PROJECT REPORT FOR AWARDING OF CERTIFICATE ON

COMPLETION OF SUMMER INPLANT TRAINING

(9th JULY - 9th AUGUST 2012)

AT

IOCL Gujarat Refinery (Vadodara)

SUBMITTED BY:

Ashwani Kumar

B.Tech. (Chemical Engineering)

Seth Jaiprakash Mukandlal Institute of Engineering and

Technology, Haryana.

JMIT, Haryana.

PREFACE

Though it has been said that best friend a man can ever get is a book but we at this juncture realize that only books cannot give all the information a person seeks. When any student is unable to understand a particular topic, he is advised to imagine the whole matter and then try to understand it. Normally, this method succeeds. But in engineering stream considering the study of wide range of process and equipments involved in it, it is hard to understand the unit operations and processes just through books or even with imagination .Unless one happens to see the process, equipments, he is like a soldier who knows to fire the gun ,but is yet to face a war.

Industrial training is one of the most vital part of a syllabus of chemical engineering, which not only teaches one the industrial unit operations, equipments and other technical aspects, but also teaches discipline, interaction with various people irrespective of their posts, the importance of teamwork, etc.

This report contains a brief introduction to GUJRAT REFINERY and knowledge gathered about various units in refinery during the training.

JMIT, Haryana.

ACKNOWLEDGEMENT

I would like to express my gratitude to all those who gave me the possibility to complete this training. I want to thank the department of training and management of Gujarat refinery for giving me permission to commence this training. I have furthermore to thank the officers of production who giving me such knowledge of about the plant and production process. It’s really great opportunity for me by which I had learned here many more of refinery. I am deeply indebted to Gujarat Refinery who given such opportunity to students by which they complete their vocational training which is the parts of the course. Without any moral support and help I was not able to visit the plant and learn about the refinery. I would like to give my special thanks to the person who supported me through the training at the day of starting to the end of the training.

Our special thanks to

Mr.M.M PARMAR: CPNM (OM&S)

Mr. TAMBOLI SPNE (AU I)

Mr. V. M. RANALKAR( Chief Technical Services Manager)

Mr. SAURABH SETH : PNM (FCC)9

Mr.VENKARAMAN : SPNE(FCC)

Mr. AVALA SRINIVAS : SPNE(HGU III)

JMIT, Haryana.

CERTIFICATE

This is to certify that Mr. Deepesh Bhatia , student of University Institute of Chemical Engineering and Technology, Chandigarh has successfully completed his industrial training at “Indian Oil Corporation Limited(IOCL), Gujarat Refinery”from 15 June 2012 to 26 July 2012 under my supervision and guidance with utmost satisfaction.

It indeed gives us pleasure to highlight that Mr. Deepesh Bhatia has worked hard and deep sincerity throughout his vocational training. I appreciate his sincere effort and I am sure that gained during the training will enable him to take up more challenging tasks in the future.

Date: July 26, 2012 C. P. Ambedkar Sr. Officer (Tra. & Dev.)

JMIT, Haryana.

CONTENTS

Sr. NO TOPIC1 INTRODUCTION TO IOCL2 GUJARAT REFINERY3 UNITS AT GUJARAT REFINERY

4 MAIN UNITS

5 UNITS

6 GUJARAT REFINERY (GR II)

7 ATMOSPHERIC UNIT III

8 GUJARAT HYDROCRACKER UNIT(GHC)

9 HYDROGEN UNIT

10 HYDROCRACKER UNIT

11 GUJARAT REFINERY SECONDARY PROCESSING FACILITIES(GRSPF)

12 FEED PREPARATION UNIT(FPU)

13 FLUID CATALYTIC CRACKING

14 CRUDE DISTILLATION UNIT(CDU)

15 VACUUM DISTILLATION UNIT(VDU)

JMIT, Haryana.

16 CATALYTIC REFORMING UNIT(CRU)

17 SULPHUR RECOVERY UNIT(SRU)

18 LEARNING

19 BIBLIOGRAPHY

1.INTRODUCTION:INDIAN OIL CORPORATION LTD. (IOCL)

Indian Oil, the largest commercial enterprise of India (by sales turnover), is India’s sole representative in Fortune's prestigious listing of the world's 500 largest corporations, ranked 189 for the year 2004. It is also the 17th largest petroleum company in the world.

Indian Oil has a sales turnover of Rs. 1, 20,000 crore and profits of Rs. 8,000 crore. Indian Oil has been adjudged second in petroleum trading among the 15 national oil companies in the Asia-Pacific region.

As the premier National Oil Company, Indian Oil’s endeavour is to serve the national economy and the people of India and fulfil its vision of becoming "an integrated, diversified and transnational energy major."

Beginning in 1959 as Indian Oil Company Ltd, Indian Oil Corporation Ltd. was formed in 1964 with the merger of Indian Refineries Ltd. (Est. 1958).

As India's flagship national oil company, Indian Oil accounts for 56% petroleum products market share, 42% national refining capacity and 67% downstream pipeline throughput capacity.

IOCL touches every Indian’s heart by keeping the vital oil supply line operating relentlessly in every nook and corner of India.

JMIT, Haryana.

It has the backing of over 33% of the country’s refining capacity as on 1 st April 2002 and 6523 km of crude/product pipelines across the length and breadth of the country.

IOCL’s vast distribution network of over 20000 sales points ensures that essential petroleum products reach the customer “at the right place and at the right Time.”

Indian Oil controls 10 of India's 18 refineries - at Digboi, Guwahati, Barauni, Koyali, Haldia, Mathura, Panipat, Chennai, Narimanam and Bongaigaon

JMIT, Haryana.

2. INTRODUCTION: GUJARAT REFINERY

Gujarat Refinery a prestigious refinery of Indian Oil Corporation Limited began its operation in 1965. Since then, the refinery has grown to be the company’s largest and country’s second largest refinery.The refinery’s success is built upon business and community partnerships with the people of Vadodara, as well as production of quality products that are compatible with the community and the environment. At the heart of the Gujarat Refinery’s success, are its employees and their commitment to Indian Oil’s vision and mission.

PROCESSING CRUDE:

Gujarat Refinery is designed to processes indigenous as well as imported crude oil. On an average it processes approximately three lakh eight thousand metric tonnes crude per day. Out of the crude slot it receives, refinery processes around 45% imported crude.

Gujarat refinery’s manufacturing and storage facilities consist of 26 major process units, 28 product lines and crude storage tanks with capacity ranging from 300 to 65,000 KLs.

South Gujarat Crude: 2.3MMTPA; supply from ONGC South Gujarat pipeline.North Gujarat: 3.5MMTPA; supply from ONGC North Gujarat pipeline.Imported low / high Sulphur crude & Bombay high: 6.2 MMTPA Supply from Salaya - Viramgam - Koyali pipeline.

SALIENT FEATURE OF REFINERY:

First Riser Cracker FCCU in the country. First Hydro cracker in the country. First Diesel Hydro De-sulphurisation Unit. First Spent Caustic Treatment Plant in refineries. First Automated Rail Loading Gantry. First LPG Mounded Bullets in Indian Refineries. Operates Southeast Asia’s biggest Centralized Effluent Treatment Plant (CETP).

Process Control:

Using the latest electronic technology to monitor and control the plants, engineers run the process units around the clock, 7 days a week. From control rooms located in each operations area, technical personnel use a computer-driven process control system with console screens that display color interactive graphics of the plants and real-time (current) data on the status of the plants.The process control systems allow operators to “fine tune” the processes and respond immediately to process changes. With redundancy designed into the control system, safe operations are assured in the event of plant upset.

JMIT, Haryana.

Product Marketing:

A network of product pipelines, tank wagons and tank trucks carries finished products to regional distribution center.In turn, these centers supply products to consumers and industrial customers in Gujarat, Maharashtra, Madhya Pradesh and Rajasthan.In addition to this Gujarat Refinery caters to the needs of NCR and Karnataka.

OPERATIONS:

1. Distillation:

Modern distillation involves pumping oil through pipes in hot furnaces and separating light hydrocarbon molecules from heavy ones in downstream distillation towers.

The refining process begins when crude oil is distilled in two large, two-stage crude units. The units are two-stage because they have two distillation columns, one that operates at near

atmospheric pressure, and another that operates at less than atmospheric pressure, i.e., a vacuum. The lightest materials, liquid petroleum gas like propane and butane, vaporize and rise to the top of

the first atmospheric column. Medium weight materials, including jet and diesel fuels, condense in the middle. Heavy materials, called gas oils, condense in the lower portion of the atmospheric column. The heaviest tar-like material, called residuum is referred to as the “bottom of the barrel” because

it never really rises. This distillation process is repeated in many other plants as the oil is further refined to make

various products.

2. Conversion:

Refinery converts middle distillates, gas oil and residuum into MS, ATF and HSD, as well as other fuel oils, by using a series of processing plants.

Most of the oil is treated with hydrogen to remove contaminants before the conversion process. Heat and catalysts are then used to convert the heavy oils to lighter products.

Since the marketplace establishes product value, refinery’s competitive edge depends on how efficiently it can convert middle distillate, gas oil and residuum into the highest value products.

Cracking is one of the conversion methods, because it literally “cracks” large, heavy hydrocarbon molecules into smaller, lighter ones.

Gujarat Refinery uses two cracking methods: fluid catalytic cracking and hydro cracking. The Fluid Catalytic Cracker (FCC) uses high temperature and catalyst to crack heavy gas oil mostly

into gasoline. Hydro cracking uses catalysts to react gas oil and hydrogen under high pressure and high

temperature to make both ATF and MS.

JMIT, Haryana.

3. Treatment (Removing Impurities):

The products from the crude distillation units and the feeds to conversion units contain some natural impurities, such as sulfur and nitrogen.

The sulfur is converted to hydrogen sulfide and sent to the sulfur recovery unit where it is converted into elemental sulfur and nitrogen is transformed into ammonia in nitrogen unit and then burnt through flare.

JMIT, Haryana.

3.UNITS AT GUJARAT REFINERY:

1) GR1Atmospheric Distillation Units, AU1 & AU2: 4.2 MMTPAAU5: 3.0 MMTPACatalytic Reforming Unit, CRU: 0.33 MMTPA

2) GR2AU3: 2.7MMTPAUDEX: 0.166 MMTPAFood Grade Hexane, FGH: 0.03 MMTPA Methyl Tertiary Butyl Ether, MTBE: 47 MMTPABUTENE 1: 2MMTPA

3) GREAU4: 3.8MMTPAVacuum Distillation Unit, VDU: 1.2MMTPABitumen Blowing Unit, BBU: 0.5MMTPAVisbreaker Unit, VBU: 1.6MMTPA

4) GRSPFFeed Preparation Unit, FPU-1: 2.0MMTPAFluidized Catalytic Cracking Unit, FCC: 1.5MMTPA

5) GHCFPU-2: 2.97MMTPA Hydrogen Generation Unit, HG: 38,000 MTPY Hydro Cracking Unit, HCU 1.2MMTPA HYDROGEN-2: 10,000 MTPYDiesel Hydro De-Sulfurization Unit, DHDS: 1.4 MMTPASulphur Recovery Unit, SRU: 88 MMTPD

6) POWER GENERATION & EFFLUENT TREATMENT

Cogeneration Plant, CGP: 30*3 MW

JMIT, Haryana.

Thermal Power Station, TPS: 12*2 + 12.5 MWCombined Effluent Treatment Plant, CETP: 1500 M3/H

4.MAIN UNITS:

Atmospheric Distillation Unit

Gujarat Refinery has five primary distillation units –AU-1, AU-2, AU-3, AU-4 and AU-5 with a combined crude processing capacity of 13.7 MMTPA and flexibility of processing indigenous or imported crude.

The various product streams obtained on crude distillation are:

1. Methane, Ethane and Propane mixture as refinery fuel gas.2. Liquefied mixture of propane and butane marketed as3. Liquefied Petroleum Gas (LPG).4. Gasoline fraction.5. Aviation Turbine Fuel (ATF).6. Superior Kerosene (SK).7. High Speed Diesel (HSD).8. Reduced Crude Oil (RCO).

Catalytic Reforming Unit (CRU)

Gasoline fractions produced from distillation units containing naphthalene and paraffin type of hydrocarbons are chemically transformed into aromatic type of hydrocarbons having higher octane number.

This unit produces feedstock for UDEX Unit for production of benzene and toluene and feedstock for Xylene.

Diesel Hydro-de-sulphurisation unit

JMIT, Haryana.

The DHDS process is an environment friendly technology. Gujarat refinery commissioned DHDS unit in June 1999. This unit reduces Sulphur content in HSD to the level of 0.05%.

The unit produces normal and ultra low Sulphur diesel qualities. Ultra low Sulphur diesel is mainly marketed amongst metro cities.

Hydrocracker Unit

To upgrade the heavy residue to valuable middle distillates Gujarat Refinery has set up a hydro cracker plant with all associated units like Feed Preparation Unit, Hydro cracker unit, hydrogen unit, nitrogen plant, power plant, Sulphur recovery unit and waste water treatment plant.

The hydro cracker unit is designed to process 1.2 million metric tonnes of vacuum gas oil per annum produced from feed preparation unit. The unit converts the vacuum gas oil into products like diesel, kerosene, and naphtha, LPG etc. by cracking process in presence of hydrogen. The products generated are of superior quality.

The unique feature of the hydro cracker unit is its capability to totally convert the feed into diesel and lighter products i.e. no residue comes out of the unit.

LAB (Linear Alkyl Benzene)

LAB is an important and vital raw material, which solely determines the cleaning action of detergent. Our LAB now goes into manufacture of most of the popular detergent brands.

The quality of LAB produced, is the best in the country on various parameters, making it a preferred grade among the customers.

LAB has also been exported to various countries and has evoked excellent response from overseas buyers.

MSQU (Motor Spirit Quality Upgradation)

Auto fuel policy guidelines stated to supply BS II and EURO III great fuel in Ahmadabad and Surat cities by 1st April 2005 and EURO IV great fuel by 1st April 2010.

To meet the specifications the MOTOR SPIRIT UPGRADATION unit was set up and commissioned in October 2006, to produce 850 TMTPA of MS at Gujarat refinery.

In this unit for the first time Gujarat refinery adopted continuous catalytic reforming regeneration technology( CCR regeneration) technology.

JMIT, Haryana.

Unit has number of processes viz. FCC gasoline splitter, naphtha hydro treater, merox, reformate splitter and CCRU.

JMIT, Haryana.

GUJARAT REFINERY:SEQUENCE OF PROCESSES

JMIT, Haryana.

5.UNITS:5.1 GUJARAT REFINERY (GR-II)

This unit has 4 sub-units under it namely: Atmospheric Unit-III (AU-III) UDEX FHG MTBE

5.1.1 ATMOSPHERIC UNIT-III

INTRODUCTION OF THE UNIT

Atmospheric Distillation Unit-III was originally designed by Russians to process 1.0 MMTPA of 50:50 mixes of Ankleshwar and North Gujarat Crudes. It was commissioned on 28.09.1967. The Unit has been revamped to process North Gujarat as well as imported (Low Sulphur) / Bombay High Crudes.

FUNCTION OF PLANT

After the last revamp in May-June, 2000, the plant can process 3.0 MMTPA North Gujarat and Imported (Low Sulphur) / Bombay High crude in a recommended proportion of 55%NG and 45% Imported (Low Sulphur) / Bombay High. The unit can also process 100% NG crude. At times of requirement, the unit can also process slop at a slow rate together with the in-going crude. LPG, Naphtha, SKO, HSD(SRGO) and RCO/LSHS are normal products obtained from this unit. On demand from UDEX, Hot Oil is produced here.

PROCESS FLOW DESCRIPTION

DETAILED DESCRIPTION OF THE PROCESS

For convenience of understanding, the unit is divided in various circuits viz. crude supply, feed preheating, crude pre-topping, furnace, main fractionating column, overhead system, Hy-Naphtha, Kerosene, SRGO, RCO, Stabilizer, Naphtha Stripper, Utilities etc.

JMIT, Haryana.

CRUDE STORAGE AND SETTLING

AU-III processes NG crude imported / BH crude and Slop. These are stored in respective tanks earmarked for them.Adequate settling time, 12 hours or more after completion of receipt is required for each tank to settle down water/sludge. The water is thoroughly drained before feeding to the unit. The sludge from tank is drained to melting pit.A crude tank prepared as above, is first fed at slow rate by crack opening of outlet valve (bleeding), along with the already feeding tank. After minimum of 4 hours bleeding, this may be made a complete feed tank. This procedure is adopted to avoid unit upsets due to possible sudden influx of water or abrupt feeding of different quality crude from the fresh tank. Feeding from the crude tank to the unit crude feed pump may be either by gravity, as in the case of low feed requirement, or via crude booster pump as in the case of higher throughput requirement.

SLOP PREPARATION AND SUPPLY

Slop is injected in the crude line Ex GRE crude. There is an indication given in AU-III CR to control the slop rate to crude depending on the unit condition. A flow rate indication is also given in the GRE control room. Slop is taken to unit initially at a slow rate, which can be slowly increased up to 500 TPD, max.

CRUDE BOOSTER PUMP

5 Crude pumps are provided at GRE Crude Control for supplying crude to AU-III. Part of this supply goes to other GR Units also. Out of these 3 pumps are in NG crude service and 1 pump each in SG & BH crude service.

FEED PREHEAT CIRCUIT

Crude is supplied to the unit by GRE Crude Controls. Through the crude booster pumps as mentioned in the above tables provided at GRE Crude Controls, crude enters AU-III. Downstream of the crude battery limit valve de-emulsifier is injected. On crude line to pump suction start up (circulation) line hook up is provided. Crude through the crude feed line reaches the crude feed pump H2, H2A, H2B and H2C. Out of 4 pumps, 3 pumps are running while operating at maximum throughput (9000 + MT/Day) level. Usually two (2) crude pump suffice is the need. With the help of crude feed pumps, crude is pumped to a number of heat exchangers to recover heat from run-down products. Crude is charged to two parallel preheat series branched by 3TV3125A and 3TV3125B. These two series of

JMIT, Haryana.

exchangers constitute pre-desalter section of preheat circuit; preheat train-1, which impart a large quantity of heat to crude. The crude preheat circuit is divided into three sections viz. pre-desalter (Preheat Train-I), post-desalter (Preheat Train-II) & post-pretopping column (Preheat Train-III).

CRUDE PRETOPPING

The crude after getting preheated enters the pre-topping column K-I (I.D = 2400 mm; Ht = 23750 mm, TL to TL) above tray No. 8 at around 259 C. This column is meant for removal of the lighter ends⁰ from the crude and has 8 sieve trays below flash zone and 21 valve trays above 8th tray.The column operates at top pressure of 2.2 - 2.9 kg/cm² (g) and a top temperature in the range of 110 C to 129 C. Light naphtha boiling up to about 110 C to 129 C is recovered as overhead product⁰ ⁰ ⁰ ⁰

from this column. This light naphtha also contains the lighter hydrocarbons like off-gas and LPG. The column top pressure is controlled by 3PC3201 located on E-1 vessel, which actually controls E-1 pressure. The c/v 3PV3201 is set to maintain a pressure fixed in the range of 2.2 – 2.9 kg/cm² (g) by liberating off- gas either to fuel gas system or to flare system. Safety valve set at 3.15 Kg/cm² (g) pressure is provided on vessel. This PSV releases pressure to flare.Below the flash zone where 8 trays are provided, crude is steam – stripped to vaporize kerosene and other light components. Stripping steam is introduced below tray no.1 through a flow controller. A pressure controller is provided at upstream to regulate the stripping pressure. The overhead vapours are condensed and cooled in the condensers T-7A and T-7B working in parallel and the product is received in the reflux drum E-1. A reflux temperature indicator is provided on the outlet of T-7A/B. 2 no’s of 100% capacity safety valve discharging to flare are provided on overhead vapour line to condensers. These PSVs are set at 3.7 kg/cm²(g). A provision of steam for flushing and fuel gas back up is provided on E-1.

MAIN FRACTIONATING COLUMN:

OVERHEAD SYSTEMPre-topped crude after getting heated to 355-366 C in F-1/F-2/F-3 enters the flash zone of the main⁰ fractionating column K-2 (I.D. = 3400 mm; Ht = 30350 mm, TL to TL) through a 22” nozzle above the 6th tray. This column has 41 trays, out of which the bottom 1 to 6 trays are sieve trays and 7 to 41 are valve trays. 5 no’s of 100% safety valves set at 1.5 kg/cm²(g) are provided at the top of K-2.

These PSVs release excess pressure to atmosphere. One vent line is also provided on the column top. The column K-2 is operated at 0.6 to 1.0 kg/cm²(g) pressure. Column K-2 pressure is controlled with

JMIT, Haryana.

the help of split range controller. This pressure controller admits gas into E-2 through gas make-up (from E4 vessel) line or releases gas from E-2 to flare depending on whether the column K-2 pressure is lower or higher than desired. A safety valve set at 1.2 kg/cm²(g) pressure is provided at E-2. This PSV releases excess pressure into atmosphere.Naphtha boiling up to about 110 C to 125 C is the overhead product from column K-2 and is⁰ ⁰ commonly known as E-2 gasoline. This naphtha is devoid of the light hydrocarbons like gas and LPG. The overhead vapour from the column K-2 enters overhead condensers T-8A, T-8B, T-8C and T-8D working in parallel and the condensed liquid is received in the reflux accumulator E-2. A reflux temperature indicator is provided on this line. A stream connection is provided on vessel E-2 for steam flushing. Ammoniated water and Ahuralan are injected in two O/H vapour lines of K-2 to maintain E-2 boot-water pH and to avoid corrosion in condensers and reflux drum.One of the pumps H8/H9 takes suction from the bottom of E-2 and partly dischargers through controller as reflux to column K-2 to maintain the column top temperature between 115 C to 120 C.⁰ ⁰ The balance is discharged through other controller which is cascaded with E-2 level controller maintaining the H/C level in E-2, and is sent to naphtha rundown as Naphtha-2.There is a provision for:Routing off grade E-2 gasoline into intermediate tank-214 of AU-III.a) Normal routing to general / GOP naphtha.b) Direct routing of E-2 naphtha to AU-I for reprocessing.Water accumulation in E-2 is drained through inter-phase level controller 3LC3505 to E-12 or OWS.

DEMULSIFIERA demulsifying agent is injected into the crude oil at the crude pumps common suction header in the unit. It is injected at the rate of 13-15 ppm on crude input and of 2-20 ppm on crude while processing slop depending upon demulsifier quality.Demulsifier helps in faster demulsification inside the desalter, whereby helping in faster removal of water injected for dissolving salt.

CAUSTIC INJECTIONCalcium and magnesium chloride present in crude hydrolyze on heating and release HCL that attacks the overhead system. Some of these calcium and magnesium chloride are removed in the desalters. To neutralize the chlorides escaping from desalters, caustic solution is added into the crude. In presence of caustic they get converted into harmless NaCl. The caustic dosing is done at a rate of 30 to 40 ppm on NG crude and is injected in desalter crude outlets common line via vortex mixer.Caustic is received from OM&S in the form of caustic dye of approximately 48% strength in tank-C. Caustic is diluted by adding water to make 6-10% solution. Caustic from tank-C is transformed into

JMIT, Haryana.

one of the dilute caustics tanks A and B and a solution of 6.0% strength is prepared by diluting with service water. Dosing of dilute caustic in crude is done with one of the two pumps H-25 and H-26.

AMMONIA SOLUTION INJECTIONAmmonia is injected into overhead vapour lines of K-1 and K-2 to:1. Neutralize residual hydrochloric acid by converting it into NH4Cl.2. Maintain pH of E-1/E-2 water in the range of 6 to 6.5, because effectiveness of corrosion inhibitor is more in this range of Ph.Ammonia is received in the unit in 40 kg cylinders. Ammonical water solution is prepared by bubbling gaseous ammonia from cylinder through fresh water in ammonia tank. There are two ammonia tanks.

GUJARAT HYDRO-CRACKER UNIT (GHC)

HYDROGEN UNIT

INTRODUCTION: Gujarat Hydrogen plant with a capacity of 38000 tonnes per annumand producing 99.99% pure hydrogen has come up as a part of Gujarat HydrocrackerProject. Hydrogen is generated in this unit by steam reforming of naphtha employing M/sLINDE’S technology. Hydrogen generated in the plant is consumed in Hydrocracker unitfor various chemical reactions. These reactions need very high purity hydrogen tomaintain requisite partial pressure of hydrogen in the Hydrocracker reactor. The fallpurity results in the lowering of the hydrogen partial pressure, which adversely affects thequality of products from Hydro cracker unit.

FEED: Naphtha

PRODUCT: Hydrogen (99.99% pure)

PROCESS: The process for hydrogen generation involves the following four steps.g) Sulphur Removalh) Steam Reformingi) High Temperature Shift Conversion.j) Pressure Swing Adsorption (PSA) purification.Different types of catalysts are used in each of the above four sections. As the processinvolves high temperature condition in steam reforming and high temperature shiftconversion, waste heat is utilized for generation of large quantity of steam. The steamgenerated in the unit satisfies the requirement in the unit and surplus steam is offered toother units for consumption. The unit is unique in the country due to following:k) 10 bed Pressure Swing Adsorption (PSA) system for the purification of

JMIT, Haryana.

Hydrogen product.l) Special design of steam reformer involving use of low pressure and low calorificvalue PSA purge gas as the major fuel.m) The microprocessor based process control of the PSA system.

SULPHUR REMOVAL: The nickel-based catalyst used in steam reforming ofhydrocarbons is sensitive to poisoning by sulphur compounds. Typically the sulphurconcentration in the feedstock must be reduced to less than 0.2 ppm before it isacceptable. This is usually achieved by converting the sulphur compounds, e.g. thiophenemercaptanes, to hydrogen sulfide, which is then removed by an absorbent.

The hydrogenation reaction for conversion to hydrogen sulfide is achieved in a reactor,bed of cobalt-molybdenum catalyst or nickel-molybdenum catalyst.R SH + H2 → RH + H2S‘R’ is radical; it may be CH3, C2H5

Hydrogen sulfide reacts with zinc oxide to produce zinc sulfide and water according to

JMIT, Haryana.

following reaction.

ZnO + H2S → ZnS + H2O

The rate of reaction is a function of temperature pressure and diffusion processes. Eachmolecule of hydrogen sulfide must diffuse to the zinc oxide before reacting to producethe sulfide ion and water. The water must diffuse away from reaction zone, while sulfideion diffuses into the interior of the granule to replace the oxide ion. This processcontinues until the whole structure is converted into zinc sulfide.

STEAM REFORMING/SHIFT CONVERSION: The objective of the catalytic steamreforming process is to extract the maximum quantity of hydrogen held in water and thehydrocarbon feedstock. The treatment or purification of reformed gases from steamreformer depends on the purpose for which the reformed gas is to be used.The common uses are:n) Synthesis gas o) Hydrogen and carbon monoxide for oxo-alcoholsp) Hydrogen for refineries hydrogenation reactions andq) Reduced gas for direct reduction of iron ore.The reforming of Natural Gas utilizes two simple reversible reactions:r) The reforming reaction CH4 + H2O → CO + 3H2

s) The water-gas shift reaction. CO + H2O → CO2 + H2

The reforming reaction is strongly endothermic, so the forward reaction is favored byhigh temperature as well as by low pressure while the shift reaction is exothermic and isfavored by low temperature but is largely unaffected by changes in pressure.

To maximize the overall efficiency of the conversion of carbon to carbon-di-oxide andthe production of hydrogen, reformers are operated at high temperature and pressure. Thisis followed by the shift process, which by using catalyst permits the shift reaction to bebrought to equilibrium at as low a temperature possible.

In our case, reforming of naphtha/steam mixture takes place in the heated high-alloyreformer tubes, which are filled with a nickel-based catalyst. The steam reformingreaction along with side reactions is as under:

CnHm + CO + CO +

nH2O 3H2 H2O

nCO + CH4 + CO2 +

(No Details+ m/2) H2---------(i)H2O-----------------------------(ii)H2 ------------------------------(iii)

The reaction equilibrium is controlled by partial pressure of H2, CO, CO2, CH4 and H2O.Reaction (i) is highly endothermic. Reaction (ii) and (iii) are reversible reaction and areinfluenced by hydrogen and steam. Most of the carbon monoxide of the reformed gas is

JMIT, Haryana.

reacted with excess steam to produce addition hydrogen and carbon dioxide. This isachieved in high temperature CO shift converter. The catalyst available is in the form offerric oxide Fe2O3 (haematite); it is to be reduced to ferrosoferri Fe3O4 (Magnetite) inpresence of hydrogen as reducing agent.

JMIT, Haryana.

HYDROCRACKER UNIT

INTRODUCTION: Residue up gradation into middle distillates and light distillates iscurrently being done in the Indian Refineries primarily by employing FCC process,delayed coking process & visbreaking. Visbreaking is adopted primarily to reduce theviscosity of the residue thereby making it marketable. Delayed coking is adopted if cokeis also to be a product. The quality of products obtained from FCC, delayed Coker &Visbreaker are relatively poor in quality with respect to stability, & sulphur and have tobe blended with other straight run products to be able to market them. Otherwise, producttreatment would be necessary (Hydro-treatment, Merox treatment etc.). In view of theseproblems Hydro cracking process is gaining more and more popularity for upgradingresidues into higher value products

Hydrocracking is an extremely versatile catalytic process in which feedstock rangingfrom Naphtha to Vacuum Residue can be processed in presence of Hydrogen and catalystto produce almost any desired products lighter than the feed. Thus if the feed is Naphtha,it can be converted into LPG and if feed is Vacuum Gas Oil as in our Refinery, it canproduce LPG, Naphtha, ATF, Diesel in varying proportions as per design requirement.Primary function of Hydrocracker unit is to maximize middle distillate production inGujarat Refinery.

The Hydrocracker is made-up of three major sections: the make-up hydrogencompression section, the reactor section (two stage) and the distillation section.Reactor Section: The feedstock is combined with hydrogen at high temperatures &pressures and is catalytically converted to lighter transportation fuels. The reactor sectionis composed of the first stage reactor and the second stage reactor.Make-up Hydrogen Compression Section: It provides hydrogen to each reactor section;the reaction products are separated and cooled.Distillation Section: It consists of the atmospheric fractionation, light ends recovery,LPG treating and a vacuum column.

Hydrocracker Unit operates under two different catalyst conditions viz. Start of Run(SOR) & End of Run (EOR). When the catalyst is new or freshly regenerated, it is SORcondition. The catalyst gets deactivated due to coke deposition (about 12-18 months) andrequires regeneration to operate under design stipulations. The operating condition justbefore regeneration is called EOR operation.

FEED: Feed consists of VGO from FPU

PRODUCTS: The primary products from HCU are:t) L.P.Gu) Stabilized Light Naphtha

JMIT, Haryana.

v) Heavy Naphthaw) Aviation Turbine Fuel (ATF)/ Superior Kerosene (SK)x) High Speed Diesel (HSD)

JMIT, Haryana.

PROCESS DESCRIPTION:

In Hydrocracker, the VGO feed is subjected to cracking in 2 stage reactors over catalyst

beds in presence of Hydrogen at pressure of 170 kg/cm2 & temperature raging from 365to 441 deg. C. The cracked products are separated in fractionator. Light ends arerecovered/stabilized in debutanizer column. The process removes almost all sulfur andnitrogen from feed by converting them into H2S & Ammonia respectively. Thus theproducts obtained are free of sulfur & nitrogen compounds & saturated. Therefore, exceptfor mild caustic wash for LPG, post treatment is not required for other products.

The unit consists of the following sections:(i) First stage Reactor section.(ii) Second stage Reactor section(iii) Fractionation Section(iv) Light Ends Recovery section

1) FIRST STAGE REACTOR SECTION: Vacuum Gas oil feed is supplied from “FPU”and heated in exchangers and brought to the pressure of 185 Kg/sq.cm by feed boosterpumps. It is mixed with recycle hydrogen and pure hydrogen from make-up compressorsand further heated in reactor effluent exchanger followed by furnace up to 385 Deg. Cbefore it enters the First Stage Reactor. The first stage reactor contains three catalyst bedswith two intermediate quench zones which use recycle gas as quenching medium. Thereactor effluent is cooled in exchangers, steam generators and finally in an air fin coolerup to 65 deg. C. It is flashed in the High Pressure Separator (HPS) from which HydrogenRich gas is recycled back to the reactor. The liquid product from the separator flowsthrough a Power Recovery Turbine (PRT) to the Cold Low Pressure Separator (CLPS).The first stage reactor converts approximately 40% of the feed to middle distillates andlighter products.

2) SECOND STAGE REACTOR SECTION: Converted feed from the first stage

reactoris removed in the fractionator section and unconverted material from the first stage formsthe feed to the second stage. Feed from vacuum column bottom is boosted up to 185

kg/cm2 and mixed with recycle gas and pure hydrogen from make up compressors and isheated in the reactor effluent exchanger followed by 2nd stage reactor furnace up to 345Deg. C before it is sent to the reactor. This reactor also contains three catalyst beds withtwo intermediate quench zones, which use recycle gas as quenching medium. The reactoreffluent is cooled in the exchangers and steam generators up to 204 deg. C and is fed toHot High Pressure Separator (HHPS). Liquid from HHPS flows through a powerrecovery turbine, which drives the feed pump, and goes to Hot low pressure separator(HLPS) before going to fractionation section. The hydrogen rich gases are cooled in

JMIT, Haryana.

exchangers followed by air cooler up to 65 deg. C before entering into Cold HighPressure Separator (CHPS).

3) FRACTIONATION SECTION: Liquid from “HLPS” is heated in the exchangers and

JMIT, Haryana.

finally in a furnace up to 345 Deg. C before it is sent to fractionator column. Theoverhead products are off-gases and light naphtha. Off gases are washed with Amine toremove H2S and are sent to the Fuel Gas System. Heavy Naphtha is withdrawn at 146Deg. C as first draw off. The second draw off is ATF at 188 Deg. C. The third draw off is‘HSD’ at 286 Deg. C. The bottom of the fractionator is pumped to Vacuum Column. Thebottom temperature of the column is maintained at 377 deg. C using a reboiler furnace.HSD is withdrawn as a side cut of vacuum column and blended with diesel fromfractionator after cooling in exchanger and cooler. The bottom of the vacuum column isfeed for second stage reactor.

4) LIGHT ENDS RECOVERY SECTION: Light Naphtha from the fractionator is sent tode-ethanizer, where gases are removed and sent to Amine Absorber where the H2S isabsorbed in the Amine and H2S free fuel gas is sent to Fuel Gas system. Rich amine withdissolved H2S is sent to Amine Regeneration Unit in Sulfur Recovery Unit Block. Thebottom of de-ethanizer is sent to de-butanizer, for the recovery of LPG. LPG is taken outfrom the top and sent to treating section where it is washed with caustic for removal ofH2S. The stabilized Naphtha from the bottom of the stabilizer is sent to Hydrogen Unitfor production of Hydrogen.

CHEMICAL DOSING:

1) DIMETHYL DISULFIDE (DMDS) INJECTION SYSTEM: Sulfiding is requiredto stabilize fresh or regenerated catalyst, which in turn promotes a smooth start-up, betteractivity and lower fouling rate. For sulfiding of catalyst Dimethyl Disulfide (DMDS) isinjected in recycle gas, going to reactor.2) ANTISTATIC ADDITIVE DOSING SYSTEM:Antistatic additive (Stadis-450)is dosed in ATF, which gives it the property to dissipate the build up static electricityduring its transportation in pipes. The dosing rate is adjusted to meet the specifications ofelectrical conductivity of 50 - 450 Ps/m. The dosing is done in the ATF rundown linedown stream of the cooler.

HYDROCARBON REACTION CHEMISTRY:

Hydrocarbons are classified into four major groups according to the types of carbon-tocarbon bonds they contain:1) Aromatics- They contain one or more benzene nuclear unsaturated, six member ringsin which some electrons are shared “equally” by all the carbon atoms in the ring. If someof the rings share two or more carbon atoms, the compounds are referred to a condensedring, or polycyclic, or polynuclear aromatics. As a group, aromatics have higher carbon-to-carbon ratios than any other group. They have relatively low API gravities and tend to

JMIT, Haryana.

produce smoke when burned so they make poor jet fuel. Aromatics have good antiknockproperties and make excellent high-octane gasoline.2) Naphthenes- They are ring compounds without any benzene nuclei. The rings aretypically five or six membered saturated rings. Naphthenes have intermediate APIgravities and burning qualities.3) Paraffins- They are straight chain or branched-chain. Straight paraffins are called normal paraffins and have very high freeze points so they make poor jet fuel. Branched-chain paraffins are called iso-paraffins. They make excellent high smoke, low freeze jetfuel. As a group, paraffins have the highest API gravities.4) Olefins- They are reactive molecules, which contain one or more double bonds in anotherwise paraffinic structure. Olefins do not occur naturally in crude oil because anyolefins would have long since reacted to form other molecules during the age longunderground aging process in which crude oil is formed. Olefin can be formed as reactionintermediates during hydrocracking, but the high hydrogenation activity of the catalystprevents any olefins from showing up in reactor products. Hydrocracker feeds also havelesser amounts of molecules, which contain chemically bound sulfur or nitrogen atoms inaromatic or naphthanic structures. The following molecules are typical of the kindspresent in hydrocracker feeds and products: y) Paraffinsz) Naphthenesaa) Aromaticsbb) Sulfur Compoundscc) Nitrogen Compounds

CATALYST CHEMISTRY:

Hydrocracking catalysts are dual functional, which means that they have both acidcracking sites and metal hydrogenation sites. The hydrogenation sites provide olefinintermediates and saturated olefin products. They saturate some of the aromatic rings andprevent the accumulation of coke on the acid sites by hydrogenating coke precursors. Theacid sites provide the carbonium ion intermediates and the isomerization activity thatresult in the dominance of isoparaffin products. More acidic catalysts produce a lighteryield distribution of higher iso-to-normal ratio products. Higher hydrogenation activitycatalysts produce more saturated products with a heavier yield distribution.

CATALYST SULFIDING:

Sulfiding is done to regenerate strong acid sites on catalyst, which were neutralized bynickel salts during catalyst manufacture. An unsulfided catalyst has much lower crackingactivity and produces products of low iso-to-normal ratio. Sulfiding itself proceeds as twoseparate reactions.The cracking of DMDS:

CH3-S-S-CH3 + 3H2 2CH4 + 2H2S

JMIT, Haryana.

Followed by the sulfiding proper:

2H2S + 3 NiO + H2 Ni3S2 + 3 H2O.

JMIT, Haryana.

CATALYST REGENERATION:

Catalyst Regeneration consists primarily of burning off accumulated coke on the catalystduring the oxidation phase:

4C1H1 + SO2 4CO2 + 2H2O

As an unwanted side reaction, some of sulfur (from sulfiding) is also oxidized:

Ni3S2 + 4O2 NiSO4 + 2NiO + SO2,

to yield nickel sulfate, nickel oxide, and sulfur dioxide. In the reduction phase, the nickelsulfate is eliminated to prevent temperature runaway during subsequent sulfiding:

3NiSO3 + 10H2 Ni3S2 + SO2 + 10 H2O

Since some of the sulfur is retained as nickel sulfide, the subsequent sulfiding uses lessDMDS than used for sulfiding of fresh catalyst. As a side reaction during reduction, metaloxides are converted to metals:

NiO + H2 Ni + H2O

JMIT, Haryana.

GUJARAT REFINERY SECONDARYPROCESSING FACILITIES (GRSPF)

FEED PREPARATION UNIT (FPU)

INTRODUCTION: Feed Preparation Unit (FPU), a part of Gujarat RefinerySecondary Processing Facilities (GRSPF) was originally designed with a throughput of1.66 MMTPA of RCO. The primary function of this unit was to produce 700,000 T/yearof vacuum gas oil for feed to FCCU along with vacuum diesel and vacuum residue. Lateron, it was decided to revamp the Feed Preparation Unit (FPU) to meet the increased VGOfeed requirement in Fluidized Catalytic Cracking Unit (FCCU), which was alsorevamped, to 1.5 MMTPA.

FEED: mixed RCO (MAX)

PRODUCTS: 1. Heavy Diesel 2. Vacuum Gas Oil

PROCESS: The process is same as that for vacuum distillation unit of GRE.Four side draw products are obtained from the column:1) Heavy diesel is obtained as the topside draw product.2) Light vacuum Gas Oil (LVGO) is obtained as the second side draw product. TheLVGO pump around is used to generate LP steam after which it is returned to the column.3) Heavy vacuum gas oil (HVGO) is obtained as the third side draw product. A pumparound reflux is also drawn off at this point. The HVGO product exchanges its heat withRCO after which it is used to generate LP steam. 4) Slop Distillate is drawn as the fourth side draw product. The recycle stream is alsodrawn off at this point and is mixed with RCO at the entry to the Vacuum furnace. TheSlop Distillate mixes with Vacuum Residue down stream of MP steam generator orcooled in slop distillate cooler and sent to GRE FO Pool.

JMIT, Haryana.

FLUIDIZED CATALYTIC CRACKING (FCC)

INTRODUCTION: During 80's with increased processing of the North Gujarat andBombay High Crude’s, the production of LSHS had gone up. This increased productionof LSHS should have been suitably disposed off to enable the refinery to operate at itsmaximum throughput for meeting requirements of the petroleum products. This LSHS,which is presently being supplied as fuel for burning, has a good potential of beingrefined into high priced distillates, which are in great deficit in our country. The steepincrease in the prices of crude oil and petroleum products in the past few years andgovernment’s policy of conservation of petroleum energy has changed the situationtotally and it became necessary to review the utilization of LSHS more economically andprofitably.

Based on the above consideration, the various alternatives of Secondary ProcessingSchemes were examined and it was decided to install Fluid Catalytic Cracking Unit(FCC) at Gujarat Refinery. In 1982 Gujarat Refinery FCC Unit was commissioned with acapacity of 1 MMTPA.

HISTORY OF FLUIDIZED CATALYTIC CRACKER:Cracking is aphenomenon in which large oil molecules are decomposed into small lower boilingmolecules. At the time certain of these molecules, which are reactive, combine with oneanother to give even larger molecules than those present in the original stock. The morestable molecules leave the system as cracked gasoline and reactive ones polymerizeforming fuel oil and even coke. Although primary objective in development of thecracking process had been to get more and more of gasoline, all other oils having boilingranges intermediate between fuel oil and gasoline is also produced. The originallydeveloped process of cracking was “Thermal Cracking”. Use of catalyst for cracking wasfirst investigated by HOUDRY in 1927. Catalytic cracking has many advantages overThermal cracking viz.1) Catalytic cracking gives more stable products2) For corresponding yield and quality of gasoline, catalytic cracking unit operates underless severe conditions3) Catalytic cracking gives high-octane gasoline (viz.91-94 octane).4) It yields less gas viz. Methane, Ethane and Ethylene.

1) BATCH PROCESS: The first commercial Catalytic Cracking Unit was put intooperation in 1936. It was a Fixed-bed Catalytic Cracking Unit. It consisted of a series ofchamber / reactors, wherein one of them is on-stream, the others will be in the process ofcleaning, regeneration etc. This type of process has a disadvantage of being anintermittent process having a high initial investment and operating cost.

JMIT, Haryana.

2) CONTINUOUS PROCESS: The advantages of continuous process led to thedevelopment of the idea of a moving bed catalyst. Examples of this type are “ThermoforCracking”; “Thermofor Catalytic Cracking” and “Houndry Airlift” processes. In the

Thermofor Catalytic cracking, the palletized catalyst was conveyed between the reactor and regenerator

by means of Bucket Elevators. Higher investment by capacity limitationsof Elevators/Air lift systems together with other engineering and process difficulties ledto the development of latest concept in moving bed catalytic cracking i.e. FluidizedCatalytic Cracking.

FLUIDIZED CATALYTIC CRACKING: The radical development was made byStandard Oil Co., New Jersey, M.W.Kellogg and UOP in early 1940’s in which thecatalyst in the form of fine powder was held in suspension in gas stream. It was foundthat by carefully controlling the catalyst particle size and the velocity of gas movingthrough it, a fluidized bed of catalyst would form which has the properties of liquid. Inthe fluidized system, finely powdered catalyst is lifted into the reactor by incoming oil,which immediately vaporizes upon contact with the hot catalyst and after reaction iscomplete, it is lifted into the regeneration zone. Catalytic crackers using powderedcatalyst in this way are known as FLUIDIZED CATALYTIC CRACKING UNITS.

FEED: VGO and VR from FPU. The feed is characterized by following:1) CARBON RESIDUE: Carbon residue of the feedstock is determined by CCR and itindicates the coke-forming tendency of feed. Values for good cracking feedstock are0.2% wt or less.2) METAL CONTENT: Most crude oils contain metallic compounds which can enter thecatalytic cracker either by entrainment or because the compounds are themselves volatileand actually distilled in the feed preparation units. Ni, Fe, Cu are particularly harmful.Cleanliness of a charge stock with respect to metals is judged by its metal factor, whichis defined as: FM = Fe +V +10(Ni+Cu) where, Fe ,V , Ni and Cu are the concentrations of these metals in ppm in the feedstock.FM below 1.0 represents acceptable feedstock.3) SULPHUR: It is undesirable in catalytic cracker charge as it is in the feed to anyrefining unit since it causes corrosion of the equipment. Also it increases difficulty oftreating products and lower lead response of catalytic cracker gasoline.

CATALYTIC CRACKING REACTIONS:

C2H4 C6H6 Gas oil feed Iso-octane branched paraffin (30 - 50 C atoms) Cetane Coke(60 % aromatics)

JMIT, Haryana.

Catalytic cracking reactions produce unsaturated short chains like ethylene, excellenthigh-octane components like benzene and iso-octane and lower molecular weight gas oilslike cetane. During cracking, apart from basic reaction of breaking of big molecules tosmall ones, other reactions like isomerization, cyclization, alkylation, polymerization etcalso take place.

CRACKING CATALYST: The catalyst used in catalytic cracking process is a finepowder made up primarily of Alumina and Silica. Basically there are two types of catalyst-amorphous and zeolite. Zeolite catalyst contains molecular sieves and varying quantities of rare earths. These are formed through reaction of reactive forms of Alumina and Silica.

PRODUCTS: The FCC unit catalytically cracks the vacuum gas oil (VGO) fromvacuum distillation unit (VDU) and feed preparation unit (FPU) to various high pricedhydrocarbons. These hydrocarbon vapors are separated into the following products in thefractionating and gas concentration section-a) Fuel Gasb) LPGc) Gasoline of high octane numberd) HSD componentse) LDO componentsf) Fuel oil components

PROCESS: FCC consists of three sections:1) Catalyst section2) Fractionating section3) Gas concentration section

Catalytic section consists of the Reactor and the Regenerator. Feed to the Reactor isobtained by the vacuum distillation of atmospheric residues in FPU. Hot feed from FPUand balanced cold feed from the storage tank is collected in a Raw Oil charge drum. Theraw oil from the surge drum passes through a series of heat exchangers where it getsheated against hot products i.e. heavy naphtha, LCO, HCO, CLO and slurry. Thetemperature of the feed is raised to around 300- 315 deg C. The combined feed enters thereactor riser at the bottom. The hot regenerated catalyst at 600 deg C from regeneratorvaporizes the feed, raises it to reaction temperature and supplies the necessary heat ofcracking.

REACTOR: The reactor riser is a vertical pipe in which all the cracking reactions takeplace. Hot catalyst enters the cold wall “wye” section at the bottom of the riser, and meetsthe raw oil and riser steam. The flow of catalyst is controlled to maintain the desiredreaction temperature. The raw oil and the riser steam are premixed in a feed distributor toform an emulsion. The raw oil /riser steam emulsion vaporizes upon contacting the hotregenerated catalyst, accelerating the catalyst and hydrocarbon vapors up the riser.

JMIT, Haryana.

Cracking reactions are carried essentially to completion in the riser with a minimum ofover cracking and coke formation. Catalyst and oil contact time using this system isapproximately 3 seconds. Catalyst and hydrocarbon vapors exit the riser into the reactorthrough the down turned disengaging arm. The disengaging arm provides the quickmethod of separating the catalyst and hydrocarbon vapors. Catalyst falling from thedisengaging arm combines with the catalyst recovered from the reactor cyclones to enterthe reactor stripping section.

Reactor is a cylindrical vessel with a conical bottom. It provides disengaging space forthe separation of catalyst from the oil vapor. Catalyst after disengaging from oil vaporsfalls down and enters the stripper. Oil vapor along with the catalyst particle travels up andenters two single stage cyclones provided at the top of reactor. Entrained catalyst is

separated in Cyclones and returned to reactor bed through cyclone dip legs. Flappervalves are provided at the end of dip legs to avoid entry of vapors through dip legs.Vapors from top of both the cyclones leave the reactor separately and join vapor line,which carries vapors to the fractionator.

Catalyst disengaging from the down turned arm disengager and reactor cyclones dip legspasses into the catalyst stripper, which surrounds the upper portion of the riser, where itflows over stripping grids, counter current to riser steam .The stripping steam displacesthe oil vapor from the catalyst particle and returns the vapor to the reactor for separationin the cyclones.

REGENERATOR:Coke is deposited on the circulating catalyst in the reaction zone.Spent catalyst flows from the reactor to the regenerator through the spent catalyst slidevalve (SCSV). The pressure difference across SCSV is around 0.4 kg/cm2. In theregenerator coke is burnt off with controlled combustion air. Air from air blower is sentto a direct fired air heater where it is heated to around 230 deg. C by fuel gas combustion.This air burns off the coke to CO2 and CO. The heat of combustion raises the catalysttemperature to 640 - 660 deg. C range. This hot catalyst supplies heat to the reactor. Thecatalyst is recirculated to the reactor through a regenerated catalyst slide valve (RCSV).The pressure drop across RCSV is 0.3 kg/cm2. The regenerator also houses 3 sets of 2stage cyclones, which separates any entrained catalyst particle from the overhead flue gas.

ORIFICE CHAMBER: The purpose of orifice chamber is to reduce the pressure dropacross the flue gas slide valve. The high-pressure drop across the slide valve would causeexcessive noise and erosion problems. Orifice chamber helps to reduce these problemsand brings down the flue gas pressure from 3.4 to 0.3 kg/cm2, which is just sufficient forCO boiler. The gases CO and CO2 come out of 3 sets of stage cyclones in regenerator andleaves from the top. The gases pass through the orifice chamber where a series ofrestriction orifices reduces the gas pressure. A two-port slide valve (TPSV) installed atthe bottom of the orifice chamber diverts the flue gas either to CO boiler or to stack.

JMIT, Haryana.

CO BOILER: The CO boiler is just like any other conventional water tube boilerconsisting of two drums and one superheater disposed at the flue gas path. It is a frontwall fired, medium pressure (MP) & temperature, natural circulation boiler.

The upper drum, which is called steam drum but essentially contains steam and waterboth, is fed with hot feed water (130-140ºC) supplied through a feed control valve. Thecolder water form the upper drum flows to lower water drum through a bunch of tubescalled “Down Comers” which are disposed at the lower temperature zone of the furnace.The water contained in the furnace wall tubes or riser tubes is heated by the heat releasedin the furnace on combustion of fuel. The heated water in the riser tubes becomes lighterand moves up into the upper drum. These riser tubes are disposed in such a fashion that itmakes a closed envelope of the furnace covering all the six sides of the furnace so as topick-up maximum possible heat. In this way the water circulates from the upper drum tothe lower drum through the down comers and from the lower drum to the upper drumthrough the water wall or riser tubes. This circulation in a boiler is called of natural circulation, which is based upon the principal of ‘Thermosyphon’.

JMIT, Haryana.

The furnace where the combustion of fuel takes place is an integral part of the boiler. Theboiler tubes are used to make the enclosure for the furnace followed by insulation andouter sheeting. The space between the tubes is closed with the help of metallic strips,which are welded to the tubes. Hence entire furnace is of welded construction.

FURTHER PROCESSING OF PRODUCTS: The main products from FCC unitare gasoline and LPG. After these products are separated through fractionation andstabilization section, they are given some chemical treatment like caustic wash and waterwash to remove the impurities still present. Following chemicals are used in FCC/GCU:

1. Caustic Soda

2 Tri-Sodium Phosphate

3 Hydrazine

4 Ahuralan

1) CAUSTIC SODA: Caustic soda is used for LPG and gasoline caustic wash. It removesH2S and lighter mercaptans from these streams. Caustic with approximately 40-45 %strength is received from LPG station through a 2” line into tank. This caustic is dilutedto (10-15 %) by adding water to tank.

2) TRI SODIUM PHOSPHATE (TSP): Tri-Sodium phosphate is added to MP steamgenerators. It helps in reducing scale formation in the steam generators by forming sludgewith the scale forming salts. This sludge goes out of the system during blow downoperations. Solid TSP is received in gunny bags. Required quantity of TSP is added tochemical mixing tanks and solution is prepared by adding DM water and mixing with thehelp of motor driven mixer provided on the tank. The normal strength of the solution is5%.

3) HYDRAZINE (N2H4): While major portion of dissolved oxygen is removed fromboiler feed water in deaerator, residual oxygen in boiler feed water is scavenged with thehelp of hydrazine. N2H4 + O2 2H2O + N2

23 % solution of hydrazine is received in drums/jerry cans of 50 kg. Hydrazine solutionof 5 % strength is prepared in chemical mixing tank by adding DM water. The tank isprovided with a motor driven mixer.

4) AHURALAN: It is an organic chemical, which acts as a corrosion inhibitor by forminga continuously renewable monomolecular layer on the metal surface with corrosiveelements, present in the system.

JMIT, Haryana.

VACUUM DISTILLATION UNIT (VDU)

INTRODUCTION: The Vacuum Distillation Unit (VDU) was designed to process

8,00,000 TPA of RCO (370°C + 50:50 North Rumaila & Arab Light). After low cost1999 revamp VDU can process 1.2 MMTPA of RCO, Heavy Diesel as top product isused as HSD, LVGO+HVGO used as VGO for FCCU feedstock. Presently there is aprovision for withdrawal of three side cuts.

FEED: The Vacuum Distillation Unit (VDU) was originally designed to processReduced Crude Oil (RCO) obtained ex CDU (Crude Distillation Unit) while processingimported crude (50: 50 mixture of North Rumaila and Light Arabian Crude Oils).However, RCO obtained from various imported crudes and indigenous crudes (BombayHigh, North Gujarat, and South Gujarat Mix.) has been processed successfully.

PRODUCTS: By distilling the RCO under vacuum in a single stage column, itproduces Light vacuum Gas Oil (LVG0), Heavy Vacuum Gas Oil (HVGO) and VacuumResiduum (VR). Slop cut (distillate between HVGO and VR) production facility has beenprovided since 1988.LVGO - used as blending component for LDO or HSD or as feed component for FCCUalong with HVGO.HVGO - used as a feed component for FCCU.VACUUM RESIDUUM (VR) - (Imported) is used as feed for Bitumen Unit.Excess VR and HVG Oil can be used as feed components to the Visbreaker Unit.Surplus BH VR (while processing Bombay High RCO in VDU) is used as blendingcomponent for LSHS.

PROCESS FLOW DESCRIPTION:

Reduced crude oil, RCO is received in feed surge drum from storage tanks. Hot RCO canbe received from CDU. RCO is pumped by charge pumps to a series of preheatexchangers and then to furnace from where feed goes to column. At the end of preheatingby preheat exchanger train feed gets heated up to 305°C in case of hot feed and up to

292°C in case of cold feed.

Preheated RCO is split into two passes and introduced to Vacuum Heater/Furnaceunder pass flow control for each pass. MP steam is injected in each pass to encouragevaporization of feed in the coils. Coil outlet temperature of 395 -398°C is maintained.The partially vaporized RCO is introduced in flash zone of column. LP steamsuperheated up to 350°C in the heater is used as stripping steam in the stripping section ofthe vacuum column. Vaporized RCO along with steam rises through the vacuum column

JMIT, Haryana.

and is fractionated into two side withdrawals.

VR along with quench stream is withdrawn from the column bottom by pumps. After

JMIT, Haryana.

preheating feed, a quench stream is routed back to the column to maintain bottom

temperature of 355°C to avoid coking in the column boot. Further VR goes to LP steamgenerator and gets cooled up to 150 0C. VR routing is as follows: (1) Hot VR to BBU, (2)Hot VR to VBU, (3) Hot VR to VR burning facility, (4) Hot VR to IFO drum, (5) DirectVR injection in BBU after cooling, & (6) After cooling in tempered water cooler VR isrouted to storage at 150°C.

The desired vacuum is created in the vacuum column by the vacuum system consisting ofmultistage ejectors, precondenser, intermediate condenser, after condenser and hot well.The hot well is located at grade level and correspondingly ejectors are elevated to providebarometric legs. Small amount of oil carried over with steam from the column isremoved from the seal pot by pump and is routed to slop or to HSD. Sour water from theseal pot is pumped out by pumps to sour water system.

JMIT, Haryana.

CATALYTIC REFORMING UNIT (CRU)

INTRODUCTION: Catalyst Reforming Unit of Gujarat Refinery was designed &commissioned with Russian collaboration in October 1966. The designed capacity of theunit was 3,00,000 MTPA. Unit was revamped for production of Benzene, Toluene &Xylene in March 1990. The reformer catalyst was changed from monometallic to CK-433(Bimetallic) catalyst of Ms. Ketjen. The new catalyst is very sensitive to the impuritieslike Sulfur, Nitrogen, Water, and Heavy Metals etc. Therefore, a new pretreater unit hasbeen set up to remove above. Hydro desulfurization catalyst KF-742 of Ketjen ofNetherlands is used in pretreater. After completion of 9 years life CK-433 was changed toE-603 in Aug-1999.Naphtha of two cut ranges i.e. 70-900C and 110-1400C cut is processed separately inblocked out operation to produce reformate specific for Benzene/ Toluene and Xylenerecovery, respectively.BT Operation: 1,80,000 MTPA of 70-900C cut is processed for 4364 Hrs for producingBT rich reformate which is subsequently processed in the UDEX Plant to produceBenzene and Toluene.Xylene Operation: 1,50,000 MTPA of 110-1400C cut is processed for producing xylenerich reformate which can be used to produced xylene.

FEED: Naphtha cut (70-90 deg C) for BT operation (paraffins-32%, naphthenes-45%,aromatics-22%) and naphtha cut (110-140 deg C) for Xylene operation (parffins-37%,naphthenes-38%, aromatics-24%)IMPURITIES: Pretreater Unit is designed for following levels of impurities in naphthafeed:By Wt.Nitrogen Chloride Heavy metals SulfurWater

PRODUCTS:

1.5 ppm 3.5 ppm 30 ppb 200 ppm 150ppm

PRETREATER: Naphtha obtained from pretreater has following impurity levels (for both70-900C cut and 110-1400C cut Naphtha operations):

ImpuritiesNitrogen Halides Arsenic and heavymetals Sulfur Water

By wt.0.5 ppm 0.5 ppm 5.0 ppb 1.0 ppm 5.0 ppm

REFORMER: Stabilized reformate, Hydrogen rich gas, Stabilizer off gas, Stabilizervapor distillate

CHEMICAL ADDITION:

JMIT, Haryana.

1) SULFIDING AGENT: Dimethyl disulfide (DMDS) added to both pretreater andreformer catalyst

2) CHLORIDING AGENT: Carbon Tetrachloride

JMIT, Haryana.

3) CORROSION INHIBITOR: CONTROL 57 or equivalent 4) ALKALINE MEDIUM: Sodium Carbonate. At the time of catalyst regeneration,alkaline water is circulated downstream of feed effluent exchangers to avoid acid attackin product coolers, product separators and associated piping.

CATALYST SPECIFICATION:

PRETREATER: CATALYST- KF-742-1,3 Q having MoO3, CoO, Na2O, Fe, SO4,

balance is Al2O3. Surface area is around 260 m2/gREFORMER: Bimetallic CATALYST E-603(ENGEL HARD) having Platinum,Rhenium, heavy metals, Iron, Na, K, Cl and support is alumina.1) Platinum metal acts as dehydrogenating agent.2) Rhenium decreases the rate of coke formation by hydrogenation of coke precursors onthe catalyst surface. Rhenium also helps in preventing the Platinum crystal growth bybreaking the intermolecular forces of two adjoining platinum crystals. Platinum is theactive metal in the reforming reactions whereas Rhenium is a deactivation inhibitor.3) The chloride content of catalyst helps in promoting the isomerization andhydrocracking reactions and serves as an acid function of the catalyst.Advantages of bimetallic catalysts are:1) Gives maximum aromatic yield.2) Cycle length and life is more.3) Low pressure operation & minimum recycle gas flow4) Have good mechanical strength.5) Less platinum content and hence less investment.Catalyst Poison- anything which reduces the activity of the catalyst is a poison e.g. coke,sulfur, water, nitrogen, arsenic, lead, copper etc.

PRETREATMENT:

INTRODUCTION: Structurally hydrotreating catalyst may be defined as a porous Al2O3

support, which carries molybdenum oxide as a bound monolayer. Cobalt or Nickelpromoter ions are deposited on to the surface of molybdenum alumina structure.

To obtain maximum activity of hydrotreating, metal oxides have to be converted intosulphides and to be maintained in sulphide phase during presulfiding procedure eitherwith the feed itself or with the external sulfiding agent. At high temperatures, the metaloxides are partially reduced by hydrogen, which result in loss of activity. Reduction of themetal oxides to metals or lower valence oxides becomes significant at catalysttemperature above 3000C. Once reduction has occurred, it is practically impossible toconvert the metals to their sulphides. If not enough sulphur has been added to the catalyst,before the catalyst temperature is set at operating level, the same irreversible reductionmay occur. Because of possible reduction, the fresh or the regenerated catalyst should notbe contacted with hydrogen at temperature above 2000C, without other reactive sulphur

JMIT, Haryana.

compounds.

HYDROTREATING REACTIONS: Predominantly, there are two types of reactions,which occur during pretreatment:

JMIT, Haryana.

1) Hydro Desulfurization: The sulfided catalyst reacts with organic sulphur to giveinorganic sulphur (H2S) and hydrocarbon at high temperature and pressure.

S + 4H2 → H2S + C4H10

C2H5SH + H2 → C2H6 + H2S

The reaction rate for each compound decreases with its molecular weight. In general, thesulphur present in aromatic type structure is more difficult to remove than in straightchain molecules.2) Hydro Denitrogenation: Hydro denitrogenation occurs simultaneously with hydrodesulfurization. Nitrogen containing compounds are converted to saturated hydrocarbonsand ammonia.3) Hydrogenation of Aromatics and olefins: Although it is not desired in most cases somehydro-generation of aromatics and olefins will occur in hydro-treating process.

REFORMING:

INTRODUCTION: Reforming process is carried out at relatively high temperature andpressure by passing the Naphtha feed stock over a bed of catalyst. Typical operatingconditions of Reformer are: Reactor inlet T= 5010C - 5160C; Pressure=16.90 kg/cm2g. Inthe reforming process, structures of hydrocarbon molecules are rearranged to form moreof higher-octane aromatics. Predominantly, there are five different types of reactions,which occur during reforming.1) Aromatization of Naphthenes & Paraffins:Dehydrogenation of Naphthenes-

Cyclohexane → Benzene + 3H2

The dehydrogenation reactions are highly endothermic and cause a decrease intemperature as the reaction proceeds. They have the highest reaction rates and they occurmostly in the first two reactors.Dehydrocyclization of Paraffins-

C6H14 → Cyclohexane + H2 → Benzene + 3H2

n-Hexane This reaction is also endothermic and has low reaction rate 2) Isomerization of Naphthenes & Paraffins:Isomerization of Naphthenes- Methyl Cyclo pentane → Cyclo hexane

Isomerization of Paraffins- H-H-H-H-H-H-H H-H-H-H-H-H

JMIT, Haryana.

H-C-C-C-C-C-C-C-H → H-C-C-C-C-C-C-H

H-H-H-H-H-H-H H-H-H-H-CH3 -H

JMIT, Haryana.

n-Heptane Iso-heptane3) Hydrocracking:

C8H18 + H2 → C3H8 + C5H10

n-Octane Propane Pentene

These reactions are highly exothermic. They are relatively slow reactions and there foremost of the hydrocracking of straight chain paraffins result in octane improvement buthydrocracking of Naphthenes will reduce the Naphthenes potential used for conversion inAromatics.4) Hydrogenation of Olefins: Olefins formed during cracking or present in feed areinstantaneously saturated with Hydrogen.

C5H10 + H2→ C5H12

Pentene n-pentane

5) Desulfurization:

Thiophine + 5H2 → H2S + C4H10

Butane

In reforming, endothermic reactions dominate and the net result is considerable drop intemperature of the reaction mixture, as it passes through the catalyst bed. An increase intemperature increases the rate of all reactions. The reduction in temperature will reducethe reaction rates such that the conversion would cease, if no additional heat will besupplied to the reactants. Some of the reforming reactions are slow reactions, whichrequire more residence time. Therefore the catalyst is placed in a number of reactors. Thereaction mixture picks up heat from the furnace before entering each reactor formaximum conversion.

In a reversible reaction, for a given value of temperature and pressure, not more than acertain conversion can be reached, even if, the reactants are kept under the reactionconditions for infinite time. To shift the reaction in forward direction either temperatureis to be increased or H2 partial pressure is to be decreased to have maximum conversion.As decrease in pressure may lead to coke formation on the catalyst, hence instead ofreducing the system pressure, reactor inlet temp is increased.

JMIT, Haryana.

SULPHUR RECOVERY UNIT (SRU)

AMINE REGENERATION UNIT (ARU)

INTRODUCTION: Rich amine saturated with hydrogen sulfide received from DHDS,is treated in ARU, which consists of a conventional stripping column equipped withassociated reboiler and overhead condenser facilities. Hydrogen sulfide and other lightcomponents are removed as overhead products and lean amine as bottom product fromthe amine stripper. The overhead gases are sent to SRU while the bottom product leanamine is sent back to DHDS. The unit consists of 4 sections:i) Rich amine sectionii) Amine regeneration sectioniii)Lean amine sectioniv)Amine storage section

FEED: Feed to ARU is rich amine (H2S 76 Kmol/hr).

PRODUCT: Product leaving ARU is lean amine (H2S 4 Kmol/hr) from the bottom of

the amine stripper and H2S rich gas from the overhead.

PROCESS:

1) RICH AMINE SECTION: The rich amine section collects rich amine from the amineabsorbers. Rich amine from the recycle gas scrubber and stripper gas amine absorber iscombined and send directly to the rich amine flash drum (RAFD). The RAFD separatesany entrained liquid or gaseous hydrocarbons from the rich amine. Hydrocarbon vaporseparated in the RAFD, which also contain some hydrogen sulfide and water vapor, isscrubbed with a small lean amine slipstream in nth stack portion of the RAFD. Thestacked portion of RAFD consists of randomly packed carbon Raschig rings to provideintimate contact between off gases and lean amine. The sweetened off gas flows througha backpressure control valve to acid gas relief header.

2) AMINE REGENERATION SECTION: Rich amine from the bottom of the RAFDis pumped by rich amine pumps and flow through the tube side of the rich-lean amineexchanger. In this exchanger the rich amine is heated by the lean amine from the bottomof the amine stripper, which is cooled thereby recovering the heat of the lean amine. Theheated rich amine flows through a level control valve into the amine stripper. The aminestripper strips nearly all of the hydrogen sulfide from the rich amine, thus regenerating itto lean amine.

JMIT, Haryana.

Stripping gas is generated in the amine stripper reboiler by vaporizing a portion of thelean amine in the column bottom. A small amount of live stripping steam is also injectedin the reboiler return line to stripper to maintain water balance in the entire amine system.

JMIT, Haryana.

The stripping gas flows up through the column thereby stripping hydrogen sulfide fromthe rich amine flowing counter current. The amine stripper reboiler uses desuperheatedMP steam as the heating medium. Reboiler heating rate is controlled by controlling thesteam flow. The absolute maximum temperature of the desuperheated steam is 149C inorder to prevent amine degradation.

Off gas from the top of the amine stripper, containing hydrogen sulfide, some lighthydrocarbons and water vapors flows to the air-cooled amine stripper trim cooler. As thevapor is cooled some water vapor is condensed. The two-phase stream then flows to theamine stripper receiver. The liquid from the receiver is pumped by the amine stripperreflux pump as reflux back to the top tray of amine stripper. The acid gas from the top ofthe receiver flows to SRU.

3) LEAN AMINE SECTION: A slipstream of lean amine flows to the filtration system,which filters lean amine through a series of 3 filters. The filtration system contains aseries of 3 filters: upstream mechanical filter, carbon filter and downstream mechanicalfilter. The lean amine from the amine regeneration unit is discharged to diesel unionfining unit.

4) AMINE STORAGE SECTION: High (99wt % DEA) solid amine is supplied to theamine regeneration unit in drums. The solid amine is melted in the amine melt tank usingsteam, to form amine solution. Amine is diluted to 25-wt % DEA solution used in therefinery at the amine storage tank. The 25% amine solution is periodically pumped byamine transfer pump to regeneration section to replenish the amine loss.

SULPHUR RECOVERY SECTION

FEED: The feedstock of SRU is a mixture of acid gas from ARU (H2S 2817 kg/hr) and

acid gas from Sour Water Stripper (H2S 358 Kg/hr).

PRODUCT: Liquid sulphur (99 wt% purity on dry basis)

PROCESS:

The amine acid gas feed from the ARU is introduced via a knock out drum. The SWS gasfeed from the sour water stripper unit is introduced via another knock out drum. Sourwater separates in the knock out drum, is intermittently collected in the sour water drainvessel and routed back to the sour water stripper unit by nitrogen propulsion. The acid gasfeed is split evenly over the two Claus trains.

The air to main burner is supplied by main air blower, which also supplies air to theSuperclaus stage and the sulphur degassing. To remove the heat generated in the main

JMIT, Haryana.

burner the gas passes through the tube bundle located in waste heat boiler. The gas iscooled there by generating HP steam. Then the process gas is introduced in the first

JMIT, Haryana.

sulphur condenser in which it is cooled, the sulphur vapor is condensed and the liquidsulphur is separated from the gas.

Upstream of the first reactor, the process stream from the waste heat boiler is heated bythe first steam reheater to obtain the optimum temperature for catalytic conversion. TheH2S and SO 2 react over a titanium oxide type catalyst until equilibrium is reached. Theeffluent gas from the first reactor passes on to the second sulphur condenser. The processgas passes to the second steam reheater after which it is once again subjected toconversion in the second reactor and cooling in the third sulphur condenser. The inlettemperature of the second reactor is 210 deg. C. Then the process gas passes to the thirdsteam reheater and the third reactor. The sulphur is condensed in the fourth sulphurcondenser .The inlet temperature of the third reactor is 195 deg. C.

To obtain a high sulphur recovery the process gas from the combined Claus trains ispassed to the fourth and the last catalytic stage i.e. SUPERCLAUS stage. The processgas is heated in the fourth steam reheater after which preheated air is injected in theprocess gas. Hydrogen sulfide is selectively oxidized into sulphur. The SUPERCLAUSreactor contains the special selective oxidation catalyst .The gas then passes to the fifthand the last condenser. The inlet temperature of the SUPERCLAUS reactor is 220 deg. C.In the condenser the sulphur vapor is condensed. The sulphur is cooled in sulphur coolerand subsequently drained into sulphur pit, which is equipped with degassing facilities.The heat liberated in the waste heat boiler and condenser is utilized to generate steam.

SULPHUR DEGASSING PROCESS: The sulphur as it is produced in the train containsabout 350 ppm (wt) hydrogen sulfide. To reduce the hydrogen sulfide content, sulphurstripping has been incorporated. Two bubble columns are located in sulphur pit. Abubble column is a box open at the top and bottom. Each bubble column is divided intotwo sections by a separation baffle. This baffle prevents channeling of undegassedsulphur. Degassed sulphur flows through a rectangular hole in the separation baffles. Thestripping air is supplied by main air blower. In the column sulphur is vigorously agitatedby bubbling of air through liquid sulphur there by accelerating decomposition ofpolysulfides into hydrogen sulfide and sulphur, stripping hydrogen sulfide from sulphurand oxidizing hydrogen sulfide partly to sulphur. The released gas, together with the air,is drawn by steam ejector to the thermal incinerator.

THERMAL INCINERATOR: In thermal incinerator, the combustible components in thevent gas from sulphur pit are thermally oxidized at a temperature of 730 C with anexcess of air. The gas to be incinerated is heated to the required temperature by mixing itin the thermal incinerator, with hot flue gases from the incinerator burner. The flue gasfrom the incinerator is sent out through chimney at much higher altitude to take for theenvironment pollution. Thus it is a suitable way for the disposal of undesired pollutinggases and side-by-side a large amount of steam is also produced by recovering the heat

JMIT, Haryana.

content of gases that are burnt in the incinerator.

JMIT, Haryana.

JMIT, Haryana.

REACTORS:

Function of Claus reactors: i) Claus reaction at catalytic region

JMIT, Haryana.

2 H2S + SO2

→

3/x SX + 2 H2O + 93 KJ (X = 6 and 8 mainly)ii)Hydrolysis of COS and CSZ at temperatures above 300°CCOS + H2OCS2 + 2 H2SRequirements:

→ →

CO2 + H2S

CO2 + 2 H2S

i) Active catalyst for Claus reactionii) Catalyst able to withstand sulfation due to free O2iii)Catalyst withstanding residual NH3

iv)Low pressure dropv) Catalyst withstanding emergency conditions, such as temperature runaway.

Claus Process Limitations:i) Thermodynamically limited conversion: 2 H2S + SO2à 3 S + H2Oii) Increases H2O content to 30 vol% decreasing H2S and SO2 concentrationsiii)Formation of non-recoverable S-compounds due to side reactions

Function of Superclaus reactor:SUPERCLAUS reaction at catalytic regionH2S + 0.5 O2

Requirements:-----> 1/8 S8 + H20 + 208 kJ

i) Active catalyst for SUPERCLAUS reactionii) Catalyst withstanding sulfidation on lack of oxygeniii)Low pressure dropiv)Catalyst withstanding emergency conditions, such as temperature run away

JMIT, Haryana.

INDUSTRIALLY DEFINED PROBLEM

Problem Statement: - High chloride content monitored in the Surge Drum.

Problem Description: - In AU-3 (Atmospheric Unit III) of GR-II, it has been found that the

content of chlorides in boot water of surge vessel E2 is very high i.e. 110ppm, but the designed acceptable limit is less than 10ppm, whereas the pH of boot water is in acceptable limits of 6.5±0.2.

Process Description:-

Initially the Crude from the storage tank is sent to the Preheat Train 1, where it is heated upto 1400 C. Then it is diverted to two simultaneously (parallel) run desalters (old and new). From the desalters, the crude is sent to preheat train 2 where the temperature is raised to 2300 C. This preheated crude is sent to a Flash Column (K-1). The bottom product products are sent to Furnace where the temperature is raised to 3600 C and then to main Fractionating column (K-2) for further treatment. The overhead product from K-2 after cooling is sent to the surge vessel (E-2), where excess of chloride is detected.

BRIEF PROCESS FLOW AND EQUIPMENT DESCRIPTION

CRUDE SUPPLY:-

These are the specifications of the Crude used in AU-III

Sr. No.

Specifications UNIT N/G B/HIMP

(Kuwait)

1 Density @ 15°C. gm/cc 0.8927 0.8278 0.8723

2 Viscosity @ 20°C 30 °C 37.8°C 40°C 50°C

CSt -

-68.042.5

-

3.753.282.24

19.513.8

---

3 Pour Point ° C + 24 + 30 +364 Sulphur % wt. 0.16 0.17 2.495 CCR (Conradson) % Wt. 5.43 1.20 6.20

JMIT, Haryana.

6 Acidicity (i) Total MgKOH/gm

3.88 0.15 0.13

(ii)Inorganic ,, 0.002 -

7 KUOP - 11.95 11.70 -

CRUDE STORAGE AND SETTLING

AU-III processes NG crude imported crude/ BH crude of 28o API and Slop. These are stored in

respective tanks earmarked for them.

NG CRUDE TANKS OF GRE CRUDE CONTROL

TANKNO

SERVICE

CAPACITY

(kL)

REFERENCE

HEIGHT(cm)

SAFE FILLIN

GHEIGH

T(cm)

CRITICALZONE(cm)

FACTORKL/CM

781 NG 20,000 1769.0 1250 220 to 250 14.1

782 NG 20,000 1700.5 1230 150 to 186 14.1

783 NG 20,000 1694.0 1230 150 to 186 14.1

911 NG 20,000 1667.5 1360 180 to 218.5 14.1

Adequate settling time, 12 hours or more after completion of receipt is required for each tank to

settle down water/sludge. The water is thoroughly drained before feeding to the unit. The sludge from

the tank is drained to melting pit.

Feeding from the crude tank to the unit crude feed pump may be either by gravity, as in the case of low

feed requirement, or via crude booster pump as in the case of higher throughput requirement.

PREHEAT TRAIN-I

It consists of two series of heat exchangers. While passing through these exchangers, crude takes

heat from Kero-I, RCO, Kero-II and SRGO. In this circuit, desalting temperature is achieved in E-305.

Crude from both circuits mixes and proceeds towards Desalter-I (old) and Desalter-II (new), which

operate in parallel. Crude oil is heated from 35°C to 148°C in the pre-desalter section i.e., Preheat

Train-I.

JMIT, Haryana.

DESALTER

Crude enters for removal of salt and water at bottom section of both desalters through inlet distributors.

Crude is initially mixed with adequate amount of DM Water (3%) with the help of mixing valve.

Recommended pressure drop across mixing valve is 0.7 to 1 kg/cm2. Adequate settling time is allowed

to break the oil-water emulsion and salt-water to settle down in desalter. The crude desalting operation

is carried out at 145° C and 12.0 kg/cm2 (g). The pressure in the desalters is controlled by pressure

controllers. DM water (and stripped sour water) is injected to crude at desalter inlets through flow

controllers.The DMW exchange heat with brine and is heated to 120- 140° C. The desalted crude is

withdrawn with the help of outlet crude collector mounted on the top most part inside the desalter. The

separated effluent water with dissolved salt is drawn from each desalter, and after combining it

exchanges heat with DM water. Effluent water is then drained through a flash drum, E-19. Interface

level is maintained around 25%. The exact interface level for efficient desalting will depend upon the

salt content and appearance of effluent water. To physically check the interface level 5 nos of try lines

are provided to each desalter and sample from these try lines is checked through a sample cooler.

Desalted crude from the two desalters combines in a common outlet for further heating.

PREHEAT TRAIN 2:-

Crude from desalters is sent to Preheat Train-II. The crude flow is again divided into two parallel branches of heat exchangers. Both the branches of Preheat Train-II combine before entering the flash zone of pre-topping column K-1. In this preheat section crude oil is heated to around 230OC which is the preheat temperature of feed to K-1.

PRE TOPPING COLUMN (K-1):-

The crude after getting preheated enters the pre-topping column K-1.This column is meant for removal

of the lighter ends from the crude and has 8 sieve trays below flash zone and 21 valve trays above 8 th

tray. Light naphtha boiling up to about 110 to 129OC is recovered as overhead product from this

column. This light naphtha also contains the lighter hydrocarbons like off-gas and LPG. The bottom

residue (pre-topped crude) at a temperature of 2450C is pumped to Preheat Train-III where the

temperature is raised to 360oC and then it is send to the fractionating column.

FRACTIONATING COLUMN (K-2):-

JMIT, Haryana.

Pre-topped crude after getting heated to 355--3660C in F-1/F-2/F-3 enters the flash zone of the main

fractionating column K-2. This column has 41 trays, out of which the bottom 1 to 6 trays are sieve trays

and 7 to 41 are valve trays. The column K-2 is operated at 0.6 to 1.0 kg/cm 2(g) pressure. Naphtha

boiling up to about 110 to 125OC is the overhead product from column K-2 and is commonly known as

E-2 gasoline. This naphtha is devoid of the light hydrocarbons like gas and LPG.

REFLUX DRUM (E-2)

The overhead vapour from the column K-2 enters overhead condensers T-8A, T-8B, T-8C and T-8D

working in parallel and the condensed liquid is received in the reflux accumulator E-2. A steam

connection is provided on vessel E-2 for steam flushing. Ammoniated water and Ahuralan are injected

in two O/H vapour lines of K-2 to maintain E-2 boot-water pH and to avoid corrosion in condensers

and reflux drum. Water accumulated in E-2 is drained out.

SNO

EQUIPMENTNO

SERVICE CAPACITY

( M3)

PRESSURE(kg/cm2)

OPERATING

DESIGN

1 E-1 K1 REFLUXDRUM

42 2.7 3.5

2 E-2

K-2 REFLUX DRUM 20 0.25

THEORY:-

The main function of Desalter is to remove salts. But as per the problem specified, we are getting more

salts in the surge vessel E-2. This indicates the inefficiency of the desalters. For this, a detailed study of

desalters is required.

JMIT, Haryana.

BILECTIC DESALTER.

DESALTER

Desalting is the accepted industry term for an electrostatic process for removing contaminants such

as salts, solids and water from crude oils at a refinery. Salts produced with crude oil are generally

present as brine a solution of salts in water. In addition, the crude oil contains solids such as finely

divided sand particles, clays, drilling mud, and rust and scale accumulated during production and

transportation of the oil to the refinery.

Before the crude oil is refined, these impurities must be removed for several reasons. Solid

contaminants can contribute to plugging of equipment and to scale formation. Chlorides, one of the

types of salts found in crude oil, can be responsible for the formation of hydrochloric acid at the

JMIT, Haryana.

temperatures commonly encountered in a crude oil distillation tower. Hydrochloric acid is extremely

corrosive. Removal of contaminants in crude oil can increase distillation capacity, cut down on refinery

fuel costs, and reduce corrosion and plugging problems. For all these reasons, desalting is the first and

one of the most important stages in a refining operation.

Crude supplied from OM&S have water in emulsion form which cannot be separated at OM&S by

settling. This water contains calcium, magnesium and sodium salts in dissolved form. Calcium and

magnesium chlorides on heating get hydrolyzed and release HCl, whereas sodium salts will get

deposited on heat exchanger surface which will foul them. To remove these salts along with water,

desalting process is used. For this a desalter is provided in the unit.

DESALTING OF CRUDE OIL IN REFINERIES

Electrical desalter is installed as an integral part of a crude distillation unit. When crude oil enters a

refinery, it typically contains a small amount of water, approximately 0.1 to 0.5 volume percent. The

water remaining in the crude oil contains water-soluble salts, and the crude oil contains insoluble

particulate matter. To lower the level of impurities in the crude oil, water must first be added to the

crude. The desalting of the crude oil is a two-part process; the first consists of forming an emulsion of

crude oil and water and the second is a demulsification process in which the emulsion of crude and

water formed in the first part is broken by means of an electrical field and demulsifier.

The salt occurs in the form of highly concentrated brine droplets dispersed throughout the curde. These

droplets are extremely small and are difficult to contact with the fresh water added to crude. Desalting

process consists of diluting this high salt content brine with incoming fresh water to produce low salt

content water. After demulsification and settling, the BS&W which remains in the crude is diluted

water instead of concentrated brine. For contacting incoming water effectively a fairly light emulsion

must be formed. This is done by means of a mixing valve ahead of electric desalter or injecting water at

the front of preheat exchanger train. Obviously, the greater the mixing or shearing action as well as

higher the velocity, the greater is the pressure drop, the samller is the particle size and higher and more

stable is the emulsion.

JMIT, Haryana.

The process of demulsification is accomplished by coalescing the small particles of emulsion together

so that they can form droplets of sufficient size to permit separation by gravity settling. This is

accomplished in electric desalting by passing the emulsion through an electric field. The particles of

water becomes polarized, orient themselves in a straight line approximately in the lines of force in the

electrical field and by random collision form large droplets which settle.

DESCRIPTION OF DESALTER

The desalter is a pressure vessel fitted with electrodes inside it to create an electric field. The crude

water emulsion enters the desalter in the bottom section of the vessel through an inlet distributor to

ensure uniform distribution over entire cross section and also to attain low velocity condition. A large

header, known as outlet crude collector is mounted inside the vessel at top portion and extends over the

entire length. This header is connected to the external withdrawal header, for drawing off the desalted

JMIT, Haryana.

crude. The water draw off piping is a header at the bottom of the vessel and extends over the entire

length. It is connected to the effluent drain header outside the desalter vessel.

At times, there can be sludge build up at the bottom of the vessel. A header with nozzles has been

provided at the bottom for creating turbulence by pumping water. Water mixed with sludge can be

drained out through a drain line. Steam also can be used in place of water for the above purpose. This

process is called desludging. It can be continuous as in AU-3 or can be done intermittently also.

Desludging is dealt under separate heading.The electrode system is the heart of desalter. These

electrodes are suspended from special suspension insulators, one electrode being immediately above the

other so that an electric field is created in the gap between the electrodes. The lower row of electordes

is connected to 18KV supply while top row of electrode is securely earthed. Both old and new desalters

in AU-3 operate on single phase supply.

DESALTER OPERATION

As the crude oil enters the unit, it is injected with a predetermined dosage of a chemical called

demulsifier that helps in subsequent breaking of emulsion in the electric field inside desalter. Crude

after passing through a number of exchangers, attains a temperature of around 130OC and at this point

water is injected into the crude at the predetermined rate, the mixture is passed through the mixing

valve (emulsifying valve) and is fed into the desalter. The water for the above injection should contain

minimum salt, and hence DM water /Stripping water (exit AU4) & boot w from E-1 and E-2 is used for

this purpose. This water is received in storage tank E-12 and any make up required is done with DM

water for which a permanent connection with the tank is provided. DMW make-up is done under

3LC3109 taken from TPS. Water from this tank is pumped with pump and heated in before injecting

into the crude line up-stream of the mixing valve.

Water separated in the desalter will settle down and will be drained out from bottom through the

interface level control valve. This water after exchanging heat with DM water is routed to a flash drum

E-19, open to the atmosphere, where water vapours are vented out and the water is drained into the

OWS system. A unit switch is provided through which supply to desalter can be put on or off. A pilot

lamp is provided which glows steadily till the current is normal and its intensity gets reduced once

JMIT, Haryana.

current exceeds 150 amps. Low-level magnetic switch is provided on desalters, which trips desalter in

the event of low crude level in desalters. In addition to this one voltmeter and one ammeter is provided

at site for each desalter. One ammeter alongwith high current alarm is provided in control room for

both desalters. To release excess pressure two PSVs set at 19.0 Kg/cm2(g) releasing to flash zone of

column K-1 are provided.

OPERATING VARIABLES

Desalter unit operation entails a great many variable factors, some of which have greater

influence than others in effective unit operation and desalter efficiency. How these factors can be taken

into account while optimising desalter operation is discussed below:

1. RAW CRUDE QUALITY

Crude oils with high viscosities, high specific gravities and asphaltic in nature are generally more

difficult to desalt. Light crude oils are easily desalted because the separation of oil and water is

facilitated by the low hold up effect of the light crude oils on the dispersed water droplets. Separation is

thus easier. In heavier oils, water droplets formation is slower and hence separation is difficult.

2. SLOP ADDITION / OIL

Oil slops collected in the refinery consist of recovered oils from the effluent system or other oils to

be reprocessed. These will sometimes adversely affect demulsification because of the stabilizing effects

of contaminants picked up in the effluent system.

3. FEED RATE

Since the desalting process is a largely physical and dynamic function, velocity and residence time

will affect its performance. Throughput changes will affect flow characteristics.

4. WATER INJECTION

Desalting may be linked to washing of the oil and hence requires sufficient wash water. The usual

recommendation is 3 to 8% vol (water) /vol (crude). If water is less desalting efficiency is reduced due

JMIT, Haryana.

to inability to contact all the droplets of high BS&W crude. If too much water is present, desalter may

shut out or current will rise to the point where operation becomes expensive. It is normally added just

upstream of the mixing valve. Some refineries divide the wash water injection, locating one entry point

(@ 1%) ahead of the preheat train, to help keep this clean. In case salt content is high, provision is there

to inject water at inlet or outlet of E-101 to increase contact time. The quality of the water used is of

course important particularly when caustic is added. Caustic addition to hard water will cause

precipitation of salt, which may plug up lines and be of considerable trouble. Normally DM water is

used. Most of refineries use stripped sour water. Normally water injection rate is varied from 2 to 6% of

crude to get required degree of desalting. Once the optimum rate is adjusted, it is not changed until

crude quality and mix is changed. During slop processing water rate is reduced due to high ingress

of water along with slop oil.

5. TEMPERATURE

In order to produce a good emulsion the viscosity of the crude oil must be kept below 40 cSt. This

means that sufficient temperature must be maintained to get a low viscosity of crude. Increased

temperature assists water settling when oil viscosity and density are as low as possible. However, oil

conductivity generally increases with temperature which may give some cause for concern when an

alarming rise in amperage is observed. So, normally most desalters are operated in the range of 120 -

140 0C.

6. PRESSURE

Pressure is not an operating variable except that the pressure should be high enough to prevent

vaporization within the desalter. Operating pressure of 2 to 3 kg/cm2 above the vaporization pressure at

a given temperature is normal.

7. MIXING ENERGY

Thorough mixing of the wash water and oil is necessary to extract the impurities. The closer the

admixing, the better is the removal. However, excessive mixing may form an emulsion too stable for

JMIT, Haryana.

the desalter to break resulting in carryover of water containing salt with the oil. The mixing energy is

controlled by the "Mixing Valve". Higher the pressure drop across the mixing valve, more thorough is

the mixing.

As the pressure drop is first increased, good desalting is quickly obtained, for a long period of increased

pressure drop no appreciable change in the salt content of the effluent is noticed, then a point is finally

reached where the effluent salt content will suddenly drop to practically zero. There will be another

point where slight increase in pressure drop will suddenly raise the salt content of the effluent crude oils

to almost the original value. BS&W of the crude increases gradually as the pressure drop is increased

until a limiting value is reached when the BS&W curve will turn abruptly upward. Average optimum

pressure drop through mixing valve is approximately 0.5 to 1.0Kg/cm2 (g). In case of slop processing

it may be required to reduce pressure drop as slop contains sludge and solids, which may

produce tight emulsion.

8. INTERFACE LEVEL

Interface level controller is provided which maintains water level in desalter. This interface should

be maintained at 85 to 105cm below the lower electrode. The exact point of control for maximum

desalting efficiency will depend upon the type of crude being desalted and appearance of effluent

water. To counter check position of interface, a number of try lines are provided. Normally interface

level remains between 2nd and 3rd try line from bottom and maximum it can be taken up to 4th try line.

If interface level is high, current drawn will shoot up and water and salts carryover along with crude

will increase which in turn will disturb column operation. Improper functioning of the interface level

controller will result in high oil content in effluent water or high current drawn.

9. CHEMICAL AGENT

A chemical agent is usually added to crude to help desalting. Its main functions are as follows:

* Help water coalescence

* Wet out solids

JMIT, Haryana.

* Avoid hydrocarbon dispersion in the aqueous phase

* Assist in emulsion breaking

These agents often referred to as "Demulsifier" are added to the crude oil at the rate of 3-10 ppm

vol/vol ahead of the charge pump and water injection.

10. AMPERAGE & VOLTAGE

A good demulsification calls for the maintenance of a high voltage across the electrodes. As the

conductivity of the fluid flowing between the electrodes increases, the current flow across the

electrodes will also increase and the voltage will drop. Generally this drop in voltage will result in poor

demulsification. When the conductivity of this becomes so great the voltage drops below

approximately 200 volts on the primary circuit, the unit will fail to break the emulsion and the

voltage may rapidly drop further to the point where the overload will kick out and shut the

desalter down.

There are various factors that affect the conductivity of the flowing fluid. The type of crude is one

variable. The temperature of the crude water mix will also have a marked effect on conductivity. As the

temperature increases, the conductivity increases. Thus from this stand point it is desirable to operate at

as low temperature as possible.

The biggest factor affecting conductivity is the percentage of water. Increase in water percentage,

increases conductivity until it reaches a point where the electrode will short out. Voltage required for

good desalting is approximately 3000 volts per inch of distance between electrodes. This high voltage

is obtained by means of transformers. Fluctuations in voltage are usually due to localized appearance of

water or emulsion and are generally not serious.

11. pH

pH has a big effect on conductivity. The conductivity becomes high at either high or low value of

pH. For this reason it is generally desirable to operate in the middle range. An operating range of pH

JMIT, Haryana.

from 6.5 to 8.5 is acceptable. In the high pH range it has been noted that the sodium naphthenates

formed by reaction of caustic and naphthenic acids in crude act as emulsion stabilizers and the

emulsion becomes very hard to break. During 2000 revamp caustic addition lines were removed and

caustic addition is discontinued. Presently Caustic is added to crude after desalter outlet.

12. SOLIDS AT WATER OIL INTERFACE

Invariably sludge will form at the water oil interface and if it is not removed, the sludge layer will

gradually build up until it finally reaches the electrodes and cause trouble. Some desalters have

skimming lines of removing the sludge periodically. Sludge or solids have a tendency to build up at the

bottom of the desalter. Some refiners have installed steam in the bottom of the desalter with the holes

facing the bottom of the vessel. Periodically steam is introduced through the drain out with the desalter

effluent water.

PROBABLE SOLUTIONS

1. RESIDENCE TIME

If more Residence time is provided to remove brine water, the salt content will be removed with it and this will reduce the salt content in further process. This will enable us to add more DM water which will increase the efficiency of the desalter. It is required to provide 24 hrs settling time so as to separate water from the crude. The water thus separated can be drained out. This is very effective measure because no extra cost is added to the process. But it is bit difficult to do so because of practical reasons.

The practicality of the solution is very less. It is not beneficial in terms of economy to provide residence time as we are in short of spare crude storage tanks.

2. INCREASE DM WATER

2 to 4 percent vol/vol of DM water should be added to the desalter. This should be done to dissolve the salt from crude to water. The addition of water to crude is very important as it decides the degree of dissolution and corresponding removal of salts.

JMIT, Haryana.

But it also has a limitation, as excess of water results into carryover of water through the desalter.

3. OPTIMISING PRESSURE DROP (∆P).

Pressure drop (∆P) is required to mix the water thoroughly with the crude as higher pressure drop enables the water to dissolve maximum salt possible. The increase in pressure drop (∆P) will form a better emulsion of oil and water. This will effectively take away the salts entrapped in oil thus increasing the efficiency of desalter to remove salt.

But the pressure drop (∆P) cannot be increased beyond a certain limit as this will cause carryover of salts with water and decreasing it beyond a certain limit will result in reduced coalescence which is not required. Thus optimization of pressure drop is suitable.

Thorough mixing of the wash water and oil is necessary to extract the impurities. The closer the admixing, the better is the removal. However, excessive mixing may form an emulsion too stable for the desalter to break, resulting in carryover of water containing salt with the oil. The mixing energy is controlled by the "Mixing Valve". Higher the pressure drop across the mixing valve, more thorough is the mixing.

4. INCREASING VOLTAGE:-

Increase in the transformer voltage will allow us to add more DM water as this will enable effective coalescence of water molecule with salt and thus would increase the efficiency of desalter.

Sr.No. PARAMETERS CURRENT VALUES PROPOSED VALUES

1 Residence time No residence time 24 hrs resident

2 DM water 2 to 4% vol/vol 5 to 8% vol/vol

3 Pressure drop 0.9 kg/cm2 1.1 to 1.4 kg/cm2

4 Voltage 11 KVA >11KVA

5 Dewatering aid Not used Should be used

6 No of transformers 1 nos. 2 or more

7 Maintainanceand cleaningof crude storage tanks

---------- Required

JMIT, Haryana.

SUMMARY

All the above mentioned solutions are deployed in the plant and chloride content has been reduced to

acceptable limits.

LEARNING

JMIT, Haryana.

I have gained knowledge by this training in various aspects as an engineer, as I had firsthand

experience in Indian Oil Corporation Limited.

Training here, has enhanced my cognition, as the employees have explained, with commitment, all the

doubts aand questions that arouse in my mind. This chance thrown at me, was a boon as I had only

seen and read about all the equipments used in industry, which now, I am able to distinguish well

enough. This was not possible with the bookish knowledge.

I heartly thank all the employees of IOCL to have helped me all throughout my training

JMIT, Haryana.

BIBLIOGRAPHY

1. IOCL MANUALS2. www. petroleumrefining.com, Petroleum Refining Engineering Website.3. Unit Operations of Chemical Engineering by Dennis C. Prieve, Pittsburg.4. www.engineeringtoolbox.com, Chemical Engineering Website5. Petroleum Refining by James H. Gary, Colorado

JMIT, Haryana.