Corrosion in Petroleum Refining and Petrochemical Operations

[Mohamed]

I read hard copy of the book (Corrosion in the petrochemical industry ) and while i read it , i take some notes and i will share it in the forum gradually

Corrosion in Petroleum Refining
and Petrochemical Operations

A large proportion of Corrosion problems are actually caused by shutdowns. When equipment is opened to the atmosphere for inspection and repair, metal surfaces covered with corrosion products will be exposed to air and moisture. This can lead to pitting corrosion and stress corrosion c racking unless preventive measures are implemented when equipment is washed with water during a shutdown, corrosion can be caused by pockets of water left to dry.
Materials Selection
The selection of materials of construction has a significant impact on the operability, economics and reliability of refining units and petro –chemical plants. For this reason, materials Selection should be a cooperative effort between the material engineer and plant operations and maintenance personnel.
There some important note should be followed:

1. Material should provide some type of warning before it fails.
2. Predictable materials performance tinder a wide range of exposure conditions.
3. Material must not only be suitable for normal process conditions but must also be able to handle transient conditions encountered during start-up, shutdown. Emergencies or extended standby.
4. Material must be resistance to fire and thermal shock when fire-fighting water is applied.

[Mohamed]

Principal Materials.
1- Carbon and low-Alloy Steels :- Carbon Steels is probably used for at lest 80% of all components in refineries and petrochemical plants because it is inexpensive, readily available, and easily fabricated, Every effort is made to use carbon steel even If process changes are required to obtain satisfactory service from carbon steel For example, process temperature can be decreased, hydrocarbon streams dried up, or additives injected in order to reduce potential corrosion problems with carbon steel. Fractionation towers, separator drums. Heat-exchanger shells, storage tanks, most piping. And all structures are generally fabricated from carbon steel. Carbon molybdenum steels have better resistance than carbon steel to high-temperature hydrogen attack.

2- Stainless steel: are extensively used in petrochemical plants because of the highly corrosive nature of the catalysts and solvents that are often used in refineries. Stainless steels have been primarily limited to applications involving high temperature sulfidic corrosion and other forms of high-temperature attack. Most stainless steels will pit in the presence Of chlorides.

3- Cast irons: because of their brittleness and low strength are normally not used for pressure- retaining components for handling flammable hydrocarbons the main exceptions are pump and valve components, ejectors, jets, strainers. And fittings in which the high hardness of cast iron reduces the velocity effect of corrosion such as impingement. Nickel cast irons have excellent corrosion, wear, and high temperature resistance because of the relatively high alloy content typical uses are valve components, pump components, dampers. Diffusers, tray components and compressor. High-silicon cast irons are extensive corrosion resistant because of a passive surface layer of silicon oxide that form during exposure to many chemical environments

4- Copper and aluminum alloys: are usually restricted to applications below 260 C (500 °F) because of strength limitations. Admiralty metal (C44300) tubes have been extensively used in water-cooled condensers and coolers at most refineries. But have often performed poorly in overhead condensers, compressor after coolers and other locations where high concentrations of hydrogen sulfide and ammonia are encountered in aqueous condensate. The usual failure modes are pitting, ammonia SCC, and dezincification. Aluminum tubes were found to be high resistant to aqueous sulfide corrosion in overhead condensers. Unfortunately, fouling and pitting corrosion on the water side hive always been a problem, and except for certain limited applications, most refineries do not use aluminum tubes The other major use of Aluminum tubes has been in vacuum towers, In which aluminum provides resistance to the naphthenic acid corrosion of tray components.

5- Nickel alloys: are especially resistant to sulfuric acid, hydrochloric acid. Hydrofluoric acid, and caustic solutions, all of which can cause corrosion problems in certain refinery and petrochemical operations. Nickel also forms the basis for many high temperatures allays. Alloy 400 (N04400) is extensively used as a lining for carbon steel equipment to prevent corrosion by hydrochloric acid and chloride salts. Although expensive. These alloys are used for specific applications to overcome unusually severe corrosion problems.

6- Titanium: is a relative newcomer to the refining industry, but it has been extensively used in certain petrochemical processes. Titanium is not a high temperature metal; welding and cutting must be done under inert gas atmospheres to prevent embrittlement From a practical point of view, the use of Titanium in refinery and petrochemical plant service Is limited to temperatures below 260 C (500F) and if hydrogen present, temperatures should not exceed 175 C (350 F) In order to prevent embrittlement due to hydride formation. Titanium tubes are often required when seawater or brackish water is used for cooling.

[Mohamed]

Codes and Standard Specifications

Rules for the design, fabrication, and inspection of pressure vessels, piping and tanks are provided by codes that have been developed by industry and/or regulatory agencies in various countries.
The ANSI/ASME Boiler and Pressure Vessel Code provide a list of acceptable steels and allowable stress values. The code also provides the method for calculating the required minimum thickness of various components based on design temperature and pressure the need for heat treating during fabrication and Inspection requirements is also defined based an die alloy selected and the pressure-wall thickness.

[Mohamed]

Fabricability With very few exception processes equipment and piping are fabricated by welding wrought steels, the shells of pressure vessels are usually made from rolled plate. This requires that she steels have sufficient ductility far forming and are readily weldable. Weldabilty of steels is important not only for initial fabrication but also for future field repairs or modifications.
Low- and High-Temperature Corrosion Far practical purposes. Corrosion in refineries and petrochemical plants can be classified into:
Low-Temperature Corrosion is considered to occur below approximately 260 C (500°F) in the presence of water, Carbon steel can be used to handle most hydrocarbon streams in this temperature range, except where aqueous corrosion by inorganic contamination, such as hydrogen chloride and hydrogen sulfide.
High-temperature corrosion is considered to take place above approximately 260 C (500 F). The presence of water is not necessary because corrosion occurs by the direct reaction between metal and environment.
Low-Temperature Corrosion Most corrosion problems in refineries are not caused by hydrocarbons that are processed but by various inorganic compounds such as water hydrogen sulfide, hydrochloric acid and sulfuric acid. There are two principal sources of these corrosion feed-stock contaminants and process chemicals.

[Mohamed]

Low-Temperature Corrosion by Feed-Stock Contaminants.

1- Air: During shutdown or turnarounds most plant equipment is exposed to air. Air also can enter the suction side of pumps if seals or connections are not tight. air contamination has been cited as a cause of accelerated corrosion in vacuum transfer lines and vacuum towers of crude distillation units.

2- Water:Water is found in all crude oils and is difficult so remove completely. Water not only functions as an electrolyte but also hydrolyzes certain inorganic chlorides to hydrogen chloride. Water is primarily responsible for various forms of corrosion in fractionation tower overhead systems. In general whenever equipment can be kept dry through suitable process or equipment change. Corrosion problems will be minimized. Moisture and air are drawn into storage tanks during normal breathings a result of pumping and changes in temperature. Because crude and heavy oils form a protective oil film on the working areas of a tank shell, corrosion is generally limited to the top shell ring. Tank bottom corrosion occurs mostly with crude oil tanks and is caused by water and salt in the crude oil.

3- Hydrogen sulfide. Sour crude oils and gases that contain hydrogen sulfide are handled by most refineries. Hydrogen sulfide is also present in some feed stocks handled by petrochemical plants. During processing at elevated temperatures, hydrogen sulfide is also formed by the decomposition of organic sulfur compounds that are present. Corrosion of steel by hydrogen sulfide forms the familiar black sulfide film seen in almost all refinery equipment. Hydrogen sulfide is the main constituent of refinery sour waters and can cause severe corrosion problems. carbon steel has fairly good resistance to aqueous sulfide corrosion because a protective iron sulfide film is formed.

4- Hydrogen Chloride:

[Mohamed]

Stress-corrosion crac*k

1-Chloride SCC: Chlorides are present in a number of refining units. Including crude distillation, hydrocrac*king and hydrotreating and reforming. Chlorides are also found in other units as contamination from upstream processing, or they are introduced with stripping stream. Process water or cooling water. The Latter is a particular problem in petrochemical processes that use stainless steel heat exchangers to make steam as a means of recovering waste heat. Any chloride contamination of boiler feed water can result in chlorides concentrating on heat-exchanger tubes and can cause petting and SCC. As a rule, austenitic stainless steels are not recommended for components in which water is likely to evaporate or condense out. There are no simple methods of preventing SCC when an austenitic stainless steel must be used in an environment known to contain chlorides. Chloride SCC in refineries and petrochemical plant often occur under shutdown conditions when air and moisture enters equipment opened for inspection and repair. In particular, excluding air and moisture by nitrogen blanketing and rinsing equipment with an aqueous 0.5% sodium nitrate solution have been shown to inhabit chloride SCC. One method of preventing the catastrophic failure of components by chloride SCC would be the use of austenitic stainless steel as an internal cladding.


2-Caustic Crac*king: Stress-corrosion crac*k of various steels and stainless steels by Caustic (sodium hydroxide) is also fairly common in refinery and petrochemical plant operations. Caustic is added in the form of 5 to 40% aqueous solution to certain process streams In order to neutralize residual acid catalysts, such as sulfuric acid, hydrofluoric acid, and hydrochloric acid. Caustic is also added to cooling water and boiler feed water to counteract large decreases in PH value due to process leaks. Caustic SCC of carbon steel occurs at temperature above 50 to 80 C (l20 to 180 F), depending on caustic concentration. Welded carbon steel components that are exposed to caustic solutions above these temperature should be post weld heat treated at 620 C (1150 F) for l h per 25 mm(l in.) of metal thickness. Crac*king of austenitic stainless steels is often difficult to distinguish from crac*king by chlorides, particularly because common grades of caustic also contain some sodium chloride. As a general rule however, SCC by Chlorides is usually but not al ways in the form of transgranular crac*king, while caustic causes intergranular crac*king, sometimes accompanied by transgranular crac*king due to the presence of chlorides.

3-Ammonia Crac*king: Ammonia has caused two types of SCC in refineries and petrochemical plants. The first is crac*king of carbon steel in anhydrous ammonia service, and the second type is crac*king of copper allays, such as admiralty metal (C44300). In copper alloys, SCC can occur by ammonia contamination of process streams or by ammonia -base neutralizers that are added to control corrosion. Carbon steel storage vessels, primarily spheres, have developed stress-corrosion crac*ks in anhydrous ammonia service at ambient temperature but elevated pressure. To minimize the likelihood of crac*king, only low-strength steels should be used in anhydrous ammonia service, Welds should be post weld heat treated. Water consent of at least 0.2% should be maintained in the ammonia because water has been found to be an effective inhibitor of crac*king. Air contamination increases the tendency toward crac*king and should be minimized.

4-Amine Crac*king: Stress corrosion crac*king of carbon steel by aqueous amine solutions, which are used to remove hydrogen sulfide and carbon dioxide from refinery and petrochemical plant streams, has been a problem for a number of years. Crac*king found at welds exposed to amine solutions at temperatures ranging from 50°C (125 °F) to below 95 C (200°F). Crac*king was Inteigranular, with crac*k surfaces covered by a thin film of magnetite. No crac*king found in piping that had received post weld heat treatment and was operating at temperatures as high as 155 °C (310 CF). Amine SCC appears to be a form of alkaline SCC that is similar in many ways to caustic SCC. The failure mode is Inteigranular crac*king in otherwise ductile material, usually without the formation of visible corrosion products. To prevent amine SCC welds of carbon steel components in amine service should be post weld heat treated regardless of service temperature.

4-Polythionic Acid Crac*king: Stress-corrosion crac*king of austenitic stainless steels by potythionic acids was first identified with the introduction of hydrotreating units. austenitic stainless steels were required to provide resistance to high temperature sulfidic corrosion in the presence of hydrogen. It was found that unstabilized austenitic stainless steels would crac*k adjacent to weldments during shutdowns. Similar crac*king was also found in hydrocrac*king units and, more recently, in catalytic crac*king units, in which austenitic stainless steels have found greater use because of an increase in catalyst regeneration temperatures. Polythionic acid SCC occurs only in austenitic stainless steels and nickel-chromium-iron alloys that have become sensitized through thermal exposure. Addition of stabilizing elements, such as titanium, or limiting the amount of carbon are two methods for reducing the effects of welding and heat treating on sensitization. Laboratory studies and plant experiences have demonstrated that austenitic stainless steels are not sensitized when applied as a weld overlay over carbon or low-alloy steels. Polythionic acids are formed by the reaction of oxygen and water with the iron / chromium sulfide scale that covers the surface of austenitic stainless steel components as a result of high- temperature sulfidic corrosion. Because neither oxygen nor water is present during normal operation under conditions in which austenitic stainless steels would be used, SCC evidently occurs during shutdowns. Oxygen and water originate from steam or wash water used to free components of hydrocarbons during shutdown before inspection or simply from atmospheric exposure. In general. However, SCC by polythionic acid is considered to be a problem primarily during shutdown periods, suitable procedures to prevent crac*king include nitrogen purging of components that were opened to the atmosphere, purging with dry air having a dew point below -15 C (5 F), or neutralizing any polythionic acids that are formed, by washing components with a 2% aqueous soda ash (sodium carbonate) solution. Soda ash solution should also be used for hydrotesting prior to returning components to service. Residues of soda ash solution should be left on components during temporary storage to prevent SCC.

[Mohamed]

Hydrogen Damage

Corrosion of carbon and low-alloy steels by aqueous hydrogen sulfide solution or sour waters can result in one or more types of hydrogen damage. These include loss of ductility on slow application of strain (hydrogen embrittlement), formation of blisters or internal voids (hydrogen blistering), and spontaneous crac*king of high-strength or high-hardness steels (hydrogen stress crac*king). Atomic hydrogen (H) forms as part of the corrosion process and then evolves from cathodic areas of the metal as molecular hydrogen (H2). As the concentration of atomic hydrogen builds up at the surface it diffuses into the steel and reduces its ductility this embrittling effect is caused by hydrogen atoms collecting between metal atoms.

1-Hydrogen embrittlement: is characterized by decreasing ductility with decreasing strain rate. For example, the ductility of carbon steel has been reported to drop from 42 to 7% when charged with hydrogen. Failure in the form of crac*king usually occurs some time after a load is applied to hydrogen-charged steel. Because this phenomenon is also known as static fatigue, the minimum load for failure to occur is known as the static fatigue limit. Hydrogen embrittlement is temporary and can be reversed by heating the steel to drive out the hydrogen.

2-Hydrogen blistering: has been a problem primarily in the vapor recovery (Light ends) section of catalytic crac*king units and, to. Lesser degree in the low-temperature areas of the reactor section of hydrotreating and hydracrac*king units. Hydrogen blistering often accompanies hydrogen embrittlement as a result of aqueous sulfide corrosion. As rule, the severity of hydrogen blistering depends on the severity of corrosion. Vapor/liquid interface areas in equipment often show most of the damage, probably because ammonia, hydrogen sulfide, and hydrogen cyanide concentrate in the thin water films or in water droplets that collect at these areas. The basic approach toward reducing corrosion and hydrogen blistering in the various vapor-compression stages of catalytic crac*king units should be aimed at decreasing the concentration of cyanide and bisulfide ions in water condensate. Several methods for accomplishing this have been used :
1- Conversion of cyanide to harmless thiocyanate (SCN) by injection of air or poly-sulfide.

2- Water washing of the compressed wet gas streams, in conjunction with corrosion inhibitor injection. Water washing reduces the concentration of cyanides; Corrosion Inhibitors help control aqueous sulfide corrosion and hydrogen blistering even though cyanides may still be present.
3- Where limited hydrogen blistering occurs in certain components of hydrotreating and hydrocrac*king units, it is usually sufficient to Line affected areas with stainless steel or alloy 440 (N04400).

3-Hydrogen Stress Crac*king: Sour water containing hydrogen sulfide can cause spontaneous crac*king of highly stressed high-strength steel components or in carbon steel components containing hard welds. Crac*king is typically transgranular and will contain sulfide corrosion products. Crac*king of this type has become known as hydrogen stress crac*king or sulfide crac*king. Hydrogen stress crac*king occurs in the same corrosive environments that lead to hydrogen embrittlement andas is in the case of hydrogen embrittlement and hydrogen blistering; hydrogen stress crac*king of steel in refineries and petrochemical plants often requires the presence of cyanides.The most effective way of preventing hydrogen stress crac*king is to ensure that the steel is in the proper metallurgical condition also postweld heat treatment of fabricated equipment will greatly reduce the occurrence of hydrogen stress crac*king.


Hydrogen Attack
The term hydrogen Attack or in more specifically, high-temperature hydrogen attack refers

[jarlet]

Can you share this book please.
Thanks.

[FATHI]

Good presentation.

thanks a lot

[lachin]

yes it gives really good brief information. Thanks Mohamed.

[dmrodrigues]

Can you share this book please.
Thanks

[Mohamed]

Can you share this book please.
Thanks

i don't have soft copy