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DETAILED FEASIBILITY REPORT FOR

DEBOTTLENECKING OF

BHARAT OMAN REFINERIES LIMITED

REPORT NO: A439‐RP-02-41‐0001

VOLUME 1 OF 1 MARCH 2014

This report is prepared for M/s BORL and it is for use by M/s BORL or their assigned representatives/organizations only.

The matter contained in the report is confidential.

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DETAILED FEASILBLITY REPORT FOR

DEBOTTLENECKING OF



(BORL)

PREPARED BY ENGINEERS INDIA LIMITED

NEW DELHI

EIL JOB NO: A439

REPORT NO: A439-RP-0241-0001

VOLUME 1 OF 1 MARCH 2014

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Copyright DFR for Debottlenecking of

Bharat Oman Refineries Limited

Document No. A439-RP-02-41-0001

Rev A Page 1 of 1

Template No. 5-0000-0001-T2 Rev. 1 Copyright EIL – All rights reserved

COPYRIGHT

This document is copyright protected by EIL and is produced for the client M/S BORL. Neither of this document or any extract from it may be produced, stored or transmitted in any form for any purpose by any party without prior written permission from EIL. Request for additional copies or permission to reproduce any part of document for any commercial purpose should be addressed as shown below: General Manager (PDD) Engineers India Limited 1, Bhikai Ji Cama Place New Delhi- 110066 India Telephone: 011-2676-3323 EIL reserves the right to initiate appropriate legal action against any unauthorized use of its Intellectual Property by any entity.

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Table of Contents of DFR for Debottlenecking of



Rev C Page 1 of 1


TABLE OF CONTENTS

SECTION CONTENTS PAGE

1. EXECUTIVE SUMMARY 1 of Ch 1

2. INTRODUCTION 1 of Ch 2

3. SCOPE 1 of Ch 3

4. DESIGN BASIS 1 of Ch 4

5. MARKET STUDY 1 of Ch 5

6. PROJECT LOCATION 1 of Ch 6 7.

7.1 7.2 7.3

7.3.1 7.3.2 7.3.3 7.3.4 7.3.5 7.3.6 7.3.7

7.4 7.5 7.6 7.7 7.8 7.9

PROJECT DESCRIPTION PROJECT CONFIGURATION TECHNOLOGY OPTION PROCESS DESCRIPTION

CDU/VDU DCU HCU/DHDT MS BLOCK H2 UNIT TREATING UNITS SULPHUR BLOCK

MATERIAL BALANCE UTILITIES DESCRIPTION OFFSITES DESCRIPTION COT/PIPELINE BINA DISPATCH TERMINAL LOGISTICS

1 of Ch 7 1 of Ch 7.1 1 of Ch 7.2 1 of Ch 7.3 1 of Ch 7.3.1 1 of Ch 7.3.2 1 of Ch 7.3.3 1 of Ch 7.3.4 1 of Ch 7.3.5 1 of Ch 7.3.6 1 of Ch 7.3.7 1 of Ch 7.4 1 of Ch 7.5 1 of Ch 7.6 1 of Ch 7.7 1 of Ch 7.8 1 of Ch 7.9

8. ENVIRONMENTAL CONSIDERATIONS 1 of Ch 8.0

9. PROJECT IMPLEMENTATION AND SCHEDULE

1 of Ch 9.0

10. PROJECT COST ESTIMATE 1 of Ch 10.0

11. RECOMMENDATIONS 1 of Ch 11.0

ANNEXURE No of Sheets

1 OVERALL PLOT PLAN 1

2 EQUIPMENT LIST 48

3 PROCESS FLOW SCHEME 74

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List of Tables DFR for Debottlenecking of



Rev A Page 1 of 2


LIST OF TABLES TABLE NO. DESCRIPTION PAGE 1.1 Existing Unit Capacities and Post Revamp

Capacities 3 of Ch 1

1.2 Existing Product Pattern and Post Revamp Product Patterns

4 of Ch 1

1.3 Summary of Modifications Required in Process Units to Achieve 7.8 MMTPA Crude throughput

4 of Ch 1

1.4 Summary of Modifications Required in Utility Systems to Achieve 7.8 MMTPA Crude Throughput

7 of Ch 1

4.1 Product Slate 9 of Ch 4 4.2 Product Specifications 10 of Ch 4 4.3 Existing & Post Revamp Units Capacity 14 of Ch 4 7.1.1 Maximum Achievable Capacity in Various Units 2 of Ch 7.1 7.1.2 Utility System 3 of Ch 7.1 7.1.3 Offsite Tanks 6 of Ch 7.1 7.3.1.1 List of Modified Equipments in CDU/VDU 3 of Ch 7.3.1 7.3.2.1 Theoretical Yields of DCU 3 of Ch 7.3.2 7.3.2.2 List of New/Modified Equipments in DCU 4 of Ch 7.3.2 7.3.4.1 List of New/Modified Equipments in NHT 4 of Ch 7.3.4 7.3.4.2 List of New/Modified Equipments in CCR 7 of Ch 7.3.4 7.3.4.3 List of New/Modified Equipments in Penex Unit 9 of Ch 7.3.4 7.3.5.1 List of New/Modified Equipments in HGU 5 of Ch 7.3.5 7.3.6.1 Modified/New Equipment list for LPG ATU 2 of Ch 7.3.6 7.3.6.2 Modified/New Equipment list for LPG CFC 2 of Ch 7.3.6 7.3.7.1 Modified/New Equipment list for SRU 5 of Ch 7.3.7 7.3.7.2 Modified/New Equipment List for Oxygen

Enrichment 6 of Ch 7.3.7

7.3.7.3 Modified/New Equipment List for SWS I/II 7 of Ch 7.3.7 7.3.7.4 Modified/New Equipment List for ARU 13 of Ch 7.3.7 7.4.1 Overall Material Balance of Refinery 2 of Ch 7.4 7.4.2 Unit Capacities 2 of Ch 7.4 7.4.3 Euro IV MS Specification 3 of Ch 7.4 7.4.4 Properties of Blending Streams of MS Pool 4 of Ch 7.4 7.5.1 Treated Raw Water Requirement 3 of Ch 7.5 7.5.2 Cooling Water Consumption 5 of Ch 7.5 7.5.3 DM Water 6 of Ch 7.5 7.5.4 Instrument Air 8 of Ch 7.5 7.5.5 Plant Air 9 of Ch 7.5 7.5.6 Nitrogen Requirement of the Various Units 11 of Ch 7.5 7.5.7 HP Steam Consumption 12 of Ch 7.5 7.5.8 MP Steam Consumption 12 of Ch 7.5 7.5.9 LP Steam Consumption 13 of Ch 7.5 7.5.10 Estimated Power Consumption 13 of Ch 7.5 7.5.11 Estimated Steam & Power Supply 14 of Ch 7.5 7.5.12 BFW Consumption 15 of Ch 7.5

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List of Tables DFR for Debottlenecking of



Rev A Page 2 of 2


7.5.13 Condensate Balance 16 of Ch 7.5 7.5.14 Overall Fuel Gas Balance 18 of Ch 7.5 7.5.15 Overall Fuel Balance 19 of Ch 7.5 7.6.1 Adequacy of Offsite Pumps 6 of Ch 7.6 7.6.2 Existing Offsite Tanks 8 of Ch 7.6 7.6.3 Existing Offsite Pumps 8 of Ch 7.6 7.6.4 Feed and Intermediate Storage Tanks 9 of Ch 7.6 8.1 National Ambient Air Quality Standards 2009 3 of Ch 8 8.2 Emission Standards For

Furnace/Boilers/Captive Power Plants 5 of Ch 8

8.3 Emission Standards For Sulphur Recovery Unit 6 of Ch 8 8.4 Emission Control For Raod Tank Truck/Rail

Tank Wagon Loading 8 of Ch 8

8.5 VOC concentration 9 of Ch 8 8.6 Monitoring Requirements and Repair Schedule 10 of Ch 8 8.7 Ambient Air Quality Standards in Respect to

Noise 12 of Ch 8

8.8 Standards for discharge of Environmental Pollutants from Petroleum Refineries

12 of Ch 8

8.9 SOx Emissions for Present Refinery Configuration

17 of Ch 8

8.10 SOx Emission for Post Expansion Refinery Configuration

18 of Ch 8

8.11 Year Wise Plantation Details 23 of Ch 8 8.12 Sapling Details 24 of Ch 8 9.1 Comparison Between Different Modes of

Implementation 9 of Ch 9

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Executive Summary DFR for Debottlenecking of



Rev C Page 1 of 9

A 18.01.2010 Issued for DFR SK VS VS

Rev. No. Date Purpose Prepared by Checked by Approved by


SECTION 1

EXECUTIVE SUMMARY

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Document No. A439-RP-0241-0001

Rev C Ch 1 Page 2 of 9


1.0 EXECUTIVE SUMMARY

1.1 INTRODUCTION

Bharat Oman Refineries Limited (BORL) is operating a 6MMTPA Refinery located at Bina, Madhya Pradesh, India, with associated crude receipt and handling facilities, cross country pipelines, marketing terminal etc.

BORL intends to augment the processing capacity of the facilities from present 6MMTPA to 7.8 MMTPA considering low cost debottlenecking. In order to minimize the cost and shutdown time for implementation of project, 30% increase in crude capacity is established and achieved in consideration of minimizing hardware modifications using in-built design margin and no new processing facilities.

BORL presently has the following facilities: - 6MMTPA refinery configuration consisting of Crude and Vacuum

Distillation Unit (CDU/VDU), Delayed Coker Unit (DCU), Integrated Full Conversion Hydrocracker unit (FCHCU) and Diesel Hydrotreating Unit (DHT), MS block comprising Naphtha Hydrotreating Unit (NHT), Continuous Catalytic Reformer (CCR) and Isomerization Unit (ISOM) and other associated facilities such as Hydrogen Generation Unit (HGU), Sulfur Recovery Unit (SRU), Sour Water Stripper (SWS) etc.

- Crude Oil Terminal at Vadinar to receive crude from crude carriers - Cross country Vadinar –Bina Pipeline to transport crude from Vadinar to

Bina refinery. - Bina Dispatch Terminal adjacent to refinery to market the final products

produced from refinery The existing refinery is producing MS and HSD conforming to Euro III/IV specifications by processing of Arab Mix type crudes besides other petroleum products like LPG, Naphtha, Kero, ATF, Petcoke & Sulphur.

1.2 BASIC DESIGN PARAMETERS

Refinery Capacity: 7.8 MMTPA (30% increase in existing capacity of 6.0MMTPA ), 8280 on stream hours. The existing refinery capacity of 6MMTPA can be augmented to annual capacity of about 7.8 MMTPA (about 30% increase over 6.0 MMTPA) considering 8280 hours (345 days) which can be achieved post expansion due to reliability of operations. Crude Blend : 100 % Arab Mix (A 65:35 weight blend of Arab Light and Arab Heavy Assay 2000)

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1.3 OBJECTIVES OF THE STUDY

The objective of the DFR is to establish the adequacy of all existing major equipment for 130% increase in throughput of existing refinery in consideration of following:

Minimum hardware modifications utilizing available design margins Low capital cost with the accuracy of ±20% Short shutdown time ( limited to 40-45days)

1.4 RESULTS OF ADEQUACY CHECK

The unit performance and adequacy of major and critical equipments are evaluated by respective unit’s licensor. The key findings for each unit are summarized below:

1.4.1 PROCESS UNITS

Table 1.1 Existing Unit Capacities and Post Revamp Unit Capacities

Units Existing Capacity (MMTPA)

Post Revamp Capacity (MMTPA)

% Increase in Capacity

Crude / Vacuum Distillation Unit 6.0 7.8 130

Integrated Full Conversion Hydrocracker and Diesel Hydrotreater

1.952/1.637 2.625/2.202

135/135

Delayed Coker Unit 1.357 1.822 134 Hydrogen Unit 0.077 0.098 127 Naphtha Hydrotreater 1.0 1.45 145 CCR Reformer Unit 0.54 0.787 146 Isomerization Unit 0.31 0.56 181 Sulphur Recovery Unit 2 x 180 MTPD 3 x 243 MTPD 202

SWS I & II 125 T/hr & 49 T/hr

162 T/hr/hr & 65 T/hr 130/132

Amine Regeneration unit 470 T/hr of Lean Amine of 25 wt % MDEA

468T/hr of Lean Amine

of 40 % MDEA

ATF Merox 0.55 0.711 129 LPG treating unit 15.5 T/hr 21.66 T/h 140

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Table 1.2 Existing Product Pattern and Post Revamp Product Pattern

Existing Case

Post Revamp case

% Increase in

Production 6 MMTPA 7.8 MMTPA Products ('000TPA) LPG 222 344 55 Naphtha 241 189 (-) 21 Euro III Regular Gasoline 385 0 -

Euro IV regular/Euro V Equivalent Gasoline 400 1242 210

Aviation Turbine Fuel 550 722 31 Kerosene 487 396 (-)18.6 Euro III Diesel 1610 0 - Euro IV/V Diesel 1181 3641 208 Total diesel 2791 3641 30 Coke 410 523 27 Sulfur 109 152 39

The product pattern post revamp corresponds to Arab mix crude slate and will vary in case of heavier crudes like Kuwait, Basra light etc which have comparatively higher pet coke yield and fuel & losses.

The equipment adequacy is based on revamp feasibility studies carried out by Licensors for the respective Licensed units and studies carried out by EIL for the units designed by EIL. A summary of findings of adequacy check on critical equipment in process units is summarized in table below:

Table 1.3 Summary of Modifications Required in Process Units to Achieve 7.8 MMTPA Crude Throughput

Unit Modifications Required for Critical Equipment

CDU/VDU/NSU

A new additional first stage deslater parallel to existing one and second stage desalter.

Minor modifications in the internals of columns e.g replacement of trays with high capacity trays/ change in deck plates/ change in packing .

New amine column and pump for hot well offgas treatment facilities.

Augmentation in heat transfer area and associated modification in the radiant section with additional 16 no of tubes for the crude and vacuum heater.

Replacement of existing pumps e.g crude booster pumps and addition of cooling water booster pump for vacuum column.

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Unit Modifications Required for Critical Equipment Additional shells in existing exchangers like HVGO

CR and additional bays in Ovhd naphtha main condenser and tempered water.

NHT

New auxiliary heater in parallel for naphtha splitter heater.

Tray replacement of naphtha splitter with UOP ECMD trays

Additional six shells of combined feed exchanger. New catalyst charge for the NHT reactor.

CCR

Additional Net gas compressor in parallel to exsiting net gas compressor

Replacement of burners in charge heater and inter heaters.

Additional shells in existing exchangers

PENEX

Additional facilities for achieving 181 % Penex capacity : Lead Lag reactors(2 nos) DIH column and stabilizer column with its

associated systems ( Separator, condenser, reboiler, reflux pump, S/D pump, bottom pump)

Hot combined feed exchanger , cold combined feed exchanger charge heater.

Minor modification in existing reactor w.r.t VLD tray with additional catalyst .

Replacement of DIH column with ECMD trays. Replacement of tube bundle with high flux tubes in

stabilizer reboiler, DIH column bottom and side draw reboiler.

Replacement of exchangers with new larger exchanger e.g methanator heater, hot combined feed exchanger etc.

New refrigeration package for balance capacity.

Integrated FCHCU & DHDT

Change in catalyst in all the HCR reactors and DHT reactor

Replacement of coils in all the Reactor furnaces and fractionators furnace

New Recycle gas compressor New pumps with PRT for the first stage HCR

charge pump Motor and impeller replacement for the 2nd stage

HCR and DHT charge pump with new PRTs Replacement of four exchangers in the HP section Additional banks in the 1st stage Feed filter and

DHT feed filter Additional backwash oil system with vessel, air

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Unit Modifications Required for Critical Equipment cooler and pump in parallel to existing backwash oil system.

Replacement of existing exchangers with new exchangers or provision of additional shells.

Delayed Coker

Replacement of existing tubes of heater with higher metallurgy Inconel800.

New parallel motor driven WGC for the balance capacity

New blowdown ring compressor for blowdown system

Tray modification in coker fractionators, LCGO stripper , absorber, stripper and debutanizer.

New Feed exchanger, new reboilers for stripper ,debutanizer and additional shells for compressor intermediate cooler and discharge cooler .

Additional coke transfer conveyor and additional coke storage facility equivalent to existing capacity.

HGU

New Pre-reformer and LT shift reactor New Technip Parallel Reformer Modifications in convection section of reformer with

replacement of coils and new preheat coil for pre-reformer.

Two additional vessels in the SMR PSA and ROG PSA.

New nitrogen circulation heater and cooler

SRU

One additional sulfur train of capacity 180 TPD with Oxygen enrichment. O2 enrichment is provided with VPSA as source of oxygen enriched air.

O2 enrichment facilities for existing trains to enhance capacity to 243 TPD

SWS-I & II Replacement of trays with high capacity trays in 2nd

stage sour water stripper Additional sour water tanks in both trains.

ARU Replacement of amine regenerator reflux drum.

LPG Amine Treating Unit

Replacement of existing trays with new configuration trays LPG Amine absorber

Replacement of mine settler drum with new drum FG Amine Treating No Modification envisaged

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Unit Modifications Required for Critical Equipment Unit

LPG CFC unit

New 1st stage CFC column , 2nd stage CFC column and 2nd stage CFC separator

New CFC solvent wash contactor and solvent wash separator

New water wash column and coalescer

1.4.2 Utility Systems

A summary of findings of adequacy check on utility systems are summarized in table below:

Table 1.4 Summary of Modifications Required in Utility Systems to

Achieve 7.8 MMTPA Crude Throughput

System Modifications required

Steam and Power

Shortfall in power requirement will be met through grid. An additional Utility Boiler for 160 TPH capacity to supply HP steam at 42 Kg/cm2g to refinery is under implementation.

Cooling Water System

One additional cooling water cell of capacity 4000 m3/hr and one additional pump of capacity of 8000m3/hr are required..

Nitrogen System

One additional chain of 500 Nm3/hr capacity is envisaged.

Raw Water System

One additional Raw water intake pump similar to existing is envisaged. Oil removal facility from Raw water feed to RO-DM is envisaged.

Compressed Air System

One additional LP Air compressor similar to existing compressor is envisaged. Additional Instrument drier (5000Nm3/hr) is also considered.

Flare System No modifications are envisaged.

RO –DM plant One additional bank of RO-I, RO-II, UF, MB train are envisaged.

CPU One additional chain of capacity of 50TPH is envisaged. ETP One additional CRWS and SWS tanks are considered.

1.4.3 Offsite Storage system

All products run down lines from refinery to Dispatch terminal are found adequate for 30% increase in flow of products. An additional 10” H2 line from H2 unit to Hydrocracker is envisaged.

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Storage capacities of all existing feed and intermediate tanks are not sufficient for 30% increase in throughput of refinery i.e. from 6.0MMTPA to 7.8 MMTPA. Total 8nos. of additional tanks in crude, intermediate products and other service like MTBE are considered.

1.4.4 Bina Despatch Terminal

Additional spur with full rake loading facility in existing rail gantry for Naphtha, HSD Euro IV/ EURO V, MS Euro IV/V, ATF and SKO are considered. Facilities are provided to load from both (existing + new) the spurs. For HSD Euro IV, new rail loading facility is considered with rail loading transfer pumps (4 working + 1 standby each with capacity of 300m3/hr), separate header and master meter in the rail gantry.

1.4.5 Crude Transport Facilities (Vadinar Bina Pipeline)

In order to cater to the increased flow of crude (around 30% increase), pumping facilities in existing 24” pipe line will require enhancement along with DRA injection at the mainline and the intermediate pumping stations. Post debottlenecking, additional booster pump and modification in main line pump at 1st intermediate pumping station are envisaged to meet the revamp flow of crude supply at the refinery.

1.4.6 Crude Oil Terminal

Four additional crude tanks, each of 60000 m3 capacity and associated facilities are envisaged at the crude oil terminal.

1.5 ENVIRONMENTAL EMISSIONS The stipulated SOx emission limit is 30 TPD for Bina refinery. For the enhanced capacity of 7.8 MMTPA, SOX emissions are estimated to remain within the maximum limits. This is possible as a result of various measures taken-up during the design of the project, such as fuel gas maximization, use of only low sulphur fuel oil in furnaces, upgrading of sulphur recovery facility, increase of amine strength etc.

1.6 CAPITAL COST ESTIMATE

The estimated capital cost for the revamp of refinery is Rs.` 2518.99 Crores’. The costing indicated as above is based on the following

The above cost estimates have an accuracy of ± 20%. Validity of the above cost is as of 4th Qtr. of 2013. The project has been assumed to be executed on conventional mode.

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1.7 RECOMMENDATIONS

The Bina refinery capacity can be increased from 6MMTPA to 7.8 MMTPA considering modifications as enumerated in the report. The desired capacity increase is proposed to be achieved by exploiting the available over design margins, limited hardware modifications in the existing process units, utilities and offsites, low capital investment and reasonably short shutdown time of 40-45 days.

The total estimated capital cost for the project is Rs. `2518.99 Crores’. The cost estimates has an accuracy of ± 20% & the validity of the above cost

is as of 4th Qtr. of 2013. Overall project implementation is scheduled within 36 months from zero date

(date of award of contract to EIL) with refinery shutdown period of maximum 45 days.

Refinery revamp for capacity increase beyond 7.8 MMTPA will require major modifications in practically all the process units namely CDU/VDU, HCU/DHDT & DCU besides augmentation of the existing Utilities and Offsites facilities and may also warrant evaluation of new plants.

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Introduction DFR for Debottlenecking of



Rev B Ch 2 Page 1 of 3


SECTION 2

INTRODUCTION

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2.0 INTRODUCTION

Bharat Oman Refineries Limited (BORL), is operating a 6MMTPA Refinery located at Bina, Madhya Pradesh, India, with associated crude receipt and handling facilities, cross country pipelines, marketing terminal etc. Bharat Oman Refineries Limited (BORL) proposes to enhance the crude processing capacity of the refinery from present 6 MMTPA to 7.8MMTPA through low cost capacity expansion utilizing the available design margins thus minimizing the hardware cost & shut down time for revamp. The existing refinery is producing MS and HSD conforming to Euro III/IV specifications by processing of high sulfur Arab Mix type crudes besides other petroleum products like LPG, Naphtha, Kero, ATF, Petcoke & Sulphur. The processing facilities at the Bina refinery primarily consist of the following units: • Crude and Vacuum Distillation unit • Integrated Hydrocracker and Diesel Hydrotreater unit • Delayed Coker unit • Hydrogen plant • MS block (NHT/CCR/ISOM) • Matching product Treating facilities • Sulphur recovery unit • Utilities & Offsites including Captive Power plant. • COT, VBPL and BDT

The refinery block diagram is as shown below:

The crude oil is received at the refinery through 24” dia, 937 Km long cross country crude pipeline from Vadinar, District Jamnagar, Gujarat.

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2.1 LOW COST DEBOTTLENECKING PROJECT Under this project, BORL intends to augment the processing capacity of Bina refinery from present 6MMTPA to 7.8MMTPA considering low cost debottlenecking. In order to minimize the cost and shutdown time for implementation of project, 130% increase in crude capacity is established and achieved in consideration of followings: Minimizing hardware modifications using in-built design margin No New processing facilities

As a first step to achieve the above objectives of project, preliminary feasibility report was prepared to establish the order of magnitude cost for debottlenecking of refinery. This was followed by maximum capacity test run conducted by BORL in the existing process units to identify the hardware bottleneck and other operating constraints In order to estimate the capital investment within accuracy of ± 20% and to establish the implementation plan for 130% increase in crude processing capacity with minimum modifications, BORL has retained EIL’s services to prepare detailed feasibility study report for low cost debottlenecking of Bina refinery.

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Scope DFR on Debottlenecking of





SECTION 3

SCOPE

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3.0 SCOPE OF WORK

The scope of Detailed Feasibility Report is to estimate capital cost of project with accuracy of ± 20% and tentative schedule for overall project implementation to achieve the processing objective of sustained refinery operation at 7.8MMTPA crude throughputs through low cost expansion. The design crude for the revamp is maintained same as the original design crude i.e, 65:35 AL:AH (by wt). In addition, environmental considerations and implementation philosophy for this project are studied and included in report.

3.1 DETAILED FEASIBILIT REPORT

The report consists of the following:

1. Design basis 2. Project configuration 3. Process description 4. Overall Material Balance 5. Process flow diagrams 6. Equipment lists 7. Requirement of raw material(crude), Utilities, Chemicals, Catalysts, Off-sites

and auxiliary facilities. Transportation logistics raw material & products

8. Environmental Considerations 9. Utilities and offsites facilities: 10. Identifying tankage, silo / warehouse requirement for intermediate and final

products including requirements for raw materials / feed streams. OSBL (Outside battery limit of process units) facilities including dispatch facilities for products, effluent treatment facilities, power and steam generation system, fire-fighting system etc.

11. Project Capital Cost

Preparation of cost estimates with ± 20% accuracy Estimated basic design and engineering fees, License / know-how fees,

list & estimated cost of proprietary items (if any), commissioning and training fees based on quote from Licensors / Consultants’ in-house data for similar projects in recent past.

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Estimated consultancy fees for carrying out detailed engineering, procurement, inspection and expediting of equipment/materials, construction supervision, etc.

Estimates for civil, electrical materials, piping, structural, instrumentation materials.

Capital cost breakup as foreign exchange component and indigenous component.

12. Project implementation strategy and project schedule along with bar chart. 13. Conclusion & Recommendations. 14. Overall Plot plan.

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Design Basis DFR for Debottlenecking of




Template No. 5-0000-0001-T2 Rev. 1

Copyright EIL – All rights reserved

SECTION 4

DESIGN BASIS

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4.0 DESIGN BASIS

Design basis considered for Debottlenecking of Bina Refinery project is detailed in Section 4.1.

4.1 BASIC DESIGN PARAMETERS FOR DEBOTTLENECKING OF BINA

REFINERY PROJECT Study to be Done by EIL FR DFR Other Execution Methodology for Project LSTK CONV HYBRID Project Duration required in Months Shall be Evaluated

4.1.1 Other Studies By EIL By Others Remarks 1 Rapid Environmental impact study Not the part of DFR. Being done

under separate job by EIL. 2 Site evaluation/selection Existing refinery area.

3 Evaluation/Selection of licensors Study report for units prepared by individual unit licensors / designers.

4 Rapid Risk analysis RRA study and data collection are included in EIL scope but not in scope of DFR. RRA and EIA studies are being done by EIL as a separate job.

5 Route survey (for transport of ODC materials from various ports / industrial areas of the country.)

As per existing data.

Marine Survey-effluent dispersion study As per existing data. 6 Downtime assessment report (For

Revamp) Only one Shutdown is envisaged and shutdown time is targeted to be approximately 45 days for all modifications.

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4.1.2 Plant Location Village City State Nearest Railway

Station Agasod BINA M.P Bina

4.1.3 Land Availability Details (Refer existing plot plan) Plot Area Road 1. Khasra Map, Land Survey map to be furnished.

Length of connecting road (between site and existing main road). Kms

As per existing plant

2. Soil investigation, site details like Extent/cost of land filling/ piling data, if available may be furnished.

Rerouting Requirement Rerouting of any existing facilities like road, power lines, drains etc. required/ not required (if required, details of the same may be furnished).

Rerouting of existing facility shall be considered as required

3. Land Rate (Rs per acre) Not applicable

Met Data As per existing plant

4. Land availability: Not Applicable

Grid power availability

Nearest Dist Sagar

Grid augmentation for 220 kV is envisaged to receive 125 MW power

Level 220kV

4.1.4 Raw Material Name A. Design case: Crude Mix

For Overall Material balance across the refinery: The Arab Mix (65:35: AL: AH) crude based on Assay 2000 of AL&AH is considered Feed for specific units shall be as per the existing design basis of the corresponding unit.

Source Pipeline

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4.1.5 Products Name

Product names, its slate post revamp and their specifications are detailed in Section 4.2, and 4.3.

Annual Capacity Market Place (preferred)

4.1.6 Plant Units Process Units

Capacity Utilities to be generated

Capacity Catalyst / chemicals Name Quantity Unit Rate

a) Existing unit capacity and post revamp capacities are given in Table

4.3 at the end of this chapter. b) New utilities to be generated for post revamp capacity are detailed in

section 4.1.10. Catalyst and chemicals consumption will increase proportionately depending on post revamp capacity

4.1.7 Offsite, Raw Material/ Product And Other Storages Optimal storage for new facilities will be considered based on existing best practices in refinery project. Details of existing tanks data is detailed in Annexure 4.1 at the end of this chapter. Materials Raw Material Intermediate Products Finished Products Name State

Liquid/ solid

No of days of storage

Name State Liquid/ solid


Name State Liquid/ solid


4.1.8 Hook Up Connection Name Distance of connection from existing facilities

Not Applicable as not in DFR scope. (Shall be done during design stage)

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4.1.9 Product Evacuation by Railway / Truck/ Pipeline Product Name

% of product to be moved by rail

% of product to be moved by road

% of product to be evacuated through Pipeline

% of product to be evacuated through Coastal movement sea tankers.

As per existing plant, Details are given in Annexure 4.1 at the end of this chapter. However new pet coke rail and truck loading facility is considered Length of rail to be laid/ distance between plant and railway siding

As per existing

Details of any major crossing (river/road/rail) coming on the way to Railway station to be considered as part of Project cost.

As per existing

4.1.10 Utilities For Debottlenecking of Bina Refinery Project, New utility facilities are considered which will be integrated with existing utility facilities.

4.1.10.1 Raw Water For Plant Operation Source As per existing plant Distance from river/sea As per existing refinery Raw water Analysis (if available)

As per existing plant

The existing raw water system will be adequate for 30% increase in crude throughput with additional pump similar to existing capacity.

4.1.10.2 Electric Power For Plant Operation Source CPP+Grid Volts At Design Stage Frequency At Design Stage Captive Power to be generated

As required

Level of Generation As per existing

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In case this is not available, whether a system is to be designed /included in execution.

The power requirement after post expansion is proposed to be met through existing CPP and from augmented grid (Grid augmentation for 220 kV is envisaged to receive 125 MW power).This shall be further reviewed during detailed feasibility study.

4.1.10.3 Construction Power Available Yes Volts 415/230 V AC LT supply KM away Within existing refinery Contract Demand Charges Power available within the plant will be used as

construction power. Energy charges Minimum energy charges (as % of Contract Demand)

4.1.10.4 Construction Water Available Yes KM away Within existing refinery

4.1.10.5 Cooling water The Refinery cooling tower capacity is inadequate as per prefeasibility report. Cooling tower fill replacement shall be considered only if this option avoids additional cooling tower. Cooling tower fill replacement shall be checked against requirement of new cooling tower after additional cooling water requirement is worked out.

4.1.10.6 Nitrogen system The nitrogen consumption is expected to change post refinery expansion to 7.8MMTPA. Hence one additional N2 chain of 500 Nm3/hr capacity is envisaged, shall be confirmed during detail feasibility study.

4.1.10.7 Air System In the post expansion scenario to 7.8 MMTPA, the instrument air and plant air requirements are expected to increase marginally. One LP air compressor identical

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to existing air compressors (8824.39 Nm3/h capacities) is to be evaluated for DFR. Existing two number instrument air driers are being operated at 50% load. Additional instrument air drier is to be considered.

4.1.10.8 Steam system To meet the steam requirement during post expansion, steam balance will be worked out during detail study. BORL is presently installing one additional 160TPH utility boiler in view of revamp scenario. Capacity of existing CFBC boilers shall be considered as 225 TPH. 4.1.10.9 DM Water One additional bank for RO-DM plant (One additional bank of RO-I, RO-II, UF, MB train) of existing capacity is considered to cater additional DM water requirement. Additional oil removal facility from Raw water feed to RO-DM is considered. One additional cooling tower blow down storage tank and one additional feeding pump for blow down of cooling tower is considered.

4.1.10.10 Condensate system No surplus capacity is available in condensate treating unit. Additional train of condensate treating unit shall be considered for the additional units. 4.1.10.11 Flare Flare load mitigation strategies will be implemented during Basic engineering phase to minimize any hardware modifications in the flare systems. Modification in existing seal drum shall be considered for low flow scenario. Flare adequacy shall be checked at 7.8MMTPA throughput

4.1.10.12 ETP The adequacy of existing ETP will be checked for 7.8 MMTPA refinery operation as per DFR study. One additional CRWS & SWS tank of existing capacity is considered.

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4.1.11 Environmental Requirement 4.1.11.1 Effluent Specifications Liquid Effluent MINAS ( Minimum National Standards)/State

Pollution Board Standards. Required facilities for Zero Liquid effluent discharge shall be considered.

Gaseous Effluent MOEF ( Ministry of Environment and Forest) guidelines/State Pollution Board. As per BORL Input max SO2 emission : 30 TPD After expansion as per PFR SOX emissions are estimated as 29.95 TPD which is in the limits of maximum permitted SOX emission from Bina Refinery. This shall be further worked out during detail feasibility report.

Soild Waste Disposal of hazardous waste as per guidelines Stack height (Limitation to be specified)

As per existing

Location of effluent discharge & its distance from B/L of plant

As per existing refinery standard

Note: Details to be furnished below in case State Pollution Board specifications exist 4.1.11.2 Green Belt Requirement As advised by State Government during site selection visit.

The Green belt forms an integral part of the approach to improve the environmental quality and aesthetics of the plant area. As debottlenecking would not require additional area to be acquired, existing green belt area shall be maintained.

4.1.12 Township No new facility envisaged.

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4.2 PRODUCT SLATE After implementation of the low cost expansion of refinery, the product slate considering present products specifications is tabulated below: This product slate will be further optimized and estimated based on yields received from licensors for revamp case as well as test runs data received from BORL.

Table 4.1: Product Slate (Shall be confirmed in DFR)

Product

Existing Case (6 MMTPA) Capacity

KTPA

Post Revamp Case

(7.8 MMTPA) Capacity

KTPA

% Increase in

Production

LPG 222 344 55 Naphtha 241 189 (-) 21 Euro III Regular Gasoline 385 0 - Euro IV/V Regular Gasoline 400 1242 210 Aviation Turbine Fuel 550 722 31 Kerosene 487 396 (-)18.6 Euro III Diesel 1610 0 - Euro IV /V Diesel 1181 3641 208 Coke 410 3641 30 Sulfur 109 523 27

4.3 PRODUCT SPECIFICATIONS

The product specifications (Manufacturing Specifications) adopted for this Project are given as under.

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A. Liquefied Petroleum Gas (LPG): Note:

1. "Pass" test indicates Hydrogen Sulfide not more than 5 ppm. 2. Product shall contain minimum 10 ppm Mercaptans as Sulphur at the first

dispatching location to ensure the detection of odour. B. Naphtha

TEST SPECIFICATION

Vapour Pressure @ 40°C, KPa Max. 1050 (152 psi)

Free-Water Nil

Hydrogen Sulphide, ppmw (1) Pass

Mercaptan sulphur, ppmw (2) Max. 150

Copper Strip Corrosion (Bomb) 1 hr. @ 38°C Max. No. 1 Strip

Volatility : Evaporation Temperature for 95%v, °C Max. 2

TEST UNIT SPECIFICATION Distillation IBP, Min Deg. C 40 - 45 FBP, Max Deg. C 160 Sulphur (Total), Max ppm 100 Aromatics, Max % vol. 10 Olefins, Max % vol. 0.2 Density @ 15 deg.C gm/ml 0.66-0.72 Lead Content, Max ppm 1 Residue on Evaporation, Max 100 ml 2

RVP @ 37.8 Deg. C, Max. Kg/cm2 0.7 Net Cal Value, Min Kcal/kg 10200 Chlorides, Max ppm 0.2 Arsenic & Other (Sb,V,Hg,P) Catalyst Poisons ppm Absent

C/H ratio - 5.3 - 5.6 Paraffins + Naphthenes % vol. 80 - 90 Water Content ppm Absent

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C. EURO IV/V Gasoline

*For Rail and Road dispatch

CHARACTERISTICS UNIT REQUIREMENTS

Unleaded Regular Euro IV

BS 4+ ( Equivalent to EURO V)

Colour, visual Orange Orange Density @ 150C kg/m3 720-775 720-775 Distillation : a) Recovery upto 700C (E 70) % volume 10-45 10-45 b) Recovery upto 1000C (E 100) % volume 40-70 40-70 c) Recovery upto 1500C (E150) % volume 75 min. 75 min. d) Final Boiling Point (FBP), max 0C 210 210 e) Residue, max. % volume 2 2 a) Research Octane Number (RON), min 91.7/91.4* 91.7/91.4* b) Motor Octane Number (MON), min. 81 85 Gum content (solvent washed), max. mg/100 ml 5 5 Oxidation stability, min. minutes 360 360 Sulphur, total, max. mg/kg 50 10 Lead content (as Pb), max. g/l 0.005 0.005 Reid Vapour Pressure (RVP), max. kPa 58 60 Vapour Lock Index (VLI) a) Summer, max 750 750 b) Other months, max 950 950 Benzene Content, max. % volume 0.96 0.96 Copper strip corrosion for 3 hr. @ 500C, max. rating Class 1 Class 1

Olefin content, max. % volume 21 18 Aromatics content, max. % volume 34 34 Oxygen content, max % mass 2.7 2.7 Oxygenates Content : % volume a) Methanol, max % volume 3 3 b) Ethanol, max. % volume 5 5 c) Iso-propyl alcohol, max. % volume 10 10 d) Iso-bytyl alcohol, max % volume 10 10 e) Tertiary-butyl alcohol, max % volume 7 7 f) Ethers containing 5 or more carbon

atoms per molecule, max % volume 15 15

g) Other Oxygenates, max % volume 8 8

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D. EURO IV/V Diesel CHARACTERISTICS UNIT REQUIREMENTS EURO IV EURO V Ash, max. % mass 0.01 0.01 Carbon residue (Ramsbottom) on 10% residue, max.

% mass 0.3 without additives

0.3 without additives

Cetane number (CN), min. 51 54 Cetane Index (CI), min. 48 51 Distillation : 96% vol. Recovery at 0C, max.

0C 360 360

Flash point : a) Abel, min. 0C 35 35 Kinematic viscosity @ 400C cst 2.0-4.5 2.0-4.5

Density @ 150C kg/m3 822.5-845 822.5-845 Total sulphur, max. mg/kg 50 10 Water content, max. mg/kg 200 200 Cold filter plugging point (CFPP)

a) Summer, max 0C 18 18 b) Winter, max 0C 6 6 Total contaminations, max. mg/kg 24 24 Oxidation stability, max. g/m3 25 25 Polycylic Aromatic Hydrocarbon (PAH), max. % mass 11 8

Lubricity, corrected wear scar diameter (wsd 1,4) @ 600C, max.

microns 440 440

Copper strip corrosion for 3 hrs. @ 500C, max. rating Class-1 Class-1

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E. SUPERIOR KEROSENE TEST SPECIFICATION Acidity, inorganic Nil Burning Quality : a) Char value. mg/kg of oil consumed Max. 20 b) Bloom on glass chimney Not darker than grey Colour (Saybolt), Min. +10 Copper Strip corrosion for 3 hrs. at 50°C Not worse than No. 1 Distillation : a) Percentage recovery below 200°C Min. 20 b) Final boiling point,°C Max. 300 Flash Point (Abel), °C Min. 39 Smoke Point, mm. Min. 18* Total Sulphur, %wt. Max. 0.235** Conforms to BIS : 1459 - 1974 * For supplies of Defence & railway signal lamps, smoke point of the product shall be minimum 22 mm. Under the emergency IS Specifications for kerosene, smoke point for general supplies has been relaxed to minimum 18 mm. ** For supplies to Defence, total sulphur content percentage by weight of the product shall be 0.20 max.

F. AVIATION TURBINE FUEL

TEST SPECIFICATION Density @ 15°C, kg/m3 Min. 775 Max. 840 Appearance Clear Mercaptan Sulphur, %w Max. 0.0020 Copper Strip Corrosion(2 hr@ 100°C) Max. No.1 strip Sulphur, Total %w Max. 0.235 Flash Point (Abel), °C Min. 39 Viscosity (Kinematic) @ -200C, MM2/S Max. 8.0 Freezing Point, °C Max. -47 Total Acidity, mg KOH/g Max. 0.015 Aromatics, %v (3) Max. 20.6 Olefins, %v Max. 5 Smoke Point, mm Min. 19 Naphthalene content, %v Max. 3.0

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Calorific Value, net Cals/kg Min. 10,225 Existent Gum (Steam Jet), mg/100 ml Max. 7 10% volume recovered @ °C Max. 205 FBP, °C Max 300 Anti-Oxidant (Active Ingredient) mg/litre Max. 24.0 Doped Fuel, pico-siemens/meter Max. 450 Lubricity Max. 0.77 # CONFORMS TO BIS SPEC IS:1571-2001 and DEFSTAN 91-91/ISSUE 4 # The requirement to determine lubricity as per IS 1571-2001 applies only to ATF containing more than 95% hydroprocessed material where atleast 20% of this is severely hydro processed. Defence requirement to be met at 0.65 mm, Max. To meet this requirement, approved Lubricity Additive as mentioned in 4.2.4 of IS:1571, 2001 to be added by appropriate agency before being inducted into the aircraft.

4.4 EXISTING & POST REVAMP UNIT CAPACITIES

Design Capacities of existing units and expected capacities post revamp are tabulate below in table 4.3:

Table 4.3: Existing & Post Revamp Units Capacities

Units Capacity (MMTPA)

Post Revamp Capacity(MMTPA)

Licensor

Crude / Vacuum Distillation Unit 6.0 7.8 EIL


1.952/1.637 2.625/2.202

CLG

Delayed Coker Unit 1.357 1.822 ABB Lummus

Hydrogen Unit 0.077 0.098 Technip Naphtha Hydrotreater 1.0 1.45 UOP CCR Reformer Unit 0.54 0.787 UOP Isomerization Unit 0.31 0.56 UOP Sulphur Recovery Unit 2 x 180 MTPD 3 x 243 MTPD EIL SWS I & II 125T/h &49 T/h 162 T/hr/hr & 65 T/hr EIL Amine Regeneration unit

470 T/hr of Lean Amine

468T/hr of Lean Amine of 40 % MDEA

EIL

ATF Merox 0.55 0.711 UOP LPG treating unit 15.5 T/Hr 21.66 T/hr EIL

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Annexure 4.1 OFFSITE FACILITIES

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1. EXISTING STORAGE TANKS

Details of existing storage tanks in Refinery area is given as under

S No. Service

Pumpable Volume( Vol in between

LLL and HLL of Tank)

Type of Tank**

Tank Size D X H

Current M3 Meter

1 CRUDE 3 54500 FR 68 X 20 2 VGO 3 15797 CR 40 X 14 3 HCGO 2+1 5220 CR 26 X 11 4 VR (DCU

FEED) 2+1 12721 CR 40 X 12

5 DHDT FEED 3 12825 CR 38 X 13.5 6 NHT FEED 1 25971 FR 52 X 15.3 7 CCR FEED 1 3857 CR 24 X 11 8 HGU FEED 1 3813 DR 20 X 14 9 DRY SLOP 1+1 2116 FR 18 X 12

10 BLACK SLOP

1 1830 CR 14 X 13.3

11 ISOMERATE 2 3813 DR 20 X 14 12 REFORMAT

E 1 8418 FR 30 X 15

13 CDU/VDU IFO

2 1293 CR 14 X 10

14 REFINERY IFO

2 1615 CR 14 X 12

15 CRUDE/WATER

1 1200 CR 14 X 10

16 HCU LT NAPHTHA

1 3813 DR 20 X 14

17 LCGO 1+1 4565 & 12825

CR 24 X 12 & 38 X 13.5

18 MTBE 1 3813 DR 20 X 14 19 COKER

NAPHTHA 1+1 3850 CR 24 X 11

** FR: Floating Roof, CR: Cone Roof, DR: Dome Roof

(Two MS tanks of existing capacity are envisaged after post revamp)

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Details of existing storage tanks in BDT area is given as under

Sr. No. Service Product

Pumpable Volume in KL

(Vol in between LLL and HLL of

tank)

Type of

tank* Tank Size

1 01A HSD - EURO III 14926 CR 34m x 18m 2 01B HSD - EURO III 14937 CR 34m x 18m 3 01C HSD - EURO III 14928 CR 34m x 18m 4 01D HSD - EURO III 14871 CR 34m x 18m 5 01E HSD - EURO III 14925 CR 34m x 18m 6 01F HSD - EURO III 14880 CR 34m x 18m 7 02A HSD - EURO IV 14869 CR 34m x 18m 8 02B HSD - EURO IV 14880 CR 34m x 18m 9 02C HSD - EURO IV 14855 CR 34m x 18m

10 02D HSD - EURO IV 14934 CR 34m x 18m 11 02E HSD - EURO IV 14850 CR 34m x 18m 12 02F HSD - EURO IV 6885 CR 26m x 14.5m 13 03A MS - EURO III 10200 FR 34m x 16m 14 03B MS - EURO III 10200 FR 34m x 16m 15 03C MS - EURO III 10200 FR 34m x 16m 16 03D MS - EURO III 10200 FR 34m x 16m 17 03E MS - EURO III 10200 FR 34m x 16m 18 03F MS - EURO III 5400 FR 26m x 14.5m 19 04A MS - EURO IV 10200 FR 34m x 16m 20 04B MS - EURO IV 10200 FR 34m x 16m 21 04C MS - EURO IV 10200 FR 34m x 16m 22 04D MS - EURO IV 10200 FR 34m x 16m 23 04E MS - EURO IV 10200 FR 34m x 16m 24 04F MS - EURO IV 5400 FR 26m x 14.5m 25 05A SKO 5300 FR 26m x 14.5m 26 05B SKO 5300 FR 26m x 14.5m 27 05C SKO 5300 FR 26m x 14.5m 28 05D SKO 5300 FR 26m x 14.5m 29 05E SKO 5300 FR 26m x 14.5m 30 06A ATF 9900 CFR 33m x 16m 31 06B ATF 9900 CFR 33m x 16m 32 06C ATF 9900 CFR 33m x 16m 33 06D ATF 9900 CFR 33m x 16m 34 06E ATF 9900 CFR 33m x 16m 35 06F ATF 9900 CFR 33m x 16m 36 07A NAPHTHA 5300 FR 26m x 14.5m

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Sr. No. Service Product

Pumpable Volume in KL

(Vol in between LLL and HLL of

tank)

Type of

tank* Tank Size

37 07B NAPHTHA 5300 FR 26m x 14.5m 38 07C NAPHTHA 5300 FR 26m x 14.5m 39 07D NAPHTHA 5300 FR 26m x 14.5m 40 08A SLOP 5300 CR 11m x 11m 41 08B SLOP 910 CR 11m x 11m

42

DU1H (UG

Tank) HSD - III/IV 95 UG 11m x3.2m

43

DU2M (UG

Tank) MS - III/IV 84 UG 11m x3.2m

44

DU3S (UG

Tank) SKO 95 UG 11m x3.2m

45

DU4A (UG

Tank ) ATF 95 UG 11m x3.2m

46

DU5N (UG

Tank) NAPHTHA 84 UG 11m x3.2m

47 UG

Tank ETHANOL 84 UG 11m x3.2m

48 UG

Tank ETHANOL 84 UG 11m x3.2m

49 UG

Tank SLOP 18 UG 6.5m x2m 2. FEED RECEIPT AND PRODUCT DISPATCH FACILITIES

2.1 Existing Crude Receipt facilities

The project also involves a crude supply system consisting of a Single Point Mooring system (SPM), Crude Oil Storage Terminal (COT) at Vadinar, District Jamnagar, Gujarat and 24” diameter and 935 Km long cross country crude pipeline from Vadinar to Bina. To transport the crude at desired pressure two intermediate pumping stations are provided between cross country crude pipe lines.

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2.2 Proposed Augmented Crude Receipt facilities

Four crude tanks, each of 60000 m3 capacity are envisaged at the crude oil terminal.

2.3 Product Dispatch Facilities a. Pipelines for MS blend Component

One rail wagon unloading facility along with unloading pump, unloading pipeline (10” size, of length of about 1-1.5 km) and transfer facility from BDT upto Blendnig station/MTBE tank at refinery .

b. Rail Dispatch facility

As per existing. Post Debottlenecking additional facilities are envisaged. c. Road Dispatch:

As per existing.

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Market Study DFR for Debottlenecking of



Rev A Ch 5 Page 1 of 2


SECTION 5

MARKET STUDY

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Market Study DFR for Debottlenecking of





This section is excluded from the report as per the scope of work.

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Project Location DFR for Debottlenecking of





SECTION 6

PROJECT LOCATION

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Project Location DFR for Debottlenecking of





6.0 PROJECT LOCATION

The proposed project is expansion of Bharat Oman Refineries Limited (BORL), located in Bina, Dist. Sagar in Madhya Pradesh. The site is located approximately at Latitude of 24◦10’48″N and longitude of 78◦12’0″E. The site is well connected by state highways and road network. The nearest important town is Bina,, which is 9 Km from the site. The nearest airport to the site location is Bhopal, which is 135 Km away from the Bina Refinery site and the nearest rail junction is Bina which is situated on the broad guage line between New Delhi to Bhopal. The power required after post expansion is proposed to be met by utilizing full capacity of existing CPP (99 MW) and balance from augmented grid (Grid augmentation for 220 kV is envisaged to receive 125 MW power). The expansion envisaged for various process units is proposed to be done within the battery limit or in immediate vicinity of the existing units. Thus the administration building and other associated facilities shall be kept same as that of existing one. The overall plot plan prepared for this project is attached in Annexure-2. BORL site can be visualised in Google map as attached below:

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Project Description DFR for Debottlenecking of



Rev A Page 1 of 1


SECTION 7

PROJECT DESCRIPTION

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Project Configuration DFR for Debottlenecking of



Rev B Ch 7.1 Page 1 of 7


SECTION 7.1

PROJECT CONFIGURATION

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7.1 PROJECT CONFIGURATION

The capacity of Bina refinery can be increased from 6MMTPA to 7.8MMTPA without replacement of any major equipment in any of the existing process units. The desired capacity increase is proposed to be achieved by exploiting the available over design margins, limited hardware modifications in the existing process units, utilities and offsites, low capital investment and reasonably short shutdown time.

7.1.1 Process Units

The extent of augmentation which can be achieved by utilizing the in-built design margins & with minimum hardware modifications and without replacement of major equipment in capacities of major process units is tabulated below:

Table 7.1.1: Maximum achievable capacity in Various Units

Units Existing Capacity (MMTPA)

Post Revamp Capacity (MMTPA)

Crude / Vacuum Distillation Unit 6.0 7.8


1.952/1.637 2.625/2.202

Delayed Coker Unit 1.357 1.822 Hydrogen Unit 0.077 0.098 Naphtha Hydrotreater 1.0 1.45 CCR Reformer Unit 0.54 0.787 Isomerization Unit 0.31 0.56 Sulphur Recovery Unit 2 x 180 MTPD 3 x 243 MTPD SWS I & II 125 T/hr & 49 T/hr 162 T/hr/hr & 65 T/hr

Amine Regeneration unit 470 T/hr of Lean Amine of 25 wt % MDEA

468T/hr of Lean Amine of 40 % MDEA

ATF Merox 0.55 0.711 LPG treating unit 15.5 T/hr 21.66 T/h

7.1.2 Utilities Systems

The utility facilities for the Refinery consist of the following:

Steam, Power & BFW System Recirculating Cooling Water System

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DM water System Condensate system Fuel Gas and Fuel Oil System Compressed Air System Nitrogen System Raw Water system

The utility systems are an integral part of the refinery and constructed on the Refinery site. The refinery is self-sufficient in all its utility requirements except raw water is brought from outside (Betwa River) the refinery. Major utility systems of refinery are summarized below in table 7.1.2.

Table 7.1.2: Utility System

S no. Description Specification

1. Recirculating Cooling Water System

Post revamp, the design capacity of Refinery cooling water system : 28000m3/hr.

A Cooling Tower One new and (6+1) existing cells of 4000 m3/hr capacity each

B Cooling Water Pumps One new and (3+1) existing Pumps of 8000 m3/hr capacity each.

In addition to Refinery cooling water system, there is 30000m3/hr of cooling water system in CPP which supplies cooling water to CPP and 4000m3/hr of cooling water to refinery utilities blocks. 2. DM Water System

A RO DM Plant Post revamp capacity: 515m3/hr

B DM Water storage Tanks 2 nos. of 9000m3 cap. each

C DM Transfer Pumps to Process (1+1) pumps of 250 m3/h cap. each

D DM Transfer Pumps to CPP (2+1) pumps of 185 m3/h cap. each

3. Condensate System

A Condensate Polishing unit

One new and existing two numbers (1w+1s) each of 50m3/hr capacity

B

Condensate storage Feed tank 2 numbers of capacity 1700m3 each and for suspect condensate. For Polished condensate- 2 nos. 2800m3 capacity each

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S no. Description Specification C Condensate pumps (2+1) pumps of 95 m3/hr cap. each

4. Compressed Air System Post Revamp Compressed air system comprises of : Plant air capacity = 3530Nm3/hr Instrument air capacity = 8810 Nm3/hr One new + Three( 2 operating + 1 standby) existing Compressor of capacity

of 8825 Nm3/hr Instrument air driers = One new and two existing of capacity of 5000 Nm3/hr

each Emergency instrument air = 2 HP storage vessel for 30 minutes I.A

requirement for safe shut down (1 vessel for HCU+DHT unit + 1 vessel for balance refinery facilities).

5. Nitrogen System Nitrogen is required during catalyst regeneration, purging, blanketing etc. One new and one existing Cryogenic Nitrogen plant capacity of

Gaseous Nitrogen = 1500 Nm3/hr existing and New plant will be of capacity of 500Nm3/hr

Liquid Nitrogen = 225 Nm3/hr (Gaseous equivalent) and for new 75 Nm3/hr

6. Fuel Gas and Fuel oil System Four Cone roof tanks for Fuel oil are situated in OSBL area, Two for CDU IFO and other two for Refinery IFO. For both CDU and refinery IFO, separate surge vessels each of 30 minutes hold up are in Fuel oil system. CDU IFO pumps : 1W+ 1S of 20m3/hr capacity each Refinery IFO pumps : 1W+ 1S of 30m3/hr capacity each

7. Raw Water System

A Raw Water reservoir 2 Reservoir of Capacity 33450 & 62750 m3 (two days equivalent storage).

B Raw water treatment plant

2 Raw water treatment plant of capacity 1500 m3/hr each

C Treated Water Storage

Total capacity 22800 m3 equivalent to 12hrs of normal demand.

D Treated water pumps Total 6 pumps, 4 operating and 2 Standby of 550m3/hr each

8. Captive Power Plant ( Fuel to CPP is coke )

A CFBC Boilers Three numbers (2w+1s) each of 225 TPH

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S no. Description Specification capacity

B CPP-STG 3 extraction cum condensing type of STG, 33 MW each

In design there is provision of importing 45 MW power from the National grid for emergency and back up to refinery power generation system. To meet the process units emergency requirements, an emergency DG set of 4.0 MW is also available.

Shortfall in power requirement will be met through grid. An additional Utility Boiler for 160 TPH capacity to supply HP steam at 42

Kg/cm2g to refinery is under implementation.

9. Flare System

The refinery flare system comprises of two flare systems. A hydrocarbon flare and a sour flare system.

The HC flare size is 66” and has a design capacity of 946,973 kg.hr (peak load)

The sour flare size is 20” and has a design capacity of 30,846 kg/hr (peak load).

In order to minimize any hardware modifications in the flare systems, flare load mitigation strategies will be implemented in the basic engineering phase. 10. Effluent Treatment Plan

Refinery has a full-fledged Effluent Treatment Plant (ETP) for treatment of the following waste water generated from the refinery.

Oily effluent flow : 198 m3/hr (avg.)/ 375 m3/hr (design) Sanitary flow : 25 m3/hr Spent caustic flow : 7 m3/hr CRWS : 25 m3/hr in dry weather and 1400 m3/hr in wet weather

7.1.3 Offsite Systems

The offsite systems in existing refinery comprises of:

Tank farm Interconnection of process lines between process units Product run down lines from refinery to Dispatch Terminal

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The tank farm which is integral part to the refinery caters to (i) Storage tanks of crude feedstock, received through the crude pipeline, (ii) intermediate and component storage needed for routine operations and blending. The summary of feed and intermediate storage tanks and their pumps are tabulated below:

Table 7.1.3 Offsite Tanks

S No. Service Nos of Tank* / Type of Tank**

Nos of Pump ( operating + standby)

FEED Storages 1 CRUDE 3 (E) + 1(N) / FR 2+1

Intermediate Storages 2 Vacuum Residue 2 (E)+1 (C) / CR 2+1 3 VGO 3(E)+1(N) / CR 2+1 4 HCGO 2(E)+1(C) / CR 1+1 5 DHDT FEED 3(E)+1(N) / CR 1+1 6 LCGO 2(E) 1+1 7 NHT FEED 1 (E)+1(N) / FR 1+1 8 CCR FEED 1 (E)+1(N) / CR 1+1 9 HGU FEED 1 (E)+1(N) / DR 1+1

10 HCU LT NAPHTHA 1 (E) / DR 1+1 11 COKER NAPHTHA 1 (E)+1(C) / CR 1+1 12 ISOMERATE 2(E) / DR 1+1 13 REFORMATE 1 (E)+1(N) / FR 1+1 14 CDU/VDU IFO 2(E) / CR 1+1 15 REFINERY IFO 2(E) / CR 1+1 16 CRUDE/WATER 1 (E)/ CR 1+1 17 DRY SLOP 1 (E)+1(C) / FR 1+1 18 BLACK SLOP 1 (E)/ CR 1+1 19 MTBE 1 (E)+1(N) / DR 1+1

*E: Existing, C: Under Construction, N : New ** FR: Floating Roof, CR: Cone Roof, DR: Dome Roof

7.1.4 Crude Receipt & Transport Facilities The project also involves a crude supply system consisting of a Single Point Mooring (SPM), Crude Oil Storage Terminal (COT) at Vadinar, District Jamnagar, Gujarat and 24” diameter and 937 Km long cross country crude pipeline from Vadinar to Bina. To transport the crude at desired pressure two intermediate pumping stations are provided between cross country crude pipe line.

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In order to cater to the increased flow of crude (around 30% increase), pumping facilities in existing 24” pipe line will require enhancement along with DRA injection at the dispatch terminal and the intermediate pumping stations. Post debottlenecking, additional booster pump and modifications in main line pumps at 1st intermediate pumping station are envisaged to meet the revamp flow of crude supply at the refinery.

7.1.5 BINA Dispatch Terminal

Bina dispatch Terminal adjacent to Bharat Oman Refinery for Marketing of Finished Petroleum products produced in the Refinery is having facilities to market MS ( Euro IV/Euro V equivalent Grades ), HSD ( Euro IV/V Grades), SKO, Naphtha, ATF and LPG via Road, Rail and Pipeline. Products are received in the Marketing Terminal from Refinery through piping.

7.1.6 Crude Oil Terminal Crude oil terminal at Vadinar has facilities of Crude Oil receipt, storage and pumping facilities to pump the crude to refinery via Vadinar Bina Pipeline (VBPL). Under the expansion project of refinery additional crude storage tanks are envisaged.

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Technology Options DFR for Debottlenecking of



Rev A Ch 7.2 Page 1 of 2


SECTION 7.2

TECHNOLOGY OPTIONS

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Technology Options DFR for Debottlenecking of





Since this project is debottlenecking of existing Bina refinery, technology options are not considered. Same Technology is adopted for revamp of existing units.

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Process Description DFR for Debottlenecking of



Rev B Ch 7.3.1Page 1 of 19



SECTION 7.3.1

CRUDE VACUUM & NAPTHA STABILIZER UNITS

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Template No. 5-0000-0001-T2 Rev. 1 Copyrights EIL – All rights reserved

7.3.1.0 CRUDE /VACUUM AND NAPHTHA STABILIZER UNITS

Crude Distillation Unit (CDU) of capacity 6MMTPA and Vacuum Distillation Unit (VDU) and Naphtha Stabiliser unit of corresponding capacity of the Crude unit capacity were successfully commissioned on 29th June 2010. CDU unit consists of Crude Preheat Section & single stage Electrostatic Desalter, atmospheric column section. Vacuum distillation section and naphtha stabilization section exist to process atmospheric residue and unstablised naphtha of atmospheric column respectively. The schematic flow diagrams of CDU/VDU and naphtha stabiliser are attached in Annexure-3. This unit has been operated consistently at higher throughput and test run was performed in Aug 2012 at 115% and 119% throughput to establish the unit performance and identify the debottlenecks of the unit. Under Debottlenecking of Bina refinery project, the capacity of CDU/VDU unit shall be increased by 130% i.e. 7.8 MMTPA and therefore to explore technical feasibility of 125% operation, the revamp process study is executed by EIL. The revamp feasibility study as described in this section is performed to evaluate unit performance and identify bottlenecks and necessary modifications for the key systems and equipments. The results of the preliminary adequacy check as described in this section shall be further evaluated in details and confirmed during design stage.

7.3.1.1 BASIS OF REVAMP STUDY Crude Throughput: 7.8 MMTPA (30% increase in existing capacity of 6MMTPA),

8280 on stream hours (345 days) Crude Blend : 100 % Arab Mix (A 65:35 weight blend of Arab Light and Arab

Heavy Assay 2000) Since Crude blend considered same as existing design crude blend, yield

patterns and product properties are kept same as existing. Adequacy check has been carried out based on the as-built details of the

equipments and with the following philosophy :

It is presumed that all existing equipments are in good health and working condition. Health check of existing equipments is excluded from existing scope of work.

No de-ration of the equipment is considered for establishing adequacy.

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BORL has provided the test run report carried out at a capacity of 115-119 % and a special study report carried out at 111 % capacity which has indicated certain equipment limitations which has been looked into and suitable modifications has been suggested. Cost provision of these modified or new equipments is kept in the feasibility report.

Adequacy check has been limited to the critical equipments and adequacy check

of the line and instruments are not in the scope of the study. An adequate margin to accommodate the flow conditions pertaining to Kuwait

crude processing has been considered for adequacy check of all the equipments. 7.3.1.2 EQUIPMENT ADEQUACY REPORT

Based on above mentioned basis and assumptions, the adequacy check has been done and the findings of the adequacy check for all major/critical equipments are summarized below in Table 7.3.1.1 and overall equipment list is attached in Annexure -2.

Table 7.3.1 List of Modified Equipments

Crude Distillation Unit

S.NO TAG NO DESCRIPTION MODIFICATION

COLUMNS

1 11-CC-00-101(M) Crude Column

Dia =6200mm, Type: Tray Tower Trays modifications: 3 Nos (Trays 15-17) -Existing tray deck plates need to be changed with new deck plates 3 Nos(Trays 25-27) - Exit Weir to be changed & downcomer bottom clearance required to be changed. 3 Nos(Trays 36-38) - Exit Weir to be changed & downcomer bottom clearance required to be changed

2 11-CC-00-103(M) LGO stripper

Dia=1600 mm, Type: Tray Tower Trays modifications: 6 Nos (Trays 1-6)- Existing deck plates to be changed with new deck plates.

3 11-CC-00-104(M) HGO Stripper

Dia=1600mm, Type: Tray Tower Trays Modifications: 6 Nos (Trays 1-6)-Existing trays will need to be replaced with new

EXCHANGERS 1 11-EE-00-

124A/B KERO Product Trim Cooler

Tube side Nozzle modifications. Inlet/Outlet nozzle Sizes to be increased to 8‖/8‖ from existing 6‖/6‖.

AIR COOLER

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1 11-EA-00-125AH

Ovhd Naphtha Main Condenser

An additional bay, identical to existing 4 bays (5.8m*10.5m) to be considered.

VESSELS 1 11-VV-VI-

119 Diesel Coalescer Replaced by new coalescer.

PUMPS 1 11-PA-CF-

101A/B Crude Pump Impeller change with motor replacement of 1MW

2 11-PA-CF-102 A/B/C

Crude Booster Pumps

Replaced by new pump ( Flow:654m3/hr, Head:522 m, Motor rating:1200 KW)

3 11-PA-CF-104 A/B

KERO CR Pump Impeller trimming

4 11-PA-CF-105 A/B

LGO CR Pump

Replaced by new pump (Flow:940m3/hr,Head:91.6m,Motor Rating:225KW)

5 11-PA-CF-106 A/B

HGO CR Pump Replaced by new pump (Flow:482m3/hr,Head:98.4m, Motor Rating:150KW)

6 11-PA-CF-107 A/B

KERO Pdt Pump Impeller change with higher dia.

7 11-PA-CF-108 A/B

LGO Pdt Pump Impeller change with motor replacement of 160KW

8 11-PA-CF-109 A/B/C

HGO Prdt Pump Motor replacement of existing pumps (PA-109 A/B) with 132kW motor & One new pump (PA-109 C) with flow 56 m3/hr, head 215m & motor rating 132 KW.

9 11-PA-CF-110 A/B/C

RCO Pump Impeller change with higher diameter

10 11-PA-CF-111 A/B

Crude Column Reflux pump

Impeller change with higher diameter

11 11-PA-CF-112 A/B

Ovhd Naphtha Pump

Replaced by new pump (Flow:224m3/hr, Head:220.4m, Motor rating 150 KW)

12 11-PA-CF-113 A/B

CDU Sour Water Pump


13 11-PA-CF-128 A/B

Recycle water pump


FIRED HEATERS 1 11-FF-00-

101 Crude Heater Additional 16 no tubes, Modification in fan and

burner, replacement of stack damper NEW EQUIPMENT 1 LGO Exchnager New Exchanger With following Specifications ,

No of Shells: One Size: 650*6000mm Area: 80m2

2 HGO Exchanger New Exchanger With following Specifications No of Shells: One Size: 800*6000mm Area: 100m2

3 2nd Stage Desalting

New pump (Cap: 104 m3/h ,Head :125m,Motor rating 75KW)

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Water Pump 4 Crude Desalter

1st stage New crude desalter (similar to existing) to be installed in parallel to existing desalter.

5 Crude Desalter 2nd Stage

New equipment

Vacuum Distillation Unit

S. NO TAG NO DESCRIPTION MODIFICATION

COLUMNS

1 12-CC-00-101 Vacuum Column

Packing modifications: Replacement of Bed no2 and Bed no 4 with new packed bed Bed No. Dia(mm) Height of bed in mm 2 6000 2000 4 9200 1000 Replacement of the existing removable type chimney trays with new welded type chimney trays with high riser area.

For Bed #1 - Bed #2 , CT dia is 5000m and Bed #3 to #6 is 9200mm.

VESSELS 1 12-VV-VI-106 Caustic

Vessel Dismantling of spray ring

EXCHANGERS

1 12-EE-00-105A/B HVGO Cooler

One additional shell, identical to existing (size:850mm*6000mm,approx area 243m2/shell) to be provided in series with existing 2 shells.

2 12-EE-00-106A/B VR+ Slop Cooler

Two additional shells, identical to existing (size: 575mm*6000mm, approx area 104 m2/shell) to be provided in parallel to existing 2 shells.

AIR COOLERS 1 12-EA-00-109A-F Tempered

Water Cooler

One Additional Bay (same as existing size: 5.8m*10.5m) to be provided.

FIRED HEATERS 1 12-FF-00-101 Vacuum

Heater Additional 16 no tubes, Modification in fan and burner, Replacement of stack damper.

PUMPS 1 12-PA-CF-101A/B Vacuum Diesel

Pump Impeller change with new motor of rated power 330 kW

2 12-PA-CF-102A/B (LVGO IR+CR) Pump


3 12-PA-CF-103A/B (HVGO IR+CR) Pump

Impeller change with new motor of rated power 460 kW

4 12-PA-CF-104A/B Recycle Pump Impeller change with higher diameter 5 12-PA-CF-105A/B (VR+ Quench)

Pump Impeller change with new motor of rated power 490 kW

6 12-PA-CF-106A/B Slop Oil Pump Impeller change with higher diameter 7 12-PA-CF-107A/B Sour Water

Pump Impeller change with higher diameter

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8 12-PA-CF-108A/B Tempered Water Pump


9 12-PA-CF-109A/B Vacuum Diesel IR Pump


10 12-PA-CF-110A/B LVGO IR Pump


13 12-PA-CF-112A/B LVGO Product Pump


14 12-PA-CF-113A/B HVGO Product Pump


EJECTOR SYSTEM 1 12-LZ-101 Vacuum

Ejector system Ejector system needs modification (Note 1)

NEW EQUIPMENTS 1 Vacuum

Column Ovhd Cooling Water Booster Pump

New pump , Capacity: 3782 m3/hr ,Head :61m, Motor power 672 KW

2

Hotwell Off Gas Amine Absorber

Dia=1500 mm Height(T/T)=18801 mm ColumnType=Packed bed Packing: No of Beds Height 2 Nos 4250 mm for each bed Weight of column : 27000 Kg

3 Rich Amine Pumps

New pump Capacity: 30m3/hr, Head :76.2m ,Motor power 15 KW

NOTES 1. Replacement/modification of elements may be required along with new/modification

in precondenser, condensers and after condenser. Shall be confirmed during detail engineering.

Naphtha Stabilizer Section

S NO

TAG NO DESCRIPTION MODIFICATION

COLUMNS

13-CC-00-101 Naphtha Stabiliser

20 Nos (Trays 1-20) of dia of 1600 mm, Replaced with high capacity trays 23 Nos (trays 21-43) of dia of 2800 mm Replaced with high capacity trays.

Pumps 13-PA-CF-101

A/B Stabiliser Reflux Pumps


13-PA-CF-102 A/B

Sour LPG Pumps Impeller change with higher diameter

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7.3.1.3 EQUIPMENT WISE ADEQUACY REPORT

Equipment wise adequacy is as detailed below:

Desalter The existing unit has a single stage Desalter. To meet desalted crude salt content of 1.0ptb and BS&W of 0.05vol%, an additional first stage desalter parallel to existing one and second stage desalter along with associated facilities (new desalting water pump etc) are considered. Columns The adequacy check of existing columns has been carried out based on the following assumptions:

No modifications of trays/internals have been carried out by BORL. Adequacy findings of internals are based on in-house information (package details) of internals.

Crude Colum The existing column diameter and trays are adequate to handle the revised vapour/ liquid loadings except the following modifications:

Tray section # 15—17- Existing trays deck plates need to be changed with

new try deck plates with more number of valves. Tray section # 25—27 & #36-38- Adequate after changing exit weir and

down-comer bottom clearance required. Pressure drop increase in trays is within the design limit.

Side strippers The existing diameter and trays of all the side strippers ( Kero/LGO/HGO) are found adequate for 130% of the design loads However, as per special study report and the test run report, it was observed that LGO is drawn at around 10% higher and HGO is drawn at around 64% higher than design draw rates. In anticipation of similar operation post revamp, the adequacy check of the strippers have been carried out with these additional overdesign margins over and above 30% increase in the design loads. For these increased loads, the LGO stripper needs change in deck plates and HGO stripper needs change in trays of new configuration. Vacuum column Vacuum Column is found to be adequate but to retain the existing column allowable pressure drop value of 17.25mmHG, following modifications are proposed

Replacement of Bed No.#2 & Bed No.#4 with new packed bed having more

open type of packing, but retaining the respective existing bed heights.

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Riser area of chimney trays CT#1 to CT#6 (Chimney trays below Bed#1 to

Bed #6) to be increased from existing chimney tray area of 25% to 30% to lower the pressure drop across chimney trays. In order to achieve this increase in area, existing removable type of chimney trays need to be replaced with new welded type chimney trays with higher riser area.

Naphtha stabilizer The column is found adequate with replacement of existing trays with high capacity trays.

Furnaces The adequacy check of the furnaces has been carried out with the following assumptions:

Clean heat transfer surface and performance of heater as per original

design with no deterioration in furnace/ heat transfer surface dimensions, no tube bulging/ bowing etc.

No adverse operating feed back / limitation on the performance of rotating equipment.

Burner performance is satisfactory (no flame impingement, no flame overlapping etc.).

Crude Heater Crude heater is checked for post revamp conditions as tabulated below: Flow

TPH Duty

MMkcal/hr Temp Deg C In Out

Existing Design 751.8 43.848 310 371 Post Revamp 751.8* 1.25 67.53 280 371

Vacuum Heater Vacuum heater is checked for post revamp conditions as tabulated below: Flow

TPH Duty

MMkcal/hr Temp Deg C In Out

Existing Design 407.3 32.6 341.4 427.9 Post Revamp 407.3* 1.25 40.075 341.4 427.9

Modifications in Crude and Vacuum Heaters

The major modifications required in the crude heater and the vacuum heater for the above post revamp conditions are as follows:

Augmentation of heat transfer area and associated modification in the radiant

section is envisaged. Additional 16 no. tubes (2 tubes per pass) with coil

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size/MOC/Thickness/elevations same as existing are required to be provided in the existing firebox (at heater arch and side walls connected with bridge floor).

Existing burners of the CDU/VDU heaters are found adequate to handle the revamp loads for ―APH-inline‖ operation. For ―APH bypass‖ operation burners are required to be studied with OEM for modification/replacement to cater for additional 5 % loadings.

Replacement of existing stack damper with new stack damper of existing details (based on operating feedback from BORL)

The calculated coil side pressure drop of the crude and vacuum furnace shall be of the order of ~16 Kg/cm2 and 10 kg/cm2.

Existing FD fans of the CDU/VDU heaters are found adequate to handle the revamp loads for ―APH-inline‖ operation.

For ―APH bypass‖ operation FD fans adequacy are as follows:

CDU Heater FD fans (11-EA-FN-101A/B) The fan is checked for following post revamp operating conditions as shown in table below:

Maximum Normal Minimum

Two Fan Operating

One Fan Operating

Two Fan Operating

One Fan Operating

Existing Revamp Existing Revamp Existing

Revamp

Existing

Revamp

Capacity (Nm3/s) (Dry)

13.1 15.0 26.2 30.1 10.9 12.5 10.9 12.5

Discharge Pressure (mm WC)

270 355 270 355 185 245 45 60

Findings Existing fan is adequate to deliver all operating conditions except for maximum capacity while one fan operating (i.e 30.1 NM3/S flow @ 355mmWC discharge pressure). To achieve this condition too, existing 150KW motor needs to be replaced with new motor of rated power 250 KW. In addition to this replacement/ rectification of some major component such as fan rotor, seals, couplings, bearings, casing with inlet box & drain, evase, drive end side base frame is also required.

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VDU Heater FD fans (12-EA-FN-101A/B) The fan is checked for following post revamp operating conditions as shown in table below:

Maximum Normal Minimum

Two Fan Operating

One Fan Operating

Two Fan Operating

One Fan Operating

Existing

Revamp

Existing

Revamp

Existing

Revamp

Existing

Revamp

Capacity (Nm3/s) (Dry)

8.9 9.8 17.8 19.6 7.7 8.5 7.7 8.5

Discharge Pressure (mm WC)

260 315

260 315 200 230 50 57

Findings Existing fan is adequate to deliver all operating condition except for maximum capacity while one fan operating (i.e 19.6 NM^3/S flow @ 315 mm WC discharge pressure). To achieve this condition too, existing 110 KW motor needs to be replaced with new motor of power rating132 KW. In addition to this replacement/ rectification of some major component such as Fan Rotor, Seals, bearings, casing with inlet box & drain, outlet evase is also required.

It is presumed that the existing APH (for both CDU & VDU heater) is working as

per design and the existing flue gas temperature of 160 degC at APH outlet is being achieved. The increase in flue gas flow rates/temperature for revamp condition is estimated to be absorbed in APH overdesign margins.APH shall be checked for new loadings during detailed engineering.

The inlet box damper for the ID fan needs to be inspected for smooth operation. Other performance parameters (TMT, BWT etc.) are under allowable limit.

Existing combined stack (ID & length) for CDU & VDU heater is adequate to handle the revamp loads w/o any modification.

Exchangers Preheat Network

The preheat network has been examined with 30% additional of design flow and duty for the revamp scenario. All the exchangers in the preheat circuit are found to be adequate for 30% additional design flow and duty and preheat temperature of 307degC will be achievable in existing network.

However as per special operating study and the test run reports, the existing operating preheat II temperature (295degC) is 15degC lower than design preheat temperature of 310degC. To evaluate the lower operating preheat temp, the design and operating data were compared as tabulated below:

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It is evident from above data that there is lot of deviation in operating and design flow and duty particularly for HVGO PDT and LVGO/ HVGOPA which are most contributing for preheat train II outlet temperature. Adequacy of preheat train for operating and test run data shall be established during design stage.

As per operational feedback, steam generation is on higher side due to higher product withdrawal temperatures of LGO and HGO from column (280 degc as against design temp of 265 degc for LGO and 339 degC as against design temp of 319 degC for HGO). In anticipation of similar operation post revamp, new exchangers LGO/Crude and HGO/Crude in the preheat circuit have been considered for utilizing excess duty with maintaining existing steam generation quantities.

Feed/Bottom Stabilizer Exchangers are found to be adequate for 25 % additional design flow and duty. Shell side and tube side pressure drop will be 1.5kg/cm2 and 0.7kg/cm2 respectively for revamped conditions.

Reboilers The Kero reboiler(11-EE-00-117) and the Stabilizer reboiler(13-EE-00-104) are found adequate for 25 % margin on design flow and duty.

Service

Design Actual % change

Flow (T/hr)

Draw off Temp.degC

Duty (Gcal/hr)

Flow (T/hr)

Draw off Temp. degC

Duty (Gcal/hr) Flow/duty

CRUDE COLUMN Col. Ovhd. 270 159 14.1 201 153 10.54 -25/-25

KERO 118 234 13.47 103 244 12.31 -12.7 /-8.6 LGO 87 254 4.59 97 278 6.53 11.5/ 42 HGO 35 308 3.0 58 336 6.05 65/ 100

KERO PA 372 198 13.4 314 201 12.55 -15.6 /-6.3 LGO PA 432 265 16 386 280 16.2 -10.6 /1.2 HGO PA 217 319 9 198 339 10.9 -8.7/21

VACUUM COLUMN

LVGO 95 254 4.94 62 246 2.94 (-34.7)/(-40) HVGO 102 333 10.089 145 327 13.71 42/36

VD(PA+PDT)

274 126 8.19 180 136 6.26 (-34.3)/(-23.56) LVGO PA 393 254 12.68 282 246 7.33 (-28.2)/(-42.19) HVGO PA 500 333 17.71 354 327 19.4 (-29.2)/9.5 VR+ SLOP 167 350 16.42 148 350 14.56 (-11.4)/(-11.3)

VR QUENCH

91 350 5.52 53 350 3.79 (-41.7 )/(-31.3)

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Overhead circuit The overhead and run down exchangers have been checked with 25 % additional flow and duty. The overhead air cooler has been checked with design air temperature of 45.6 deg C. Crude Column Over head exchangers The crude column reflux condenser(11-EE-00-101A/B) is found adequate but the overhead naphtha main condenser (11-EA-00-125) is found thermally and hydraulically limiting . One additional bay have been considered for the naphtha main condenser and with reduced inlet temperature of trim condenser (11-EE-116 A/B), exchanger is found adequate for the revamp load with cooling water increase from 460m3/hr to 527.5m3/hr. Stabilizer overhead Exchangers Stabilizer overhead condenser (13-EE-AS-103 A/B) is found adequate for the revamp duty with increased cooling water flow rate from 520 m3/hr to 690 m3/hr. Products Run down Exchangers The rundown circuit shell and tube exchangers and the air coolers have been found adequate with minor increase in rundown temperatures or increased cooling water flow rate as tabulated below:

Product Exchangers Findings/

Modifications

Cooing water m3/hr

Rundown Temp degC

Existing Post revamp Existing Post

revamp Stabilized Naphtha

13-EA-00-101 13-EE-102 A/B

Adequate 124.2 204.5 40 40

Kero 11-EA-00-128 EE-00-124A/B

Adequate 150.4 230 40 42.5

LGO 11-EE-00-118 11-EE-00-121 11-EA-00-126 11-EE-00-122

Adequate 97.2** 110 40 46

HGO 11-EE-00-119 11-EE-00-120 11-EA-00-127 11-EE-00-123

Adequate 41.7** 47.0 40 43

VacDiesel 12-EA-00-107 12-EE-00-107

Adequate 237 237 40 39

LVGO 12-EE-00-108 12-EA-00-108

Adequate NA NA 80 89*

HVGO 12-EE-105 A/B Adequate with one additional, identical shell as existing

291.6 291.6 80 78*

VR+slop 12-EE-106A/B.

adequate with additional two extra shells identical to the existing shells in parallel to the existing two shells

177 177 160 176

Desalter Effluent cooler

Adequate 159 239 60 60

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*Combined LVGO & HVGO run down temperature: 83degC ** Increase in steam generation by 25%. Temper water System In order to cool HVGO and VR+Slop to the rundown temperatures mentioned above one additional bay identical to the existing 3 bays to be provided for the Tempered water Air cooler 12-EA-109 to cool 468.6 m3/hr of tempered water to 60 deg c. Vessels All the vessels are found adequate for the revamp conditions with acceptable reduced residence time and the hold up time

Pumps The pump adequacy has been carried out based on the following assumptions: The pumps have not been checked w.r.t NPSHA / NPSHR & downstream

design pressure as these aspects will be checked in the detail engineering . Adequacy Check of the pump has been carried out based on existing pump

data sheets /predicted performance curves on the assumption that the actual performance of the pumps are as per datasheets /curves

Adequacy Philosophy Pump adequacy check has been performed with an objective of retaining the existing pump with the following philosophy: Minimum overdesign margin is provided for the rated flows of the pump over

and above 25 % increase in normal flow for the revamp Head increase post revamp has been avoided by considering replacement of

line size, instruments , if required.

Adequacy Results A summary of the adequacy results of the pumps are tabulated below. Majority of the pumps are found adequate with impeller replacement and /or motor replacement.

Motor Replacement If pump is found adequate and motor inadequate (Total 9 Pumps:3 in CDU & 6 in VDU), replacement of motor with a higher rating is envisaged. Replacement of motor may call the following changes :

a) Base plate modification/replacement b) Couplings need replacement, c) Foundation may require modification

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Modifications related to Motor shall be carried out by OEM only which might invite opportunity costs.

Shut down time requirement is more as compared to implementation of new pumps

Normally motor related modifications are preferred by OEM at their workplace. Shifting of pumps at OEMs works are mostly difficult, time consuming & cost ineffective. To carry out the motor related modifications at site, BORL shall check adequate facilities at their workshop.

Therefore, the philosophy of motor change from economical feasibility and execution point of views shall be reviewed at design stage in consultation with OEM.

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PUMP ADEQUACY CHECK RESULTS

CRUDE DISTILLATION UNIT

PUMP DESCRIPTION

PRE-REVAMP POST-REVAMP MODIFICATIONS/FINDINGS RATED

FLOW (m3/hr)

DIFF HEAD (M)

RATED FLOW (m3/hr)

DIFF HEAD (M)

Crude Pump (11-PA-CF-101 A/B)

958.2 201 1197 254.2 Existing motor (Rated Power: 665 kW) to be replaced by new (Rated Power: 1MW approx).Impeller change with higher diameter

Crude Booster Pump (11-PA-CF-102 A/B/C)

523 391.3 654 522.1 New Pump. Existing Pump is insufficient for revamp rated flow.

Desalting Water Pump (11-PA-CF-103 A/B)

70 183.1 80 180 Adequate

KERO CR Pumps (11-PA-CF-104 A/B)

663 99.2 853 82.2 Impeller Trimming

LGO CR Pumps (11-PA-CF-105 A/B)

758.0

73.2 940 91.6 New Pump. Existing Pump is insufficient for revamp rated flow.

HGO CR Pumps ( 11-PA-CF-106 A/B)

378 69.6 482 98.4 New Pump. Existing Pump is found inadequate due to maximum achievable head of 70 m for the revamp flow.

KERO Product Pumps (11-PA-CF-107 A/B)

211 152.2 220 155 Impeller replacement with higher diameter. (In operation since KERO Draw has been reduced to 85%, this pump can be made adequate with impeller change).

LGO Product Pumps (11-PA-CF-108 A/B)

154 207.4 188* 226.4 Existing motor (Rated Power: 110 kW) to be replaced by new (Rated Power: 160 kW approx). . Impeller change with higher diameter

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HGO Product Pumps (11-PA-CF-109 A/B)

56 215 112* 215 Existing motor (Rated Power: 75 kW) to be replaced by new (Rated Power: 132 kW approx). One Additional pump (2W +1S) is required to accommodate the revamp rated flow.

RCO Pumps (11-PA-CF-110 A/B/C)

306 173.2 336 175 Impeller replacement with higher diameter

Crude Column Reflux Pump(11-PA-CF-11 A/B)

275.3

102.5 315 112.6

Impeller replacement with higher diameter

Overhead Naphtha Pumps (11-PA-CF-112 A/B)

187.4 205 224 220.4 New Pump. Existing Pump is only sufficient for flow of 215 m3/hr (3% margin) which is very less.

CDU Sour Water Pumps (11-PA-CF-113 A/B)

21 68.5 24 72.6 Impeller replacement with higher diameter

Recycle Water Pumps (11-PA-CF-128 A/B)

10.3 42.6 13 48 Impeller replacement with higher diameter

VACUUM DISTILLATION UNIT Vacuum Diesel Pump (12-PA-CF-101 A/B)

540 147.5 590 160 Existing motor (Rated Power : 250 kW) to be replaced by new (Rated Power: 330 kW approx). Impeller change with higher diameter

LVGO IR + CR Pump (12-PA-CF-102 A/B)


HVGO IR + CR Pump (12-PA-CF-103 A/B)

934 136.6 1161 135 Existing motor (Rated Power: 390 kW) to be replaced by new (Rated Power: 460 kW approx). Impeller change with higher diameter

SLOP Recycle Pumps (12-PA-CF-104 A/B)


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*Flow as per operational feedback (25% margin over operating flow based on Test Run Report)

VR + Quench Pumps ( 12-PA-CF-105 A/B)

380 242 472 270 Existing motor (Rated Power: 385 kW) to be replaced by new (Rated Power: 490 kW approx). Impeller change with higher diameter

Slop Oil Pumps (12-PA-CF-106 A/B)

11.8 178.1 12.5 184.3 Impeller replacement with higher diameter

Sour Water Pumps (12-PA-CF-107 A/B)


Tempered Water Pumps (12-PA-CF-108 A/B)


Vacuum Diesel IR Pump (12-PA-CF-109 A/B)


LVGO IR Pumps (12-PA-CF-110 A/B)


LVGO PDT Pumps (12-PA-CF-112A/B)


HVGO PDT Pumps (12-PA-CF-113 A/B)

147 238.1 176 261 Existing motor (Rated Power: 132 kW) to be replaced by new (Rated Power: 160 kW approx). Impeller change with higher diameter.

NAPHTHA STABLIZER UNIT Stabiliser Reflux Pumps (13-PA-CF-101A/B)


Sour LPG Pumps (13-PA-CF-102A/B)

21.2 253 27 268.1 Impeller replacement with higher diameter

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Ejector System The study has been performed on the existing ejector system for increase in capacity by 30% by Ejector Vendor. Based on the adequacy study following two options are suggested:

1) Replacing of existing ejector system to meet the revamped capacity of 30%. With new ejector system

2) Installing an additional condenser with a three stage vacuum system for balance 30% load in parallel to existing system.

As per test run report, ejector performance for design conditions has not been established due to non-availability of sufficient cooling water to condensers. Ejector performance can be established after installation of dedicated cooling water pumps to ejector system. Modifications in ejector system shall be firmed up after accomplishing the performance of ejector on design conditions and subsequently test run data at maximum achievable capacity of ejectors. However for costing point of view replacement/modification of ejector elements, new pre-condenser and modifications in inter condenser and after condenser are considered.

7.3.1.4 NEW FACILITIES

BORL requested some of following facilities to be considered for post expansion case based on their operating experience: Hot well Off Gas Scrubbing section As per operational feedback, there is considerable corrosion in the APH of the crude heater due to sour gases from the Hot well. Hence a new amine based absorber system for treating hot well off gases have been conceived .The new hot well off gas treatment system shall employ 40 % MDEA and shall include the following: Hot well off gas amine absorber Hot well off gas KOD (Existing caustic vessel 12-VV-VI-106 will be modified for

this service) Rich amine pumps

Cooling water Pumps for Ejector’s System Presently there is limitation in condensing duty of vacuum column OVHD condensers due to improper cooling water flow. Cooling water flow to the unit battery limit is 57% of design flow. To overcome the limitation of cooling water to condensers additional CW pumps within unit shall be considered.

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7.3.1.5 CONSTRUCTABILITY

The existing plot was considered for all the proposed modifications and it was determined that there is sufficient space for new/modified equipment.

A joint site visit was made by EIL and BORL team to assess the extent of modification work involved in the revamp as well as to locate space for the new equipments. The modifications /new facilities as tabulated in Tables 7.3.1 were checked for and found feasible from construction and implementation point of view.

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Rev B Ch 7.3.2 Page 1 of 7



SECTION 7.3.2

Delayed Coker Unit

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7.3.2.0 DELAYED COKER UNIT

A debottlenecking study for increasing the capacity of DCU from its current operation of 1.36 MMTPA to 1.822 MMTPA of fresh vacuum residue feed is performed by CB&I Lummus. The revamp study done by CBI Lummus includes benchmarking of current operation, determining key revamp operating parameters and yield structure and identification of bottlenecks and necessary modifications for the key systems and equipments.

Delayed Coker Unit which is licensed by CBI Lummus includes Coker Heaters, composed of two separate cabins with their own convection sections, common APH, common stack, common ID/FD Fans; two Coke Drums; and a Coker Fractionator with Side Strippers and a Vapor recovery section. The Vapor recovery section consists of a Wet Gas Compressor, Stripper/Absorber, Sponge Absorber and Debutanizer. The DCU Area features three auxiliary facilities: Coke Drum Blowdown System, Coke Cutting System including Water Circulating Facilities and coke handling system. Process flow diagram as furnished along with study report are given in Annexure 3.

7.3.2.1 FEASIBILITY STUDY REPORT

CB&I Lummus carried out revamp feasibility report for 134% increase in unit throughput considering vacuum residue feedstock quality same as FEED case 2 ( VR of 65% AL & 35% AH crude) of design package and feed CCR as 23.99wt% & API as 4.18. For specified feed and considering no modifications in existing coke drums, the confidential coking yield correlations were fine-tuned and simulation model was updated to bench mark unit operation based on the results of the test run data that has been performed in August 2012 in order to closely match plant performance. Lummus envisaged following operating parameters for 34% expanded capacity due to system hydraulics and other design considerations. Coke Drum Pressure = 1.52-2.5 kg/cm2g Main Fractionator inlet pressure = 1.17-2.15 kg/cm2g Wet Gas Compressor Discharge pressure = 14.3 kg/cm2g Wet Gas Compressor first stage inlet pressure = 0.16-1.5 kg/cm2g Recycle ratio = 5% Coke Drum Cycle = 18 hours C3+C4 recovery = 90% The remaining operating parameters are close to the original design case. Revamp feasibility study submitted by Lummus comprises process evaluation including key revamp operating parameters, yield structure and required

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modifications along with preliminary engineering for two options i.e. i) coke drum overhead pressure of 1.52kg/cm2g and ii) coke drum overhead pressure of 2.5 kg/cm2g.

In order to minimize fuel gas yield and coke make, option 1 of coke drum overhead pressure of 1.52kg/cm2g is pursued for revamp of 34% increase in unit capacity. The key features and modification as reported in Lummus Revamp feasibility report which are considered under this project are summarized below:

Post revamp yield pattern for coker overhead pressure of 1.52kg/cm2g are tabulated below in Table 7.3.2.1.

Table7.3.2.1: Theoretical Yield (Wt% of Fresh Feed)

Coker Gas 6.57 LPG 4.05 Coker Naphtha (C5-140°C) 8.74 LCGO (140°C-370°C) 31.58 HCGO (370°C Plus) 19.18 Coke 29.88

Coker Heaters: Lummus has carried out preliminary adequacy check of heater and identified potential changes to the furnace and its auxiliary systems. Since the furnace rating was not included in the Lummus scope of revamp feasibility report, detailed rating of the heater and interaction with the auxiliary equipment suppliers will be performed during design stage. The modifications as reported in revamp feasibility study are listed below: Radiant Section: To meet the revamp duty of 41.98MMKcal/hr and to achieve

both EOR TMT and allowable pressure drop, replacement of all existing tubes with higher metallurgy i.e. SS347H of sch 40. Additional 6 tubes per pass of MOC SS347H of sch 40. Total no of passes are two per heater. Subsequently it is found that SS347H MOC is not suitable for high content of chloride ( around 20ppm as per BORL data) as exist presently in vacuum residue feed, Lummus proposed to consider Inconel800 tubes in place of SS347H.

Convection Coil: Use of two future rows is required. The use of future rows will help reduce the radiant flux by shifting some duty to convection section and also help in maintaining the heater efficiency.

Tube supports: Tubes supports will be adequate with reduced load of 40 schedule tubes. However tube supports need to be checked for revamp conditions and thermal movements which might be controlling in tube support design during design stage.

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Convection intermediate Tube Supports: Flue gas temperature profile has changed to 70°C from 50°C throughout convection. Design margin has reduced from 110°C to 65°C. Mechanical check is required during design stage to verify the design of supports for revamp conditions.

FD Fans: Two FD fans running at 50% capacity will be adequate for revamp volumetric flow and static pressure required. For fuel oil firing single FD fan will not be adequate. Some reduction of load or combination of fuel oil with fuel gas or reduction in excess air is required.

ID Fans: ID fans are adequate for fuel gas firing. But for fuel oil firing it is marginally short. Adequacy of ID fans to be verified by vendor during detail engineering.

Burner: Burner tips may need modification. To be confirmed by vendor during detail engineering.

Stack: Stack is adequacy to be checked during detail engineering for ID fan trip and APH bypass. Load need to be reduced during natural draft operation.

Wet Gas Compressor: The adequacy for the WGC was checked by compressor

vendor for the process conditions provided by licensor. Vendor reported maximum Possible flows with given operating conditions as given below in table :

Stage 1 31910 Kg/hr 20128 m3/hr Compressor is adequate subject to 1st stage discharge pressure is considered as 4.04 kg/cm2g instead of 3.5 kg/cm2g Stage 2 24322 Kg/hr 4521 m3/hr

Compressor is not found adequate for the required revamp flow rate of 40912*1.1 kg/hr for stage 1 and 31182*1.1 kg/hr for stage 2. Therefore a new compressor of balance capacity in parallel to existing compressor is considered to handle the revamp load. The new compressor is envisaged of fixed rating of 1.3MW motor driven machine.

The adequacy and modifications suggested for other equipments as well as requirement of new equipments as proposed in Lummus revamp feasibility study report are summarized below in Table 7.4.2 and overall equipment list is tabulated in Annexure 2.

Table 7.3.2.2: List Of New/Modified Equipments

S.NO TAG NO DESCRIPTION MODIFICATION

FURNACE

1 14-FF-00-101A/B Coker Heater

Radiant section: Replacement of Existing Tubes change with Inconel 800 material. Convection Section: Use of

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additional two future rows. COLUMNS 1

14-CC-00-101

Coker Fractionator

Top trays (26-15): modification of tray panel with VG-10, modify Downcomer width. HCGO Frac (14-7) Trays: number of valves to be increased. HCGO PA trays (6-1): modification of panels with Pro-Valve and Downcomer width modification.

2 14-CC-00-102

LCGO Stripper

Trays (2-6): Increase number of valves.

3 14-CC-00-104 Absorber Trays (1-30): Modification in Downcomer width and clearance.

4 14-CC-00-105 Stripper

Tray (1-30): Modifiy Downcomer width and clearance along with increase in number of valves.

5 14-CC-00-107 Debutanizer

Top Section: Increase in number of valves and Downcomer clearance. Bottom Section: Modification of downcomer width and clearance along with increase in number of valves.

EXCHANGERS 1

14-EE-00-101A Feed/HP Stream Exchanger

New (Area: 597 m2, No. of Shells: 1)

2 14-EE-00-107E/F

Compressor Interstage Cooler

New in parallel with exchanger 14-EE-00-107A/B/C/D. (Area: 147 m2, No. of shells: 2)

3 14-EE-00-109E/F

Compressor Discharge Cooler

New in parallel with exchanger 14-EE-00-109A/B/C/D. (Area: 278 m2, No. of Shells: 2)

4 14-EE-00-115E/F

Debutanizer Overhead Condenser

New in parallel with exchanger 14-EE-00-115A/B/C/D. (Area: 204 m2, No. of Shells: 2)

5 14-EE-00-118B

Absorber Intercooler

New in parallel with exchanger 14-EE-00-118B. (Area: 37 m2, No. of Shells: 1)

6 14-EE-00-119

Debutanizer Steam Reboiler

Replaced with new 14-EE-00-121.

7 14-EE-00-120 Stripper Reboiler New (Area: 113 m2, No. of Shells: 1) 8

14-EE-00-121 Debutanizer Steam Reboiler


9 14-EE-00-123

Debutanizer Bottom Water Cooler


AIR COOLERS 1 14-EA-00-102A-

L Coker Fractionator Overhead Condenser

One additional Bay of 5.0m X10.0m to existing 6 bays. (Surface Area:

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2,650 m2) DRUMS 1

14-VV-00-103 Compressor Interstage Drum

In situ increase the length of vessel (Note: 1).

2 14-VV-00-104 Recontact Drum

In situ increase the length of vessel (Note: 1).

3 14-VV-00-107

Debutanizer Overhead Receiver

Replaced with new vessel. (Dia: 2,500 mm and Length: 7,500 mm)

4

14-VV-00-122

Feed/HP Steam Exchanger Condensate Pot

New (Diameter: 910 mm and length 1,700 mm)

5 14-VV-00-123

Stripper Reboiler Condensate Pot

New (Diameter: 910 mm and length 1,700 mm)

PUMPS 1

14-PA-CF-101A/B

Coker Unit Feed Pump

Impeller change with larger diameter and motor replacement (75 KW)

2 14-PA-CF-105A/B

Debutanizer Bottom Pumps

Replaced with new pump of motor rating 95 KW. (Flow: 256.74 m3/hr, Head:152 m)

3 14-PA-CF-107A/B

Lean Sponge Oil/ LCGO Product Pumps

Impeller change with larger diameter and motor replacement (150 KW)

4 14-PA-CF-110A/B

Fractionator Overhead Liquid Pumps

Impeller Change with larger diameter

5 14-PA-CF-113A/B Stripper Feed Pumps

Replaced with new pump of motor rating 75 KW.(Flow: 256.25 m3/hr, Head: 99.73 m)

6 14-PA-CF-121A/B

Absorber Bottom Pumps

Replaced with new pump of motor rating 30 KW. (Flow: 195.9 m3/hr, Head:59.8 m)

7 14-PA-CF-122A/B

Absorber Intercooler Pumps

Replaced with new pump of Rating 30 KW.(Flow: 220.88 m3/hr, Head:48.61 m)

COMPRESSOR 1

14-KA-CF-101B Wet Gas Compressor New in parallel to existing 14-KA-CF-101. HT Motor Driven (1.3 MW).

2 14-KA-CF-102 Blowdown Ring Compressor

New. Motor Driven (45 KW).

NOTES 1. Replacement of vessel is not feasible from implementation/constructability point of view. Licensor shall confirm the adequacy of this vessel in view of retaining the same diameter and increasing the length in situ. Lummus recommended that it is feasible to increase the capacity of existing

coker up to 1.822MMTPA at 5vol% recycle rate with above mentioned additions and alternations.

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7.3.2.2 CONSTRUCTABILITY For the feasibility of implementation and constructability of all new/ modified equipment were evaluated at site and following are the findings:

Wet Gas Compressor: There is space to locate shed of 8m width for new

WGC at the north side of existing shed & to accommodate it, existing staircase on northern side of existing compressor shed will be needed to be relocated.

Blowdown Ring Compressor: The location of new blowdown ring compressor is identified in west side of northern battery limits of pipe rack.

Vessels: Replacement of Recontact drum due to its size cannot be taken out and replaced with new one. Therefore diameter of existing recontact drum shall be retained ( To be confirmed by licenser during design stage) and length of Recontact drum can be increased in situ. It is more economical to increase the length of Compressor Inter-stage vessel as required post revamp, at site instead of replacement with other vessel. Debutanizer Overhead Receiver can be replaced with new vessel.

Other Equipments: Implementation/ constructability of all other equipments (modified or new) were checked and found feasible.

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SECTION 7.3.3

HCU/DHDT

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7.3.3.1 Hydrocracker and Diesel Hydro treating Unit

A debottlenecking study for increasing the capacity of HCU/DHT from its current operation of 1.952MTPA for HCU & 1.637MTPA for DHT to 2.625 MMTPA HCU & 2.202 MMTPA for DHT has been performed by CLG. The revamp study done by CLG includes the operating data at 115%, expected operating parameters & yield structure, bottlenecks & necessary modifications for the key systems & equipments at revamped capacity.

7.3.3.2 Revamp Feasibility Study

CLG performed revamp feasibility study to achieve 135% increase in existing capacity by analyzing plant data along with rigorous simulation modelling in consideration of followings:

Feed quality for HCU and DHT unit same as per original design. Product yield pattern and quality for HCR and DHT are considered same as in

original design. Battery limit conditions of all feeds and products have been considered same as

original design except feed streams will be a 80:20 mix of hot and cold feed instead of 100% hot feed as considered in original design.

With the above basis, CLG carried out revamp study and stated post revamp process data of all equipment. Based on CLG simulated process data of each equipment adequacy of the unit was checked by CLG and EIL. The process flow scheme as furnished by CLG in their report is attached in Annexure 3. CLG furnished the results of adequacy check of the HP section in their report. EIL carried out the adequacy check of the LP section with the data provided by CLG.

The key features and adequacy check of major equipment based on data given by CLG in their report are summarized below. The overall equipment list is attached in Annexure 2.

1. Reactors a) HCR Stage 1 Reactors (16-RB-00-101/102/103): No changes in reactor

internals except increase in sizes of orifice of reactor quench piping. New generation catalyst ( ICR 180) is recommended having higher size i.e “NAQ” from current” L” size. New catalyst system consisting of demet, treating and cracking will provide higher activity, lower pressure drop and flexibility to shift more conversion in Stage1.

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b) HCR Stage 2 Reactors (16-RB-00-201/202) : No changes in reactor internals are expected. New generation catalyst ( ICR 250 is recommended having higher size i.e “NAQ” from current” L” size.

c) DHT Reactor (16-RB-00-301) : No changes in reactor internals except

increase in sizes of orifice of reactor quench piping. New generation catalyst is recommended having higher size i.e “NAQ” from current” L” size. New catalyst system will provide lower activity with a lower hydrogenation and lower pressure drop for higher capacity operation. Quench valve size to be increased

2. Make up Hydrogen Compressors (16-KA-RP-801A/B/C)

The adequacy of the makeup gas compressor has been checked by compressor vendor based on the revamped operating conditions provided by Licensor. However, mechanical adequacy check of the subject compressor and its associated system needs to be carried out and shall require the necessary component modifications. This check will be carried out by vendor during detailed engineering stage.

3. Recycle Gas Compressor (16-KA-CF-401A/B)

Since the adequacy for the RGC based on revamped conditions i..e flow: 496 KNm3/hr, suction / discharge pr: 150.3/ 186.3kg/cm2gas provided by licensor could not be established by compressor vendor, the same shall be checked during detail engineering. Cost provision for new RGC has been kept in the feasibility report.

4. Heaters

The adequacy of hydrocracker furnaces have been checked based on the flow, duty and inlet/outlet temperatures provided by CLG for each of the furnaces. CLG has provided the preliminary adequacy of the heaters with respect to coil change for reduction in pressure drop. EIL carried the detailed adequacy of the furnaces to assess the constructability of the coil change and associated changes in the auxiliaries.

1st Stage HCR Reactor Feed Heater (16-FF-00-101): 1st Stage HCR Reactor Feed Heater is checked for post revamp conditions as tabulated below: Flow

Kg/Hr Duty

MMkcal/hr Temp DegC DP

kg/cm2 In Out Existing Design 277743 8.4 370 402 4.9 Post Revamp 355106*1.

1 8.03 (10% overdesign

margin on revamp duty of 7.2 MMKcal/hr

360 382 4.2

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To achieve the revamped duty with reduction in the pressure drop, coil modifications for the 1st stage HCR reactor Feed Heater, augmentation of heat transfer area and associated modification in the radiant section are envisaged. The modification details are summarized below:

Existing Configuration

Modified configuration based on Preliminary findings

- No. of Cells: 2 (one each for each pass)

- No. of coil passes: 2 - No. of tubes per pass/cell: 12 (total

24 tubes) - Coil orientation: Horizontal - Coil MOC: SS347H - Coil OD: 8 inch (Non standard Coil) - Coil thickness: 17 mm (MWT) - Effective tube length: 12.8 m - Tube Spacing: 431.8 mm (Vertical) - Tube Supports: Ladder Type

- Calculated Pressure Drop: 4.9

Kg/cm2


- No. of coil passes: 2 - No. of tubes per pass/cell: 10 (total 20

tubes) - Coil orientation: Horizontal - Coil MOC: SS347H - Coil OD: 9 inch (Non standard Coil) - Coil thickness: 20 mm (MWT) - Effective tube length: 12.8 m - Tube spacing: 527.7 mm (Vertical) - Tube Supports: Tube supports to be

modified / replaced to suit new coil configuration.

- Calculated Pressure Drop: ~4.2 Kg/cm2

2nd Stage Reactor Feed Heater (16-FF-00-201): 2nd Stage HCR Reactor Feed Heater is checked for post revamp conditions as tabulated below:

Flow

Kg/Hr Duty

MMkcal/hr Temp DegC DP

kg/cm2 In Out Existing Design 208280 6.5 348 379 4.2 Post Revamp 239920 7.15 (10% overdesign


348 376 3.3

To achieve the revamped duty with reduction in the pressure drop, coil modifications for the 2nd stage HCR reactor Feed Heater, augmentation of heat transfer area and associated modification in the radiant section are envisaged. The modification details are summarized below:

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Fractionator Feed Heater (16-FF-00-501): Fractionator Feed Heater is checked for post revamp conditions as tabulated below:

Flow

Kg/Hr Duty

MMKcal/hr Temp DegC DP

kg/cm2 In Out Existing Design 397378 44 300 393 5.2

Post Revamp 488950 44.75 (10% overdesign


310 393 5.2

To achieve the revamped duty with reduction in the pressure drop coil modifications for the Fractionator feed Heater augmentation of heat transfer area and associated modification in the radiant section are envisaged. The modification details are summarized below:


Modified configuration based on

Preliminary findings


- No. of coil passes: 2 - No. of tubes per pass/cell: 12

(total 24 tubes) - Coil orientation: Horizontal - Coil MOC: SS347H - Coil OD: 7 inch (Non standard

Coil) - Coil thickness: 14.9 mm (MWT) - Effective tube length: 12.8 m - Tube Spacing:431.8 mm - Tube Supports: Ladder Type

- Calculated Pressure Drop: 4.2

Kg/cm2



tubes) - Coil orientation: Horizontal - Coil MOC: SS347H - Coil OD: 8 inch (Non standard Coil) - Coil thickness: 17 mm (MWT) - Effective tube length: 12.8 m - Tube Spacing:431.8 mm - Tube Supports: Tube supports to be



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DHT Fractionator Reboiler (16-FF-00-701) : For the revamp conditions as tabulated below as per Licensor data there is no change expected in the heater duty as column is modelled utilizing design margins available in furnace.

Flow Kg/Hr

Duty MMkcal/hr

Temp DegC DP kg/cm2 In Out

Existing Design 252734 9 321 351 5.3 Post Revamp 278000 9.0 303 338 5.3

5. Columns The trays / packing of the all columns have been checked based on the loads provided by Licensor in the report & subsequent discussions & correspondences with Licensor. Findings for each column are tabulated below:

Columns Post Revamp Data Modifications 16-CC-00-401 High Pressure H2S Absorber

Tray 1-10: 16% higher vapor & liquid load than existing design

Dia =2440 mm Trays modifications: Existing 10 no of trays (Tray 1 to


Modified configuration based on

Preliminary findings


- No. of coil passes: 4 - No. of tubes per pass/cell: 20

(total 80 tubes) - Coil orientation: Horizontal - Coil MOC: SS347H - Coil OD , Coil thickness& Tube

spacing : (20 nos. tubes per pass) 8”NB SCH40 coils spaced on 2D/3D spacing.

- Effective tube length: 22.35 m - Tube Spacing:431.8 mm - Tube Supports: Ladder Type - Calculated Pressure Drop: 5.2

Kg/cm2



tubes) - Coil orientation: Horizontal - Coil MOC: SS347H - Coil OD , Coil thickness & Tube

spacing :7 nos. per pass of 8”NB SCH40 and 11 nos. per pass of 10”NB SCH40 spaced on 2D/3D spacing

- Effective tube length: 22.35 m - Tube Spacing:431.8 mm - Tube Supports: Tube supports to be



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Columns Post Revamp Data Modifications 10) need to be replaced with new high capacity trays as per Licensor

16-CC-00-402 Low Pressure H2S Absorber

Packing; 30% higher vapor load than existing design & liquid load is same as existing design.

As Existing

16-CC-00-403 LP Ammonia and Wash Water Column

Packing:30% higher vapor & liquid load than existing design

As Existing

16-CC-00-501 HCR Product Stripper

Above feed section : 50% higher vapor & liquid load than existing design. Below feed section: 30% higher vapor & liquid load than existing design. Feed distributor: 33% higher vapor & liquid load than existing design Liquid re distributor: 30% higher vapor & liquid load than existing design

Dia =1370 mm Trays modifications: Existing 6 no of trays (Tray 1 to 6) need to be replaced with new high capacity trays . New feed distributor & liquid redistributor modifications.

16-CC-00-502 Fractionator

Bottom section:30% higher vapor & liquid load than existing design Tray no 11 to 54 except tray 20-22 & 28-30 : 33% higher vapor & liquid load than existing design Tray 20-22 & 28-30: 33% higher vapor load than existing design &20% higher liquid load than existing design respectively.

Dia =3050 mm Trays modifications: Existing 10 no of trays (Tray 1 to 10) need to be replaced with new high capacity trays. Dia =5180 mm Trays modifications: Existing 37 no of trays (Tray 11 to 22 & Tray 28-54)) need to be replaced with new high capacity trays.

16-CC-00-503 Kerosene side cut Stripper


Dia =1680 mm Trays modifications: Existing 10 no of trays (Tray 1 to 10) need to be replaced with new high capacity trays.

16-CC-00-504 Light Diesel side cut Stripper



16-CC-00-505 Heavy Diesel Stripper


Dia =1680 mm Trays modifications: Existing 10 no of trays (tray 1 to 10) need to be replaced with new high capacity trays.

16-CC-00-601 Deethanizer

Tray 1- 34: 33% higher vapor & liquid load than existing design As Existing

16-CC-00-602 Sponge Oil Absorber

Packing: 33% higher vapor & liquid load than existing design

Packing modifications: Replacement of Bed # 2 of dia 760 mm & height 6400 mm.

16-CC-00-603 Tray 1-42 : 33% higher vapor & liquid Dia =1680 mm

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Columns Post Revamp Data Modifications Debutanizer load than existing design

Feed distributor: 33% higher vapor & liquid load than existing design. Liquid re distributor: 33% higher vapor & liquid load than existing design Bottom reboiler return & sump: 33% higher vapor & liquid load than existing design

Trays modifications: Existing 24 no of trays (Tray 1 to 24) need to be replaced with new high capacity trays. Dia. =1070 mm Trays modifications: Existing 17 no of trays (Tray 25 to 42) need to be replaced with new high capacity trays. New feed distributor & liquid redistributor modifications

16-CC-00-604 Naphtha Splitter

Tray 1-32 : 33% higher vapor & liquid load than existing design.


16-CC-00-701 DHT Product Stripper

Above feed section: 50% higher vapor & liquid load than existing design. Below feed section:30% higher vapor & liquid load than existing design. Feed distributor: 33% higher vapor & liquid load than existing design. Liquid re distributor: 30%higher vapor & liquid load than existing design.

Dia =920 mm Trays modifications: Existing 5 no of trays (Tray 1 to 5) deck plates need to be replaced with new tray deck plates with more no of valves.

16-CC-00-702 DHT Fractionator

Bottom section: 30% higher vapor & liquid load than existing design. Above flash zone: 30% higher vapor & liquid load than existing design.

Dia =2590 mm Trays modifications: Existing 12 no of trays (Tray 1 to 12) need to be replaced with new high capacity trays Existing 6 no of trays (Tray 21 to 26) deck plates need to be replaced with new tray deck plates with more no of valves.

16-CC-00-703 DHT Kerosene side cut Stripper

Tray 1-8 : 30% higher vapor & liquid load than existing design.


6. Vessels

Adequacy of vessels has been checked based on operation feedbacks and from process point of view. All vessels are adequate from process point of view except replacement of the caustic washer (16-VV-VW-603) and LPG coalescer (16-VV-VW-605) with larger vessel. The other modifications of vessels as tabulated below are based on operational feedbacks:

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Vessels Post Revamp Modifications 16-VV-VI-401 Cold High Pressure Separator 401

New Generation Coalescer pad to be consider (typical York pads)

16-VV-VI-404 Cold Low Pressure Separator

New Generation Coalescer pad (typical York pads) to be considered

16-VV-VI-603 Caustic Washer Drum

Replaced by new drum Shell dia.* height: 2000mm*6000mm WT=11 MT New Generation Coalescer pad (typical York pads) to be considered

16-VV-VI-604 Water Washer Drum

New Generation Coalescer pad (typical York pads) to be considered.

16-VV-VI-605 LPG Coalescer

Replaced by new vessel Shell dia.* height: 2000 mm*6000 mm Wt=11.5 MT.

16-VV-HW-607 Naphtha Splitter Reflux Drum

New boot added of dia. 610 mm & length 1400 mm

16-VV-HW-714 DHT Fractionator Overhead Accumulator

Boot replaced with higher dimension of dia. 610 mm & length 1400 mm

7. Pumps

The adequacy of pumps has been checked based on process data provided by CLG in their report,HP pump vendor inputs ,hydraulics done by EIL for LP section pumps & various discussions & correspondences’ with CLG. The adequacy report is summarized below:

Pumps Post Revamp Data Adequacy Results 16-PA-CF-101A1st Stage HCR Reactor Feed Pumps

Existing: Flow: 311.5 m3/hr. Diff. Head: 2405 m Post Revamp Flow: 405 m3/hr Diff. Head: 2402 m

Replaced with New (Flow: 445 m3/hr, Head: 2415m, Motor Power: 3685 Kw) & new PRT.

16-PA-CF-101 B 1st Stage HCR Reactor Feed Pumps

Post Revamp Flow: 405 m3/hr Diff. Head: 2402 m

New

16-PA-CF-102A/B Backwash Oil Pumps

Same as existing As Existing

16-PA-CF-201A/B 2nd Stage HCR Reactor Feed Pumps

Existing: Flow: 272 m3/hr Diff. Head: 2714 m Post Revamp Flow: 327m3/hr. Diff. Head: 2998 m

Impeller change with motor replacement of 2800 KW

16-PA-CF-301A/B DHT Reactor Feed Pumps

Existing: Flow: 282 m3/hr. Diff. Head: 2318 m Post Revamp Flow: 367 m3/hr.

Impeller change with motor replacement of 2700 KW.

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Pumps Post Revamp Data Adequacy Results Diff. Head: 2370 m

16-PA-RP-401A/B Injection Water Pumps

Same as existing As per Licensor, one New Pump 401 C added (Flow:12 m3/hr,Head:1626 m, Motor Power :160 Kw)

LP Lean Amine Pumps 16-PA-CF-402A/B

Existing: Flow: 32.2 m3/hr. Diff. Head: 297 m Post Revamp Flow: 35.42*1.1 m3/hr Diff. Head: 297 m

As Existing

16-PA-CF-403A/B HP Lean Amine HP Pumps

Existing: Flow: 299.2 m3/hr .Diff. Head: 1559 m Post Revamp Flow: 299.2*1.1m3/hr. Diff. Head: 1560.9 m

As Existing

16-PA-CF-404A/B Wash Water Pumps

Existing: Flow: 4.6m3/hr. Diff. Head:271 m Post Revamp Flow: 6 m3/hr. Diff. Head: 277 m.

Impeller change with motor replacement of 8 HP

16-PA-CF-501A/B Product Stripper Reflux Pumps

Existing: Flow: 70.7 m3/hr. Diff. Head: 27 m Post Revamp Flow:115 m3/hr. Diff. Head: 76 m

Replaced with New (Flow: 116.6 m3/hr, Head: 73 m, Motor/ turbine Power : 37 KW)

16-PA-CF-502A/B Naphtha Reflux Pumps

Existing: Flow: 326 m3/hr. Diff. Head: 102 m Post Revamp Flow: 424*1.1 m3/hr. Diff. Head: 85.3 m

Adequate

16-PA-CF-503A/B Fractionator Overhead Water Pumps

Existing: Flow: 11.1m3/hr. Diff. Head: 61 m Post Revamp Flow: 14.43*1.1m3/hr. Diff. Head: 63 m

Adequate

16-PA-CF-504A/B Kerosene Product Pumps

Existing: Flow: 22.1 m3/hr. Diff. Head: 98 m Post Revamp Flow: 33.15*1.1 m3/hr Diff. Head: 140.1 m

Impeller change

16-PA-CF-505A/B Light Diesel Pump around Pumps

Existing: Flow: 279.6 m3/hr. Diff. Head: 63 m Post Revamp Flow: 336*1.1 m3/hr. Diff. Head: 109.2 m

Impeller change with motor replacement of 110 Kw

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Pumps Post Revamp Data Adequacy Results 16-PA-CF-506A/B Light Diesel Product Pumps

Existing: Flow: 151.2 m3/hr. Diff. Head: 144 m Post Revamp Flow: 197 m3/hr. Diff. Head: 140.2 m

Impeller change

16-PA-CF-507A/B Diesel Pump around Pumps

Existing: Flow: 449.9 m3/hr. Diff. Head: 152 m Post Revamp Flow: 540*1.1 m3/hr. Diff. Head: 147.5 m

Impeller change

16-PA-CF-508A/B Heavy Diesel Product Pumps B

Existing: Flow: 105.4 m3/hr. Diff. Head: 204 m Post Revamp Flow: 132*1.1 m3/hr Diff. Head: 208 m


16-PA-CF-509A/B Fractionator Bottoms Pumps

Existing: Flow: 289.9 m3/hr.Diff. Head: 163 m Post Revamp Flow: 348*1.1m3/hr Diff. Head: 172 m

Impeller change with motor & Turbine replacement of 300 Kw .

16-PA-CF-601A/B Sponge Absorber Bottoms Pumps

Existing: Flow: 27.3 m3/hr. Diff. Head: 62 m Post Revamp Flow: 35.5*1.1 m3/hr. Diff. Head: 67 m

Replaced with New (Flow: 39.1 m3/hr, Head: 67 m ,Motor Power :15 Kw)

16-PA-CF-602A/B Deethanizer Reflux Pumps

Existing: Flow: 79.8 m3/hr. Diff. Head: 87 m Post Revamp Flow: 107.8*1.1 m3/hr. Diff. Head: 87.2 m

Impeller change

16-PA-CF-603A/B Deethanizer Bottoms Pumps

Existing: Flow: 91.1 m3/hr Diff. Head: 43 m Post Revamp Flow: 123*1.1 m3/hr. Diff. Head: 38.9 m

Impeller change

16-PA-CF-604A/B Debutanizer Reflux Pumps

Existing: Flow: 41.3 m3/hr. Diff. Head: 234 m Post Revamp Flow: 56*1.1 m3/hr. Diff. Head: 241 m

Impeller change

16-PA-CF-605A/B Naphtha Splitter Reflux Pumps

Existing: Flow: 90 m3/hr. Diff. Head: 159 m Post Revamp Flow: 121*1.1 m3/hr. Diff. Head: 160 m

Impeller change

16-PA-CF-606A/B Existing: Flow: 92.6 m3/hr. Impeller change with motor

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Pumps Post Revamp Data Adequacy Results Naphtha Splitter Bottoms Pumps

Diff. Head: 300 m Post Revamp Flow: 125*1.1 m3/hr. Diff. Head: 273.2 m

replacement of 125 Kw

16-PA-CF-608A/B Sponge Oil Absorber Reflux Pumps

Existing: Flow: 23.6 m3/hr. Diff. Head: 57 m Post Revamp Flow: 30.7*1.1 m3/hr. Diff. Head: 71 m

Impeller change

16-PA-CF-609A/B Make Up Caustic Pumps

Same as Existing As existing

16-PA-CF-610A/B Caustic Washer Circulation Pumps


Replaced with New (Flow: 14.3 m3/hr, Head: 45 m ,Motor Power : 5.5 Kw)

16-PA-CF-611A/B Water Washer Feed Pumps


16-PA-CF-612A/B Degassed Caustic Pumps

Same as Existing Adequate

16-PA-CF-701A/B DHT Product Stripper Reflux Pumps

Existing: Flow: 14.2 m3/hr. Diff. Head: 75 m Post Revamp Flow: 23.4 *1.1 m3/hr. Diff. Head: 87 m

Replaced with New (Flow: 23.4 m3/hr, Head: 87.7 m Turbine & Motor Power : 37 Kw))

16-PA-CF-702A/B DHT Naphtha Reflux Pumps

Existing: Flow: 60.8 m3/hr. Diff. Head: 81 m Post Revamp Flow: 79.04*1.1 m3/hr. Diff. Head: 81m


16-PA-CF-703A/B DHT Fractionator Overhead Water Pumps


16-PA-CF-704A/B DHT Kerosene Product Pumps


Impeller change

16-PA-CF-705A/B DHT Fractionator Bottoms Pumps

Existing: Flow: 731.4m3/hr. Diff. Head: 210 m Post Revamp Flow: 877*1.1 m3/hr. Diff. Head: 207.9 m

Impeller change

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Pumps Post Revamp Data Adequacy Results

16-PA-CF-813A/B Sour Water Pumps

Existing: Flow: 40 m3/hr. Diff. Head: 63.9 m Post Revamp Flow: 67.22 m3/h Diff. Head: 54.5 m

Adequate

8. HP Exchangers

The adequacy for the HP Exchangers has been carried out by CLG and their recommendations are tabulated below: Addition of a new HP exchanger in the MUG compressor discharge circuit is proposed post revamp.

HP Exchanger Adequacy Results as per Licensor 16-EE-00-105A-B 1st Stage Reactor Feed /Effluent Exchanger

Replacement with new for cost purpose, Mechanical Integrity to be checked with respect to vibrations

16-EE-00-106 Inter Reactor Effluent/Fractionator Feed Exchanger

Adequate, Mechanical Integrity to be checked with respect to vibrations

16-EE-00-107 1st Stage Reactor Effluent/DHT Reactor Feed Exchanger

Adequate, Mechanical Integrity to be checked with respect to vibrations

16-EE-00-108 1st Stage Reactor Effluent/Fractionator Feed Exchanger

Adequate, , Mechanical Integrity to be checked with respect to vibrations

16-EE-00-109 1st Stage Reactor Effluent Steam Generator


16-EE-00-201 2nd Stage Reactor Feed/Effluent Exchanger


16-EE-00-202A-B 2nd Stage Reactor Effluent/Fractionator Feed Exchanger


16-EE-00-304A-B DHT Reactor Feed/Effluent Exchanger

Replacement with New for cost purpose, , Mechanical Integrity to be checked with respect to vibrations

16-EE-00-305 DHT Reactor Effluent/Feed Gas Exchanger


16-EE-00-401 DHT HHPS Vapor/CLPS Liquid Exchanger

New Heat Exchanger considered based on 20 % higher area than existing exchanger area. For cost purpose, , Mechanical Integrity to be checked with respect to vibrations

16-EE-00-402 1st Stage HHPS Vapor/Feed Gas Exchanger

New Heat Exchanger considered with 30 % higher weight of existing bundles for cost purpose , Mechanical

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Integrity to be checked with respect to vibrations

EE-00-403 Make Up Hydrogen/Cooling Water

New Exchanger With following Specifications Type: AEL, No of Shells: One Area: 81m2

9. LP Exchanger

All the LP exchangers are found adequate with nozzle modifications, tube pass modification and addition of shell in series /parallel wherever required. Replacement of exchangers in five cases is considered (mainly reboilers) and two new LP exchangers are added. The LP exchangers have been checked based on the data provided by CLG in their report, adequacy checks done by EIL & various discussions & correspondences’ with CLG. The adequacy report is summarized below:

LP Exchangers Post Revamp Data Adequacy Results 16-EE-00-101 Common HCR-DHT Cold Feed Heater

Same as existing As existing

16-EE-00-102 HCR Feed/Light Diesel Exchanger

Existing Duty : 4 MMKcal/Hr Revamp Duty : 5.5 MMKcal/Hr

Tube side Inlet/Outlet nozzle Sizes to be increased to 10”/10” from existing 8”/8”.

16-EE-00-103 HCR Feed/Heavy Diesel Exchanger

Existing Duty : 1.7 MMKcal/Hr Revamp Duty : 2.3 MMKcal/Hr


EE 104 HCR Feed /Frac Bottom Exchanger -

Duty: 1.7MMKcal/hr New Exchanger With following Specifications Type: AES, No of Shells: One Size: 725*3000mm Area: 65m2

16-EE-00-302 DHT Feed/ Diesel Product Exchanger


Replaced with new Area: 650 m2/shell Size: 1350mm x 6000mm No of shells : 1

16-EE-00-405 Treated CLPS Vapor cooler


Adequate

16-EE-00-406 Lean Amine Heater

Duty: 5.6 MMKcal/Hr

Adequate

EE 407 Injection Water Cooler

Duty:0.67MMKcal/hr New Exchanger With following Specifications Type: AES,

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No of Shells: One Size: 575*6000mm Area: 110m2

16-EE-00-503 Kerosene Stripper Reboiler

Existing Duty:1.5 MMKcal/Hr Revamp Duty: 2.2 MMKcal/Hr

Replaced with new Area: 60 m2 Size: 800mm x 2500mm No of shells : 1

16-EE-00-505 Kerosene Product Water Cooler

Existing Duty: 0.2 MMKcal/Hr Revamp Duty: 0.26 MMKcal/Hr


16-EE-00-506 Light Diesel Stripper Reboiler


Adequate

16-EE-00-508 Light Diesel Product Water Cooler

Existing Duty: 1.1 MMKcal/Hr Revamp Duty: 2.3 MMKcal/Hr


16-EE-00-511 Heavy Diesel Product Water Cooler

Existing Duty : 0.9 MMKcal/Hr Revamp Duty: 1.55MMKcal/Hr

Tube pass modification for changing 4 pass to 2 pass

16-EE-00-512 MP Steam Generator

Duty: 5.49MMkcal/hr Adequate as per Licensor

16-EE-00-514A/B Heavy Diesel Product/BFW Exchanger


Adequate

16-EE-00-601A/B Deethanizer Overhead Cooler


Adequate

16-EE-00-602 Deethanizer Reboiler


Replaced with new Area : 265 m2/shell Size : 1150mm x 4000mm No of shells : 1

16-EE-00-603A/B Debutanizer Overhead Cooler

Existing Duty :2 MMKcal/Hr Revamp Duty : 2.66 MMKcal/Hr


16-EE-00-604 Debutanizer Reboiler


Replaced with new Area : 155 m2 Size : 1025mm x 3000mm No of shells : 1

16-EE-00-606 Naphtha Splitter Reboiler


Replaced with new Area : 185 m2 Size : 1250mm x

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3000mm No of shells : 1

16-EE-00-607 Light Naphtha Product Cooler


Adequate

16-EE-00-609AB Heavy Naphtha Product Water Cooler



16-EE-00-610 Sponge Oil/Naphtha Exchanger


Adequate

16-EE-00-612 Sponge Oil Absorber Overhead Cooler


Additional shell Area : 72 m2/shell No of shells : 1

16-EE-00-702 DHT Fractionator Feed/Bottoms

Adequate as per Licensor

16-EE-00-704 DHT Diesel Product /BFW Exchanger



16-EE-00-706 DHT Kerosen Sidecut Stripper Reboiler


Adequate

16-EE-00- 708 DHT Diesel Water Cooler


Tube side Inlet/Outlet nozzle Sizes to be increased to 10”/10” from existing 8”/8”. Also tube pass modification for changing 4 pass to 2 pass

10. Air Coolers

The reaction effluent air cooler (16-EA-FN-403) in the HP section is found adequate with replacement of motors of fans from 30 HP to 40 HP. All other air coolers in the LP section are found adequate with replacement of fan or addition of bay wherever required. One additional air cooler has been considered in LT diesel pump around circuit. The LP air coolers have been checked based on the data provided by Licensor , adequacy checks done by EIL & various discussions & correspondences’ with CLG.The adequacy report is summarized below:

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Air Coolers Post Revamp Data Adequacy Results

16-EA-FN-110 Backwash Oil Air Cooler

Revamp Duty: 7.1 MMKcal/Hr same as existing

Adequate

16-EA-FN-403 Reactor Effluent Air Cooler

Duty: 27.8MMKcal/hr Motor replacement of 40 HP for air temp of 42degC.

16-EA-FN-404 HCR HLPS Vapor Air Cooler

Existing Duty : 2.8 MMKcal/Hr Revamp Duty: 4 MMKcal/Hr

An additional bay (identical to existing bay ie 5.0 m*8.5 m) to be considered.

16-EA-FN-501 Product Stripper Overhead Air Cooler

Existing Duty : 9.8MMKcal/Hr Revamp Duty: 12.74 MM Kcal/Hr

An additional bay added (identical to existing 2 bays each bay of ie 5.4 m*8.5 m) to be considered.

16-EA-FN-502 Fractionator Overhead Air Cooler

Existing Duty : 33.90 MM Kcal/Hr Revamp Duty: 32 MM Kcal/Hr

Adequate

16-EA-FN-504 Kerosene Product Air Cooler

Existing Duty : 1.4 MM Kcal/Hr Revamp Duty: 1.82 MM Kcal/Hr

Adequate

16-EA-FN-507 Light Diesel Product Air Cooler


Adequate

16-EA-FN-510 Heavy Diesel Product Air Cooler

Existing Duty:3.94 MM Kcal/Hr Revamp Duty: 5.24MMKcal/Hr

Adequate

16-EA-FN-513 Fractionator Bottoms Product Air Cooler

Duty : 19.6 MMKcal/hr same as existing

As existing

16-EA-FN-514 Lt Diesel Pump Around Air Cooler

Duty: 3.45MMkcal/hr New Air cooler With following Specifications No of bays/unit: one No of bays/bundle: one Approx Dimension:3.0 m x6.5 m Area: 80 m2

16-EA-FN-605 Naphtha Splitter Overhead Cooler


An additional bay added (Identical to existing 2 bays each bay of i.e 5.3 m*10.5 m) to be considered .

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Air Coolers Post Revamp Data Adequacy Results

16-EA-FN-608 Heavy Naphtha Product Air Cooler


Adequate

16-EA-FN-701 DHT Product Stripper Overhead Cooler

Existing Duty : 2.9 MMKcal/Hr Revamp Duty: 3.77 MM Kcal/Hr

Motor replacement of 30 HP

16-EA-FN-703 DHT Fractionator Overhead Air Cooler

Existing Duty : 6.10 MMKcal/Hr Revamp Duty: 7.93 MMKcal/Hr

Motor replacement of 50 HP

16-EA-FN-707 DHT Diesel Product Air Cooler


Adequate

11. Miscellaneous Systems

The new facilities as per client operational constrain and based on licenser recommendations are considered as tabulated below:

Miscellaneous Adequacy Results

16-GN-00-1011st Stage HCR Feed Filter

One additional bank similar to existing banks

16-GN-00-301 DHT Feed Filter One additional bank similar to existing banks

16-VV-VW-405 Low Pressure Centrifugal Separator

Replaced by new

16-VV-VW-402 High Pressure Centrifugal Separator

Replaced by new

16-VV-VW-104A Backwash Oil Surge Drum

New Backwash Oil Surge Drum similar to existing (16-VV-VW-104)

16-EA-FN-110A Backwash Oil Air Cooler

New Backwash Oil Cooler (16-EA-FN-110) similar to existing

16-PA-CF-102A/B (N) Backwash Oil Pumps

New Backwash Oil Pumps (16-PA-CF-102A/B) similar to existing


The existing plot was considered for all the proposed modifications and it was determined that there is sufficient space for new/modified equipment. A joint site visit was made by EIL and BORL team to assess the extent of modification work involved in the revamp as well as to locate space for the new equipments.

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The modifications /new facilities as detailed above were checked and found feasible from construction and implementation point of view with the following observations: The existing structure to be extended to accommodate one additional bay in Naphtha splitter overhead cooler (16-EA-FN-605). For extension of structure one exchanger (16-EE-00-610) has to be relocated adjacent to (16-EE-00-601A).

Structural work is envisaged for carrying out the modifications listed above (like making of new tech structures to accommodate new bays of air coolers, relocation of staircase etc.).

Piping rerouting/modifications shall be required wherever new vessels/exchangers/air coolers/pumps are to be accommodated

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SECTION 7.3.4

MS BLOCK

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7.3.4.1 MS BLOCK (NAPTHA COMPLEX)

Naphtha complex (MS Block) of Bina refinery consists of Naphtha hydrotreater (NHT) of capacity of 1.0MMTPA , Continuous catalytic reformer (CCR Platforming unit) of capacity of 0.54MMTPA, a Cyclemax CCR Regeneration section and a Penex process unit of capacity of 0.31MMTPA. These units were designed by UOP in the year 2006 for the production of Euro III and Euro IV grade gasoline. Under this project, unit licenser M/s UOP carried out a process study to explore technical feasibility of MS block for processing of additional naphtha due to expansion of refinery and maximum processing of Hydrocracker heavy naphtha with the objective of maximization of production of Euro IV grade gasoline and low cost upgradation of existing units. To accomplish the objectives, UOP conducted a MS blending and preliminary revamp feasibility studies. There after objective of study was revised for 100% production of Euro IV/Euro V MS and the following were concluded: Revamp of existing MS Block

NHT - 145% increase in capacity (SRN + HCU HN) Penex – 181% increase in capacity CCR/Plaforming – 130% and 146% increase in capacity

Based on above, UOP has carried out detailed Revamp feasibility study which included evaluation of operating process parameters, identification of the bottlenecks, modification in major equipment and requirement of new equipments. Also, UOP carried out assessment of MS blending for total production of 100% Euro IV/Euro V MS utilizing available naphtha streams. UOP evaluated and presented various cases which involved revamping of Penex and CCR units and MTBE blending etc. Based on techno- commercial evaluation the option wherein revamp of Penex unit to 181% and CCR revamp capacity of 146% was selected. The revamp of Penex to 181% capacity is comparatively simpler and can be implemented with minimum shutdown time and low capital cost. UOP performed high level assessment for 181% increase in capacity of Penex unit and provided additional new equipments along with cost estimates to be considered in detail feasibility report.

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7.3.4.2 FEASIBILITY STUDY REPORT

The outlines of Feasibility study report of MS block as furnished by UOP are presented in next section.

1. Naphtha Hydro Treating Unit (NHT)

The UOP Naphtha Hydrotreating unit is a catalytic process that removes organic sulfur, oxygen and nitrogen from the naphtha streams. Process flow scheme as furnished by UOP in their report is attached in Annexure 3. The key features and modification as reported in UOP Revamp feasibility report which are considered under this project are summarized below:

The unit has been checked to process approximately 1,450,234 MTPA naphtha feed (@8280 hours per year operation, approximately 145% of original design feed rate) consisting of 1,081,362MTPA of straight run naphtha, 213,682MTPA of HCU light naphtha and 155,189 MTPA of HCU heavy naphtha.

The naphtha feed spec considered is same as original naphtha feed composition

except that the sulfur and the N2 of the blended feed to be considered as 500 ppmwt sulfur and 2 ppmwt Nitrogen.

The product specifications considered for NHT revamp are:

i) Naphtha Splitter overhead liquid: 5.63 wt% C7+to maintain 10 wt % C7+ in Depentaniser bottom.

ii) Naphtha Splitter net bottom liquid: 0.5 vol% max benzene precursor. iii) Sulfur and N2 less than 0.5 wt ppm.

Reactors (19-RB-00-101) : The existing reactor is suitable for the NHT revamp

conditions without internals modification. The reactor needs new charge of catalyst (HYT-1119) and new catalyst volume and three layers of top graded beds (Cat Trap 10, Si Trap 30 and TK-437).

Make up Hydrogen Compressors (19-KA-RP-101A/B): Existing Recycle

Compressor has been evaluated based on the required revamp operating condition and found to be adequate to handle the increased inlet volumetric capacity. Based on the preliminary evaluation, the motor appears to be adequate. The existing motor power rating is 320 kW whereas the revamp brake horse power is 226 kW.

Stripper Reboiler Heater (19-FF-00-102): It was found inadequate with regards to

burner capacity to provide revamp duty of 8.59MMkcal/h as against original design

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duty of 7.21MMKcal/hr. To avoid the modifications of the existing stripper reboiler, the convection section of the Auxiliary Naphtha Splitter Reboiler Heater will provide the heat (~1.26 MMKcal/hr ) to Stripper bottoms first and then routed to the existing Stripper Reboiler Heater.

Splitter Reboiler Heater (19-FF-00-103) and Auxilliary Naphtha splitter Reboiler

Heater (19-FF-00-103B): The required process duty of the Naphtha Splitter Reboiler for the revamp case is 15.75 MM Kcal/hr. The existing heater is inadequate to handle the revamp process duty even with modifications. UOP recommends adding an Auxiliary Naphtha Splitter Reboiler Heater in parallel to the existing heater to supplement the required process duty for the revamp operation. The convection section of the auxiliary heater will be utilized for heating both Stripper bottoms and Naphtha Splitter bottoms. The maximum duty from the existing Naphtha Splitter Reboiler Heater will be 11.35 MM Kcal/hr without the burner modification and the remaining duty of 4.4 MMKcal/hr will be provided by the auxiliary Naphtha Splitter Reboiler Heater.

The adequacy and modifications suggested for other equipments as well as

requirement of new equipments as proposed in UOP revamp feasibility study report are summarized below in Table 7.3.4.1 and overall equipment list is tabulated in Annexure 2.

Table 7.3.4.1.: List Of New/Modified Equipments

SL NO TAG NO DESCRIPTION MODIFICATION

COLUMNS

1 19-CC-00-101 Stripper Existing 20 No of trays of bottom section to be replaced with new trays

2 19-CC-00-102 Naphtha Splitter

Existing 24 No of bottom section trays to be replaced with 28 Nos. of ECMD trays

VESSELS

1 19-VV-HW-106 Water Break Tank Existing tank to be replaced by new. Dimensions dia*length:0.8m*1.9m

REACTORS

1 19-RB-00-101 Reactor As existing with New catalyst EXCHANGERS 1

19-EE-00-101A-F Combined Feed Exchanger

6 Additional shells to be installed in parallel Area-4074 m2 Size: 1125mm*6000mm No of shells : 6

2 19-EE-00-102 Stripper Feed-Splitter

Bottoms Exchanger

Replaced by larger exchanger Area-52.6 m2 No of shells : 1

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3

19-EE-00-104 Naphtha Splitter Bottoms Cooler

Requires two Identical Shells in parallel Area-356.8 m2 Size: 600mm*6000mm No of shells : 2

AIR COOLERS

1 19-EA-00-103 Naphtha Splitter Condenser

Post revamp- Two additional bays same as existing (5.8m*10.5m) are required

PUMPS

1 19-PA-CF-101A/B Charge Pumps Impeller of higher dia with new motor of 510 KW

2 19-PA-CF-102A/B Wash Water Injection

Pumps

Replaced by New pump (Flow-7.72m3/hr; head 366.1m; Power-30 KW)

3 19-PA-CF-104A/B Naphtha Splitter Bottoms Pump

Impeller of higher dia with new motor of 300 KW

4 19-PA-CF-105A/B Naphtha Splitter Overhead Pump

Impeller of higher dia with new motor of 110 KW

NEW EQUIPMENTS 1

19-FF-00-103B Naphtha Splitter Reboiler Auxilliary Heater

One Auxiliary Heater in parallel for naphtha splitter and convection section to be used for naphtha splitter reboiler. Duty (Absorbed) - 4.4 MMCkal/hr

2 Product Trim Condenser

New exchanger Area-158.4 m2 No of shells : 2

2. Continuous Catalytic Reforming Unit (CCR)

UOP performed revamp feasibility study report of CCR unit for 130% (678859 MTPA) and 146% ( 793,113 MTPA) increase in existing capacity considering feed composition as derived by NHT unit yield estimate and simulation work for the naphtha splitter. The CCR REGENERATOR section assessment had been performed by UOP previously and was excluded from the scope of current study of UOP. Since the additional modification required in the case of 146 % from 130 % is very minimal, the 146 % case is pursued for detail feasibility report and considered as revamp case. The process flow scheme as provided by UOP in their report is attached in Annexure 3.

The key features and modification as reported in UOP Revamp feasibility report, are summarized below:

The CCR unit shall produce 98C5+RONC reformate as in the original design. Reactors: The existing reactors were evaluated for the new revamp conditions

with R-264TM catalyst and found to be adequate. The revamp operating

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conditions are within the limits in terms of reactor design temperature and pressure. The catalyst volume specified for the new operating conditions is also the same as the originally specified volume.

Net Gas Compressors (20-KA-RP-102A/B/C): The existing Net Gas Compressors

are adequate for the revamp operating condition for both 130% and 146% operating case based on implementation of suggested revamp to recontact section exchangers. The compressor spillback would be limited to 5% during revamp operation. The adequacy of the compressors has been checked by UOP based on the vendor as built documents and the revamp conditions. BORL has decided to consider one more Net Gas compressor based on actual performance of the compressors and cost provision has been kept for the same. .

Recycle Gas Compressor (20-KA-CF-101A/B): The existing Recycle Compressor

appears to be adequate for the revamp process requirements for both 130% and 146% operating case. For the 146% operating case, the Separator pressure has been increased from original design of 2.46 Kg/cm2g to 2.81 Kg/cm2g to enable Recycle Compressor operate within existing performance curve. The compressor is estimated to run at about 102% of its original design speed for the revamp operation.

Recovery Plus: Post revamp the net gas flow is around 39 KNM3/h for 146% and the existing Recovery Plus unit which is designed for 25 KNM3/h is not adequate to handle the revamp net gas flow for both 130% and 146% operating cases. A parallel new Recovery Plus unit was proposed by UOP to handle the total net gas for the revamp operating conditions. The new Recovery Plus system will have a design net gas processing capacity of approximately 15KNm3/h. UOP provided a cost estimate for the new recovery plus and considering the prevailing LPG ,naphtha and fuel gas price at BORL, the payback worked out to be ~9 yrs. Hence it is decided not to install the new recovery plus system.

Charge Heater, interheaters & debutanizer reboiler (20-FF-00-101/102/103/104) :

The heaters have been checked considering only fuel gas firing in the heaters post revamp. For both 130% and 146% operating cases, burner replacement is required for all the reactor section heaters. The extent of modification will require further analysis, but it will range from simple replacement of fuel gas tips with larger orifice drillings (probably possible for 125% design case) to the replacement of burners with burners that have greater heat release capabilities than current model sizes installed (likely for 146% design case). The common stack for the NHT and the Platforming heaters seem to be adequate for the revamp process condition.

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The adequacy and modifications suggested for other equipments as well as requirement of new equipments as proposed in UOP revamp feasibility study report are summarized below in Table 7.3.4.2 and overall equipment list is tabulated in Annexure 2.


SL NO

TAG NO DESCRIPTION MODIFICATION

FIRED HEATERS 1 20-FF-00-101 Charge Heater Replacement of burners with high

heat release burner Duty (Absorbed): 12.14 MMKcal/h

2 20-FF-00-102 No 1 Interheater Replacement of burners with high heat release burner Duty (Absorbed): 11.89 MMKcal/h

3 20-FF-00-103 No 2 Interheater Replacement of burners with high heat release burner Duty (Absorbed): 8.37 MMKcal/h

EXCHANGERS 1

20-EE-00-103 Net Gas Cooler

Additional shell in parallel Area-359.2 m2. Size: 775mm*6000mm No of shells : 1

2

20-EE-00-104 Recontact Cooler No 1

Additional shell in parallel required Area-722.4 m2 Size: 1050mm*6000mm No of shells : 1

3

20-EE-00-106 Debutanizer Bottoms Cooler

Additional shell in parallel required Area-442 m2 Size: 800mm*6000mm No of shells : 1

AIR COOLERS 1 20-EA-00-101 Product Condenser One additional bay same as

existing (6.2m*10.5m) required PUMPS 1 20-PA-CF-

101A/B Separator Pumps Impeller of higher diameter required

2 20-PA-CF-102A/B

Debutanizer Reboiler Pumps

Impeller of higher diameter required

NEW EQUIPMENTS 1 20-KA-RP-102C Net Gas

Compressor One additional new net gas compressor is required.

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3. Penex Process Unit UOP performed revamp feasibility study report of Penex considering feed composition as derived by NHT unit yield estimate and simulation work for the naphtha splitter. The process flow scheme as provided by UOP in their report is attached in Annexure 3. The key features and modification as reported in UOP Revamp feasibility report which are considered under this project, shall be confirmed during design stage. Also UOP will attempt to optimise the scheme to reduce some of equipment count(if possible) at the time of basic engineering. The key findings and modifications are as follow:

The unit has been checked meeting the following product specification: The De-pentanizer column net overhead liquid shall have minimum 97 wt%C5+. The De-pentanizer column net bottoms liquid shall have maximum 10 wt% C7+.

As a result of the adequacy check of the Penex , the Isomerate Product resultant

(DIH bottom plus DIH overhead) maximum achievable C5+ RONC is 88.5 for SOR and 87.5 for EOR .

Methanator Reactor:The existing Methanator Reactor was evaluated for the new

revamp conditions with PURASPEC 2020 catalyst and found to be adequate. The revamp operating conditions are within the limits in terms of reactor design temperature and pressure. The expected bed life for the revamp flow is around 3 yrs.

Penex Reactors: The existing Penex Reactors were evaluated for the new revamp conditions with I-82 catalyst. The revamp operating conditions are within the limits in terms of reactor design temperature and pressure. To meet the revamp scenario UOP suggested adding more catalyst in existing Reactors. UOP suggests that each of the Penex Reactors (15-RB-00-202 A/B/C) can accommodate 1.76 m3 more catalyst with following modifications: Existing Vapor and liquid distribution tray is not suitable for revamp operating conditions. UOP recommends two options for VLD tray

- Modified VLD tray by increasing size of all holes (by 2mm) on each VLD tray riser

- Provide New VLD tray. VL tray (new or modified) need to be placed 300mm above from current location on new support structure welded/attached on existing Reactor wall or existing ring

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Makeup Hydrogen Compressors( 15-KA-RP-201A/B): Existing Makeup Compressors (15-KA-RP-201A/B) have been evaluated based on required revamp capacity and discharge pressure considering one machine is operating and the other is on stand-by mode. With spillback of around 5 %, the Makeup Gas Compressors are adequate for the Makeup gas from CCR Platforming Unit. However for the Makeup gas from PSA Unit, the Makeup Compressors are not adequate since the supply pressure of the gas from the PSA unit is lower and consequently the required volumetric flow rate is high. Even with the battery limit pressure of the PSA gas increased from 20 Kg/cm2g to 21.5 Kg/cm2g and reduced spill back (5 %), the Makeup Compressors fall short by around 5.3 % to handle the revamp conditions. In order to make the existing machines adequate, the battery limit pressure of the PSA gas needs to be increased to around 22.6 Kg/cm2g.The option of revamping the compressor shall be explored during detail engineering.

The adequacy and modifications suggested for other equipments as well as requirement of new equipments as proposed in UOP revamp feasibility study report are summarized below in Table 7.3.4.3 and overall equipment list is tabulated in Annexure 2.



COLUMNS 1 15-CC-00-202 Net Gas Scrubber Gas Distributor to be modified

2 15-CC-00-204 Deisohexanizer Existing 80 Nos. of valve trays to be replaced with 95 nos. of ECMD trays

VESSELS

1 15-VV-VI-205A/B Feed Driers As Existing, Change in piping for change in flow direction

2 15-RB-00-202A/B Penex Reactor New vapour liquid distribution tray at new location and additional catalyst

EXCHANGERS

1 15-EE-00-201 Methanator Heater Replaced by new larger exchanger Area/shell-9.1 m2

2 15-EE-00-208 Cold Combined Feed Exchanger

Existing tube bundle needs to be replaced by new

3 15-EE-00-209 Hot Combined Feed Exchanger

Replaced by new larger exchanger

4 15-EE-00-211 Stabiliser Reboiler New Tube Bundle with High Flux Tubes Area -338.8m2 No of shells : 2

5 15-EE-00-212 Stabiliser Condenser Replaced by new larger exchanger Area-660 m2

6 15-EE-00-213 Stabiliser Net Gas Chiller

Replaced by new larger exchanger Area- 215 m2 Size: 850mm*5500mm

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7 15-EE-00-214 LPG Stripper Reboiler Replaced by new larger exchanger Area-17 m2

8 15-EE-00-215 LPG Cooler Replaced by new exchanger Area- 45 m2

9 15-EE-00-216 Deisohexanizer Side Draw Reboiler

Replaced by new with high flux Tubes Area-214.7 m2

10 15-EE-00-217 Deisohexanizer Reboiler

New tube bundle with high flux Tubes Area-300 m2

11 15-EE-00-218 Deisohexanizer Bottom Cooler

Replaced by new larger exchanger Area-55 m2

12 15-EE-00-219 Isomerate Cooler Tube bundles to be replaced

13 15-EE-00-222 Depentanizer Overhead Cooler

Replaced by new Exchanger Area-121 m2

AIR COOLERS

1 15-EA-00-202 Deisohexanizer Condenser

Two additional bays same as existing (5.55m*10.5m) is required.

2 15-EA-00-203 Depentanizer Condenser

One additional bay same as existing (5.4m*10.5m) is required.

PUMPS

1 15-PA-CF-201A/B Charge Pump Impeller change with motor replacement of 230KW

2 15-PA-CF-206A/B Deisohexaniser Side Draw Pumps

New Impeller of larger diameter is required

3 15-PA-CF-208A/B Deisohexaniser Overhead Pumps


4 15-PA-CF-209A/B Depentanizer Overhead Pumps


5 15-PA-CF-226A/B LP Condensate Pumps New Impeller of larger diameter is required

6 15-PA-CF-230A/B Sour Water Degassing Pump


NEW EQUIPMENTS

1 15-EE-00-223 Intermediate Combined Feed Exchanger

New Exchanger Area-228 m2

2 15-XZ-00-205A Refrigeration package Additional refrigeration package required for balance capacity.

3 Two additional reactors(One lead and lag reactor)

(Note 1)

4 CCFE,HCFE& Charge Heaters

(Note 1)

7 Deisohexaniser Column and its associated equipments

Associated equipments consists of Separator, condenser, reboiler, reflux pump, S/D pump, bottom pump (Note 1)

8 Stabiliser and its associated systems

Associated equipments consists of reboiler, product condenser, stabilizer reflux pump (Note 1)

Notes 1. Required for 181% capacity increase in PENEX unit.

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UOP will attempt to optimise the scheme to reduce some of equipment count (if possible) at the time of basic engineering.


The existing plot was considered for all the proposed modifications and it was determined that there is sufficient space for new/modified equipment.

A joint site visit was made by EIL and BORL team to assess the extent of modification work involved in the revamp as well as to locate space for the new equipments. The modifications /new facilities as tabulated above were checked for and found feasible from construction and implementation point of view with the following observations: NHT Unit The space for new naphtha splitter reboiler auxillary heater (19-FF-00-103B) is identified adjacent to the existing heater (19-FF-00-103). Two stacked shells of new Combined feed exchanger (19-EE-00-101 G/H) to be located near existing (19-EE-00-101 A/B).Two stacked shells (19-EE-00-101 I/J) to be located at the grade level on north of (19-EE-00-101 E/F) and for other two shells (19-EE-00-101 K/L) additional structure(7m*4m) to be made.

CCR Unit New net gas compressor can be located on north of 20-KA-RP-102. Presently this space is reserved for dropout. New dropout shall be created at the southern end of the shed

PENEX Unit The new refrigeration package shall be located towards east of existing refrigeration section (15-XZ-00-205). In addition, structural work is envisaged for carrying out these modifications ( like making of new tech structures to accommodate new bays of air coolers, relocation of staircase etc.). Also piping rerouting/modifications shall be required wherever new vessels/exchangers/air cooler/pumps are to be accommodated.

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SECTION 7.3.5

HYDROGEN GENERATION UNIT (HGU)

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7.3.5.0 HYDROGEN GENERATION UNIT 77,000MTPA of Hydrogen has been operating at Bina refinery to cater the H2 requirement of hydrocracker unit, DHDT and MS block. The unit was commissioned in the year 2010.

The unit consists of Naphtha Dechlorination / Desulphurisation, Steam Naphtha reformer, HT shift Reactor and a Pressure Swing Adsorption (PSA) for Hydrogen purification. The unit is designed for hydrocracker naphtha and hydrotreated mix pentane as a feed & fuel to the reformer. Under this project, Technip has been awarded to conduct a revamp study for increase in capacity of hydrogen unit to meet the requirement of hydrogen for expansion of HCU, DHDT and MS Block.

7.3.5.1 REFINERY HYDROGEN BALANCE

To establish the revamp capacity of unit, the refinery hydrogen balance is worked out based on the followings: 35% increase in capacity of HCU/DHDT 45% increase in NHT 81% increase in ISOM 46% increase in CCR capacity

Existing

(KTPA) Revamp (KTPA)

Hydrogen Consumption HCU/DHT 86.7 114.7 NHT+ISOM 4.9 10.56 Total 91.6 125.3 Hydrogen Generation H2 from ROG PSA

24.5 32.16

H2 from HGU 67.0 93.15 H2 plant capacity 77 % Revamp ~21

Post revamp, the Hydrogen requirement may increase by 27% to cater the H2 requirement n the case of CCR shutdown operating at lower load.

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FEASIBILITY STUDY REPORT

M/S Technip carried out revamp feasibility study for following cases considering naphtha feed with FBP of 184 degC (which is heavier naphtha than the plant is designed for):

15% increase in hydrogen design capacity (i.e. margin over 77KTPA of hydrogen).

27% increase in hydrogen design capacity (i.e. margin over 77KTPA of hydrogen).

In order to achieve a capacity increase of 15% or more, Technip proposed the following two combinations which are economically most feasible.

Case 1: incorporation of Prereformer + LT shift (15% capacity increase) Case 2: Incorporation of Prereformer + TPR + LT shift (27% capacity increase)

Technip performed a study to identify the adequacy of existing equipment and determine new/modified equipment with the level of investment associated for each case considering no up-gradation of reformer.

Based on post revamp H2 requirement as stated in section 7.3.5.1 above, BORL opted to pursue the Case 2 which enhances the design capacity by 27% . The process flow scheme for Case2 as given by Technip in their report is attached in Annxure-3.

The key features and modification as reported in Technip Revamp feasibility report are summarized below:

Steam Reformer (18-FD-00-11): Existing reformer is adequate for increased plant capacity with integration of pre-reformer and LT shift reactor. However main header of the inlet system needed to be replaced with new material (SS 347H) due to higher inlet temperature. Reformer burners are on limits and shall be checked with vendor in detailed phase. Also the convection section of existing steam reformer needs to be modified to handle the revamp load. The details of modifications required are summarized below: a) Feed/Steam Superheater (18-EE-00-22): Due to higher inlet temperature,

bottom three rows need to be replaced with three rows of SS 347H. MOC of outlet header shall be changed to SS 347H.

b) Naphtha Feed Superheater (18-EE-00-25): The coil arrangement needs to be changed (stream distribution change to 28 from existing 8) to reduce the pressure drop across the coil. Also the inlet and outlet manifold size shall be increased to 12” from existing 8”.

c) Pre-reformer Preheat Coil (18-EE-00-26): To preheat the feed for pre-reformer, an additional coil needs to be incorporated in convection section of steam reformer. New coil with 5 rows of MOC P22 and 3” ID shall be provided in between 18-EE-00-22 and 18-EE-00-23.

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Pre-Reformer (18-RB-00-10A/B): The Pre-reformer needs to be installed

upstream of TPR because direct naphtha reforming in TPR is not favourable due to following reasons: a) The potential for potash fouling on the shell side migrated by primary reformer

effluent leading to poor heat transfer within the TPR in longer term b) The potential for condensation of heavy hydrocarbon where the tube sheet

meets the refractory.

Therefore in heavy hydrocarbon based plant, a pre-reformer must be installed before TPR can be used. Two pre-reformer reactors (1W+1S) will be installed in plant to provide flexibility of on line replacement of the pre-reformer catalyst for plant operation.

TPR (18-FD-00-12): For increased plant capacity, a TPR is provided in parallel to the existing reformer. An add on TPR provides extra plant capacity without modifying the steam reformer. TPR is a tubular reformer in which heat of reaction is supplied by hot process stream at the shell side of the reactor. It is placed in parallel to the steam reformer in such a way that hot effluent from the steam reformer is used as heat source for TPR.

LT Shift Reactor (18-RB-00-14): For additional conversion of carbon monoxide

and to improve hydrogen yield, LT shift reactor shall be provided downstream of HT shift reactor.

H2 Booster Compressor: M/s Technip has worked out a battery limit pressure of 17.52 kg/cm2g as against 21.5kg/cm2g required based on the hydraulic study and suggested a booster compressor to boost up the pressure from 17.52 kg/cm2g to required 21.5 kg/cm2g.

EIL reviewed the pressure profile submitted by M/s Technip and based on the hydraulic check in both ISBL and OSBL system, the followings are suggested to M/s Technip for elimination of H2 product booster compressor: A parallel product Hydrogen line will be laid to HCU/DHDT block.

Set point of Pressure controller located at downstream of dechlorinator / desulfurization reactor was increased from the existing design value of 31.3 kg/cm2g as was considered by Technip to 33.1kg/cm2g which will meet the desired battery limit pressure of 20.2 kg/cm2g.

This results in increase in mixing point (Mixing point is defined as the point where the recycle gas from the recycle gas compressor and naphtha from the feed pump mixes) pressure which provide additional pressure required in the circuit.

The pressure controller set point is maintained by controlling the discharge pressure of the naphtha feed pump.

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The adequacy of the recycle gas compressor and naphtha feed pumps were checked and found feasible to ensure higher mixing point pressure as 35.2kg/cm2g.

EIL submitted above modifications along with detailed hydraulic study to Technip for their confirmation. M/s Technip accepted that elimination of the booster hydrogen compressor is possible and recommended the same to BORL.

The adequacy and modifications suggested for other equipments as well as requirement of new equipments as proposed in Technip revamp feasibility study report are summarized below in Table 7.3.5.1 and overall equipment list is tabulated in Annexure 2.

Table 7.3.5.1: List of modified Equipments in HGU

SL NO TAG NO DESCRIPTION MODIFICATION REACTORS 1 18-RB-00-11 Comox Reactor Modification in inlet distributor 2 18-RB-00-12A/B Dechlorinator/Desulph

uriser Reactor Modification in inlet distributor

VESSELS

1 18-VV-VI-14 Cold Condensate Separator

Replaced by new vessel with specification Dia(mm)*Height(mm) :2900*4600

REFORMER/CONVECTION COILS 1 18-FD-00-11 Steam Reformer Modification in inlet system. 2 18-EE-00-22 Feed/Steam

Superheater Replacement of 3 Nos of rows of coils of SS347H

3 18-EE-00-25 Naphtha Feed Superheater

Modification in coil arrangement and new manifolds

EXCHANGERS 1

18-EE-00-11B Naphtha Feed Vaporiser-2

Replaced by new exchanger No of shells: 1; Area/shell:102m2

2 18-EE-00-27

Hydrogen Product Cooler

Replaced by new exchanger No of shells: 1; Area/shell:155m2

FANS 1

18-KA-CF-12 Flue Gas Fan Impeller change with motor replacement of rating 1250 KW.

PACKAGE EQUIPMENTS 1

18-LZ-00-12 Hydrogen Generation PSA

Additional adsorber vessels and purge gas drum required

2 18-LZ-00-41

Hydrogen Recovery PSA

Additional adsorber vessels and purge gas drum required

NEW EQUIPMENTS 1 18-RB-00-10A/B Pre Reformer New equipment

Dia(mm)*Height(mm) :2600*3900 2 18-FD-00-12 TPR New equipment

No of tubes 226

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Tube length 14m 3 18-RB-00-14 LT Shift Reactor New equipment

Dia(mm)*Height(mm) :5100*4900 4 18-EE-00-28 Boiler Feed Water

Exchanger New equipment No of shells: 1; Area/shell:420m2

5 18-EE-00-26 Pre Reformer Preheat Coil

New coil 5 rows with 20tubes/row

6 18-EA-00-13 Nitrogen Circulation Cooler

New equipment No of bundles:1; No of tubes 298;

7 18-EE-00-29 Nitrogen Circulation Heater

1500 KW electric heater


The existing plot was considered for all the proposed modifications and it was determined that there is sufficient space for new/modified equipment. A joint site visit was made by EIL and BORL team to assess the extent of modification work involved in the revamp as well as to locate space for the new equipments.

The modifications /new facilities as tabulated in Tables 7.3.5.1 were checked for and found feasible from construction and implementation point of view.

Modifications in Convection Section of Reformers: The modifications required in convection section of reformer have been studied in detail from construction and implementation point of view as follows: The convection section of Reformer consists of 5 nos of Heat exchangers with tag nos. EE-21,EE-22, EE-23,EE-24 & EE-25, from El.12370 to El.16630.The inlet and outlet headers are provided inside the header box i.e. outside ETS and the pipe connections from headers are provided at the road side and plant side of the convection section. Structural platforms and pipe supports are provided at the road side of the convection box. Length of the tube is approx 17 m. There are 7 nos of ITS (Intermediate Tube Supports) and 2 ETS(End Tube Support).( Ref Drg: Technip drg no. 745-18-DW-013-083 Sh 1 of 1 Rev.0)

Exchanger no

Dia and No of rows of tubes

Inlet Header size with elevation

Outlet Header size with elevation

Remarks

EE-21 60.3 mm dia X 2 rows 22” dia : EL.11950 24” dia EL 12370 Header on either side

EE-22 3” dia X 6 rows 22” dia : EL 123873

20” dia EL 13815 Header on same side

EE-23 60.3 mm dia X 4 rows 20” dia EL 15237 20” dia EL 14387 Header on same side

EE-24 60.3 mm dia X 2 rows 24” dia EL 15786 24” dia EL 16200 Header on either side

EE-25 60.3 mm dia X 2 rows 8” dia EL 16973 8” dia EL 116630 Header on either side

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Proposed Modification

1. MOC of 3 bottom rows of EE-22 need to be changed to SS-347 H. 2. One new heat exchanger with 5 no of rows of metallurgy (2 1/4 Cr + 1 Mo)

with inlet and outlet headers to be installed between EE-22 and EE-23. Size of inlet and outlet headers and metallurgy is not available in the referred drawing.

3. Raising the elevation of header and coil location of EE-23 to a safer height to accommodate the new exchanger.

4. Pitch of tubes of EE-25 to be increased to 3D from the existing 2D. Methodology of Execution: EIL proposed following methodology of execution which shall be confirmed during detail engineering stage The total height of the convection box is 6.517 m (Header bottom El is 11220 and Header top El is 17737).Since there is no adequate space available for coil removal / insertion at the plant side, it is proposed to pull out the coil from the road side. Sequences of activities involved are as below:

1. Cutting and removing of structural members provided for pipe supports and

walk way platforms on the road side. 2. Connected pipe with exchanger headers need to cut and remove. 3. Header box on either side of the convection box to be removed. 4. Inlet and outlet Header provided on the road side of EE-22 , inlet header of

EE-24, and outlet header of EE-25 need to be cut and removed. 5. Cutting of all bends provided on plant side. 6. Tube connections to inlet header of EE-25, outlet connection of EE-24, Inlet

and outlet connection of EE-23 to cut to enable pulling out of the coil. 7. Pulling out of coils of all exchangers except EE-21 from the road side. 8. Removal of ITS of EE-25,24 & 23. This is required to accommodate the new

coil between 22 & 23, elevation change of coils of EE-23 and pitch change of EE-25.

9. Insertion of SS-347 H coil for EE-22. It is to be noted that, prefabrication of pipe to pipe connection of the coil is only possible and all return bends needs to be welded in-situ only, as there is no space available on plant side for coil insertion.

10. Subsequent coil of EE-22 can be inserted only after completion of welding /NDT of bottom layers.

11. Erection of inlet and outlet header. Welding and NDT of the coil with the headers.

12. Erection of ITS and ETS of all exchangers. 13. Erection, welding and NDT of pre-fabricated coil, header of the new

exchanger.

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14. Complete the erect ion of the coils, header, welding & NDT of the subsequent exchangers. It may be noted that welding and NDT of the bottom layer to be completed before insertion of the top layer.

15. Hydro test of all the coils including header of all exchangers.

In order to perform coil pulling and insertion, suitable structure arrangement to be made on the road side. The structural arrangement may consist of extending the two columns of the pipe rack available on the road side up to top elevation of convection box ie up to a height of 17737 mm. Intermediate columns with foundation may be provided on road and tie up with reformer columns. Suitable capacity and requisite nos of chain pulley blocks/ trolley arrangement to be provided on the temporary structures. Chain pulley blocks needs to be installed inside the convection box also to enable removal / insertion of the coils. Crane needs to be positioned for lowering the structures, headers and coils. After hydro test of the coils, complete the piping outside the convection section, structural etc , which are cut and removed for coil removal/insertion. Inference A structural analysis and constructability check was conducted by Technip on convection section and it was concluded that the proposed modifications can be done with the existing structure. In order to keep the shutdown revamp time of about 45 days, it is recommended that a modular design be applied for the modification in convection section. Technip have reviewed the observation and comments regarding modifications in the reformer convection section. Technip has also confirmed that estimation of site work/ work duration for the Hydrogen plant modifications remains as indicated for the Revamp, as 45 days based on their experience for other revamps.

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SECTION 7.3.6

TREATING UNIT

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7.3.6.0 TREATING UNITS

In this section, adequacy check of following units are addressed: LPG Amine Treating Unit (LPGATU) LPG CFC Fuel Treating Unit (FGATU)

7.3.6.1 LPG Amine Treating Unit (LPG ATU)

The existing capacity of LPG ATU is 15.5 T/hr and 25% MDEA solution is used for amine treatment of LPG. Post revamp the capacity of LPG treating unit as tabulated below is worked out considering:

LPG produced from 7.8MMTPA of AM ( 65:35::AL:AH) crude processing in existing CDU/VDU

LPG produced from DCU which is augmented for 135% of existing capacity. LPG yield is considered as furnished by Licenser for 1.52 kg/cm2g Coker Drum Overhead Pressure

UNIT EXISTING FEED (KG/HR)

POST REVAMP FEED (KG/HR)

CDU/VDU 10225 12750 DCU 5268 8950 Total 15493 21700

Post revamp 40% MDEA solution shall be used for amine treatment of LPG and loading of lean and rich amine are considered same as existing. Simulations have been done for 40% increase in the unit capacity by our e Research and Development department keeping the feed composition same as existing design and for 40% MDEA solution. The process flow scheme for this unit is given in Annexure 3.

Equipment Adequacy Report

Based on above mentioned basis, the adequacy check has been performed and the findings of the adequacy check for all major/critical equipments are summarized in Table 7.3.6.1and overall equipment list is attached in Annexure 2.

. Table 7.3.6.1 Modified/New Equipment List for LPG ATU

S.No. TAG NO DESCRIPTION MODIFICATION VESSELS

1 21-VV-HI-101 Amine Settler Drum New

COLUMNS

1 21-CC-00-101

LPG Amine Absorber

Trays (1-10): Replace existing trays with new configuration trays.

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Equipment wise Adequacy Report

COLUMN

The adequacy check of existing columns has been carried out based on the following assumptions:


LPG Amine Absorber (21-CC-AS-101): The column is adequate with replacement of exiting 10 trays with new configuration trays.

VESSEL Amine Settle Drum (21-VV-HI-101): Adequacy check for this vessel is not done at this stage as it is a vendor furnished item. Cost for new Vessel is taken considering 40% increase in vapor load.

EXCHANGERS LPG Amine Cooler(21-EE-AS-101): Adequacy of LPG cooler was checked for data as tabulated below:

Exchangers

Cooing water m3/hr

Outlet Temp (Process Side) °C

Duty MMKCal/Hr


revamp Existing Post revamp

LPG amine cooler

13.13 21.21 40 40.3 0.07 0.1059

It was found that Cooling water flow rate will increased from 13 X 1.1 TPH to 21 X 1.1 TPH post revamp. Process stream can be cooled from 45°C to 40.3°C which is a acceptable deviation from existing LPG amine cooler outlet temperature of 40°C.

PUMPS

The pump adequacy has been carried out based on the following assumptions: The pumps have not been checked w.r.t NPSHA / NPSHR & downstream design

pressure as these aspects will be checked in the detail engineering . Adequacy Check of the pump has been carried out based on existing pump data

sheets /predicted performance curves on the assumption that the actual performance of the pumps are as per datasheets /curves.

Adequacy Philosophy Pump adequacy check has been performed with an objective of retaining the existing pump with the following philosophy:

Minimum overdesign margin is provided for the rated flows of the pump over and above 25 % increase in normal flow for the revamp

S.No. TAG NO DESCRIPTION MODIFICATION PUMPS

1 21-PA-CF-102 A/B Lean Amine Booster Pumps

Change with larger impeller diameter.

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Head increase post revamp has been avoided by considering replacement of line size, instruments, if required.

Lean Amine Booster Pumps (21-PA-CF-102A/B):

7.3.6.2 LPG CFC Unit

Post revamp capacity of LPG CFC will be corresponding to LPG treating unit i.e. 21.7T/hr. The process flow scheme of this unit is given in Annexure 3.

The adequacy of this unit is performed in consideration of followings:

Mercaptan in Feed LPG : Increased by 48 % Crude Blend : 100 % Arab Mix (A 65:35 weight blend of Arab Light and Arab

Heavy Assay 2000) Since Crude blend considered same as existing design crude blend, LPG

composition and properties are kept same as existing. Adequacy check has been carried out based on the as-built details of the

equipments and with the following philosophy : It is presumed that all existing equipments are in good health and working

condition. Health check of existing equipments is excluded from existing scope of work.

No de-ration of the equipment is considered for establishing adequacy. Cost provision of modified or new equipments is kept in the feasibility report. Adequacy check has been limited to the critical equipments and adequacy

check of the line and instruments are not in the scope of the study.


Based on above mentioned basis, the adequacy check has been performed and the findings of the adequacy check for all major/critical equipments are summarized in Table 7.3.6.2 and overall equipment list is attached in Annexure 2.

. Table 7.3.6.2: Modified/New Equipment List for LPG ATU


COLUMNS 1 21-CC-00-201 Prewash Column LPG distributor to be changed

2 21-CC-00-202 Regeneration Column

Replaced with new (Dia: 1980 mm and height: 12000 mm)

PUMP DESCRIPTION

EXISTING POST-REVAMP

MODIFICATIONS/FINDINGS RATED FLOW (m3/hr)

DIFF HEAD (M)

RATED FLOW (m3/hr)

DIFF HEAD (M)

Lean Amine Booster Pumps

24 109 25.1 130 Impeller need to be changed with higher diameter.

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3 21-CC-00-203 Water Wash Column

New (Dia: 1500 mm and 4500 mm)

REACTORS 1 21-RB-00-201

Ist Stage CFC Column

Replaced with new (shell Dia: 680 mm and height: 4500 mm)

2 21-RB-00-202 IInd Stage CFC Column


3 21-RB-00-203

CFC Solvent Wash Contactor


VESSELS 1 21-VV-HW-201

Ist Stage CFC Separator

Replaced with existing 2nd Stage vessel 21-VV-HI-202

2 21-VV-HI-202

IInd Stage CFC Separator


3 21-VV-HI-203

CFC Solvent Wash Separator


4 21-VV-VI-204

Treated LPG Sand Filter Vessel


5 21-VV-HI-209 Coaleascer Vessel

New (Dia: 1800 mm and 6000 mm)

PUMPS 1 21-PA-CF-201 A/B

Interstage Caustic Circulation Pumps

Impeller need to be changed with higher diameter

2 21-PA-CF-202 A/B

Solvent Circulation Pumps


3 21-PA-CF-203 A/B

Regenerated Caustic Circulation Pumps


4 21-PA-CF-207 A/B

Water Circulation Pumps, flow

New Pump (Flow: 6 m3/hr and Head: 110 m)

Equipment wise Adequacy Report

Equipment wise adequacy is as detailed below:

COLUMNS

The adequacy check of existing columns has been carried out based on the following assumptions: No modifications of trays/internals have been carried out by BORL.

Prewash Column (21-CC-00-201): The existing column diameter and packing is adequate to handle the revised loadings except the following modifications: LPG Distributor needs to be changed. Batch time for the prewash column will reduce from 3 days to 2 days.

Regeneration Column (21-CC-00-202): Regeneration Column is checked for post revamp flow and are found to be inadequate. The new Column of higher diameter is required.

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CFC CONTACTOR AND SEPARATORS

1st Stage CFC Contactor and separator (21-RB-00-201 & 21-VV-HW-201): 1st stage CFC column and separator is checked for post revamp flow and major modifications required are as follows: Due to increase in LPG flow , new CFC column is required For separator , 2nd stage CFC separator will be used after increasing

the CFC column nozzle from 600mm to 680 mm.

2nd Stage CFC Contactor and separator (21-RB-00-202 & 21-VV-HW-202): 2nd stage CFC column and separator is checked for post revamp flow and major modifications required are as follows: Due to increase in LPG flow, both CFC column and separator are found

to be inadequate and new are required.

CFC Solvent wash Contactor and separator (21-RB-00-203 & 21-VV-HW-203): CFC Solvent wash contactor and separator is checked for post revamp flow and major modifications required are as follows: Both CFC column and separator are found to be inadequate and new are

required.

SAND FILTER

LPG Sand filter (21-VV-VI-204): LPG Sand filter is checked for post revamp flow and found inadequate, new is required.

EXCHANGERS

LPG Cooler & Caustic Heater (21-EE-AS-201 & 21-EE-DP-202): The exchangers LPG Cooler and Caustic heater have been found adequate with minor increase/ decrease in outlet temperature and / or increased utility flow rate as tabulated below:

Exchangers Findings/ Modifications

Cooing water m3/hr / Steam , Kg/hr

Outlet Temperature degC

Existing Post revamp

Existing Post revamp

LPG cooler

Tube side inlet / outlet nozzle size to be increased to 3” / 3” from 2” / 2”

11 13.45 40 41.2

Caustic Heater

135 152 52 49.5

PUMPS

The pump adequacy has been carried out based on the following assumptions:

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The pumps have not been checked w.r.t NPSHA / NPSHR & downstream design pressure as these aspects will be checked in the detail engineering.

Adequacy Check of the pump has been carried out based on existing pump data sheets /predicted performance curves on the assumption that the actual performance of the pumps are as per datasheets /curves


Minimum overdesign margin is provided for the rated flows of the pump over and above increase in normal flow for the revamp


Adequacy Results A summary of the adequacy results of the centrifugal pumps are tabulated below. Majority of the pumps are found adequate with impeller replacement. For the pumps used in intermittent service the operating hours will increase.

PUMP ADEQUACY CHECK RESULTS

The metering pumps used in intermittent service are found adequate with increase in the operating hours.

New facilities As per operational feedback, there is intermittent caustic carryover in LPG-CFC which results in Cu strip corrosion failure. To avoid this, provision of Water wash column followed by Coalescer in LPG-CFC unit has been considered. Following equipment shall be included: Water Wash Column (21-CC-00-203) Coalescer Vessel (21-VV-HI-209) Water Circulation pumps(21-PA-CF-207A/B)

PUMP DESCRIPTION

PRE-REVAMP POST-REVAMP


DIFF HEAD (M)

RATED FLOW (m3/hr)

DIFF HEAD (M)

Interstage Caustic Circulation Pumps (21-PA-CF-201 A/B)

6.42 50.3 9.18 50.3 Impeller need to be changed

Solvent Circulation Pumps (21-PA-CF-202 A/B)


Regenerated Caustic Circulation Pumps (21-PA-CF-203 A/B)


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7.3.6.3 FUEL GAS TREATING UNIT (FG ATU)

The existing Fuel Gas Treating Unit (FGATU) is of capacity 12.47 T/hr. The following is the total feed to FGATU from different units:

UNIT EXISTING FEED (KG/HR) POST REVAMP FEED (KG/HR)

HCU/DHDT 2965 3146 NHT 802 1169 DCU 8705 14454 TOTAL 12472 18769

The post revamp capacity increases to 18.7 T/hr. Adequacy check was done for 50 % increase in capacity and based on 40 wt% MDEA instead of 25 wt% MDEA. The process flow scheme of this unit is given in Annexure 3.


Based on the above post revamp conditions, adequacy check has been performed for and it has been found that all the equipments are adequate without any modification. The overall equipment list is attached in Annexure 2. Equipment Wise Adequacy

COLUMNS:

The adequacy check of existing columns has been carried out based on the following assumptions:


Fuel Gas Amine Absorber (22-CC-00-101): The column is checked for loading of 0.4 kmol of H2S/kmol of MDEA (100%) and is found to be adequate for the revised conditions without any modification.

VESSELS

All the vessels are found adequate for revamp conditions with acceptable reduced residence time and hold up time.

HEAT EXCHANGER

Adequacy Philosophy

No overdesign margin has been considered for the adequacy check of exchangers.

5% de-rating factor has been considered. Fuel Gas Cooler (22-EE-AS-102): Existing exchanger shall cool the process stream from 45 degC to 41.5 degC (instead of 40 degC). The corresponding duty shall be 0.0376 MMKCAL/hr and cooling water flow shall be same as existing (12.1 T/hr).

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Exchangers Findings/ Modifications

Cooing water (m3/hr )

Outlet Temperature (degC)


revamp Fuel Gas Cooler

Higher fuel gas outlet temperature

12.1 12.1 40 41.5

7.3.6.4 CONSTRUCTABILITY The existing plot was considered for all the proposed modifications and it was determined that there is sufficient space for new/modified equipment. A joint site visit was made by EIL and BORL team to assess the extent of modification work involved in the revamp as well as to locate space for the new equipments. The modifications /new facilities as tabulated in Tables 7.3.6.1&7.3.6.2 were checked and found feasible from construction and implementation point of view.

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SECTION 7.3.7

SULFUR RECOVERY UNIT

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7.3.7.0 SULFUR BLOCK

Sulfur block consist of following units:

Sulfur Recovery Unit (SRU) Sour Water Stripping Unit I/II (SWSI/II) Amine Regeneration Unit (ARU)

7.3.7.1 SULPHUR RECOVERY UNIT

The process objective of Sulphur Recovery unit is to convert hydrogen sulphide present in feed gas streams i.e. acid gas from Amine Regeneration unit, sour gas from Sour Water Stripper Unit and to recover it as sulphur product in order to minimize pollution. Tail gas containing residual sulphur species is incinerated in thermal incinerator and vented to atmosphere. Under this project, the revamp of all process units are envisaged for the capacity expansion of 30-40% which will result the expansion/ revamp of sulphur recovery unit to sustain the allowable SOx limit of refinery post expansion.

Existing SRU Configuration

Design Sulphur production rate, MTPD : 360 (Total) In existing configuration,

Two parallel Claus trains, each of capacity 180 MTPD sulphur production Tail Gas Treatment unit (TGTU) to enhance overall sulphur recovery

New SRU configuration (Post Expansion of Refinery)

SRU capacity post expansion is worked out as 488.5 TPD in consideration of followings:

Refinery capacity : 7.8 MMTPA Crude : 100 % Kuwait crude same as existing design case Sulphur in crude : 2.704 %* DCU pet coke sulfur : 8%* Sulphur as SOx not included.

*Data as furnished by BORL

Capacity increase has been checked for the same feed quality as per the original design basis i.e. Kuwait feed case. For other crudes like Arab Mix crude (AL:AH:;65:35) and for mix of Arab Mix and Kuwait ( 60% Arab Mix, 40% Kuwait), the capacity worked out as 382 and 420 MTPD respectively.

As a part of DFR, various options as detailed below have been worked out to arrive optimal configuration of SRU to meet the revamp requirement of sulphur recovery of 488.5 MTPD.

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Option-1 No Standby SRU Train Under this option, revamp of existing train to its maximum achievable capacity considering O2 enrichment and no additional train shall be considered.

Case A: Revamp of existing train to achieve SRU capacity of 488.5MTPD SRU shall run all the time meeting full capacity with both trains operating. This will imply: Max capacity of train: 245 MTPD (0.5*488.5) For Kuwait crude case : Existing trains of capacity shall be revamped for 245MTPD i.e. 36% increase in

capacity TGTU revamp requirement i.e. 36% increase in design capacity Operating capacity of each train will be :100% With outage of one train, achievable crude throughput : 50%

Case B: Revamp of existing train to Maximum achievable SRU capacity The revamp of existing train can be done upto 50% increase in capacity considering O2 enrichment. For Kuwait crude Case

The maximum achievable revamp capacity of SRU train is: 270MTPD. TGTU revamp requirement i.e. 36% increase in design capacity Operating capacity of each train will be :90% With maximum achievable revamp capacity (270MTPD) of SRU considering

outage of one train, the crude throughput of refinery for different crudes are tabulated below:

Crude Case Maximum achievable capacity of refinery

Kuwait 55% Arab mIx 71% 60% Arab Mix and 40% Kuwait

64%

Case C: Revamp of Existing Train based on 80% minimum crude throughput The revamp capacity of SRU train shall be based on 80% minimum crude throughput equivalent sulfur recovery capacity available in event of an outage of one train. In consideration of above SRU revamp capacity for different crude cases are tabulated below

Crude Case Capacity of SRU train considering 80% crude throughput with outage of one train in MTPD

% Revamp Required

Kuwait 390.8 217% Arab mIx 305.6 170% 60% Arab Mix and 40% Kuwait

336 186%

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The revamp of existing train is not feasible for such high capacities i.e. 170-200% of existing capacity. Therefore this option shall be ruled out. Option-2 Consideration of Standby SRU Train

Case D: Additional Train with Revamp of Existing Train One additional Sulfur train without TGTU, SRU shall run all the time meeting full capacity with 2 trains operating and one standby. This will imply

Max capacity of train: 245 MTPD ( 0.5*488.5)

For Kuwait crude case : Existing trains of capacity shall be revamped for 245MTPD i.e. 36% increase in

capacity New train capacity : 245 MTPD TGTU revamp requirement i.e. 36% increase in design capacity

Case E: Additional Train without Revamp of Existing Train Additional train of same capacity as existing and no revamp in existing SRU, the maximum achievable capacity with standby train will be as follows:

Crude Case Maximum achievable capacity of refinery

Kuwait 74% Arab mIx 94% 60% Arab Mix and 40% Kuwait

86%

Conclusion

1. It is evident from option C that BORL’s need to achieve minimum 80% crude throughput in the event of one train down could not be met.

2. All SRU conceivable configurations are tabulated below:

Case A Case B Case D Case E Standby Train No No One One Revamp of existing train 35% 50% No

revamp 35%

SRU Train capacity in MTPD 245 270 180 245 TGTU revamp 35% 35% 35% 355 Refinery throughput ( Kuwait crude case ) with outage of one train

50% 55% 73 100

Final SRU Configuration Case D is selected i.e.

One additional standby train of 180 MMTPD along with 35% capacity by oxygen enrichment. Enhancement of existing two trains to 243 MMTPD by oxygen enrichment.

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List of all the equipments required for new SRU train are tabulated in Table 7.3.7.1.The process flow schemem is attached in Annexure 3and overall equipment list for new train of 243TPD is attached in Annexure 2.

Table 7.3.7.1 Modified/New Equipment List for SRU SL NO TAG NO DESCRIPTION MODIFICATION

VESSEL 1

29-VV-00-007C Tail Gas Coalescer New (Diameter: 2400 mm and Height: 3250 mm)

REACTORS 1 29-RB-00-

001C Converter-I New (Diameter: 3390 mm and Height: 4800 mm)

2 29-RB-00-002C Converter-II

New (Diameter:3450 mm and 4700 mm)

HEATER 1 29-FB-00-001C Main Burner New 2

29-FF-00-001C Main combustion chamber

New

EXCHANGER 1 29-EE-00-001C Waste Heat Boiler New 2 29-EE-00-002C Sulfur Condenser-I New 3 29-EE-00-003C Sulfur Condenser-II New 4 29-EE-00-004C Reheater-I New 5 29-EE-00-005C Sulfur Condenser-III New 6 29-EE-00-006C Reheater-II New 7 29-EE-00-007C Acid Gas Preheater New

Oxygen Enrichment System

The existing SRU uses plant air. For post revamp scenario, oxygen enriched air shall be used instead of plant air which will increase the plant capacity by 35%. The following options have been looked for Oxygen enrichment of plant air:

Vaporised Oxygen injection: The liquid oxygen will be procured and stored in a

storage vessel. The vaporized oxygen from liquid oxygen storage vessel will be injected to the combustion air line.Enriched air will be used in the main burner of SRU.

Waste Nitrogen Utilisation: Waste nitrogen vented from the nitrogen plant will

be routed to the main burner of SRU.Make up vaporized oxygen will be injected from liquid oxygen storage facilities. The typical composition of waste nitrogen.

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S.No Component Mole% 1 O2 29.0 2 N2 62.9 3 H2O 8.1 MW 28.4

To cater the balance oxygen required to achieve the desired oxygen enrichment of air, the following two options are envisaged: a) Membrane system:

It involves the generation of 35%(v) Oxygen enriched air from air by using air separation membrane unit. Oxygen enriched air will be routed to the main burner of SRU.

b) VPSA System: Vacuum Pressure Swing Adsorption (VPSA) is a technology used for selective separation of a component from a mixture of gases by means of adsorption. The process is similar to Pressure Swing adsorption except that it is carried out at very low pressure. Following are the specifications of O2 from VPSA plant:

Average O2-content of product : 92 vol% Dew point at 1.013 bar approx. :-40 degC Product Pressure @ B/L : 5 bar(a)

Selected O2 enrichment system

BORL has opined for waste Nitrogen option for the oxygen enrichment. The total waste N2 requirement for two trains will be 24000Nm3/hr(12000 Nm3/hr for each train) . The waste N2 available from the existing N2 plant is 2640 Nm3/hr. With installation of an additional new N2 plant of 500 Nm3/hr capacity, additional 880Nm3/hr of waste N2 shall be available. The following facilities for O2 enrichment using waste N2 as tabulated below in Table 7.3.7.2 are envisaged in N2 plants and these facilities shall be confirmed during detail engineering phase:

Table 7.3.7.2: Modified/New Equipment List For Oxygen Enrichment

Sl.No TAG No. DESCRIPTION MODIFICATION 1 XX-VV-00-001

Waste Nitrogen Surge Vessel

New (Diameter: 2500 mm and 7500 mm, Qty: 2)

2 29-K-00-001 A/B

Waste Nitrogen Blower

New (motor Driven of rating 16 KW)

3 Option 1 Membrane Unit New 4 Option 2 VPSA Unit New

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To meet balance requirement of waste N2 i.e. 24000-2640-880=20480Nm3/hr which is equivalent to 142 TPD or 4148 Nm3/h of oxygen (based on 100 % oxygen), VPSA system is considered.

7.3.7.2 SOUR WATER STRIPPING UNIT I/II (SWS I/II)

CAPACITY: The existing capacity of SWS I is 125 T/hr and that of SWS II is 49 T/hr. The following is the total Sour Water flow to SWS I the unit:


POST REVAMP FEED (KG/HR)

CDU/VDU 71200 89000 DCU 30300 39400 ARU 4400 5720 SRU/TGTU 11500 17250 FLARE KOD 7600 10260 TOTAL 125000 161620

The total Sour Water Flow to SWS II unit:


POST REVAMP FEED (T/HR)

HCU/DHT 41500 58367 NHT 7500 7516 TOTAL 49000 65883

In the post revamp scenario SWS I/II is checked for increased flow of 30% over original Capacity. Equipment Adequacy Report Based on above mentioned basis and assumptions, the adequacy check has been done and the findings of the adequacy check for all major/critical equipments are summarized in Table 7.3.7.3 and overall equipment list is attached in Annexure 2. The Process Flow scheme is attached in Annexure 3 .

Table 7.3.7.3: Modified/New Equipment List For SWS I/II

S.NO TAG NO DESCRIPTION MODIFICATION VESSELS 1 28-VV-HI-101

Sour Water Surge Drum-I

Internal modification including shifting of baffles and nozzles.

2 28-VV-HI-201

Sour Water Surge Drum-II

Internal modification including shifting of baffles and nozzles.

COLUMNS 1 28-CC-00-202 2nd Stage Sour

Water Stripper Tray (25-32): Existing Trays need to be replaced by high capacity trays.

AIR COOLERS 1

28-EA-00-103 Single Stage PA Air Cooler

Existing 6 fan motors replaced by new motors of 50 HP per fan.

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2

28-EA-00-207 2nd Stage PA Air Cooler

One new bay in addition to existing 3 bays of area 6.4 m X 10.5 m. (Surface Area: 3244 m2/bundle)

PUMPS 1

28-PA-CF-101 A/B

Single Stage Stripper Feed Pumps

Impeller change with larger diameter and change in motor of rating 90 KW.

2 28-PA-CF-102 A/B/C

Single Stage Stripper PA Pumps

Impeller change with larger diameter.

3 28-PA-CF-103 A/B

Single Stage Stripper Bottom Pumps

Impeller change with larger diameter and change in motor of rating 90 KW.

4 28-PA-CF-203 A/B

2nd Stage Stripper Bottoms Pumps

Replaced with new pump of motor rating 55 KW. (Flow: 79.5 m3/hr and Head: 123.8 m)

TANKS 1

28-TT-CR-101A Sour Water Storage Tank-IA

New Tank. (Diameter: 22,500 mm and Height: 14,000 mm)

2 28-TT-CR-201C

Sour Water Storage Tank-IIA

New Tank. (Diameter: 15,000 mm and Height: 11,600 mm.

Equipment wise adequacy Report

COLUMN The adequacy check of existing columns has been carried out based on the following assumptions:


Single Stage Sour Water Stripper (28-CC-00-101): The column ID and Tray Spacing are adequate for handling the revamped loads with existing conventional valve trays. 1st Stage Sour Water Stripper (28-CC-00-201): The column ID and Tray spacing are found adequate for handling the revamped loads with conventional valve trays. 2nd Stage Sour Water Stripper (28-CC-00-202): Tray 1-24: The column ID and Tray spacing are found adequate for handling the revamped loads with conventional valve trays. Trays 25-32: (i) The column ID and Tray spacing are found adequate for handling the revamped loads with conventional valve trays when feed is at tray No 24. (ii) The column ID and Tray spacing are found to be inadequate for handling the revamped loads with conventional valve trays when feed is at tray no 32 (alternate feed location). This section needs to be replaced with high capacity trays for the accommodating alternate feed case. Trays 34-39: The column ID and Tray spacing are found adequate for handling the revamped loads with conventional valve trays.

VESSELS: Sour Water Surge Drum-I/II (28-VV-HI-101/201): BORL informed that separation of hydrocarbon is not taking place properly in existing vessels and oil is getting slipped

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to Sour water storage tanks. Keeping in view of above issue and based on post revamp flows adequacy of SWS I/II Surge Vessels were checked and found that existing vessels are not adequate for post revamp flow. Two options were envisaged for feasibility study:

Option 1: Replacement of both the existing vessels with new vessels. Option 2: Internal Modifications of baffles and nozzles to increase the separation length in existing vessels. During site visit, it was confirmed it is not feasible to take out existing vessels for replacements. Therefore, option 2 of in situ modification of exiting vessels shall be considered.

EXCHANGERS Adequacy check for the exchangers is done for duty and outlet temperature conditions as tabulated in table below. Findings of the study are summarized below:

TAG Service Duty (MMKcal/hr) Outlet Temp

(degC)


revamp Exchangers

28-EE-00-101A/B

Sour Water (Tube Side) 6.63 8.52

99.65 99

Stripper Sour Water (Shell Side)

74 74.5

28-EE-00-104A/B Stripped Water Cooler-I

4.23 5.447 40 41

28-EE-00-201A/B 1st stage Feed Mix Cooler

0294 0.3822 37 37

28-EE-00-202A/B Sour Water (Tube Side)

2.567 3.3371 89.8 89.8

Stripper Sour Water (Shell Side)

70 70

28-EE-00-203A/B

Sour Water (Tube Side)

2.407 2.951 138 136

Stripped Sour Water (Stripped Sour Water)

123.5 125.9

28-EE-00-208A/B Stripped water 1.352 1.729 40 41 Reboilers 28-EE-00-102A/B Single Stage

Stripper Reboiler 12.58 16.45 126.76 126.76

28-EE-00-204 1st Stage Stripper Reboiler

2.088 2.8423 166.2 166.2

28-EE-00-206 2nd Stage Stripper reboiler

8.066 9.5043 126.5 126.5

Air Coolers 28-EA-00-103 Single stage PA air

cooler 9.3 12.09 65 65

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28-EA-00-205 1st Stage Stripper PA Cooler

0.296 0.3848 65 65

28-EA-00-207 2nd Stage Stripper PA Cooler

7.6 10.67 65 65

Exchangers: Single Stage Feed Exchanger (28-EE-00-101A/B): It has been found that the tube side (sour water) maximum achievable outlet temperature is 99 degC instead of existing 99.65degC and shell side fluid (stripper sour water) would get cooled from 126.8 degC to 74.5 degC (instead of existing 74 degC). Also the tube side calculated pressure drop is 0.6 kg/cm2 and velocity is more than 1m/sec. Stripped water cooler-I (28-EE-00-104A/B): Existing exchanger can cool the stripped water (shell side fluid) from 74.5 degC (existing 74 degC) to 41 degC (existing 40 degC). Cooling water flow rate shall be increased to 459069 kg/hr from existing 405950 kg/hr. Also the tube side calculated pressure drop is 0.9 kg/cm2 and velocity is more than 1m/sec.

1st stage Feed Mix cooler (28-EE-00-201A/B): Existing exchanger is adequate for the post revamp conditions but cooling water flow rate shall be increased to 60060 kg/hr from existing 50600 kg/hr. Also tube side calculated pressure drop shall be 0.9 kg/cm2. 2nd Stage Feed Bottom Exchanger (28-EE-00-202A/B):It has been found that the existing exchanger is adequate for the post revamp conditions without any modification..However the tube side calculated pressure drop is 0.55 kg/cm2 and velocity is more than 1m/sec. 1st Stage Feed/Bottom Exchanger (28-EE-00-203A/B): It has been found that the Tube side (sour water) maximum outlet temperature is 136 degC instead of existing 138 degC and shell side fluid (stripper sour water) would get cooled from 166.2 degC to 125.9 degC (instead of existing 123.5 degC). 2nd Stage Trim water cooler (28-EE-00-208A/B): Existing exchanger can cool the stripped water from 70 degC to 41 degC (instead of 40 degC) and cooling water flow rate shall be increased to 15990 kg/hr from existing 129567.05 kg/hr.Aso the tube side pressure drop shall be 1kg/cm2 Reboilers: Single Stage Stripper Reboiler (28-EE-00-102A/B): Exchanger is adequate for the 130% increase in flow & duty without any modification. However the stripper bottom (shell side) velocity is greater than 1m/sec. 1st Stage Stripper Reboiler (28-EE-00-204A/B): Exchanger is adequate for 130% increase on flow & duty without any modification. 2nd Stage Stripper Reboiler (28-EE-00-206A/B): Exchanger is adequate for the 130% increase in flow & duty without any modification. However the stripper bottom (shell side) velocity is greater than 1m/sec.

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Air Coolers:

Single Stage PA Air Cooler (28-EA-00-103): Existing air cooler shall cool the stripper Pump Around to 68degC (instead of 65 degC) from 90 degC. To cool the stripper PA to the desired temperature of 65 degC, existing motors of power rating 40 HP for all the six fans needs to be replaced with new motors of power rating 50 HP. 1st Stage PA Air Cooler (28-EA-00-205): Existing Air cooler is adequate to handle the post revamp conditions without any modification. 2nd Stage PA Air Cooler (28-EA-00-207): Existing air cooler is inadequate to cool the stripper PA to 65degC from 92degC. To achieve the same, one additional bay similar to existing would be required.

Tanks: Existing two sour water storage tanks are insufficient to handle post revamp storage capacity. Thus one new sour water storage tanks (similar to existing) is required for each of the unit.

Pumps: The pump adequacy has been carried out based on the following assumptions :

The pumps have not been checked w.r.t NPSHA / NPSHR & downstream design pressure as these aspects will be checked in the detail engineering . Adequacy Check of the pump has been carried out based on existing pump data sheets /predicted performance curves on the assumption that the actual performance of the pumps are as per datasheets /curves


Minimum overdesign margin is provided for the rated flows of the pump over and above 30 % increase in normal flow for the revamp


Adequacy Results A summary of the adequacy results of the pumps are tabulated below. Majority of the pumps are found adequate with impeller replacement and /or motor replacement.

Motor Replacement If pump is found adequate and motor inadequate (Total 2 Pumps), replacement

of motor with a higher rating is envisaged. Replacement of motor may call the following changes : a) Base plate modification/replacement b) Couplings need replacement, c) Foundation may require modification

Modifications related to Motor shall be carried out by OEM only which might invite opportunity costs.

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Shut down time requirement is more as compared to implementation of new pumps

Normally motor related modifications are preferred by OEM at their workplace. Shifting of pumps at OEMs works are mostly difficult, time consuming & cost ineffective. To carry out the motor related modifications at site, BORL shall check adequate facilities at their workshop.

Therefore, the philosophy of motor change from economical feasibility and execution point of views shall be reviewed at design stage in consultation with OEM.

7.3.7.3 AMINE REGENERATION UNIT (ARU):

The existing capacity of ARU is 470 T/hr. The existing unit is working on 25% wt MDEA and rich amine loading of 0.45 moles of H2S per mole of MDEA (except for

PUMP DESCRIPTION

EXISTING POST-REVAMP


DIFF HEAD (M)

RATED FLOW (m3/hr)

DIFF HEAD (M)

28-PA-CF-101 A/B (Single stage stripper feed pumps)

139.2 74 181.2 90 Impeller change of higher diameter an new motor of power rating 90KW

28-PA-CF-102 A/B/C( Single stage stripper PA pumps)

254 64.7 302.5 68.9 Impeller change with larger diameter.

28-PA-CF-103 A/B( Single stage stripper bottom pumps)

146 106 189.7 113.8 Impeller change of higher diameter an new motor of power rating 90KW

28-PA-CF-201 A/B(1st Stage Stripper Feed Pumps)

55.7 218.9 72.35 208.5 Adequate

28-PA-CF-202 A/B(1st Stage Stripper PA Pumps)

15.3 48.2 18.3 45.7 Adequate

28-PA-CF-203 A/B(2nd Stage Stripper Bottoms Pumps)

61.1 108.7 79.5 123.8 Replaced with new pump of motor rating 55KW

28-PA-CF-204 A/B(2nd Stage Stripper PA Pumps)

204.3 53.9 243.1 48.78 Adequate

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LPG ATU, loading is 0.34) and Lean Amine Loading is 0.015 moles of H2S per mole of MDEA. The post revamp adequacy check is based on 40 wt% MDEA and rich amine loading of 0.4 moles of H2S per mole of MDEA for FGATU, 0.436 moles of H2S per mole of MDEA for HCU/DHDT and 0.015 moles of H2S per mole of MDEA for LPG ATU.

The following is the feed from different units:

As the concentration has increased and loading remaining almost the same, the rich amine feed flow to the unit is within the existing flow to the unit. Therefore all the equipments are adequate except for the Amine Generation Reflux Drum because the vapor load has increased. Overall Equipment list is attached in Annexure-2 and Process Flow Schemes are given in Annexure 3.

Table 7.3.7.4: Modified/New Equipment List for ARU


VESSELS

1 27-VV-VI-102 AMINE REGENERATOR REFLUX DRUM

Replaced by New


The existing plot was considered for all the proposed modifications and it was determined that there is sufficient space for new/modified equipment. A joint site visit was made by EIL and BORL team to assess the extent of modification work involved in the revamp as well as to locate space for the new equipments. The modifications /new facilities as tabulated in Tables 7.3.6.1 to 7.3.6.4 were checked and found feasible from construction and implementation point of view with the following observations:

1) The space for additional train of SRU has been identified towards the south side of existing Sulfur Block.

2) Space for New Sour Water Storage tanks 28-TT-CR-101A and 28-TT-CR-201C is not available near the existing tanks. The space for these tanks has been identified in the space available for new SRU train. .

3) Also the area required for oxygen enrichment facilities (i.e. Vessels, Blowers, VPSA) has been identified near existing Nitrogen plant

4) The existing Surge Drums (28-VV-HI-101/201) cannot be taken out for replacement. It is advisable to go for internal modification.

UNIT EXISTING FEED (KG/HR) POST REVAMP FEED

(KG/HR)

FG ATU 105000 113370

LPG ATU 23000 23648

HCU/DHDT 342000 321069

TOTAL 470000 458087

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Material Balance DFR for Debottlenecking of



RevB Ch 7.4 Page 1 of 5


SECTION 7.4

MATERIAL BALANCE

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7.4.1 OVERALL MATERIAL BALANCE

Table 7.4.1: Over all Material Balance of Refinery

KTPA

Crude ( 65% Arab Light 35% Arab Heavy

7800

Products LPG 344 Naphtha 189 Euro III Regular Gasoline 0 Euro IV Regular Gasoline 1242 Aviation Turbine Fuel 722 Kerosene 396 Euro IV/V Diesel 3641 Coke 523 Sulfur 152 Fuel & Loss 597

The above material balance corresponds to Arab mix crude slate. In case of heavy crudes like Kuwait, Basra light etc the petcoke yield and fuel & losses are comparatively higher which accordingly changes the product pattern.

The overall Material Balance is worked out using LP model (as tabulated above) and in consideration of followings:

Unit capacities are corresponding to same cut points of distillates as considered

for original design of CDU/VDU except gasoil TBP cut point which has been changed to 240-370 instead of original design TBP cut point of 250-370. The unit capacities for above material balance are worked as:

Table 7.4.2: Unit Capacities

Process Unit Revamp Design Capacity MMTPA

Capacity Utilisation MMTPA

CDU/VDU 7.8 7.8 NHT 1.45 1.45 CCR 0.787 0.77 ISOM 0.56 0.56 HCU/DHDT 2.625/2.202 2.486/2.224 DCU 1.822 1.75 HGU 98 KTPA 83 KTPA

The yields of DCU, HCU/DHDT, MS block and H2 units are considered as furnished by respective licensers for post revamp scenario.

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As per BORL inputs , depentanizer OVHD is considered as 40% of feed and

hydrocracker yields of light naphtha and heavy naphtha are considered as 7.8 and 10.1wt% of HCU feed.

The overall Block flow diagram is attached at the end of this chapter. 7.4.2 MAXIMIZATION OF 100% EURO IV MS PRODUCTION

To maximize total Euro IV MS of specification as tabulated below, UOP evaluated various cases with an aim to upgrade available naphtha to maximum Euro IV quality MS through (i) Direct Blending into MS Pool (ii) Processing in Units (iii) Additives (MTBE or Alkylate) to MS Pool.

Table7.4.3: Euro IV MS Specification

For maximization of Euro IV MS Production, following revamp of existing MS block unit has been considered: NHT capacity: 145% increase of design capacity Penex Unit: 181% increase of design capacity CCR Unit: 146% increase of design capacity

Euro IV MS production of 1242 KTPA (refer Table 7.4.3) is estimated following UOP suggested scheme as shown below

Product Qualities Specification of Euro IV MS

SPECIFIC GRAVITY 0.72-0.775 SULFUR, WT% 0.005 (max) Vapour Lock Index (7*E70+10*RVP(kpa))

750 (Summer)/ 950 (winter)

RON 92 (min) MON 81.3 (min) BENZENE, vol% 1.0 (max) AROMATICS, Vol% 34.0 (max)

OLEFINS, vol% 18.0 (max) % Recovery AT 70C - % Recovery AT 100C - % Recovery AT 150C - RVP, PSI 8.41 (58 Kpa)

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Penex/DIHUnit

DeC5

NapthaSplitter

CCRPlatforming

Euro IVMS

POOL

SGB

NHT Unit

SGB

C5-90CHydrocrackerLight Naptha

C5-150CSR Naptha

Hydrogen LPG

Reformate

Isomerate

Off Gas

HydrocrackerHeavy Naptha

LPG

C5s

375

218

1076

487

154

157

264

54659

394

790

770

20

696

22

29

502

All values are in KTPADesign Capacity (xxxx)

Operating capacity

(560) 551

(787) 770

(1450) 1450

(1242)

157

1295

0

HDT Heavy Naptha

HCU HY Naptha

1449

157

To Naptha Pool/HGU 234

TO HGU

LOSS

The properties which are considered for blending streams of MS pool are given in Table 7.4.4 below:

Table 7.4.4: Properties of Bleanding Streams of MS Pool

Product Qualities Reformate Isomerate HCU Hy Naphtha

NHT Heavy Naphtha

SPECIFIC GRAVITY 0.806 0.658 0.75 0.733 SULFUR, WT% 0 0 0.0001 0 Vapour Lock Index (7*E70+10*RVP(kpa)) 275 778 138 96.1 RON 98 88 55 65.2 MON 87 86.7 55 63.4 BENZENE, vol% 1.1 0 0.6 0 AROMATICS, Vol% 66.0 0 6 9 OLEFINS, vol% 1.3 0 0 0 % Recovery AT 70C 5 84 0 2 % Recovery AT 100C 15 94.5 15 100 % Recovery AT 150C 80 100 100 100 RVP, PSI 3.5 10.88 2.0 1.2

Euro IV MS pool composition based on above scheme and properties of blended streams are as follows:

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Streams KTPA Wt% NHT-Heavy Naphtha 20 1.6 Isomerate 502 40.2 Reformate 696 55.8 HCU Hy Naphtha 29 2.3 Total 1247 100

The production of 100% Euro IV MS as explained above is based on UOP preliminary study. The followings shall be needed to taken up during design stage: The properties of hydrocracker light naphtha and heavy naphtha for higher

yields than present design yields. Processing of hydrocracker light naphtha in Penex unit by-passing hydro-

treatment (via Sulphur Guard Bed), processing directly to Penex and its impact on Isomerate yield and quality.

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Utility System DFR for Debottlenecking of





SECTION 7.5

UTILITY SYSTEM

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7.5.0 UTILITY SYSTEM

This chapter provides the details of increased utility requirements and description of additional facilities required for various utility systems envisaged for the refinery post revamp for the detailed feasibility report. The following utility systems are reviewed for DFR: 1. Raw water system 2. Cooling water system 3. DM water system 4. Compressed air system 5. Nitrogen system 6. Steam, power and BFW system 7. Condensate system 8. Internal fuel oil and fuel gas system 9. Flare system The revised utility consumption and the additional facilities required post revamp of the above facilities have been done based on estimation of utility consumption of the process units based on the following:

Estimated requirement post expansion unit wise from the utility design values for 6 MMTPA.

Operating data of the existing units at increased capacity of the units Licensor utility figures for the post revamp

7.5.1 REFINERY UTILITIES SUMMARY

Sl. No System Units Existing Value Revamp Value

1 CW System m3/hr 21729 25430

DM Water 2 Process m3/hr 152 162.8 Utility Block m3/hr 347 447.3 3 Raw Water m3/hr 2516 2630 4 Nitrogen Nm3/hr 1169 2557

Instrument Air 5

Process Nm3/hr 6370 5680 Utility Block Nm3/hr 630 3140

6 Plant Air Nm3/hr 3160 3530

Boiler Feed water 7

MP+LP m3/hr 135.6 184.8 HP m3/hr 8 4.6

Steam 8 HP TPH -3.6 60.92 MP TPH 76.4 81.25 LP TPH 83.4 118

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Sl. No System Units Existing Value Revamp Value

9

Condensate Surface Pure Suspect

TPH TPH TPH

52.8 67.7 32.8

81.2 116.7 46.3

7.5.2 RAW WATER SYSTEM

Raw water is available at the refinery battery limit from Betwa via Raw Water Pumping facility. To meet the refinery complex demand raw water reservoir of capacity 96,200 m3 (2 no’s - 33450 & 62750 m3 capacity) is provided. The raw water from the reservoirs is pumped, treated and filtered in raw water treatment plant (RWTP). The treated water is stored in two reservoir (holding capacity of each reservoir is equivalent to 6 hrs of max treated water requirement of the refinery project) from where the supplies is pumped to the various consumers in the refinery to meet its process and other requirements. Treated water shall be used as follows:

1. Cooling water make-up 2. Service water 3. DM Plant feed 4. Bearing Cooling water 5. Drinking water system 6. Fire water system

Raw Water Reservoir To meet the refinery complex two raw water reservoirs are available.

Treated Water Reservoir Treated water is stored in one reservoir with two compartments designed for catering to approximately 12.0 hrs of max treated water requirement of the refinery.

Treated water requirement The revised estimated treated water requirement for various purposes in the complex is given below in Table-7.5.1.

Table-7.5.1: Treated Raw Water Requirement (m3/hr)

S.No Unit Estimated Demand

m3/hr Normal

Estimated Demand

m3/hr maximum

1. Cooling Tower Makeup (Process) 689 754

2. Cooling Tower Makeup (CPP) 724 790

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3 DM Plant/RO plant feed 250 600

4. Service Water 85 240

5. Pump Bearing Seal cooling 112 135

6. Drinking Water 87 204 7. Fire water make up 10 180 Total Treated water Demand 1947

Total raw water Demand 1957 2630

Capacity of Raw water treatment Plant

The raw water system consists of the following: Raw water reservoir capacity : 96,200 m3 (2 no’s, 33450 & 62750 m3 Capacity) Treated water reservoir Capacity : 22,800 m3 RWTP capacity : 2 X 1,500 m3/hr. Normal raw water demand for the refinery complex for post revamp is 1957 m3/hr. against existing 1891 m3/hr. Maximum raw water demand for the refinery complex for post revamp is 2630 m3/hr. against existing 2516 m3/hr. Since no major augmentation is required for Refinery Cooling Tower and minor augmentation is required in RO-DM system, the existing raw water system will be adequate for 25% increase in crude throughput with an additional raw water intake pump similar to existing capacity. No change in RWTP, except Oil removal facility to be considered. Treated water pumps (service water/BCW/CW make up/DM feed pumps) are adequate for revamp peak requirement of 2246 m3/hr.

Service water Existing service requirement is 63 (nor) m3/hr and 210 (max) m3/hr .New service water requirement is 85 (nor) m3/hr / 240(max) m3/hr. No modification in service water system is envisaged.

7.5.3 COOLING WATER SYSTEM

The existing cooling water facilities are classified into two systems, namely, Refinery cooling water and CPP cooling water system. The existing facilities for these two cooling water systems are as follows:

Refinery Cooling Tower : 24000 m3/hr CPP Cooling Tower : 30000 m3/hr

The unit wise cooling water demand for the refinery post expansion is tabulated in table 7.5.2. The cooling water system envisaged for the refinery complex is fresh water recirculation type. The Refinery cooling water system includes cooling towers, pumps, cooling water treatment facilities, distribution network supply to various

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units, Utilities (except CPP, Compressed air system, nitrogen system ,CPU/DM and MCR). Cooling Water Requirement The cooling water requirement of various process units is given below in the Table-7.5.2.

Table-7.5.2: Cooling water consumption (m3/hr)

UNITS Existing Post Revamp

CDU/VDU 4750 5937 NHT/NSU 575 543 PENEX 1474 1474 CCR 2710 3037 HGU 578 693 HCU/DHDT 6314 7137 DCU 2250 2925 SWSU 523 706 LPG Treating 55 68 ARU 880 861 (Note 1) S-BLOCK 690 900 SRR & Sub-Stations 330 330 Utilities & Offsite 600 819 TOTAL- Refinery CT 21729 25430 TOTAL- Refinery CT (with margin) ~24000 ~28000

Note 1: Value taken as per Client from original utility summary given by EIL

(Licensor).

Cooling Tower

CPP CT There is no change in power generation capacity of CPP; hence no increase in CW consumption of CPP is envisaged. 4000 m3/hr was allocated for other consumers of CPP CT against the final estimate of 1500 m3/hr pre revamp. Hence, the additional CW requirement of about 300 m3/hr for proposed new N2 plant and LP Air compressor can be catered within this allocated 4000 m3/hr. Refinery CT New cooling water requirement post revamp for refinery cooling tower works out to be 28000 m3/hr as against the existing system of 24000 m3/hr. One additional cell same as existing Cells (6W+1S) of capacity 4000 m3/hr will be required for augmentation of refinery cooling tower. Hence total no of cells in post revamp will be (7W+1S) of capacity 4000 m3/hr.

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Recirculating cooling water pumps A new cooling water circulation pump same as existing (3W+1S ) of capacity 8000 m3/hr is to be installed in refinery cooling tower .So total no of pumps post revamp will be 4W+1S with capacity of each pump as 8000 m3/hr. Type : Horizontal centrifugal Type of Drive : Electric motor No. Of additional pumps : one Capacity : 8000 m3/hr The existing header sizes of the cooling water are 72”/66”/54”/38”. For the increased cooling water a new header of 36 “/28”/20 “ shall be laid in the offsite to meet the unit battery limit pressures. This can be further optimised during detail engineering. Bearing Cooling Water Existing BCW requirement is 760 m3/hr. BCW is taken from Raw water header and BCW return is sent to cooling water headers as Cooling tower make up. Recirculation system of BCW in all process units is being implemented by BORL to prevent overflowing of cooling tower sump .Hence only 10% of original BCW consumption to be considered in Process units. Hence BCW make up to cooling tower reduces to 112.5 m3/hr and no modification in bearing cooling water system is envisaged.

7.5.4 DM WATER SYSTEM

DM water in the refinery complex is required as Boiler feed water make-up for steam generation and as process water for dilution, reaction and washing. DM water for the refinery is produced in RO system which is part of ETP. The demand summary of DM water in various units and utilities is given below in Table-7.5.3

Table-7.5.3:DM WATER (m3/hr)

UNIT Existing Post Revamp CDU/VDU 5 6.3 NHT/NSU 0 6 HGU 132 132 (Note-2) ARU 0 2.5 SRU 15 15 TGTU 0.5 1.0 Total process 152 162.8

Utility Block Caustic Dilution 15 18.8 CPP 332 428.6

TOTAL- Utility 347 447.3 TOTAL- Process & Utility 499 610 Total process and utility with 10 % margin 548.9 671

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Condensate Return (recovery) Note 1 -128 -194 TOTAL- Process & Utility 420.9 477

Note 1: Condensate has been considered for DM water make up. Condensate recovery is based on 60 % recovery of suspect condensate & 85% recovery of pure & surface condensate.

Note-2: As per Licensor data.

DM water storage Two DM water tanks of 16 hr storage are provided .Normally one tank receives DM water from the RO plant and the second tank supplies DM water to consumers. New DM water requirement is around 486 m3/hr In post revamp DM water storage tank hold up will reduce to 14.8 hrs. Total Flow 486 m3/hr Capacity of each tank (80 % filling) 7200 m3 Number of tanks 1+1 Hold Up Time 14.8 hrs

DM water transfer pump In present scenario for CPP (2W+1S) DM water transfer pumps of capacity 185 m3/hr are present. Since the requirement of the utility block is 447.43m3/h, the adequacy of the transfer pumps shall be checked during design stage. For process units existing DM water transfer pumps of 250 m3/hr (1W+1S ) are adequate since the process requirement is worked out to be 197 m3/hr. DM water transfer pumps to process users:

Type : Horizontal centrifugal Type of Drive : Electric motor No. of pumps : 1 operating + 1 stand by Capacity : 250 m3/hr each

To meet the additional DM water requirement .One additional bank for RO-DM plant of existing capacity is considered to cater additional DM water requirement. One new cooling tower blow down storage tank and one set of feeding pump is considered for feeding cooling tower blowdown to RO DM plant. Details of the blow down tank and pump:

Tank Tank size : Vertical Fixed cone roof tank, 18 m (Dia) x15 m

(HT) Pump Type : Horizontal centrifugal Type of Drive : Electric motor No. of pumps : 1 operating + 1 stand by Capacity : 300 m3/hr each, 15 m Head

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7.5.5 COMPRESSED AIR SYSTEM

The Compressed air is required in the complex for following usages:

As instrument air As plant air As service air for hose stations and for other requirements of the complex.

Compressed Air Specification Quality of Plant air and service air is same and these requirements in the complex shall be supplied through common header.

Consumption Requirement The requirement of instrument air and plant air in the complex are given in Table 7.5.4 and Table 7.5.5 respectively.

Table-7.5.4: Instrument Air (Nm3/hr)

UNITS Continuous maximum requirement (Nm3/hr)

Existing Post Revamp CDU/VDU 440 350 HCU/DHT 960 1300 DCU 1100 420 NHT/NSU/PENEX 325 1300 CCR Plt& Regen 1430 0 HGU 385 180 SWS-I 55 55 SWS-II 55 55 LPG Treating 100 100 ARU 55 55 SRU 440 840 CPP 1025 1025 Subtotal 6370 5680 Utilities and CT 10 Note-1

off-sites RW 20 Note-1 CPU 30 Note-1 RO 50 Note-1 Comp. Air 20 Note-1 N2 50 Note-1 WWTP 120 Note-1 Flare 30 Note-1 Tankage 120 Note-1

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CR 30 Note-1 Workshop, Lab. & Misc 50 Note-1

Marketing Terminal 100 Note-1 Sub-total 630 3140 TOTAL 7000 8820

Note-1: As per BORL operating data total instrument air consumption for offsites and utilities (other than CPP) is 3140 Nm3/h.

Table-7.5.5: Plant Air (Nm3/hr)

UNITS Continuous maximum requirement (Nm3/hr)

Existing Post Revamp CDU/VDU HCU/DHT

DCU 300 390 NHT/NSU CCR PENEX HGU SWS-I SWS-II LPG treating 340 340 ATF Treating ARU SRU WWTP 200 200 Cooling towers TANKAGES Workshop, Lab. & Misc.

CPP 480 760 Hose station 340 340 Total 3160,(Maximum)

(Note-1) 3530 (Note-1)

Note-1: Maximum plant air requirement includes intermittent requirement of 1500 Nm3/h of plant air for coke cutting in DCU.

Total Air Requirement The compressed air requirement of the refinery complex works out to be Instrument Air : 8820 Nm3/hr Plant air : 3530 Nm3/hr

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Total air requirement (as per design) : 11200 Nm3/h Total air requirement Post revamp (with 10%margin) : 13600 Nm3/h Additional air requirement : 2400 Nm3/h Air requirement of new N2 plant : 6000 Nm3 /h Total additional air requirement : 8400 Nm3/h

LP Air Compressor One additional LP air compressor similar to existing compressor capacity of 8825 Nm3/hr) is considered to meet the additional air requirement post expansion. This LP air compressor will be common for N2 plant and the Plant air /instrument air plant. Type : Centrifugal, non-lubricated Drive : Electric motor Capacity of compressor : 8825 Nm3/hr No. : 1(one) Discharge Pressure : 8.0 Kg/cm2 (g) Additional Instrument air requirement will be met by additional air dryer of 5000 Nm3/hr in addition to existing two no of dryers each of capacity 5000 Nm3/hr. A new instrument air header of size 6” in parallel to existing 10” shall be laid to conform to the battery limit pressure of the offsites and utility due to considerable increase in post revamp requirement. Existing Emergency instrument air: 2 HP storage vessels for 30 minutes I.A requirement for safe shut down (1 vessel for HCU+DHT unit + 1 vessel for balance refinery facilities).The adequacy of the existing instrument system has been checked w.r.t the post revamp requirement and found adequate.

7.5.6 NITROGEN SYSTEM

High purity Nitrogen is required in the refinery for the following purposes: A) Continuous Requirement During catalyst regeneration Blanketing of surge drums and storage tanks Purging of compressor seals

B) Intermittent Requirement Purging of systems during start-ups and shut-downs Catalyst Regeneration The process related activities such as reactor section dry out, system purging, catalyst regeneration, etc. require high purity nitrogen (>99.5% purity). Accordingly, a existing nitrogen plant based on cryogenic air separation cater to the nitrogen requirement of the refinery.

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The nitrogen requirement post revamp against the existing consumption is tabulated in the table 7.5.6

Table-7.5.6 Nitrogen requirements of the various units.

The total nitrogen demand post expansion considering design margin and margin for leakage is ~ 3000 Nm3/h . The existing Cryogenic Nitrogen plant capacity is as follows:

Gaseous Nitrogen : 1,500 Nm3/hr Liquid Nitrogen : 225 Nm3/hr (Gaseous equivalent)

The requirement of 3000Nm3/hr of gaseous nitrogen Post revamp will be met by additional new N2 chain of 500 Nm3/hr capacity. Liquid N2 storage capacity is adequate as there is no change in start up, regeneration etc data.

7.5.7 STEAM, POWER AND BFW SYSTEM

The steam is produced in the captive power plant. The fuel to CPP is coal. There are three levels of steam in the refinery viz: HP, MP and LP. The steam is being generated / consumed in process units at these levels. The steam consumption in the various units for different purposes such as:

Process use (Chemical reaction, Stripping steam, etc.) Steam drives for some of the compressors/pumps As heating medium for steam heated exchangers Fuel oil atomisation. Internal fuel oil atomization,

UNITS Maximum continuous (Nm3/hr) Existing Post Revamp

CDU/VDU Nil 0 ATF Merox 20 25 NHT 10 41.4 CCR-Pt. 54 250.0 PENEX 10 41.4 HGU 80 96 DCU 11 395.6 HCU/ DHT 56 72.8 SRU 200 439 ARU 61 123.8 SWS 27 55 DM plant 100 125 CPU 25 31.3 Offsites 535 860 TOTAL 1169 2557

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Steam tracing of lines (congealing service) Tankage heating Deaerator Intermittent requirement like snuffing, decoking, soot blowing, purging etc. Air conditioning units for the Control rooms and the administrative building

Steam Requirement Tables 7.5.7, 7.5.8 and 7.5.9 give the consumption / generation figures for steam in various units at HP, MP & LP levels of steam respectively under normal operating conditions which corresponds to case-I in the original utility steam design basis. The unit-wise net steam consumption /generation for the existing as well as post revamp is tabulated below:

Table 7.5.7: HP steam consumption (TPH)

Units Existing Post Revamp HCU/DHDT 34.3 54.7 (note-1) DCU 21.8 35.6 (note-1) PENEX 0.4 0.6 Utilities & Offsite 2 2 HGU -62.1 -31.9 (note-1) NET TOTAL -3.6 61 With 10% margin -3.6 67.0

-ve sign indicates generation Note-1: As per Licensor data.

Table 7.5.8: MP Steam Consumption (TPH)

Units Existing Post Revamp CDU/VDU 30 44.7 NHT/NSU 2 2.5 PENEX 19.8 24.8 CCR 14.8 2 (note-1) HGU 0.5 0.5 HCU/DHDT -36.1 -30.9 (note-1) DCU 24.9 23.7 HOT OIL 1.5 1.5 Utilities & Offsite 10 12.5 NET TOTAL 76.4 81.3 With 10% margin 84 89.4

-ve sign indicates generation Note-1: As per Licensor data.

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Table 7.5.9:LP Steam consumption (TPH) Units Existing Post Revamp

CDU/VDU 10 12.5 PENEX 0.5 1.2 (Note-1) CCR -2.8 -5 (Note-1) HGU 0.5 3.7 ( Note-1) HCU/DHDT 7.5 13.3 (Note-1) DCU 9.6 9.6 SRU -36.3 -25 (note-3) ARU 49 49 (Note2) SWS-1 24.6 33 SWS-2 15.8 19 Utilities & Offsite 5 6.8

NET TOTAL 83.4 118 With 10% margin 92 ~130

-ve sign indicates generation Note-1: As per Licensor data. Note-2: In ARU simulation, duty of reboiler remains same as in post revamp scenario so LP steam consumption taken same as in existing. However same will be confirmed during design stage Note-3:, LP steam generation as expected post revamp in SRU based on

operational feed backs.

The existing LP steam header in the offsite is 26”/22/18”. A new LP steam header of size 20” shall be provided in the offsite in parallel to the existing header for revamp requirement. However same will be confirmed during design stage. Power Requirement Table 7.5.10 gives the power requirement of the various units under normal operating conditions. Table 7.5.11 gives estimated steam and power summary for existing and post revamp scenario.

Table 7.5.10: Estimated Power Consumption (kW) (Normal) Units Existing Post Revamp

CDU/VDU 7522 9402.5 NHT/NSU 1700 2125 PENEX 3010 3762.5 CCR 5164 7229.6 HGU 3593 4311.6 HCU/DHDT 30910 40183 DCU 5802 7542.6

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Units Existing Post Revamp SRU 7388 9973.8 Utilities & Offsite 24299 30373.8 Total (Normal) 89388 114904

Table 7.5.11: Estimated Steam & Power Summary Existing Post Revamp

Refinery Normal/Rated Power demand (MW) (Including CPP)

Normal: 90 Normal: 114.9 Rated : 126.39 (with 10% margin on normal

requirement)

Refinery Steam Normal/Rated demand (TPH)

Rated Flows with 10%

margin HP : -3.6, MP:84 LP : 92 Total Rated: 172.4

Rated Flows with 10% margin HP : 67 MP : 89.4 LP : 118 Total rated : 260

The existing steam and power generation facilities consist of:

CFBC : (2W+1S ) boilers of capacity 225 TPH each (VHP

Level) STG : 3 X 33 MW each (Extraction type) Grid back-up : 20 MW(As per design) (Currently BORL is

withdrawing 47 MW power from grid)

DG set : 4.0 MW (to meet emergency power)

Total power requirement post revamp will be 115 MW (all units running normally) As per BORL operating data post revamp comes out to be 94 MW only as compared to 115 MW estimated based on original power requirement of units. Post expansion power available from CPP will be same as existing as 47 MW. The balance power 68 MW shall be available from Grid power.

Total steam requirement for all units post revamp running normally: 260 TPH Steam available from CPP post revamp (as per BORL operating data): 228 TPH. Presently one additional 160 UB boiler is under implementation by BORL. This will cater to the additional requirement of steam. The existing 225 TPH boiler will be

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common standby for both existing and the revamped system. Hence no new facility is required for steam. Steam balance of refinery in conjunction with new and existing boilers shall be worked out during design stage from energy optimization point of view like consideration of back pressure turbine type pumps in some services etc. Boiler Feed Water Requirement

Boiler feed requirement of various units and Captive Power Plant (CPP)is given in Table-7.5.12.

Table 7.5.12: BFW consumption (TPH)

Units Level Existing Post Revamp

CDU/VDU MP 21.9 27.4

CCR LP 1.3 4.6 (Note-2) MP 8.7 12.9 (Note-2)

ISOCRACKING MP 80 125 (Note-2) PENEX HP 1 1.5 (Note-2)

DCU HP 7 3 (Note-1,2) MP 23.6 14.9(Note-2)

TOTAL HP 8 4.5 MP 134.2 180.5 LP 1.3 4.6

NET TOTAL 143.5 189.5

Note-1: The HP BFW requirement in DCU is intermittent and for spalling of the heater considered for total requirement of BFW . Note-2: As per Licensor data.

The MP+LP BFW import system from CPP is designed for 170 m3/hr on continuous basis as per existing and HP BFW is supplied by HGU. In post revamp MP +LP BFW requirement is around 185 m3/hr. HP BFW requirement = 4.5 m3/hr. Since MP+LP BFW pump rated flow is 197m3/h, no change in BFW system and pump is envisaged.

7.5.8 CONDENSATE SYSTEM

Steam is being used in the refinery as process steam motive fluid for the steam turbine drives, ejectors, heating etc. Condensate results from the condensing steam turbine drives, steam re-boilers and ejector condensers. Within the each individual units suspect condensate and pure condensate is segregated. During

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normal operation, suspect condensate is treated in centralised condensate polishing unit before use. However, the pure condensate and surface condensate is directed to polished condensate tanks. Condensate generation summary for various units is given below in Table-7.5.13.

Table 7.5.13: Condensate Balance

Units Total Condensate (TPH) Existing Post Revamp

CDU/VDU Nil 4.0 ISO CRACKING & DHDT

53.6 83.1

DCU 30.5 52.9(Note-1) HGU +REFORMER Nil Nil CCR Platforming 9.9 18 Penex unit 19.3 26.1 Sulphur Block 40 60 Utilities & Offsite Nil Nil CPP Nil Nil Total (Normal) 153.3 244.2

Note -1: As per Licensor data. CPU Capacity

Design capacity of existing chains is 50TPH. Two chains of 50 TPH capacity (1W+1s) is provided for treating suspect condensate and tracer condensate.. Post expansion Total condensate generation will be 244.2 TPH .The break up of condensates for the post revamp scenario is as follows: Surface Condensate : 81.2 TPH Pure Condensate : 116.7 TPH Suspect Condensate : 46.3 TPH The total suspect condensate including tracer condensate works out to be 52.55(6.25+46.3). Although the post revamp requirement is marginally higher than the existing train capacity one additional chain of CPU in parallel to existing chain with capacity same as existing capacity of 50 T/hr has been considered based on BORL requirement. Feed Condensate tank (Unpolished Condensate) The feed condensate tank(1+1) was originally designed for 16 hrs(total flow =106 TPH) equivalent storage of continuous suspect(37.8TPH) and largest pure/surface condensate flow (67.7 TPH). Post revamp the Feed condensate tank hold up reduces to 11 hrs for a total condensate flow of 163 TPH.

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CPU Feed Pumps In existing two no’s (1W+1s) unpolished condensate transfer pumps of 50 m3/hr each are provided. No additional unpolished condensate pump is considered for the additional chain of CPU. Polished Condensate tank The feed condensate tank was originally designed for 16 hrs (total flow =170.5 TPH) equivalent storage of continuous polished condensate(50TPH), Surface condensate from unit (52.8 TPH)and pure/surface condensate flow(67.7 TPH). Post revamp the Polished condensate tank hold up reduces to 11.4 hrs for a total condensate flow of 244.2 TPH. Polished Condensate/Preheat exchangers and Polished condensate pumps Both the preheat exchangers in CPU are sized for 182 TPH of total condensate (suspect +pure+ surface condensate).The adequacy of the preheat exchangers will be established during the engineering for the revised polished condensate and feed condensate flow. The existing three polished condensate transfer pumps(2W+1S) are of capacity 95 m3/h each with total flow of 190 m3/h. The adequacy of these pumps for 30% increase in flow will be checked during detail engineering.

7.5.9 FUEL GAS AND FUEL OIL SYSTEM

The fuel requirement for the BINA Refinery post revamp would continue to be met by fuel oil & fuel gas generated internally from various process units. Furnaces within process units would operate partially by fuel gas system and partially by fuel oil systems. For CPP the CFBC boilers are presently operated on Indonesian coal instead of pet coke and HSD will continue as start up fuel. Two types of fuel oil is being used, IFO for only CDU/VDU heaters with 0.5 % sulphur, RFO for remaining consumers with 0.5 % sulphur. Fuel Demand

The total fuel demand in MMKCal/hr of respective units of BINA Refinery project, considering all units running is indicated in the following table. The following consumers in the complex are considered to be on fuel gas only.

101/201 heaters in HCU unit. NHT Charge heater 19-FF-00-101(as per Licensor report) NHT Auxiliary Heater 11-FF-00-103B CCR heaters 20-FF-101/102/103(as per Licensor report) Pilot burners in all heaters, SRU and Flare. Fuel gas purging for flare network DCU, WGC seal purging. Incinerator in SRU.

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Overall Fuel Gas Balance A) Fuel gas balance in the BINA refinery complex for 100% fuel gas firing in

various units operating scenarios is as follows:

Table-7.5.14: Overall Fuel Gas Balance

UNIT FG Generation KG/HR

FG Consumption KG/HR(100%firing)

CDU 0 6640.12 VDU 0 3940.51 HCU/DHT 6146.8(NOTE-2) 7687.28 3146(NOTE-3)

DCU 14519.7 4302.83 NHT 1169 3105.00 CCR 3212 (NOTE-4) 4778.76 PENEX 931 HGU 0 50.00 SRU 0 2900.00 HOT OIL HTR 3088.94 Pilot Burner 0 557.00 Flare Purging 0 500.00 Total 29124.5 37550

Note -1: 100 % fuel gas firing is not possible as the fuel gas generation is less

than the consumption. Note -2: 6146.8 kg/hr of fuel gas from Off Gas of HCU/DHDT after hydrogen recovery from recovery PSA in HGU. This will be updated after receiving data from PSA vendor. Note- 3: 3146 kg/hr after H2S removal in amine treating within CDU/VDU. Note -4: 3212 kg/hr of fuel gas from Net Gas of CCR after hydrogen recovery from recovery PSA in HGU. This will be updated after receiving data from PSA vendor.

B) Since fuel gas is not available for 100 % firing fuel balance in the BINA refinery complex is distributed between fuel gas and fuel oil. The ratio of fuel gas and fuel oil is based on the splits provided by BORL during PFR study for various units:

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Table-7.5.15: Overall Fuel Balance

Unit Total fired duty, MMKcal hr

FG Consumption

KG/HR

FO Consumption

KG/HR CDU 75.03 4421.2 2639.4

VDU 44.53 1113.9 3362.1 HCU/DHT Reaction Heaters 27.14 2402.1 0 HCU Fractionators Heaters 59.72 1493.6 4349.7 DCU Heater 46.64 1166.4 3397.4 WGC comp dry seal gas

175

NHT 35.09 1666 1650.8 CCR 54 4778.7 0 HGU

50 0

SRU 0 2900 HOT OIL HTR 34.91 872.4 2542.8

Pilot Burner 0 557 0 Flare Purging 0 500 0 Total

22096 17942.3

Note -1: Excess of fuel gas ~7028 kg/hr is available when fuel oil is fired along with fuel gas.

7.5.10 FLARE SYSTEM

The existing flare system is provided for safe disposal of combustible, toxic gases which, are relieved from process plants and off sites during start-up, shutdown, normal operation or in case of an emergency such as:

Cooling water failure General Power failure External fire case Any other operational failure Blocked outlet Reflux failure Local power failure Tube rupture

The refinery complex shall have two flare systems, one for Hydrocarbon flare for process units & off-sites handling hydrocarbon and the other for the sulphur block handling sour flare.

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Of the above emergencies defined for flare system, the complex power failure was the governing load for sizing the flare system. The existing design flare load and the flare load in revamp for the general power failure is tabulated below:

HC Flare Existing Capacity : 946,973 kg/hr

HC Flare Post Revamp Capacity : 1217133.4 kg/hr

S.NO UNIT Load Mol. Wt Temp. Existing Revised Existing Revised Existing Revised

1 CDU/VDU - - - - - - 2 DCU 292075 350000 39 57 167.1 215 3 MS

BLOCK 274250 372291 86.2 89.3 161.2 175.26

4 HCU/DHT 380648 494842.4 45.4 45.4 151.9 151.9 5 HGU - - - - - - TOTAL 946973 1217133.4 56.98 62.16 159.3 177.19

The adequacy of the existing Flare system has been checked for the revised flare load ,mol wt and temperature. The flare loads of DCU and MS block are as per the Licensor data and the load for HCU-DHT is based on the estimated value post expansion . The major findings of the flare system for the revised flare load conditions are as below: a) Flare Stack: The Existing flare stack is adequate for the Post Revamp load. b) Flare KOD: The Existing flare KOD is adequate for the Post Revamp load. c) Water Seal Drum: Water Seal drum is adequate for the post revamp

conditions .However as suggested by BORL internal modifications in water seal drum is envisaged due to low flow of flare gas during normal conditions.

d) Flare Header : The existing flare header is found adequate for the revamp load.

Sour Flare Existing Capacity : 30,846 kg/hr ( peak load)

Sour flare Post Revamp Capacity : 30,846 kg/hr (peak load)

Since the governing case for sour flare is fire case for TGTU which remains unchanged post revamp thus existing sour flare is adequate for the post revamp conditions.

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Offsites Description DFR for Debottlenecking of





SECTION 7.6

OFFSITES DESCRIPTION

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7.6.0 OFFSITE SYSTEM

The offsite facilities of existing refinery consists of a) Tank Farm b) Interconnection of process lines between process units c) Product Run down lines from refinery to Dispatch Terminal.

7.6.1 TANK FARM

Tank Farm facilities are designed to store and transfer feed, intermediate and finished products. The storage capacities are based on the crude, intermediate and finished products material balance vis-à-vis number of days of stock requirements. The summary of existing feed and intermediate storage tanks and their pumps are tabulated in tables 7.6.2 & 7.6.3, given at the end of the chapter. Adequacy check has been done for the existing feed and intermediate storage tanks based on the revised capacities of the units for refinery expansion from 6 MMTPA to 7.8 MMTPA. Details of Storage tanks considered for feed and intermediate services are attached in Table 7.6.4 (at the end of the chapter) as per the basis given below.

7.6.1.1 Crude storage and transfer

The refinery has three storage tanks (51-TT-FR-01A/B/C) which were designed originally for 6.5 days of operation. The holdup time available will get reduced from 6.5 to 6.3 days with existing tanks. One additional crude storage tank is considered which will provide 8.3 days of hold up post revamp. The existing crude water Tank (52-TT-CR-15) will be sufficient to collect drain water from additional Crude tank and no new tank is considered. The existing pumps 51-PA-CF-01A/B/C have been checked for the revised duty conditions and the pumps have been found adequate with the change in impeller and replacement of motor.

7.6.1.2 Intermediate Feed Storage and Transfer

For all intermediate services the holdup time available in the intermediate feed/storage tanks based on post revamp scenario has been reviewed as against the holdup time originally envisaged for each service. Additional Tanks have been proposed in the intermediate services whenever there is a considerable reduction in hold up time post revamp.

a) Naphtha Hydro Treater (NHT) Unit Feed Storage and Transfer

The feed to NHT storage tank (52-TT-FR-06) consists of full range stabilised naphtha from CDU/VDU. The existing tank was designed to provide storage requirement of 5.9 days production of Naphtha from CDU/VDU operating @60% when NHT is down. For the post revamp scenario, the no of day storage reduces to 4.8 days. One additional tank has been proposed which would provide storage for 9.6 days.

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The existing feed pump 52-PA-CF-06 A/B has been checked for the revamp duty conditions and found adequate with replacement of impeller with higher diameter.

b) Continuous Catalytic Reforming (CCR) Feed Storage Tank and Transfer

The feed to CCR feed tank (52-TT-CR-07) is HDT heavy naphtha from NHTU and HCU heavy naphtha. The existing tank (1 no) was designed to provide storage requirement of 2.5 days@60% throughput when NHT is down. For the post revamp scenario, the number of storage days reduced to 1.1 days. One additional tank has been proposed which would provide storage for 2.2 days. The existing pumps 52-PA-CF-107 A/B have been checked for the post revamp scenario and found adequate for the revamp duty conditions.

c) Reformate Storage and Transfer

Normally reformate from CCR will be routed to both Euro-V and Euro-IV Premium Gasoline blending pools. The existing reformate tank (52-TT-FR-12) is designed for supplying 4.8 days of reformate for MS blending when CCR unit is shutdown. In the post revamp scenario the no. of days reduces to 3.2 days. Hence one additional tank has been proposed which would increase the available storage to 6.3 days. The existing pumps (51-PA-CF-12A/B) will be adequate with impeller change.

d) Isomerate Storage And Transfer

The existing 2 no. of tanks (52-TT-DR-11A/B) are designed for 5.6 days of production for isomerate of MS blending. For the post revamp flow the isomerate , hold up available will be for 4.6 days in the existing tanks. No new tank is proposed for Isomerate. The existing pumps 52-PA-CF-11A/B are not adequate for the revamp flows and needs impeller to be replaced with higher diameter along with replacement of motor.

e) Hydrogen Generation Unit Feed Storage Transfer

The HGU feed storage tank (52-TT-DR-08) receives mixed Pentane (Depentanizer Overhead) from PENEX unit. The existing tank is designed to cater HGU for 2.5 days @60% throughput when Penex Unit is shutdown. Since the no. of days will reduce to 2.0 days of storage for the post revamp scenario, one additional tank has been considered. The existing feed pumps 52-PA-CF-08 A/B for HGU is adequate for the post revamp scenario.

f) Coker Naphtha Coker Naphtha produced in DCU will be stored in Coker Naphtha Tank (52-TT-CR-19). The existing tank is designed to store 8.5 days of production of Coker Naphtha from DCU operating at 60% throughput when HCU is

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shutdown and to cater the HCU unit operating at 60% throughput for 2.3 days when DCU is shutdown. The storage requirement reduces to 7.1 days(when HCU down)and 1.9 days (when DCU down)in post revamp scenario. Since one tank is already under construction in addition to the existing tank, no new tank is proposed. The existing pumps 52-PA-CF-19A/B are adequate for the revamp duty conditions.

g) Diesel Hydrotreating Unit (DHDT) Feed Storage and Transfer

A combined stream of light gas oil, heavy gas oil, vacuum diesel from CDU/VDU is to be stored in DHDT feed tank (52-TT-CR-05A/B/C). The existing 3 tanks (52-TT-CR-05A/B/C) are designed for storage of 11.8 days of production of diesel form CDU/VDU operating at 60% throughput and 3 days of feed to DHDT @60% throughput when CDU/VDU is shutdown. Since 11.8 days and 3 days storage reduces to 9.4 days and 2.3 days for diesel from CDU/VDU and feed to DHDT, one additional tank has been considered and with additional tank the no. of days will increase to 12.6 and 3.0 days. The existing DHDT feed pumps 52-PA-CF-05A/B have been found adequate for the revamp scenario.

h) Light Coker Gas Oil

In existing refinery one LCGO tank (52-TT-CR-17) has been provided for 16.3 days of production of LCGO from DCU operating at 60% throughput when DHDT is shutdown. For post revamp flow, the storage days reduces to 12.5 from 16.3 days. Since LCGO is normally routed hot from DCU to DHDT, 12.5 no. of days are acceptable and no new tank is proposed. The existing LCGO pumps 52-PA-CF-17A/B have been found adequate for the revamp flows.

i) Hydrocracker Unit Feed Storage and Transfer

The feed from Hydrocracker unit (HCU) consists of vacuum gas oil (VGO) from CDU/VDU, Heavy Coker Gas Oil (HCGO) and coker Naphtha from DCU. VGO, HCGO and Coker Naphtha will be stored separately.

Vacuum Gas Oil The existing three tanks (52-TT-CR-02A/B/C) for VGO are sized for storing 12 days of production of VGO from CDU/VDU operating at 60% throughput when HCU is shutdown as well as for catering the HCU operating at 60% throughput for 3.5 days when CDU/VDU is shutdown. For post revamp flows, hold up available in the tank reduces to 9.5 days from 12 days and to 2.3 days from 3.0 days. One additional tank has been considered similar to existing 3 tanks. The additional tank would provide storage for 12.7 days (when HCU is shutdown) and 3.1 days (when CDU/VDU is shutdown) respectively for VGO. The existing pumps 52-PA-CF-02A/B are adequate for the revamp flows.

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Heavy Coker Gas Oil The existing two tanks (52-TT-CR-03A/B) are designed to store 11 days of production of HCGO from DCU operating at 60% when HCU is shutdown or to cater the HCU for 3.5 days operating at 60% when DCU is shutdown. For post revamp scenario, the holdup reduces to 8.7 days for HCGO from DCU and 3.0 days for HCGO to HCU unit. Since already one tank is under construction, no new tanks are proposed. The existing HCGO pumps 52-PA-CF-03A/B are not adequate for the revamp duty conditions and impeller to be replaced with impeller of higher diameter.

j) Vacuum Residue (VR) Storage and Transfer

VR from VDU will be stored in VR (DCU) feed storage tank (52-TT-CR-04A/B). The existing two tanks were designed for 8.2 days of production of VR from CDU/VDU operating at 60% throughput when DCU is shutdown as well as to cater DCU operating at 60% throughput for 2 days when CDU/VDU is shutdown. Since already one tank is under construction and with new tank, storage requirement of 9.9 days(VR from CDU) and 2.3 days(feed to DCU) are met, no new tank is envisaged. The existing pumps 52-PA-SC-01A/B/C are adequate for the revamp duty conditions.

Miscellaneous Offsite Storages

a. CDU/VDU Internal Fuel Oil (1wt% Sulfur) Storage and Transfer

No additional tank is proposed as consumption of fuel oil in CDU/VDU is envisaged to be reduced in post revamp scenario. The existing pumps will be adequate for post revamp case.

b. Refinery Fuel Oil (2% wt Sulfur) Storage and transfer

No additional tank is proposed as consumption of fuel oil in refinery is envisaged to be reduced in post revamp. The existing pumps will be adequate for post revamp case.

c. Dry Slop Storage and Transfer

The storage requirement of the existing tank (52-TT-FR-09) is to store 8 hour off spec production from CDU/VDU at 60% of normal throughput during start up. In the post revamp scenario, the holdup time available will be 6.4 hours. However since a new tank is already under construction no new tank is considered. Accordingly, the existing pumps are adequate for post revamp.

d. MTBE Storage

MTBE is uploaded from the truck tankers and stored in MTBE Storage tank. Existing tank (52-TT-DR-18) has holdup time of 8.3 days. As per the post

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revamp requirement of MTBE, one new tank to be considered. The existing MTBE pump (52-PA-CF-18) and MTBE blowdown pump (52-PA-CF-20A/B) will be adequate for post revamp conditions. Miscellaneous Offsite Pumps

The remaining pumps consisting of Flushing Oil Pump (52-PA-CF-21A/B), White oil Blowdown Pump (52-PA-CF-22A/B), Black Oil Blowdown pump (52-PA-CF-23A/B), Crude Surge Storage pump (52-PA-CF-24A/B) and BCW pump (52-PA-CF-25A/B) will be adequate for post revamp flow. The adequacy report of all offsite pumps is tabulated in Table 7.6.1 as below:

Table 7.6.1: Adequacy of Offsite Pumps

S.NO PUMP TAG NUMBER SERVICE MODIFIACTIONS

1 51-PA-CF-01A/B/C CRUDE

Impeller change of larger diameter and motor replacement of rating 320 KW.

2 52-PA-CF-02A/B/C VGO As Existing

3 52-PA-CF-03A/B HCGO Impeller change with larger diameter

4 52-PA-SC-04A/B/C VR As Existing 5 52-PA-CF-05A/B DHDT FEED As Existing

6

52-PA-CF-06 NHT FEED Impeller change with larger diameter

7 52-PA-CF-07A/B CCR FEED As Existing 8 52-PA-CF-08A/B HGU FEED As Existing 9 52-PA-CF-09A/B DRY SLOP As Existing

10 52-PA-SC-10A/B BLACK SLOP As Existing

11 52-PA-CF-11A/B ISOMERATE

Impeller change of larger diameter and motor replacement of rating 45 KW.

12 52-PA-CF-12A/B REFORMATE Impeller change with larger diameter

13 52-PA-CF-13A/B CDU IFO As Existing 14 52-PA-CF-14A/B REFINERY IFO As Existing 15 52-PA-CF-15A/B CRUDE WATER As Existing 16 52-PA-CF-16A/B HCU LT NAPHTHA As Existing 17 52-PA-CF-17A/B LCGO As Existing 18 52-PA-CF-18 MTBE As Existing 19 52-PA-CF-19A/B COKER NAPHTHA As Existing 20 52-PA-CF-20A/B MTBE As Existing

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BLOWDOWN 21 52-PA-CF-21A/B FLUSHING OIL As Existing

22 52-PA-CF-22A/B WHITE OIL BLOWDOWN As Existing

23 52-PA-CF-23A/B BLACK OIL BLOWDOWN As Existing

24 52-PA-CF-24A/B CRUDE SURGE STORAGE As Existing

25 52-PA-CF-25A/B BCW As Existing

7.6.1.3 Finished Product Storage and Transfer Philosophy

Finished product for the refinery is stored in the BINA dispatch terminal Refer section 7.8 for details.

7.6.2 INTERCONNECTION OF PROCESS LINES BETWEEN PROCESS UNITS

The interconnecting offsite lines between various units are checked for revamped flow which are corresponding to respective units revamp capacity. Sizes of all lines are found adequate from hydraulic point of view.

7.6.3 PRODUCT RUN DOWN LINES FROM REFINERY TO MARKETING TERMINAL

Final Products are received to Marketing Terminal from Refinery through piping.The maximum length of each pipe from Refinery to Bina Dispatch Terminal is 2.5 Kms. These pipes are above ground lines on Pipe sleepers. The product wise piping sizes are given in the following table.

Product Receipt Pipeline Size in inch MS-Euro III/IV 8” ( Common) HSD-Euro III 12” HSD- Euro IV 10”

ATF 8” SKO 8”

Naphtha 6” LPG 6”

LPG ( off spec) 4”

Besides indicated above two more lines are provided from Marketing Terminal to Refinery.

1. Slop Return line (WO) - 8”

2. LPG reprocessing line - 3”

3. ETP Water to Refinery ETP - 6”

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All final products run down lines are checked for product slate based on revamped material balance ( refer section 7.4) across refinery and blending of EuroIV MS and diesel.

Existing product headers are found adequate for the post revamp increase in production. For Euro-IV Gasoline the offsite header sizing is just adequate and unit B/L pressure for HCU Heavy naphtha, Isomerate and reformate may be required to increase which shall be established during design stage.

Table 7.6.2: Existing Offsite Tanks

Table 7.6.3 : Existing Offsite Pumps

SERVICE NO. OF PUMPS RATED CAPACITY

OF EACH PUMP M3/Hr

PRESSURE AT UNIT B/L, Kg/cm2 g

CRUDE 2 + 1 485 3.0 VGO 2 + 1 155 12.0

S No. Service Pumpable Volume

( Vol in between LLL and HLL of Tank)

Type of Tank**

Tank Size D X H

Current M3 Meter 1 CRUDE 3 54500 FR 68 X 20 2 VGO 3 15797 CR 40 X 14 3 HCGO 2 5220 CR 26 X 11 4 VR (DCU FEED) 2 12721 CR 40 X 12 5 DHDT FEED 3 12825 CR 38 X 13.5 6 NHT FEED 1 25971 FR 52 X 15.3 7 CCR FEED 1 3857 CR 24 X 11 8 HGU FEED 1 3813 DR 20 X 14 9 DRY SLOP 1 2116 FR 18 X 12

10 BLACK SLOP 1 1830 CR 14 X 13.3 11 ISOMERATE 2 3813 DR 20 X 14 12 REFORMATE 1 8418 FR 30 X 15 13 CDU/VDU IFO 2 1293 CR 14 X 10 14 REFINERY IFO 2 1615 CR 14 X 12 15 CRUDE/WATER 1 1200 CR 14 X 10 16 HCU LT NAPHTHA 1 3813 DR 20 X 14 17 LCGO 1+1 4565 &

12825 CR 24 X 12 &

38 X 13.5 18 MTBE 1 3813 DR 20 X 14 19 COKER NAPHTHA 1 3850 CR 24 X 11

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HCGO 1 + 1 50 12.0 VR 2 + 1 115 4.0 DHDT FEED 1 + 1 205 10.0 NHT FEED 1 + 0 105 7.0 CCR FEED 1 + 1 105 15.5 HGU FEED 1 + 1 40 6.0 DRY SLOP 1 + 1 50 3.0 BLACK SLOP 1 + 1 10 3.0 ISOMERATE 1 + 1 55 7.0 REFORMATE 1 + 1 85 7.0 CDU IFO 1 + 1 20 4.0 REFINERY IFO 1 + 1 30 4.0 CRUDE WATER 1 + 1 55 2.0 HCU LT NAPHTHA

1 + 1 24 6.0

LCGO 1 + 1 75 10.0 MTBE 1 + 0 20 7.0 COKER NAPHTHA

1 + 1 30 12.0

FLUSHING OIL 1 + 1 70 7.0

Table 7.6.4: Feed and Intermediate Storage Tanks

Tank Descriptio

n

Pump- able

volume

(m3)

Vol of Tank (m3)

No of storage days

Existing

No. of storage days Post

Debottlenecking Remarks

Crude (51-TT-FR-01A/B/C)

54500 60000 6.5 6.5 days will be reduced to 6.3 days

One additional tank is required

VGO (52-TT-CR-02A/B/C)

15797 17050 i) In case of HCU down with CDU/VDU operating at 60% throughput considering tanks are 20% filled, no. of storage days =12

i) In case of HCU down with CDU/VDU operating at 60% throughput considering tanks are 20% filled, no. of storage days =9.5

One additional tanks

ii) In case of CDU/VDU down & HCU operating at 60% throughput considering 20%

ii) In case of CDU/VDU down & HCU operating at 60% throughput considering 20% filled tanks, no. of

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Tank Descriptio

n

Pump- able

volume

(m3)

Vol of Tank (m3)

No of storage days

Existing



filled tanks, no. of days available=3.5

days available=2.3

HCGO (52-TT-CR-03A/B)

5220 5820 i) In case of HCU down with DCU operating at 60% throughput considering tanks are 20% filled, no. of storage days =11

i) In case of HCU down with DCU operating at 60% throughput considering tanks are 20% filled, no. of storage days =8.7

One additional tank under construction with one additional tank provided storage days = 13.0 in case of HCU down with DCU operating at 60% throughput.

ii) In case of DCU down & HCU operating at 60% throughput considering 20% filled tanks, no. of days available=3.5

ii) In case of DCU down & HCU operating at 60% throughput considering 20% filled tanks, no. of days available=3.1

Considering one additional tank being constructed, storage time increases to 4.7days.

VR (52-TT-CR-04A/B)

12721 15000 i) In case of DCU down with CDU/VDU operating at 60% throughput considering tanks are 20% filled, no. of storage days =8.2

i) In case of DCU down with CDU/VDU operating at 60% throughput considering tanks are 20% filled, no. of storage days =6.6

one additional tank is under construction. With one additional tank provided storage days=9.9

ii) In case of CDU/VDU down & DCU operating at 60% throughput with 20% filled tanks, no. of days available=2

ii) In case of CDU/VDU down & DCU operating at 60% throughput with 20% filled tanks, no. of days available=1.6

one additional tank is under construction. With one additional tank provided storage days=2.3

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Tank Descriptio

n

Pump- able

volume

(m3)

Vol of Tank (m3)

No of storage days

Existing



DHDT (52-TT-CR-05A/B/C)

12825 15240 i) In case of DHDT down with CDU/VDU operating at 60% throughput considering tanks are 20% filled, no. of storage days =11.8

i) In case of DHDT down with CDU/VDU operating at 60% throughput considering tanks are 20% filled, no. of storage days =9.4

One additional tank

ii) In case of CDU/VDU down & DHDT operating at 60% throughput with 20% filled tanks, no. of days available=3

ii) In case of CDU/VDU down & DHDT operating at 60% throughput with 20% filled tanks, no. of days available=2.3

One additional tank

NHT (52-TT-FR-06)

25971 28860 i) In case of NHT down with CDU/VDU operating at 60% throughput considering tank are 50% filled, no. of storage days =5.9

i) In case of NHT down with CDU/VDU operating at 60% throughput considering tank are 50% filled, no. of storage days =4.8

One additional tank

ii) In case of CDU/VDU down & NHT operating at 60% throughput with 50% filled tank, no. of days available=5.9

ii) In case of CDU/VDU down & NHT operating at 60% throughput with 50% filled tank, no. of days available=4.8

CCR (52-TT-CR-07)

3857 4960 i) In case of NHT down with CCR operating at 60% throughput considering tank are 50% filled, no. of storage days =2.5

i) In case of NHT down with CCR operating at 60% throughput when tanks are 50% filled, no. of storage days =1.1

One additional tank

HGU (52-TT-DR-08)

3813 4410 i) In case of ISOM down with

i) In case of ISOM down with HGU

One additional tank

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Tank Descriptio

n

Pump- able

volume

(m3)

Vol of Tank (m3)

No of storage days

Existing



HGU operating at 60% throughput considering tank are 50% filled, no. of storage days =2.5

operating at 60% throughput considering tank are 50% filled, no. of storage days =2.2

ISOMERATE (52-TT-DR-11A/B)

3813 4398 i) In case of ISOM down, two tanks with pumpable capacity of 3813 m3 will supply 5.6 days of production of isomerate for MS blending

i) In case of ISOM down, two tanks with pumpable capacity of 3813 m3 will supply 4.6 days of production of isomerate for MS blending

Sufficient storage time post debottlenecking, no additional tanks

REFORMATE (52-TT-FR-12)

8418 10603 i) In case of CCR down, one tank with pumpable capacity of 8418 m3 will supply 4.8 days of production of reformate for MS blending

i) In case of CCR down, one tank with pumpable capacity of 8418 m3 will supply 3.2 days of production of reformate for MS blending

One additional tank

CDU/VDU IFO (52-TT-CR-13A/B)

1293 1539 3.4 days of IFO consumption in CDU/VDU considering two tanks 50% filled

2.7 days of IFO consumption in CDU/VDU considering two tanks 50% filled

REFINERY IFO (52-TT-CR-14A/B)

1615 1847 2.8 days of IFO consumption in refinery with two tanks 50% filled

HCU LT NAPHTHA(52-TT-DR-16)

3813 4410 i) In case of NHT down with HCU operating at 60% throughput considering tanks are 50% filled, no. of storage days =3.3

i) In case of NHT down with HCU operating at 60% throughput considering tanks are 50% filled, no. of storage days =2.6

No additional tank is considered

LCGO (52- 4565 5410 i) In case of i) In case of DHDT No additional

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Tank Descriptio

n

Pump- able

volume

(m3)

Vol of Tank (m3)

No of storage days

Existing



TT-CR-17) DHDT down with DCU operating at 60% throughput considering smaller tank 20% filled ,and bigger tank empty, no. of storage days =16.3

down with DCU operating at 60% throughput considering smaller tank 20% filled, and bigger tank empty, no. of storage days =12.5

tank required .

LCGO (52-TT-CR-17A)

12825 15240

COKER NAPHTHA (52-TT-CR-19)

3850 4960 i) In case of HCU down with DCU operating at 60% throughput considering 20% filled, tank, no. of storage days =8.5

i) In case of HCU down with DCU operating at 60% throughput considering 20% filled, tank, no. of storage days =7.1

One additional tank already under construction. With one additional tank no of storage days =14.2

ii) In case of DCU down & HCU operating at 60% throughput with 20% filled tank, no. of days available=2.3

ii) In case of DCU down & HCU operating at 60% throughput with 20% filled tank, no. of days available=1.9

One additional tank already under construction. With one additional tank no of storage days =3.8

MTBE (52-TT-DR-18)

3813 3813 Tank with pumpable volume of 3813 m3. No storage days available for blending in MS= 8.3

Post revamp MTBE requirement is 96 MTPA. No reduction in storage days.

One Additional Tank

DRY SLOP (52-TT-FR-09)

2116 2116 To Store 8 hours of off spec product form CDU @60% throughput during start up

Storage time decreases to 6.4 hours.

One Additional Tank under Construction

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Tank Descriptio

n

Pump- able

volume

(m3)

Vol of Tank (m3)

No of storage days

Existing



BLACK SLOP (52-TT-CR-10)

1886 1830 To store 8 hours off spec product for CDU @60% throughput during start up

Storage Time decreases to 6.3 hours.

No additional tank

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Crude Oil Terminal/Pipeline DFR for Debottlenecking of





SECTION 7.7

CRUDE OIL TERMINAL/ PIPELINE

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7.7.1 CRUDE OIL TERMINAL

System Description

Crude oil will be received and stored in the crude storage tanks in Crude Oil Terminal. Free water associated with crude, which settles down during intermediate storage period, will be drained and treated in the Effluent Treatment Plant (ETP) located within COT. After settlement and draining of water, crude will be transferred to the Refinery crude storage tanks through 935 KM Vadinar Bina Pipeline. The system consists of Crude Oil receipt, storage and pumping facilities.

Receipt of crude

Crude from SPM will be directly received in tanks located in COT (Crude pumping rate from SPM to COT will be approximately in the order of 6600 m3/hr to 9000 m3/hr depending on pressure available at ship tanker end), through a 48" OD pipeline in the subsea portion as well as onshore portion.

Storage of crude

The crude oil storage terminal is designed on the basis of import of crude oil by ship tankers of parcel size 3,60,000m3 as the largest tanker capacity. The storage requirement at the COT is based on the following criteria: 1. Stored capacity of each crude storage tank shall be 60,000m3. 2. Though different types of crudes such as Arab Mix, (50:50), Kuwait and

Oman shall be received, the present design is based on the Arab Mix (50:50 / AL: AH) only.

3. Crude pumping with drag reducing agent injection to the refinery shall be at the rate of 1078 M3/hr (corresponding to crude density of 870kg/m3 of AM crude) to meet the demand of 7.8 MMTPA.

4. There shall be common storage tanks for all crudes. 5. Slippage time of tanker arrival is considered as 2 days. 6. Ship tanker can arrive 1 day in advance. 7. Received parcel will ready for pumping in 48 hours or 2 days (tank

preparation time after receiving crude for any one tank). First tank receiving the parcel will be ready for pumping after one day after unloading is completed from a VLCC parcel

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Major Equipments/Lines Requirement

Based on this basis, following major facilities are envisaged for cost consideration

S. no Equipment/

Instrument/Line Quantity Specification

1. Crude Tanks 4 Same as Existing crude tanks

Dia x Ht = 68.0m x 20.0m Storage Capacity = 60000 M3

2. Receipt Header 1

Size =48” Length = 300 m (including individual tank

manifold) Line Spec = A9A

3. ROSOV 4 Size-48”, Spec-A9A

4. MOV 8 Size-48”, Spec-A9A

8 Size-36”, Spec-A10A

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7.7.2 PIPELINE A crude oil pipeline is installed to transport crude oil from COT located at Vadinar to Bina refinery of BORL through 24” x 931 km pipeline. The pipeline has 3 pumping stations at chainage 0, 358.6 and 556.7 km from Vadinar and is designed for throughput of 6 MMTPA. BORL intends to augment the processing capacity of Bina refinery from present 6 MMTPA to maximum achievable capacity considering low cost expansion. In line with the expansion of refinery, feasibility study for the Vadinar-Bina pipeline has been done for 7.8 MMTPA refinery throughput. Suitability of Drag Reducing Agent injection was also explored to analyze the capacity augmentation without many modifications in the pipeline. Salient Features Of The Existing Pipeline

Size : 24” Design Pressure : 70.1 Kg/Cm2g Length : 931 km No. of Pumping Stations : 3 Configuration : 2 working + 1 Stand by Chainage 0.0: Vadinar Chainage 358 km: Thamna Chainage 556 km: Bewari Intermediate pigging stations : 2 Nos Chainage 189 km: Sidhasar Chainage 758 km: Sandavata Present design capacity : 6 MMTPA Margin available for enhancement : NIL (due to intermediate pumping

station at Thamna operating near design pressure)

Pipeline Maximum operating Pressure (MOP) : 63.73 kg/cm2 g Pipeline Maximum allowable Operating Pressure (MAOP) : 70.10 kg/cm2 g (MOP x 1.1) Present Pumping capacity : 862 m3/hr

VBPL Simulation With DRA Injection

125% of the existing throughput is considered to check for the capacity augmentation of the pipeline. Hence flow rate considered is 862 x 1.25 = 1078 m3/hr. Presently BORL is using following type of DRA in their pipeline operation. The basic properties of the used DRA are given below.

1. Type : Vegetable Oil based DRA. Suspension type. 2. Density : 7.5 lbs/gal = 0.9 kilos/liter

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3. Below are the model and correlation

CONOCO DRA type model is used in the simulation which is most applicable for the type of DRA being introduced presently. Following are the major results from simulation output:

Sr No DRA injection rate (ppm) Pump Discharge Pressure(kg/cm2 g)

Vadinar Thamna (IP-1)

Bewari (IP-2)

Vadinar Thamna (IP-1)

Bewari (IP-2)

Case-I 10 36 30 63.6 65.4 59.7

Case-II 10 35 30 63.6 65.6 59.7

Case-III (SeeNote)

6 (6) 10(10) 6(6) 65.65(59.5) 73.1(56) 74.8(58.5)

6 30 20 65.65 66 63.3

Where, Case-I: Kuwait Crude with 125% of the normal capacity i.e. 1078 m3/hr Case-II: Arab-Mix with 125% of the normal capacity Case-III: Kuwait crude with 120% of the normal capacity i.e. 1060 m3/hr

Note: Case-III was used to check/validate the simulation results with the present DRA injection rate and operating conditions of pipeline. In the first row of the case-III, the values outside the bracket are present observations at site. Values inside the bracket are simulation results keeping the same DRA injection rate as present. In the second row, DRA injection rate is changed to keep the pump discharge pressure in the acceptable range.

Performance Coefficients

m 9.000 b 1.250 DR = 1 / ( m / ppm + b )

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Conclusion

In order to increase throughput to 130% of normal (6MMTPA *1.3) DRA needs to be injected at pump discharge @ 10 PPM at Vadinar,@36/35 PPM at Thamna (IPS-1) and @30 PPM at Bewari (IPS-2) for both Arab Mix and Kuwait crudes. The validation simulation was also carried out for the 120% increase throughput for Kuwait Crude to compare with actual field data. It was observed that with present dosing rate at Vadinar of 6PPM simulation predicts that Vadinar pumps are just adequate, however the pump discharge pressure required is higher than the field data. However for IPS-1 and IPS-2 the simulation predicts that at IPS-1 the dosing rate should be 30 PPM instead of field data of 10 PPM and at IPS-2 the dosing rate should be 20 PPM instead of field data of 6 PPM in order to keep pump discharge pressure within limits of existing pumps. Pump Adequacy

Based on the simulation with DRA injection at the three stations, the revised requirement of head and flow rate for pumps of VBPL calculated as under:

Station Booster pump @ Vadinar

Main line pump @Vadinar

IPS-1 IPS-2

Flowrate (M3/Hr) 539 539 539 539

Differential Head (m) 54 714 669 737

Pump adequacy was checked with respect to the above revised requirements. Following table enlists the results of the pump adequacy.

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Sl. No

Item No. Description Existing Pump parameters Proposed pump rated parameters

Adequacy of pumps for Post Revamp

Remarks

1 10-PA-CF-101 A/B/C

Booster Pump

Rated Flow: 474.1 m3/hr Diff. Head: 60 m Driver Rating: 110 kW Parallel Operation (2 Stage, Vertical Barrel Type)

Rated Flow: 539 m3/hr Diff. Head: 54 m

Inadequate

Based on pump vendor's reply, the existing pumps are Inadequate. Additional booster pump shall be considered with the same parameters as existing.

2 10-PA-CF-102 A/B/C, (Vadinar Dispatch Terminal)

Mainline Pump

Rated Flow: 474.1 m3/hr Diff. Head: 738 m Driver Rating: 1400 kW Parallel Operation (6 Stage)

Rated Flow: 539 m3/hr Diff. Head:714 m

Adequate

Based on vendor's reply, the existing pumps can be considered adequate for the revised operating parameters, without any modification.

3 30-PA-CF-201 A/B/C (Intermediate Pumping Station-I)

Mainline Pump


Rated Flow: 539 m3/hr Diff. Head:737 m

Adequate Based on vendor's reply, Pumps can be considered as adequate. However, motor and VFD will require replacement for the new duty condition.

4 40-PA-CF-301 A/B/C (IP Station- II)

Mainline Pump


Rated Flow: 539 m3/hr Diff. Head:669m

Adequate Based on vendor's reply, the existing pump can be considered adequate for the revised operating parameters, without any modification.

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Bina Dispatch Oil DFR for Debottlenecking of





SECTION 7.8

BINA DISPATCH TERMINAL

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7.8.1 STORAGES 7.8.1.1 Existing Storage Details

Finished Products received from Refinery are stored in storage tanks. The storage capacities of each product in existing facilities are decided based on operational requirement. The number and capacity of tanks can be decided based on following philosophy.

Receipt Road Dispatches ( All products ) Rail Dispatches ( HSD, MS, SKO and ATF ) Pipeline dispatch (HSD, MS, SKO and ATF) Settling time / Quality checks / Certification Maintenance

The following Table indicates the details of existing product storage facilities for different products in the Bina Dispatch Terminal.

PRODUCTS NO. OF TANKS

TYPE OF TANK

PUMPABLE CAPACITY OF EACH

TANK (M3)

Total storage in terms of

days for 6 MMTPA

Total storage in terms of days for

7.8 MMTPA

HSD Euro III 5 FIXED ROOF 14125

14.5 11.5 1 FIXED ROOF 14125

HSD Euro IV 5 FIXED ROOF 14125

17.8 14.2 1 FIXED ROOF 6140

MS Euro III 5 FLOATING ROOF 12125

41.6

28.9 1 FLOATING ROOF 6155

MS Euro IV 5 FLOATING ROOF 12125

40 1 FLOATING ROOF 6155

SKO 4 FLOATING ROOF 6155

16.3 11.4 1 FLOATING ROOF 6155

NAPHTHA 3 FLOATING ROOF 6155

22.5 26.0 1 FLOATING ROOF 6155

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ATF

5 FIXED CUM

FLOATING ROOF 10450

29.5 29.5

1 FIXED CUM

FLOATING ROOF 10450

SLOP (OFF

SPEC

PRODUCT)

2 FIXED ROOF 858 NA NA

TOTAL 41 TANKS 414886 M3

LPG

5 MOUNDED

STORAGE 1400 MT

13.8 10.7

1

MOUNDED

STORAGE (off

spec LPG)

1400 MT

TOTAL 6 MOUNDED STORAGE 8400 MT

Notes:

1. Normally smaller capacity tank (as indicated for individual products in the above table) is used for product dispatch through Road & Rail loading system. However flexibility is provided for dispatching product from any of the tank. Products cannot be received from the refinery directly in the small tanks. Product are transferred to smaller capacity tanks using inter tank transfer line.

2. Split of product is not available between Euro-III and Euro-IV grade for Gasoline

and Diesel production. There is a common receipt header for Euro III and Euro IV Regular Gasoline, hence total production of gasoline is considered for both the grade.

3. There are separate headers for Euro-III and Euro-IV grade Diesel. Productions of

both the diesel grades have been assumed in the same proportion of existing production.

CONCLUSION With respect to product receipt rate, present storage facility is found adequate.

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7.8.2 PRODUCT DISPATCH FACILITY

Existing product dispatch facility is based on loading points in the bays of Marketing Terminal. The products are dispatched through Road and Rail loading facility as well as through pipeline transfer. Road and Rail loading facility satisfies local demand while pipeline transfer is utilized for satisfying demand from other regions of India.

7.8.2.1 Road Loading Facility

For white oil, tanker capacity is considered as 12 KL where as for LPG tanker capacity is 18 MT. Two separate weigh bridges in existing facility are provided for weighing of the empty and filled LPG and Naphtha at the entry and exit point. Custody transfer of other while oil products are through PD meter. Road Tanker loading facility can be utilized to maximum extent on the following basis:

1. Design Basis for white oil road gantry:

345 days per year shall be considered for loading operation.

Loading is done in two shifts operation per day.

Working hours per shift shall be 8 hours.

Effective working hours per shift shall be 6 hours.

Minimum time considered to fill 12 KL white oil tanker is 10 minutes. (For Top

& bottom loading). Minimum time considered for connection/disconnection is

10 minutes.

Maximum loading rate in case of top loading will be 72 M3/Hr. (1200 L/m)

while for bottom loading maximum rate will be 144 M3/Hr. (2400 L/m).

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TLF Gantry Configuration

White oil TLF Gantry bay configuration and loading pattern is given under,

Products HSD

-III HSD-IV

MS-III MS -IV

SKO ATF Naphtha Total

Top loading points 5 - 3 - 3 1 4 16

Bottom loading points

- 1 - 1 - 1 1 4

Total 5 1 3 1 3 2 5 20 Maximum trucks (Proportionate to the no of loading points)

90 18 54 18 54 36 90 360

Maximum loading per day according to maximum no of trucks, m3/day

1080 216 648 216 648 432 1080 4320

Maximum loading per annum according to maximum no of trucks, KTPA

320 64 192 64 192 128 320 1282

Details of Road loading pumps

Products Design Pumping Rate Required

No. of Pumps

Capacity of each pump

(M3/Hr.) OP. S/B (M3/Hr.)

HDS-III 396 2 1 200 HSD-IV 158.4 1 1 160 MS-III 237.6 2 1 200 MS-IV 158.4 1 1 160 SKO 237.6 2 1 200 ATF 237.6 2 1 160

NAPHTHA 475.2 3 1 240

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2. Design Basis for LPG road gantry

345 days per year shall be considered for loading operation. LPG road tanker loading is being loaded from bottom only. Minimum time considered for LPG tanker (18 MT) loading is 45 minutes.

Maximum time considered for connection/disconnection is 15 minutes. Loading is done in two shifts operation per day. Working hours per shift shall be 8 hours. Effective working hours per shift shall be 6 hours. LPG Road loading pump capacity = 150 M3/Hr (2 operating and 1 Stand by)

Based on above basis, Maximum trucks per day = 4 x 12 = 48 Maximum loading per day according to maximum no of trucks, TPD = 864 Maximum loading per day according to maximum no of trucks, KTPA = 298

CONCLUSION Maximum loading achievable is just below Post revamp LPG production i.e. 287 KTPA. 345 effective days per year and 6 effective hours per shift are considered for LPG loading operation. If loading time can be increased marginally or over design margin is reduced, there would not be any additional requirement of loading facility. No additional LPG road gantry is envisaged. LPG pumps are adequate enough to take care of design LPG loading rate of 220 M3/Hr.

7.8.2.2 Rail Loading Facility

Rail loading of products are on volumetric basis for White oils. One full rake siding is developed for white oils for filling the following products,

Naphtha - 1 Full Rake HSD (Euro IV) - 1 Full Rake ATF - 1 Full Rake SKO - 1/2 (Half) Rake MS (Euro III) - 1 Full Rake MS (Euro IV) - 1/2 (Half) Rake

The facility is designed for rail loading of HSD, ATF, SKO and MS from single spur.

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Basis For Design Time available for loading one full rake for Naphtha, HSD Euro IV, ATF, MS and Half Rake of SKO/MS shall be 5 hours. Total Time available for a filling = 3.5 hours Number of BTPN wagons per rake = 50 wagons. Capacity of each BTPN wagon = 47-55 MT. Gantry configuration is one gantry for two spurs to accommodate 1full rake in

each spur. One spur is being used in the present scope. The gantry is being operated in three shifts i.e. 24hrs, 365 days. However, for

design purpose 345 number of working days (10% margin for maintenance and other contingencies) and 2.5 rakes per day are considered for Rail loading.

Single shift shall be of 8 hours. Effective working hours per shift shall be 6 hours. The number of wagons considered for pump design (the pumping time shall be

3.5 hours) shall be as follows :-

Product No. of wagons for pump design Naphtha 50 BTPN HSD (Euro-IV) 50 BTPN MS (Euro-III) 50 BTPN MS (Euro-IV) 25 BTPN ATF 50 BTPN SKO 25 BTPN

The pump details for existing rail loading are given below:

Products No of Wagons for

pump design No. of Pumps. Rated capacity of

each Pump (M3/Hr.) OP. SB

Naphtha 50 BTPN 4 1 300

HSD Euro IV 50 BTPN 4 1 300

MS Euro III 50 BTPN 4 1 300

MS Euro IV 25 BTPN 2 1 300

ATF 50 BTPN 4 1 300

SKO 25 BTPN 2 1 300

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CONCLUSION There are 1 full rake spurs available in the rail gantry and considering 2.5 rakes per day with 345 working days about 862.5 full rakes (maximum) filling is anticipated.

1 BTPN full rake capacity = 55 MT x 50 wagons = 2750 MT Approximate Total Rail loading achievable per year = 862.5 rakes x 2750 MT

= 2371.87 KTPA Approximate maximum road loading achievable = 1733 KTPA Total white oil products to be evacuated in post-revamp shall be about 6275

KTPA. In case of shut down of BKPL total product evacuation cannot be achieved and which may directly impact the refinery production.

Consider additional spur with full rake loading facility in existing rail gantry. Facility shall be designed for rail loading of Naphtha, HSD Euro III, HSD Euro IV,

MS Euro III, MS Euro IV, ATF and SKO from both the spurs. New HSD Euro III rail loading facility shall also be considered with rail loading

transfer pumps, separate header and master meter in the rail gantry. There shall be common PD meter assembly and loading arms for HSD Euro III and HSD Euro IV.

Tap off for separate loading arm shall be taken downstream of PD meter assembly of each product as shown diagrammatically below:

Following are the specifications for additional equipments considered:

1. HSD Euro III rail loading transfer pumps

Total No of Pumps : 5 (4 operating + 1 Stand by) Rated capacity of each pump : 300 M3/Hr Differential Head : 90 meter Design Pressure/ Temperature : 15 kg/cm2 G/ 65 °C MOC : KCS

NEW SPUR

RAIL

WAGONS

PD METER

ASSEMBLY

LOADING ARMS

RAIL

WAGONS

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2. Loading arms for new spur

No of loading arms for HSD Euro III/ Euro IV : 50

No of loading arms for Naphtha : 50 No of loading arms for MS Euro III/ Euro IV : 50 No of loading arms for ATF : 50 No of loading arms for SKO : 50 Normal/ Design flow of each loading arm : 65/72 M3/Hr

Design Pressure/ Temperature : 19 kg/cm2 G/ 65 C MOC : CS Type : Top Loading Size : 3”

7.8.2.3 Pipeline Facility

Following is the product slate for marketing through multiproduct pipeline facility. No modification is envisaged for pipeline transfer facility. Figures in MTPA (000’TPA)

Route 2013-14 MS-4 MS-3 HSD-4 HSD-3 SKO ATF Total

Bina - Kota 363 205 703 915 139 439 2764

Kota - Mathura 363 180 703 775 135 439 2595

Mathura - Piyala 315 146 609 538 84 439 2131

Piyala - Bijwasan 292 0 404 0 14 439 1149

Route 2019-20 MS-4 MS-3 HSD-4 HSD-3 SKO ATF Total

Bina - Kota 459 248 889 1147 139 707 3588

Kota - Mathura 459 216 889 975 135 707 3380

Mathura - Piyala 399 176 771 674 84 707 2810

Piyala - Bijwasan 370 0 511 0 14 707 1602

7.8.2.4 MTBE Tank Wagon Unloading Facility

To optimize Euro-IV gasoline blending around 98000 TPA MTBE requirements is forecasted. To cater the demand Tank wagon unloading facility is required to be designed at BDT.

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Presently MTBE storage tank is already available at BORL (Tag No. 52-TT-DR-18) with the storage capacity of 4250 M3. One additional tank is required to accommodate bulk storage through rail gantry. Consideration of new storage tank at BDT will not be of much benefit as extra set of pumps shall be required to transfer MTBE from BDT to MS blending station and above that redundancy/flexibility of tank will not be there. Hence, additional MTBE tank shall be provided in BORL nearer to the existing tank. Tank wagon unloading facility and Pipeline from Tank Wagon gantry to the MTBE tanks at BORL are considered on following basis:

Total Time available for unloading one full rake of MTBE shall be 5 hours. Time available for a unloading = 3.5 hours Time for connection/Disconnection = 1.5 hours Number of BTPN wagons per rake = 50 wagons. Capacity of each BTPN wagon = 55 MT. 1 full rake from one of the spurs is considered for unloading MTBE. Only one

spur shall be designed for unloading MTBE. Single shift shall be of 8 hours. Effective working hours per shift shall be 6 hours. 50 number of BTPN wagons are considered for pump design (the pumping time

shall be 3.5 hours) Total Rake capacity = 50 wagons x 55 MT = 2750 MT i.e. 3682 M3 (MTBE sp.

Gravity = 0.747) The pump details for MTBE unloading pumps are considered as below:

Pump Rated Capacity : 300 M3/Hr Pump Head : 100 meter No of Pumps : 4 working + 1 stand by

Design Pressure/ Temperature : 15 kg/cm2 G/ 65 °C MOC : KCS

ANNEXURE Refer to annexure 7.8.1 for Bina Dispatch Terminal layout for post revamp scenario.

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Logistics DFR for Debottlenecking of


Document No. A439-RP-0241 -0001



SECTION 7.9

LOGISTICS

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7.9.0 LOGISTICS

This chapter deals with movement of crude, finished products and utiltites. 7.9.1 Crude

Crude carried by Ocean Tanker is off loaded at Single Point Mooring (SPM) of CALM type near Vadinar, Gujarat, at a distance of about 15 KM offshore. From SPM crude is conveyed by sub sea line and onshore (approx 3.5 KM from Land fall point (LFP)) pipeline to Crude Oil Terminal (COT) battery limits. Crude oil is recieved and stored in the crude storage tanks in Crude Oil Terminal. From COT tanks, crude is pumped to Refinery through Vadinar Bina Pipeline (VBPL) which is 935 Km long cross country crude pipeline from Vadinar to Bina.

7.9.2 FINISHED PRODUCTS

The final products from refinery as listed below are dispatched through Road and Rail loading facility

LPG Naphtha Euro III/ Euro IV Gasoline Kerosene Aviation Turbine fuel Euro III/ Euro IV Diesel Coke

All final liquid products are sent to Marketing terminal from refinery via piping. Sufficient facilities for road and railway loading/ unloading at marketing terminal are provided to meet the local demand. Facilities for pipeline transfer of multi products are also available for satisfying demand from other regions of India. Coke produced within refinery is transported by road to nearby places and by railway to other parts of India. The utility systems are an integral part of the refinery and constructed on the Refinery site. All utilities required for the plant shall be generated inside the complex The refinery is self-sufficient in all its utility requirements except raw water and partly power.

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Raw water: Raw water is made available at the refinery battery limit from river Betwa. Raw water requirement is around 2000m3/h. Raw water storage and treatment facility is provided for the refinery. Raw water is the source for Cooling water, DM water, Drinking water and BFW that are used in the plant.

Power: Total power requirement post revamp will be around 115MW. Post expansion power available from CPP will be around 47 MW ( CPP designed for 99MW) . The balance power shall be available from Grid power. The fuel for existing CPP is Coke which is transported to refinery via railway.

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Environmental Considerations DFR for Debottlenecking of





SECTION 8

ENVIRONMENTAL CONSIDERATIONS

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8.0 ENVIRONMENT CONSIDERATIONS 8.1 INTRODUCTION

Industrial development is essential for growth and betterment of the living conditions of the society. Industrial development, however, is endemic with its effect on the environment. It is essential that even while the industrial development is spurred for growth, the environment is conserved and protected. It has been considered essential to adopt environmental protection measures and adhere to legislations such that the ecology and the habitat of the area are not disturbed.

Various pollution control measures required to meet the prevailing environmental standards are planned at the different stages of execution of the project, viz., design, construction and operational phases.

8.2 POLICY AND LEGAL FRAMEWORK

Government of India has made many legislations/rules for the protection and improvement of environment in India. Various environmental legislations/rules applicable to the proposed project facilities are as follows:

Indian Environmental Legislation

The Environment (Protection) Act, 1986. The Environment (Protection) Rules, 1986 Environment (Protection) Third Amendment Rules, 2002 Coastal Regulation Zone-Notification dated May 21, 2002 The Public Liability Insurance Act, 1991 The Public Liability Insurance Rules, 1991 The Water (Prevention and Control of Pollution) Act, 1974, and its subsequent notifications.

The Water (Prevention and Control of Pollution) Cess Rules 1977 and its subsequent notifications.

The Air (Prevention and Control of Pollution) Act 1981 and its subsequent notifications.

Hazardous Wastes (Management and Handling) Rules, 1989, and its subsequent notifications.

Manufacture, Storage and Import of Hazardous Chemical Rules, 1989 and its subsequent notifications.

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Noise Pollution (Regulation and Control) Rules, 2000 and its subsequent notifications.

The proposed project shall be designed taking into account the above-referred legislations/rules. Besides this the proposed effluent and emission standards for Refineries will also be complied for this Project. A brief description of the environmental protection measures proposed to be adopted in the project with respect to the various components of the environment like air, water, noise, land, etc., is given in the subsequent sections.

8.2.1 Air Environment

The gaseous emissions from the proposed project will be controlled to meet all the relevant standards stipulated by the regulatory authorities.

8.2.1.1 Ambient Air Standards

The ambient air quality around the premises will be limited to those limits as per National Ambient Air Quality Standards, which are given below in Table- 8.1.

Table 8.1: National Ambient Air Quality Standards 2009

S.No.

Pollutants

Time Weighted Average

Concentration in Ambient Air

Industrial, Residential, Rural and Other Area

Ecologically Sensitive Areas (Notified by Central Government)

1 Sulphur Dioxide (SO2), µg/m3

Annual Average*

50 20

24 hours** 80 80 2 Oxides of

Nitrogen as NO2,

µg/m3

Annual Average*

40 30

24 hours** 80 80 3 Particulate Matter

(size less than 10 µm) or PM10 µg/m3

Annual Average*

60 60

24 hours** 100 100

4 Particulate Matter (size less than 2.5

Annual Average*

40 40

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S.No.

Pollutants

Time Weighted Average

Concentration in Ambient Air

Industrial, Residential, Rural and Other Area

Ecologically Sensitive Areas (Notified by Central Government)

µm) or PM2.5 µg/m3

24 hours** 60 60

5 Ozone (O3), µg/m3

8 hours** 100 100 1 hour** 180 180

6 Lead (Pb), µg/m3 Annual Average*

0.5 0.5

24 hours** 1 1 7 Carbon Monoxide

(CO) mg/m3 8 hours** 2.0 2.0 1 hour** 4.0 4.0

8 Ammonical (NH3), µg/m3

Annual Average*

100 100

24 hours** 400 400 9 Benzene (C6H6),

µg/m3 Annual Average*

5 5

10 Benzo (α) Pyrene (BaP), Particulate Phase Only ng/m3

Annual Average*

1 1

11 Arsenic (As), ng/m3

Annual Average*

6 6

12 Nickel (Ni), ng/m3 Annual Average*

20 20

* Annual Arithmetic mean of minimum 104 measurements in a year at a particular site taken twice a week 24 hourly at uniform intervals. **24 hourly or 8 hourly or 1 hourly monitored values, as applicable shall be complied with 98% of the time in a year. 2% of the time, it may exceed the limits but not on two consecutive days of monitoring.

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8.2.1.2 Emission Standards

The Emission Standards as proposed by CPCB for Petroleum Oil Refineries in the context of the proposed project are given below:

Table 8.2: Emission Standards For Furnace / Boilers / Captive Power Plant

S. No. Parameter Fuel Type

Limiting Concentration (mg/Nm3) Existing Refineries

New Refinery / Furnace / Boiler

1 NOx (Oxides of Nitrogen)

Gas Firing 50 50

Liquid Firing 1700 850

2 SO2 (Sulphur Dioxide)

Gas Firing 350 250


3 PM (Particulate Matter)

Gas Firing 10 5


4 CO (Carbon Monoxide)

Gas Firing 150 100


5 Ni + V (Nickel + Vanadium)

Liquid Firing 5 5

6 H2S (Hydrogen Sulphide) in Fuel gas

Liquid / Gas 150 150

7 Sulphur Content in

liquid fuel, wt.% Liquid / Gas 1.0 0.5

Notes:

1. In case of mixed fuel (gas and liquid) use, the limit shall be computed based on heat supplied by gas and liquid fuels.

2. All the furnaces/boilers with heat input of 10 million kilo calories/hour or more shall have continuous systems for monitoring of SO2 and NO2. Manual monitoring

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for all the emission parameters in such furnaces or boilers shall be carried out once in two months.

3. All the emission parameters in furnaces/boilers having heat input less than 10 million kilo calories/hour will be monitored once in three months.

4. In case of continuous monitoring, one hourly average concentration values shall be complied with 98% of the time in a month. Any concentration value obtained through manual monitoring, if exceeds the limiting concentration value, shall be considered as non-compliance.

5. Data on Nickel and Vanadium content in the liquid fuel (in ppm) shall be reported. Nickel and Vanadium in the liquid fuel shall be monitored at least once in six months, if liquid fuel source & quality are not changed. In case of changes, measurement is necessary after every change.

Table 8.3: Emission Standards For Sulphur Recovery Unit (SRU)

S.No. Parameter Plant Capacity (TPD)

Existing SRU

New SRU or Refinery Commissioned

1 Sulphur Recovery, % Above 20 98.7 99.5 2 H2S, mg/Nm3 15 10 3 Sulphur Recovery, % 5-20 96 98 4 Sulphur Recovery, % 1-5 94 96

5 Oxides of Nitrogen (NOx), mg/Nm3 All Capacity 350 250

6 Carbon Monoxide (CO), mg/Nm3 All Capacity 150 100

Notes:

1. Sulphur recovery units having capacity above 20 tonnes per day shall have

continuous systems for monitoring of SO2. Manual monitoring for all the emission parameters shall be carried out once in a month.

2. Data on Sulphur Dioxide emissions (mg/Nm3) shall be reported regularly.

3. Sulphur recovery efficiency shall be calculated on monthly basis, using quantity

of sulphur in the feed to SRU and quantity of sulphur recovered.

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8.2.1.3 Standards For Fugitive Emission, Leakages & Voc Emissions

Storage of Volatile Liquids: General Petroleum Products

1. Storage tanks with capacity between 4 to 75m3 and total vapor Pressure (TVP) of more than 10 kpa should have Fixed Roof Tank (FRT) with pressure valve vent.

2. Storage tank with the capacity between 75 to 500 m3 and total vapor Pressure

(TVP) of 10 to 76 kpa should have Internal Floating Root Tank (IFRT) of External Floating Root Tank (EFRT) or Fixed Roof Tank with vapor control or vapor balancing system.

3. Storage tanks with the capacity of more than 500 m3 and total vapor Pressure

(TVP) of 10 to 76 kpa should have Internal Floating Roof Tank or External Floating Roof Tank or Fixed Roof Tank with vapor control system.

4. The tanks with the capacity of more than 75 m3 and total vapor Pressure (TVP)

of more than 76 kpa should have Fixed Root Tank with vapor control system.

5. Requirement for seals in Floating Roof Tanks: (i) (a) IFRT and EFRT shall be provided with double seals with minimum

vapor recovery of 96%. (b) Primary seal shall be liquid or shoe mounted for EFRT and vapor

mounted for IFRT. Maximum seal gap width will be 4 cm and maximum gap area will be 200 cm2/m of tank diameter.

(c) Secondary seal shall be rim mounted. Maximum seal gap width will be 1.3 cm and maximum gap area will be 20 cm2/m of tank diameter.

(d) Material of seal and construction shall ensure high performance and durability.

(ii) Fixed Roof Tanks shall have vapour control efficiency of 95% and vapour

balancing efficiency of 90%

(iii) Inspection and maintenance of storage tanks shall be carried out under strict control. For the inspection, API RP 575 may be adopted, In-service inspection with regard seal gap should be carried out once in every six months and repair to be implemented in short time. In future, possibility of on-stream repair of both seals shall be examined.

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Storage of Volatile Liquids: Benzene Storage

1. FRT with vapor to incineration with 99.9% of removal efficiency for volatile organic compounds (VOC) shall be provided.

2. IFRT/EFRT with double seals, emission-reducing roof fitting and fitted with

fixed roof with vapor removal efficiency of at least 99% shall be provided.

Solvents for Lube-Base Oil production (Furfural, NMP, MEK, Toluene and MIBK)

IFRT with double seals and inert gas blanketing with vapor removal efficiency of at least 97% shall be provided.

Table 8.4: Emission Control For Road Tank Truck / Rail Tank Wagon

Loading

Loading of Volatile Products

Gasoline & Naphtha: (i) VOC reduction % 99.5 (ii) Emission, gm/m3 5 Benzene: (i) VOC reduction % 99.99 (ii) Emission, gm/m3 20 Toluene & Xylene: (i) VOC reduction % 99.98 (ii) Emission, gm/m3 150

Notes: (i) It shall be applicable for Gasoline, Naphtha, Benzene, Toluene and Xylene loading. (ii) Road tank Truck shall have Bottom loading and Roll tank wagon shall have Top submerged loading. (iii)Annual leak testing for vapor collection shall be done.

8.2.1.4 Standards for Equipment Leaks

1. Approach: Approach for controlling fugitive emissions from equipment leaks

shall have proper selection, installation and maintenance of non-leaking or leak-tight equipment. Following initial testing after commissioning, the monitoring for leak detection is to be carried out as a permanent on-going Leak Detection and Repair (LDAR) programme. Finally detected leaks are to be repaired within allowable time frame.

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2. Components to be Covered: Components that shall be covered under LDAR

programme include (i) Block valves; (ii) Control valves; (iii) Pump seals; (iv) Compressor seals; (v) Pressure relief valves; (vi) Flanges – Heat Exchangers; (vii) Flanges – Piping; (viii) Connectors – Piping; (ix) Open ended lines; and (x) Sampling connections, Equipment and line sizes more than 1.875 cm or ¾ inch are to be covered.

3. Applicability: LDAR programme would be applicable to components (given at 2

above) for following products/compounds: (i) hydrocarbon gases; (ii) Light liquid with vapor pressure @ 20o C > 1.0 kPa; and (iii) Heavy liquid with vapor pressure @ 20o C between 0.3 to 1.0 kPa.

4. While LDAR will not be applicable for heavy liquids with vapor pressure < 0.3

kPa, it will be desirable to check for liquid dripping as indication of leak. 5. Definition of leak: A leak is defined as the detection of VOC concentration

more than the values (in ppm) specified below at the emission source using a hydrocarbon analyzer according to measurement protocol (US EPA – 453/R-95-017, 1995 Protocol for equipment leak emission estimates may be referred to) :

Table 8. 5 Component General Hydrocarbon

(ppm) Benzene (ppm)

Till 31st Dec 2008

w.e.f Jan 1, 2009

Till 31st Dec 2008

w.e.f Jan 1, 2009

Pumps / Compressor 10000 5000 3000 2000 Valves / Flanges 10000 3000 2000 1000 Other Components 10000 3000 2000 1000

6. In addition, any component observe to be leaking by sight, sound or smell,

regardless of concentration (liquid dripping, visible vapor leak) or presence of bubbles using soap solution should be considered as leak.

7. Monitoring Requirements and Repair Schedule: Following frequency of monitoring of leaks and schedule for repair of leaks shall be followed as per Table 8.6:

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Table 8. 6: Monitoring Requirements and Repair Schedule

S.No. Component Frequency of

monitoring Repair schedule

1 Valves / Flanges Quarterly (semiannual after two consecutive periods with < 2% leaks and annual after 5 periods with < 2% leaks)

Repair will be started within 5 working days and shall be completed within 15 working days after detection of leak for general hydrocarbons. In case of benzene, the leak shall be attended immediately for repair.

2 Pump seals Quarterly

3 Compressor seals

Quarterly

4 Pressure relief devices

Quarterly

5 Pressure relief devices (after venting)

Within 24 hours

6 Heat Exchangers Quarterly

7 Process drains Annually 8 Components that

are difficult to monitor

Annually

9 Pump seals with visible liquid dripping

Weekly Immediately

10 Any component with visible leaks

Weekly Immediately

11 Any component after repair/ replacement

Within a week -

8. The percentage leaking components should not be more than 2% for any group of components monitored excluding pumps/compressors. In case of pumps/compressors it should be less than 10% of the total number of pumps/compressors or three pumps and compressors, whichever is greater.

9. Emission inventory: Refinery shall prepare on inventory of equipment

components in the plant. After the instrumental measurement of leaks,

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emission from the components will be calculated using stratified emission factor (USEPA) or any other superior factors. The total fugitive emission will be established.

10. Monitoring following types of monitoring methods may be judiciously employed for detection of leaks: (i) instrumental method of measurement of leaks; (ii) Audio, visual and olfactory (AVO) leak detection; and (iii) Soap bubble method.

11. Data on time of measurement and concentration value for leak detection; time

of repair of leak; and time of measurement & concentration value after repair of leak should be documented for all the components.

12. Pressure relief and blow down systems should discharge to a vapor collection

and recovery system or to flare. 13. Open-ended lines should be closed by a blind flange or plugged. 14. Totally closed-loop should be used in all routine samples. 15. Low emission packing should be used for valves. 16. High integrity sealing materials should be used for flanges.

8.2.1.5 Standards For Voc From Waste Water Collection And Treatment

1. All contaminated and odorous wastewater streams shall be handled in closed

systems from the source to the primary treatment stages (oil-water separator and equalization tanks).

2. The collection system shall be covered with water seals (traps) on sewers and

drains and gas tight covers on junction boxes. 3. Oil-water separators and equalization tanks shall be provided with

floating/fixed covers. The off-gas generated shall be treated to remove at least 90% of VOC and eliminate odour. The system design shall ensure safety (prevention of formation of explosive mixture, possible detonation and reduce the impact) by dilution with air/inert gas, installing LEL detector including control devices, seal drums, detonation arrestors etc. The system shall be designed and operated for safe maintenance of the collection and primary treatment systems.

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4. Wastewater from aromatics plants (benzene and xylene plants) shall be treated to remove benzene & total aromatics to a level of 10, 20 ppm respectively before discharge to effluent treatment system without dilution].

8.2.2 Noise Environment

Ambient Standard for Noise, specified by CPCB is given below in Table-8.7.

Table 8.7: Ambient Air Quality Standards in respect of Noise

S.No. Area Code Category of Area Limit in dB (a) Leg

Day Time Night Time

1.0 A Industrial area 75 70

2.0 B Commercial area 65 55

3.0 C Residential area 55 45

4.0 D Silence zone 50 40

Notes: 1. Daytime is reckoned in between 6 am and 9 pm 2. Nighttime is reckoned in between 9 pm and 6 am 3. Silence zone is defined as areas upto 100 meters around such Premises as

hospitals, educational institutions and courts.The Silence zones are to be declared by the competent authority.

4. Mixed categories of areas should be as "one of the four above Mentioned categories" by the competent authority and the Corresponding standard shall apply.

8.2.3 Water Environment The treatment scheme envisaged will meet the quantitative and qualitative limits of parameters stipulated in General Standards for Discharge of Environmental Pollutants for Petroleum Refineries as given in Table-8.8.

Table 8.8: Standards for discharge of Environmental Pollutants from Petroleum Refineries

S.No Parameter Concentration not to exceed limits in mg/l except pH

1 pH 6.0-8.5

2 Oil & Grease 5.0

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3 BOD 3 days, 27oC 15

4 COD 125

5 Suspended Solids 20

6 Phenols 0.35

7 Sulphides as S 0.5

8 Cyanide (CN) 0.2

9 Ammonia as N 15.0

10 TKN 40.0

11 Phosphorus (P) 3.0

12 Chromium (Cr) Hexavalent 0.1

13 Chromium (Cr) Total 2.0

14 Lead (Pb) 0.1

15 Mercury (Hg) 0.01

16 Zinc (Zn) 5.0

17 Nickel (Ni) 1.0

18 Copper (Cu) 1.0

19 Vanadium (V) 0.2

20 Benzene 0.1

21 Benzo (a) – Pyrene 0.2

Notes: 1. Concentration limits shall be complied with at the outlet, discharging effluent

(excluding discharge from sea water cooling systems) to receiving environment (surface water Bodies, marine systems or public sewers). In case of application of treated effluent directly for irrigation/horticulture purposes (within or outside the premises of refinery), make-up water for cooling systems, fire fighting, etc., the concentration limits shall also be complied with at the outlet before taking the effluent for such application. However, any use in the process such as use of sour water in Desalter is excluded for the purpose of compliance.

2. In case of circulating seawater cooling, the blow-down from cooling systems shall be monitored for pH and oil & grease (also Hexavalent & total chromium, if chromate treatment is given to cooling water) and shall conform to the concentration limits for these parameters. In case of reuse of treated

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effluent as cooling water make-up, all the parameters (as applicable for treated effluent) shall be monitored and conform to the prescribed standards.

3. In case of once through cooling with seawater, the oil & grease content in the effluent from cooling water shall not exceed 1.0 mg/l.

8.3 EMISSION DETAILS

8.3.1 Liquid Effluents

A comprehensive waste water management system already exists in the refinery to treat the liquid effluent to meet the EC / State Pollution Control Board requirements for existing refineries. The waste water treatment plant at BORL is designed based on combining physical, chemical and biological treatment systems to effectively control the quality of effluent. The effluent treatment plant has adequate capacity to treat this additional load (max. 50 m3/hr) generated from the proposed facility. The main sources of waste water generation due to proposed project are: (i) Cooling Tower - Cooling tower blow down (due to addition of cooling water

cell of capacity 3000 m3/hr. (ii) Sour Water Stripper Unit - Stripped sour water. (iii) Desalter in CDU/VDU Other sources (minor) of waste water generation are: (i) Hydrogen Generation Unit (ii) Boiler blow down, and (iii) Sulphur Recovery Unit - water sprayed for solidification.

Water Balance for the Refinery Post Expansion is shown in Fig 8.1

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Fig.8.1

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Refinery has a full-fledged Effluent Treatment Plant (ETP) for treatment of the following waste water generated from the refinery.

Oily effluent flow : 198 m3/hr (avg.)/ 375 m3/hr (design) Sanitary flow : 25 m3/hr Spent caustic flow : 7 m3/hr CRWS : 25 m3/hr in dry weather and 1400 m3/hr in wet weather

Schematic Diagram of Existing ETP System is attached in Annexure-3

Design capacity of existing ETP at the refinery is 375 m3/h. As per operating data furnished by BORL the average monthly effluent is 200 m3/h. Post debottlenecking the maximum additional effluent generation shall be around 50m3/h. Hence existing ETP shall be adequate post debottlenecking and no capacity augmentation is envisaged for existing ETP. One additional CRWS tank of existing capacity is considered.

8.3.2 Gaseous Emissions

The atmospheric emissions related to the proposed facilities consist of Point or stack emissions from continuous combustion sources. The existing Refinery has a limit of SOx emissions of 30 TPD. At present configuration of 6 MMTPA the total SOx emissions are 28.25 TPD. The unit wise details are listed in Table 8.9 below:

Table 8.9: SOx emissions for Present Refinery Configuration.

Unit Fired Duty

Fuel Gas, kg/h

Fuel Oil, kg/h

FG (S content 150

ppm) FO

(S content 0.5 %)

Equivalent Sulphur,

kg/h SOx, kg/h

Equivalent Sulphur,

kg/h SOx, kg/h

CDU 64.45 1612 4867 0.24 0.48 24.34 48.67

VDU 42.5 1063 3210 0.16 0.32 16.05 32.1

HCU 88.1 4033 4465 0.61 1.22 22.33 44.66

DCU 42.7 1243 3110 0.16 0.32 15.55 31.1

NHT 27.05 676 1970 0.1 0.2 9.86 19.7

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CCR 37.9 948 2761 0.14 0.28 13.81 27.61

Hot Oil Heater

23.651 591 1723 0.09 0.18 8.62 17.23

HGU 50 0.01 0.02

SRU 1200 0.18 0.36

Pilot Burner 6.294 557 0.08 0.17 Flare Header Purge

500 0.08 0.15

TOTAL 332.65 12473 22106 1.84 3.69 110.5 221 Power Plant Per Coke

840

SRU 112.5

TOTAL TPD 28.25

The Total SOx emissions from the Refinery with proposed expansion to 7.5 MMTPA processing capacity, are estimated to be 29.33 TPD. The unit wise details are listed in Table 8.10 below:

Table 8.10: SOx emissions for Post Expansion Refinery Configuration. Unit Fired

Duty Fuel Gas, kg/h

Fuel Oil, kg/h

FG (S content 150 ppm)

FO (S content 0.5 %)

Equivalent Sulphur, kg/h

SOx, kg/h Equivalent Sulphur, kg/h

SOx, kg/h

CDU 75.03 4421 2639 0.66 1.32 13.19 26.39

VDU 44.53 1113 3362 0.16 0.33 16.8 33.62

HCU 86.86 3895 4349 0.58 1.17 21.74 43.49

DCU 46.64 1166 3397 0.17 0.35 16.98 33.97

NHT 35.09 1666 1650 0.25 0.5 8.25 16.50

CCR 54 4778 0.71 1.43

Hot Oil Heater 34.91 872 2542 0.13 0.26 12.71 25.42

HGU 50 0.01 0.02

SRU 2900 0.43 0.87

Pilot Burner 6.29 557 0.08 0.16

Flare Header Purge

500 0.08 0.16

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TOTAL 383.35 22096 17942 3.28 6.56 89.64 173.34

Power Plant Per Coke

840

SRU (243 TPD x 2 Trains)

Note 1 202.5

TOTAL TPD 29.33

Note1: SOx considering 99.5% recovery in SRU (i) Fugitive Emissions from the process and storage units.

The major sources of fugitive emissions (VOCs) are the main processing area, and storage tanks. These fugitive emissions originate from the pumps, valve packing and connections/ joints to the atmosphere like relief valves etc.

8.3.3 Solid waste

Following types of solid wastes are generated in complex: (i) ETP Sludge &Tank bottom sludge (ii) Spent catalyst (iii) General Solid Wastes

8.4 POLLUTION CONTROL MEASURES

8.4.1 Air Environment

Point / Stack Emissions: For the expansion project, the major air pollutants will be SO2, NOx, and HC. In order to control the pollution right at the source, low sulphur fuel gas is proposed to be used. While the project is designed to use low sulphur fuel oil as fuels, flexibility to use low sulphur fuel gas is also incorporated, depending on the availability, to minimize SO2 emission. It has been proposed that low NOx burners be used to reduce the NOx level substantially in comparison to conventional burners. During start up/shut down or any emergency operation, the hydrocarbon emissions arising due to lifting of relief valves, shall be directed to an elevated flare for complete combustion. This shall eliminate the possibility of forming an explosive mixture due

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to sudden release of unburnt hydrocarbon to the atmosphere. The existing flare is adequate to handle the additional load from this project. The hydrocarbons will be fully burnt and adequate steam will be supplied at the flare tip to minimize smoke. To ensure complete combustion of released hydrocarbon through flare, a pilot flame shall always be burning with the aid of fuel gas. The proposed project shall employ state-of-the-art environmental control technologies to minimize or eliminate toxic releases and emissions. Fugitive Emissions Control:

In order to minimize the fugitive emissions of VOCs, the following measures shall be taken during design stage.

(i) Minimum number of flanges, valves etc. (ii) High grade gasket material for packing. (iii) Usage of "State of the art" low leakage valves preferably with bellow seals. (iv) Usage of pumps with double mechanical seals for lighter

hydrocarbon/hazardous service. (v) Provision of seals in the drains and manholes. (vi) Floating roof tanks with double seals. Dome/Cone roof tanks with N2

blanketing. (vii) Close blow down system in offsite and process units. (viii) Bottom loading & vapor recovery system in Dispatch Terminal (ix) Collecting and recycling seal leaks back to the process, or treating in a

separate emission control device. (x) Capping or blinding of open-ended valves. (xi) Providing for closed sampling systems. (xii) Instituting a comprehensive inspection, leak detection, and maintenance

program conforming to the requirements of the government. (xiii) VOC Collection and Treatment system is already installed in the Effluent

Treatment Plant of the Refinery

8.4.2 Water Environment The water requirement at present for the refinery operation is met through construction of a weir on Betwa River. At the design stage, there are several measures proposed to be incorporated in the process so as to minimize the impact on water environment during operational phase on the surrounding water bodies. Some of these measures are described in subsequent sections. In the design stage, two major mitigation steps are involved.

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(i) In-plant or Pretreatment Technology (ii) End of Pipe treatment

These steps are discussed separately below. In-plant Control Measures

Provision of appropriate segregation and collection philosophy for various effluents depending on individual stream characteristics.

The process waste water will be segregated and thereafter treated further in the existing waste water treatment plant within refinery complex.

Closed blow down system shall be incorporated for all hydrocarbon liquid discharges from the process units which in turn reduce the effluent to ETP both in terms of quantum and quality.

Paving the process areas to avoid contamination of soil/sub soil/ ground water in case of accidental spills/leakage of hydrocarbon liquids.

Removal of hydrogen sulphide and ammonia which are toxic, odorous and exhibit high oxygen demand by stripping the process sour water.

Reuse of treated effluent to the extent possible.

End of Pipe (EOP) Treatment

A comprehensive waste water management system already exists in the refinery to treat the liquid effluent to meet the EC / State Pollution Control Board requirements for existing refineries. The waste water treatment plant at BORL is designed based on combining physical, chemical and biological treatment systems to effectively control the quality of effluent. The existing waste water treatment plant is working efficiently as confirmed by the water analysis carried out during the study period. The effluent treatment plant has adequate capacity to treat this additional load (max. 50 m3/hr) generated from the proposed facility.


The statutory national standards for noise levels at the plant boundary and at residential areas near the plant will be met. The selection of plant equipment will be made with specification of low noise levels as a major consideration. The design will be undertaken with the aim of minimizing noise at source. Noise suppression measures such as enclosures and buffers will be used to limit noise levels in areas frequented by personnel to below 85 dB(A). Areas with high noise levels will be identified and segregated where possible and will be provided with

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prominently displayed caution boards. The existing noise levels at the boundary walls are in the range of 35-60 dB(A). Comprehensive measures for noise control, at the design stage, shall be followed in terms of

(i) Noise levels specification of various Rotating Equipments as per Occupational Safety and Health Association (OSHA) standards.

(ii) Equipment layout to consider the segregation of high noise generating sources.

(iii) Erecting suitable enclosures if required to minimize the impact of high noise generating sources.

(iv) Sizing of flare lines with low Mach number to have lower noise levels. (v) Silencers are provided on high velocity venting systems (vi) Acoustic insulations are provided in Compressor area/Ejector area.

8.4.4 Land Environment

The land environment management at design stage encompasses solid waste disposal plan and development plan for local land use in such a way that treatment and disposal do not cause any serious impact on the existing land use pattern.

8.4.4.1 Solid Wastes Handling, Treatment and Disposal

The Handling, Treatment and Disposal of the Solid wastes generated shall comprise of the following : ETP Sludge & Tank Bottom Sludge As the proposed plant will generate only a fraction of total waste water generated, subsequent increase in ETP sludge generation will also be marginal. Hence, existing solid waste handling, treatment and disposal facilities will be adequate for this purpose. General Solid Wastes The general solid waste generated will include packaging materials, scraps, spent catalysts etc. Most of the solid wastes like packaging and scrap materials have commercial value and will be disposed of by sale.

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Spent Catalysts

Spent catalysts are essentially Co, Mo, Ni and alumina pellets. These catalysts have a life of about 5 years after which they are either returned to the manufacturers or sold to approve re-processors or disposed off to authorized TSDF agencies. Other hazardous wastes and solid wastes generated during refinery operation are disposed as per the applicable guidelines.

8.4.4.2 Green Belt Development

BORL has carried out plantation activities in the 200m wide Greenbelt area around the refinery and in BORL Township in a phased manner since 2008. The detailed year wise saplings planted till date is given in table 8.11:

Table 8.11: Year Wise Plantation Details

S. No. Area & Location of Plantation Year Approx. area

Sapling planted

I Refinery 1. Phase – I: (North west side of the

Refinery complex adjoining village Bhakri and South East Side near gate no. 02).

2008 65 Hec. 1,06,900

2. Phase – II (South west adjoining village Bildhai) .

2009 40 Hec. 62,000

3. Phase – III (South side of refinery complex, rear side of Admin block & front of Engg office).

2010 16 Hec. 25,000

4. Phase – IV (Back side of refinery railway siding area).

2011 36 Hec. 40,000

5. Phase-V (South side of refinery complex- Old Labour Colony (rear side of flare and SRU), In front contractor yard & Fly ash pond area)

2012 32 Hec 35,000

6. Beside Change Room1, Opp to Workshop

2013 1 hec 300

Total 190hec. 2,69,200 II Township 1. Phase – I (along township internal 2008 12,000

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roads) 2. Phase – II (along township boundary

wall) 2009 7,800

3. Road Side plantation (Refinery gate to township gate)

2009 4,200

4. Fruit Bering tree plantation (Beside villa A2)

2013 300

Total 24,300

It has been planned that during this year another 25000 Saplings shall be planted inside refinery and 3500 plants in the township apart from the above mentioned saplings.

The various species of sapling planted in the Greenbelt are given in table 8.12:

Table8.12: Sapling details

S.No. Name of Species S. No. Name of Species

1 Delvergia Sisoo 13 Castar 2 Pongamia Pinetta 14 Holopterlia Belleria 3 Azadiracta Indica 15 Ucaliptus Hybrid 4 Casia Samia 16 Embilica Officinalis 5 Beuhania purpuria 17 Peltaforum Deltadis 6 Habiscus Rozasinensis 18 Sizygium Cumini 7 Casia Biflora 19 Jakrunda Mimiosa 8 Pshethapodia 20 Casia Gluca 9 Dendrocalemus Structus 21 Bouganbelia Spictivillis 10 Delonix Regia 22 Temerendus Indica 11 Anthosephelus Kandamba 23 Annano Squamosa 12 Beuhania Verigeta 24 Psidium Gqaba

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8.4.5 Monitoring of Emissions and Effluents

8.4.5.1 Stack Monitoring

In order to keep a check on the emissions of SO2, NOx, SPM and CO from all the point sources, all stacks shall be monitored as per statutory regulations.

8.4.5.2 Ambient Air Quality Monitoring

At present ambient air quality of the refinery and the surrounding area is measured on continuous/periodic basis with four number of monitoring stations which are identified on the basis of micro-meteorological conditions and human settlement data as susceptible zones. The pollutants monitored are SPM, SO2, NOx, and HC (non methane). The monitoring of these pollutants will be continued in future also.

For regular monitoring of the operation of various pollution control facilities, a laboratory with sophisticated instruments and well-trained manpower exists. A separate Environment Cell with qualified Chemical Engineers/Scientists also exists, which will ensure that all pollution control measures are effectively operating and to carry out day-to-day checks, trouble shooting and further improvements wherever necessary

8.4.5.3 Micro Meteorological Monitoring

In order to effectively co-relate the stack emissions and the real time ambient air quality, the real time micro-meteorological data is also needed. A permanent meteorological data monitoring station within the plant site area, to measure parameters like wind speed, wind direction, ambient temperature, Relative Humidity, Cloud cover, rainfall etc. is already existing.

8.4.5.4 Water Quality Monitoring

The monitoring of raw influent, the intermediate stages of Effluent Treatment Plant, the treated effluent, the receiving water body and the ground water quality in the surrounding areas is not only because of statutory compliance with the regulatory authorities but also helps in reflecting the overall water management of the complex.

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At present, a comprehensive water quality monitoring is carried out for physico-chemical and micro biological parameters (i.e. pH, Oil & Grease, SS, DO, COD, BOD, Sulphide, Phenol) at the inlet and outlet of both the existing Effluent Treatment Plants. This monitoring shall be continued in the post project scenario also.

8.4.5.5 Soil/Sub Soil Quality Monitoring

Provision shall be kept for periodic monitoring of soil and subsoil characteristics in and around the plant area. The important physico-chemical and biological parameters of the soil shall be monitored to evaluate the impact on the land environment.


As the plant is going to be operational on a 24-hour basis, noise considerations are very important. All equipments will be specified to meet 85 dB(A) at 1 m distance. As incorporated during the design stage, the plant areas where noise levels are high enough to cause operations some adverse impacts, the usage of ear plugs or ear muffs shall be strictly enforced. The exposure of employees working in the noisy area shall be monitored regularly to ensure compliance with the OSHA requirements.

8.4.7 Socio-Economic Environment

The local population is to be helped to take up the opportunities afforded by the increased economic activities in the area. Efforts shall be made to promote harmony with the local population and further consolidate their positive perceptions of industrialization by engaging in socially-friendly activities such as building hospitals, educational and technical training institutes, etc. in due course of time, by co-coordinating with the present and future industries of the area.

8.4.8 Health and Safety

In order to provide safe working environment and safeguard occupational health and hygiene, the following measures will be undertaken:

Exposure of workers to hazardous/toxic substances will be minimized by adopting suitable engineering controls.

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Toxic and hazardous HC processing/handling areas shall be clearly identified and regular health monitoring for the people working in these areas shall be carried out.

All the employees shall be trained in Health, Safety and Environment (HSE) aspects related to their job.

Exposure of workers to noise, particularly in areas housing equipment which produce 85dB (A) or more will be monitored by noise desimeters.

Periodic compulsory health check up will be carried for all the plant employees. Particular attention will be given to respiratory and hearing disorders. The yearly statistics along with observations will be reported each year to the chief executive of the plant.

8.4.9 Environmental Audit

Records of quality and quantity of air emissions and liquid effluent will be maintained. Details of quantity of solid waste disposed will be recorded on regular basis. Details of waste storage area in the refinery complex will be maintained, this will include details of the type of waste and the quantity stored. Addresses of buyers of refinery wastes and details of proposed use of wastes will also be maintained. Data on influent to the effluent treatment plant and treated effluent quality and stack emissions will be used to ascertain compliance with stipulated standards. The quantity of waste generated from various units will be compared with previous years' data and efforts will be made to minimize wastes for more efficient utilization of resources.

8.4.10 Environment Cell

M/s. BORL is already having an Environment Cell under its technical services department which is headed by a well qualified and experienced technical person from the relevant field. He is directly reporting to the Head of the plant operations. The cell carries out number of activities related to effluent treatment and monitoring of treated effluent, ambient air quality and stack emissions. The cell also has an analytical laboratory under its control to carry out the analysis of air & water samples. The lab has requisite technical staff to carry out these analyses. The existing set-up shall be utilised for Debottlenecking of BORL project also.

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Project Implementation & Schedule

DFR for Debottlenecking of Bharat Oman Refineries Limited


Rev B

Ch 9 Page 1 of 8


SECTION 9

PROJECT IMPLEMENTATION AND SCHEDULE

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Rev B

Ch 9 Page 2 of 8


9.0 INTRODUCTION

The main purpose for realization of implementation strategy for Low Cost Debottlenecking of BORL, Bina Refinery Project is to define a natural approach to a sequence of planned events to allow the progress of the work to be achieved in the set time frame and within the planned budget. There are various modes of project implementation namely:

Conventional Mode of Execution (EPCM : Engineering, Procurement Contract Management)

Lump Sum Turnkey / Open Book Estimates (LSTK/OBE) Based on the merits and de-merits of the above mentioned mode of execution of the project. BORL shall review and finalise the mode of execution.

9.0.1. Engineering, Procurement Contract Management (EPCM) mode of Implementation In this mode of execution, Owner line up a CONSULTANT to perform the following activities and Owner has responsibility for placement of orders and contracts. Residual Process Design

Detailed Engineering

Contracts and Purchase

Inspection

Shipping

Construction Supervision

Commissioning Assistance

Overall Project Management and control

Advantages:

Minimal Investment Risk

Paralleling of activities with Front End Design for upstream Schedule advantages

Disadvantages:

Diffused responsibilities leading to high Schedule risk

Uninhibited Tendency to affect mid course changes

Extensive Owners Management set up

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Rev B

Ch 9 Page 3 of 8


9.0.2. Engineering, Procurement and Construction (EPC) mode of Implementation

In this mode of execution, there are two type of contract implementation philosophy:

Lump sum Turn Key (LSTK)

Open Book Estimate (OBE)

9.0.2.1 Lump Sum Turn Key (LSTK) / Open Book Estimate (OBE) mode of Implementation

In this mode of execution, OWNER engages a CONTRACTOR to implement the job on EPCM basis with fixed commitment on Project Schedule at an agreed fee /Cost. In case of LSTK contract, contractor has to complete work within agreed schedule and Cost. In case of OBE mode, the Contractual arrangement provides for the commitments to be made by contractor & shared with the owner transparently till an agreed commitment level of 65-70% of the target cost is achieved (at the point of time when majority of orders and contracts are awarded, while services cost quoted in lump sum and service fees as percentage at the time of bidding), however single Point responsibility lies with the Contractor to deliver the project as per agreed schedule. There may be option for conversion of the contract to LSTK mode after typically 65-70% of the commitment of the Target cost has been achieved.

Advantages:

Minimizes Contractor/client risks - Optimizes the Project Investment.

Enables start of Implementation from Process Package resulting in significant Schedule gains. No need of formal FEED.

Transparent working arrangement between Owner and Contractor.

Owner gets the combined benefits of EPC and EPCM under the ambit of PSU procedures for optimal cost and Fixed time frame advantage.

Option of Converting the OBE Contract to LSTK available with Owner based on a pre agreed arrangement.

Significant Cost advantage accrual out of minimisation of Financial risks of the Contractor.

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Rev B

Ch 9 Page 4 of 8


9.0.3. Comparison between Different modes of Implementation

The qualitative comparison between different modes of execution is tabulated below:

Table 9.1: Comparison between different modes of implementation

PARAMETER EPCM EPC (OBE/LSTK)

Overall Cost Low High Schedule Commitment Low High Owner’s Risk High Low Contractor Risk Low High Flexibility to Change High Low Contractual Issues & Change Orders Low High Owners Management team Resources High Low Quality of Produce Flexible Not Flexible

9.1 STIPULATIONS – PROPOSAL SCHEDULE FOR LOW COST EXPANSION OF 1.8 MMTPA OF BHARAT OMAN REFINERIES LIMITED (BORL)

General & Pre-shutdown related:

1. Zero Date of the Project is considered as award of Contract to EIL/ Go ahead from BORL.

2. Environmental clearance considered to be available on Zero date. 3. Effective start date of the Project shall be considered as availability of complete

process package (BEDP) from respective licensors for licensed units. 4. Final Process package inputs from licensor shall be made available by M/s BORL

within 5 months from agreement with Licensors so that effective start date could be maintained as indicated in the schedule

5. Mode of Project execution considered to be on EPCM. 6. Schedule has been Prepared considering capacity enhancement of following

areas based on adequacy check carried out by EIL: 9.1.1 Refinery Increase in Capacity (Modification including additional Equipment) :

o CDU/VDU- 30% o Integrated HCU and DHDT- 35%

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Rev B

Ch 9 Page 5 of 8


o DCU- 35% o LPG Amine Treating Unit, only tray replacement in LPG Amine Absorber

with new Amine settler drum. o LPG CFC Unit. o FG Amine Treating Unit. o Amine Regeneration Unit.

Increase in Capacity with major modification in Reformer: o HGU- 27%

Increase in SRU capacity: o Modifications in existing Sour water Stripping (SWS–I & II) with addition

of 2 nos. Sour water storage Tank- 34% o SRU New Train + Modification in existing 2 trains - 102%

Increase in MS Block : o Naphtha Hydrotreating Unit- 45% o Continues Catalytic Reforming Unit- 46% o Penex Unit- 81%

Utility & Offsite (Exact Capacity to be finalised based on licensors input) o 1 Cooling Tower (Cap: 4000 m3/ Hr. with 1 Pump Cap. 8000 m3/ Hr.) o Pre-treatment facility for Treated water before feeding to RO DM Plant o DM Water - 1 additional Bank and CPU - 1 Additional Chain o N2 Plant - 1 additional unit- 500 Nm3/ hr o Compressed Air system – 1 CF LP Air Compressor & 1 Dryer o Additional tank for CRWS and SWS. o Product Storage Tank – 8 Nos. and related product lines. o Flare system: No modification.

9.1.2 Outside Refinery Crude Pipeline – Addition of Pumps and DG at intermediate Pumping stations. COT – 4 Nos. with Fire water network. Betwa River Weir – Increase in wall height + additional pump.

7. For Electrical system, only modifications in existing Electrical panels & Sub-station

are considered to cater requirement of expansion. Requirement of New Sub-station and additional panels are not considered.

8. Post expansion, Power requirement will be drawn from Grid. Hence no addition or capacity expansion in Power Plant & Switchyard is considered.

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Rev B

Ch 9 Page 6 of 8


9. For modification in Recycle gas Compressor and Makeup Gas Compressor in HCU, Original Equipment Manufacturers (OEM) are to be ensured.

10. Modification in heater including supply or additional requirement shall be done by Heater Vendor.

11. Supply of DCS & erection shall be done by Original Equipment Manufacturer (OEM).

12. Procurement of Tank Plates and Structural Steel shall be kept under scope of respective contractors.

13. Graded site shall be made available on effective start date. 14. Piling work is not envisaged. 15. All civil work and major structural work shall be completed during pre-shutdown.

Foundation or major civil work is not considered during the shutdown. 16. All Piping Fabrication/ Spools for pre-shutdown and shutdown requirement shall be

carried out during pre-shutdown only. 17. All Instrument calibration shall be completed during pre-shutdown period only. 18. During pre-shutdown refinery work, round the clock permit is required with prior

intimation. 19. All work related to Crude Pipeline & work related to facility outside refinery is

considered as pre-shutdown activity. 20. Total work for New SRU Train shall be carried out as pre-shutdown activity by

isolating physical area by properly barricading from existing 2 trains. 21. Work related to pre- reformer and shift reactor (LT) in Hydrogen unit shall be

carried out during pre shut down by isolating area. 22. 2 agencies are considered for carrying out composite work for all unit areas.

Demarcation of work shall be done based on staggering of various units taking workload in to consideration.

23. Dispatch terminal and rail gantry related work shall be carried by BORL directly. 24. All statutory approvals for establishment of new facilities have been considered in

the scope of BORL.

Shutdown related: 25. Start date for shutdown is considered as permission to start hot work by BORL

after Refinery shut down. 26. Shutdown duration of 45 days considered is based on feedback/ assessment

received from M/s Technip KTI for HGU. 27. Shutdown related work in HGU shall be carried out through M/s Technip KTI. 28. All units are planned for shutdown at same time in the schedule. 29. Possibility of completing some of hook ups and tie-in during intermediate shutdown

as part of Plant Maintenance shall be discussed & finalized with BORL.

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Rev B

Ch 9 Page 7 of 8


30. No. of agencies for Mechanical/ Piping, Electrical/ Instrumentation and Insulation/ Painting work during shutdown shall be decided at later stage based on workload of Construction and hook ups based on detail Engineering.

9.3 OVERALL PROJECT IMPLEMENTATION SCHEDULE IS GIVEN IN BELOW

S.No Activity Schedule

1 Award of Contract to EIL Zero Date. 2 Discussions & agreement with

Licensor 1 Month from zero date.

3 Receipt of datasheet of critical/long lead equipment

3 months from zero date progressively.

4 Final Process package inputs from licensor

5 months from agreement with Licensors.

5 Process package from licensor 6 months from zero date progressively.

6 Effective Start date Receipt of Process package from Licensor.

7 Land free from encumbrance for new SRU and agreed plan for handing over of areas within various units of Refinery & Offsite area

On effective start date.

8 Basic Engineering for non-licensed units

Starting from zero date with a duration of 7 months.

9 Detailed Engineering Detailed Engineering for Procurement: To commence 2 months after receipt of critical equipment datasheet of licensed unit or 1 month after receipt of critical equipment datasheet of non-licensed unit with duration of 17 months excluding bal. Vendor Engg. Detailed Engineering for Construction:

To commence 1 month after receipt of input data of licensed unit or immediately after receipt of input data of non-licensed unit with duration of 23 months (17 months for Major engineering + 6 months for balance Vendor Engineering).

10 Procurement To commence 2 months after receipt of critical equipment datasheet of licensed

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Rev B

Ch 9 Page 8 of 8


S.No Activity Schedule unit or 1 month after receipt of critical equipment datasheet of non-licensed unit with duration of 25 months.

11 Tendering (incl. S/D related Contracts)

First tendering to commence in 3 month after effective start date with overall duration of 15 months to complete award of all balance tenders.

12 Construction Construction work/ mobilization of contractor at site to commence immediately after award of 1st tender with duration of 23 months to complete all construction activities incl.New train of SRU.

13 Mechanical Completion (Pre-shutdown Activities)

30 months from effective start date

14 Shutdown & Commissioning 45 Days as per assessment of M/s Technip KTI from shutdown granted by owner. Shutdown duration to start from permission of hot work by BORL.

15 Refinery Mechanical Completion

On completion of shutdown activities.

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PROPOSAL SCHEDULE - LOW COST EXPANSION OF BINA REFINERY (M/s BORL)REMARKS

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36

1. PROCESS INPUTS FROM LICENSOR

1.1 Environmental Clearance

1.2Discussion & agreement for modification with Licensors M/s ABB (for DCU), M/s CLG (for HCU/DHDT), M/s UOP (for NHT, CCR & Penex) & M/s KTI for HGU

1.3 Revised Eqpt. Data Sheets for Licensed unit (From Licensor)

1.4 Revised P&ID & Line List (From Licensor)

1.5 Instrumnet data sheets & Process Package (from Licensor)

2. BASIC/ RESIDUAL ENGINEERING

2.1 Revision of Plot Plan identifying areas for New facilities. S/D ACTIVITIES

2.2Revised/ New Equipment Data sheets for CDU & VDU, SRU & Other Non Licensed units

2.3 Issue of Revised P&ID's

2.4 Issue of Line List

2.5 Issue of Instrumentation Data Sheet

2.6 Updation of P&ID's based on Vendors data & Assistance to Engg.BALANCE VENDOR ENGG.

3. DETAILED ENGINEERING4. PROCUREMENT

4.1 Wet Gas Compressor for DCU (1 no.) 21 M Supply DELY. - 19 FOB+2 MONTHS

4.2Net Gas Compressor for MS Block (1 no.) & Blow Down Compressor for DCU (1 No.)

18 M DELY. - 18 MONTHS

4.3 Desalter Vessel with Trays for CDU/VDU (1 No.) 12-14 M DELY. - 12 to 14 MONTHS

4.4Modification Eqpt. for Recycle Gas Compressor & Make up Gas Compressor for HCU/DHDT (2 Nos.)

Discussion with Vendor 12 M DELY. - 12 MONTHS

4.5Pumps (CDU-12 Nos., VDU- 2 Nos.,DCU- 8 Nos., HCU/DHDT- 13 Nos. MS Block-2 Nos., LPG-4 Nos.,SRU-2, Offsite -3 Nos.=Total 46)

12 -16 M DELY. - 12 to 14 MONTHSHCU Pump- 16 Months

4.6Heat Exchangers (CDU-2 Nos., DCU-11 Nos., HCU-10 Nos., MS block-16 Nos. HGU-3 Nos, SRU-7 Nos. = Total 49 nos.)

10 -12 M DELY. - 10 to 12 MONTHS

4.7Air Coolers CDU-1 No., VDU-1 No., DCU-1 No., HCU/DHDT-5 Nos. MS Block- 6 nos., HGU-1 No.SRU-1 No.= Total 15 Nos.)


4.8 Feed Filter (Addl. Bank) for HCU/ DHDT (2 No.) 10 M DELY. - 10 MONTHS

4.9Column (VDU-1 Columns, LPG CFC -1 No., LPG Amine-1 No, Total-3 Nos.)


4.10 Column Trays/ Bed Modi. (27 Columns) 8 -10 M DELY. - 08 to 10 MONTHS

4.11Vessel/ Separators (DCU-1 No., HCU- 5 Nos., MS Block-1 No., HGU- 1 No., LPG-9 Nos., SRU-6 Nos., Total-23 Nos.)


4.12 Auxiliary Heater (MS block - 1 No.) 10 M DELY. - 10 MONTHS

4.13 Piping Material - Pipes/ Fittings/ Flanges (2 MTOs) DELY. - 06 to 10 MONTHSDELY. - 04 to 06 MONTHS

4.14 Piping Material - Valves (2 MTOs) DELY. - 08 to 12 MONTHSDELY. - 06 to 08 MONTHS

4.15 Electrical & Instrument items 6 -12 M DELY. - 06 to 12 MONTHS

4.16 DCS (Procurement & Installation) 10 -12 MDCS INSTALLATION

DELY. - 10 to 12 MONTHS

5. TENDERING5.1 Refinery

5.1.1 Pre shutdown Composite works (Refinery)

5.1.2 Pre shutdown Composite works (Offsite+New SRU Train)

5.1.3 Additional Tankage works (COT- 3 Nos.+ Product-8 Nos.)

5.1.4 Heater Modification works (Including supply)

5.1.5 Shutdown Composite works - Piping+Eqpt Erection

<<< - - - - - - MONTHS - - - - - ->>>S. N. Description

6-10 M

8-12 M4-6 M

6-8M

--

---

MECH. COMPLN Pre S/D

Activities

AWARD OF CONTRACT to EIL (Zero Date)

--

--

--

--

---

EFFECTIVE START DATE (PROCESS PKG. FROM

LICENSORS)

------ --

---

START OF SHUTDOWN

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PROPOSAL SCHEDULE - LOW COST EXPANSION OF BINA REFINERY (M/s BORL)REMARKS

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36<<< - - - - - - MONTHS - - - - - ->>>

S. N. Description

5.1.6 Shutdown - Electrical + Instrumentation

5.1.7 Shutdown - Insulation + Painting

5.2 Crude Receipt Pipe lines

5.2.1 Crude Pipeline & Booster station Composite works (Inclu. DG supply)

6. CONSTRUCTION6.1 PRE SHUTDOWN ACTIVITIES6.1.1 Refinery

Civil work/ Foundations incl. extension/ strengthening Total 20 Months duration

Structural Fabrication & Erection

Structural Modifications

Equipment erection S/D ACTIVITIES

Piping Prefabrication/ Spools (Pre S/D+ S/D Reqmt.)

Piping erection & Field Welding incl. Offsites requirements

Electrical Cable laying (if Required)

Instrument Calibration

Stock of Completed activities and Preparedness for Shut-down

Preparation for S/D related Contract activities6.1.2 SRU New Train + Offsite

Civil / Foundations & Structural work incl. extension/ strengthening Total 20 Months Duration

Equipment erection

Piping Fab./ Erection & Field Welding incl. Offsites requirements

Electrical & Instrumentation Work6.1.3 Tankage Work (COT+Product)

Construction of Tankages incl. procurement 16 Months

Tie in / Hook up & Commissioning6.1.4 Crude Receipt Pipe lines

Construction/ Revamping of Pump Station

Pump/ DG Foundations

Installation of Pumps/ DG & Piping Prefab+ piping erection

Tie-in with Crude line, Hookup & commissioning6.1.5 Cooling Tower (Addl. 1 No.)

Construction, Supply & Installation 15 Months

Hook up with Existing CT.6.1.6 DM Plant & CPU (1 Addl. Chain)


Hook up with Existing Plant6.1.7 N2 Plant & Compressed Air (1 Addl. Chain)


Hook up with Existing Plant

6.2 REFINERY SHUTDOWN

Cool down & HC cleaning by BORL

Shut down activity

Note: This schedule shall be read in ine with stipulations attached as Annexure-1.

Document No.

CLIENT M/s BHARAT OMAN REFINERIES LIMITEDA439-00-2744-P001Issued to Client with DFR

PURPOSE PREP CHKD APVD

PROJECT LOW COST EXPANSION (ADDL. CAPACITY 1.5 MMTPA)OF BINA REFINERY

C 17-Jan-14 Revised for description change & Reissued

PROPOSAL SCHEDULEB 11-Jan-14

:

:

10-Dec-13

REV DATE

A

Revised & Reissued

START OF SHUTDOWN

DELIVERY AT SITE COMPLETE

R

MILESTONE

MATERIAL REQUISITION

DELIVERY (FULL)

T TENDER READY AWARD OF WORK ACTIVITY

DELIVERY (PART) ISSUE LOI / FOA

MECH. COMPLN Pre S/D

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Project Cost Estimate DFR for Debottlenecking of






SECTION 10

PROJECT COST ESTIMATE

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10.0 PROJECT COST ESTIMATE

10.1 PROJECT COST Project cost estimate for the identified scope of works is Rs 2518.99 Crore. Validity of Cost estimate is as of 4th Qtr 2013 price basis. This Project cost estimate shall be read along with Key assumptions and Exclusions listed at Para 10.2 & 10.3

10.2 KEY ASSUMPTIONS

The basic assumptions made for working out the Project cost estimate are as under: Project Cost estimate is on conventional mode of execution. Cost estimate is valid as of 4th Qtr 2013 price basis. No provision has been made for any future escalation. No provision has been made for any exchange rate variation. Existing land is adequate for expansion project and no site development is

required. Piling is not required. Existing infrastructure facilities are adequate and no cost provision has

been made for the same. All costs are reflected in INR and all foreign costs have been converted into

equivalent INR using exchange rate of 1USD=Rs 61.0 Existing township is adequate and no cost provision has been made for the

same. 10.3 EXCLUSIONS

Following costs have been excluded from the Project cost estimate: Forward escalation Exchange rate variation Construction site facilities Working Capital Margin Interest During Construction

10.4 ESTIMATION METHODOLOGY

As indicated in para 10.3, the estimated Project cost for the identified scope and technical details, Project cost works out to be Rs 2518.99 crores including foreign component of Rs 522.23 crores New equipment / augmentations / modifications required in equipment of existing process units to achieve 7.8 MMTPA crude throughputs have been identified to

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firm up the scope of work. Cost estimate for these equipment / facilities are based on equipment lists / specifications provided by Process Department and in-house cost data base. Cost estimate for Utilities & Offsites including Tankages is based on information provided by Process department and in-house cost data base. Executed cost data base for Bina refinery project has been used to the extent possible using present exchange rate and economic indices. Suitable cost provision has been made for Piping, Electricals and Instrumentation items. Cost provision has been made for construction cost on factor basis. Applicable duties and taxes have been added. Cost estimate for new equipment & facilities is based on equipment list and technical specifications developed for this project and cost estimate is based on in-house cost data base. Cost of Proprietary items in MS Block, HGU & LPG CFC have been considered based on the information provided by the Licensors. Cost estimation for one new train of Sulphur recovery unit is based on analogous reference for similar type of unit executed and cost has been updated to present date price level considering conventional mode of execution. Cost provision has been made for Oxygen Enrichment Facilities also. Cost is considered for 30% capacity enhancement of ATF Merox Unit. Based on available preliminary technical information, above assumptions & exclusions and methodology adopted for cost estimation, it is targeted to achieve an overall accuracy of these estimates at ± 20%.

10.4.1 Modification / Replacement / Additional Items for Expansion Project

CDU/VDU unit Column Internals, Vessels, Desalter Vessels & Internals, Pumps, Exchangers, Air coolers, Heater Tubes, Vacuum Ejector System.

HCU/ DHDT unit Column Internals, Vessels, Heat Exchangers, Heater tubes, Pumps, PRTS, Recycle gas Compressor, Air coolers, Feed Filter, Separators.

DCU unit . Column Internals, Vessels, Heater tubes, Exchangers, Air coolers, Pumps, Wet Gas Compressor & Ring Compressor.

MS Block Units NHT- Column Internals, Vessels, Exchangers, Air coolers, Pumps, New Auxiliary Heater. CCR- Exchangers, Air coolers, Net Gas Compressor, Burners PENEX- Column Internals, Vessels, Exchangers, Air coolers, Pumps, Hot Oil Heater, Refrigeration Package,Reactors.

HGU Pre-Reformer, Technip Parallel Reformer (TPR), PSA, Reformer Tubes.

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SRU One additional sulphur train, O2 enrichment facilities.

ARU & SWS-I & II Tanks, Vessels, Pumps, Exchangers.

LPGCFC Column, CFC Contactors & Separators, Pumps.

Utilities & Offsites Crude & Intermediate Tanks, Offsite Pumps, Raw Water Pump, Cooling Tower and Cooling Water Pump, additional nitrogen chain, LP Compressor, additional bank in RO-DM, additional CPU Train, Oil Removal facility, CRWS Tank.

COT & BDT facilities Additional crude tanks, Pumps and associated bulk items.

Pipelines Additional Booster Pumps & Modification in existing pumps

10.4.2 Catalysts & Chemicals Cost provision for first fill of catalysts required is based on available information of quantities and cost.

10.4.3 Indirect Costs, Exchange Rates The cost estimate is based on following Exchange Rates & Indirect costs:

Exchange Rate 1 US$=Rs 61.0 Ocean Freight 5.0% of FOB cost of imported equipment Port Handling 2.0% of FOB cost of imported equipment Inland freight 5% of FOB cost of imported equipment and ex-

works cost of indigenously sourced equipment Insurance 1% of Plant & machinery cost

Provision for ocean freight is for supplies by marine transportation / ships only. No provision has been kept for any special transportation means such as Air freighting or usages of barges.

10.4.4 Statutory Taxes and Duties

Provision for statutory taxes & duties has been made as under: Custom Duty 25.85% of CIF cost of imported equipment

(7.5% Basic Customs Duty + 12.36% CVD+ 3% Education Cess and 4% SAD).

Excise Duty 12.36% of ex-works cost of indigenously sourced equipment.

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Central Sales Tax Applicable rate for CST is 4.1% VAT on Works Contract 12.5% on Contract Service Tax on Engineering and Works Contract

12.36% ( 12% Service Tax + 3% Education Cess) on Engg; 4.94% on contract

State Entry Tax 1% on Supplies 10.4.5 Land and Site development

Existing land is adequate for expansion project and no cost provision has been made for land & site development.

10.4.6 Royalty, Know-How, Process Design / Basic Engineering Fees

Cost provision for Royalty, Know-how, Process Design, Licensor’s expatriate and Basic Engineering has been made based on available information. Cost includes provision for withholding tax and service tax.

10.4.7 Project Management, Detailed Engineering, Procurement Services &

Construction Supervision Cost provision has been made towards the EPCM services for the project based on in-house information. Service tax has been considered @ 12.36%.

10.4.8 Pipeline

Cost provision for Pipeline has been made as per available inputs.

10.4.9 COT & BDT Cost provision for COT & BDT has been made based on information provided by the Process department.

10.4.10 Roads & Buildings

No new Road & Building has been envisaged for the project and no cost provision has been kept in the Project cost.

10.4.11 Effluent Treatment Plant Two new Tanks & Two new Pumps have been considered for ETP modification. Cost for the same has been included under Utilities & Offsites cost.

10.4.12 Infrastructure facilities It has been assumed that existing infrastructure facilities shall meet the requirement of expansion project and no cost provision has been made under this head.

10.4.13 Construction Site Facilities Existing construction site facilities such as construction power, construction water,

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construction equipment, ware house etc. shall be used and no cost provision has been made.

10.4.14 Township Existing township shall meet the requirement of expansion project.

10.4.15 Owners Construction Period Expense

Cost provision for owner’s construction period expenses has been made on factor basis of Plant and machinery cost for items such as project management, salaries & wages, vehicles hire / rentals / maintenance, stationary, travel etc. during project construction period.

10.4.16 Start-up & Commissioning

Cost provision has been made for chemicals & consumables, vendor servicemen, technicians & operators required during start-up and commissioning period as factor of plant and machinery cost.

10.4.17 Contingency

Cost provision for contingency has been made @ 10% of capital cost excluding interest during construction. This provision has been kept to take care of inadequacies in estimate basis definitions (including design and execution) and inadequacies in estimating methods and data elements.

10.4.18 Working Capital Margin

No cost provision has been made for additional Working Capital.

10.4.19 Interest during construction(IDC) No cost provision has been made for IDC.

Based on the above assumptions and exclusions, Project cost estimate with details for the project is enclosed as Annexure-I. Process unit cost summary for all the units is also enclosed as Annexure II.

10.5 ATTACHMENTS

1. Project cost summary (sht-1) Annexure 10.1 2. Unit Cost Summary (Process Units) Annexure 10.2 Total shts: 11

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