iogtr.com · 2019. 10. 3. · SHUAIBA REFINERY - UNIT OVERVIEW UNIT OVERVIEW 2 APPENDIX-1B CLAUSE...

SHUAIBA REFINERY - UNIT OVERVIEW

UNIT OVERVIEW APPENDIX-1B

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APPENDIX-1B

SHU REFINERY - UNIT OVERVIEW



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CLAUSE TITLE PAGE

1.0 UNIT - 01 OVERVIEW - BUGAN GAS UNIT 04

2.0 UNIT - 02E/W OVERVIEW – HYDROGEN PRODUCTION UNIT 11

3.0 UNIT - 03 OVERVIEW - HYDROGEN COMPRESSION UNIT 19

4.0 UNIT - 04 OVERVIEW - SULPHUR RECOVERY UNIT 25

5.0 UNIT - 05 OVERVIEW - CATALYTIC REFORMER UNIT 31

6.0 UNIT - 06 OVERVIEW - CRUDE AND VACUUM UNIT 37

7.0 UNIT – 06F OVERVIEW - FOUL WATER TREATING UNIT 45

8.0 UNIT – 07A/B OVERVIEW - H OIL TRAIN A/B 47

9.0 UNIT - 08 OVERVIEW - ISOMAX UNIT 56

10.0 UNIT - 09 OVERVIEW - NAPHTHA FRACTIONATOR UNIT 64

11.0 UNIT - 10 OVERVIEW - NAPHTHA UNIFINER UNIT 70

12.0 UNIT - 11 OVERVIEW - KEROSENE UNIFINER UNIT 76

13.0 UNIT - 12 OVERVIEW - LIGHT DIESEL UNIFINER UNIT 83

14.0 UNIT - 13 OVERVIEW - HEAVY DIESEL UNIFINER UNIT 91

15.0 UNIT - 14 OVERVIEW - AMINE TREATING UNIT 98

16.0 UNIT - 15 OVERVIEW - AMMONICAL WATER TREATING UNIT 105

17.0 UNIT - 15C OVERVIEW - SOUR WATER CONCENTRATOR UNIT 111

18.0 UNIT - 17 OVERVIEW - KEROSENE MEROX UNIT 114

19.0 UNIT - 19 OVERVIEW - DIMINERALIZING UNIT 120

20.0 UNIT - 20 OVERVIEW - BOILERS UNIT 125

21.0 UNIT - 22 OVERVIEW - COOLING WATER SYSTEM 130

22.0 UNIT - 23 OVERVIEW - SEA COOLING WATER SYSTEM 135



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CLAUSE TITLE PAGE

23.0 UNIT - 29 OVERVIEW - FUEL GAS SYSTEM, FLARE SYSTEM, FLARE

GAS RECOVERY UNIT & INSTRUMENT AND PLANT AIR 137

24.0 UNIT - 35 OVERVIEW – SULPHUR DEGASSING UNIT 149

25.0 UNIT - 61 OVERVIEW – ACID GAS REMOVAL UNIT 151

26.0 UNIT - 62 OVERVIEW - HYDROGEN PRODUCTION UNIT 158

27.0 UNIT - 63 OVERVIEW - H-OIL VACUUM DISTILLATION UNIT 164

28.0 UNIT - 64 OVERVIEW - COOLING WATER SYSTEM 170

29.0 UNIT - 68 OVERVIEW - ISOCRACKER UNIT 175

30.0 UNIT - 74 OVERVIEW - SULPHUR RECOVERY UNIT 182

31.0 UNIT - 75 OVERVIEW - TAIL GAS TREATING UNIT 189

32.0 UNIT - 60 OVERVIEW - OFFSITE PIPING 197

ANNEXURES

01 ANNEXURE - 01 - SINGLE LINE DIAGRAM UNIT-WISE



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1.0 UNIT - 01 OVERVIEW (Burgan Gas Unit)

1.1 PROCESS OVERVIEW

1.1.1 Objective

To compress and treat Burgan Gas (currently LP Lean Gas from MAA) for providing feed

gas to Hydrogen Units (02/62) and Engine Fuel Gas required for engine drivers on

Hydrogen compressors in Unit – 03 and also used in SRU’s. The Unit also provides low

pressure gas to Refinery Fuel Gas system as make up.

1.1.2 Capacity

The Unit is designed to compress and treat 48.7 MMSCFD (Insurance – 73 MMSCFD) of

LP Lean Gas.

The LP lean Gas Compressors are two stage centrifugal machines with 900 psig steam

driven turbines.

1.1.3 Feed and Products

Refer Tables 1&2 below.

a) Table-1: Typical Material Balance

b) Table-2: Typical Feed & Product Qualities



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1.1.4 Process Description

Refer sketch-1

Lean imported L.P. gas, containing mostly C1, C2, C3 (mostly C1, post Ethane Recovery

Project) is received into the Refinery through a knockout Drum V-01-01 where entrained

liquid condensate is separated and pumped to Unit-09.

Approximately 40 - 60% of the gas is routed directly to the Refinery Fuel Gas system as

make-up. The balance, about 25 MMSCFD of gas is compressed through compressor C-

01-01A/B first stage to 150 psig, cooled and condensed liquid separated. The separated

gas is treated in the Amine Unit 14 Contactor, V-14-02 where H2S and CO2 are

removed. Following treatment, the gas passes through the absorber V-01-04, where

originally most of the C4 and heavier hydrocarbons are removed from the gas stream by

absorption with cold lean oil, Kerosene. Currently V-01-04 is not in service. The lean gas

from the absorber goes to a knockout drum, V-01-03, for removal of entrained

condensate. A part of this dry treated gas is compressed further in Compressor’s second

stage and sent to the Hydrogen plants (02/62). A part of gas is also used in Sulfur Units

as fuel gas at startup & S/D , blanketing gas and back up for Engine Fuel Gas for

Hydrogen compressor C-03-01 A-E.

The mixture of hydrocarbons removed from the L.P Lean Gas by lean oil absorption is

sent as rich oil to Naphtha Fractionation Unit (09) for Naphtha recovery. Condensate

recovered from the various knockout drums is also sent to Naphtha Fractionation Unit

(09).

An additional K.O drum V-01-05 was installed in association with Rich gas injection from

U-61 to help increase gas density when required.

Recently, in 2010, a facility to desulfurize some quantity of Imported LP Gas for use as

part Refinery Fuel was commissioned to reduce H2S content in Fuel gas. Up to about 25

MMSCFD of LP Gas is routed to Amine Contactor V-14-01 through V-29-04. Low H2S

outlet gas is used as component of Refinery Fuel Gas.



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1.1.5 Brief History

C-01-01A Compressor revamped along with new PLC and control systems in the

year 2000.

Vessel V-01-05 knockout drum for rich gas injection added in year 2009

1.2 STATIC & PIPING OVERVIEW

Brief write-up on Static and Piping equipment are given in Refinery Overview. However,

the summary of the Static Equipment for Unit-01 is listed as follows; List of Static

Equipment with History are furnished vide Appendix 2A hereof.

Sl. # Equipment Description No of Equipment

1 Exchangers, Shell & Tube 07

2 Air Coolers 03

3 Vessels 09

4 Tanks / Drums 06

5 Filters 08

6 PSVs 26



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1.3 ROTATING OVERVIEW

Unit 01 – This Unit Compress and treat Burgan gas and LP Lean gas for providing feed

gas to Hydrogen units and Fuel gas required for gas engine drivers in unit 03.

All the Rotating equipment in 01 unit are inspected and maintained as per the guidelines

of Process Licensor & good Engineering practices. Turn around schedules are fixed as

per these guidelines to ensure safety, integrity, operability, reliability and efficiency of the

plant.

Unit 01 has 8 Pumps, 6 Fin fans, 2 Turbines & 2 Compressors. List of Rotating

Equipment are furnished vide Appendix 2A hereof.

Pump/Compressor/Blower package auxiliary items (filters, SO/LO Coolers, Gearboxes,

Seals, Couplings, Piping items etc.) are not included in the list. Bidders can collect

relevant details of maintenance records, healthiness of the equipment and inspection

records during PTM/Site visit.

1.4 ELECTRICAL OVERVIEW

Unit -01 is considered as classified area (Class 1 Div. 2 Group D) as per Shuaiba

Refinery Hazardous Area Classification drawing (refer drawing # R-00-6030). The source

of power to the Unit is aided from Substation 04 which is located south side of the Unit.

The substation is Building with Basement Type & facilitated as non-classified area by

employing pressurized / Air conditioned systems. Substation has 3 nos. of “6.6kV”

Switchgears (4A, 4B & 4C) fed from SS1A & SS1B (ref. drawing # R-00-6012), 9 nos. of

“440V” MCC (MCC-4A, MCC-4B, MCC-4C, MCC-4D, MCC-4E, MCC-4F, MCC-4G, MCC-

4H & MCC-4J), 9 nos. of power transformers (1MVA, 6.6kV/440V) and 4 nos. of

Emergency panel (EDB-01-01). The “6.6kV” Switchgears 4C were replaced completely

with latest new ABB panels during GRTA-2011 under contract CS/1955. The Substation

is equipped with Fire Detection, Alarm & Suppression system which was installed under

contract CB/CSPD/2004 & commissioned on 2016. Battery Charger along with Battery

backup bank are also available.

The list of LT Motors associated with this Unit is enclosed vide Appendix 2A hereof.

Motors rated less than or equal to 280HP is designated as LT motor. Unit-01 has 12 nos.

of 440V motors. All motors are under Preventive Maintenance program by maintenance

department.

Other electrical equipment such as Light fixtures, Distribution Boards, junction Box,

power sockets, push button stations, Fire Alarm detectors, Lighting transformers (25kVA

440/415V), above ground cables, conduits etc. available in the Unit are not listed

separately. Bidders can collect relevant details during Site visit.

The Unit-01 is powered from the Substation # 4 and the Single Line Diagram (SLD) for

SS # 4 is as follows (for details Refer Annexure-01, KNPC Sketch # SK-2434 Sheet 01

of 08).



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Note: The Substations are shared between different units and a table that shows the

association of different units to Substation is shown in Appendix 1A - Refinery Overview.



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1.5 INSTRUMENTATION OVERVIEW

Unit – 01 is designed to process low pressure lean gas Burgan gas supplied by KOC

through LP Gas Network. A large portion of the gas is used as Refinery fuel gas make up

and balance is compressed by Compressors C-01-01 A/B treated in Amine Treatment in

Unit – 14 before being further processed in Unit – 01.

1.5.1 Instrumentation System

a) DCS: Honeywell make TPS System installed in SIH #7, SIH # 10 & GUS

Operating stations installed in CCR.

b) ESD System: Honeywell make Safety Manager System installed in SIH # 7, SIH #

10 & CCR.

c) FSC System: Honeywell make FSC system installed for ROIV Control in Unit – 01.

d) PLC System: Allen Bradley make PLC System for C-01-01 A/B Compressor

Interlock Control.

e) Bently System: Bently make Vibration Monitoring System for C-01-01A

Compressor.

f) Speed Governor: Wood ward speed Governor for C-01-01A Compressor.

1.5.2 Critical Safety Interlocks and Controls

a) C-01-01A/B Compressor Interlock & Control.

b) Burgan gas header pressure Control & Interlock.



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c) C-01-01A/B – Anti Surge Control.

d) Engine Fuel Gas Pressure Control.

e) Refinery Fuel Gas Pressure Control.

f) 01-ROIV-1000/01-ROIV-1001/01-ROIV-1002 Interlock Control.

1.5.3 Field Instrument List

SR. # CATEGORY MAKE QTY REMARKS

1 BTU / H2S & SP.GR.

ANALYZER ROSEMOUNT-GCX V 3.2 / YOKOGAWA-

GD43 7

2 CONTROL VALVE MASONEILAN / SAMSON / TYCO /

VIRGO 47

3 CONTROLLER FOXBORO / YOKOGAWA / MOORE /

MASONEILAN 10

4 DISPLACER LT MASONEILAN / MAGNETROL 7

5 FLOW ELEMENT DANIEL 23

6 HMI SIEMENS 2

7 LEVEL GAUGE GLASS JERGUSON / PENBERTHY / K-TEK 21

8 LEVEL SWITCH MAGNETROL / MOORE / SOR 21

9 PLC ALLEN BRADELY (CONTROL LOGIC) 2

10 PRESSURE GAUGE ASHCROFT / WIKA / WISE / GENERAL /

AM GAUGE 146

11 PRESSURE SWITCH UE / ASHCROFT / SOR / BOURDON

SEDEME 23

12 SOLENOID VALVE ASCO 7

13 TEMPERATURE SWITCH UE 7

14 THERMOWELL THERMO ELECTRIC / TECNOMATIC /

TC LTD 72

15 TRANSMITTER ROSEMOUNT / YOKOGAWA /

HONEYWELL / ABB / FOXBORO / SMAR 61

16 VIBRATION BENTLY NEVADA-3300 1

17 MISC HONEYWELL 57



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2.0 UNIT – 2E / 2W OVERVIEW (Hydrogen Production Unit)

2.1 PROCESS OVERVIEW – (Unit – 2E/2W)

2.1.1 Objective

Hydrogen Units generate and supply high purity and high pressure Hydrogen needed in other Refinery Units, e.g. H-Oil, Isocrackers, Unifiners.

2.1.2 Capacity

There are three Hydrogen manufacturing Units in Shuaiba Refinery. Each plant is

designed to produce 74 MMSCFD of 95% purity Hydrogen.


The feed to the Hydrogen Unit is a mixture of treated Burgan Gas and recycle High

Pressure Flash Gas. Burgan Gas is mainly hydrocarbons, while recycle gas is a mixture of

different Hydrogen rich bleed gases from Hydrogen consuming Units (treated in U-14).

The design product Hydrogen purity is 95% and the maximum Carbon Oxides

specifications is 10 PPMV. The battery limit pressure and temperature of export Hydrogen

to consuming Units are 2800 psig and 250oF respectively. The product Hydrogen from

Unit-03 is routed to H-Oil, Isomax / Isocracker and Unifiners.

2.1.4 Material Balance

The attached Table-1 indicates the overall material balance for design and test run

conditions.

a) Table-1: Feed and Product Qualities

DESIGN TEST RUN DESIGN TEST RUN

Hydrogen % Vol 39.96 46.40 94.99 94.93 Methane 41.68 30.57 5.01 5.07 Ethane 13.25 8.26 Propane 4.17 10.41 Butane 0.94 4.36 Mol. Wt. 13.86 15.41 2.74 2.73 Lbs/Hr 36667 38920 22165.00 23075.00 MMSCFD 24.09 22.98 73.79 77.08

FEED PRODUCTS



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The Feed Gas is preheated in Hydrogen Reformer Convection Section and the last

traces of organic and inorganic Sulfur compounds are removed in Zinc Oxide beds.

High Pressure steam is mixed with the treated feed gas and further heated up in the

Reformer Convection Coils before it is introduced into the Reformer Catalyst Tubes filled

with Reformer catalyst. Steam and feed gas hydrocarbons react in the presence of Nickel

catalyst to form Hydrogen, Carbon dioxide and Carbon monoxide. This steam reforming

reaction is highly endothermic, requiring heat energy for reaction.

Waste heat is recovered from the Reformer effluent to produce 900 psig steam and partly

for heating Methanator inlet gas.

The carbon monoxide (with excess steam) in the Reformer effluent is further converted

into Hydrogen and Carbon dioxide in High Temperature and Low Temperature Shift

Convertors. Shift conversion reaction is exothermic, producing heat energy.

The Shift Converter Effluent exchanges heat in the MEA Regenerator Reboilers and

further cooled before it is passed through MEA Absorber. A 20% by Wt.

Monoethanolamine solution is used to absorb carbon dioxide. The Rich solution is

regenerated by heating and flashing at low pressure and the regenerated Lean MEA

solution is pumped back to CO2 Absorber after cooling. A slip stream of Lean MEA

solution is filtered in a mechanical filter and a charcoal filter.

The CO2 Absorber effluent gas is heated and in the Methanator the remaining small

quantities of carbon monoxides & carbon dioxide are converted to methane in order to

meet the product carbon dioxide specification.

The Methanator effluent is heat exchanged with the Methanator inlet gas, further cooled

and sent to Unit-03 for compression.

The process scheme is shown in the attached Sketch -1.



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2.1.6 Brief History

Unit 02E and Unit 02W Reformers were revamped.



the summary of the Static Equipment for Unit-02E/02W is listed as follows; List of Static




2 Air Coolers 08

3 Vessels, columns, tanks, drum 38

4 Heaters 02

5 Boilers 02



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6 Filter 04

7 Silencers / Ejectors etc 07


Unit 02 East & West Hydrogen units generate and supply high purity and high pressure

Hydrogen needed in other units e.g. H-Oil, Isocrackers and Unifiners.

All Rotating equipment in 13 Unit are inspected and maintained as per the guidelines of

Process Licensor & Good Engineering practices. Turn around schedules are fixed as per

these guidelines to ensure safety, integrity, operability, reliability and efficiency of the

plant.

Unit 02 E&W has 16 Pumps, 109 Fin fans, 2 Steam Turbines & 1 Mixer. List of Rotating


Critical pumps packings converted to mechanical seals to the spirit of API 682 to prevent

Gas leakage to environment.

Pump/Compressor/Turbine package auxiliary items (filters, SO/LO Coolers, Gearboxes,

Seals, Clutches, Couplings, Piping items etc.) are not included in the list. Bidders can

collect relevant details of maintenance records, healthiness of the equipment and

inspection records during PTM/Site visit.


Unit -02 is considered as classified area (Class 1 Div. 2 Group B) as per Shuaiba


of power to the Unit is aided from Substation 08 which is located north-west side of the

Unit. The substation is Building with Basement Type & facilitated as non-classified area

by employing pressurized / Air conditioned systems. Substation has a 6.6KV Switchgear

fed from SS1A & SS1B (ref. drawing # R-00-6012), 3 nos. of 440V MCC (MCC-100,

MCC-200 & MCC-300), 3 nos. of power transformers (1MVA, 6.6kV/440V) and an

emergency distribution board (EDB-02-01). The 6.6KV Switchgear were replaced

completely with latest new ABB panels during GRTA-2011 under contract CS/1955. The

Substation is equipped with Fire Detection, Alarm & Suppression system which was

installed under contract CB/CSPD/2004 & commissioned on 2016. Battery Charger along

with Battery backup bank are also available.

The list of HT & LT Motors associated with this Unit is enclosed vide Appendix 2A

hereof. Motors rated above 280HP is designated as HT motor and if less than or equal to

280HP, as LT motor. Unit -02 has 3 nos. 6.6KV motors and 119 nos. 440V motors. All

motors are under Preventive Maintenance program by maintenance department.



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SS # 8 is as follows (for details Refer Annexure-01, KNPC Sketch # SK-2434 Sheet # 06

of 08);

Note: The Substations shared between different units and a table that shows the

association of different units to Substation shown in Appendix 1A - Refinery Overview.


Hydrogen Unit Processes mixtures of treated Burgan Gas, High Pressure Flash Gas and

stream to produce Hydrogen. Feed gas and process steam reacts at high temperature

and pressure in pressure of Catalyst to produce Hydrogen Gas.

2.5.1 Instrumentation System in Unit-02E

a) DCS: Honeywell make TPS System installed in SIH #2, SIH # 10. GUS Operating

stations installed in SIH # 2 & CCR.


10 & CCR.

c) FSC System: Honeywell make FSC system installed in SIH # 10.



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2.5.2 Critical Safety Interlocks and Controls Unit-02E

a) Heater - H-02-01 – Interlock East Cell

b) Heater – H-02-01 – Interlock West Cell

c) Methanator – V-02-03 – Interlock

d) CO2 Absorber – V-02-04 – Interlock.

e) P-02-03A/B MEA Circulation Pump Interlock

f) 02-ROV-1000 – Feed gas Inlet to V-02-21 Interlock.

2.5.3 Field Instrument List Unit-02E

2.5.4 Instrumentation System in Unit-02W

a) DCS: Honeywell make TPS System installed in SIH #2, SIH # 10 & CCR. GUS

Operating stations installed in SIH # 2 & CCR.


10 & CCR.

SR # CATEGORY MAKE QTY REMARKS

1 ANALYZER ROSEMOUNT / YOKOGAWA / ABB 6

2 CONTROL VALVE FISHER / MASONEILAN / SAMSON GERMANY

/ TYCO / VIRGO 32

3 CONTROLLER FOXBORO / YOKOGAWA / TAYLOR /

MASONEILAN 12

4 DISPLACER LT MASONEIAN / MAGNETROL 7

5 FLOW ELEMENT DANIEL / SAMIL 42

6 FLOW SWITCH MAGNETROL / ITT BARTON 2


8 LEVEL SWITCH MAGNETROL / MOORE / SOR / 7

9 LOCAL INDICATOR ITT BARTON / BROOKS / KROHNE / WISE /

AMETEK 88

10 PRESSURE GAUGE ASHCROFT / WIKA / WISE / GENERAL / AM

GAUGE 184

11 PRESSURE SWITCH UE / ASHCROFT / SOR / BOURDON SEDEME 7


13 THERMOWELL THERMO ELECTRIC / TECNOMATIC / TC LTD 106

14 TRANSMITTER ROSEMOUNT / YOKOGAWA / HONEYWELL /

ABB / FOXBORO / SMAR 79

15 MISC HONEYWELL 8



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c) FSC System: Honeywell make FSC system installed in SIH # 10.

2.5.5 Critical Safety Interlocks and Controls Unit-02W





e) P-02-53A/B MEA Circulation Pump Interlock

2.5.6 Field Instrument List Unit-02W


1 ANALYZER YOKOGAWA / ABB 3

2 CONTROL VALVE FISHER / MASONEILAN / SAMSON GERMANY

/ TYCO / VIRGO 31


MASONEILAN 10





8 LEVEL SWITCH MAGNETROL / SOR 2


AMETEK 71


GAUGE 104

11 PRESSURE SWITCH UE / ASHCROFT / BOURDON SEDEME 6





15 MISC HONEYWELL 8



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3.0 UNIT – 03 OVERVIEW (Hydrogen Compression Unit)


3.1.1 Objective

Hydrogen Compression Unit compress and supply high purity and high pressure

Hydrogen needed in other Refinery Units, e.g. H-Oil, Isocrackers, Unifiners.

3.1.2 Capacity

There are seven compressors in the unit. The total capacity of the unit is 228 MMSCFD


Refer to attached Flow schemes SK-01.

There are seven reciprocating compressors for Hydrogen. Two of them are driven by

motors and the rest with internal combustion engines using Refinery Engine Fuel Gas/HP

Lean Gas. The Hydrogen is compressed in three stages with intermediate Coolers and

Separators. Also, Unit-03 contains a Tempered Water cooling circuit for the

Compressor/Engine jacket and Lube Oil Coolers.



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1 Exchangers 14

2 Air Coolers 14

3 Vessels / tanks 30

4 Compressor accessories - Filters 10

5 Compressor accessories - Silencers 05

6 PSVs 11


Unit 03 – This Unit helps to Compress the Hydrogen from units 02 & 62 and supply high-

pressure nitrogen needed in other units.




plant.

Unit 03 has 9 Pumps, 38 Fin fans, 5 Engines, 10 Compressors & 10 Blowers. List of

Rotating Equipment are furnished vide Appendix 2A hereof.

Pump/Compressor/Blower package auxiliary items (filters, SO/LO Coolers, Gearboxes,





Unit-03 is considered as classified area (Class 1 Div. 2 Group B) as per Shuaiba Refinery

Hazardous Area Classification drawing (refer drawing # R-00-6030). The source of power

to the Unit is aided from three Substations, SS # 8, & SS # 15 which is located south side

of the Unit. The substation is Building with Basement Type & facilitated as non-classified

area by employing pressurized / Air conditioned systems. The Substation is equipped

with Fire Detection, Alarm & Suppression system which was installed under contract

CB/CSPD/2004 & commissioned on 2016. Battery Charger along with Battery backup

bank are also available.



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280HP, as LT motor. Unit -03 has 3 nos of 6.6KV motors and 55 nos. 440V motors. All






The Unit-03 is powered from the Substation # 8 & 15 and the Single Line Diagram (SLD)

for SS # 8 & 15 is as follows (for details Refer Annexure-01, KNPC Sketch # SK-2434

Sheet # 06 & 07 of 08);





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Compression of Hydrogen product from 270 PSIG to about 2800 PSIG is carried out in

Unit – 03 using 07 no. Hydrogen Compressor C-03-01 A to G. Out os these 5 no’s are

Gas Engine driven and 2 no’s are Electric motor drive Compressor.


a) DCS: Honeywell make TPS System installed in SIH #2, SIH # 10 Extension &

CCR. GUS Operating stations installed in SIH & CCR.


10 & CCR.

c) FSC System: Honeywell make FSC System installed in SIH # 10


a) C-03-01 A, B, C, D, E, F & G – Compressor – Interlock Control

b) 03-ROV-1000 – C-03-01A – Suction Interlock.

c) 03-ROV-1001 – C-03-01A – Discharge Interlock.

d) 03-ROV-1002 – C-03-01A – Vent Interlock.



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e) 03-ROV-1003 – C-03-01B – Suction Interlock.

f) 03-ROV-1004 – C-03-01B – Discharge Interlock.

g) 03-ROV-1005 – C-03-01B – Vent Interlock.

h) 03-ROV-1006 – C-03-01C – Suction Interlock.

i) 03-ROV-1007 – C-03-01C – Discharge Interlock.

j) 03-ROV-1008 – C-03-01C – Vent Interlock.

k) 03-ROV-1009 – C-03-01D – Suction Interlock.

l) 03-ROV-1010 – C-03-01D – Discharge Interlock.

m) 03-ROV-1011 – C-03-01D – Vent Interlock.

n) 03-ROV-1012 – C-03-01E – Suction Interlock.

o) 03-ROV-1013 – C-03-01E – Discharge Interlock.

p) 03-ROV-1014 – C-03-01E – Vent Interlock.

q) 03-ROV-1015 – C-03-01F – Suction Interlock.

r) 03-ROV-1016 – C-03-01F – Discharge Interlock.

s) 03-ROV-1017 – C-03-01F – Vent Interlock.

t) 03-ROV-1018 – C-03-01G – Suction Interlock

u) 03-ROV-1019 – C-03-01G – Discharge Interlock

v) 22. 03-ROV-1020 – C-03-01G - Vent Interlock



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SL. # CATEGORY MAKE QTY REMARKS

1 SP.GR. ANALYZER YOKOGAWA-GD40T 1

2 FT - 50 FT 50 PANEL 5

3 CONTROL VALVE FISHER / MASONEILAN / TYCO /

BETTIS 76

4 CONTROLLER FOXBORO / TAYLOR 3



7 FLOW SWITCH LUBRIQUIP / LUBE SENTRY / GRACO 11


9 LEVEL SWITCH MAGNETROL / MOORE / SOR /

JERGUSON / INTRA AUTOMATION 16

10 LOCAL INDICATOR ITT BARTON / BROOKS / KROHNE /

WISE / AMETEK 69

11 PRESSURE GAUGE ASHCROFT / WIKA / WISE / GENERAL

/ AM GAUGE 236

12 PRESSURE SWITCH UE / ASHCROFT / SOR / DELTA

CONTROL 69


14 TEMPERATURE

SWITCH UE 34


TC LTD 95


HONEYWELL / ABB / FOXBORO / SMAR

61




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4.0 UNIT - 04 OVERVIEW (Sulphur Recovery Unit)


4.1.1 Objective

This unit recovers elemental sulfur from Acid Gases containing H2S generated in

upstream treating units. The process adopted in these units is called Modified Claus

Process.

4.1.2 Capacity

The original design capacity of unit 04 is 600 LT/D. but under normal operation, sulfur

production is 430-460 LT/D. However, after implementation of Oxygen Enrichment

Project in 2004, the capacity of the unit increased to 665 LT/D of sulfur product (700

LT/D of sulfur feed) but not operated under Oxygen enrichment mode.


Refer Tables 1&2 below

a) Table-1: Original Design : Material Balance

MMSCFD LT/D TYPICAL QUALITY

FEED :

Acid Gas 19.2 768 H2S : 81.2 Vol. % CO2 : 11.0 Vol. % HC : 1.4 Vol. % H2O : 6.4 Vol. %

Combustion Air 42.1 1513

2281

PRODUCTS :

Sulfur - 598 99.5 % wt. Pure Liquid Tail Gas 53.4 1683

2281



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b) Table-2: Oxygen Enrichment Case: Material Balance

LT/D

FEED :

Acid Gas 1200.0 SWS Off Gas 26.8

Air 629.0

Oxygen 218.0

2073.8

PRODUCTS :

Sulfur 665.0

Tail Gas 1408.8

2073.8

MMSCFD

28.2

47.3

1.3

18.8

5.8

-

4.1.4 Process Description – Original Design Unit-04

Refer Sketch-1

4.1.4.1 Original Design Unit-04

Acid gas from upstream treating units is mixed with air and burned in the reaction furnace

(H-04-01). The gas product emerges from the furnace at about 2100oF and passes

through a Waste Heat Boiler (B-04-01), producing 475 psig steam. After leaving the

boiler, the sulfur laden gas enters the first condenser (E-04-01) where sulfur is

condensed and routed to a sulfur sump.

The gas leaving the first condenser is reheated in the first reheater, BR-04-02, by burning

a slip of acid gas feed to reactor inlet temperature of 450oF. Then, reheater effluent gas

passes through the first catalytic reactor (V-04-04) where additional sulfur is formed. The

Sulfur formed in the reactor is removed on the second condenser (E-04-02) and routed to

sulfur sump. The gas is again reheated in the second reheater (BR-04-03) and passed

through a second catalytic reactor (V-04-05) for further conversion to elemental sulfur

which is removed in the third condenser (E-04-03). The overall sulfur recovery is ranging

from 92% to 96%. After leaving the third condenser, the tail gas containing traces of H2S

and other sulfur species is sent to Tail Gas Treating Unit (Unit-75) for further recovery of

sulfur. In case of emergency or Unit-75 Shutdown, the tail gas is then routed to either the

new or old incinerator.

The sulfur from Waste Heat Boiler and all condensers is routed to the sulfur sump where

it is kept molten by steam coils. The molten sulfur is then transferred to Sulfur Degassing



27

Facility (SDF) where dissolved H2S is removed from the sulfur before transferring it to

liquid Sulfur storage tanks. From the tanks, it is pumped to Sulfur Flaking Facilities in

Mina Al-Ahmadi refinery for producing solid sulfur.

Note that in Unit-04, 475 psig steam is produced in Waste Heat Boiler and 50 psig steam

in the three condensers.

4.1.4.2 Oxygen Enrichment Project

This project was implemented in 2004. In this project, Unit-04 was modified to increase

its capacity to 665 LT/D sulfur product (700 LT/D sulfur feed), under Oxygen mode. The

project is based on the use of Oxygen enriched air (instead of plain air) to achieve this

increase in capacity.

The main changes involved are the change modification of the Reaction Furnaces to be

able to use both air and Oxygen enriched air and the change of Waste Heat Boilers to

produce 475 psig steam .Also, additional K.O. drum is provided for SWS gas. New tail

gas feedback controller is provided for better adjustment of Air/Acid gas ratio. A layer of

Titania catalyst at the bottom of first reactor and a layer of Oxygen scavenging catalyst at

the top of the second reactor are used.

Process sketch – 2 shows the process flow diagram for Unit-04 after implementation of

Oxygen Enrichment Project.



28

4.1.5 Brief History

Unit 04 is revamped in the year 2004.






1 Waste heat Boiler 01

2 Heat Exchanger 08

3 Furnace 01

4 Vessels / Tank / drum 13

5 Filter 07

6 Burner 04

7 Stack 01

8 Silencers, Ejectors & Coolers 08



29


Unit 04 Unit recovers elemental sulfur from acid gases containing H2S generated in

upstream treating units.

All Rotating equipment in Unit 04 are inspected and maintained as per the guidelines of



plant.

Unit 04 has 11 Pumps & 1 Blower. List of Rotating Equipment are furnished vide

Appendix 2A hereof.

Pump/Blower package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals,

Clutches, Couplings, Piping items etc.) are not included in the list. Bidders can collect






of power to the Unit is aided from Substation 02 which is located north side of the Unit.


employing pressurized / Air conditioned systems. Substation has 3 nos 6.6 KV

Switchgears (2A, 2B & 2C) fed from SS1A & SS1B (ref. drawing # R-00- 6012), 4 nos. of

440V MCC (MCC-2A, MCC-2B, MCC-2C & MCC-2D), 4 nos. of power transformers

(1MVA, 6.6kV/440V) and an emergency distribution panel (EDB-32-01). The HT

Switchgear section 2A was replaced completely with latest new ABB panels during

GRTA-2011 under contract CS/1955. The Substation 2 will be retained post SHU. The


installed under contract CB/CSPD/2004 & commissioned on 2016. Battery Charger along

with Battery backup bank are also available.



280HP, as LT motor. Unit -04 has a 6.6KV motor and 7 nos. 440V motors. All motors are

under Preventive Maintenance program by maintenance department.





The Unit-04 is powered from the retained Substation # 02.



30


Sulfur is recovered from the gas streams containing Hydrogen Sulphide (H2S) using “Modified Claus Processes” in the Sulfur Recovery Unit – 04. In this process 1/3rd of H2S in the gas stream is burnt with air in the reaction furnace to form SO2. The resulting SO2 then burns with balance H2S to form elemental Sulfur (S) and water in the Vapour Phase.


a) DCS: Honeywell make TPS System installed in SIH #8A & GUS Operating

stations installed in CCR.

b) ESD System: Honeywell make Safety Manager System installed in SIH # 8A &

CCR.


a) SWS / Acid gas feed to unit Pressure Control & Interlock.

b) Engine Fuel gas / combustion Air to start up burner Ratio Control & Interlock.

c) Engine Fuel Gas / Combustion Air to Main Burner Ratio Control & Interlock.

d) Trim Air to Reaction furnace Flow Control.

e) 1st Reheat Burner Interlock & Control.

f) 2nd Reheat Burner Interlock & Control.

g) Incineration Interlock & Temp Control.

h) Waste Heat Boiler Interlock & Control.


SR. # CATEGORY MAKE QTY REMARKS

1 ANALYZER ROSEMOUNT / AMETEK 4

2 CONTROL VALVE FISHER / MASONEILAN / HOPKINSON UK/

Virgo/Rotork 37

3 CONTROLLER FOXBORO / YOKOGAWA / MASONEILAN 4




7 LEVEL SWITCH MAGNETROL / MOORE / SOR / 5

8 LOCAL INDICATOR ITT BARTON / BROOKS / KROHNE / WISE

/ AMETEK 70


AM GAUGE 127

10 PRESSURE SWITCH UE / ASHCROFT / SOR 10


12 THERMOWELL THERMO ELECTRIC / TECNOMATIC / TC

LTD 59






31

5.0 UNIT - 05 OVERVIEW (Catalytic Reformer Unit)


5.1.1 Objective

The Catalytic Reformer is designed to up-grade Naphtha containing low Octane Paraffin

and Naphthenes to high Octane Motor Gasoline blending component. The best

hydrocarbon fuels for internal combustion engines are iso-Paraffines and Aromatics

which have high Octane Number. The Catalytic Reforming converts the low octane

hydrocarbon components to high octane hydrocarbons.

5.1.2 Capacity

The design capacity of the Unit is 15820 BPD producing about 12300 BPD of Reformate

with Octane Number of 96 (clear).


Refer Tables 1 & 2 below.

a) Table-1 - Material balance

BPSD % VOL. SOURCE / DESTINATION

Feed 15000 100 From Unit 10

Products

Reformate 12000 80.00% To storage

Total Liquid Product 12000 80.00%

b) Table-2 – Feed and Product Qualities

Gravity API 59.20 48.40 Sulfur PPM / % wt. < 1.0 < 1.0 Dist. Range , Deg. F EP 328 96 - 370

PONA : Paraffins 60.5 38.7 Olefins 0.0 1.1 Naphthenes 31.1 0.3 Aromatics 8.4 59.9

PRODUCTS

REFORMATESPEC. FEED



32

5.1.4 Process Descriptions

The Unit consists of three Reactors (containing Platinum catalyst), Fired Heaters,

Hydrogen recycle system with gas drier and product debutanizing facilities.

The hydrotreated Naphtha charge from Naphtha Unifiner (Unit-10) is combined with a

hydrogen rich recycle stream and passes through Feed Effluent Heat Exchangers,

Heaters and then first of the three Reactors in series (V-05-01/02/03) at about 930oF and

350 psig. There is intermediate Coil heaters (H-05-01 Coil# 2 & #) for outlet streams of

the first and second Reactors (combined together as Heater H-05-01, Coil 1,2,&3) which

provides the necessary heat and reheat between reaction stages. This set up is due to

the endothermic nature of reaction Naphthenes to Aromatic products and to a lesser

degree of dehydrocyclization of paraffins to aromatic ends that brings down temperature

of reacting stream. This requires reheating of the Reactor feed so as to have the highest

conversion possible.

Reactor effluent is cooled in feed Reactor effluent Heat Exchanger followed by Fin

fan/water trim coolers. It is separated into a liquid product and a hydrogen rich gas in this

product separator. Most of the gas is used as a recycle. The excess gas produced during

reforming reaction is used as a Hydrogen make-up gas to the Naphtha Unifiners,

bleeding off gas as needed to maintain pressure.

The liquid product from the Reactor effluent is stabilized in the Debutanizer Tower, where

light components (C1, C2, C3) are removed as overhead. This overhead gas is sent

directly to the Refinery Fuel Gas System. Condensed liquid from the Debutanizer

overhead is returned to the Column as reflux. The Debutanizer bottom product after heat

exchange with the Debutanizer feed, is cooled and sent to Reformate Storage Tanks for

MOGAS blending.

The process scheme is shown in the attached Sketch SK-1.



33






1 Exchangers 19

2 Air coolers 02

3 Heater 01

4 Reactors 03

5 Vessels / Tanks 12

6 Filters 06

7 Ejectors 02

8 PSVs 26



34


Unit 05 – The Catalytic reformer is designed to upgrade Naphtha containing low octane

paraffin and Naphthenic to high-octane Motor Gasoline blending hydrocarbons.

All the Rotating equipment in unit-05 are inspected and maintained as per the guidelines



plant.

Unit 05 has 9 Pumps, 20 Fin fans, 1 compressor & 1 Turbine. List of Rotating Equipment

are furnished vide Appendix 2A hereof.






Unit-05 is considered as classified area (Class 1 Div. 2 Group D) as per Shuaiba Refinery


to the Unit is aided from Substation 5A which is located south side of the Unit. The

substation is Building with Basement Type & facilitated as non-classified area by

employing pressurized / Air conditioned systems. Substation has a “6.6kV” Switchgears

fed from SS1A & SS1B (ref. drawing # R-00-6012), 3 nos. of “440V” MCC (MCC-A, MCC-

B & MCC-C), 3 nos. of power transformers (1MVA, 6.6kV/440V) and an Emergency

panel. The “6.6kV” Switchgear was replaced completely with latest new ABB panels

during GRTA-2011 under contract CS/1955. The Substation is equipped with Fire

Detection, Alarm & Suppression system which was installed under contract






department.





The Unit-05 is powered from the Substation # 5A and the Single Line Diagram (SLD) for

SS # 5A is as follows (for details Refer Annexure-01, KNPC Sketch # SK-2434 Sheet 02

of 08);



35




Catalytic reforming process enables production of High Octane gasoline from Naptha.

Unit – 05 processes unified Naptha at high temperature in presence of Catalyst and

convert into gasoline having higher Octane Components.


a) DCS SYSTEM: Honeywell make TPS System installed in SIH # 5, SIH # 10. GUS

operating Stations in CCR

b) ESD SYSTEM: Honeywell make Safety Manager System installed in SIH # 5, SIH

# 10 & CCR.


a) Unit – 05 Feed Flow Meter.

b) Reactions V-05-01/02/03 temperature control.

c) V-05-04 product separator Level & Pressure Control.

d) Recycle gas compressor C-05-01 Interlock.

e) Feed Pump P-05-01 Interlock.



36



1 O2 & H2 ANALYZER ROSEMOUNT-3081FG / ABB-PGC VISTA

2000 4

2 ANNUNCIATOR PANEL 1

3 CONTROL VALVE MASONEILAN / ELLIOT-FISHER UK 19

4 CONTROLLER FOXBORO 2

5 DISPLACER LT MASONEILAN 4


7 LEVEL GAUGE GLASS JERGUSON / K-TEK 12

8 LEVEL SWITCH MAGNETROL / SOR 4


/ AMETEK 35


AM GAUGE 143



13 TEMPERATURE

SWITCH UE 1


LTD 63



16 MISC HONEYWELL 3



37

6.0 UNIT – 06 OVERVIEW (Crude & Vacuum Unit)


6.1.1 Objective

Crude and Vacuum Unit is the primary Crude Fractionation Unit which processes Kuwait

Export Crude and produces distillates such as Unstabilized Naphtha. Kerosene, light &

heavy Diesel, Vacuum Gas Oil and Residue for further processing in downstream

Processing Units.

The Unit also includes a Foul Water Treating System to treat the Refinery foul water

streams.

6.1.2 Capacity

The Unit is designed to process 180,000 BPSD of Kuwait Export Crude Oil. It, however,

normally operates at 200,000 BPD.


Refer Tables 1, 2 & 3 for Material balance, Feed & Product Quality


SECTION FEED BPSD PRODUCTS BPSD

Atmospheric & Crude 200000 Naphtha 57000 Pre-Flash Towers Kerosene 28000

Lt. Diesel 15000 Atmos. Bottom 97000

Vacuum Tower Atmospheric 97000 Vac. Hy. Diesel 16000 Bottoms Vac. Hy. Gas Oil 30000

Vac. Bottoms 50000

Note: Excludes Gas & Loss

b) Table-2: Typical Feed & Product Quality - Atmospheric Section

SPEC. FEED

Preflash Naphtha Atm. Naphtha Kerosene Lt. Diesel

Gravity API 29.4-30.5 -- -- -- -- Sulfur Content wt.% 2.50% -- -- -- -- Salt Content 4 PTB -- -- -- -- End Point , Deg. F -- 450 450 570 740 Flash Point , Deg. F -- -- -- 150 -- Recovery @ 975 Deg. F

DESTINATION U-09 U-09 U-11/13/17&FO U-12/13/GO

PRODUCTS



38

c) Table-3: Typical Product quality-Vacuum Section

SPEC.

Hy. Diesel VGO Vac. Btms

Gravity API -- -- --

Sulfur Content wt.% -- -- --

Salt Content -- -- --

End Point , Deg. F 740 -- --

Flash Point , Deg. F -- -- --

Recovery @ 975 Deg. F 90% 12%

DESTINATION U-12/13&68 U-68 U-07 & FO

PRODUCTS


6.1.4.1 Preheat Train & Pre-flash Section

This simplified process sketch is indicated in the attached Sketch 1

The Crude Oil received from CrudeTank through booster pumps is pumped by charge

pumps and preheated in parallel trains of preheat Exchangers with hot intermediate

streams and products. A small quantity of water and demulsifier chemical are added

before preheating. The hot crude is mixed with wash water and fed to the Desalters to

reduce its salt content by electric desalting process. A water phase containing most of the

salts is separated out.

The desalted crude is dosed with NaOH (Caustic Soda) solution to avoid formation of the

free HCl acid in towers. It is pumped and further heated through two parallel trains of

Heat Exchangers and fed to Pre-flash Tower, V-06-17. The Pre-flash Tower Overhead

vapors are cooled by exchanging heat with Crude, condensed in Fin Fan Coolers and

routed to Overheads Drum, V-06-18. Part of liquid Naphtha from Overhead Drum is used

as reflux. The Naphtha vapors and liquid from Accumulator are sent to Naphtha

fractionation Unit, U-09. The crude from the bottom of Preflash Tower is pumped through

heat exchangers receiving heat from Vacuum Tower bottoms product and subsequently

to Atmospheric Heaters, H-06-01/03 operating in parallel.

6.1.4.2 Atmospheric Section

Preflashed Crude is heated and partially vaporized in the fired heaters before entering

the Atmospheric Tower, V-06-01. Superheated stripping steam is introduced at the

bottom.

The Tower overhead vapors are cooled by exchanging heat with Crude Oil, condensed in

Fin Fan Coolers and routed to overhead product drum, V-06-05. Overhead gases from

the drum are compressed and sent to Unit-09 along with Preflash Naphtha gas. Naphtha



39

is separated from condensed water. A part of this Naphtha is pumped to tower top as

reflux and balance is sent to Unit-09 along with Preflash Tower Naphtha and gases.

Kerosene and Light Diesel cuts are taken as side streams from the Atm. Tower and

steam stripped in side strippers, V-06-02/03. These Kero/LD product streams exchange

heat with Crude Oil feed in Crude preheat Trains and are finally cooled in Fin Fan

Coolers and Trim Water Coolers and sent to storage. Superheated stripping steam is

introduced to V-06-02/03 for flash point and IBP Control. Atmospheric Tower bottoms

(Reduced Crude) is heated in Heaters H-06-02/04 for Vacuum Tower feed.

6.1.4.3 Vacuum Section

The reduced crude from Vacuum Heaters enters the flash zone of Vacuum Tower, V-06-

04. The column operates under vacuum by means of Steam-jet Ejectors & Condenser

system to achieve required separation between heavy components at lower temperature.

From O/H, the un-condensed Sour Gas is compressed using C-06-03 and sent to Gas

Treating Unit (U-14). Condensed water is routed to Desalter feed water surge drum, V-

06-08.

The tower bottom section is equipped with a vacuum residue quench to control the tower

bottom temperature to avoid coke formation. Superheated stripping steam is used at

vacuum tower bottom to maximize distillate recovery.

The Heavy Diesel product, drawn as a side stream, exchange heat with Crude Oil in

preheat train. It is partly used as top/intermediate reflux to the Column as cold recycle

and hot recycle and the balance is sent to storage after cooling.

The Vacuum Gas Oil cut, drawn as lower side stream, is steam stripped in Stripper V-06-

07, routed through Crude Preheat Train and cooled in Fin Fan Coolers before sending to

off-site storage tanks. A part of the vacuum gas oil is recycled back to vacuum tower as

wash oil.

The bottom product, Vacuum Residue exchanges heat with Pre-flash Tower Bottom in

the Crude Preheat Train before being sent to H-Oil unit.

Inhibitor and 3% Ammonia solution is injected into all three Towers Overhead System to

control pH and corrosion

All of the four Heaters in the Unit are provided with steam-air decoking facilities.

6.1.5 Brief History

Commissioned in Year 1968 with 95,000 BPD

Revamped in year 1978 with preflash tower & additional heaters

Desalters revamped in year 2001 to handle higher salt levels up to 10 PTB

As part of safety enhancement ROIV’s provided & Heater safety upgradation done

by providing safety interlocks



40







2 Air Coolers 07

3 Vessels, Columns, Tanks and Drums 24

4 Heaters 04

5 PSVs 79



41


Crude and Vacuum unit is the primary crude fractionation unit, which processes Crude

and produces distillates…




plant.

Unit 06 has 78 Pumps, 88 Finfans, 2 Compressors, 5 Turbines. List of Rotating


In Many Critical pumps (P-06-01A/B/C/D, 02 A/B, 03A/B, 04 A/B, 06, 08 A/B/C/D, 10 D,

13A,14A/B, 15A/B, 16,17 A/B, 18 A/B, 19 A/B, 21 A/B, 29, 35 A/B,36 A/B/C, 38A/B,

45A/B) Gland packings converted to mechanical seals to the spirit of API 682 (in 2011) to

prevent the gas leakage to environment.

Pump/Compressor/Turbine package auxiliary items (filters, SO/LO Coolers, Gear boxes,



records during Site visit.




of power to the Unit is aided from Substation 07 which is located inside the Unit. The

substation is facilitated as safe area by employing pressurized / Air conditioned system.

Substation has 3 nos. of HT Switchgear “6.6kV” (7A, 7B & 7C), 5 nos. of LT MCC “440V”

(MCC-100, MCC-200, MCC-300, MCC-400 & MCC-500), 5 nos. of power transformers

(1MVA, 6.6kV/440V) and Emergency panel (EDB-06-01)along with Automatic Transfer

Switch as per Single Line Diagram enclosed. The HT Switchgear 7A & 7B were replaced

completely with latest new ABB panels during GRTA-2011 under contract CS/1955.

Upgradation of Obsolete Fire Detection, Alarm & Suppression system for the unit

including the phase out of Halon system was carried under contract CB/CSPD/2004 was

completed in 2016. Batteries, Battery Charger, & Air conditioning system are also

available.



280HP, as LT motor. Unit -06 has 20 nos. 6.6KV motors and 141 nos. 440V motors. All

motors are under Preventive Maintenance program by maintenance department. All open

type HT motors have been replaced over the years with closed type TEFC motors.



42

Other electrical equipment such as 6 nos of Desalter Power Transformers(150KVA,

440V/22KV), Light fixtures, Distribution Boards, junction Box, power sockets, push button

stations, , Fire Alarm detectors, Lighting transformers (25kVA 440/415V), above ground

cables, conduits etc. available in the Unit are not listed separately. Bidders can collect

relevant details during Site visit. Single Line Diagrams for Substation # 7 as follows:



of 08);





43


Crude Unit Operations involves Controlling Parameters such as Flow, Level,

Temperature and Pressure. The DCS system provided monitors the above parameters

and provide basic regulatory control.

The field Instruments provided to measure the Process Parameter are SMART (Single

Module Addressable Rangeable transducer) which are state of art Microprocessor based

Electronic Instruments and connected to the DCS system.

The Control Valves in the field are the latest type valves from reputed Manufacturer like

Masoneilan, Fisher, Honeywell etc. The Valves are provided with Electronic Smart

(Digital) Positioners with diagnostic features.

Oxygen Analyzers are provided in the Heater stack to monitor the efficient operation of

the Heaters. Also, PH Analyzers are provided to monitor the PH of condensate,

The RIOVs installed in the plant are Emergency Block valves used to isolate critical

equipments to control the Hazardous situation. The RIOVs are operable from GUS

station in CCR. The ROIVs are also provided with “Partial Stroke Testing” (PST) facility to

check the functionality of the shutdown valve during unit in operation.

ESD system (Safety Manager of Honeywell make) provides Safety Interlock Control for

the unit. List of some critical interlocks are as follows:

a) C-06-01 – Atmospheric Gas Compressor Control.

b) C-06-03 – Sour Gas compressor Control

c) Desalter Interlock.



44

d) Heater H-06-01, H-06-02, H-06-03 & H-06-04 Interlock Control.


SUMMARY OF UNIT-06 INSTRUMENT LIST

SR. # DEVICE MAKE QTY REMARKS

1 CONTROL VALVE/ ROV FISHER/ MASONEILAN/ HONEYWELL/ SAMSON GERMANY/ TYCO/ VIRGO

148

2 TRANSMITTER ROSEMOUNT/ YOKOGAWA/ HONEYWELL/ ABB/ FOXBORO/ SMAR

246

3 DISPLACER LT MASONEILAN/ MAGNETROL 22

4 FLOW ELEMENT DALIEL / SAMIL 146

5 LEVEL GAUGE GLASS JERGUSON/ PENBERTHY/ K-TEK 47

6 LOCAL CONTROLLER FOXBORO/ YOKOGAWA/ TAYLOR/ MASONEILAN

7

7 LEVEL SWITCH MAGNETROL/ MOORE/ SOR/ JERGUSON/ INTRA AUTOMATION

19

8 PRESSURE SWITCH UE/ ASHCROFT/ SOR/ DELTA CONTROL 61

9 THERMOWELL THERMO ELECTRIC/ TECNOMATIC/ TC LTD

287

10 LOCAL INDICATOR ITT BARTON/ BROOKS/ KROHNE/ WISE/ AMETEK

39

11 SOLENOID VALVES ASCO 61

12 PRESSURE GAUGE ASHCROFT/ WIKA/ WISE/ GENERAL/ AM. GAUGE

249

13 FIXED GAS DETECTOR HONEYWELL 8

14 JUNCTION BOX 20

15 ANALYZER (OXYGEN, PH) ROSEMOUNT/ YOKOGAWA/ AMETEK/ SERVOMAX

12

16 VIBRATION MONITER 3300 BENTLY SYSTEM 1

17 LIMIT SWITCH/ PROXIMETER (MISC)

HONEYWELL 86



45

7.0 UNIT – 06F OVERVIEW (Foul Water Treating Unit)


7.1.1 Objective

This unit can be run as a Concentrator for foul water from various units to generate Unit-

15 feed or independently as a stripper producing overhead gas only for flaring.

7.1.2 Capacity

The unit designed to process 350 GPM foul water.


All the Refinery foul water streams are combined, cooled with cooling water in E-15-19

A/B, degassed to flare in V-15-18 and pumped to Tank for storage. In the tank, oil and

sludge separate from water and are skimmed periodically to Slop Oil System.

From Tank TK-482, foul water is pumped by P-34-23/22S thru Heat Exchanger, E-06-34

to Foul Water Stripper V-06-09 located in Unit-06. Superheated steam is introduced at

the bottom of Tower for stripping H2S and NH3 from the foul water.

The overhead gases are cooled/condensed in air Fin Cooler E-06-27. Non-condensable

gases are routed to the flare header through overhead Accumulator,V-06-20. The

condensed NH3/H2S concentrate is sent to Unit-15 Degasser, V-15-19 for further

processing in Unit-15 or is returned to the column as total reflux.

The hot stripped water from the column bottom is pumped by P-06-21A/B through cold

feed exchanger E-06-34. This stripped water, meeting Effluent water specification for

NH3/H2S, is routed to the sea water pit for discharge with Refinery effluent water. A part

of this Water is reused in Unit-06 Desalter water system through V-06-08 (refer Fig. SK-

100-06-B). The stripped water can also be recycled to the feed tank during start-up or if

the stripped water NH3/H2S/Oil contents are high.



46



the summary of the Static Equipment for Unit-06F is listed as follows; List of Static




2 Air Coolers 02

3 Vessels, Columns, Tanks and Drums 04

4 PSVs 03



47

8.0 UNIT – 07A/B OVERVIEW (H-Oil Train A/B)


8.1.1 Objective

The purpose of the Unit is to upgrade the Crude residual stocks (bottoms of Crude Unit

Vacuum Distillation section) by catalytic hydrocracking process in the presence of

hydrogen and obtain valuable distillate products.

These distillate products are separated as side streams from the Fractionation Tower as

Naphtha, Kerosene and Light Diesel.

The heavy products from Reaction Section and Fractionator Tower Btm are mixed and

further separated in a vacuum distillation tower to produce Heavy Diesel, LVGO, HVGO,

and Vacuum Bottom Residue (Fuel Oil).

8.1.2 Capacity

The H-Oil Unit consists of two parallel Reactor Trains followed by common Fractionation

Section. Each 07 Train was originally designed to Process 36,000 BPD of mixed Feed

(14,400 BPSD Fresh feed ,9.3 Deg. API Crude Vacuum Bottom + 21,600 BPD of

Str./Frac.Btm Recycle).

Since commissioning, the Unit operating mode has been modified to suit the prevailing

refinery operating pattern. Now, up to 25,000 BPSD of Vacuum bottoms is being

processed in each Train.


Refer Table-1 below

a) Table-1: Material Balance

BPSD % VOL.

Feed

06 Vac. Btms 50000

HVGO Recycle 0

Slops 2000

Total Feed 52000 100

Products

Naphtha 3000 5.77 Kerosene 5000 9.62 Lt Diesel 3500 6.73 Frac./ Str. Bottoms 42000 80.8

Total Liquid Product 53500 102.885

To Unit 13 To Unit 63

SOURSE / DESTINATION

From Unit 06

From Unit 63

From TK-477/478/479/342

To Unit 11 To Unit 11



48


Refer to Sketch -1 below

8.1.4.1 Reaction Section

The fresh feed, Crude Unit Vacuum Bottoms is received in Feed Drum, V-33. Heavy

vacuum gas oil from U-63 can be taken as diluent up to about 8%, if needed. The

combined streams from feed Surge Drum V-07-33 are pumped to feed Heater H-07-01

and then mixed with high pressure recycle hydrogen gas (80-82% Vol. Purity preheated

in Heater H-07-02) in mixers. Mixer outlet at about 730oF and 2450 psig is fed to H-Oil

Reactor V-07-01. Within the reactors, the charge oil is cracked at elevated temperature

(820oF) and high hydrogen pressure in the presence of catalyst.

The H-Oil reaction takes place in an ebullated bed of catalyst (NiMo Type). Pump P-07-

02 drawing suction form reactor top level maintains a circulation to keep the catalyst

particles in continuous ebullition and near isothermal reaction conditions. The catalyst

level is monitored by a radioactive source (Ohmart Detectors). Some spent catalyst is

withdrawn at regular intervals (daily) and replenished by loading fresh catalyst to maintain

required catalyst activity. Catalyst consumption is about 90 Tons/Month for both Trains

A/B.

The Reactor effluent flows as a vapor-liquid mixture into Separator, V-07-02. The vapor

is a Hydrogen rich stream containing lighter hydrocarbon reaction products. The liquid is

composed essentially of heavier hydrocarbon products, unconverted charge oil and

appreciable amounts of dissolved Hydrogen and light ends.

The flash vapor leaving V-07-02A is cooled with light distillate in Exchanger E-07-02A

and total hydrogen in Exchanger E-07-01A. Cooled vapor effluent is then fed to Primary

Distillate Knockout drum, V-07-03A for removal of condensed liquid. Vapor from V-07-

03A is further cooled to about 140oF in an Air Cooler E-07-03A and enters Distillate

Separator Drum, V-07-04A. The Hydrogen rich gas which upon leaving the separator V-

07-04A, splits into two streams. The larger of the two streams is compressed to

approximately 2500 psig in Recycle Gas Compressor C-07-01A and returned to H-Oil

reactor, as Hydrogen recycle. The smaller purge gas stream, combined with an identical

stream from “B” train is sent to the Unifiners through vessel V-07-11.

Condensed liquid from V-07-03A joins with reactor effluent liquid from V-07-02A and

flashed to remove hydrogen and low molecular weight hydrocarbons in three successive

stages. The first stage let down to 1050 psig is in V-07-07A. The resulting Hydrogen rich

vapor is cooled with light distillate in exchanger, E-07-05A and then with cooling water to

approximately 110oF, in E-07-06A. This cooled stream is flashed again in Flash Gas

Drum V-07-16A.



49

The vapor from V-07-16A are let down to a pressure of about 550 psig and joins the High

Pressure Flash Gas from V-07-05A. The liquid (from V-07-16A) is further let down to a

pressure of 550 psig in High Pressure Flash Gas Drum V-07-05A.

Water wash is injected upstream of E-07-03A (about 75 gpm) and E-07-06A (about 10

gpm) to avoid ammonium bisulfide deposits. The Ammonical water from V-07-04A and

V-07-05A are returned to Ammonical Water Treating Unit (Unit-15).

The second stage let down to about 550 psig occurs in High Pressure Temperature Flash

Drum V-07-14A. Vapor from this flash is cooled with light distillate in Exchanger, E-07-

12A and cooling water in E-07-18A. It is fed to Flash drum V-07-05A, in addition to high

pressure condensate from V-07-04A and V-07-16A along with corresponding streams

from Train “B” are sent to Unit-14.

The final let down occurs at 75 psig in the flash drum situated above Steam Stripper V-

07-09A. The resulting vapor is cooled through Light Distillate Exchanger, E-07-19A to

300 oF and then in Water Cooler E-07-21A to 120oF, before it is fed to Low Pressure

Flash Drum V-07-06A at about 30 Psig along with condensate from V-07-05A. The Low

Pressure Flash Gas from V-07-06A along with that from Train-B is sent to Unit-14.

The light distillate from V-07-06A is pumped by P-07-03A, through Exchangers E-07-19A,

E-07-12A, E-07-05A, and E-07-02A and is preheated to approximately 550-600oF. The

light distillate streams from both H-Oil Trains are then combined and fed to the common

Fractionator, V-07-10. Refinery Slop oil is injected in V-06 for reprocessing.

The hot flashed reactor liquid from V-07-09 flows in to the Stripper V-07-09A, where it is

steam stripped to remove the middle distillates. The stripper overhead streams from both

H-Oil trains are fed to Fractionator Tower V-07-10, along with the preheated light

distillates from V-07-06A&B. The Stripper bottoms stream is pumped by P-07-04A be

pumped to Unit 63 Feed Surge Drum, V-07-50. Alternatively, stripper bottoms can also

be pumped to Fuel Oil run down system.

8.1.4.2 Fractional Section

The Fractionator Tower V-07-10 feed consists of light and middle distillates from V-07-06

A/B and stripped gases from Strippers V-07-09 A/B. The Fractionator bottoms are

circulated through H-07-03 for additional heat input and further supplemented by heating

slops and fractionator bottoms through H-Oil Cold Feed Heater, H-07-04.

Fractionator overhead vapor is cooled and partially condensed in Air Cooler E-07-11

before going in Naphtha Accumulator Drum V-07-08. The vapor from V-07-08 is sent to

the Amine Treating Unit. The unstablized liquid Naphtha from V-07-08 is pumped by P-

07-31 & 31S to kerosene Unifiner charge tank TK-34-331. The separated water,

withdrawn from V-07-08 is sent to the Oily Water Condensate System.



50

From the fractionator a Kerosene cut is drawn to stripper V-07-12 and light components

removed by steam stripping. The raw kerosene stream is pumped by P-07-07, Cooled in

Air Cooler E-07-09, and sent to Kero Unifiner, U-11, feed tank.

A Light Diesel cut is fed to diesel side Stripper V-07-13, for removal of light ends by

steam stripping. The raw Light Diesel stream is pumped by P-07-06 and cooled in the Air

cooler E-07-08A/B before it is routed to Diesel Unifiner Charge tank.

A pump-around side stream is circulated near the top of the Fractionator Tower with P-

07-08A/S and Air Cooler E-07-10.A lower pump around is taken at the light diesel draw

off by Pumps P-07-05 A/S passing through Air Cooler E-07-07 to the Fractionator. The

Fractionator bottoms product is pumped by P-07-16/16S to Unit-63 Feed Surge Drum, V-

07-50.

8.1.5 Brief History

a) Fuel Oil cooling strings added in 1978

b) Part of the Unit damaged in fire incident in Year 2015.



51



the summary of the Static Equipment for Unit-07A/B is listed as follows; List of Static

Equipment with History are furnished vide Annexure – 01 hereof.


1 Exchangers 57

2 Air Coolers 09

3 Heaters 06

4 Reactors 04


6 PSVs 166


Unit 07 – This Unit is to upgrade the Crude residual stocks (bottoms of crude unit

vacuum distillation section) by catalytic hydrocracking process in the presence of

hydrogen and obtain more desirable middle distillate products.




plant.

Unit 07 has 80 Pumps, 56 Fin fans, 22 Turbines & 2 compressors. List of Rotating


Most of the Critical pumps packings converted to mechanical seals to the spirit of API

682 to prevent Gas leakage to environment.











Switchgears (6A & 6B) fed from SS1A & SS1B (ref. drawing # R-00-6012), 6 nos. of

“440V” MCC (MCC-6A & MCC-6B,MCC-07-600,1,2&3), 6 nos. of power transformers

(1MVA, 6.6kV/440V) and 4 nos. of Emergency panel (EM-PNL-A, EM-PNL-B, EM-PNL-C



52

& EM-PNL-D ) along with Automatic Transfer Switch as per Single Line Diagram

enclosed. The “6.6kV” Switchgears 6A & 6B were replaced completely with latest new

ABB panels during GRTA-2011 under contract CS/1955. The Substation is equipped with

Fire Detection, Alarm & Suppression system which was installed under contract



The list of HT & LT Motors associated with this Unit is enclosed vide Annexure - 03


280HP, as LT motor . Unit -07 has 2 nos. 6.6KV motors and 122 nos of 440V motors. All





separately. Bidders can collect relevant details during Site visit. Details of Electrical

Assets damaged during the Fire Incident in Aug. 2015 are available in SHU Archives for

Bidders reference.

The Unit-07A/07B is powered from the Substation # 06 and the Single Line Diagram

(SLD) for SS # 06 is as follows (for details Refer Annexure-01, KNPC Sketch # SK-2434

Sheet 04 of 08);





53


H-Oil Unit – Heavy Vacuum residue containing Sulfur, Nitrogen & Organic Mettalic

Compounds is Hydrocracked to middle distillates such as Naptha, Kerosene, Diesel &

Gas Oils at high pressure and temperature in presence of Catalyst.

8.5.1 Instrumentation System Unit-07A

a) DCS: Honeywell make TPS System installed in SIH # 4, SIH # 10 & CCR with

GUS operating Stations in CCR


10 & CCR.

8.5.2 Instrumentation System Unit-07B




10 & CCR.

8.5.3 Critical Safety Interlocks and Controls Unit-07A

a) Heater H-07-01A – Trip Interlock & Control.

b) Heater H-07-02A – Trip Interlock & Control

c) Feed Pump – P-07-01A – Trip Interlock.

d) Recycle Gas Compressor – C-07-01A – Trip Interlock & Control.

e) V-07-33A – Feed Surge drum level / pressure Control.



54

f) H-07-01A – Outlet Temperature Control.

g) V-07-01A, V-07-02A, V-07-03A & V-07-04A Pressure Control.

h) V-07-01A Catalyst Average Temperature Control.

i) V-07-01A – Catalyst bed Level Control.

8.5.4 Critical Safety Interlocks and Controls Unit-07B

a) Heater H-07-01B – Trip Interlock & Control.

b) Heater H-07-02B – Trip Interlock & Control

c) Feed Pump – P-07-01B – Trip Interlock.

d) Recycle Gas Compressor – C-07-01B – Trip Interlock & Control.

e) V-07-33B – Feed Surge drum level / pressure Control.

f) H-07-01B – Outlet Temperature Control.

g) V-07-01B, V-07-02B, V-07-03B & V-07-04B Pressure Control.

h) V-07-01B Catalyst Average Temperature Control.

i) V-07-01B – Catalyst bed Level Control.

8.5.5 Field Instrument List Unit-07A


1 02 ANALYZER YOKOGAWA-ZR 402T / ABB-ENDURRA

AZ30 3

2 CONTROL VALVE FISHER / MASONEILAN /

VIRGO /ROTORK 41

3 CONTROLLER FOXBORO / YOKOGAWA 3




7 LEVEL SWITCH MAGNETROL / MASONEILAN 8


AMETEK 70


GAUGE 76

10 PRESSURE SWITCH UE / E-CELLA / BOURDON SEDEME 29


12 TEMPERATURE SWITCH UE 9


LTD 113

14 TRANSMITTER ROSEMOUNT / YOKOGAWA / HONEYWELL

/ ABB / FOXBORO / SMAR 93




55

8.5.6 Field Instrument List Unit-07B

Details of Instrumentation Assets damaged during the Fire Incident in Aug. 2015 are available in SHU Archives for Bidders reference.


1 02 ANALYZER YOKOGAWA-ZR 402T 2


VIRGO /ROTORK 39





7 LEVEL SWITCH MAGNETROL / MASONEILAN 8


AMETEK 56


GAUGE 62




LTD 97






56

9.0 UNIT – 08 OVERVIEW (Isomax Unit)


9.1.1 Objective

To convert Heavy Gas Oil feed stocks into light higher value products like Naphtha,

Kerosene and Diesel by hydrocracking. Chemical reactions in Isomax Reactor are

essentially same as those in the Isocracker Unit-68 Reactor, i.e. De-sulfurization, De-

nitrification and cracking in the presence of hydrogen.

9.1.2 Capacity

Isomax Unit is designed for total feed of 36000 BPSD with 23000 BPSD of fresh feed. it

normally operates as a second stage to Isocracker Unit (68), to process U-68 Frac.

Bottom at a rate of about 23000 BPSD. Products are similar to U-68 products, i.e.

Naphtha, Kerosene (JP-5/ATK) and Low Sulfur Diesel.


Refer to Tables 1&2 below

The feed to the Unit is either fractionator bottoms from Unit-68 or fresh feed from tank,

comprising of heavy diesel & vacuum gas oil from Unit-06 and unifined heavy diesel from

Unit 13.



Feed 23000 100 From Unit -68 or Units 06/13

Products

Naphtha 8000 34.78 To Unit 10 / Storage JP-5 8500 36.96 To Storage High Pour Diesel 6500 28.26 To Storage Frac. Bottoms 1500 6.52 To Storage




57

b) Table-2: Typical Feed & Product Quality

PRODUCTS

Spec. Feed Naphtha JP - 5 H. Pour

Fract.

Btms.

Diesel

Gravity API 33 68.7 46.8 41.2 39

Sulfur PPM / % wt. 250 10-15 <10 <10 <10

Nitrogen, PPM <1.0 <1.0 <1.0 <1.0 <1.0

Dist. Range , Deg. F 570 - 960 98 - 350

350 -

570 520 - 720 550 - 950

Flash Point , Deg. F -- -- 150 210 > 230

Smoke Point , MM -- -- 36 -- --

Pour Point , Deg. F 90 -- -- 10 100

Freezing Point , Deg C -- -- -50 --

Nickel + Van. , PPM

Max. -- -- --

-- --

Fe + Na , PPM Max. -- -- -- -- --

Asphaltenes , PPM -- -- -- -- --

Polycyclic Index (PCI) 100-300 -- -- -- <50


Refer to attached Sketch -1

This Unit consists of the following two sections:

9.1.5.1 High Pressure Section

The Fractionator bottoms from the first stage (Unit-68) or fresh feed from the tank is

preheated in a Heat Exchanger. It combines with the recycle feed (Fract. Btm. and

passes through self-cleaning filters. The mixed feed is then pumped (to ~2800 psig) by

the feed pump. It mixes with the Recycle Gas from the Compressor before entering the

Feed – Reactor Effluent Exchangers. The mixture is further heated in Heater H-08-01

and enters the Reactor V-08-01, from the top. The make-up hydrogen, after heating in

Reactor Effluent Exchanger E-08-01, enters Rx bottom through annulus of the Reactor.

travels upwards and joins the reactor feed mixture at the top.

The Reactor consist of five catalyst beds (Hydrocracking catalyst) with provision for inter-

bed quenches of recycle gas to control the catalyst temperatures. Under high pressure

and temperature (~2400 psig & 730-780 F), the feed is hydrocracked. Effluent from

bottom of the reactor, is cooled through a series of Heat Exchangers and an Air Cooler to

about 140oF. It then enters the High Pressure Separator, V-08-02 where gases, liquid

hydrocarbons and water are separated. In order to combat corrosion caused by

H

i

g

h

P

o

u

r

D

i

e

s

e

l

F

r

a

c

t

.

B

o

t

t

o

m

s

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-



58

Hydrogen Sulfide and Ammonia, a small quantity of condensate / Ammonical water is

injected upstream of the Air Cooler.

Water from High Pressure Separator containing Ammonium Sulfides, goes to the

Ammonical Water Treating Unit for further treatment. Gaseous stream from High

Pressure Separator (mainly Hydrogen) is compressed by Recycle Gas Compressor. A

major part of Recy. Gas is sent back to the Reactor along with feed, while part is utilized

for Rx. inter-bed quenches. A small part is bled to the Unifiner Units to maintain the

Recycle Gas purity. Hydrocarbon liquid stream from H.P. Separator is let down to 550

psig in Low Pressure Separator V-08-04. Separated gases are routed to Amine Treating

Unit and liquid hydrocarbons are further let down to 150 psig in Flash Drum V-08-05.

9.1.5.2 Low Pressure Section

Gases from Flash Drum V-08-05 are routed to Amine Treating Unit. The hydrocarbon

liquid is pumped thru and preheated in Rx. Effluent Exchanger E-08-03 and further

heated in Heater H-08-02. It then enters a Fractionation Column V-08-06, called “Recycle

Splitter”. Tower overhead vapors are cooled/condensed in Fan Coolers and flow into

Reflux Drum V-08-07. From here Naphtha is pumped to the tower top as reflux. Excess

condensate and vapor is further cooled and flow into the Product Drum V-08-08.

Kerosene side cut flows to Stripper V-08-09, where heat supplied at bottom by Reboiler

E-08-07, improves the flash point to specification. Diesel side cut is stripped in V-08-14

with superheated stream. Both these products are cooled and sent to off-plot storage.

The Splitter bottom is recycled hot to the feed. A small part is cooled and sent to storage

(UCO) to maintain system cleanliness.



59

9.1.6 Brief History

a) Unit fresh feed rate was increased to 23000 BPD and Diesel Withdrawal was

introduced in the year 1974.

b) Unit 68 was commissioned in 1978 and thereafter Unit 08 was functioning as a

second stage Hydrocracker after revamp and designed to process 20900 BPD of

Unit 68 fractionator bottoms.

c) During Iraqi Invasion unit was damaged and restoration was carried out in 1994.

d) During the span of Operation, unit was upgraded with ROIVs and other safety

modifications as a result of HAZOP and Flare Adequacy studies.







60



2 Air Coolers 07


4 Heaters 02

5 Reactor 01

6 Filters 10

7 PSVs 45


In Shuaiaba Refinery Unit 08- Isocracker being used to upgrade heavy Gas Oil feed

stocks into higher value products like Naptha, Kerosene, Diesel by Hydrocracking.




plant.

Unit 08 has 29 Pumps, 67 Fin fans, 2 Compressors, 4 Turbines. List of Rotating


In 2007, C-08-01 Compressor/Turbine upgraded with latest technology Instrumentation &

Control system to monitor Vibrations, Temperature, Speed & Control system.

Many Critical pumps Gland packings converted to mechanical seals to the spirit of API

682 (in 2012) to prevent the gas leakage to environment.






Unit-08 is considered as classified area (Class 1 Div. 2 Group B) as per Shuaiba Refinery


to the Unit is aided from Substation 06 which is located south-east side of the Unit. The

substation is Building with Basement Type & facilitated as non-classified area by


Switchgears (6A & 6B) fed from SS1A & SS1B (ref. drawing # R-00-6012), 6 nos. of

“440V” MCC (MCC-6A & MCC-6B,MCC-07-600,1,2&3), 6 nos. of power transformers

(1MVA, 6.6kV/440V) and 4 nos. of Emergency panel (EM-PNL-A, EM-PNL-B, EM-PNL-C



61

& EM-PNL-D ) along with Automatic Transfer Switch as per Single Line Diagram

enclosed. The “6.6kV” Switchgears 6A & 6B were replaced completely with latest new

ABB panels during GRTA-2011 under contract CS/1955. The Substation is equipped with

Fire Detection, Alarm & Suppression system which was installed under contract





280HP, as LT motor . Unit -08 has 2 nos. 6.6KV motors and 93 nos. 440V motors. All








of 08);





62


Isomax Unit Processes Vacuum gas oil & Isocracker Fractionation bottoms. It produces

light gases, Naptha, kerosene, Diesel Products.


a) DCS: Honeywell make TPS System installed in SIH #3, SIH # 10 & GUS



10 & CCR.

c) FSC System: Honeywell make FSC system installed in SIH # 10 for ROIV

Controls.

d) List of ROIV’s in Isomax Unit

08-ROV-1000 C-08-01 Suction Line

08-ROV-1001 C-08-01 Discharge Line.

08-ROV-1002B P-08-04A Suction Line

08-ROV-1002B P-08-04B Suction Line

08-ROV-1003 P-08-11A/B Suction Line

e) Bently Vibration Monitoring System:

Bently Model 3500 Vibration and Temperature Monitoring & Trip Control for P-08-

01 feed pump to unit.

Bently model 3300 System for recycle gas compressor C-08-01



63

f) PLC System:

Modicon PLC System installed in Local for feed pump P-08-01A interlock

control.

Siemens Make PLC system for feed filter control.


a) C-08-01 - Recycle gas compressor Interlock

b) C-08-02 - Splitter Naptha Gas Compressor Interlock.

c) C-08-02 - Woodwar Governor for speed control of Turbine

d) P-08-01A & HPRT – Interlock Control

e) H-08-01 & H-08-02 – Heater Interlock Control



1 O2 ANALYZER AMETEK – WDG2000 2

2 CONTROL VALVE FISHER / MASONEILAN / HONEYWELL /

SAMSON GERMANY / TYCO / VIRGO 79


MASONEILAN 6




7 LEVEL SWITCH MAGNETROL / MOORE / SOR / JERGUSON /

INTRA AUTOMATION 23


AMETEK 94

9 PLC SIEMENS (MOD # S7-200) / MODICON

QUANTUN SERIES 5


GAUGE 158

11 PRESSURE SWITCH UE / ASHCROFT / SOR / DELTA CONTROL 47



LTD 158




16 VIBRATION BENTLY NEVADA SYSTEM – 3300 & 3500

SYSTEM 2



64

10.0 UNIT – 09 OVERVIEW (Naphtha Fractionator Unit)


10.1.1 Objective

Naphtha Fractionation Unit produces Naphtha as finished product and also prepares feed

stock for Naphtha Unifiners, Kero Unifiners and Merox unit by fractionation of full range

Naphtha from Crude Unit, Kero & Diesel Unifiners.It also provides circulating lean

Kerosene to Burgan Gas Unit-01 ( if required). Unit-09 also processes Refinery gas

streams recovering Butane & hexane hydrocarbons for absorption.

10.1.2 Capacity

The unit designed to process 65,000 BPD of Naphtha liquid and 17.5 MMSCFD of vapor.


Refer to Tables 1 below


BPSD

Feed

Naphtha Liquid 65,000

Naphtha Gas 22.7 MMSCFD

Rich Oil -

Products

Naphtha 41,500

Kero Product 23,500

Lean Oil to Unit-01 -

LP Gas to Unit-14 / 61 20 MMSCFD

SOURCE / DESTINATION

From Unit-06 / 11 / 12 / 13

From Unit-06 / 07 / 08 / 68 / Unifiners

From Unit-01 ( Currently not in use )

To Unit-10 / Storage

To Unit-17 / Storage

To Unit-01 ( Currently not in use )

To Unit - 14 / C-61-01


Naphtha liquid from Crude Unit, Kero and Diesel Unifiner and naphtha gases from Crude,

Isocracker, Iso-Max, Kero and Diesel Unifiners are all combined, cooled and received in

feed drum V-09-01 along with any gas condensate. The separated vapour joins L.P.

Flash gas streams from H-Oil & Iso-caraker Units, and is fed to L.P. Absorber V-09-06

where Heavy hydrocabons are recovered by absorption with lean Kerosene.

The liquid stream from V-09-01 joins Rich Kerosene stream from L.P. Absorber V-09-06,

then exchanges heat with splitter bottom stream in E-09-03. It is further heated by 150



65

Psig steam in E-09-16. This combined stream is satbilized by removal of butane and

lighter gas in Debutanizer (V-09-08). The overhead gas from V-09-08 joins the lean low

presssure gas from V-09-06 and goes either to Amine Treatment Unit-14 or to C-61-01.

The debutanizer product is fed directly to splitter (V-09-09) for fractionation into Naphtha

and Kerosene streams. A part of Naphtha product goes directly to Napntha Unifiner and

balance is trim cooled in E-09-12 and sent to the Naphtha stroage tank.

The bottom Kerosene stream after heat exchange with debutanizer feed in E-09-03, is

cooled in E-09-04 and part is routed to Kero Unifiner and partly to V-09-06 as lean oil.

In Feb 2011 new facility was commissioned to desulfurize Naphtha product .The facility

involve a fixed bed of ZnO installed in the redundant vessel V-17-05. A slip stream of

Naphtha product from U-09 is routed to this Zinc oxide bed where part of H2S in the

Naphtha is absorbed .Subsequently the treated Naphtha stream joins the rest of

Naphtha product routed to storage.

10.1.5 Brief History

Major debottlenecking to increase the capacity from 38.7 KBPD to 65 KBPD year 1974



66






1 Exchangers 17

2 Air Coolers 03

3 Vessels 10

4 Heaters 01

5 PSVs 16


Unit 09 – This Unit prepares Feedstock for Naphtha Kero Unifiners Merox Unit by

fractionation of full range of Naphtha from Crude unit, Kerosene and Diesel Unifiners &

recovering Butane and heavier hydrocarbons by absorption.




plant.

Unit 09 has 24 Pumps, 60 Fin fans, 1 steam turbine. List of Rotating Equipment are

furnished vide Appendix 2A hereof.


















67








280HP, as LT motor . Unit -09 has 5 nos of 6.6KV motors and 78 nos. 440V motors. All








of 08);





68



69


Unstabilized Naptha Vapor & Liquid streams provided in other units like 06, 07, 08, 68,

11, 12 & 13 are processed in Unit – 09 to produce stabilized Naptha and Kerosene

feedstock for Unifiners. Unit aslo supplies Lean oil to Burgan Gas Unit – 01 and feed to

Kerosene Merox Unit – 17.


a) DCS: Honeywell make TPS System installed in SIH # 7, SIH # 10 & GUS

operating Stations in CCR.


10 & CCR.

c) FSC System: Honeywell make FSC system for ROIV Control in unit.


a) 09-ROIV-1000, 09-ROIV-1001, 09-ROIV-1002, 09-ROIV-1003, 09-ROIV-1004, 09-

ROIV-1005, 09-ROIV-1006, and 09-ROIV-1007, interlock Control.

b) P-09-09A/B Interlock

c) P-09-014A/B – Naptha Splitter Pump Interlock.

d) H-09-01 – Debutanizer Reboiler Heater trip Interlock & Control.

e) V-09-01 – Naptha Feed Surge Drum Control.

f) V-09-06 – LP Absorber Pressure Level Control.



1 O2 ANALYZER YOKOGAWA-ZR 402 1

2 CONTROL VALVE / ROV FISHER / MASONEILAN / TYCO / BETTIS 42




6 FLOW SWITCH FCI – FR70 (THERMAL FLEX SWITCH) 4


8 LEVEL SWITCH MAGNETROL 2


AMETEK 32


GAUGE 100









70

11.0 UNIT – 10 OVERVIEW (Naphtha Unifiner Unit)


11.1.1 Objective

The Naphtha unifiner serves primarily to make a Naphtha feed suitable for the catalytic

Reforming Unit by removing sulfur and traces of Nitrogen and other poisons to Reforming

catalyst. The unit has reaction and distillation sections.

Hydrogenation reactions occurring in the Reactor are:

11.1.2 Capacity

The unit design capacity is 26060 BPD. It yields approximately 68% Naphtha as reformer

feed stock and 27% as Light Naphtha product. Hydrogen consumption is approximately

200 SCF/BBL.


Feed to the Naphtha Unifiner is from the following sources:

a) Naphtha Fractionation Unit

b) Isomax

c) Isocracker

d) Kerosene Unifiner

The process scheme is shown in the Sketch -1

Typical Material Balance and feed/products specification are shown in the following table

– 1 & 2.



Feed 26000 100 From Units 68/08/09/11

Products

Light Naphtha (Dehex. O/H) 7070 27.19% To storage Heavy Naphtha (Dehex. Btm) 18052 69.43% To storage




71

b) Table-2 : Typical Feed & Product Qualities

SPEC. FEED Dehexaniser Dehexaniser

Overhead Bottom

Gravity API 67.40 82.89 59.15 Sulfur PPM / % wt. 500 <1 < 1.0 Nitrogen, PPM 330 <1 <1 Dist. Range , Deg. F EP 318 100 - 200 210 - 328

PONA : Paraffins 71.8 60.5 Olefins 0 0 Naphthenes 22.5 31.1 Aromatics 5.7 8.4

PRODUCTS


Naphtha Unifiner feed (C5-350oF Naphtha) from various units is pumped and preheated

through a Reactor Effluent-Feed Exchanger and a Fired Heater (vapor phase) into the

top of the Reactor, V-10-01, currently loaded with N-21 catalyst. Hydrogen rich gas from

Catalytic Reformer (export) is compressed by C-10-01A/B,

1st stage, and mixed with the feed stream, upstream of the Reactor Effluent Feed

Exchanger. The Reactor Effluent after hydrotreatment is further cooled in the Effluent

Feed Exchanger, Air cooler and a Water Trim cooler before flowing into the H.P.

Separator, V-10-02.The Hydrogen rich vapors from the H.P. Separator are compressed

again with C-10-01 A/B 2nd & 3rd Stage of the compressor as export bleed gas to the

Unifiners. Hydrogen Sulfide and light hydrocarbons (mainly gases) are released from the

Separator liquid in a Flash Drum V-10-03.

The vapors from the Flash Drum is routed combined with the Stabilizer overhead gas.

The liquid in the Drum is pumped out to the E-10-15 Exchanger then through the

stabilizer feed bottoms Exchanger E-10-07, into the Stabilizer V-10-04.

Stabilizer overhead vapors are condensed in an Air Cooler and a Water Trim Cooler and

flow into an Accumulator V-10-05. The vapors from the Accumulator (butanes and lighter

Gases) along with gas from the Flash Drum are routed to the Amine Unit low pressure

Absorber. The liquid from the Accumulator is returned to the stabilizer as total reflux.

Stabilizer bottoms flow through E-10-07 Exchanger to the Dehexanizer V-10-06. The

Dehexanizer overhead vapors are condensed in an air cooler and flow into an

Accumulator. Part of the Accumulator liquid is pumped back as reflux, the excess is

pumped through Water Trim Cooler to storage as C5/C6 product (Light Naphtha).



72

Dehexanizer bottoms (Heavy Naphtha) are cooled by pumping through an Air Cooler and

routed to Catalyticfeed. The excess product is further cooled in a Water Cooler and

routed to storage.






1 Exchangers 17

2 Air Coolers 04


4 Heaters 01

5 Reactor 01



73

6 Filters 02

7 PSVs 34


Unit 10 – The Naphtha unifiner serves primarily to make a Naphtha feed suitable for

catalytic Reforming by removing sulfur and traces of Nitrogen and other poisons. It has

reaction & distillation sections.

All the Rotating equipment in unit-10 are inspected and maintained as per the guidelines



plant.

Unit 10 has 16 Pumps, 44 Fin fans & 2 compressors. List of Rotating Equipment are


C-10-01 A/B has the flexibility of using high Pressure Stages for compressing fluid.

Pump/Compressor package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals,

Couplings, Piping items etc.) are not included in the list. Bidders can collect relevant

details of maintenance records, healthiness of the equipment and inspection records

during PTM/Site visit.




of power to the Unit is aided from Substation 5A which is located south side of the Unit.


employing pressurized / Air conditioned systems. Substation has a “6.6kV” Switchgears

fed from SS1A & SS1B (ref. drawing # R-00-6012), 3 nos. of “440V” MCC (MCC-A, MCC-

B & MCC-C), 3 nos. of power transformers (1MVA, 6.6kV/440V) and an Emergency

panel. The “6.6kV” Switchgear was replaced completely with latest new ABB panels

during GRTA-2011 under contract CS/1955. The Substation is equipped with Fire

Detection, Alarm & Suppression system which was installed under contract





280HP, as LT motor. Unit -10 has 4 nos of 6.6KV motors and 61 nos. 440V motors. All






74



The Unit-10 is powered from the Substation # 05A and the Single Line Diagram (SLD) for

SS # 05A is as follows (for details Refer Annexure-01, KNPC Sketch # SK-2434 Sheet

02 of 08);




Unit – 10 prepares feed stuck for Unit – 05. Feed from Unit – 10 is supplied from

Isocracker, Isomax & Naptha fractionation Units.


a) DCS SYSTEM: Honeywell make TPS System installed in SIH #6, SIH # 10 & &



# 10 & CCR.


a) Reactor V-10-01 - Pressure Control.

b) Reactor V-10-01 – Temperature Control.

c) Compressor C-10-01 A/B Interlock.



75

d) Feed Pump P-10-01 Interlock.

e) Heater H-10-01 Interlock



1 H2 ANALYZER ABB-PGC VISTA 2000 1

2 CONTROL VALVE MASONEILAN / MESTO /VALTEK UK 26




6 FLOW SWITCH ITT BARTON 1




AMETEK 28


GAUGE 120






15 ANNUNCIATOR PANEL RONNAN 1



76

12.0 UNIT – 11 OVERVIEW (Kerosene Unifiner Unit)


12.1.1 Objective

The objective of this Unit is to upgrade Crude Raw kerosene from Crude Unit along with

H-Oil Cracked Naphtha & Kerosene distillates to meet Kerosene and Jet fuel products

specification suitable for marketing.

Kerosene Hydro treatment is carried out using Hydrogen in the presence of a catalyst in

Reactor whereby Nitrogen and Sulfur compounds are converted to Ammonia and

Hydrogen Sulfide. Simultaneously undesirable aromatic hydrocarbons are converted to

saturates.


The design capacity of the Unit is 34,250 BPSD. However, the present operating capacity

of the unit is 35,000 BPSD.

Material Balance & Feed, Product Qualities is shown in table-1&2



Feed 35000 100 From Units 06/07/09

Products

Naphtha 2900 8.3% To Unit 09 Flash Blending Stock 1500 4.3% To Unit 10 or storage Combined Stream 19500 55.7% To storage

Heavy Kerosene 11000 31.4% To storage



Spec. Feed Naphtha JP - 1 Heavy

Kerosene

Gravity API 45.3 59.3 46.8 41.6 Sulfur PPM / % wt. - / 0.56 160 22 30 Nitrogen, PPM 100 - 150 < 1,0 <1,0 Dist. Range , Deg. F EP 560 116 - 404 322 - 482 466 - 570 Flash Point , Deg. F -- 130 222 Smoke Point , MM 22 -- 25 25 Pour Point , Deg. F -- -- < (-) 24 < (-) 20 Freezing Point , Deg C -- -- ( - ) 51 ( - ) 17

PRODUCTS



77



Kerosene feed is preheated in the Effluent Feed Exchanger followed by final heating in

the Fired Heater H-11-05, mixed with preheated Hydrogen Recycle Gas and flows

through reactor ( currently loaded with Albemarle Graded type catalyst). The Reactor

effluent is cooled in the exchanger series, Effluent/Feed, Effluent/Hydrogen,

Effluent/Stabilizer Feed and Air Cooled Exchangers before flowing into the Separator V-

11-03.

The Hydrogen rich gas from the Separator is recycled to the reactor section by a

Centrifugal Compressor (C-12-01 / C-12-02) common to Kerosene and Diesel Unifiners.

Recycle gas is preheated in an Effluent/Hydrogen Exchanger. It is further heated in a

Fired Heater H-11-04 and joins with preheated hydrocarbon feed to the Reactors. Part of

the Recycle Gas is used as quench Hydrogen in the Reactor.

The hydrocarbon liquid from the Separator is depressured into a Flash Drum V-11-04.

The flash gas containing H2S is sent to Amine Unit.

The liquid from the Flash Drum is fed into the Stabilizer, V-11-05, after preheating in E-

11-04 & E-11-29. The Stabilizer overhead vapors are partially condensed in an Air Cooler

and flow into Accumulator, V-11-06. Naphtha gas from Overhead accumulator is routed

to Naphtha Fractionation Unit (U-09) The Accumulator Liquid Naphtha is returned to V-

11-05 as reflux and the excess is sent to U-09.

Stabilizer bottoms flow to the Fractionator V-11-07, where Flash Blending Stock is taken

as overhead. Flash blending stock can be blended as per the flash requirement either in

Combined stream as JP-1 product or diverted to U-10 or directly to Naphtha pool.

Light Kerosene base stock is drawn from the Fractionator as a side stream. It passes

through a kerosene side Stripper V-11-08 for flash point control.

Fractionator bottoms flow to the splitter V-11-10, where ATK base stock is taken as

overhead. Antioxidant is injected into Combined Stream (blend of FBS, Light Kerosene &

ATK) JP-1 or JP-5 product before it is finally sent to storage.

Part of the Splitter bottoms are circulated through a reboiler heater (H-11-06) to provide

heat for the Splitter. The bottoms product stream is pumped through an Air Cooler and a

Water Trim Cooler to storage as Heavy Kerosene, a Diesel Blending component.



78


a) 2 reactors were replaced with a single reactor.

b) HPRT installed for feed Pump P-11-01.

c) New heat exchanger E-11-29 installed to reduce load on Stabilizer Reboiler H-11-

01.






1 Exchangers, Shell & Tubes 19

2 Air Coolers 08




79

4 Heaters 05

5 Reactor 01

6 Filters 04

7 PSVs 33


Unit 11 – Unit Upgrade raw kerosene distillates to produce specification products suitable

for marketing as kerosene and jet fuel.




plant.

Unit 11 has 30 Pumps, 41 Fin fans, 4 Turbines & 2 Mixers. List of Rotating Equipment











of power to the Unit is aided from Substation 04 which is located south-east side of the


by employing pressurized / Air conditioned systems. Substation has 3 nos. of “6.6kV”













80

280HP, as LT motor. Unit -11 has a 6.6KV motors and 67 nos. 440V motors. All motors

are under Preventive Maintenance program by maintenance department.







of 08);





81



82


The unit processes Kerosene streams to produce ATK & Lamp Kerosene products. Feed

is supplied from crude distillation unit, Naptha fraction unit, H-Oil unit.



GVS operating Stations in CCR


# 10 & CCR.


a) Feed pump P-11-01 Trip Interlock on Kerosene feed flow low or Recycle gas flow low or Lube oil pressure low.

b) H-11-02 - Trip Interlock & Control Logic

c) H-11-03 - Trip Interlock & Control Logic

d) H-11-04 - Trip Interlock & Control Logic

e) H-11-05 - Trip Interlock & Control Logic

f) H-11-06 - Trip Interlock & Control Logic

g) MOV-11-01 - Open / Close command & Interlock



1 ANALYZER (FLUE GAS

02 & H2S) ROSEMOUNT / YOKOGAWA 4




MASONEILAN 4






INTRA AUTOMATION 2


AMETEK 72


GAUGE 188




LTD 124



15 MISC(LIMIT

SWITCH/PROXIMITY SWITCH ETC..)

HONEYWELL 2



83

13.0 UNIT – 12 OVERVIEW (Light Diesel Unifiner Unit)


13.1.1 Objective

Upgrade Diesel stocks (from Crude unit) in the high pressure Diesel Unifiner by removal

of Sulfur and Nitrogen compounds and saturating aromatics. H-oil Diesel component are

also upgraded in this as per the defined scenario.

13.1.2 Capacity

The design capacity of the Unit is 12600 BPSD. At present, unit is operating at 17000

BPSD feed rate.





Feed 17000 100 From Units 06/07

Products

Naphtha 220 1.29% To Unit 09 Splitter Overhead 7900 46.47% To Storage Splitter Bottoms 9540 56.12% To Storage



Spec. Feed Naphtha Splitter Splitter

Overhead Bottom

Gravity API 26.30 51.89 33.09 31.11 Sulfur PPM / % wt. - / 2.29 260 93 300 Nitrogen, PPM 773 162 336 Dist. Range , Deg. F EP 825 98 - 456 444 - 692 615 - 835 Flash Point , Deg. F -- -- 200 > 230 Pour Point , Deg. C 12 -- (-) 6 21 Asphaltenes -- -- 0.0018 0.0022

PRODUCTS

-



84



Diesel feed is pumped through the Effluent – Feed Exchanger into the Reactor V-12-01

which is loaded with HDS catalyst (currently, Albemarle Graded type). The recycle gas

from compressors discharge (C-12-01 or C-12-02) is heated through Effluent Heat

Exchanger (E-12-02) and subsequently Heater H-12-01 and then mixes with the liquid

feed going to the Reactor. The Reactor effluent is cooled in the effluent – hot feed,

stabilizer feed – Recycle Gas, cold feed Exchangers and air cooler and then flows into

the separator, V-12-02.

The Hydrogen rich gas phase in the Separator, along with makeup Hydrogen (from H-Oil,

08 & 10) is recycled to the reactor by a centrifugal compressor(s) common to the

Kerosene and Diesel Unifiners. The advantage of having two compressors C-12-01 and

C-12-02 is to give more flexibility of shutting down and start up for units 11, 12, 13. Part

of the recycle is used as quench Hydrogen in the Reactor. The hydrocarbon bottoms

from the Separator are routed into the Flash Drum V-12-03. The flash drum off gas (from

V-12-03) is sent to the Amine Unit.

The bottoms from the Flash Drum are preheated by Splitter bottoms and Reactor effluent

streams before they flow into the stabilizer (V-12-04). The Stabilizer overhead vapors

flow through an Air Cooler into the overhead drum.

The overhead liquid (unstabilized naphtha) is used as reflux and the excess is pumped to

the Naphtha Fractionation Unit. Vapors from the overhead drum are also sent to Unit-09.

Stabilizer bottoms are pumped to the splitter and the incremental heat is supplied to

Splitter by a fired heater (H-12-04). Overhead vapors from the splitter are condensed in

air cooler E-12-09 and flow into an accumulator. The accumulator liquid is used as reflux,

and the excess after cooling is pumped to storage as Light Diesel base stock.

The splitter bottoms are recirculated through a fired reboiler. (H-12-03)

A bottoms stream is drawn off at the pump discharge, cooled in two water trim coolers /

Fin fan cooler, and sent to storage as Diesel.



85


a) V-12-01 was replaced in the year 2006.

b) C-12-02 new compressor was installed in the year 2006

c) E-12-04 shell and Tube exchanger was replaced with Breach Lock type

exchanger.

d) H-12-01 radiant and convection sections, H-12-03 Convection, and tube section

metallurgy changed.



86






1 Heat Exchangers, Shell & Tubes 21

2 Air Coolers 04

3 Vessels / Tanks / Drums 20

4 Heaters 03

5 Reactor 01

6 Filters 13

7 PSVs 16


Unit 12 – Diesel stocks being improved in the high-pressure Diesel unifiner by removal of

sulfur and nitrogen compounds.




plant.

Unit 12 has 20 Pumps, 18 Fin fans, 4 Steam Turbines & 2 compressors. List of Rotating


Recycle Gas compressor C-12-02 installed in 2008, which can operates three unifiners

(11/12/13) & independent units. Critical pumps packings converted to mechanical seals

to the spirit of API 682 to prevent Gas leakage to environment.













87











280HP, as LT motor . Unit -12 has a 6.6KV motors and 33 nos. 440V motors. All motors








of 08);





88



89


The unit processes mixture of Hydrocarbons containing unsaturated components,

Aromatics, Sulphur and Nitrogen compounds to produce Light Diesel, Local Diesel and

unstabilized Naptha



GVS operating Stations in CCR


# 10 & CCR.

c) PLC SYSTEM: Allen Bradley make PLC System for C-12-02 Interlock control.

d) BENTLY VIBRATION SYSTEM: Bently make Temperature Vibration System for

C-12-02 Vibration Temperature Monitor

e) Woodward Speed Governor System: C-12-02 Turbine Speed Control.


a) H-12-01 - Trip Interlock & Control

b) H-12-02 - Trip Interlock & Control

c) H-12-03 - Trip Interlock & Control

d) H-12-04 - Trip Interlock & Control

e) MOV-1202 - Open / Close Command & Interlock

f) MOV-1203 - Open / Close Command & Interlock

g) C-12-01 - Trip Interlock

h) C-12-02 - Trip Interlock

i) Feed Pump P-12-01 Interlock Control



90



1 02 & HYDROGEN

ANALYZER ABB-PGC VISTA 2000/ PANAMETRIC-TM02 /

TELEDYNE-3000 TB 3


FARRIS USA 44


MASONEILAN 6




7 HMI SIEMENS 4



INTRA AUTOMATION 8


AMETEK 75

11 PLC ALLEN-BRADLEY / WOODWORD 5009 1


GAUGE 171




LTD 126




18 VIBRATION BENTLY NEVADA- 3300 1



91

14.0 UNIT – 13 OVERVIEW (Heavy Diesel Unifiner Unit)


14.1.1 Objective

Upgrade Diesel stocks (Cracked H-oil Diesel component) are improved this Unit by

removing Sulfur and Nitrogen compounds and saturating aromatics. Crude raw Diesel

component are also upgraded in this as per the defined scenario.

14.1.2 Capacity

The design capacity of the Unit is 9300 BPSD. At present, unit is operating at 12000

BPSD feed rate.


The feed to this Unit is mainly a mixture of heavy and light diesel cuts from H-Oil Unit (07)

and H-Oil Vacuum Unit (63) respectively. However, Light and Heavy Diesel from

Atmospheric Distillation Unit can also be included in the Feed.




Feed 12000 100 From Units 06/07

Products

Naphtha 130 1.08% Unit 09 Splitter Overhead 7510 62.58% Storage Splitter Bottom 4830 40.25% Storage




92


Spec. Feed Naphtha Splitter Splitter

Overhead Bottom

Gravity API 25.95 55.03 33.21 30.75 Sulfur PPM / % wt. - / 2.39 1000 100 200 Nitrogen, PPM 753 105 236 Dist. Range , Deg. F EP 820 106 - 424 434 - 698 630 - 830 Flash Point , Deg. F -- -- 216 > 230 Pour Point , Deg. C 12 -- (-) 6 24 Asphaltenes -- -- 0.004 0.008

PRODUCTS



Feed from charge tank is pumped to suction of feed booster pump P-13-01. Liquid feed

preheated by hot reactor effluent in E-13-01 & E-13-03. Recycle gas from C-12-01

discharge is also preheated in E-13-02 by exchanging heat with hot reactor effluent.

Water was injection facility is provided for E-13-03 to dissolve any accumulated

Ammonium Bisulfite salt which reflect in reduction of pressure drop across reactor

section.

The hot gas from the furnace combines with hot liquid feed at inlet to the Reactor V-13-

01 which is loaded with HDS (currently, Albemarle graded type) catalyst. The

temperature of the combined feed, controlled by firing in the heater, varies from 560-

620oF depending upon the product quality, rate of the feed stock and product

requirements.

The reactor effluent temperature varies from 620 to 720oF depending upon the feed

quality and gas/oil ratio of the combined feed. The effluent is cooled to about 150oF by

flowing through exchangers E-13-01, E-13-04, E-13-02, E-13-03 & E-13-05.

The level of liquid Hydrocarbon product is maintained by the level controller letting down

the liquid product to Flash Gas drum V-13-03.

Flash gas is sent to Amine unit. The liquid from flash drum is heated to 400-450oF by

splitter bottoms in E-13-07 and reactor effluent in E-13-04. Then it flows to the Stabilizer

V-13-04. The Naphtha and lighter components are removed overhead by stripping with

superheated Steam (from convection section of H-13-03).



93

The overhead liquid and gas stream from the Stabilizer are sent to the Naphtha

Fractionation Unit (09). The degree of steam stripping is regulated for the flash point of

the overhead product from the Splitter.

The Splitter, V-13-06 is operated under vacuum with a two stage ejector on overhead

drum V-13-07. A Reboiler Heater (H-13-03) provides heat in the bottom section and heat

removed from the top by providing reflux V-13-07. The overhead product from this drum

after air cooling in E-13-10 is sent to Diesel storage. The bottom product after trim

cooling in E-13-11 is routed to Isocracker feed tank.


a) Reactor V-13-01 was replaced in the year 1998

b) Splitter Tower V-13-06 was replaced in the year 2002

c) Trim cooler E-13-13 was provided to reduce Splitter Bottom product rundown

temperature.



94






1 Heat Exchangers 11

2 Air Coolers 05

3 Vessels 09

4 Heaters 02

5 Reactor 01

6 PSVs 17


Unit 13 – Diesel stocks are improved in this unit by removing sulfur and Nitrogen

compounds and saturating aromatics.

All Rotating equipment in 13 Unit are inspected and maintained as per the guidelines of



plant.

Unit 13 has 13 Pumps, 22 Fin fans, 1 Steam Turbines. List of Rotating Equipment are


















95









280HP, as LT motor. Unit -13 has a 6.6KV motors and 33 nos. 440V motors. All motors








of 08);





96



97


Unit – 13 processes light as well as heavy diesel produced in Crude and H-oil Units to

reduce the Sulfur Content.





10 & CCR.


a) Feed Pump P-13-01 Interlock

b) Recycle Gas Heater H-13-01 Interlock & Control.

c) Splitter Reboiler H-13-03 Interlock & Control.

d) Oil Water Drum V-13-09 Control.

e) Reactor V-13-01 Bed Temperature Control



1 CONTROL VALVE FISHER / MASONEILAN 33







/ AMETEK 32


AM GAUGE 87

9 PRESSURE SWITCH UE / ASHCROFT 6



LTD 69



13 MISC HONEYWELL 2



98

15.0 UNIT – 14 OVERVIEW (Amine Treating Unit)


15.1.1 Objective

Amine treating unit treats three separate gas streams for removing H2S & CO2

components. This whelps to prepare feed gas for Hydrogen Units & Fuel Gas systems.

Simultaneously unit recovers acid gas for Sulfur Plant feed.

15.1.2 Capacity

The Unit is designed to treat 48.7 MMSCFD of Burgan Gas, 57 MMSCFD of low pressure

Gas and 42 MMSCFD of High Pressure Flash Gas in three separate systems.




MMSCFD

23 MMSCFD

40 MMSCFD

5 MMSCFD

30 MMSCFD

15 MMSCFD

22.5 MMSCFD

42.3 MMSCFD

37.0 MMSCFD

Acid Gas 11.2 MMSCFD

* : Total LP Refinery Gas is about 44 MMSCFD (30.0 MMSCFD to Unit-14 & 14.0 MMSCFD to C-61-01)

Products

LP Lean Gas to V-14-01 From KOC

To Refinery Fuel Gas To Sulfur Unit

Treated Refinery & LP Gas

Feed

LP Lean Gas to V-14-02 HP Flash Gas to V-14-03 HP Lean Gas to V-14-03 LP Refinery Gas to V-14-01 *

Treated Gas Treated HP Flash Gas & Lean Gas

From Refinery Units

To Hydrogen Unit To Hydrogen Unit


From KOC

From KOC From Refinery Units


Specification

H2S % 0.1 6.0 17.0 6-10 PPM 3-5 PPM 40-80 PPM 92.0%

CO2% 2.2 - 0.7 < 0.2 - - 8.0%

Mol. Wt. 21 10.5 29.0 21.0 10.0 29.0 34.8

Treated LP

Gas Acid GasLP Lean Gas

HP Flash &

HP Lean Gas

LP Refinery &

Lean GasTreated Gas

Treated HP

Gas

FEED PRODUCTS



99



Unit has three MEA Contactors. Each of the Amine Contactors has a gas feed at the

bottom and circulting Monoethanoalamine solution from the top. The contactors are

equipped with knockout drum. Overhead treated Gas is sent to other units as feed or

Fuel Gas.

V-14-01 Low Press Contactor, is fed with a mix of Refinery LP Gas from V-09-06, FGRU

recovered Flare Gas and H-Oil unit Naphtha gas and low pressure Flash Gases. The

treated low H2S Gas is sent to the Refinery Fuel Gas Drum, V-29-02.Recently a

modification was implemented in U-14. In this modification a slip stream of Burgan gas is

fed to V-14-01 (through V-29-04) to help reduce H2S content in Fuel gas. This

modification was commissioned in Aug 2010.

V-14-02 Medium Press Contactor, operating at ~ 150 psig is fed with compressed LP

Gas from first stage of Compressors, C-01-01 A/B. The treated gas from top of the

contactor is routed to the second stage of the compressor for further increase in pressure

to about 430 psi to be used as Hydrogen Plant feed.

V-14-03 Low Press Contactor, operating at about 430 psi, is fed with a mix of HP

Bleed/Flash Gases form H-Oil Unit, Unifiners and HP imported Gas from C-14-01 if

needed. The treated H2S free gas from top of the contactor is routed to the Hydrogen

Plant as supplementary feed.

The Rich MEA solution from Low & Medium Press contactors are flashed in V-14-01, and

them pumped out from the bottom to the Regenerators, V-14-04 A/B. The feed is

preheated by Regen Bottoms in E-14-03 A-D. Rich Amine is stripped of H2S with 50#

Steam reboilers.

Lean Amine is cooled in Fan cooler E-01’s and Water Coolers E-02”s and recycled to the

three Amine Contactors.

Acid Gas from the Amine Regenerators overhead is sent to the Sulfur Plant (04/74) for

Sulfur recovery.



100


a) V-14-01, V-14-09 vessels were replaced

b) Amine filtration facilities were enhanced by adding F-14-03 A/B and F-14-04 in the

year 1986.

c) New compressor C-14-01 was installed in the year 2002.






1 Exchangers 21

2 Air Coolers 03



101

3 Vessels / Tanks / Drums 20

4 Filters 16

5 PSVs 50


Unit 14 – Treat three separate gas streams for removing H2S & CO2 components &

recovers acid gas for sulfur plant feed.




plant.

Unit 14 has 21 Pumps, 45 Fin fans, 12 Steam Turbines, 1 compressor & 1 Mixer. List of

Rotating Equipment are furnished vide Appendix 2A hereof.






















Motors rated less than or equal to 280HP is designated as LT motor. Unit -14 has 60 nos.


department.



102







of 08);





103


Amine Treating Unit Processes gas Streams for Unit – 01, 06, 07, 09, 29, 08, 10, 11, 12,

13, 68 HP Lean gas from KOC to remove entrained acid gases from the feed gas

streams. The recovered acid gas is routed to Sulfur recovery Unit.



104





10 & CCR.

c) FSC System: Honeywell make FSC system for ROIV Control in unit.

d) PLC System: Duel Redundant Siemens make PLC System for Compressor C-14-

01 Interlock & Control.


a) 14-ROIV-1000 – Acid gas line Interlock Control.

b) C-14-01 – Compressor Interlock.

c) C-14-01 – Anti Surge Control & Interlock.

d) C-14-01 – Wood ward speed Governor Control.

e) C-14-01 – Bently make Vibration Monitoring System & Interlock control.



1 H2S/02 ANALYZER YOKOGAWA-GD40T / ABB-2000 VISTA 4

2 VIBRATION BENTLY-3500 2

3 CONTROL VALVE FISHER / MASONEILAN / Valtek UK/Virgo / Rotork

35


MASONEILAN 16



7 HMI SIEMENS 5




AMETEK 61

11 PLC WOODWARD - 5009 2


GAUGE 193

13 PRESSURE SWITCH UE / ASHCROFT / SOR / BOURDON

SEDEME 15

14 ROTAMETER BROOKS 6



LTD 39






105

16.0 UNIT – 15 OVERVIEW (Ammonical Water Treating Unit)


16.1.1 Objective

The Unit serves to strip out Ammonia and H2S from concentrated Ammonical Water produced in Unit – 15C and concentrated Foul Water produced in Unit – 06 foul water system.

16.1.2 Capacity

Unit capacity is 140 GPM.



c) Table-1: Typical Material Balance

LBS/HR. % WT.

Feed Ammonical Water 72630 90.75 Condensate - H2O 7400 9.25

Total 80030 100.00

Products

Stripped Water 70420 87.99

Acid Gas (H2S) 3700 4.62

NH3 Gas 2280 2.85 Overhead liquid 3630 4.54

Total Product 80030 100.00


Reuse a part & balance to effluent

To Sulfur Recovery Units

To flare / Sulfur Plants To TK-476

From TK-476

d) Table-2 : Typical Feed & Product Qualities

Composition / Spec Feed

NH3, % WT/ (PPM) 4.61 (50 PPM Max.) 270 PPM 90.89 35.13

H2S, % WT/ (PPM) 5.84 (10 PPM Max.) 99.54 5.85 11.70

H2O, % WT 89.55 99.99 0.43 3.26 53.17

PRODUCTS

Stripped

WaterAcid Gas (H2S) NH3 Gas

Overhead

Liquid

-

-



106



Unit has two strippers. Most ( about 85%) of the feed H2S is stripped in H2S Stripper,

operating under higher pressure. In the subsequent lower pressure NH3 Stripper all the

remaining H2S and complete NH3 is stripped off.

In the feed system, the concentrated overhead Accumulator liquids from Unit-06 Foul

Water Stripper, V-06-09 and Unit-15C Ammonical Water concentrator, V-15-16 are

mixed and degassed to flare in V-15-19.The Degasser liquid is pumped by P-15-01A/B/S

to TK-476. From the tank TK-476, separated oil is skimmed to the Slop Oil System and

water is sent (using pump P-15-15) to Unit–15 Stripper Tower, V-15-04.

About 85% of the feed to H2S Stripper is heated in Exchangers, E-15-02 & E-15-03

before it is fed to the column on tray 18. The rest of 15% of the feed is fed to tray 22.

Also, a small amount of HP cold condensate is fed to the top tray 35 as reflux.

The heat required for stripping H2S from the feed is further supplemented by 150 psig

Steam Reboiler E-15-05.

The overhead cold almost pure H2S gas is routed to Sulfur Units 04/74 under pressure

control through a knock-out pot V-15-06.

The H2S Stripper bottom is routed to the NH3 Stripper V-15-07, through E-15-03. Hot H2S

Stripper bottom is heat exchanged in E-15-03, mainly to control the NH3 Stripper feed

temperature. Reboiler E-15-07, uses 150 psig steam to supply necessary heat for

stripping H2S/NH3 in the column. V-15-07 bottom is cooled through E-15-02. A stripped

water almost free of NH3 & H2S is obtained from NH3 Str. Bottom that is recycled partly

as injection water and the excess is routed to Effluent Treatment Plant located in MAB

refinery.

The overhead vapors are condensed in Air Fin Coolers E-15-08, and collected in V-15-

08, which is used partly as reflux to V-15-07 and the rest is recycled to TK-476 via

Degasser V-15-19. The non-condensed H2S/NH3 gases are routed to Sulfur Plants/Flare

under pressure control.



107


Tower V-15-04 was replaced in the year 2003.






1 Exchangers 08

2 Air Coolers 02

3 Vessels, columns, tanks, drums 09

4 PSVs 13



108


Unit 15 – This Unit serves to strip out Ammonia and H2S from concentrated Ammonical

water produced in Unit 15C and concentrated Foul water produced in Unit 06 foul water

system.




plant.

Unit 07 has 30 Pumps, 8 Fin fans. List of Rotating Equipment are furnished vide

Appendix 2A hereof.



Pumps package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals, Couplings,

Piping items etc.) are not included in the list. Bidders can collect relevant details of

maintenance records, healthiness of the equipment and inspection records during

PTM/Site visit.




of power to the Unit is aided from three Substations, SS # 5A which is located south east

side of the Unit & SS # 5B which is located north east side of the Unit. The substation is

Building with Basement Type & facilitated as non-classified area by employing

pressurized / Air conditioned systems. The Substation is equipped with Fire Detection,

Alarm & Suppression system which was installed under contract CB/CSPD/2004 &

commissioned on 2016. Battery Charger along with Battery backup bank are also

available.




department.





The Unit-15 is powered from the Substation # 05A & 05B and the Single Line Diagram

(SLD) for SS # 05A & 05B is as follows (for details Refer Annexure-01, KNPC Sketch #

SK-2434 Sheet 02 & 03 of 08);



109




Ammonical Water stripping unit processes ammonical water (sour water) to meet

environmental norms H2S and NH3 are removed from ammonical water by steam

stripping. Unit is feed by crude Unit – 06 & Unit – 15C.



110





10 & CCR.

Note: ESD & DCS system in SIH # 5, SIH # 10 & CCR are not for sale and will be

retained to cater the requirement of remaining operating system in Shuaiba.


a) V-15-04 – Reboiler Feed flow / pressure control.

b) V-15-04 – Reboiler Temperature Control.

c) V-15-07 – Reboiler Temperature Control.

d) V-15-16 – Feed Flow (Hot & Cold) Control.

e) V-15-16 – Temperature, Pressure & Level Control.



1 O2 ANALYZER ROSEMOUNT-5081 1

2 CONTROL VALVE MASONEILAN 30




6 LEVEL GAUGE GLASS JERGUSON / PENBERTHY 23


8 LOCAL INDICATOR ITT BARTON / BROOKS 50

9 PRESSURE GAUGE ASHCROFT / WIKA / WISE /

GENERAL / AM GAUGE 96

10 PRESSURE SWITCH UE 1


TC LTD 56


HONEYWELL / ABB / FOXBORO / SMAR

32



111

17.0 UNIT – 15C OVERVIEW (Sour Water Concentrator)


17.1.1 Objective

This Unit prepares H2S/NH3 concentrated water stream from the various sour water

streams, for further processing in Unit-15.

17.1.2 Capacity

Unit capacity is 340 GPM.



e) Table-1: Typical Material Balance

FEED & PRODUCTS LBS/HR. % WT.

Feed Ammonical Water 170000 87.46 Stripping Steam 24375 12.54

Total 194375 100.00

Products Stripped Water 148248 76.27 Overhead liquid 46127 23.73

Total Product 194375 100.00

To TK-476


From TK-481

Reuse a part & balance to sea

f) Table-2 : Typical Feed & Product Qualities

NH3, % WT (PPM) 1.10

H2S, % WT (PPM) 2.01

H2O, % WT 96.89

COMPOSITION / SPECS. FEED

99.99

Stripped Water

(5 PPM Max.)

(20 PPM Max.) 4.05

7.37

88.58

Overhead Liquid

PRODUCTS

-

-



112



Ammonical water streams from various Refinery Units are mixed, cooled with cooling

water in E-15-16A/B, degassed to Flare in V-15-01 and then pumped through P-15-

16A/B to tank TK-34-481 /TK 482

Oil and sludge separated in TK-481/TK 482 is pumped intermittently to Slop Oil System.

Pump P-34-22/22S takes suction from TK-481 and feeds Unit-15C through a filter F-15-

01 (Currently not in use). About 85% of this feed heated in Exchangers E-15-17A/B, by

means of Concentrator bottoms, (i.e. stripped water going to MAB ETF) and routed to the

top tray of the Concentrator Column V-15-16. The remaining 15% of the total feed is

routed as cold feed to the Concentrator overhead gases Static Mixer.

V-15-16 concentrator contains 35 sieve trays. Stripping of NH3 and H2S from the sour

water is done by 150 psig steam.

The overhead gases from V-15-16 after mixing with the cold feed are further

cooled/condensed in Air Fin Coolers E-15-20 and in E-15-18 by means of cooling water.

The condensed concentrate is collected in Overhead Accumulator V-15-17 and pumped

by P-15-18A/B to TK-476 through Degasser V-15-19 and P-15-01A/B/S pumps. This is

further stripped in Unit-15. The overhead non-condensable gases are routed to Flare.

The hot stripped water from Concentrator V-15-16 bottom is pumped by P-15-17A/B

pumps through E-15-17A/B Exchangers to the Effluent Treatment Plant in MAB. A

portion of this stripped water is recycled to the H.P. water injection system Accumulator

V-15-13.



113



the summary of the Static Equipment for Unit-15C is listed as follows; List of Static



1 Exchangers, Shell & tube 08


3 Filters / dampers 06

3 PSVs 08



114

18.0 UNIT – 17 OVERVIEW (Kerosene Merox Unit)


18.1.1 Objective

The Merox Unit is used for sweetening raw Kerosene.

The process is based upon oxidation of mercaptans to Disulfide using Merox catalyst.

18.1.2 Capacity

The unit is designed to sweeten 15000 BPSD of light Kerosene from the Naphtha

Fractionation Unit (Unit-09). Later the unit was revamped to produce Aviation Turbine

Fuel (ATK) by adding clay filter and salt filter to produce 20000 BPSD of ATK. The Unit

can also be operated on a full range Kerosene from the Crude Unit (Unit – 06), but at a

lower feed rate.





Feed 20,000 100.0%

Products

Product ATK 20,000 100.0%

Total Liquid Product 20,000 100.0%

From Unit - 09

To Storage


Specification

Gravity API

Mercaptan, PPM

H2S, PPM

Dist. Range , Deg. F

Flash Point , Deg. F

49.1

4 - 6

0 - 0.1

305 - 470

105 - 110

49.1

180

5 - 8

305 - 470

Feed PRODUCT ATK

105 - 110



115



Raw Kerosene from Unit-09 at approx. 105-115oF is first bubbled through pre-wash

Tower V-17-01 containing approx. 2% caustic solution, thereby removing traces of H2S

and Naphthenic acid. The outlet stream is mixed with air and fed to two parallel Reactors

V-17-03 A&B, each containing a bed of charcoal impregnated with Merox-FB catalyst.

Reactor bed is kept alkaline by intermittent circulation of approx. 8% caustic solution.

The outlet sweet Kerosene is passed through settler V-17-04 to separate entrained

caustic. The Kerosene from caustic settler is routed to water wash tower (V-17-08) for

wash off the entrained caustic. The water wash outlet is passed through Salt filter (F-17-

01) to remove the moisture content and then through the Clay filter (F-17-02) to improve

color and stability.

The (sweet/water free) Kerosene is routed to ATK product tank.



116


a) Post treatment facilities such as Salt Filter and Clay filter installed in the year 2000

b) New Air compressor C-17-01 B installed in the year 2009.






1 Vessels 13

2 Tanks 04

3 Filters 02

4 PSVs 20

5 Compressor accessories - coolers 02

6 Compressor accessories - Traps 04


Unit 17 – The Merox unit is used to sweetening raw Kerosene, based on oxidation of

mercaptans to disulfide, from Naphtha fractionation unit.




plant.

Unit 17 has 11 Pumps & 2 Reciprocating compressors. List of Rotating Equipment are


New compressor C-17-01 commissioned in 2008 with higher capacity.. Most of the



Pump/Compressor package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals,











117











Motors rated less than or equal to 280HP is designated as LT motor. Unit -17 has 13 nos.


department.







of 08);





118



119


The unit processed Kerosene feed stock to remove H2S and Organic acid Compounds.





10 & CCR.

c) PLC System: Siemens make Simantic S7-3 PLC for reciprocating Air

Compressor.


a) C-17-01 – Air Compressor Interlock & Control.

b) C-17-01 – Air Receiver Control.

c) Unit – 17 – Feed Temperature Control.



1 CONTROL VALVE FISHER / MASONEILAN 6

2 CONTROLLER YOKOGAWA 2






8 PLC 1 C-17-01B AIR

COMPRESSOR


AM GAUGE 62




LTD 22





120

19.0 UNIT – 19 OVERVIEW (Dimineralizing Unit)


19.1.1 Objective

Deminerlaizer Unit processes distilled water from MEW to prepare high purity water for the Boilers in the Refinery. This is accomplished by Ion exchange process utilizing a mixed Cation/Anion bed.

19.1.2 Capacity

The Unit has a design capacity of 1450 US GPM of Treated Water during normal operation and 1,800 US GPM at maximum capacity.


The feed water to Unit – 19 is distilled water supplied by MEW and received in the storage tanks TK-471/475. Tables 1&2 show the material balance and typical analysis of Feed Water and Treated Water from the demineralizer.


Feed

Treated Distilled Water from MEW

Products

Demineralized Water ( Via TK- 480 )

GPM

To Deaerators in Boiler Unit


From TK-471/475

1450

1450



121


Specification / Analysis

Cations

Calcium 15 0 Magnesium 5 0 Sodium 9 <0.2 Total Cations 29 <0.2

Anions

Bicarbonate 8 0 Carbonate 0 0 Chloride 13 <0.2 Sulfate 8 0 Total Anions 29 <0.2

TDS 40 1.0 Iron, total 0.1 0.0 Carbon Dioxide 1.0 0.0 Silica 0.1 <0.02 pH 7.2 7.0 - 7.5

Feed Water

as CaCO3 in PPM

Demineralized Water

as CaCO3 in PPM



Demineralizer Unit contains three parallel mixed Cation/Anion resin beds. Normally two

beds are in line. Feed water enters the resin beds at the top and passes through mixed

bed, containing both Anion and Cation resin in mixed form, exits at the bottom. In the

beds, ion exchange process takes place, i.e. Cations ( Sodium, Calcium, Iron, etc. )

present in the water are removed by cation resin while the Anions ( Chlorides, Sulfates,

etc.) are removed by anion resin, thus producing a high purity water which essentially

free of salts.

The resin gets exhausted after during operation for 3-7 days after which regeneration is

needed. Each of the Demineralizer beds are equipped with automatic regeneration

facilities. Normally, two beds are in commission, the third being under regeneration.

Regeneration is accomplished by treating with dilute sulfuric acid ( for cation resin) and

Caustic Soda ( for anion resin) followed by rinsing before taking back on line again.

Regeneration effluents are neutralized to remove acidity/alkalinity before disposal.

Treated Demineralized water is stored in TK-480 as intermediate tank and from there

pumped to the De-aerators in Boilers area.



122

Part of resin bed rinse water is reused as make up to the Cooling Towers with provision

for pH correction as a part of water conservation projects.







2 Exchangers 01

3 Filters 01



123


Unit 19 – Demineralizer unit processes distilled water from MEW to prepare high purity

water for the high pressure Boilers in the Refinery, accomplished by Ion exchange

process utilizing a mixed Cation/anion bed.

All the Rotating equipment in Unit-19 are inspected and maintained as per the guidelines



plant.

Unit 19 has 8 Pumps & 1 Blower. List of Rotating Equipment are furnished vide

Appendix 2A hereof.

Pumps/ Blowers package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals,





Unit -19 is considered as unclassified area as per Shuaiba Refinery Hazardous Area

Classification drawing (refer drawing # R-00-6030). The source of power to the Unit is

aided from Substation 1A which is located west side of the Unit. substation is Building

with Basement Type & facilitated as non-classified area by employing pressurized / Air

conditioned systems. Substation 1A is one of the main intake substation from Ministry of

Electricity & water (MEW) and has 4 Nos. of 31.5MVA 132/6.9kV Transformers

connected in parallel to 6.6kV Switchgear with Is-Limiters between the bus-sections in

order to limit maximum short circuit fault current at its bus to 31.5kA (ref. drawing # R-00-

6012), 3 nos. of “440V” MCC (MCC-A, MCC-B & MCC-C ), 3 nos. of power transformers

(1MVA, 6.6kV/440V) and an Emergency panel. The 6.6kV Switchgear, section-4 was

replaced completely with latest new ABB panels during GRTA-2011 under contract

CS/1955. The Substation is equipped with Fire Detection, Alarm & Suppression system

which was installed under contract CB/CSPD/2004 & commissioned on 2016. Battery

Charger along with Battery backup bank are also available.




department.







124

Unit # 19 is powered from retained Substation # 01A.


Unit – 19 has three mixed beds. In these beds cations and anions resin are used. These

resins absorb salts from distilled water. The bed is regenerated with acid & caustic

solution.


a) DCS System: Honeywell make TPS System for process parameter monitoring.

b) PLC System: Allen Bradley make PLC System installed in Local Control room for

regeneration of mixed bed.


a) Dewerator storage vessel V-20-01 &01S Interlock.

b) Acid to regeneration bed concentration high Interlock.

c) Caustic tank level low Interlock.

d) Regeneration of bed Interlock.



1 PH / CONDUCTIVITY

ANALYZER ROSEMOUNT-5081 / FOXBORO-

870EC/871EC 10

2 CONTROL VALVE FISHER / MASONEILAN / WARRON

MORRISON 58



5 FLOW SWITCH HEINRICHS 2

6 HMI SIEMENS 2


8 LOCAL INDICATOR ITT BARTON 5

9 PLC ALLEN BRADLEY 5/30 1

10 PRESSURE GAUGE ASHCROFT / WIKA / WISE / GENERAL 25

11 PRESSURE SWITCH UE / ASHCROFT 4


13 THERMOWELL THERMO ELECTRIC 2

14 TRANSMITTER ROSEMOUNT / YOKOGAWA 5




125

20.0 UNIT – 20 OVERVIEW (Boilers & Steam System)


20.1.1 Objective

Steam System consists of steam generator and distribution network at different pressure

levels for process and utility requirements. It also distributes BFW for various uses in

refinery.

20.1.2 Capacity

Shuaiba Refinery has four fired boilers with design production capacity of 300,000 lbs/hr

of 900# steam per boiler.

Additional steam is produced from other Waste Heat Boilers:

Hydrogen Units – 02/62 : 900 psig steam.

SRU Unit-04 & 74 and Incinerator : 475 psig Steam

Unit-63/ Unit 68 : 150 psig Steam



Boiler unit consist of two Deaerators DA-20-01/V-20-01 and DA-20-01A/ V-20-01 A.

Demineralized water along with the CO2 rich condensate from hydrogen units and High

pressure cold condensate stream are deaerated and fed to the Boiler Feed Water Pumps

P-20-01 A/B/C/D. These pumps supply BFW to refinery as well as the boilers. There are

four boilers B-20-01 A/B/C/D each with 300,000 lbs/hr capacity built by Foster Wheeler.

Each boiler consists of a steam drum , water wall tubes , four gas fired burners and a

Forced Draft Fan. Each boiler is also provided with steam superheaters.

The product 900 psig steam is sent to the 900 psig header. There are four different

headers for steam distribution as follows:

a) 900 psig: Steam is supplied to the 900 psig steam header from the Boiler Plant

and Hydrogen Plants. The 900 psig steam is then used by Steam Turbines and as

make-up to 475 psig header through let-down and desuperheating.

b) 475 psig: Sources of 475 psig steam are WHB at units-04/74/75, exhaust of steam

turbines at U-01/U-08 and make-up from 900 psig steam. 475 psig is consumed in

Hydrogen manufacturing process, Steam Turbines and reboilers.

c) 150 psig: Sources of 150 psig steam are Steam Turbine exhaust(U-07/U-68),

Waste Heat Boilers in Units 63/68 and make-up 475 psig steam. The consumers

are steam stripping, reboilers, steam tracing and ejectors. All excess 150 psig

steam is letdown to the 50 psig header.



126

d) 50 psig: Sources of 50 psig steam are Steam Turbine exhaust, Sulfur Plant

Condensers and from 150 psig steam letdown. 50 psig steam is consumed for

process steam stripping, reboilers, and steam tracing. All excess 50 psig steam is

condensed in sea water condenser E-29-02 and condensate is returned to Boiler

Plant.

e) BFW: BFW from Deaerators is treated with oxygen scavengers / neutralising

amines and then pumped through pumps P-20-01 A/B/C/D to BFW system. A

small portion of the discharge is routed as despuerpheating water to steam

letdown stations and turbine exhaust steam desuperheaters in various uses.

Treatment chemical is added to the main stream of BFW before routing it to the

boilers and for other refinery Waste heat boilers.


Boiler D and additional Deaerator was installed in the year 1978.



127






1 Exchangers 03

2 Vessels, Stream Drums & tanks 16

3 Deaerator 02

4 Stack 04

5 Boiler Assembly 04

6 PSVs 37


Unit 20 – Boilers used to support steam system consists of steam generators and

distribution network at different pressure levels for process and utility requirements.

All the Rotating equipment in Unit-20 are inspected and maintained as per the guidelines



plant.

Unit 20 has 19 Pumps, 4 Blowers, 8 Steam turbines involved in this unit. List of Rotating


Pumps/ Blowers/ Steam Turbines package auxiliary items (filters, SO/LO Coolers,

Gearboxes, Seals, Couplings, Piping items etc.) are not included in the list. Bidders can




Unit -20 is considered as unclassified area as per Shuaiba Refinery Hazardous Area

Classification drawing (refer drawing # R-00-6030). The source of power to the Unit is

aided from Substation 5B which is located west side of the Unit. The substation is

Building with Basement Type & facilitated as non-classified area by employing

pressurized / Air conditioned systems. Substation has a “6.6kV” Switchgears fed from

SS1A & SS1B (ref. drawing # R-00-6012), 3 nos. of “440V” MCC (MCC 5B-A, MCC 5B-B

& MCC 5B-C), 3 nos. of power transformers (1MVA, 6.6kV/440V) and 2 nos. of

Emergency panel (RPP-1 & ATS-29-04). The Substation is equipped with Fire Detection,




128


available.









The Unit-20 is powered from the Substation # 05B and the Single Line Diagram (SLD) for

SS # 05B is as follows (for details Refer Annexure-01, KNPC Sketch # SK-2434 Sheet

03 of 08);




Unit – 20 boilers generate 900 PSIG steam. There are 4 boilers and capacity of each

boilers 300,000 lb/hr. DM water capacity for boiler is supplied by Demineralizer Unit – 19.



GUS operating Stations in CCR.



129


10 & CCR.

c) PLC System: Modicon PLC System for Burner Management & Boiler Interlock

Control housed in BMS House.


a) Boiler steam drum level control.

b) Boiler feed water pressure control.

c) Deaerator storage Level / Temperature control.

d) Boiler Load Control.

e) Boiler steam superheat Control.

f) Air flow to Boiler Control.

g) Excess Air Control for Boilers.

h) Master Fuel Trip Interlock for Boilers.



1 O2 / DENSITY &

CONDUCTIVITY ANALYZER ROSEMOUNT-5081 / ROSEMOUNT-2081

C / ROSEMOUNT-IFT 3000 / PEEK-HC 900 10

2 CONTROL VALVE FISHER / MASONEILAN / SAMSON 58

3 CONTROLLER FOXBORO / TAYLOR / MASONEILAN 8






/ AMETEK 82

9 PLC MODICON 4


AM GAUGE 94

11 PRESSURE SWITCH UE / ASHCROFT / SOR / DELTA CONTROL / BOURDON SEDEME

28



LTD 52






130

21.0 UNIT – 22 OVERVIEW (Cooling Water System)


21.1.1 Objective

Cooling Water System Unit 22 consists of a cooling tower and pumps and distribution

network to cater to most of the Refinery cooling water requirement.

21.1.2 Capacity

Unit – 22 is designed to supply 40,000 of cooling water respectively to the units.


The process scheme is shown in the attached Sketch SK-1.

Unit – 22 has three circulating pumps, eight induced draft fans and four sea water coolers

to pre-cool the returning water before entering the Cooling Tower.

From the main cooling water supply headers, the cooled water flows and branches into

individual area/unit headers and is distributed to area coolers and condensers. The warm

water at about 113oF, returning from the area coolers and condensers is routed to the top

of the Cooling Tower through sea water exchangers, where it is cooled to about 102 Deg

F, where it is cooled to about 88oF by the time it reaches the basin. From the basin, cold

water is pumped out to the supply headers with circulating pumps.

The primary source of cooling water make-up is treated distilled water (from the treated

distilled water tanks) which is required to maintain level in the Cooling Tower basins.

Both systems have chemical treatment facility to control corrosion, scaling and biological

growth which will otherwise seriously affect operations.



131






1 Exchangers 02

2 Cooling Tower 01

3 Filters 02

4 Vessels & tanks 01



132


Unit 22 – Cooling water system consists of two cooling towers and distribution network to

cater to refinery cooling water requirement.

All the Rotating equipment in Unit 22 are inspected and maintained as per the guidelines

of Process Licensor & Good Engineering practices. Turn around schedules are fixed as


plant.

Unit 22 has 6 Pumps, 3 Turbines & 8 Fin-fans. List of Rotating Equipment are furnished

vide Appendix 2A hereof.

Pump/Turbine package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals,







of power to the Unit is aided from two substations, Substation # 1A which is the main

SHU intake substation located at north side of the unit and Substation # 18 which is

located north east side of the Unit. The substation 18 is Building with Basement Type &

facilitated as non-classified area by employing pressurized / Air conditioned systems.

Substation has a “6.6kV” Switchgears fed from SS1A & SS1B (ref. drawing # R-00-

6012), a “440V” MCC (MCC-61), a power transformers (1MVA, 6.6kV/440V) and an

Emergency panel. The Substation is equipped with Fire Detection, Alarm & Suppression

system which was installed under contract CB/CSPD/2004 & commissioned on 2016.

Battery Charger along with Battery backup bank are also available.











of 08);



133




Cooling Tower provides cooling water used in Refinery Operation for cooling, condensing

product / process streams and cooling of rotary parts like bearing gland & compressor

jackets etc.


a) DCS SYSTEM: Honeywell make TPS System installed in SIH # 5, SIH # 10.

b) GUS operating Stations in CCR

c) ESD SYSTEM: Honeywell make Safety Manager System installed in SIH # 5, SIH

# 10 & CCR


a) Cooling water basin level control.

b) P-22-01 B/C – Cooling water pump Interlock.



134



1 PH & COUNUCTIVITY

ANALYZER ROSEMOUNT-5081 / SENTRY 4

2 CONTROL VALVE MASONEILAN / JORDAN 9

3 CONTROLLER FOXBORO / MASONEILAN 5





GAUGE 89




LTD 25


ABB / FOXBORO / 14

12 MISC HONEYWELL 9



135

22.0 UNIT – 23 OVERVIEW (Sea Cooling Water System)


22.1.1 Objective

Sea water is utilized for cooling circulating water of Unit – 22 cooling Tower, 50# excess

steam condensers, in Flare Gas Recovery Unit, and as cooling water for Unit – 61. It can

also be used as a source of back-up fire water in emergency.

22.1.2 Capacity

Sea water system is designed to receive 64800 GPM of sea water. Actual sea water

intake is 18000-25000 GPM.



Bot Sea water is supplied to KNPC battery limit by PAI through 72” ID concrete culvert.

Sea water flows in parallel via four 30” inlet lines to the bottom of four parallel sea water

exchangers E-23-01 A/B/C/D tube side for cooling circulating cooling water from Unit –

22 cooling Tower. The outlet of sea water is combined in a 68” ID header and flow by

gravity into the top of Steam Condenser E-29-02 and pass through the tube side for

condensing the Refinery excess 50# steam.

A part of sea water from E-23-01 A/B/C/D outlet header is pumped to Flare Gas

Recovery Unit (FGRU) by pumps P-29-11 A/B as cooling water for surface condenser E-

29-11. Return sea water after heat exchange joins the same E-23-01 A/B/C/D outlet

header at upstream of sea water condenser E-29-02.

Part of sea water is supplied to Unit – 61 as cooling water via 14” header from the main

72” ID header.

Sea water collected in the sea water pit flows back through 60”ID concrete culvert to the

Gulf.

An 18” jump-over is also provided from E-23-01 A/B/C/D suction (72” supply header) as

back-up for the fire water pumps.



136









137

23.0 UNIT – 29 OVERVIEW

(Flare Gas Recovery Unit, Flare System & Instrument / Plant Air System)

23.1 PROCESS OVERVIEW (Flare Gas Recovery Unit)

FGRU was not in original Refinery design. As a pollution control and Energy

Conservation measure, a Flare Gas Recovery Unit was installed and achieved its full

operation on January, 2002.

23.1.1 Objective

FGRU provided for recovery of flared gases and reusing the same as fuel gas after

necessary treatment while releasing a minimum amount of residual flare gas for burning

at the stacks. The import gas (LP Gas, Burgan Gas) used as fuel gas was significantly

reduced. The emission of sulfur dioxides gases to atmosphere is reduced to minimum

level and healthy environment is achieved.

23.1.2 Capacity

The unit can recover 18.7 MMSCFD (Max.) of refinery gases routed to flare header.

However, after a successful program to reduce flaring at Shuaiba Refinery, the total Flare

Gas is reduced drastically, i.e. ~ 7-8 MMSCFD.


Material Balance & Feed, Product Qualities is shown in table-1, 2 & 3


MMSCFD

16.5 From Refinery Process Units

15.3 To Amine Treating Unit (14) *

1.2 To East Flare Stacks Gases to Flare


FEED

Total Refinery Flare Gases

(Feed to FGRU)

PRODUCTS

Recovered Gases in FGRU



138

b) Table-2 : Typical Feed Qualities

Light Normal Heavy Min. MW

68.0 62.7 54.9 77.5

5.0 5.0 5.0 5.0

0.2 0.2 0.2 0.1

3.0 4.2 4.8 2.3

16.3 17.4 18.6 9.4

3.3 4.3 5.2 2.3

2.4 2.8 4.5 1.5

1.4 2.5 4.3 1.4

0.4 0.9 2.5 0.5

100.0 100.0 100.0 100.0

Components % Vol

n-Butane

Total

Methane

Ethane

Hydrogen

Water

Carbon Dioxide

Hydrogen Sulphide

n-Pentane

Propane

c) Table-3 : Typical Product Qualities

Light Normal Heavy

69.81 64.37 56.36

2.47 2.47 2.47

0.21 0.21 0.21

3.08 4.31 4.93

16.73 17.86 19.10

3.39 4.42 5.34

2.46 2.87 4.62

1.44 2.57 4.41

0.41 0.92 2.56

0.0 100.00 100.00 100.00 Total

Components % Vol

Hydrogen

Water

Carbon Dioxide

Hydrogen Sulphide

Methane

Ethane

Propane

n-Butane

n-Pentane

d) Battery Limit Conditions

Feed Temperature 140 Deg FPressure 1.1 PSIG

Product Temperature 110 Deg F

Pressure 40.3 PSIG



139



In the Flare Gas Recovery Unit, the gases released to the Flare system are recovered

through compressor(s) under specially designed control scheme, to ensure that in no

case the flare header is under negative pressure.

The flare gas available in the East flare header knocks off its condensates in the main

flare knockout drum, V-29-01. The flare gas recovery unit is connected to the outlet of

this knock out drum. Additional amount of gas, which cannot be recovered, bubbles

through two water seal drums, V-29-14 and V-29-15, before being burnt in North and

South stacks, ST-29-01 and ST-29-02 respectively. Water seal maintained in the water

seal drums imposes a positive back pressure in the flare header. This provides a means

of directing flare gases either to the recovery system or to the flare stacks, when gas flow

rate exceeds the capacity of the flare gas recovery unit.

A continuous purge of fuel gas maintains a positive pressure at the downstream of the

water seal drums avoiding any possibility of vacuum formation, burn back situation or air

ingress through flare tip.

Sour gases originating from units 14, 61 and 68 bypass the main flare KOD and are

routed to the sour gas knock out drum, V-29-16. This prevent the sour gases from these

units being compressed in the flare gas recovery unit. The condensate, if any, is knocked

out in this drum. The sour gases then pass through a water seal drum V-29-13, and join

main stream of sweet gas header at the inlet of respective stacks. The ammonia vent

header originating from unit 15 is burnt in sulfur plants and the balance is routed to water

seal drum, V-29-13 and to Flare Stacks.

Make up water to seal drums is provided on level control. The liquid level in drums is kept

just below the external seal height so as to avoid any continuous discharge/overflow of

water from seal drums to the drain pit. Provision is kept for manual periodic

skimming/draining of hydrocarbons from above the water surface to avoid a hydrocarbon

build up in the seal drums. Water, when overflows from seal drums, is routed to existing

drain pit.

The Flare Gas Recovery Unit consists of two 50% capacity water injected single stage

screw compressors designed for a capacity of 7320 CFM (9.58 MMSCFD) each, at inlet

condition. One of the compressors is driven by condensing type steam turbine (LP

Steam), while the other is driven by variable speed electric motor. The Surface

Condenser of the condensing type steam turbine is provided with sea water supply

through Sea Water Supply Pumps (P-29-11 A/B) for cooling.

Prior to entering the suction of the compressors the flare gas passes through suction

KOD, V-29-10 for removal of entrained condensate in the flare gases coming from main



140

flare KOD, V-29-01. The KOD, V-29-10, is provided with mist eliminator to allow only

liquid free gases to the suction of the compressors.

In the compressors, the flare gas is compressed from 15.8 psia to 55 psia. After

compression, the flare gas is cooled in the After Cooler (E-29-08 A/B) at individual

compressor discharge using cooling water. Gas from After Coolers combines and enters

discharge KOD (V-29-12) to separate condensate from gas. The gas is then sent to V-

14-01 of existing Amine Unit for further treatment. Condensate generated in the suction

KOD is sent back to main flare KOD through Sour Condensate Pumps, P-29-10A/B while

the same from discharge KOD is pressure transferred to main flare KOD under level

control.



141

23.2 PROCESS OVERVIEW (Flare Gas System)

23.2.1 Objective

The flare system is designed to provide safe release and disposal of combustible, toxic

gases and vapors released from Process equipment during normal operations and/or

upset conditions. The released materials is first routed to Flare knock-out drum where

heavy end and condensable are separated out and residual gases are burnt at elevated

stack. Controlled amount of steam is used at the Flare tip to ensure smokeless burning

and easy dispersion of combustion products.

23.2.2 Capacity

Shuaiba Refinery has three Flare Stacks in two systems, East and West. East Flares ST-

29-01 & 02 have design load of 245,380 lb/hr each. West Flare ST-29-03 which is

generally a stand-by, is designed for 647,000 lb/hr under general power failure case.



Flare system essentially consists of flare K.O. drum and Flare stacks and piping network.

The Flare network includes several headers and sub-headers originating from various

Process Units. The six Flare Headers are routed to the old K.O. Drum. The major 30”

Flare header is connecting both old (East) and new (West) Flare K.O. Drums and also

used by most of the Process Units. Shuaiba has a Flare Gas Recovery Unit (FGRU) for

recovery of Flare Gases and reuse as Fuel Gas. Only a small part, the unrecoverd gases,

is burnt at the Stacks.

23.2.3.1 East Flare System

East flare system consists of flare gas KOD V-29-01, sour gas KOD V-29-16, flare gas

seal drums V-29-14 & V-29-15, sour gas seal drum V-29-13 & two flare stacks ST-29-01

& ST-29-02. Most Flare gases from refinery join in V-29-01 and diverted to Flare Gas

Recovery Unit (FGRU) for recovery of major amount (Ref. Process description of FGRU).

Balance gas is sent to flare stacks ST-29-01 & ST-29-02 via seal drums V-29-14 & V-29-

15.

Sour gas, containing mainly Hydrogen Sulfide, from Unit-14/61/68 is diverted to flare

stacks via KOD V-29-16 & seal drum V-29-13. Ammonia gas from Unit – 15 is directly

routed to sulfur plants with a provision to route to flare stacks via seal drum V-29-13.

23.2.3.2 West Flare System

Normally West Flare is a standby by using a static seal provided at ST-29-03 bottom. In

case of process units major upset, the high rate of gas flowing in the common flare

header exceeds capacity of the East Flare and the common Flare Header gets

pressurized. Consequent back pressure if high enough to break/overcome the static

seal, West Flare comes in action and gas flow is shared by the east and west Flares.



142

All flare stacks are provided with:

Fuel gas purge to prevent air ingress inside the stacks

Pilot burner to ensure flame availability at all times

Facility for reigniting the Stack in case of flame outage


West Flare system which was installed in the year 1978

Flare Gas Recovery Unit was installed in the year 2004.

23.3 PROCESS OVERVIEW (Instrument / Plant Air System



Instrument Air is clean dry air that is supplied to almost all control valves in the Refinery.

Air is withdrawn from atmosphere through a suction filter into a compressor first stage.

The air, then, is passed through an inter cooler, compressor second stage, cooler and a



143

knockout drum receiver. The air then is passed through driers, a filter and then it is

distributed to the refinery.

Instrument air consists of 3 reciprocating compressors (one motor driven and two steam

turbine driven) with capacity 775 SCFM each, 3 air dryers and 2 Filters.

Coupled with this system is the plant air section that consists of 3 electrically driven

compressors (two reciprocating compressors with capacity of 950 SCFM each and one

centrifugal compressor with capacity of 1500 SCFM) to provide plan air to all the Refinery

Units.

The plant air is not suitable (clean and dry) for use as instrument air. It is only used in

general service where dry air is not essential.







144



2 Air Coolers 03


4 Stack 02

5 Compressor accessories - Exchangers 10

6 Compressor accessories – Air coolers 03

7 Compressor accessories - Filters 14

8 Compressor accessories - Tanks 06

9 Compressor accessories - Dryer 03

10 PSVs 25


Unit 29 – Instrument air is clean dry air that is supplied to almost all control valves in the

refinery. Also to maintain supply of Fuel gas required for refinery heaters and boilers.


of Process Licensor & Good Engineering practices. Turn around schedules are fixed as


plant.

Unit 29 has 23 Pumps, 6 Turbines & 4 Engines, 8 compressors. List of Rotating


Pump/Turbine/Engine package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals,





Unit-29 is considered as classified area (Class 1 Div. 2 Group D) as per Shuaiba Refinery


to the Unit is aided from three Substations, SS # 18, SS # 4 & SS # 5A which is located

north east side of the Unit. The substation is Building with Basement Type & facilitated as

non-classified area by employing pressurized / Air conditioned systems. The Substation










145





The Unit-29 is powered from the Substations # 04, 05B & 18 and the Single Line

Diagram (SLD) for SS # 04, 05B & 18 are as follows (for details Refer Annexure-01,

KNPC Sketch # SK-2434 Sheet 01, 03 & 08 of 08);





146



147


23.7.1 Instrumentation System – Flare Gas Recovery Unit

The unit is designed for recovery of flared gases and reusing the same as fuel gas after

necessary treatment. This ensures reduction of toxic gases to minimum level and

achieving healthy environment.

a) PLC SYSTEM: HIMA make PLC System installed in the field with connectivity to

Honeywell make DCS system.

b) BENTLY SYSTEM: Bently 3300 Vibration & Temperature monitoring system for C-

29-04 A & B.

c) WOODWARD GOVERNOR: Woodward Speed Governor System Model 505 for

C-29-04A steam turbine driver Compressor.

23.7.2 Instrumentation System – Flare Gas

The unit is designed to provide safe disposal of combustible toxic gases / vapors

released from process units during Normal / Abnormal on upset conditions.

Flare stacks, ST-29-01, ST-29-02 & ST-29-03 provided to ensure burning of the gases. 6

No’s pilot burners are provided in each stack to ensure flame availability at all times. All

flare stacks are provided with fuel gas purge line.

a) PLC SYSTEM: Siemens make PLC System in local for each flare for Auto /

Manual ignition of Pilot Burners.



148

b) DCS SYSTEM: Honeywell make TPS System installed in SIH # 9, & GUS

operating stations in CCR.

23.7.3 Instrumentation System – Instrument & Plant Air

Instrument Air and plant air is generated in this unit and supplied to all the units in the

Refinery.

Three reciprocating Compressors C-29-04 A, B & C along with driers DR-29-01, DR-29-

01A & DR-29-02 provided for supply of Instrument Air.

Compressor C-29-03 A, B & C are provided for supply of plant air.

a) PLC SYSTEM: Siemens make PLC System for Air Drier Control.

b) DCS SYSTEM: Honeywell make TPS System installed in SIH # 5, SIH # 10 &

GUS operating stations in CCR.

23.7.4 Field Instrument List - Unit-29


1 ANALYZER ROSEMOUNT-5081C / SERVOMAX-1902 2

2 CONTROL VALVE FISHER / MASONEILAN / TYCO / BETTIS 85

3 CONTROLLER FOXBORO / MASONEILAN / GERHARDT / FISHER

12

4 GOVERNER

CONTROLLER WOODWARD-505 1





9 LOCAL INDICATOR ITT BARTON / BROOKS / KROHNE / WISE / AMETEK

138

10 PLC SIEMENS / HIMA 5

11 PRESSURE GAUGE ASHCROFT / WIKA / WISE / GENERAL / AM GAUGE

172

12 PRESSURE SWITCH UE / ASHCROFT / SOR / BOURDON SEDEME

70


14 THERMOWELL THERMO ELECTRIC / TECNOMATIC / TC LTD

132

15 TRANSMITTER ROSEMOUNT / YOKOGAWA / HONEYWELL / ABB / FOXBORO / SMAR

128

16 MASS FLOW METER QURZ 1




149

24.0 UNIT – 35 OVERVIEW (Sulphur Degassing Unit)


24.1.1 Objective

Sulfur Degassing Facilities U-35 (SDF) has been designed to reduced hydrogen sulfide

content in the raw liquid sulfur which is produced in the existing sulfur recovery units

(Units -04 & 74) and in tail gas treating unit ( TGTU U-75). Refined (product) liquid sulfur

is delivered to MINA – AL-AHMADI Refinery (MAA) for farther processing. The principle

is to release the free H2S and accelerate the decomposition of the polysulfides to free

H2S.

The H2S dissolved in liquid phase (free H2S) passes into the gaseous phase by physical

desorption .

24.1.2 Capacity

The SDF unit is able to process the raw liquid sulfur of 600 MT/D. normal capacity is 480

MT/D.

24.1.3 Feed & Products

Refer to the below Table-1 for material balance.

a) Table-1: Feed & Product Qualities:

H2S, wt. PPM PURITY, wt. %

FEED : 300 99.5

PRODUCTS : 15 99.5


The SDF unit -35 sulfur consist of sulfur pit (TK-35-03), Flasher (FL-35-01) and other

relative equipment. The sulfur pit is divided into 3 compartments provided with steam

coils to maintain the liquid sulfur above 250 ˚ F (121 ˚C).

The raw sulfur from the Claus units flows into the first compartment of the pit which has

14.7 hour residence time at the normal feed rate.

Some parts of hydrogen polysulfides (H2SX ) in the raw sulfur will be decomposed to free

H2S by agitation resulting from recycling of liquid sulfur through flasher (FL-35-01)

submerged feed pump (P-35-05 A/B), pumped the liquid sulfur to static Mixer (MX-35-

01).

The liquid sulfur from mixer is discharged to the flasher which installed above the second

compartment of sulfur pit.

The flasher, which is a cyclone type gas/liquid separator, free H2S in liquid sulfur is

evolved with steam by flashing. The separated off gas ( composed of steam & a small



150

amount of H2S) is routed to new (ST-75-01) & old incinerator (ST-04-02). The partition

wall between the first and second compartments of the sulfur pit has some opening at its

bottom which make the degassed sulfur recycle to first compartment. The residence time

in the second compartment is about 7.5 hours based upon the normal flow rate.

In third compartment partition wall height is low that one third of degassed sulfur

inevitably overflows. After residence time 6.6 hours based in normal flow rate, refined

sulfur is continuously pumped ( P-35-06 A/B) up to storage tank (TK-35-271, 272 & 273).

The stored liquid sulfur is delivered to MINA – AL-AHMADI Refinery as product by

product discharge pump (P-35-07 A/B).






1 Vessels and Tanks 05

2 Flasher 01

3 PSVs 02



151

25.0 UNIT – 61 OVERVIEW (Acid Gas Removal Unit)


25.1.1 Objective

Acid gas removal plant treats West Field Gases and West Field Liquid for removal of

Hydrogen Sulfide and Carbon Dioxide using Benfield Solution to provide sweet gas

product to LPG Plant at Mina Al-Ahmadi Refinery. The unit is also designed to treat some

refinery gases after compressing them using C-61-01. The Benfield Solution is a mixture

of Potassium Carbonate (23-30%) and Diethanol Amine (2-3%).

In the Benfield Process, Diethanol Amine is used as an activator for the carbonate

solution.

25.1.2 Capacity

The Unit design capacity is 72.2 MMSCFD of equivalent, i.e. combined Gas and Liquid.

25.1.3 Feed & Products

Refer to the below Table-1 for material balance.

b) Table-1: Feed & Product Qualities:

MMSCFD H2S CO2( BPSD) % VOL. % VOL.

FEED :

West Field Gas 48.5 4.14 11 West Field Liquid (4000) 4.2 5.9 Refinery Gases 15 21 0

PRODUCTS :

Sweet Gas 55 0.07 0.4 Sweet Liquid (2675) 0.06 0.16 Acid Gas 10.3 50.5 44


25.1.4.1 Original Design

West Field Gas and West Field Liquid (currently not processed) coming from the fields

join with the Refinery gases compressed in C-61-01 and enter the Feed Surge Drum.

Liquid and gas feeds are recombined and fed as two – phase mixture to the sweet

product heat exchanger E-61-02, where it is preheated with warm overhead product and

then superheated using 50 psig steam in preheater E-61-05 and then fed to the acid gas



152

Absorber V-61-05. Lean Potassium Carbonate solution is fed to the Absorber at its top

cold circulation section and middle sections hot circulation. The rich solution reaching the

bottom of the Absorber is routed to the Regenerator V-61-06 via the Flash Drum V-61-08.

Absorber pressure is about 370 psig while Regeneration pressure is about 10 psig.

The sweet gas from the Absorber overhead is cooled in E-61-02 by heat exchanged with

feed and then in Sea Water cooler E-61-07 and then collected in the separator V-61-04,

where condensate is separated. Water and hydrocarbons separate out and the Sweet

Water is returned to V-61-08. The Sweet hydrocarbon product is pumped out to mix with

the sweet gas going to Mina Al-Ahmadi for further processing in LPG Plant.

The rich Benfield Solution is regenerated in V-61-06. The solution is regenerated by

reboiling with steam in Reboiler E-61-03 A/B/C/D at reduced pressure. The Lean solution

is collected at the bottom of the column is returned to the Absorber V-61-05. Four

Storage vessels V-61-11 A/B/C/D for the Benfield Solution are provided to absorb any

fluctuations in the Absorber requirements. The unit is provided with three filters F-61-

01/02/03.

The regenerator overhead is condensed in E-61-04 and collected in the Regenerator

Accumulator V-61-07. The acid gases remain uncondensed and leave the Accumulator

to Sea Water cooler E-61-09. These gases are routed to Sulfur Recovery Units for

recovery of Sulfur. Refinery gases, mainly from U-09 and U-05 is compressed using C-

61-01 and mixed with West Field Gas feed to Unit-61. This provides additional LPG

recovery from rich gas which otherwise would be used as Fuel Gas.

Sketch-2 shows the original process flow diagram of Unit-61.



153

25.1.4.2 Feed Filtration Facility

This project was implemented in the unit and put in commission in 2002. This new

system aims to remove dirt, fine corrosion products and sludgy material accompanying

West Field Gas and Liquids causing foaming and major upsets in the unit.

Sketch -1 shows the major equipment involved in Feed Filtration Facility and its general

configuration.



154







2 Air Coolers 03


4 Filters 11

5 PSVs 46



155


Unit 61 – AGRP unit treats west field gases and west field liquid for removal of Hydrogen

sulfide and Carbon dioxide using Benfield solution to provide sweet gas products to MAA.




plant.

Unit 61 has 31 Pumps, 22 Fin fans, 2 Mixers & 1 Compressor. List of Rotating Equipment











of power to the Unit is aided from Substation 18 which is located north east side of the


by employing pressurized / Air conditioned systems. Substation has a “6.6kV”

Switchgears fed from SS1A & SS1B (ref. drawing # R-00-6012), a “440V” MCC (MCC-

61), a power transformers (1MVA, 6.6kV/440V) and an Emergency panel. The Substation












The Unit-61 is powered from the Substations # 18 and the Single Line Diagram (SLD) for

SS # 18 are as follows (for details Refer Annexure-01, KNPC Sketch # SK-2434 Sheet

08 of 08);



156




Unit – 61 processes the feed gas from KOC, H-oil unit (07), Naptha Fractionation Unit

(09) using Benfield process for removal of H2S & CO2 gas present in the gas & liquid

hydrocarbon feed stream. The sweet gas produced is routed to LPG plant in MAA. The

mixture of removed H2S & CO2 gas (Acid Gas) is sent to Sulfur Recovery Units for

production of Sulfur.





10 & CCR.


a) C-61-01 – Feed Booster Compressor Trip Interlock & Control.

b) V-61-03 – Feed Surge drum Interlock & Control.

c) V-61-04 – Sweet gas separator Interlock & Control.

d) V-61-09 – Condensate drum Interlock & Control.

e) V-61-10 – Sour Water Effluent Interlock & Control.



157

f) Oily water sump SU-61-03 Interlock.

g) Area Sump SU-61-01 Interlock & Control.

h) F-61-06 – Filter Separator Interlock.

i) Slog catcher V-61-07 Interlock & Control.



1 H2S / DENSITY & CONDUCTIVITY

ANALYZER

ROSEMOUNT- 2081 C / YOKOGAWA- GD 40T / TELEDYNE- 6000B

5

2 CONTROL VALVE FISHER / MASONEILAN / ELLIOT / SEVERN GLUCON / TOKO VALEX

68

3 LOCAL CONTROLLER HONEYWELL / MOORE / FIELD PAC /

FOXBORO / 15







AMETEK 120


AM GAUGE 286




LTD 119



15 VIBRATION BENTLY NEVADA – 3300 1




158

26.0 UNIT – 62 OVERVIEW (Hydrogen Production Unit)


26.1.1 Objective

Hydrogen Units generate high purity Hydrogen needed in other Refinery Units, e.g. H-Oil,

Isocrackers, Unifiners.

26.1.2 Capacity

The unit is designed to produce 74 MMSCFD of 95% purity Hydrogen.


The feed to the Hydrogen Unit is a mixture of treated Burgan Gas and recycle High

Pressure Flash Gas. Burgan Gas is mainly hydrocarbons, while recycle gas is a mixture

of different Hydrogen rich bleed gases from Hydrogen consuming Units (treated in U-14).

The design product Hydrogen purity is 95% and the maximum Carbon Oxides

specifications is 10 PPMV.

The attached Table-1 indicates the overall material balance for design and test run

conditions.

a) Table-1: Feed and Product Qualities

DESIGN TEST RUN DESIGN TEST RUN

Hydrogen % Vol 39.96 46.40 94.99 94.93 Methane 41.68 30.57 5.01 5.07 Ethane 13.25 8.26 Propane 4.17 10.41 Butane 0.94 4.36 Mol. Wt. 13.86 15.41 2.74 2.73 Lbs/Hr 36667 38920 22165.00 23075.00 MMSCFD 24.09 22.98 73.79 77.08

FEED PRODUCTS



159


The Feed Gas is preheated in Hydrogen Reformer Convection Section and the last

traces of organic and inorganic Sulfur compounds are removed in Zinc Oxide beds.

High Pressure steam is mixed with the treated feed gas and further heated up in the

Reformer Convection Coils before it is introduced into the Reformer Catalyst Tubes filled

with Reformer catalyst. Steam and feed gas hydrocarbons react in the presence of Nickel

catalyst to form Hydrogen, Carbon dioxide and Carbon monoxide. This steam reforming

reaction is highly endothermic, requiring heat energy for reaction.

Waste heat is recovered from the Reformer effluent to produce 900 psig steam and partly

for heating Methanator inlet gas.

The carbon monoxide (with excess steam) in the Reformer effluent is further converted

into Hydrogen and Carbon dioxide in High Temperature and Low Temperature Shift

Convertors. Shift conversion reaction is exothermic, producing heat energy.

The Shift Converter Effluent exchanges heat in the MEA Regenerator Reboilers and

further cooled before it is passed through MEA Absorber. A 20% by Wt.

Monoethanolamine solution is used to absorb carbon dioxide. The Rich solution is

regenerated by heating and flashing at low pressure and the regenerated Lean MEA

solution is pumped back to CO2 Absorber after cooling. A slip stream of Lean MEA

solution is filtered in a mechanical filter and a charcoal filter.

The CO2 Absorber effluent gas is heated and in the Methanator the remaining small

quantities of carbon monoxides & carbon dioxide are converted to methane in order to

meet the product carbon dioxide specification.

The Methanator effluent is heat exchanged with the Methanator inlet gas, further cooled

and sent to Unit-03 for compression.




160







2 Air Coolers 04


4 Heaters 01

5 PSVs 40



161


Unit 62 – Hydrogen units generate and supply high purity and high pressure Hydrogen

needed in other units, H-Oil, Isocrackers, Unifiners.




plant.

Unit 62 has 15 Pumps, 56 Fin fans, 2 Turbines & 1 Compressor. List of Rotating











of power to the Unit is aided from Substation 15/16/17 which is located south side of the

Unit. substation is Building with Basement Type & facilitated as non-classified area by

employing pressurized / Air conditioned systems. Substation has a 3 nos. of 6.6KV

Switchgears(15, 16 & 17) fed from SS1A & SS 1B (ref. drawing # R-00-6012), 8 nos. of

“440V” MCC (MCC-200, 300, 400, 500, 00,700 ,800 & MCC-1 at CCR ) and 8 nos. of

power transformers (1MVA, 6.6kV/440V). The Substation is equipped with Fire Detection,



available.











162

The Unit-62 is powered from the Substations # 08 & 15 and the Single Line Diagram

(SLD) for SS # 8 & 15 are as follows (for details Refer Annexure-01, KNPC Sketch # SK-

2434 Sheet 06 & 07 of 08);





163


Hydrogen Unit Processes mixtures of treated Burgan Gas, High Pressure Flash Gas and

stream to produce Hydrogen. Feed gas and process steam reacts at high temperature

and pressure in pressure of Catalyst to produce Hydrogen Gas.


a) DCS: Honeywell make TPS System installed in SIH #2, SIH # 10. GUS Operating

stations installed in SIH # 2 & CCR.


10 & CCR.






e) P-62 -03A/B MEA Circulation Pump Interlock



1 O2 / H2S & DENSITY

ANALYZER YOKOGAWA- GD 40T / YOKOGAWA- ZR

402T / ABB- 2000 VISTA II GC 4

2 CONTROL VALVE FISHER / MASONEILAN / SAMSON

GERMANY / TYCO / VIRGO 42








/ AMETEK 93


AM GAUGE 179




LTD 129






164

27.0 UNIT – 63 OVERVIEW (H-Oil Vacuum Distillation Unit)


27.1.1 Objective

H-Oil Vacuum Unit processes Unit – 07 Residue (Stripper & Fractionator Bottoms)

separating distillates, i.e. Heavy Diesel, Light Vacuum Gas Oil and Heavy Vacuum Gas

Oil. The old Vacuum Section of H-Oil Unit was abandoned in early 1978 due to capacity

limitation and a new Vacuum Section, Unit – 63, was provided.

27.1.2 Capacity

The Unit is designed to handle 42700 BPSD of feed. The actual Unit throughput is 42-44

KBD with both H-Oil trains in operation. If one H-Oil train is shutdown, the unit operates

at lower feed rate of 28,000 BPSD.


The Vacuum Distillation Unit feed is a combination of 07 Unit Strippers Bottoms and

Fractionation bottoms. If Unit -07 one train is S/D, the feed to Unit 63 will be Unit – 07

stripper bottoms plus fractionator bottoms, in addition to Heavy Vacuum Gas Oil recycle

(normally about 5000 BBLS/Day HVGO) as per minimum flow requirement

Refer to the below Table-1&2 for material balance and Feed & Product qualities.



Feed 44000 100 From unit - 07

Products

Hy. Diesel 9000 20.45 To Unit 13 LVGO 3000 6.82 To Unit 68 HVGO 5000 11.36 To TK-052/Fuel Oil/Recycle Vac. Btms 27000 61.36 To Fuel Oil System




165

b) Table-1: Typical Feed and Product Qualities

H. DIESEL LVGO HVGO VAC. BTMS

Sp. Gravity 0.9868 0.9212 0.9396 0.9402 1.0231

Sulfur % wt. 3.06 1.8 1.9 1.92 3.6

Nitrogen, PPM 3350 1800 1900 2000 4000

Dist. Range , Deg. F 50% @ 975 450 - 840 650 - 920 675 - 950 22 % @ 975

Flash Point , Deg. F -- -- -- -- --

Asphaltenes , % wt. 6.6 -- -- -- --

PRODUCTSSPECS FEED


The Fractionator bottoms and the stripper bottoms from both the H-Oil Trains are routed

to Surge Drum, V-07-50, from where it is pumped by P-07-58 to the Charge Heater, H-

63-01. The charge is heated to a temperature of about 715-730oF before it enters the

Vacuum Tower.

Heavy Diesel and LVGO, drawn as side cuts, pass through Waste Heat Boilers,

Exchangers E-63-01/02/03/04/05, cooled and sent rundown as Diesel Unifiners and

Isocracker Units feed, respectively. Heavy Gas Oil side cut is pumped through E-63-06

for 150 psig steam generation, cooled in Fan Cooler, E-63-08 ,Heavy gas oil is sent to

TK-052 from where it can be transferred to the Fuel Oil Tanks. A portion may be sent in

H-Oil feed as recycle diluents.

Vacuum bottoms from Unit-63 is pumped by Fuel Oil Pumps P-07-09A/B/C and P-07-45

thru the Fuel Oil Cooling System and finally to the Fuel Oil Tanks, where it is blended

with the required cutter stocks( mainly Kerosene) to meet the specification of fuel oil.




166







2 Air Coolers 03


4 Heaters 01

5 PSVs 09



167


Unit 63 – Unit separates distillates, Heavy Diesel, Light Vacuum Gas Oil and Heavy

Vacuum Gas Oil from unit 07 residue under vacuum conditions.




plant.

Unit 68 has 17 Pumps, 10 Fin fans, 4 Turbines & 2 Mixers. List of Rotating Equipment













employing pressurized / Air conditioned systems. Substation has a 3 nos. of 6.6KV

Switchgears(15,16&17) fed from SS1A & SS 1B (ref. drawing # R-00-6012), 8 nos. of





available.




department.







168



07 of 08);




Vacuum Distillation Unit – 63 processes H-Oil stripper & fractionation bottoms to recover

Heavy Diesel, Light Vacuum Gas Oil & Heavy Vacuum Gas oil.



Operating stations installed in CCR.


10 & CCR.


a) HVGO to Unit – 07 – Interlock



169

b) BFW Pump P-63-06A – Discharge Pressure Interlock.

c) H-63-01 – A Cell – Interlock.

d) H-63-01 – B Cell – Interlock.

e) V-63-01 – Vacuum Tower Interlock.



1 02 ANALYZER YOKOGAWA – ZR 402T 1

2 CONTROL VALVE MASONEILAN / VIRGO/ROTORK 31


MASONEILAN 2




7 LEVEL SWITCH MAGNETROL / MOORE / SOR /

JERGUSON / INTRA AUTOMATION 3


/ AMETEK 70


AM GAUGE 105




LTD 69





170

28.0 UNIT – 64 OVERVIEW (Cooling Water System)


28.1.1 Objective

Cooling Water System consists of a cooling tower with three cells and distribution

network to cater to some of the Refinery units cooling water requirement.

28.1.2 Capacity

Unit 64 is designed to supply 24,000 GPM of cooling water respectively to the refinery.


Unit – 64 is across flow cooling tower with two circulating pumps, and three induced draft

fans

Both systems has two segregated pairs of cooling water supply and return headers.

From the main cooling water supply headers, the cooled water flows and branches into

individual area/unit headers and is distributed to area coolers and condensers. The warm

water at about 113oF, returning from the area coolers and condensers is routed to the top

of the Cooling Tower where it is cooled to about 88oF by the time it reaches the basin.

From the basin, cold water is pumped out to the supply headers with circulating pumps.

The primary source of cooling water make-up is treated distilled water (from the treated

distilled water tanks) which is required to maintain level in the Cooling Tower basins.

Both systems have chemical treatment facility to control corrosion, scaling and biological

growth which will otherwise seriously affect operations.




171


Unit 64 cooling tower was installed in the year 1978.






1 Filter 01

2 Cooling Tower 01

3 PSVs 06



172


Unit 64 – Cooling water system consists of two cooling towers and distribution network to

cater to Refinery cooling water requirement.




plant.

Unit 64 has 3 Pumps, 3 Cooling tower fans, 1 Turbine. List of Rotating Equipment are


Pump/Turbine/Cooling tower package auxiliary items (filters, SO/LO Coolers, Gearboxes,







of power to the Unit is aided from Substation 15/16/17 which is located east side of the


employing pressurized / Air conditioned systems. Substation has a 3nos. of 6.6KV






available.



280HP, as LT motor . Unit -68 has a 6.6KV motors and 4 nos. 440V motors. All motors








173



07 of 08);




Cooling Tower provides cooling water used in Refinery Operation for cooling,

condensing product / process streams and cooling of rotary parts like bearing

gland & compressor jackets etc.


a) DCS SYSTEM: Honeywell make TPS System installed in SIH # 5, SIH # 10.

b) GUS operating Stations in CCR

c) ESD SYSTEM: Honeywell make Safety Manager System installed in SIH #

5, SIH # 10 & CCR.

d)



174


a) Cooling water basin level control.

b) P-64-01 A/B – Cooling water pump Interlock.



1 PH & CONDUCTIVITY

ANALYZER ROSEMOUNT- 2081C / ROSEMOUNT-

2081PH 2

2 CONTROL VALVE MASONEILAN 5






8 PRESSURE GAUGE ASHCROFT / WIKA / WISE / GENERAL 20



11 THERMOWELL THERMO ELECTRIC 5

12 TRANSMITTER ROSEMOUNT / YOKOGAWA 4

13 MISC HONEYWELL 3



175

29.0 UNIT – 68 OVERVIEW (Isocracker Unit)


29.1.1 Objective

Isocracker Unit converts a blend of Heavy Gas Oils and Heavy Diesels to lighter and

high-value distillate products like Naphtha, Kerosene/JP-5 and Low Sulfur High Pour

Diesel by hydrocracking process.

Hydrocracking reactions occur at high temperature in the presence of Hydrogen on a

fixed bed catalyst.

29.1.2 Capacity

Isocracker Unit is designed for feed rate of 44000 BPSD. The Unit however is normally

operated at 46000 BPSD. Feed is a mix of Vacuum Gas Oil & Heavy Diesel from Unit-06

and unifined Heavy Diesel from Unit-13. Sometimes H-Oil LVGO is included in the feed

in small quantity.





Feed 46000 100 From Units 06/13/63

Products

Naphtha 6000 13.04 To Unit 10 / Storage JP-5 9000 19.57 To storage High Pour Diesel 10000 21.74 To storage Frac. Bottoms 23000 50.00 To Unit 08 / Storage




176

b) Table-2: Typical Feed and Product Qualities

PRODUCTS

SPEC. FEED NAPHTHA JP - 5 H. Pour Fract. Btms.

Diesel

Gravity API 22.9 60 37.1 34 34 Sulfur PPM / % wt. - / 2.74 <10 <10 <100 <250 Nitrogen, PPM 823 <1.0 <1.0 <1.0 <1.0 Dist. Range , Deg. F EP 1000 120 - 300 330 - 520 510 - 700 680 - 980 Flash Point , Deg. F -- -- 150 >200 -- Smoke Point , MM -- -- 19 -- -- Pour Point , Deg. F -- -- -- 35 90 Freezing Point , Deg C -- -- ( - ) 50 -- Nickel + Van. , PPM Max. <1 -- -- -- -- Fe + Na , PPM Max. <1 -- -- -- -- Asphaltenes , PPM <100 -- -- -- -- Polycyclic Index (PCI) 1050 -- -- -- 150


Isocracker Unit consists of the following three sections: Refer to Sketch SK-1

29.1.4.1 High Pressure Section

Feed from storage is passed thru filters and is pumped by high pressure Feed Pump. It

mixes with recycle gas and the mixture is preheated thru Feed/Reactor effluent

Exchanger and further in the Reactor Feed Heater, H-68-01. The mixture then enters top

of the Reactor, V-68-01. Make-up Hydrogen preheated with reactor effluent in E-68-01

enters (at the bottom) annulus of the reactor and combines with the feed at top of the

reactor. Reactor operates at about 2400 psig pressure and temperature 760 – 820oF.

The reactor consists of four catalyst beds with Isocracking catalyst with provision of inter-

bed recycle gas quenches to control catalyst bed temperatures. The reactor effluent is

cooled by series of Heat Exchangers and Coolers and enters High Pressure Separator V-

68-02, where water, gases and liquid hydrocarbons are separated. A small quantity of

condensate / Ammonical water injected just upstream of the final cooler E-68-04 in order

to combat corrosion due to Hydrogen Sulfide and Ammonia. Water separated in V-68-02

is sent to Ammonical Water Treating Unit.

Gas stream from High Pressure Separator (which is mainly Hydrogen and some

Hydrogen Sulfide) enters the H2S Absorber where H2S is removed by circulating DEA

solution. H2S free gas is then compressed by the Recycle Gas Compressor and recycled

back to the reactor feed and inter-bed quench. In order to maintain system pressure and

hydrogen purity, a small portion of the recycle gas is bled to Unifiners.



177

29.1.4.2 Low Pressure Section

Hydrocarbon liquid stream from the High Pressure Separator is let down to the L.P.

Seperator, V-68-06, operating at about 550 psig. L.P. Separator gas is routed to Amine

Treating Unit, while the liquid stream is let down to the Flash Drum, V-68-10. The

separated gas from this Drum also goes to Amine Treating Unit and the liquid stream,

after preheating with reactor effluent in a Heat Exchanger, enters the H2S stripper, V-68-

11. Superheated steam is introduced at the bottom of the Stripper.

Gas from Overhead Drum of H2S Stripper goes to Amine Treating Unit. The bottom

stream from H2S Stripper is heated through a series of Heat Exchangers and Fractionator

Feed Heater, H-68-02, before entering the Fractionator, V-68-13.

The Fractionator overhead vapors are cooled/condensed in fan Coolers and flow to the

overhead drum. Part of the liquid Naphtha is pumped to the Tower top as reflux and

balance is rundown as product after cooling. Kerosene and Diesel are drawn as side-cuts

thru strippers, V-68-15 & 16, cooled through Heat Exchangers & Coolers and sent to off-

plot finished product storage tanks. The bottoms product after cooling is routed to feed

the second stage Isomax Unit-08. Under alternate mode of operation, the Fract. Bottom

can be fully or partially recycled back to Unit-68 feed or routed to storage for blending.

29.1.4.3 DEA Section

Rich DEA from H2S Absorber, V-68-04, goes to DEA Flash Drum and to the DEA

Regenerator. H2S is stripped out of rich DEA in the Regenerator and sent to Sulfur

Recovery Units. From regenerator bottom, the DEA solution free of H2S, is cooled and

pumped by High Pressure DEA pump back to the H2S Absorber.



178







2 Air Coolers 08


4 Heaters 02

5 PSVs 59



179


Unit 68- Isocracker used to upgrade a blend of heavy Gas Oils & heavy diesel into higher

value products like Naptha, Kerosene, Diesel & JP5 by Hydrocracking.




plant.

Unit 68 has 35 Pumps, 66 Fin fans, 1 Compressor, 5 Turbines. List of Rotating


In 2006, C-68-01 Turbine revamped with revised/improved blades design / internals to

avoid corrosion/erosion & improve the unit performance.

Many Critical pumps packings converted to mechanical seals to the spirit of API 682 to

prevent Gas leakage to environment.










employing pressurized / Air conditioned systems. Substation has a 3nos. of 6.6KV






available.











180



07 of 08);




Isocracker Unit Processes light and heavy Vacuum Gas Oil, Heavy Diesel and Unifier

bottoms in presence of Catalyst and Hydrogen at High Temperature and High Pressure

to produce Light Gases, Naptha, Kerosene (JP-5), Diesel products unconverted Gas Oil

is supplied to Isomax Unit – 08.


a) DCS: Honeywell make TPS System installed in SIH # 1, SIH # 10 with GUS



10 & CCR.

c) FSC System: Honeywell make FSC system installed in SIH # 10 for ROIV

Controls.



181

d) VIBRATION MONITORING SYSTEM: Bently make Vibration Monitoring System

installed for C-68-01 Compressor.

e) PLC System: Siemens make PLC System installed for Feed Filter backwashing

facility


a) Feed Pump P-68-01 & HPRT Interlock

b) P-68-22A – Pump Interlock

c) H-68-02 – Fractionation Feed Heater Interlock

d) H-68-01 – Cell A Interlock

e) H-68-01 – Cell B – Interlock

f) C-68-01 – Recycle Gas Compressor Interlock



1 02 ANALYZER YOKOGAWA-ZR402T / ABB-CALDOS17 5




MASONEILAN 11



6 HMI SIMENS 1



INTRA AUTOMATION 14


AMETEK 138

10 PLC ALLEN BRADLEY-MICROLOGIC-500/

WOODWORD – 505/ SIEMENS 6


GAUGE 198




TC LTD 203



16 VIBRATION BENTLY NEVEDA - 3300 1




182

30.0 UNIT – 74 OVERVIEW (Sulphur Recovery Unit)


30.1.1 Objective

This unit recover elemental sulfur from Acid Gases containing H2S generated in upstream treating units. The process adopted in these units is called Modified Claus Process.

30.1.2 Capacity

The original design capacity of was 600 LT/D of sulfur product, respectively. but under normal operation, sulfur production is 430-460 LT/D. However, after implementation of Oxygen Enrichment Project in 2004, the capacity of the unit increased to 665 LT/D of sulfur product (700 LT/D of sulfur feed) but not operated under Oxygen enrichment mode.



a) Table-1: Original Design: Material Balance

MMSCFD LT/D TYPICAL QUALITY

FEED :

Acid Gas 19.2 768 H2S : 81.2 Vol. % CO2 : 11.0 Vol. % HC : 1.4 Vol. % H2O : 6.4 Vol. %

Combustion Air 42.1 1513

2281

PRODUCTS :

Sulfur - 598 99.5 % wt. Pure Liquid Tail Gas 53.4 1683

2281



183

b) Table-2: Oxygen Enrichment Case: Material Balance

LT/D

FEED :

Acid Gas 1200.0 SWS Off Gas 26.8

Air 629.0

Oxygen 218.0

2073.8

PRODUCTS :

Sulfur 665.0

Tail Gas 1408.8

2073.8

MMSCFD

28.2

47.3

1.3

18.8

5.8

-


Acid gas from upstream treating units is mixed with air and burned in the reaction furnace

(H-74-01). The gas product emerges from the furnace at about 2100oF and passes

through a Waste Heat Boiler (V-74-09), producing 475 psig steam. After leaving the

boiler, the sulfur laden gas enters the first condenser (E-74-01) where sulfur is

condensed and routed to a sulfur sump.

The gas leaving the first condenser is reheated in the first reheater, BR-74-02, by burning

a slip of acid gas feed to reactor inlet temperature of 450oF. Then, reheater effluent gas

passes through the first catalytic reactor (V-04-07A) where additional sulfur is formed.

The Sulfur formed in the reactor is removed on the second condenser (E-74-02) and

routed to sulfur sump. The gas is again reheated in the second reheater (BR-74-03) and

passed through a second catalytic reactor (V-04-07B) for further conversion to elemental

sulfur which is removed in the third condenser (E-74-03). The overall sulfur recovery is

ranging from 92% to 96%. After leaving the third condenser, the tail gas containing traces

of H2S and other sulfur species is sent to Tail Gas Treating Unit (Unit-75) for further

recovery of sulfur. In case of emergency or Unit-75 Shutdown, the tail gas is then routed

to either the new or old incinerator.

The sulfur from Waste Heat Boiler and all condensers is routed to the sulfur sump where

it is kept molten by steam coils. The molten sulfur is then transferred to Sulfur Degassing

Facility (SDF) where dissolved H2S is removed from the sulfur before transferring it to



184

liquid Sulfur storage tanks. From the tanks, it is pumped to Sulfur Flaking Facilities in

Mina Al-Ahmadi refinery for producing solid sulfur.

Note that in Unit-74, 475 psig steam is produced in Waste Heat Boiler and 50 psig steam

in the three condensers.

30.1.4.1 Process Description – Original Design Unit – 74

Refer sketch-1

Unit-74 has the same configuration as unit 04 but differed in some respects:

Unit-74 produced 150 psig steam instead of 900 psig steam in Waste Heat Boiler.

In the third condenser 50 psig steam was not produced, instead Boiler Feed Water

was heated and routed to Waste Heat Boiler and the other two condensers where

150 psig steam and 50 psig steam are produced, respectively.

30.1.4.2 Oxygen Enrichment Project:

This project was implemented in 2004. In this project, Unit-04 and Unit-74 were modified

to increase their capacity to 665 LT/D sulfur product (700 LT/D sulfur feed), under

Oxygen mode. The project is based on the use of Oxygen enriched air (instead of plain

air) to achieve this increase in capacity.

The main changes involved are the change modification of the Reaction Furnaces to be

able to use both air and Oxygen enriched air and the change of Waste Heat Boilers to

produce 475 psig steam in both Units-04 & 74. Also, additional K.O. drum is provided for

SWS gas. New tail gas feedback controller is provided for better adjustment of Air/Acid

gas ratio. A layer of Titania catalyst at the bottom of first reactor and a layer of Oxygen

scavenging catalyst at the top of the second reactor are used.



185






1 Waste heat Boiler 01

2 Heat Exchangers, S&T 09

3 Reactor 01


5 Burners 04

6 Filters 08

7 Seal Pots 11

8 PSVs 15



186


Unit 74 – Sulphur present in crude oil gets converted to hydrogen sulphide H2S during

various refining processes such as reforming, hydrocracking and Unit 74 remove H2S

from other gases to use them in the refining process.




plant.

Unit 74 has 6 Pumps & 1 blower. List of Rotating Equipment are furnished vide

Appendix 2A hereof.

Pumps / Blower package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals,







of power to the Unit is aided from Substation 02 which is located west side of the Unit.


employing pressurized / Air conditioned systems. Substation has 3 nos 6.6 KV

Switchgears (2A, 2B & 2C) fed from SS1A & SS1B (ref. drawing # R-00- 6012), 4 nos. of

440V MCC (MCC-2A, MCC-2B, MCC-2C & MCC-2D), 4 nos. of power transformers

(1MVA, 6.6kV/440V) and an emergency distribution panel (EDB-32-01). The HT

Switchgear section 2A was replaced completely with latest new ABB panels during

GRTA-2011 under contract CS/1955. The Substation 2 will be retained post SHU. The


installed under contract CB/CSPD/2004 & commissioned on 2016. Battery Charger

along with Battery backup bank are also available.



280HP, as LT motor . Unit -74 has a 6.6KV motor and 6 nos. 440V motors. All motors are

under Preventive Maintenance program by maintenance department.





Unit # 74 is powered from retained Substation # 02.



187


Sulfur is recovered from the gas streams containing Hydrogen Sulphide (H2S) using

“Modified Claus Processes” in the Sulfur Recovery Unit – 04. In this process 1/379 of H2S

in the gas stream is burnt with air in the reaction furnace to form SO2. The resulting SO2

then burns with balance H2S to form elemental Sulfur (S) and water in the Vapour Phase


a) DCS: Honeywell make TPS System installed in SIH #8 & GUS Operating stations

installed in CCR.

b) ESD System: Honeywell make Safety Manager System installed in SIH # 8 &

CCR.


a) SWS / Acid gas feed to unit Pressure Control & Interlock.

b) Engine Fuel gas / combustion Air to start up burner Ratio Control & Interlock.

c) Engine Fuel Gas / Combustion Air to Main Burner Ratio Control & Interlock.

d) Trim Air to Reaction furnace Flow Control.

e) 1st Reheat Burner Interlock & Control.

f) 2nd Reheat Burner Interlock & Control.

g) Incineration Interlock & Temp Control.

h) Waste Heat Boiler Interlock & Control.

Note: DCS & ESD System installed in SIH # 8 and CCR are not for sale.



188



1 TAIL GAS ANALYZER AMETEK 1

2 CONTROL VALVE FISHER / MASONEILAN / HOPKINSON UK 37





7 HMI SIEMENS 1




/ AMETEK 101


AM GAUGE 122




LTD 56






189

31.0 UNIT – 75 OVERVIEW (Tail Gas Treating Unit)


31.1.1 Objective

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 Process which is based on the continuation of Claus reaction

between residual H2S and SO2 in a solvent containing Polyethylene Glycol, molecular

weight 400, Salicylic Acid and Sodium Hydroxide. The tail gas also contains organic

sulfur compounds (COS and CS2) that is being hydrolyzed in the TGTU reactor

The produced H2S from the hydrolysis is used in the Claus reaction to produce liquid

sulfur.

31.1.2 Feed and Products Specification

Refer to attached Table-1 and Table-2. The different cases corresponds to the cases of

the Claus units: Air Mode Case and Oxygen Enrichment Mode. Since Oxygen mode is

not employed currently, only Air mode is recited here.



190

a) Table-1: Design Case

Feed Tail Gas (lb/hr) Treated Gas (lb/hr) Sulfur Product (lb/hr)

FEED

H2S 2042.2SO2 1919.4S vapor (S1) 655S liquid (S1) 268.1COS 32.7CS2 155.6H2 0H2O 42353.7CO 0CO2 8237.9N2 116978.1Organic acid 0NaOH 0PEG 0Na elemenet 0

PRODUCTS :

H2S 113.9 0SO2 80.5 0S vapor (S1) 65.2 0S liquid (S1) 0 3619.2COS 19.6 0CS2 132.3 0H2 0 0H2O 43373 0CO 0 0CO2 8261 0N2 116978.1 0Organic acid 3.1 0NaOH 0 0PEG 19.8 2.2Na elemenet 0 0

Total (lb/hr) 172642.7 169046.5 3621.4



191

b) Table-2: Actual Case

Feed Tail Gas (lb/hr) Treated Gas (lb/hr) Sulfur Product (lb/hr)

FEED

H2S 3312.5SO2 3113.3S vapor (S1) 1246.7S liquid (S1) 494.8COS 31.1

CS2 148.1

H2 0

H2O 36954.8

CO 0

CO2 14252.5

N2 110684.2

Organic acid 0

NaOH 0

PEG 0

Na elemenet 0

PRODUCTS :

H2S 115.2 0

SO2 83 0

S vapor (S1) 61.8 0

S liquid (S1) 0 6229.9

COS 18.7 0

CS2 125.8 0

H2 0 0

H2O 38644.9 0

CO 0 0

CO2 14274.5 0

N2 110684.2 0

Organic acid 3 0

NaOH 0 0

PEG 18.7 3.7

Na elemenet 0 0

Total (lb/hr) 170238 164029.8 6233.6


Refer Sketch-1

The unit was commissioned in 2006. The tail gas exiting the Sulfur Recovery Units (U-04

and U-74), merges into one stream and enters at the bottom of the reactor, V-75-01,

where it is contacted with a countercurrent flow of the solvent. The reactor consist of four



192

beds of Intalox saddles, where the gas-liquid is contacted. Above the first bed, a liquid

redistributor is provided for uniform spray of PEG for effective gas liquid contact. The

reactor is equipped with a demister, at the top, to limit PEG entrainment in the off gas

going to the incinerator. The solvent is circulated from the bottom of the reactor to top by

P-75-01 A/B/C and through exchanger E-75-01 that ensures the temperature control of

the reactor. The reactor is also equipped with a decantation system that separated the

liquid sulfur from the solvent and gathered at the bottom of the reactor where the sulfur is

kept in the liquid phase by steam coils mounted at the boot of the reactor. The liquid

sulfur, then, leave the reactor through a seal to a sulfur separator drum V-75-04 which is

also provided with a steam coil. In the sulfur separator, any entrained solvent is

separated. The sulfur separation drum can hold 2 days of production of sulfur. Then, the

sulfur is pumped by batch to degasifier Unit-35. All sulfur lines and valves are steam

jacketed to avoid sulfur solidification.

Catalyst, containing 10% weight of Salicylic Acid and sodium hydroxide, in the reactor is

converted into inactive sodium sulfate salts, insoluble in PEG, that deposits on the

packing and cause a pressure drop across the reactor that tends to increase with time

(hence, water washing of the reactor is required whenever pressure drop reaches to a

level where the unit cannot be operated). A catalyst make-up is required to maintain the

catalyst activity. The catalyst make-up drum is prepared in the mixing drum, V-75-02, with

demineralized water, caustic 32% Wt. solution and organic acid in powder. Another

vessel V-75-03 is provided to allow for easier control of the make-up catalyst quantities

and to hold catalyst make-up when preparing for a new solution in V-75-02. The catalyst

make-up is injected continuously by catalyst pumps P-75-02 A/B into the solvent

circulation pump at the discharge of pumps P-75-01 A/B/C.

31.1.3.1 Incinerator Section – ST-75-01

Refer Sketch 2

The objective of the new thermal incineration system is to convert all sulfur species in the

off gas from U-75 (U-04/74 in case of U-75 by-pass) to SO2 before it is disposed to

atmosphere at safe location. The new incinerator system is provided with Waste Heat

Boiler to recover heat from flue gas for intermediate superheated steam production.

In the incinerator system, air is supplied by two forced draft fans, BL-75-01A/B. BL-75-

01A is driven by steam turbine and BL-75-01B is driven by an electric motor. The steam

outlet from the steam turbine is routed to LP steam network after de-superheated by

BFW in de-super heater DS-75-02.

Off gas from U-75 (Tail Gas U-04/74 in case of U-75 by-pass) is sent to thermal oxidizer,

H-75-01 along with gases from sulfur pits/degasser/vent gases. In case of shutdown or

emergency, gases is routed to the old incinerator, ST-04-02.

Gases and air is mixed and heated in the thermal oxidizer to the required operating

temperature for conversion of sulfur species to SO2. The operating temperature is



193

maintained in a range of 1600oF max., normal 1450oF, and 1430oF min. by controlling air

and fuel flow.

Heat from the gas leaving the oxidizer is recovered by Waste Heat Boiler producing

superheated IP steam. The Waste Heat Boiler consists of pre-evaporator E-75-03, super

heater coil E-75-04, evaporator E-75-05, steam drum V-75-07 and mud drum V-75-08.

The required BFW is supplied from the Refinery network to steam drum V-75-07 under

drum level control. The BFW blow-down from steam drum V-75-07 and from mud drum

V-75-08 is collected in blow down drum V-75-10, where hot BFW blow down is flashed at

LP steam header pressure. The waste heat recovery section cools down the flue gas

from thermal oxidizer before routed to vent stack ST-75-01 for safe disposal.



194






1 Exchangers, shell & tube 11

2 Air coolers 01


4 Heaters 01

5 PSVs 31


Unit 75 – Tail Gas produced in Sulfur recovery units 04 & 74 is further treated in this Unit

to distillates.



195




plant.

Unit 75 has 14 Pumps, 2 Fin fans, 2 Turbine, 1 Mixer & 4 blowers. List of Rotating


Pump/Turbine/Blower package auxiliary items (filters, SO/LO Coolers, Gearboxes, Seals,







of power to the Unit is aided from Substation 20 which is located west side of the Unit.

The substation is Package Type & facilitated as non-classified area by employing

pressurized / Air-conditioned systems. Substation has a 6.6KV Switchgear fed from SS

1A & SS1B (ref. drawing # R-00-6012), 2 nos. of 440V MCC (MCC-75-01 & MCC-75-

02), 2 nos. of power transformers (1MVA, 6.6kV/440V) and an E.D.G control Panel &

emergency MCC (MCC-75-03). The Substation 20 will be retained post SHU. The

Substation is equipped withwith Fire Detection, Alarm & Suppression system installed

under Contract CB/CSPD/2004 & commissioned on 2016. Battery Charger along with

Battery Backup bank are also available.



280HP, as LT motor . Unit -75 has 3 nos of 6.6KV motor and 19 nos. 440V motors. All






Unit # 75 is powered from retained Substation # 20.


Tail Gases produced in Sulfur Recovery Units 04 & 74 is further treated in Tail Gas

Treating Unit to Convert remaining Sulfur compounds to Liquid Sulfur in presence of

Catalyst.



196


a) DCS: Honeywell make TPS System installed in SIH #8A & GUS Operating

stations installed in CCR.

b) ESD System: Honeywell make Safety Manager System installed in SIH # 8A &

CCR.


a) Tail Gas feed to Unit Interlock & Control.

b) Tail Gas feed Pressure High Interlock.

c) Solvent Recycle Pumps P-75-01 A/B/C Interlock.

d) Clauspol Reactor V-75-01 Interlock.

e) Area Sump Tank TK-75-04 Interlock.

f) Area Sump Tank TK-75-04 Interlock.

g) Incinerator Section H-75-01 Interlock & Control.

h) Waste Heat Boiler V-75-07 Interlock & Control.

i) Air Blower BL-75-01A Interlock & Control.

j) Gas Detectors Interlock.



1 TAIL GAS/MULTI GAS &

SO2 ANALYZER AMETEK 880NSL / AMETEK 900D2 / AMETEK

920 5

2 CONTROL VALVE FISHER / MASONEILAN / VIRGO/ROTORK 60


4 LEVEL GAUGE GLASS JERGUSON 2


AMETEK 98


GAUGE 84

7 PRESSURE SWITCH UE 2








197

32.0 UNIT – 60 OVERVIEW (Offsite Piping)

The main pipe rack interconnecting the Processing Units of SHU Refinery is designated

as Unit 60. All pipelines between Units or tank farm traverse through this pipe rack and

no line is routed directly between Units. The Pipe rack has three decks and is of

structural steel construction & fire proofed. Lines enter / exit each unit at one battery limit

directly to this Unit 60 pipe rack.


1 Vessels 01

2 Desuperheater 03

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