Sulfur Recovery Units:
Gas Treating Units:
Hydrogen Manufacturing Units:
The unit was upgraded to achieve the capacity of 195,000 BPD. However, it is currently operated at 200,000 BPD.
The Crude Oil is separated by fractionation into the following raw products and feedstock for various downstream processing units:
Hydrogen Manufacturing Units (Units 02E, 02W, & 62)
Each of the three identical Steam/Gas Reforming Units can produce 74 MMSCFD (87,110.75 Sm3/h) of 95% pure Hydrogen. The Hydrogen product is then compressed to a pressure of about 2800 psig (193 barg) by compressors in Unit 03.
Unit 03 consists of five gas engine driven compressors, each of 30 MMSCFD (35,315.17 Sm3/h) capacity and two electric motor driven compressors, each of 40 MMSCFD (47,086.89 Sm3/h) capacity. The compressed Hydrogen is supplied to Hydro—cracking and Hydro-treating Units.
Catalytic Reforming Unit (Unit 05)
This unit is for production of Reformate — high octane motor gasoline blending component and has a design capacity of 15,800 BPSD Max. The unit operates with Hydrotreated Naphtha feed from U-10 using a Platinum based catalyst in three reactors.
Isocracker Unit (Unit 68)
Unit original design capacity is 44,000 BPSD and it is currently operated at 46,000 BPSD. The feed comprises a mixture of Heavy Gas Oil and Heavy Diesel from Crude Unit, Heavy Diesel Unifiner Bottoms and LVGO from H-Oil Vacuum Unit. Hydro-cracking reactions take place in a ﬁxed bed reactor using proprietary catalyst. The reactor product stream is fractionated into quality products, Naphtha, Kerosene and High Pour Diesel. The fractionator bottoms (unconverted part of Gas Oil) is fed to the Isomax Unit.
Isomax Unit (Unit 08)
Unit design capacity is 36,000 BPD with 23,000 BPSD of fresh feed. The feed is normally fractionator bottoms from Unit - 68. Hydro-cracking reactions take place in a fixed bed reactor using proprietary catalyst. The reactor effluent, is separated in into Naphtha, Kerosene, High Pour Diesel products. Unconverted oil, fractionator bottom, is recycled as feed while small part is sent out as bleed which normally goes to FCC feed.
H-OIL Unit (Unit 07)
H-Oil unit processes about 50,000 BPSD of Vacuum Bottoms from Crude Unit. By hydrocracking with a catalyst, it converts about 50% of the heavy feed into value Distillates and a Fuel Oil of considerably low Sulfur content. The unit consists of two independent trains (07A & 07B) each of 25,000 BPSD capacity. Each train reactor section consists of feed and hydrogen heaters, an ebullating catalyst bed reactor, and recycle gas compressor. The reaction product passes thru common fractionation and vacuum distillation facilities (Unit — 63) producing mainly Naphtha, Kerosene, Diesel, light and heavy Gas Oils. These streams are further refined except heavy Gas oil that can be partly recycled with the feed.
H-Oil Vacuum Unit (Unit 63)
The unit is designed to process 42,000 BPD of Unit — 07 bottoms. Mainly the heavy ends that cannot be distilled under atmospheric pressure is separated in the vacuum tower. The feed is heated up and is sent to vacuum tower. The separation products are Heavy Diesel, LVGO, HVGO and Fuel Oil. Heavy diesel and LVGO is sent to U-13 and U-68 for further treatment. HVGO and Fuel Oil is sent to tanks.
Gas Unit (Unit 01)
The unit capacity is 73.3 MMSCFD Burgan Gas (LP Gas) feed. Part goes to Refinery Fuel Gas system while other part is compressed with a pair of compressors. Compressed gas is amine treated for removal of H2S and used as feed gas for production of Hydrogen.
HP lean gas from MAA is used as Engine Fuel Gas for gas engine driven Hydrogen Compressors in Unit 03 as well as H2 plant feed utilizing a new compressor in Unit 14 and amine treating.
Naphtha Fractionation Unit (Unit 09)
Unit design capacity is 65,000 BPSD of Naphtha liquid feed and 17.5 MMSCFD of Naphtha Gas feed from Crude Distillation and other secondary process units. It produces stabilized Naphtha, Kerosene and low pressure gas destined for Refinery Fuel Gas System. The Unit also provides circulating Kerosene lean oil to Gas Absorbers in Unit 09 and Gas Unit (Unit 01) for recovery of Butane and heavier hydrocarbons.
Naphtha Unifiner Unit (Unit 10)
This unit has a design capacity of 26,000 BPSD Max. It hydrotreats Naphtha using Hydrogen on a ﬁxed catalyst bed. Heavy Naphtha is separated from the Reaction product to be used as feed for Catalytic Reforming Unit. Hydrogen requirement is normally met by excess Hydrogen available from Catalytic Reformer.
Kerosene Unifiner Unit (Unit 11)
This unit has a design capacity of 34,250 BPSD, normally operating at 35,000 BPD Maximum. It hydrotreates kerosene from Crude, Naphtha fractionation unit and H-Oil Units into finished products. The Unit utilizes Hydrogen in a fixed bed reactor.
Light Diesel Unifiner Unit (Unit 12)
The unit design capacity is 12,600 BPSD but normally operated at enhanced capacity of 17,000 BPD. It hydrotreats and hydro-desulfurizes light and heavy diesel fractions from Crude. The Unit utilizes Hydrogen in a fixed bed reactor. The products are Light diesel Base stock for blending as final product.
Heavy Diesel Unifiner Unit (Unit 13)
This unit design capacity is 9,320 BPSD but normally operated at enhanced capacity of 12,000 BPD. It hydrotreats and hydro-desulfurizes light and heavy diesel fractions from H-Oil & Vacuum Unit (U-63) and Crude Unit. The Unit utilizes Hydrogen in a fixed bed reactor. The products are light diesel Base stock for blending. Bottom heavy Diesel is used as part feed to the Isocracker Unit 68.
This unit can also operate on an alternate feed of raw kerosene like Unit 11.
Amine Treating Unit (Unit 14)
This unit essentially serves to remove H2S from various gas streams mainly resulting from hydrocracking and hydrodesulphurization operations. The H2S is removed by absorption with 15% Mono-ethanolamine solution circulating in three contactors. The treated gas is used as Hydrogen Unit feed gas. Recovered Acid Gases are sent to Sulfur Recovery Plants.
Kerosene Merox Unit (Unit 17)
The unit is designed to sweeten 15,000 BPSD of light kerosene from Naphtha Fractionation Unit (Unit 09) to produce ATK product. The process utilizes a proprietary catalyst on-charcoal and air to remove Mercaptans and any H2S . Unit currently operates at enhanced capacity of 22,000 BPD.
Sulfur Recovery Plant (Units 04 & 74)
Each of these units is capable in the original design of processing 19.2 MMSCFD of Acid Gas for production of about 600 Lt/D elemental Sulfur product. Normally both units operate in parallel. H2S rich gas is burnt with controlled amount of air in reaction furnace and subsequently in two reactor loaded with catalyst to produce liquid sulfur which is sent to MAA for export.
Tail gases from SRU’S, containing about 5% of original Sulfur are fed to the TGTU (Unit 75) for recovering the residual Sulfur.
Tail Gas Treating Unit (Unit-75)
The tail gas exiting the Sulfur Recovery Units (U 04 and U 74), merges into one stream and enters Unit 75. The purpose of the Tail Gas Treating Unit (TGTU) is to convert the remaining sulfur compounds, mainly H2S and SO2, into liquid sulfur, thus increasing the recovery of sulfur up to 99.5%. The Unit uses Clauspol II Process which is based on the reaction between residual H2S and SO2 in a liquid catalyst solution containing Polyethylene Glycol, Salicylic Acid and Sodium Hydroxide.
Acid Gas Removal Plant (Unit — 61)
The unit is designed to treat 48.5 MMSCFD West Field Gases, 15.0 MMSCFD Reﬁnery Gases and 4,000 BPSD (currently not used) West Field Condensate for removal of H2S and CO2. The treated sweet product is routed to an LPG Plant at a nearby refinery and Acid Gas is routed to Sulfur Units (Units 04/74) for Recovering Sulfur.
Ammonical Water Treating Units (U-15C & 15)
The units 15 & 15C are designed for treating sour water from various unit to remove mainly H2S and NH3. Unit-15C is the Ammonical Sour Water Concentrator. It operates in parallel to Unit 06F, Foul Water Concentrator. Both 06F and 15C produce concentrated Ammonical Water. The concentrate is reprocessed in Unit15 to remove the H2S and NH3 separately and produce treated water for safe discharge and/or recycling. Recovered H2S is sent to Sulfur Recovery Unit and NH3 is burnt in SRU furnace or, alternately Flared.
Utilities (Areas 20,29,22,64,--)
Besides above mentioned units, there are other auxiliaw and support units systems in the Reﬁnery, e.g. Boilers and Steam Stations to supply four levels of steams (i.e. 900psig, 475 psig, and 50 psig) and Instrument Air, Cooling Water, Distilled water, Process water, high and low pressure condensates and Nitrogen supply system and Eff. Water Treating Units.
Flare Gas Recovery Unit
This unit designed to recover 18.76 million SCFD of flared gas from refinery process units. Flared gases, which earlier was burnt at Flare Stacks, are now recovered with a pair of compressors and utilized as fuel gas after necessary amine treatment for H2S removal. The amount of gas burnt in the flare is reduced from 16.5 (average) to 0.9 million SCFD. This has drastically reduced the emission of sulfur oxides to atmosphere and minimized pollution.
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