What Makes Bearing Housing Pressures Rise?- A Reliability Issue

Most bearing-housing breather vents, and especially small vents, offer a restriction that might allow a small amount of pressure build-up in bearing housings. It is also reasonable to expect that some oil will get flung into the close clearance region, typically fitted with lip seals or labyrinth seals, where the shaft penetrates the bearing housing. The oil has film strength, which makes it cling to surfaces. This oil now tends to bridge the gap between the rotating shaft and the surrounding stationary components.

In that event, the trapped air above the oil level will constitute a closed volume. As this volume of air is warmed by sun exposure or by frictional heat generated in the bearings, its pressure will increase in accordance with the perfect gas law:

(P2) = (P1)(T2/T1)

Using Rankine (absolute) temperatures and absolute pressures, it is easy to see how relatively minor temperature increases may cause pressures to rise by amounts that cannot be ignored. As pressures go up beyond the rupture strength of oil films, the sealing oil film will be temporarily interrupted. The bearing housing seal will open up for a fraction of a second.However, rising bearing housing pressure may lead to one of two undesirable events:

• During a pressure rise, the oil level will go down in the bearing housing and will rise in the lower surge chamber supporting the lubricator bottle (Bernoulli’s law).If the housing level drops sufficiently, the bottom of the bearing may be deprived of oil, or slinger ring immersion may no longer be sufficient for satisfactory lubrication.

• If oil overflows the surge chamber during a pressure rise, it is lost from the system, while the pressure in the lubricator adjusts to the new housing pressure. Oil from the bottle refills the housing when the system re- equilibrates with each“burp.” As the cycle repeats itself, more and more oil will be lost. These problems are caused by system features that allow for pressure differentials between the housing interior and the environment. There is evidence that installing bearing isolators and other narrow-gap housing closures increases the likelihood of potential problems with lubricators that had served perfectly well as long as not-so-close fitting labyrinth seals were being used. Fortunately, the pressure-balanced constant-level lubricator does not introduce the same risk. As mentioned earlier, the oil levels “x” at locations inside the bearing housing and inside the lubricator are always exposed to identical pressures. The problem is solved, and another step towards increased equipment reliability has been implemented. Only Pressure equilibrated level and not OTA-type lubricators should be used in reliability-minded plants. By providing a piping connection between the lubricator and bearing housing, lubricator port “x” and the bearing housing operate at the same pressure and the risk of oil leakage or unintended lowering of oil levels due to pressure buildup in bearing housings is eliminated. This approach provides protection from airborne contaminants, as well. Disadvantages? The pressure-balanced constant-level lubricator probably costs more, but the resulting reduction in the risk of failure far outweighs any disadvantages, both perceived and real.

Do we know how a constant level oiler works?

The Basic Principle (Based on Bernoulli’s law)

When rotary equipment is under rest, the constant level oiler very much resembles a simple, mercury barometer. As long as the neck of the filler bottle (reservoir) is immersed in the pool of lubricating oil, preventing air intrusion, the column of liquid in the bottle is supported by the atmosphere. The pressure in the air/vapor space at the top of the bottle, plus the head of fluid, exactly balances ambient air pressure (p).

If depletion of lubricant causes the level (x) to drop below the bottleneck, it allows air to enter. As air bubbles up into the bottle, it displaces lubricant, which pours down into the pool below.

 When the pool surface rises sufficiently to again seal the bottle from air, lubricant flow stops. The vapor space and new, lower, liquid height have re-equilibrated with ambient pressure. Figures are self-explanatory.

Equipment Performance is "Predictable" and Risk is "Manageable"

Ask any maintenance engineer  working in a reactive maintenance environment if they believe equipment performance is predictable and risk manageable and they will almost always answer, ?No, those statements are not true!? Even those who do agree will usually add the disclaimer that they simply don't have the time to do anything about either of them.
For those who claim they don't have the time to implement a reliability program, I ask them this question, ?Why is it you can always find time to fix the equipment, but never the time to engineer out the problems and prevent them from recurring ?? For as many times as I've asked this question, I've yet to hear a good answer.
The reality is equipment performance is predictable, risk is manageable and maintenance organizations can and should set forth the necessary time and effort to do something about it. It is the only way a maintenance organization will ever break out of its reactive maintenance environment.

No Pain, No Gain

Make no mistake about it, implementing a Reliability-Centered Risk Management program will require time, additional effort, cultural changes and an increase in short-term maintenance costs. It makes me cringe when I hear so-called experts tell maintenance organizations otherwise because it paints an unrealistic picture and companies become completely disillusioned when they find out it is not the case.
The old adage of ?no pain, no gain? is very much applicable to implementing a Reliability-Centered Risk Management program, as is the case with any major program implementation. However, the pain is short-lived and the gain is well worth the upfront investment of time, money and effort. Let me explain?
An Implementation Will Take Time ? Depending on the starting point a maintenance organization must elevate itself from, it can take upwards of two years to establish a credible Reliability-Centered Risk Management program. That's not to say benefits won't be realized during the start-up period, because they will. Results generally materialize in as little as 3-6 months. Of course, this is somewhat dependent on the amount of time and effort a maintenance organization is willing to invest in the implementation? the more focused and concentrated the effort, the quicker the results.
An Implementation Will Require Additional Effort ? There's no doubt that implementing a Reliability-Centered Risk Management program will require additional upfront effort. After all, a maintenance organization can't forego its responsibilities to maintain plant equipment during the implementation. Maintenance organizations often must choose how they will assimilate the additional work during the start-up phase of the program. Some choose to mandate overtime, some reorganize trying to free up key maintenance personnel, while others bring in temporary contractors to assume some of the workload.
An Implementation Will Require Cultural Changes ? There will be shifts in responsibilities, either within the maintenance organization itself or between maintenance and operations during the implementation of a Reliability-Centered Risk Management program. These cultural changes will need to be well managed to overcome the fear of change, keeping a clear vision of the end result in mind. Handled correctly, the cultural changes will be accepted and embraced. Handled incorrectly, and it can become a political hot potato.
An Implementation Will Increase Short-Term Costs ? There are always upfront costs when implementing any program with proven long-term rewards and benefits. That's also true of implementing a Reliability-Centered Risk Management program. Typical upfront costs include purchasing new Predictive Maintenance equipment, training, higher labor costs because of increased overtime and/or supplemental contract labor and the costs of refurbishing older equipment to return them to a like-new condition again.
Maintenance costs may well increase during the first 12-18 months of the program as it ramps up and begins to gain momentum. After that, costs will quickly fall, dipping well below what they were before the onset of the implementation.
It has been my experience that the return on investment (ROI) from any upfront investment in a Reliability-Centered Risk Management program will be realized within 2-3 years. Of course, this is dependent on the level of commitment a maintenance organization demonstrates toward achieving a successful implementation

Today's Maintenance Organizations Can't Afford to Turn Blind Eye on "Asset Reliability"

In present economic scenario of competitive market, maintenance organizations of any manufacturing organization can't afford not to implement a Reliability-Centered Risk Management program. Maintenance is one of the last frontiers in a company's battle to improve bottom line profitability and gain a competitive advantage in their respective market segments.
Increasing reliability and reducing risk lowers the total cost of asset  maintenance, lowers production costs and increases plant capacity and increases contribution margin  exactly what today's companies need.

Is Reliability Without Risk?

Everyone considers Reliability-Centered Maintenance must do to effectively manage  asset repair costs and increase overall plant efficiency. Reliability-Centered Maintenance has long been recognized as the most proactive maintenance method because it incorporates all of the best practices of traditional maintenance into a single, harmonious and complimentary program.

In spite of this, maintenance organizations often don't include Risk Management as part of their overall reliability program even though it's considered a sub component of Reliability-Centered Maintenance. Usually this is because organizations either don't understand its concepts or fully appreciate what Risk Management can do for them.
Risk Management compliments Reliability-Centered Maintenance by helping classify the criticality of equipment for example - PSM Critical equipment in the context of process industry; the most likely modes of failure; the effects these failures might have on equipment, the environment, and personnel; and what critical spares will be required in the event of a failure. It would be nearly impossible to develop a sound maintenance strategy without taking risk into consideration. Therefore managing risk is an essential component of a reliability program.
Reliability-Centered Risk Management strives to restore the balance between managing reliability and risk.
Reliability-Centered Risk Management program helps organizations achieve all of the benefits and potential of a well-rounded, comprehensive proactive maintenance program, including:
•  Increased equipment availability
•  Increased production capacity
•  Reduced spare parts inventory
•  Reduced work in process inventory
•  Extended equipment life
•  Reduced risk of failure
•  Lowest total cost of equipment 
•  Increased morale
•  Equal focus on production, the environment, and worker health and safety
•  And more?

Six stages of crevice corrosion

1.Formation of crevice by crevice former which can be either man made by design or by nature -oversight.
Some examples of man made ( desigh basis) crevice formers are : stationary "O" ring in "O" ring groove,Gasket surfaces,Tube to tube sheet joint of heat exchangers etc.
Some examples of man made by oversight are: poor root pass of pipe weld joint ,roughened surfaces,natural sediments and deposits.
2.Oxygen depletion. It has been recognized that oxygen is depleted in well shielded crevices creating an oxygen concentration cell between crevice and area out side the crevice.
3.Hydrolysis of metal ions and decrease in pH. The few metal ions entering the moist environment of crevice hydrolyze depleting the hydroxyl ions.The pH decreases.
4.Migration of chloride ions in to the crevice from outside of crevice region to balance the charge resulting from depletion of hydroxyl ions.
5.Initiation of crevice corrosion if pH decreases sufficiently and chloride ion concentration increases sufficiently to a critical values (Threshhold value) at which film break down  and corrosion initiation will occur
6.Propagation.

Asset Integrity is a journey not a destination

Points to remember :
•At this stage of aging refinery/petrochemical /oil industry’s facilities Integrity implementation is not an option, it is our safe guard from catastrophic failures
•Integrity is not about new standards , it is how to apply the existing standards effectively
•Integrity is a change case to any organization, leaders mind set, the way we manage our business and the competencies of our workforces
•Integrity is a journey not a destination, it need committed leaders to keep sailing it steadily. The question is Can we do it? The answer should be "Yes"


Six steps approach to assure MI (Mechanical Integrity) in a process or oil/gas industries:

1.Establish the EAM system in place after several round of brain storming sessions /reviews with experienced and working level executives at corporate and site level.
2.Imparting Training and provision of necessary tools.
3.Pilot Implementation.
4.Integrity assurance
5.Full Implementation across all units of Enterprise
6.Improvement

Equipment failure because of High Temperature Corrosion

High Temperature Corrosion : High temperature corrosions are named as follows:
- sulfidic corrosion
- sulfidic corrosion without hydrogen present
- sulfudic corrosion with hydrogen present
- naphthenic acids
- fuel ash
- oxidation
1. Sulfidic corrosion:
Corrosion by various sulfur compounds at temperatures between 260 and 540°C is a common
problem in many petroleum-refining processes and  in petrochemical processes. Corrosion is in the form of uniform thining, localized attack, or errosion corrosion. Nickel and nickel rich alloys are rapidly attacked by sulfur compounds at elevated temperatures, while chromium containing steels provide excellent corrosion resistance (as does aluminum). The combinations of hydrogen sulfide and hydrogen can be particularly corrosive, and as a rule, austenitic stainless steels are required for effective corrosion control.
2. Sulfidic corrosion without hydrogen present:
This type of corrosion occurs in various components of crude distillation units, catalytic cracking
units, hydrotreating and hydrocracking units upstream of hydrogen injection line.
Preheat-exchanger tubes, furnace tubes, and transfer lines are generally made from carbon steel,
as is corresponding equipment in the vacuum distillation section. The lower shall of distillation
towers, where temperatures are above 230°C is usually lined with stainless steel containing 12% Cr
such as Type 405.
 Metal skin temperature, rather than flow stream temperatures, shall be used to predict corrosion rates when significant differences between the two arise. For example metal temperatures of
furnace tubes are typically 85 to 110°C higher than the temperature of the hydrocarbon stream
passing through the tubes. Furnace tubes normally corrode at a higher rate on the hot side (fire
side) than on the cool side (wall side).
3. Sulfidic corrosion with hydrogen present:
The presence of hydrogen in, for example, hydrotreating and hydrocracking operations, increases
the severity of hightemperature sulfidic corrosion. Hydrogen converts organic sulfur compounds in
feed stocks to hydrogen sulfide; corrosion becomes a function of H2S concentration.
Down stream of hydrogen injection line, low-alloy steel piping usually requires aluminizing in order
to minimize sulfidic corrosion. Alternatively Type 321 (S32100) stainless steel can be used. Tubes
in the preheat furnace are aluminized low-alloy steel, aluminized 12% Cr stainless steel.
Reactors are usually made of 2.25 Cr-1 Mo steel, either with a Type 347 (S34700) stainless steel
weld overlay or an internal factory lining. Reactor internals are often Type 321 stainless steel.
4. Naphthenic acids:
These organic acids are present in many crude oils. The general formula may be written as R(CH2)n
COOH, where R is usually cyclopentane ring.. This acid is corrosive only at temperature above 230°C in the range of 1 to 6 neutralization number encountered with crude oil and various side-cuts. At any given temperature, corrosion rate is proportional to neutralization number. Corrosion rate triples with each 55°C increase in temperature. In contrast to high-temperature sulfidic corrosion, no protective scale is formed, and low-alloy and stainless steels containing up to 12% Cr provide no benefits
whatsoever over carbon steel. The presence of naphthenic acids may accelerate high-temperature
sulfidic corrosion that occurs at furnace headers, elbows, and tees of crude distillation units because
of unfavorable flow conditions.
Severe naphthenic acid corrosion (in the form of pitting) has been experienced in the vacuum
towers of crude distillation units in the temperature zone of 290 to 345°C and sometimes as low as
230°C. Attack is often limited to the inside and very top of the outside surfaces of bubble caps.
Alloy 20 (N08020) and titanium Grade 2 (R50400) are also resistant to naphthenic
acid corrosion. In contrast, aluminized carbon steel tray components, such as bubble caps, have
performed poorly.

5. Fuel ash:
Corrosion by fuel ash deposits can be one of the most serious operating problems with boiler and
preheat furnaces. All fuels except natural gas contain certain inorganic contaminants that leave the
furnace with products of combustion.These will deposit on heat-receiving surfaces, such as
superheater tubes, and after melting can cause severe liquid-phase corrosion. Contaminant of this
type include various combinations of vanadium, sulfur, and sodium compounds. Fuel ash corrosion
is most likely to occur when residual fuel oil (Bunker C fuel) is burned.
In particular, vanadium pentoxide vapor (V2O5) reacts with sodium sulfate (Na2SO4) to form sodium
vanadate (Na2O-6 V2O5). The latter compound reacts with steel, forming a molten slag that runs off
and exposes fresh metal to attack.
Corrosion increases sharply with increasing temperature and vanadium content of fuel. If the
vanadium content in the fuel oil exceeds 150 ppm, the maximum tube wall temperature should be
limited to 650°C. Between 20 and 150 ppm V, maximum tube wall temperatures can be between
650 and 845°C depending on sulfur content and the sodium-vanadium ratio of the fuel oil. With 5 to
20 ppm V, the maximum tube wall temperature can exceed 845°C.
In general, most alloys are likely suffer from fuel ash corrosion. However, alloys with high chromium
and nickel contents provide the best resistance to this type of attack. Sodium vanadate corrosion
can be reduced by firing boilers with low excess air (<1%). This minimizes formation of sulfur
trioxide in the firebox and produces high-melting slages containing vanadium tetroxide and trioxide
rather than pentoxide. In the temperature range of 400 to 480°C boiler tubes are corroded by alkali
pyrosulfates such as sodium pyrosulfate and potassium pyrosulfate, when appreciable
concentrations of sulfur trioxide are present.
6. Oxidation:
Carbon steels, low-alloy steels and stainless steels react at elevated temperatures with oxygen in
the surrounding air and become scaled. Nickel alloys can also become oxidized, especially if
spalling of scale occur. The oxydation of copper alloys usually is not a problem, because these are
rarely used where operating temperatures exceed 260°C. Alloying with both chromium and nickel
increases scaling resistance. Stainless steels or nickel alloys except alloy 400 (N04400), are
required to provide satisfactory oxidation resistance at temperatures above 705°C.
Thermal cycling, applied stresses, moisture and sulfur-bearing gases will decrease scaling
resistance.
High temperature oxidation is limited to the outside surfaces of furnace tubes, tube hangers and
other parts that are exposed to combustion gases containing excess air.
At elevated temperatures, steam decomposes at metal surfaces to hydrogen and oxygen and may
cause steam oxidation which is more severe than air oxidation at the same temperature. Fluctuating
steam temperatures tend to increase the rate of oxidation by causing scale to spall and thus expose
fresh metal to further attack.

Low Temperature Corrosion in petroleum refinery and petrochemical plants.

 Most corrosion problems are not caused by hydrocarbons but by various inorganic compounds such
 as water, hydrogen sulfide (H2S), hydrochloric acid (HCl), hydrofluoric acid , sulfuric acid (H2SO4 )
 and caustic. There are two main sources of these compounds:
- feed-stock contaminants and
- process chemicals.

1. Low temperature corrosion by feed-stock contaminants
The cause of the refinery corrosion is the presence of contaminants in crude oil as it is produced.
Corrosive hydrogen chloride evolves in crude preheat furnaces from relatively harmless magnesium
and calcium chloride entrained in crude oil. In petrochemical plants, certain corrosives may have
been introduced from upstream refinery and other process operations, other corrosives can form
from corrosion products after exposure to air during shut-down: polythionic acids fall into this
category. Corrosive contaminants are as follows:
- air
- water
- hydrogen sulfide
- hydrogen chloride
- nitrogen compounds
- sour water
- polythionic acids
Air:
Air may enter to many potential inlets equipments of  during prolong shutdown of plant. In general, the air contamination of hydrocarbon streams has been more detrimental with regard to fouling than corrosion. However, air contaminant has been sited as a cause of accelerated corrosion in vacuum towers and vacuum transfer lines, also accelerate overhead corrosion of crude distillation towers.
Water:
Water content of crude oils and water originated with stripping steam for fractionation towers
hydrolyses certain inorganic chlorides to hydrogen chloride, and is responsible for various forms of
corrosion in fractionation tower overhead systems. It is a good practice to keep equipment dry in
order to minimize corrosion.
Combination of moisture and air enters into storage tanks during normal breathing as a result of
pumping and changes in temperature. Corrosion of tank bottoms occurs mostly with crude oil tanks
which is caused by water and salt entrained in the crude oil. A layer of water usually settles out and
can become highly corrosive.

Hydrogen sulfide is the main constituent of refinery sour waters and can cause severe corrosion
problems in overhead of certain fractionation towers, in hydrocracker and hydrotreater effluent
streams in vapor recovery of Fluid Catalytic Cracking (F.C.C) Units, in sour water stripping units and
in sulfur recovery units. Carbon steel has fairly good resistance to aqueous sulfide corrosion
because a protective film of FeS is formed to avoid hydrogen stress cracking (sulfide cracking),
hard welds (above 200 HB) must be avoided, if necessary, through suitable postweld heat
treatment. Excessive localized corrosion in vessels can be resolved by selective lining with alloy
400 , but this alloy can be less resistant than carbon steel to aqueous sulfide corrosion at
temperatures above 150°C. If significant amounts of chlorides are not present, lining vessels with
 Type 304 (S30400) stainless steel can be considered.
In refineries, corrosion by hydrogen chloride is primarily a problem in crude distillation units, and to
lesser degree in reforming and hydrotreating units. In petrochemical plants, HCl contamination can
be present in certain feed stocks

Ammonia is also produced in ammonia plants to become a raw material for the manufacture of urea
and other nitrogenbase fertilizers. Ammonia in synthesis gas at temperatures between 450 and
500°C causes nitriding of steel components. When synthesis gas is compressed to up to 34.5 MPa
(5000 psig) prior to conversion, corrosive ammonium carbonate is formed, requiring various
stainless steels for critical components. Condensed ammonia is also corrosive and can cause SCC
of stressed carbon steel and low-alloy steel components.
Polythionic acids:
Combustion of H2S in refinery flares can produce polythionic acids of type H2SxOy (including
sulfurous acid) and cause severe intergranular corrosion of flare tips made of stainless steels and
high-nickel alloys. Corrosion can be minimized by using nickel alloys such as alloy 825  or
alloy 625
2. Low temperature corrosion by process chemicals:
Severe corrosion problems can be caused by process chemicals, such as various alkylation
catalysts, certain alkylation by-products, organic acid solvents used in certain petrochemical
process, hydrogen chloride stripped off reformer catalyst, and caustic and other neutralizers that
ironically, are added to control acid corrosion.  Another group of process chemicals
that are corrosive, or become corrosive, is solvents used in treating and gas-scrubbing operations.
These chemicals are as follows:
- acetic acid
- aluminum chloride
- organic chloride
- hydrogen fluoride
- sulfuric acid
- caustic
- amine
- phenol

Acetic acid :
Corrosion by acetic acid can be a problem in petrochemical process units for the manufacture of
certain organic intermediates such as terephthalic acid. Various types of austenitic stainless steels
are used, as well as alloy C-4 , alloy C-276 and titanium, to control corrosion by acetic acid in the presence of small amount of hydrogen bromide or hydrogen chloride.Small amount of water in acetic acid can have a significant influence on corrosion. Type 304 (S30400) stainless steel has sufficient resistance to the lower concentration of acetic acid up to the boiling point. Higher concentration can be handled by type 304 stainless steel if the temperature is below 90°C.Corrosion by acetic acid increases with temperature. Bromide and chloride contamination causes pitting and SCC, while addition of oxidizing agents, including air, can reduce corrosion rates by several orders of magnitude.
Aluminum chloride :
Certain refining and petrochemical processes such as butane, isomerization, ethylbenzene
production and polybutene production, use aluminum chloride as a catalyst. Aluminum chloride is
not corrosive if it is kept absolutely dry otherwise it hydrolyzes to hydrochloric acid. During shutdown
equipment shall be opened for the shortest possible time. Upon closing, the system shall be
dried with hot air followed by inert gas blanketing. Equipment that is exposed to hydrchloric acid
may require extensive lining with nickel alloys, such as alloy 400 (N04400), B-2 (N10665), C-4
(N06455), or C-276 (N10276).
Hydrogen fluoride:
Some alkylation processes use concentrated HF instead of H2SO4 as the catalyst. In general, HF is
less corrosive than HCl because it passivates most metals by the formation of protective fluoride
films. If these films are destroyed by diluted acid, severe corrosion occurs. Therefore as long as
feed stocks are dry, carbon steel-with various corrosion allowances-can be used for vessels, piping,
and valve bodies of hydrofluoric acid alkylation units. All carbon steel welds that contact HF, shall be PWHT (postweld heat treated).
Fractionation towers shall have Type 410 (S41000) stainless steel tray valves and bolting for
desiobutanizer tower tray valve and bolting, alloy 400 (N04400) is recommended. Corrosion
problems in HF alkylation units occur after shutdown because pockets of water have been left in the
equipment. It is very important that equipment be thoroughly dried by draining all low spots and by
circulating hydrocarbon before the introduction of HF catalyst at start-up.
Sulfuric acid :
Certain alkylation units use essentially concentrated sulfuric acid as the catalyst; some of this acid
is entrained in reactor effluent and must be removed by neutralization with caustic and scrubbing
with water. Acid removal may not be complete, however, and trace of acid-at various concentrations
(in terms of water)-remain in the stream.
Dilute sulfuric acid can be highly corrosive to carbon steel, which is the principal material of
construction for sulfuric acid alkylation units. Because the boiling point of sulfuric acid depending on
concentration ranges from 165 to 315°C, depending on concentration entrained acid usually ends
up in the bottom of the first fractionation tower and reboiler following the reactor; this is where the
entrained acid becomes concentrated.
Acid concentration above 85% by weight are not corrosive to carbon steel if temperatures are below
40°C. Cold-worked metal (usually bends) shall be stress relieved. Under ideal operating conditions,
few, if any, corrosion and fouling problems occur.
Carbon steel depends on a film of iron sulfate for corrosion resistance, and if its film is destroyed by
high velocities and flow turbulence, corrosion can be quite severe.
Phenol
Phenol (carbolic acid) is used in refineries to convert heavy, waxy distillates obtained by crude oil
distillation into lubricating oils. As a rule, all components in the treating and raffinate recovery
sections, except tubes in water-cooled heat exchangers, are made from carbon steel. If water is not
present, few significant corrosion problems can be expected to occur in these sections. In the exact
recovery section severe corrosion can occur, especially where high flow turbulence is encountered.
As a result, certain components require selective alloying with Type 316 (S31600) stainless steel.
Typically stainless steel liners are required for the top of the dryer tower, the entire phenol flash
tower, and various condenser shells and separator drums that handle phenolic water.
Tubes and headers in the extract furnace shall also be made of Type 316 (S31600) stainless steel
with U-bends sleeved with alloy C-4 (N06455) on the outlet side to minimize velocity accelerated
corrosion.

Combating crevice corrosion and pitting corrosion in engineering installations

Crevice Corrosion
Intensive localized corrosion frequently occurs within crevices and other shielded areas on
metal surfaces exposed to corrosives. The attack associated with small volumes of stagnant
solution caused by holes, gasket surfaces, lap joints, surface deposits, and crevices under bolt and
rivet heads.
Methods and procedures for combating crevice corrosion are as follows:

- Use welded butt joints instead of  bolted joints in new equipment if system permits for maintainability
- Close crevices in existing lap joints by continuous welding, caulking or soldering.Example:Pipe in SORF
  flange joint should be fillet welded from inside of flange bore and from out side at flange socket end to
  avoid crevice
- Design vessels for complete drainage; avoid sharp corners and stagnant areas.
- Inspect equipment and remove deposits frequently.
- Remove solids in suspension early in the process or plant flow sheet, if possible.
- Remove wet packing materials during long shutdowns.
- Provide uniform environments, if possible, as in the case of back-filling a pipeline trench.
- Use "solid"Spiral wound metallic gaskets with inner ring of MOC compatible with corrosive media or other
  suitable metallic gasket where ever possible so  as to avoid formation of crevice.
- Seal weld instead of pure rolling joint  in tubes, in tube sheets of heat exchangers.
 Pitting Corrosion
Pitting is a form of extremely localized attack. That results in holes in the metal. It is a cavity
or hole with the surface diameter about the same as or less than the depth.
Pitting is one of the most destructive form of corrosion, it causes equipment to fail because of
perforation with only a small percent weight loss of the entire structure. Pitting may be considered
as the intermediate stage between general overall corrosion and complete corrosion resistance.
Oxidizing metal ions with chlorides are aggressive pitters. Cupric, ferric and mercuric
halides are extremely aggressive even our most corrosion resistant alloys can be pitted by CuCl2
and FeCl3.
 Prevention
The methods suggested for combating crevice corrosion generally apply also for pitting. Materials
that show tendencies to pit, shall not be used to build the plant under consideration. For example the addition of 2% molybdenum to 18-8S (Type 304) to produce 18-8S
Mo (Type 316) results a very large increase in resistance to pitting.

Significant Thermal Gradient causes equipment failure.

Equipment such as heat exchangers, reboilers, reactors in process industries are likely to be subjected to thermal stress and strain  because of temperature differences within the vessels .These can cause changes in the dimensions of a part. Whenever a change in dimension is resisted, a thermal stress will result.


In cases where a temperature difference or gradient occurs within the material, the forces generated will be internal.The hotter parts of the material will usually have expanded more than the colder parts, causing compression of the hotter areas and tension in the colder parts. Some of the processes involved in
discussing heat stress are described below for better understanding of failure mechanism and root cause analysis :

• Thermal Expansion, (or the increase in length) for most materials,results from an increase in temperature. The extent of the expansion depends on the temperature change, the temperature itself, the length of the part, and the material(s) involved.

• Differential thermal expansion results whenever there is a temperature difference or gradient from point to point in metals. The differential occurs because most metals expand with increasing temperature. If the
increase (or decrease) in temperature is different in different sections of a material, the sections will have expanded to a different extent. In this case, the compressive and tensile stresses can result in the bending of the part.

• Thermal shock is an internal stress that is the result of rapid heating or cooling of a part. In the case of heating, high compressive stresses near the surface can result in internal fracturing while in the case of cooling, the high tensile stresses on the surface of the part can result in external cracking.

To avoid the possibility of internal or external failure of the component, heating and cooling down rates are designed to limit temperature differences and the consequent strains due to thermal stresses to acceptable levels.

Therefore it is suggested  to follow proper heating and cooling  processes strictly as per procedure described in SOP of  equipment operation to prevent thermal cracking - a dangerous failure mode resulting in loss of containment leading to environment problem.

The best practices to control fatigue failure of machined parts.

Let us understand the failure mechanisms due to fatigue caused by work hardening .Fatigue is a failure phenomenon associated with work-hardening of materials caused by fluctuating or repeated loads that result in increased brittleness and reduced service life of machine parts. Fatigue is characteristic of ductile materials but the final failure is rapid and characteristic of brittle fracture.
The time leading up to fatigue failure cannot be predicted exactly but the following conditions are known to result in work- hardening, leading to fatigue:

• a relatively large, fluctuating applied stress
• a sufficiently large number of stress cycles

Fracture failure due to fatigue often occurs at relatively low applied stress and well within specified design loads. The stress can be mechanical, thermal or both and can alternate between compression and
tension, or simply alternate between high and low values.The best ways to ensure a reasonable service life for parts subject to the above conditions is; to ensure that scratches and other surface imperfections are removed by polishing and, if possible, by heat treatment, which relieves internal strains.

The only reasonably reliable methods of checking the progress of fatigue are by visual, x-ray or ultra-sound examination for surface and other cracks of the parts likely to be subject to work- hardening.

Why a large Turbine shaft becomes deformed when at rest ?

The force of gravity (weight) applies a constant load to turbine shafts, whether at rest or rotating. This stress always applies downward towards the centre of the earth. When the rotor is stationary, the metal is stressed in one direction only and tends to sag. Initially, the turbine shaft experiences time dependent-anelastic stress.
Ultimately, the sag may become irreversible (permanent deformation), and the resulting creep can lead to extra stress on bearings, vibration, and potential failure of the turbine internals including bearing damages resulting in seizure or catastrophic failure.
 "Creep is the permanent or irreversible, time-dependent deformation of a material under a continuing loads. If the deformation is not managed properly, cracking and permanent failure can result."

How to avoid such potential failure?
It is advised to go for Rolling the shaft which evens out the effect of the gravitational stress on the shaft metal and reduces or eliminates the effects of anelastic stress and sag. If the turbine is left stationary for a long time, the undistributed stress may result in creep, which is irreversible. For this reason, turbines must be rolled regularly as Good operating practice to ensure reliability.

Basic Principles of Corrosion and its Prevention by cathodic Protection

Basic Principles of Corrosion in a bi-metallic structure and in single metallic structure  :

Corrosion is basically a deterioration of materials usually metals from any part of its surface when in contact partly or fully with soil or water by way of an Electro- chemical reaction. Electro-chemical corrosion of metallic parts of process equipment is a process  in which the metal surface is in contact with an electrolyte which may be a film of moisture containing dissolved salts, ( example: atmospheric corrosion), or may be the whole or part of the surrounding medium, e.g. when metal is immersed in fresh water or seawater or buried in the soil (under ground pipe line). In the last case, the electrolyte is the water in the soil,containing dissolved salts.
Corrosion in presence of bi-metallic structure:
When two metals having different energy levels or potentials are coupled together, current will flow. The direction of positive current flow will be from the metal with the more negative potential through the soil to that which is more positive. Corrosion will occur at the point where positive current leaves the metal surface.
 Different metals have different potentials in a specific electrolyte.
Corrosion in single metallic structure:
The same metallic structure, when placed in an electrolyte (e.g. soil) can develop differences in potential as a result of metal grain composition, milling imperfections, scratches, threads, etc., being exposed. Those portions will usually be, anodic to the remainder of the surface and will corrode.
Corrosion in same metallic structure can also occur due to differences in the electrolyte. These differences may be in the soil resistivity, oxygen concentrations, moisture content and various ion concentrations. The variations produce current flow from one location, through the electrolyte, to another portion of the same metallic structure.
 At the surface of single metal corroding in an electrolyte, there are anodic and cathodic areas, which have small differences in potential. They form active electrochemical cells in which current flows from the anodic areas into the electrolyte, and from the electrolyte into the cathodic areas .Corrosion takes place at anodic area where dissolution of metal takes place.

 The corrosion cell
At anodic locations of metal part, positively charged metal ions migrate the metal surface, where as at cathodic locations,electrons leave the metal surface. Thus, corrosion takes place at the anodic locations

where metal ions react with the electrolyte to form the typical corrosion products. The basic
electrochemical reaction is:

Fe à Fe⁺⁺ + 2e^-

At the cathodic areas, dissolution of metal does not take place, but reduction reactions
occur in the electrolyte. Depending on the pH and presence of oxygen, the basic
electrochemical reaction can be:

2H ⁺ + 2e^-     à  H₂     or    ½O₂ + H₂O +2e^-    à 2OH^-

At the anode the electrochemical current leaves the metal surface and at the cathodic
areas the current enters the metal surface.As the reaction involves the flow of electrons, the reaction rate can be expressed as an electric current. The path of the current will be from the corroding metal, through the electrolyte (soil) to the non-corroding metal and then back through the connection (conductor) between the two metals. The corroding metal is the one where the current leaves to enter the electrolyte and is called an anode. The metal that receives the current is called the cathode.

Cathodic Protection

It has been established that electric current can generate corrosion, corrosion, in turn can generate electric current. As indicated by these phenomena, it has become possible to prevent corrosion by use of electrical current. This, then, is the basis for cathodic protection. When direct current is applied with a polarity which opposes the natural corrosion mechanisms, and with sufficient magnitude to polarize all the cathodic areas up to the open circuit potential of the anodic areas, corrosion is arrested.
The theoretical considerations indicate that the basis for cathodic protection is relatively simple not difficult to understand. However, practical designs for various applications can vary considerably based on the type of structure to be protected and the conditions encountere
There are basically two methods of applying cathodic protection. One of these methods makes use of anodes which are energized by an external DC power source. In this type of cathodic protection system, anodes are installed in the electrolyte and are connected to the positive terminal of a DC power source and the structure which is to be protected is connected to the negative terminal of that source. Because the power source is almost always a rectifier unit, this type of system is often referred to as a rectifier or impressed current cathodic protection.
The second method of protection makes use of galvanic anodes which have a higher energy level or potential with respect to the structure to be protected. These anodes are made of materials, such as magnesium or zinc, which are naturally anodic with respect to steel structures and are connected directly to these structures.
In most cases, the impressed current  type system is designed to deliver relatively large currents from a limited number of anodes, and the galvanic anode type system is designed to deliver relatively small currents from a large number of anodes. Each method of applying cathodic protection has characteristics that make it more applicable to a particular problem than the other.
Regardless of the type of system used, current flows from the cathodic protection anode through the soil to the structure to be protected. Where this current flows onto a structure from the surrounding electrolyte (soil), the potential of the structure is made more negative. Cathodic protection is achieved when this change in potential is sufficient to arrest corrosion.

It would appear that cathodic protection can be achieved merely by the application of current of sufficient magnitude. Although this statement is true, it is deceptively simple because there are very large differences in the design of cathodic protection systems. These differences result from the infinite variety of structures that are to be protected and from the large assortment of environments in which those structures are located. Because of the large differences in the designs of systems necessary to achieve protection, it is often necessary for existing structures that each system be custom designed for a given location.
In order to prevent corrosion using cathodic protection, current must flow from the electrolyte onto the structure at all locations. If a portion of the structure does not receive current, the normal corrosion activity will continue at that point. If any of the cathodic protection current picked up by the structure leaves that structure to flow back into the electrolyte, corrosion will be accelerated at the location where the current is discharged. As an example, when mechanically coupled piping is used, this can be discontinuous from one pipe section to the next. If a galvanic anode type system is used for protection, it may be necessary to install an anode on each pipe length or to electrically bond across each joint. If one length of pipe is neglected, that length will receive no cathodic protection and the normal corrosion activity will continue. When a rectifier type system is installed on an underground storage tank system, it is even more important that the tank and lines be electrically continuous. If there are non-continuous joints, it is possible for the cathodic protection current to leave the pipe or tank to flow around the electrically discontinuous joint causing corrosion at each point where the current leaves the pipe surface. Similarly, if cathodic protection current is applied to one structure in an area, it is possible for other structures in the neighborhood to be exposed to damage unless proper steps are taken. Potential measurements are used to determine whether such damaging exposure exists. Just as protection is indicated when the potential of a structure is made more negative, stray current corrosion is indicated when the potential of a structure is made less negative as a result of the application of cathodic protection current.


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Corrosion Management - A Top Management important initiative in process, oil and gas industry.

 

Corrosion is an unacceptable phenomena in any process and hydrocarbon industries. The pipelines and vast manufacturing instalaltions such as columns,vessels,heat exchangers,storage tanks,jetty structure and underground installations, some of which may be subject to corrosion. If that corrosion remains undetected, the results can be disastrous, and very expensive. Only with proper attention to safeguards, maintenance and modern protective technologies can the world's oil supplies remain steady, and the environment safe from disaster.

According to statistics available across the globe on steel /metallic corrosion across all industrial sectors, corrosion is the main factor that affects the longevity and reliability of pipelines and billions of dollars in  a year is spent in corrosion-related costs. The expenses related to maintenance and reactive repairs, as well as the public safety and environmental factors involved, should place corrosion in the highest priority, both from the energy and oil/ gas industry's perspective as well as from a public policy perspective. While money must be spent in assessment, risk management, and maintenance, it is far less when compared to the alternative of having to replace pipelines and deal with the destructive after-effects in the surrounding environment. Therefore the process of having to make sure that corrosion prevention in pipelines, storage tanks and other critical infrastructure and supplies becomes a more vested solution.

An asset corrosion management system and preparation of PIAM (Plant Integrity Assurance Manual ) manual for each process plants of the manufacturing unitis will help protect against these dangerous and expensive threats.Mechanical Integrity and  Corrosion management is part of an overall system, which develops, implements, reviews, and maintains both policy and strategy for managing, mitigating and preventing corrosion. While it may not be possible to completely eliminate any instance of corrosion and the leakage that results, proper attention, maintenance and technology will keep it to a manageable level.

It all starts with adequate planning right from design phase to steady state with short term and long term perspective.

Like most other systems, a corrosion management system doesn't start in the field, it starts on paper, with strategy. An in-depth review of the current scenario and potential threat scenarios, a review of the integrity of all existing systems, followed by a review of available mitigating techniques and technologies all contributes to the creation of the all-important strategic document that guides the actual implementation of the corrosion management program.

Corrosion management isn't purely a reactive approach that treats corrosion after it has already begun. The place to begin after the strategic session is during the design phase, where engineering and design principles are applied before any pipes are even put in the ground. This ensures that the best materials are used, and the most appropriate anti-corrosive technologies are integrated.

Good preparation is the best approach. When pipelines lay in hostile environments or very remote territories, maintenance becomes more difficult and costly simply because of the access limitations. The biggest part of battling corrosion is in the planning and routine maintenance and inspection, particularly when monitoring can be done from a remote basis.

The GAP which needs to be bridged.

A corrosion management system is sometimes not adopted post-commissioning, simply because of confusion from the beginning. The oil pipeline operator may mistakenly believe that all of the management tools have already been considered in the design phase by the EPC engineer, so no further management system is needed. This is a major misunderstanding and a big mistake, which can lead to an increased risk of failure and higher costs down the line, due to lack of corrosion management tools. At that point, corrosion mitigation becomes an afterthought and a reactive process that is much more costly.

What is Corrosion Management?

Corrosion management is one of important element of MIQA (Mechanical Integrity and Quality Assurance ) plan of oil and gas industry.It isn't a single piece of technology or a single process. Rather, it is a management discipline that continuously reviews all engineering considerations, regularly monitors the entire system's performance, and evaluates the effectiveness of any corrosion management technologies after commissioning. The evaluation phase constantly evaluates data and looks at key performance indicators to determine levels of corrosion and the relative effectiveness of anti-corrosion techniques that have been applied.

Starting with an integrity review process, data is gathered at the beginning stage of the corrosion management process, including inspection data. This allows for a risk assessment to be carried out, then finally the creation of a corrosion management strategy meant to protect the asset. This review process will help to determine what level of inspection will be required, what mitigation processes need to take place, and what type of monitoring needs to be in place.

The initial integrity review process, which takes place before implementation, is perhaps the most important, and allows the project to progress more effectively while also preventing and rectifying many common corrosion issues. Only with a good integrity review can an adequate corrosion management plan be created.

The Right People with the Right Knowledge

One of the biggest shortcomings in the field of corrosion management is the lack of skilled personnel. The industry needs skilled engineers understand the industry, the chemistry of corrosion and the technologies required to address it.

Protecting the integrity of energy sector assets depends both on effective corrosion engineering, and corrosion management. Corrosion management however, is often ignored, because of a lack of training on the engineering side, or the incorrect perception that the engineering phase will necessarily address all of the corrosion management requirements. The problem lies in the educational system, where corrosion engineers are taught topics that are associated mostly with the design stage of an oil and gas asset. Corrosion management, on the other hand, is more concerned with post-commissioning phases. The result is a serious training gap.

It is therefore necessary to consider both corrosion engineering and corrosion management, as two separate disciplines, to achieve the most effective results. Its of high importance that skilled professionals need to be equipped in both areas, and have prior expedience in highly effective corrosion management technologies that is desperately needed by the oil and gas industry.