dilute

solution recommended for general neutralization, and should be applied to the tube surfaces as

soon as the heater box has cooled sufficiently to prevent vaporizing the soda ash solution, and

preferably before any moisture has begun to condense out on the tube surfaces. A fairly

efficient and effective method of applying the soda ash solution is to utilize a vat or tank with a

small portable pump which can pump the solution through a hose fitted with a spray nozzle

which will produce a fairly fine mist. A low pressure spray is advisable as high pressure may

erode the refractory. Small diameter pipe extensions can be fitted to the hose to allow reaching

up to the tube areas at the top of the heater box. This type of spray equipment will minimize the

soda ash consumption and provide a reasonable means to reach all tube surfaces that are

exposed to the heater flames. Once the soda ash solution has been applied, it should be

allowed to dry to form a protective film on the surfaces of the tubes; do not wash off this

protective film.

If the exterior tube surfaces are heavily coated with an oxide or carbonaceous material, it should

be removed by wire brushing or sandblasting. This cleaning, however, will also remove any

protective soda ash film that may have been applied. In this case, the tube surfaces should be

further protected by applying another film of soda ash without delay.

On the occasions when the heater fires are shut down, it is convenient to also schedule

inspection of the tubes. Inspection should include measuring the tube outside diameters for

comparison to the original new tube O.D.'s, dye penetrant checking of welds and heat affected

zones for cracks, and random ultrasonic flaw detection of the heat affected zones around welds.

Periodic radiographic inspection should be conducted to check for scale or deposits inside the

tubes.

7. Heat Exchangers

If lines leading to or from heat exchangers containing austenitic stainless steel are to be

opened, blinds can be rapidly inserted to isolate the exchanger, while maintaining a nitrogen

purge through the exchanger involved to prevent air from entering. A nitrogen blanket or

continuous nitrogen purge should then be maintained in the exchanger during this maintenance

period.

If shell and tube exchangers containing austenit ic stainless steel are to be opened and

inspected, or if the tube bundles are to be pulled, then before exposing this equipment to air,

both shell and tube sides should be flooded with soda ash solution and allowed to soak for a

minimum of two hours. If there are any pockets or high areas which cannot be reached with the

soda ash solution, then the soda ash solution should be vigorously circulated through the

exchanger for a minimum of two hours. Do not rinse with water, but instead allow a film of soda

to remain on the surfaces.

If tube bundles of austenitic stainless steel are to be cleaned by hydroblasting, then soda ash

solution should be used for this purpose instead of just water.

8. Reactor Internals

Any time a reactor is to be opened, maintain sufficient nitrogen purges to prevent the entry of air

into any part of the system and isolate the combined feed heater(1010-H1) coils and the reactor

effluent system with blinds. A blanket of nitrogen should also be maintained in the reactor(1010-

R1), especially if it contains unregenerated catalyst. A slight amount of air coming in contact

with the reactor internals for relatively short periods of time is normally not considered to be

harmful to the metal; however, precautions should be taken to prevent contact with water or

moisture, especially in the presence of air. If any exposure to air has occurred, the air should be

purged out with nitrogen as soon as possible.

When the reactor internals are to be exposed to air for a prolonged period of time, such as

during a catalyst change, the reactor walls and internals should be washed very thoroughly as

soon as possible with a high pressure hose, using copious amounts of soda ash solution. A

portable pump and a vat of soda ash solution on skids is typically used for this operation. In

order to do this washing properly, a workman equipped with a fresh air mask and following all

other proper safety precautions, might have to enter the vessel to make sure all surfaces,

including the underside of the top head, are thoroughly wetted. Be especially careful to

thoroughly soak welded areas with particular emphasis on welds normally required to support

heavy loads, such as those on support beams, grids and trays.

When the reactor contains trays, which would make wetting all surfaces with soda ash solution

difficult, a sufficient amount of soda ash solution should be sprayed around the top of the

reactor, and allowed to rain down through the reactor to wet as much of the surfaces as

possible in the areas below the top tray. Be sure to thoroughly soak and keep wetted any used

catalyst remaining in the reactor, and then air can be drawn through the reactor so that

personnel can enter. During this time, a small flow of soda ash solution to the reactor should be

maintained, and as each tray manway is removed, the vessel area beneath that tray and the

underside of the tray should be thoroughly washed with soda ash solution.

Whenever spent, unregenerated catalyst is unloaded from a reactor, some amounts of catalyst

will inadvertently remain on the trays and in the bottom of the reactor. This catalyst must be kept

wet to prevent ignition of sulfide scale when air is admitted, which is another reason for

conducting a thorough washing operation with the soda ash solution.

After washing with soda ash solution, allow the surfaces to dry with a fine deposit of soda ash.

Do not rinse this residue off with water. Later, just prior to reloading catalyst, wipe as much

excess soda ash residue from the surfaces as possible with brushes or dry cloths; do not use

water or wet cloths.

9.Summary:

During the start up and shut downs, always Minimum Pressurization should be

considered, otherwise metal may undergo embrittlement, Hydrogen assisted cracking and

temperature embrittlement. When this happens metal can damage catastrophically. The only

way to avoid from this type of damage is to follow vendor instructions of MPT which is 93C.

During shut downs temperatures of the heater is maintained at 205C to avoid Wet

H2S Corrosion and Polythionic Acid Attack inside the heater tubes. Because below this

temperature water can condense and dew point can achieve. Moreover, external surface of the

tubes should be away from water condensation and O2 ingress.

If required to expose surfaces of the austenitic stainless steel to the oxygen, then neutralize

using 5% Soda Ash solution, otherwise maintain positive pressure of Nitrogen.

11. References

DHDS Operating Manual

Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, Recommended practice by API-571

Operational life improvements in modern hydroprocessing reactors by Leslie P

Antalffy and Michael B Knowles Fluor Daniel Inc and Takayasu Tahara

Japan Steel Works Ltd Pran N Chaku ABB Lummus Global Inc

The structural integrity of insert parts of high pressure hydrotreating reactor - by

Steffen Weber, TOTAL Raffinerie Mitteldeutschland GmbH (TRM), Maienweg 1,

D-06237 Spergau, Tel. 03461-48 4220, steffen.weber@total.de, www.total.de

http://www.sescocp.com/typesofcorrosion.php