High Temperature Hydrogen Attack In Indian Oil Corporation, Haldia Refinery

Brief overview of various process units in Haldia Refinery, working of

Inspection department and detail study of HTHA phenomena, factors and

units affected within the refinery.

DEPARTMENT OF METALLURGY AND MATERIALS ENGINEERING NATIONAL INSTITUTE OF TECHNOLOGY, DURGAPUR

For the award of degree of BACHELOR OF TECHNOLOGY

In METALLURGY AND MATERIALS ENGINEERING

By Arijit Karmakar (12/MME/29)

Dolma Tamang (12/MM/10) R. Sanish (12/MM/70)

CERTIFICATE

This is to certify Industrial Training Work titled “High Temperature Hydrogen Attack: In Indian Oil Corporation, Haldia Refinery” that is submitted by Arijit Karmakar (12/MME/29), Dolma Tamang (12/MM/10) R. Sanish (12/MM/70) 3rdyear students of B.Tech, Metallurgy and Materials Engineering of National Institute of Technology, Durgapur, during the academic year 2014-2015 and it has found worthy of acceptance. Date: Shri Nilratan Baidya Inspection Department

ACKNOWLEDGEMENT

We are really grateful because we managed to complete our project work on

the topic “High Temperature Hydrogen Attack” within the given time. We are

thankful to Indian Oil Coorporation Limited for giving us the opportunity to

pursue vocational training in their industry.

We would like to thank Mr. A.B. Das for guiding us throughout the training

period and also Mr. G.C. Kundu for making us aware of various safety

procedures opted inside the refinery.

We also sincerely thank our mentors Mr. Nilratan Baidya, Mr. K. Boral, Mr.

Arun Kumar Kar, Mr. Tamal Ghoshal, Mr. Gourab Seal, Mr. Amit Kumar Mishra,

Mr. Krishanu Saha and Mr. Avik Dey for the guidance and encouragement in

finishing this project and also for teaching us during the course. We

acknowledge with a deep sense of obligation, the encouragement and valuable

support received throughout the course of this project.

Last but not the least we would like to express our gratitude to our friends

and respondents for the support and willingness to spend some time with us

to fill in the questionnaires.

DECLARATION

We hereby declare that the project report titled “High Temperature Hydrogen Attack: In Indian Oil Corporation, Haldia Refinery” submitted is an original work carried out by us. The matter embodied in this Industrial Training Report is a genuine work by me done during the visit to IOCL, Haldia Refinery and has not been submitted earlier to college or any other university.

Arijit Karmakar Dolma Tamang R. Sanish

TABLE OF CONTENT

1. Haldia Refinery An Overview

2. Fire & Safety

3. Inspection Department

Role/activities of inspection Inspection Instrument & Tools Inspection Procedure Inspection Techniques

4. PROCESS UNITS DESCRIPTION

Fuel Oil Block (FOB) Lube Oil Block (LOB) Once Through Hydro Cracking Block (OHCU) Diesel Hydro Desulphurization Unit (DHDS) Captive Power Plants (I & II) Oil Movement & Storage Facilities

5. High Temperature Hydrogen Attack (HTHA)

What is HTHA? Mechanism Different forms of HTHA Factors influencing HTHA Inspection and detection of HTHA Prevention of HTHA Overview of process units vulnerable towards HTHA Conclusion

6. Bibliography

Haldia Refinery

An Overview Haldia Refinery was commissioned in January 1975 with refining capacity of 2.5 MMTPA of Middle East Crude with two sectors – one for producing fuel products and the other for Lube base stocks. The refinery is in Haldia near Kolkata (West Bengal). The fuel sector was built with French collaboration and the Lube sector with Romanian collaboration. The refining capacity of the refinery was increased to 2.75 MMTPA in 1989 through debottlenecking measures. The refining capacity was further expanded to 3.75 MMTPA with the commissioning of new crude distillation unit of 1.0 MMTPA in March 1997. The present refining capacity of this refinery is 7.50 MMTPA. The present facilities of Haldia Refinery include:

30 individual Process Plants Offsite facilities including: 208 Storage tanks Bitumen Drum filling plants Effluent Treatment Plant Product dispatch facilities Captive Power Plant with: 4 Boilers : 3 x 125MT/hr+1x150MT/hr 4 TGs : 3 x 10.5 MW + 1 x 16.5 MW Gas Turbines: 3 x 20MW with HRSG: 1 x 100MT/hr+ 2 x130 MT/hr

LAYOUT OF HALDIA REFINERY

FIRE & SAFETY

The plant and equipment of refineries are generally modern, and the processes are largely automatic and totally enclosed. Routine operations of the refining processes generally present a low risk of exposure when adequate maintenance is carried out and proper industry standards for design, construction, and operation have been followed. However, the potential for hazardous exposures always exists. The crude undergoes several processes in the refinery for production of various petroleum products which can be hazardous not only in their final state but during their processing and refining stages too.

o Fire Hazards

The principal hazards at refineries are fire and explosion. Refineries process a multitude of products with low flash points. Although systems and operating practices are designed to prevent such catastrophes, they can occur. Constant monitoring is done by the Fire& Safety Control Room. Safeguards include warning systems, emergency procedures, and permit systems for any kind of hot or other potentially dangerous work. The use of matches, lighters, cigarettes, and other smoking material is generally banned in the plant except in specially designated areas called smoking booths.

o Chemical Hazards

In a refinery, hazardous chemicals can come from many sources and in many forms. In crude oil, there are not only the components sought for processing, but impurities such as sulphur, vanadium, and arsenic compounds. The oil is split into many component streams that are further altered and refined to produce the final product range. Most, if not all, of these component stream chemicals are inherently hazardous to humans, as are the other chemicals added during processing. Hazards include fire, explosion, toxicity, corrosiveness, and asphyxiation.

o Health & Hygiene Hazards

Care should be exercised at all times to avoid inhaling solvent vapours, toxic gases, and other respiratory contaminants. Because of the many hazards from burns and skin contact, most plants require that you wear long-sleeved shirts or coveralls. The table reviews common hazardous chemicals and chemical groups typically present and their most significant hazards.

Common Hazardous Materials Material Dominant Hazard Additives Usually Skin Irritants Ammonia Toxic on Inhalation Asphalt Dermatitis (can be photosensitizer) Benzene Designated substance under industrial regulation Carbon Monoxide (CO) Toxic on Inhalation Caustic Soda Corrosive to eyes and skin High Boiling Aromatic Hydrocarbons (HBAHs)

Potential Carcinogens

Hydrofluoric Acid Corrosive to skin and tissue on contact/inhalation

Hydrogen Sulphide (H2S) Toxic on Inhalation Methyl Ethyl Ketone (MEK) Corrosive to skin Nitrogen Asphyxiant Nitrogen Oxides (NOx) Corrosive to skin and tissue on inhalation Sulphuric Acid Corrosive to skin and tissue on contact/inhalation Sulphur Oxides (SOx) Toxic on Inhalation

Safe Work Practices and Procedures To ensure the safety of every personnel working in the plant, they are advised to equip with Personal Protection Equipment (PPE)-

o Hearing protection and safety glasses must be worn in all operating areas or as posted. o While working on the field, always wear safety shoe and helmet with strap. Use

leather/rubber gloves and mono-goggles while inspection. o Respiratory protection or equipment must be fit tested. o Facial hair is unacceptable where the mask must make an airtight seal against the face. o Shirts must be long-sleeved and worn with full-length pants or coveralls. o Clothing must not be of a flammable type such as nylon, Dacron, acrylic, or blends. Fire-

resistant types include cotton, Nomex, and Proban. o Smoking is allowed only in designated areas/smoking booths.

Emergency Warning System and Procedures In the refinery there are both plant alarms and individual unit alarms. All workers must receive training in recognizing and responding to these alarms. Verbal messages usually accompany the alarms. There are different alarms for a fire emergency and toxic alarm.

When an alarm sounds, secure all equipment and shut down all vehicles. Note the wind direction (wind socks) and proceed to the appropriate assembly area (or safe

haven). Do a head count to make sure all personnel are accounted for and report the result to a

client contact person. Know the local designated safety areas and emergency phone number(s).If you are the one

who is first aware of an emergency, then call the emergency number.

Haldia Refinery Siren Code Small Fire- No Siren Major Fire- Wailing Siren for 2 min Disaster- Major fire Siren 5 timeswith an interval of 1 min in between (total 8 min) All Clear- Straight Siren for 2 min Test- Straight Siren for ½ min everyday at 7:45am

Inspection Department

The role of inspection is very important during construction stage, operation and shutdown for planning and reliability and run down length improvement of the equipment. From safety angle and checking of equipment failure due to erosion and corrosion and thereby preventing unscheduled shutdown of various units is one of its major importance.

Role/activities of inspection To ensure safe and uninterrupted plant operation through availability of static equipments. To reduce downtime of the static equipments and process / utility piping. Routine inspection of units and offsite area to check various parameters which effect

corrosion pattern and abnormalities. Periodic /shutdown and maintenance inspection. Also breakdown inspection. RLA study, health forecast for short term/long term measures for reliability improvements. Metallurgical up-gradations as per requirements based on performance and suitability of

material in particular service conditions. Hence providing quality control throughout the refinery.

To inspect, measure and record the deterioration of material and to evaluate present physical condition of the equipments and its components for their soundness to continue in service.

To maintain up-to date maintenance and inspection records and history of equipments To implement new and latest inspection technologies for better plant reliability. To ensure testing of equipments as per statutory requirements. To carry out failure analysis of all failed static equipments and advice remedial measures

for non-occurrence of such failures in future.

Inspection Instrument & Tools Inspection department is having variety of inspection instruments and tools which are used for Non-destructive testing, temperature measurement of hater tubes, thickness checking of equipments and piping, dimension measurement, quality checking of paints and coatings etc. List of instruments is attached below.

List of Instruments Ultrasonic Flaw Detector Magnetic Particle Testing Hardness Tester Ultrasonic Thickness Gauge SHORE A rubber hardness tester SHORE D rubber hardness tester Ferritescope Alloy Analyzer

Thermography Camera Infrared thermometer DFT Meter

Inspection Procedure During inspection of equipments, inspection procedures are to be followed as per different standards / manuals and codes. On the basis of experience and different Indian and International codes e.g. IS, ASME, BS, API, ANSI, NACE, TEMA etc. inspection procedures are referred.

Inspection Techniques Common inspection techniques to be followed for inspection of equipments on-stream as well as during shutdowns are Visual, Ultrasonic Testing & Thickness measurement, Radiography, Magnetic Particle Inspection, Dye Penetrant Test, Hardness checking, Paint Thickness Measurement, Spot Chemical Analysis, Microscopic Examination, Hydrostatic or Pneumatic Testing, Vacuum Testing, Spark Testing of Rubber Lining, Holiday testing , Temperature Scan & Thermography, Automatic Ultrasonic testing (AUS), Internal rotary Inspection system (IRIS), Acoustic Emission testing (AET), LFMPT, Time of flight, Diffraction (TOFD), Phase Array –UT, Corrosion measurement (Corrosion Coupons, LPR, ER, CEION probes) and Eddy current Testing.

ON-STREAM INSPECTION

Prior to inspection of equipments, the inspector should familiarize himself with the complete previous history of the equipment, its design parameters, service, original thickness, corrosion allowance, corrosion rate and vulnerable location of corrosion. The on-stream inspection shall be carried out to determine the extent of general damage and deterioration of the heater. Findings of on-stream inspection form a basis to determine the repairs to be carried out during the next planned shutdown of the equipment. It also helps to identify and rectify unsafe conditions arising out of faulty operation.

INSPECTION DURING SHUTDOWN

Comprehensive internal / external inspection of static equipments is done during planned M&I shutdown of the plant. Assessment of remaining safe life of individual equipment/process piping is worked out from the thickness data and other inspection observations made during this period.Prior to scheduled shutdown of the unit, the unusual condition of the equipments should be recorded during on-stream inspection. During shutdown, before cleaning the equipment, preliminary internal inspection shall be done. Preliminary inspection shall reveal the areas having deposits, scales etc. requiring thorough cleaning to detect metal wastage underneath the deposits during detailed inspection. After the Preliminary inspection, clearance for internal cleaning may be given.Before going for inspection, internal or external, of any equipment like furnaces, columns, vessels, reactors, piping etc., the inspector should update himself with its complete history like original thickness of the equipment or piping, corrosion allowances, corrosion rate, previous repair job undertaken, data on daily routine observations and history of any plant upset or abnormal condition.

PROCESS UNITS DESCRIPTION

BLOCK FLOW DIAGRAM OF HALDIA REFINERY

Fuel Oil Block (FOB)

CRUDE DISTILLATION UNIT (CDU-I)

The Crude Distillation Unit (CDU-I) at Haldia Refinery was originally designed for processing of 2.5 MMTPA. The unit was debottlenecked in Dec’84 to 2.75 MMTPA by minor modifications. After that trays and column internals replacement was undertaken in May’88 with the help of M/S EIL to suit the column to process 3.16 MMTPA. Subsequently a Prefractionator column was installed in May’96 which increased the capacity of CDU to 3.5 MMTPA. Working:

The crude oil is heated to 120-130oC in the first set of Pre-heat Exchangers before feeding to the

Desalter. Crude is desalted to the extent of 95% in the Desalter. Crude is thereafter heated to approximately 180-200°C in the second set of exchangers and pretopped in the prefractionator column to get overhead gasoline from the top and pretopped crude from the bottom of the column. Again Crude is heated to 260-265°C in the third set of exchangers and then up to 350-360oC in the furnace. The crude oil is then fractionated in the Atmospheric Distillation Column.The overhead cut

is fractionated in stabilization column into two products. The Stabilizer overhead product is first distilled in De-ethaniser of Gas Plant for separation of Ethane. LPG from Gas Plant is caustic washed and then sent to LPG Extractor and after caustic separation is sent to LPG storage. De-ethaniser bottom is Amine Washed for removal of H2S and then routed Merox. A part of Merox treated LPG is fractionated in De-propaniser column of Gas Plant. The stabilizer bottom is routed to Naphtha Redistillation column. The C5–90 cut from overhead is routed for caustic wash to remove H2S and then sent to Naphtha Storage. 90-140 cut from bottom is used as feed stock for Catalytic Reforming Unit. The Heavy Naphtha is drawn from the main distillation column as the first side drawnoff and blended on line with sweet HSD coming from DHDS. The Kerosene/ATF/MTO/RTF is produced from the Kero side draw off and routed to intermediate storage tanks for subsequent treatment in Kero HDS. The Straight run gas oil is drawn and directly routed to sour HSD storage. The Jute Batching Oil (clear and pale grades) is directly drawn from Main Distillation Column in blocked out operation and is sent to JBO storage. The Reduced Crude is sent to Vacuum Distillation for further fractionation into Lube Oil Distillate cuts.

CRUDE DISTILLATION UNIT (CDU-II) The Crude Distillation Unit (CDU-II) at Haldia Refinery was originally designed for processing of 1.5 MMTPA crude. Subsequent to revamp in 2009, the capacity has been increased to 4.2 MMTPA. Working: Crude Oil is heated to 125-130OC in the first set of Pre-heat exchangers before feeding to the desalters. Crude is further heated in second set of heat exchangers to around 2100 C and then sent to Prefractionator Column. The prefractionated crude is heated further in another set of preheat exchangers and then heated in furnace to around 350-360oC . This is then fractionated in the Atmospheric Distillation Column. The overhead product of both Atmospheric and Prefractionator Column is fractionated in Naphtha Stabilizer. Stabilizer overhead product is distilled in De-ethaniser for separation of ethane.16C05 overhead gases which is rich in ethane is sent to fuel gas system of the refinery. De-ethaniser bottom is sent for LPG Caustic treatment. The Stabilizer bottom is sent to Naptha Splitter. In Naptharedistillation column, C5-140 cut from bottom is fractionated into C5-90 and 90-140 cuts. C5-90 cut from overhead is routed for caustic wash. 90-140C cut from bottom and light naphtha from prefractionator is used as feed stock for Catalytic Reforming Unit. Kerosene is drawn off as side cut and after stream stripped in the side stripper is routed to storage. Light Gas oil is also drawn off and after steam stripped in the stripper routed to storage. LGO forms one of the components of HSD. Heavy Gas oil is drawn off and after steam stripped in the stripper routed to storage. HGO forms one of component of HSD. Reduced Crude Oil obtained from the bottom is sent to rundown tanks.

NAPHTHA HYDRO DESULPHURISATION UNIT (NHDT) The objective of Naphtha Hydro Desulphurization Unit is to treat a straight run naphtha and heavy FCC gasoline to produce Naphtha containing less than 0.5 wt ppm sulfur and less than 0.1 wt ppm nitrogen. Heavy SR naphtha and Heavy FCC gasoline are taken as Feed in the unit. The Feed-mix is preheated in Heat Exchangers and subsequently enters the furnace. The hydrotreating reaction takes place in 1st Hydrotreating Reactor and 2nd Hydrotreating Reactor. The Effluent is cooled in the tube side of preheat exchangers and sent to the separator drum. The liquid from the separator drum, it is reheated in the shell side of exchangers and is fed to the stripper. The stripper overhead vapors are cooled in condenser and the liquid is collected in the reflux drum to be pumped to the stripper as reflux. The stripper bottom is routed as Reformer feed or to storage.

CATALYTIC REFORMING UNIT (CRU) The purpose of the Catalytic Reforming unit is to improve octane number of hydrotreated gasoline, producing a total reformate cut (RONC 97) and hydrogen rich gas. The Pretreated naphtha is mixed with the recycle gas and is preheated in the welded plates exchanger (Packinox). The mixture is also preheated and then is further heated in a preheater and then fed to a reactor. The effluent from the first reactor is reheated in furnace and is then passed through the 2nd Reactor. Effluent from the second Reactor is again reheated in furnace and passed through Reactor. The effluent from reactor is cooled and partially condensed in a series of exchangers (tube side), Packinox exchanger and Cooler. The effluent thereafter is sent to the separator drum. The liquid from the separator drum is reheated and is fed to the stabilizer. The stabilizer overhead vapors are cooled and partially condensed by condenser and are collected in the overhead horizontal reflux drum. The stabilizer bottom part is passed through exchangers and coolers before it is sent to storage and feed to reformate splitter.

KEROSENE HYDRO DESULPHURISATION UNIT (KHDS) The purpose of the Kero Hydro Desulphurization unit is to process the raw kerosene distillate cuts produced from the Atmospheric Distillation Units. Raw kerosene/MTO/ATF/RTF feed from the storage is taken to the unit and mixed with recycle gas from compressor. The stream is heated in Heat Exchangers in the shell side while the hot reactor effluent passes through the tube side and is taken to the furnace. The heated feed then flows through a reactor wherein the desulphurization reactions take place. The effluent from reactor is cooled and partially condensed. Finally this effluent is sent to the separator drum. The liquid from the separator drum is preheated in exchangers, and fed into the Stripper Column. The stripper overhead vapors, upon leaving from the top are first cooled and partially condensed in the water cooler and then separated in the Reflux drum. The stripper bottom is cooled and sent to the storage.

Lube Oil Block (LOB)

VACUUM DISTILLATION UNIT (VDU-I) The function of the Vacuum Distillation Unit is to produce distillate cuts from RCO generated in Crude Distillation Unit at pressure less than atmospheric pressure to facilitate vaporization. Reduced crude received from the Atmospheric Unit or from Intermediate storage tanks is preheated to 285ºC in a train of heat exchangers and then it is partially vaporized by further heating in furnaces. Steam is injected in the vacuum heater with the feed and introduced into the flash zone of the Vacuum Distillation tower. The bottom liquid is steam stripped below the flash zone. The vapors leaving the flash zone of the vacuum tower pass through a demister pad to ensure removal of entrained asphaltenes. Most of the hydrocarbon vapor is condensed stepwise by top reflux as well as pump around sections and fractionated to produce five liquid side draw products. Some uncondensed and entrained gas oil with steam leave the top of the column and enter the vacuum system. The Gas oil and steam are condensed in surface condensers. The condensed oil is recovered from the hot well, and separated from water in a separator. Spindle oil, Intermediate oil and Heavy oil are provided with steam stripping facility. These products are routed to individual storage tanks. Excess quantities of these products are routed to Fuel Oil, Visbreaking Unit and to Internal Fuel Oil respectively. Unstripped Light Oil goes to either Visbreaking Unit or Fuel Oil storage tanks. Short Residue drawn from the bottom of the tower is sent to Propane Deasphalting Unit (PDA) and Visbreaking Units’ storage tanks. Vacuum in the tower is maintained by a set of booster and ejectors with surface condensers. The vapors leaving the top of the tower are taken into primary ejectors via precondensers from the two overhead vapor lines. The non-condensable gases are successively passed through inter condenser and secondary ejectors. The secondary ejectors exhausts non-condensable after passing through condenser directly to the atmosphere through a vent system via water seal pot.

PROPANE DE ASPHALTING UNIT (PDA) This Unit produces Deasphalted Oil (DAO) by removing asphalt from Short Residue obtained from VDU by extraction with liquid Propane. Solvent deasphalting takes short residue feed from VDU and removes the paraffinic DAO from the asphalt by counter current solvent extraction. In the extraction, the DAO component in the feed is soluble in the liquid propane at operating temperatures of the extractor. The asphalt component remains undissolved and settles down at bottom. The propane-DAO mix leaving the top of extractor is sent to a ROSE column. Here the feed is heated and maintained above the supercritical temperature of propane (above 93oC). At this temperature, the solubility of DAO propane is negligible and hence DAO separates out at bottom and sent out for further recovery.

FURFURAL EXTRACTION UNIT (FEU) The Furfural Extraction Unit (FEU) is designed to process distillate oils to improve viscosity index (VI) of the respective oil by extracting out the aromatics using furfural as solvent. Distillate oil is heated in Distillate oil vs De-aerator bottom and then in Feed-steam Exchanger and thereafter enters the Deaeration column. Deaerated distillate oil is sent through charge oil cooler into bottom of Extractor. Furfural is taken from Solvent Drying Tower through and cooler. Subsequently furfural enters Extractor for extraction process.

Raffinate solution from the top passes through (Raffinate solution vsRaffinate) and Heater. This outlet then enters raffinate flash tower where furfural vapors are discharged overhead and condensed. Liquid furfural is then collected. Raffinate solution from bottom passes to Raffinate Stripper for stripping out the trace amount of furfural from raffinate solution. Furfural and water vapors from the top enter the condensers. Mixture of liquid furfural and water is collected in vessel. From bottom of raffinate stripper, furfural free raffinate is passed through heat exchanger and cooler to the raffinate storage tanks. Extract solution from the bottom of extractor passes through Extract solution vs Furfural exchangers in series and finally flashed into Flash Tower. Furfural vapors from the top are cooled and pass into Furfural Drying Column. From the bottom of extract flash tower, extract solution is pumped to the Pressure Flash tower. Furfural vapors from the top are cooled in heat exchanger, Steam Generator and admitted into furfural drying column. Extract solution containing a low quantity of furfural passes from the bottom into Vacuum Flash Tower. Furfural vapors are discharged overhead and condensed. The extract solution from the bottom is passed to Stripper Column. Water and furfural vapors from the top enter the condensers and are collected in Wet Furfural vessel. From the bottom of extract stripper, furfural free extract is taken to de-aerator feed exchanger, steam generator and then into cooler and finally goes to storage tanks.

SOLVENT DEWAXING UNIT (SDU) Solvent Dewaxing Unit process the vacuum distillates obtained from VDU-I directly or after processing the same in Furfural Extraction unit NMP Unit. The objective of this process is to remove paraffinic hydrocarbons to the extent that the lube base stock produced will have enough low pour point so that is suitable for low temperature applications. Solvent dewaxing is a complex process which includes extraction and crystallization followed by filtration. The solvent blend (mixture of Methyl Ethyl Ketone (MEK) and Toluene) extracts the useful part of the feed stock (i.e. the lube oil) and crystallizes and precipitates the undesirable part (i.e. wax). The two phase mix thereby developed is filtered and the useful filtrate solution is separated from wax solution. [The above unit is no longer funtional]

HYDRO FINISHING UNIT (HFU) Hydrofinishing Unit is designed to meet the specification, to improve the colour and the colour stability of Lube Oil Base Stocks through hydrodesulphurization, mild hydrodenitrogenation, hydrogenation of olefins, aromatics and decomposition of other heteromolecules such as oxygenated compounds using hydrogen in presence of catalyst. [The above unit is no longer funtional]

NMP EXTRACTION UNIT (NMPU) The NMP (N-Methyl Pyrrolidone) Extraction Unit is designed for processing the intermediate distillate, mainly IO, HO and DAO to produce Lube Oil Base Stocks of higher viscosity index. NMP is used as a solvent for removal of undesired aromatics. The Unit consists of the following sections: Deaeration/ Extraction section Raffinate recovery section Extract recovery section Solvent recovery section

Solvent utility/ conservation section

WAX HYDRO FINISHING UNIT (WHFU) The Wax Hydrofinishing Unit produces micro crystalline wax (MCW) by removing sulphur and nitrogen from de-oiled wax obtained from Solvent De-waxing Unit (SDU). The Wax Hydrofinishing Unit contains four main sections: Feed Section where the feed is pumped from surge drum to filters and preheated. Then it injected in the reaction section after mixing with hydrogen. Reaction Section where the mixed stream is heated in feed/effluent exchangers and Feed Heater and reacted in Hydrofinishing Reactor. The effluent is cooled and flashed in HP separator drum. Separation section where the liquid phases and HP Cold separator are mixed and flashed in LP separators and liquid phase is sent to distillation section. Distillation section where the separated liquid is sent to steam stripper whose bottom product feeds Vacuum drier. The bottom product is withdrawn as final product.

CATALYTIC ISO DEWAXING UNIT (CDWU) The Catalytic Isodewaxing Unit consists of hydro-treating followed by catalytic de-waxing and hydro-finishing various hydrocarbon feeds, to produce low volatility Group II and III base stocks. The HDT processing step is a feed pretreatment consisting of a multi-bed lube hydro treating reactor, which is operated at high Cold Hydrogen Partial Pressure (130 to 135 kg/cm2-H2) and elevated temperatures (310 - 380 °C) to remove essentially all of the sulfur and nitrogen from the feedstock. The feed is heated and is mixed with recycle gas and then heated in HDT Reactor Charge Heater before it is fed in the Reactor. The HDT reactor effluent is cooled and goes to HDT Effluent Stripper. The vapor is cooled in HDT Stripper Overhead Cooler and Trim Cooler and then phase-separated in the HDT Low Temperature Separator. The liquid is sent to the High Pressure Stripper. The vapor is scrubbed with lean amine in the High Pressure Amine Absorber for H2S removal. The overhead vapor is sent to the Amine K.O. Drum and then to the Wash Water Column for NH3 removal. The sweetened vapors are reheated and combines with the bottoms liquid product. The combined stream is then heated in MSDW Feed/Effluent Exchanger and MSDW Reactor Charge Heater and goes to MSDW Reactor. MSDW reactor effluent is cooled against the reactor’s feed prior to entering the Hydrofinishing (HDF) Reactor. Liquids are fed to the HP Stripper for separation of naphtha and lighter material from the dewaxed oil stream. The effluent from the MSDW process is flashed and the liquid product sent to the Recovery Section. The liquid products - naphtha, light distillate, and heavy distillate and lube oil - are separated using steam stripping, and vacuum fractionation/drying. Dissolved gases in the MSDW liquid effluent are recovered as overhead product from the stream stripper, amine treated and delivered to the refinery fuel gas system. Unstabilized naphtha is recovered as the overhead liquid product from the steam stripper. Liquid product, boiling higher than ~177° C leaves the bottom of the steam stripper and enters the vacuum fractionators. Light distillate is recovered as the overhead liquid product from the Vacuum Fractionator. The mid-tower liquid is recovered as heavy distillate and the heaviest liquid leaves from the bottom of the vacuum fractionator, passes through a Vacuum Drier and is recovered as dewaxed lube oil.

Once Through Hydro Cracking Block (OHCU)

ONCE THROUGH HYDRO CRACKING UNIT The purpose of the unit is to process blends of heavy distillates (Spindle Oil, Light Oil, Intermediate Oil, Heavy Oil, De asphalted Oil and Light Cycle Oil) to maximize LPG and Diesel production through hydrogenation and hydro cracking reactions. The feed is pumped from feed surge drum to the reaction section heat exchangers train after mixing with hydrogen make-up and recycle gas. The feed is brought up to the required temperature in the reactor feed heater. The hydrogenation and hydrocracking catalysts takes place inside the reactors. The reactor effluent is used to preheat successively the reactor feed and the stripper feed. The reactor feed and the stripper feed is cooled in effluent air cooler. The cold reactor effluent is collected at the HP separator where three phases are separated. The sour water containing ammonium salts is routed to MP separator drum. The main part of the liquid HC is routed to the MP separator. The remaining part is directly routed to the MP separator. The HC liquid from the MP separator is withdrawn under flow control reset by level, it is then heated and routed to the stripper. This stripper removes H2S from the reaction section effluent. The stripper overhead is partially condensed in the air cooled condenser and in H2S stripper trim condenser. The H2S stripper bottom is fed to Main Fractionator after heating. The products from the fractionation section are a fraction of the heavy naphtha, kerosene, gas oil and residue. The naphtha is produced at the overhead and is sent to the naphtha stripper. The naphtha stripper bottom product is sent to the debutanizer. The debutanizer bottom product is sent to the naphtha splitter. The naphtha splitter splits the full range naphtha (C5–140°C) into a light naphtha (C5–125°C) and a heavy naphtha (125–140°C). The LPG is caustic washed to decrease the H2S content. The combined sour gas from the H2 membrane package, H2S stripper reflux drum and naphtha stripper reflux drum is treated in amine scrubber.

HYDROGEN GENERATION UNIT (HGU)-II The plant consists of a naphtha pre-desulfurization section, followed by a final desulphurization section, pre-reforming, reforming, process gas cooling with high temperature and low temperature shift reaction to increase the hydrogen content of the process gas and then purification and product routing. Finally the Hydrogen is purified by pressure swing adsorption technology of UOP. The Hydrogen unit is designed for SRN (straight run naphtha) or a mixture of FCC Gasoline and SRN with a wt. ratio of 20/80 (maximum). The following main process steps are:- Naphtha pre-desulphurization Naphtha vaporization by preheating followed by final desulphurization Pre-reforming Steam naphtha reforming Shift conversion Process gas heat recovery and cooling Hydrogen purification (PSA) Steam system Fuel system

In the PDS section bulk of the organic sulphur is removed by catalytically converting H2Sin Comox-I Reactor which is further removed in Naphtha Stripper. In desulphurization section, Removal of Sulphur and Chlorine takes place by selective adsorption of H2S and HCl on ZnO and Al2O3 respectively in Comox-II Reactor. In prereforming and steam reforming section, the feed in the presence of steam reacts to give a mixture of methane, carbon-dioxide, carbon monoxide and hydrogen over a Nickel based catalyst. The gas mixture which leaving the reformer enters the shift reactors, which utilizes a low temperature for further conversion of unconverted carbon monoxide to Hydrogen by reaction of CO and water in presence of catalyst. Finally PSA technology is used to remove the impurities from the reformed gas to produce 99.99% purity of the Hydrogen gas with expected recovery is 89.5%. The heat required for the reforming reactions in the steam methane reformer is supplied by purge gas fuel supplemented by vaporized fuel naphtha.

Diesel Hydro Desulphurization Unit (DHDS)

DIESEL HYDRO DESULPHURIZATION UNIT The purpose of the Diesel Hydro Desulphurization Unit is to upgrade the gasoil components by removal of containments like Sulphur, nitrogen through catalytic Unionfining© Process. Feed and Preheating Section: The Unit receives sour diesel feed from the atmospheric distillation unit means of the DHDS Feed Pumps. The feed is sent to the Feed Filters and Magnetic Feed Filter and enters the Stripper Bottom Feed Exchanger. The feed then is fed to Feed Coalescer and Surge Drum. From the drum the feed goes to the Feed Pumps and mixed with the recycle hydrogen, coming from the recycle compressor. The mixed phase feed enters the Cold Combined Feed Exchangers and then the Hot Combined Feed Exchangers. The combined feed stream enters the mixed phase Charge Heater to reach the desired reactor inlet temperature. Reaction Section: The reactants enter the top of the Reactor No. 1, a two catalyst bed reactor. As the reactants flow downward through the catalyst bed, various exothermic chemical reactions occur and the temperature increases. The sulfur and nitrogen contained in the feed are converted to hydrogen sulfide (H2S) andammonia (NH3) in the reactor. The reactor effluent is cooled in Hot Combined Feed Exchangers, Stripper Feed Effluent Exchangers, and Cold Combined Feed Exchangers. After this exchangers train, the reactor effluent is sent for further cooling in the reaction air cooler. Separation Section: Final cooling of the reactor effluent is obtained in Separator air fin Condenser. Water is injected into the stream, before it enters the air cooler. After the cooler, the treated gasoil is sent first to be heated and then finally fed to the stripper column to remove the H2S and the lighter hydrocarbons. The recycle gas from the Separator is cooled in the Recycle Gas Cooler by means of cooling water and then enters the Recycle Gas Scrubber KO Drum. From the drum, the light hydrocarbons are mixed with the treated gasoil from the Separator and sent to the stripper column. The recycle gas from the KO drum enters the bottom of the Recycle Gas Scrubber and is contacted counter-current with amine in the lower 9 trays section. The rich amine, under level control, from the bottom of the scrubber it is sent to the Amine Regeneration Unit. Fractionation Section: The stripper column feed enters the column on the 18th tray. The gasoil product from the stripper column bottom through the Stripper Bottom Pumps finally goes to the air cooler Diesel Product Cooler and Diesel Product Trim Cooler. The gasoil product enters the Diesel Product Coalescer and sent to storage. The overhead vapors are condensed in the air fin Stripper

Overhead Condenser and in the Stripper Overhead Trim Cooler. The overhead products then enter the Stripper Receiver. The sour gas, under pressure control, is sent to the amine washing system to remove the H2S, prior to be sent to the refinery fuel gas network. Stripper off-gas amine washing: The sour gas from the Stripper Receiver enters the Stripper Gas Absorber KO Drum and goes to the bottom of the Stripper Gas Amine Absorber and is contacted counter-current with amine over 21 trays. The clean gas is cooled in the Amine Absorber Off-gas Cooler, by means of cooling water, and then enters the Stripper Gas Amine KO Drum and goes to fuel gas network. The recovered amine is sent to the Amine Regeneration Unit.

SOUR WATER STRIPPING UNIT (SWSU) The function of the Sour Water Stripping Unit is to strip off the acid gases from the sour water generated in VDU-2, FCCU, DHDS, HGU and CDWU. The sour water is received in Sour Water Surge Drum and is pumped by to stripper column after preheating in the feed/bottom exchanger. The stripped water from the column bottom is first cooled in feed/bottom exchanger and in Stripped Water Cooler before routing to battery limit. The sour gas from top is routed to SRU.

HYDROGEN GENERATION UNIT (HGU-1) The purpose of the Hydrogen Generation Unit is to produce 99.99 vol% purity hydrogen from straight run naphtha. The hydrogen generation unit can be divided into four sections. These are:

Predesulphurization Desulphurization Reforming CO-Conversion

In the predesulphurization section the organic sulphur compounds are removed from naphtha by catalytic conversion to hydrogen sulphide. Hydrogen sulphide is removed by stripping in the H2S stripper and the pre-desulphurized naphtha is cooled and sent to the final desulphurization section. The desulphurization unit contains three reactors, Hydrogenator followed by two reactors where the hydrogen chloride and the hydrogen sulphide are absorbed. The gas from the final desulphurization section is mixed with steam and sent to the reforming section where hydrocarbons and steam react over the Topsøe nickel reforming catalysts. The steam reforming takes place in two steps: first in the adiabatic prereformer and then in the tubular reformer. The process gas leaving the tubular reformer passes through the waste heat boiler, then through 1st boiler feed water preheater and enters the medium temperature shift converter. The process gas after purification is cooled in BFW preheaters and goes to 1st process condensate separator. The gas is further cooled in DM water preheater, Process gas air cooler, Process gas water cooler and goes to 2nd process condensate separator and then to PSA inlet. The pressure swing adsorption (PSA) unit (designed by M/s UOP) is based on the selective adsorption of impurities on an adsorbent at high pressure and is capable to handle 34505Nm3/hr of feed gas (34381 Nm3/hr of dry gas) coming from second process condensate separator of hydrogen unit to produce 99.99% pure hydrogen.

SULPHUR RECOVERY UNIT (SRU) The Sulphur Recovery Units are designed to recover Sulphur from the sour streams originating from ARU and SWS. The SRU consists of the following sections:

A knock-out section for the feed gas streams and fuel gas stream A Claus section, consisting of a thermal stage and three reactor stages A SUPERCLAUS® stage

The amine acid gas feed from ARU is received and then mixed and heated in Acid Gas Preheater. The feed gas is then burnt in Combustion Chamber and after heat recovery in Waste Heat Boiler is fed to 1st Sulphur Condenser. The liquid Sulphur is drained into the Sulphur pit via Sulphur Lock. The stream is heated by the 1st Steam Reheater and goes to 1st Reactor. The effluent gas from 1st reactor goes to 2nd Sulphur Condenser. The liquid Sulphur is drained to the Sulphur pit via Sulphur Lock. The process gas passes to the 2nd Steam Reheater after which it is once again subjected to conversion in the 2nd Reactor and cooling in the 3rd Sulphur Condenser. The liquid Sulphur is drained to the Sulphur pit via Sulphur Lock. Then the process gas passes to the 3rd Steam Reheater and the 3rd Reactor. The Sulphur is condensed in the 4th Sulphur Condenser. To obtain a high Sulphur recovery, the process gas is passed to the fourth and last SUPERCLAUS® stage. In this stage, the process gas passes to the 4th Steam Reheater and the SUPERCLAUS® Reactor. The Sulphur is condensed in the 5th Sulphur Condenser and liquid Sulphur is sent to pit by lock. Downstream the process gas passes through Sulphur Coalescer. In Thermal Incinerator the combustible components in the tail gas from Sulphur Coalescer and vent gas from the Sulphur pit are thermally oxidized and heat is recovered in Waste Heat Boiler and Steam Superheater and goes to stack. The Sulphur from the Sulphur locks is cooled in the Sulphur Cooler and goes to Sulphur Pit. The liquid Sulphur is pumped via Sulphur Pump to the Sulphur Yard.

VACUUM DISTILLATION UNIT (VDU-II) The function of the Vacuum Distillation Unit is to fractionate Reduced Crude Oil (RCO) to obtain the Gas oil (GO), Spindle oil (SO), Light oil (LO), Intermediate oil (IO), Heavy oil (HO), Slop cut and Short residue (SR). The RCO is preheated in a train of preheat exchangers and then it is partially vaporized by further heating in furnace. After heating in the furnace the feed enters the flash zone of the Vacuum column. The bottom liquid is steam stripped in the stripping section below the flash zone. Most of the hydrocarbon vapor is condensed stepwise by Top circulating reflux as well as Light oil circulating reflux and fractionated to produce six liquid side draw products Gas oil, Spindle Oil, Light oil, Intermediate Oil, Heavy Oil & Slops. Some uncondensed and entrained gas oil with steam leaves the top of the column and enters the vacuum system. Vacuum in the column is maintained with the help of three stage ejector condensers. Three numbers of ejectors are present in each stage. The gas oil and steam are condensed in condensers and collected in hot well. Gas oil and sour water are separated in the hot well with the help of baffles and pumped out separately. Side cuts Spindle oil, light oil, Intermediate oil & Heavy oil are stripped of lighters in the side strippers with the help of super-heated stripping steam. These products after further cooling are routed to individual storage tanks. Short Residue drawn from the bottom of the tower, after cooling, is sent to PDA feed tanks, FCC feed tanks & IFO tanks.

AMINE REGENERATION UNIT The purpose of the Amine Regeneration Unit is to regenerate rich amine from Units and supply lean amine.

The ARU consists of 4 sections: the rich amine section, the amine regeneration section, the lean amine section and the amine storage section. The acid gas from the ARU overhead is routed to the SRU and the lean amine to DHDS, Lube Oil Block and Fuel Oil Block. The rich amine from the Recycle Gas Scrubber and Stripper Gas Amine Absorber of DHDS is combined outside battery limit and sent directly to Rich Amine Flash Drum. Rich amine from the bottom goes to Rich-Lean Amine Exchanger and sent to Amine Stripper. Acid gas from the top is cooled in Amine Stripper Condenser and trim condenser. The lean amine goes to battery limit.

Captive Power Plants (I & II) Captive Power Plants are those power plants which operate independent of wheeling to grid. They are mostly meant by in-house power generation for industry and not selling the power to grid of electricity boards. For efficient and un-interrupted running of a refinery, a reliable source of power is very much required. To meet electrical demands of process units and for maintaining dependable electrical power, steam and power generators have been installed. There are four nos. of steam turbo generators and five gas turbo generators for power generation and 4 nos. boilers-VHP and 3 no.s HRSG. While VHP boilers cater to the needs of steam requirements of STGs, HRSGs serve the demands of steam in various units of refinery. Boiler Technical Specifications Net output - 125 T/hr SH Steam Pressure- 62 Kg/cm2 (operating) SH Stem Temp. - 4500 C (operating) Feed Water Temp.- 2000 C at economizer inlet Efficiency at 100 % MCR - 88.30

Oil Movement & Storage Facilities Imported crude, brought by tankers, stored in Refinery's storage tanks is processed successively in different units and finished petroleum products are obtained, which are dispatched for marketing by tankers, barges, wagons, trucks, pipeline, drums, cylinders etc.The broad functions of OM&S are listed as follows: -

Receipt and storage (a) Crude oil from tankers (b) Intermediate /finished products from process units.

Preparation and supply of feed to various units. Blending of products. Dispatch of products. Supply of Internal fuel oil to all Furnaces. Unloading, storing and supplying various solvents and chemicals to units. Recovery of steam condensate. Accounting of petroleum products and observing necessary customs and excise formalities. Effluent Treatment.

High Temperature Hydrogen Attack (HTHA)

What is HTHA? At normal atmospheric temperatures, gaseous molecular hydrogen does not readily permeate steel, even at high pressures. Carbon steel is the standard material for cylinders that are used to transport hydrogen at pressures of 2000 psi. Many post-weld heat treated carbon steel pressure vessels have been used successfully in continuous service at pressures up to 10,000 psi and temperatures up to 221°C. However, under these same conditions, highly stressed carbon steels and hardened steels have cracked due to hydrogen embrittlement. At elevated temperatures, molecular hydrogen dissociates into the atomic form, which can readily enter and diffuse through the steel. Under these conditions, the diffusion of hydrogen in steel is more rapid. Hydrogen reacts with the carbon in the steel to cause either surface decarburization or internal decarburization and fissuring, and eventually cracking. This form of hydrogen damage is called high temperature hydrogen attack (HTHA). There are recommended practices to increase the resistance of steels to HTHA.

Mechanism

What causes HTHA?

Atomic hydrogen that is formed during the corrosion process or by dissociation of molecular hydrogen in a gas stream at the steel surface, diffuses into the steel. At grain boundaries, crystal imperfections, inclusions, discontinuities and other defects, the atomic hydrogen reacts with the dissolved carbon or metal carbides, forming methane:

8H + C+ Fe3C = 2CH4 + 3Fe Because of the pressure build-up of the methane in the steel, this result in the formation of intergranular cracks, fissures and blisters, that often extends to the surface. Moreover, the decarburization process leads to loss of carbon in the steel and hence a reduction in tensile strength and an increase in ductility and creep rate. HTHA microstructure:

Operational Limit

The above graph is known as the Nelson Curve for HTHA attack illustrates the resistance of steels to attack by hydrogen at elevated temperatures and hydrogen pressures. It gives the operating conditions (process temperature and hydrogen partial pressure) above which these types of attack can occur. The figure is often used when selecting materials for new equipment in hydrogen service. But it is important to recognize that it only addresses a material’s resistance to HTHA. It does not take into account other factors important at high temperatures, such as: a) Other corrosives that may be in the system, such as hydrogen sulfide, b) Creep, temper embrittlement, or other high temperature damage mechanisms, c) Interaction of hydrogen and stress (primary, secondary and residual), and d) Synergistic affects such as between HTHA and creep.

Susceptible Areas

HTHA affects carbon and low alloy steels, but is commonly found in Carbon Steel and Carbon-0.5 Mo steel that is operating above its corresponding Nelson Curve limits. Areas that are hotter, often near the outlet nozzle of catalytic equipment or the inlet nozzle of an exchanger that is cooling the process, are areas of concern for HTHA. Welds often suffer from HTHA degradation as well.

Different forms of HTHA HTHA in steels are seen in two forms as follows:

Surface Decarburization

The combination of high temperature and low hydrogen partial pressure favors surface decarburization. The broken-line curves at the top of the Nelson Curve shown in the Mechanism section represent the tendencies for surface decarburization of steels while they are in contact with hydrogen. The currently accepted theory for surface decarburization is based on the migration of carbon to the surface where gaseous compounds of carbon are formed, rendering the steel less rich in carbon. The gaseous compounds formed are CH4 or, when oxygen-containing gases are present, CO. Water vapor hastens the reaction. Carbon in solution diffuses to the surface so that the rate controlling mechanism appears to be carbon diffusion. As the carbon in solution is continuously supplied from the carbides, carbide stability is directly related to the rate of surface decarburization. In cases where surface decarburization predominates over internal attack, the actual values of pressure-temperature combinations have not been extensively studied. The usual effects of surface decarburization are a slight, localized reduction in strength and hardness and an increase in ductility.

Internal Decarburization and Fissuring

The combination of low temperature, but above 221°C, and high hydrogen partial pressure favors internal decarburization and fissuring, which can eventually lead to cracking. The solid-line curves represent the tendencies for steels to decarburize internally with resultant fissuring and cracking created by methane formation. Internal decarburization and fissuring are caused by hydrogen permeating the steel and reacting with carbon to form methane. The methane formed cannot diffuse out of the steel and typically accumulates at grain boundaries. This results in high localized stresses which lead to the formation

of fissures, cracks, or blisters in the steel. Fissures in hydrogen-damaged steel lead to a substantial deterioration of mechanical properties. The presence of nonmetallic inclusions tends to increase the extent of blistering damage. When steel contains segregated impurities, stringer-type inclusions or laminations, hydrogen or methane accumulations in these areas may cause severe blistering. Surface decarburization without fissuring has been associated with hydrogen partial pressure and temperature conditions that are not sever enough to generate the methane pressures needed to form fissures. This typically occurs where the Nelson curves become vertical. At high temperatures and high hydrogen partial pressure both mechanisms are active. Microstructure HTHA voids on grain boundaries are shown below (left) and on the right blistering on C-0.5Mo nozzle flange is shown:

Factors influencing HTHA

Steel Composition

Carbide Forming alloy elements, such as Cr, Mo, V, Nb, Ti, reduce the tendency to internal fissuring, due to its stabilizing influence on internal iron carbides. At a hydrogen partial pressure value of 6.9 MPa, absolute, for example, no HTHA attack is expected for carbon steels at temperatures of 500 °F, and lower. For 1.25 Cr 0.5 Mo steels at the same pressure, however, no HTHA attack is expected at temperatures up to 975 °F. These inter-relationships between steel type, hydrogen partial pressure, temperature, and forms of HTHA attack, are summarized on curves developed by G.A. Nelson, and referred to as Nelson Curves. The first of these curves were developed in 1949, and have provided satisfactory guidance for many years. However, longer-term exposure showed damage in C–0.5 Mo and Mn-0.5 Mo steels, at operational conditions below the appropriate C-0.5 Mo immunity lines. The latest guidelines for these steel types indicate that the carbon steel immunity line should be used as the guideline to establish C–0.5 Mo and Mn-0.5 Mo susceptibility.

Incubation Time

HTHA begins once the service conditions (high pressure and high temperature hydrogen) are such that the hydrogen diffused into the steel beings to react with the carbon or carbides in the steel. A series of microscopic damages occur in the steel after which material damage is evident with resultant decreases in strength, ductility, and toughness. This varies with the type of steel and severity of exposure; it may lastonly a few hours under extreme conditions and become progressively longer at lower temperatures and hydrogen partial pressures. With some steels under mild conditions, no damage can be detected even after many years of exposure. During this

initial stage of attack, in some cases, laboratory examination (high magnification metallography, utilizing optical microscopy and scanning electron microscopy) of samples removed from the equipment have revealed the initial stages of attack with voids at grain boundaries. The length of the incubation period is important because it determines the useful life of steel at conditions under which HTHA occurs. During the incubation period, methane pressure builds up in submicroscopic voids. These voids grow slowly due both to internal methane pressure and applied stress. When the voids reach a critical size, and begin connecting to form fissures, the effects on mechanical properties become evident. The incubation period depends on many variables, including the type of steel, degree of cold working, amount of impurity elements, applied stress, hydrogen pressure, and temperature.

Primary Stresses

The Nelson curves have been drawn up on the basis of steels operating at stress levels not exceeding the limits imposed by Section VIII, Division 1 of the ASME code. No cases of observed damage of units operated below the Nelson Curves have been attributed to primary stress levels exceeding the Division 1 requirements. If seen, such primary stresses can accelerate the process of HTHA.

Secondary Stresses

HTHA can be accelerated by secondary stresses, such as thermal stresses or those induced by cold work. The decrease in specific gravity over time indicates the rate at which internal fissures produced by HTHA. Annealed samples (0% strain) had an incubation period followed by a decrease in specific gravity. Steels with 5% strain had shorter incubation periods, and specific gravity decreased at a more rapid rate. Steels with 39% strain showed no incubation period at any test temperature, indicating that fissuring and cracking started immediately upon exposure to hydrogen. These tests are considered significant in explaining the cracks sometimes found in highly stressed areas of an otherwise apparently resistant material.

Heat Treatment

Post weld heat treatment (PWHT) of the 0.5Mo and chromium-molybdenum steels in hydrogen service improves resistance to HTHA. The PWHT stabilizes alloy carbides. This reduces the amount of carbon available to combine with hydrogen, thus improving HTHA resistance. Also, PWHT reduces residual stresses and is therefore beneficial for all steels. Both high PWHT temperatures and longer times are beneficial. The user must balance the advantages of high PWHT temperatures with other factors, such as the effect upon strength and notch toughness.

Inspection and detection of HTHA Material degradation caused by high temperature hydrogen damage occurs in three distinct stages. During the first stage hydrogen reacts with carbides located in the material leading to decarburization and the formation of methane bubbles located at the grain boundaries. With time the methane bubbles will lead to micro-cracks, stage two, which, affect the mechanical properties of the material, these micro-cracks can propagate, stage three and may lead to failure. Detection of HTHA is reliably performed by various NDTs mentioned below, during the stage two degradation. The purpose of the inspection technique is to reliably detect the presence of micro-cracking as well as accurately and effectively measure and report the depth of penetration such that this information can be used to determine fitness for service and remaining life. The exact technique

deployed as the primary detection technique is dependent on whether the parent material or welds are to be inspected:

Velocity Ratio

Ratio of shear and longitudinal wave velocity is measured. HTHA changes the ratio.It is recommended for base metal HTHA detection when advanced damage is suggested by the results of other methods or used as a complementary technique with a backscatter method.

Attenuation

Dispersion of ultrasonic shear wave is measured by recording drop in amplitude of multiple echoes. HTHA increases attenuation. It has been shown to detect HTHA fissures in base metal away from weldments.

Spectral Analysis

The first backwall signal is analyzed in terms of amplitude versus frequency. HTHA will attenuate high frequency response more than low frequencies. Very sensitive to internal fissuring due to HTHA. It can beused to differentiate between inclusions and HTHA damage.

Backscatter

Amplitude Based: High frequency ultrasonic waves backscattered from within the metal are measured. HTHA can increase backscatter signal amplitude.

Pattern Recognition: High frequency ultrasonic waves backscattered from within the metal are analyzed. HTHA causes a rise and fall in backscatter pattern.

Spatial Averaging: Backscatter data are collected over an area scanned. The signal is averaged to negate grain noise.

Directional Dependence: Compares backscatter signal as taken from ID and OD directions.

HTHA damaged material will show a shift in indicated damage towards the exposed surface (ID).

Frequency Dependence: Compares backscatter of two different frequency transducers.

HTHA damaged material will show a shift and spread of backscatter in time.

Conventional Shear Wave UT and TOFD

Routinely used for crack detection at weldments. Higher frequencies increase detection capability. TOFD is a developing technology. Not recommended for HTHA inspection to detect fissures. It can be used to detect developed cracks.

High Frequency Shear Wave

High frequency (10 MHz or higher) shear waves operated in pulse-echo mode for detection of HTHA in weldments/HAZ. Requires use of focused beam to inspect thick vessels.

Angle-beam Spectrum Analysis

The spectrum of any suspect signal from pulse-echo inspection of weld/HAZ is compared with a reference spectrum taken in the pitch-catch mode from the base metal. HTHA causes the pulse-echo spectrum to increase amplitude with increase of frequency.

Magnetic Particle

Conventional wet fluorescent AC yoke magnetic particle inspection used for detection of cracks at a surface. Blending the welds and sanding smooth increases sensitivity. Recommended for internal inspection of pressure vessels to use in addition to UT techniques, recognizing it is limited to advanced stages of HTHA with cracking. It will not find fissures.

Field Metallography and Replication

Polish and etch as in a creep evaluation looking for fissures, possibly voids, and changes in microstructure, i.e. decarburization. Replicas can be taken for laboratory analysis. It can differentiate between HTHA damage (fissures and decarburization) and other forms of cracking. Detailed Field Metallography may detect voids, but this performance level should be demonstrated before relied upon by the user.

Radiography

Conventional radiography used to inspect welds for cracks. Not recommended for general HTHA detection. May be useful for verification of shear wave UT indications.

Acoustic Emission

Monitors the sound that cracks emit when they are stressed. Capable of monitoring a large system including piping and pressure vessels. Potentially offers a technique for identifying areas needing follow-up inspection. May offer a method for full coverage of base metal.

Prevention of HTHA Typically HTHA can be avoided by choosing the proper steel to resist the combination of hydrogen partial pressure and temperature, or by adjusting the operating conditions to stay below the Nelson Curve limit for the existing materials of construction. However, there have been several cases where HTHA are found even through operating conditions were below the Nelson Curve. Other prevention methods that can be opted are avoiding usage of Carbon steel in high temperature conditions. Prefer usage of highly alloyed steel. Strictly follow the limits defined by the Nelson Curve while selecting material for the in HTHA prone regions and maintaining a safety margin of 30°C.

Overview of process units vulnerable towards HTHA

Fuel Oil Block (FOB)

Naphtha Hydro Desulphurization Unit (NHDT)

In NHDT feed mix i.e. Heavy SR Naptha and Heavy FCC gasoline is preheated in exchangers and then sent to furnace. So the flow from exchangers to furnace, till the effluent from hydrotreating reactors is prone to HTHA due to high temperature and presence of H2 and hydrocarbon. Hence if desired conditions are achieved H2 would dissociate and according to the metallurgy of the steel used HTHA might take place.

Catalytic Reforming Unit (CRU)

Here the use of recycle gas in Packinox exchanger allows contact of Hydrogen gas to high temperature region. Also exchanger, reactor and splitter region due to high temperature condition and presence of hydrocarbons with H2 increases the chances of HTHA.

Kerosene Hydro Desulphurization Unit (KHDS)

Raw kerosene/MTO/ATF/RTF feed from the storage is taken to the unit and mixed with recycle gas from compressor and preheated in the exchangers. Hence the exchanger outlets, reactor inlet & outlets where desulphurization takes place and stripper region can suffer from Hydrogen attack.

Liquid Oil Block (LOB)

Hydro Finishing Unit (HFU)

In HFU reaction section hydrodesulphurization, mild hydrodenitrogenation, hydrogenation of olefins, aromatics and decomposition of other heteromolecules such as oxygenated compounds using hydrogen in presence of catalyst takes place. This hydrogen rich section experiences high temperature in the reactor, exchangers and the compressor regions, hence prone to HTHA.

Wax Hydro Finishing Unit (WHFU)

Here also the hydrofinishing reactor region in the reaction section is vulnerable to high temperature hydrogen attack.

Catalytic IsoDewaxing Unit (CDWU)

Here the HDT processing step utilizes the hydrotreating reactor, which is operated at high Cold Hydrogen Partial Pressure (130 to 135 kg/cm2-H2) and elevated temperatures (310 - 380 °C) to remove essentially all of the sulfur and nitrogen from the feedstocks. Hence the following outlet, exchangers, reactors and columns can be hydrogen attacked.

Diesel Hydro Desulphurization Block (DHDS)

Diesel Hydro Desulphurization Unit

In the reaction section the sulphur and the nitrogen is converted to H2S and NH3 by using gaseous hydrogen. Hence the rector outlet, feed outlet and exchanger can experience HTHA due to abundance of hydrogen in these high temperature regions.

Naphtha Splitter, NHDT, Reformate Splitter (UNIT 85), Isomerization Unit (UNIT 86), Selective

Hydrogenation, FCC Gasoline Splitter & Prime-G (UNIT 87) [MSQU]

The hydrotreatment plants, selective hydrogen facilities, desulphurization unit and isomerization section experience a high temperature along with presence of gaseous hydrogen. If the metallurgy of the steel used is not good enough it would experience failure due to HTHA.

Once Through Hydro Cracking Block (OHCU)

Once Through Hydro Cracking Unit

In OHCU the hydrogenation and hydrocracking process makes hydrogen available throughout the system. As high temperature is attained at the exchangers, reactors and stripper outlets, these regions are prone to severe HTHA.

Hydrogen Generation Unit (HGU-II)

HGU is the most vulnerable unit towards HTHA in the refinery. Here also high temperature is attained in the region from pre-reformer inlet to reformer outlet, desulphurization section and hydrogen purification section along with presence of gaseous hydrogen. If conditions are met HTHA might take place. NOTE: Over the years tests had been carried in these units to check vulnerability towards HTHA. It has been found that metallurgy of the steel used in these sections are already resistant towards HTHA and chosen according to the Nelson Curve.

Conclusion HTHA is a damage mechanism with significant relevance in the Refinery Industry. The slow progress of the mechanism at first, combined with the rapid acceleration after the incubation period, makes it prone to catastrophic damage if not detected early. Hence it is advised to make sure that the HTHA material selection is done during the design phase itself. Inspection and NDT strategies can and must be focused on units and locations of high risk, and can be performed unobtrusively. The combination of a risk – based approach and advanced NDE will ensure the early detection and effective mitigation of damaged assets.

BIBLIOGRAPHY

1. Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants, API RECOMMENDED PRACTICE 941 SEVENTH EDITION, AUGUST 2008

2. Fitness-for-Service; American Petroleum Institute Recommended

Practice 579, First Edition January 2000

3. Practical Experience In The Early Detection And Assessment Of Vessels With HTHA Degradation, William R Sharp and Roelof Johannes Mostert

4. Inspection Manual, Inspection Department, Haldia Refinery January 2011

5. HTHA Study in Naphtha Cracker Complex- Essential key element of Pressure Equipment Integrity Management (PEIM) program

6. Compiled HTHA Study done in Haldia Refinery by Inspection Department