feasibility report of j-18...

FEASIBILITY REPORT OF J-18 PROJECT

REVISED DRAFT FEASIBILITY REPORT

FOR

CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO

FUEL PRODUCTION FOR IOCL GUJARAT REFINERY

INDIAN OIL CORPORATION LIMITED GUJARAT REFINERY

JULY -2017


FOR

CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS VI AUTO FUEL

PRODUCTION

CLIENT INDIAN OIL CORPORATION LIMITED

GUJARAT REFINERY

PREPARED BY ENGINEERS INDIA LIMITED

NEW DELHI

EIL JOB No.: A510

REPORT No. A510-RP-7941-0004 VOLUME 1 OF 1

JULY 2017

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

Document No. A510-RP-7941-0004

Rev. No. A Page 2 of 284

FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO FUEL

PRODUC TION FOR IOCL GUJARAT REFINERY

COPYRIGHT

This document is copyright protected by EIL and is produced for the client M/S IOCL. 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 (Process-2) Tower-II, 5th Floor Engineers India Limited Complex Sector-16 Gurgaon- 122001 Haryana (India) Telephone: 0124-380-3701 EIL reserves the right to initiate appropriate legal action against any unauthorized use of its Intellectual Property by any entity.



Rev. No. A

REVISED D RAFT FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0

MMTPA WITH 100% BS-VI A UTO FUEL PRODUC TION

FOR IOCL GUJARAT REFINERY

TABLE OF CONTENTS

SECTION CONTENT

1. EXECUTIVE SUMMARY 4 2. INTRODUCTION 22 3. SCOPE 25

4. DESIGN BASIS 27 5. MARKET STUDY 155

6. PROJECT LOCATION 157 7. PROJECT DESCRIPTION 160

7.1 PROJECT CONFIGURATION 161 7.2 REFINERY CONFIGURATION STUDY 170

7.3 PROCESS DESCRIPTION 200 7.4 UTILITIES DESCRIPTION 219

7.5 OFFSITES DESCRIPTION 228 7.6 FLARE SYSTEM DESCRIPTION 232

8. ENVIRONMENTAL CONSDIERATION 236 9. PROJECT IMPLEMENTATION AND SCHEDULE 257

10. PROJECT COST ESTIMATE 268 11. HEALTH SAFETY & ENVIRONMENT 280 12. CONCLUSION & RECOMMENDATIONS 283

ANNEXURES

I CRUDE ASSAYS II BLOCK FLOW DIAGRAMS

III SCHEMATIC DIAGRAMS IV PLOT PLAN



Rev. No. A

REVISED D RAFT FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO FUEL


SECTION 1.0

EXECUTIVE SUMMARY






EXECUTIVE SUMMARY

1.1 Introduction

Indian Oil Corporation Limited (IOCL) operates one of its largest oil refineries at Koyali (near Vadodara) in Gujarat, Western India. The refinery was commissioned in the year 1965 with a nameplate capacity of 3.0 MMTPA. Over the years, the capacity of the refinery has gradually been increased to 13.7 MMTPA with augmentation of old primary Atmospheric Units (AU-I, AU-II and AU-III) and addition of new primary units viz. Atmospheric Unit-IV in 1978 and AU-V in 1999 as well as augmentation of AU-IV in 2000.

Secondary processing facilities viz. Fluidized Catalytic Cracking Unit (FCCU) and Hydro-cracking Unit (HCU) were added in the years 1982 and 1993 respectively to improve the distillate yield. Diesel Hydro-desulphurization Unit (DHDS) and Hydrogen Generation Unit (HGU) were added in 1999 to meet BS-2000/BS-II quality of HSD. MS Quality Improvement Project comprising of Continuous Catalytic Reforming Unit (CCRU) and revamp of DHDS were carried out in the years 2006 and 2007 respectively to meet BS-II/BS-III MS and HSD quality respectively.

Further, under the Residue Up gradation Project (RUP) and MS/HSD quality improvement Project Delayed Coking Unit (DCU), Vacuum Gas oil Hydro-Treater Unit (VGO-HDT), Diesel Hydrotreater Unit (DHDT), Hydrogen Generation Unit-III (HGU-III), Sulphur Recovery Unit (SRU), Isomerization Unit (ISOM), ATF & LPG Merox units were commissioned in 2010-11.

At present, Gujarat Refinery has capacity to process 13.7 MMTPA of crude oil, with crude basket comprising of 55% high sulphur crude (7.6 MMTPA) and 45% low sulphur indigenous crude (6.1 MMTPA).In addition to BS-III/BS-IV fuel products, the refinery also has the capability to produce a wide range of specialty products such as benzene, toluene, MTBE, MTO, Food Grade Hexane & LAB. Currently refinery is executing projects to upgrade the entire gasoline and diesel to BS-IV specification by revamp of existing DHDT, DHDS and VGO hydrotreater units.

Further, with objective of meeting the guidelines established in Auto Fuel Policy 2025, wherein refinery would be required to manufacture 100% BS-VI fuels, IOCL is also executing BS VI project under which a new DHDT unit, a FCC Gasoline Desulphurization unit and a new HGU are envisaged.

M/s IOCL is now considering increasing the processing capacity of the refinery from current 13.7 MMTPA to 18.0 MMTPA. M/s EIL had carried out the job of configuration study and had prepared a feasibility report for capacity expansion of Gujarat refinery from 13.7 to 18.0 MMTPA as entrusted by M/s IOCL. The report was issued to IOCL on July 2013. This configuration study however had envisaged production of BS-III/IV auto fuels from the refinery with incremental HSD production complying to BS IV auto fuel specification (no incremental motor spirit production was envisaged). However in view of Auto Fuel Policy 2025 by MOP& NG, M/s IOCL intended to update the study carried out in 2013 with additional facilities required for meeting 100% BS VI auto fuel production. Accordingly another Feasibility Report for capacity expansion of IOCL Gujarat refinery from 13.7 to 18.0 MMTPA has been submitted to IOCL during Aug-






2016 by M/s EIL. This report was prepared considering a new HCU and SDA as addit ional processing units (as recommended by FR prepared during July-2013), crude/product prices as provided by IOCL and BS VI product quality for gasoline and diesel. But the IRR arrived for this option was lower than the hurdle values due to current price scenarios and revised base case. IOCL has now assigned EIL, the job to carry out a revised configuration study and preparation of feasibility report with a cost estimate of +30% for capacity expansion of Gujarat refinery from 13.7 to 18.0 MMTPA by exploring alternate configuration options. This report documents the results of the study.

1.2 Objectives

The major objectives of the capacity expansion project are to:

Study alternate refinery configuration for enhanced refining capacity of 18.0 MMTPA in order to have an attractive IRR.

Entire MS and Diesel produced in refinery should meet BS VI specif ications.

Minimize the production of naphtha product from refinery.

Zero kerosene sales.

Maximum utilization of existing facilities.

Dismantling of smaller atmospheric and vacuum units like AU I, AU II, AU III, AU IV, FPU I and VDU by considering a more efficient AVU of 15.0 MMTPA.

Estimate addit ional utilit ies requirement for selected option.

Limit total SOx emission from the entire complex post expansion at the present allowable limit.

Zero Fuel Oil sales.

Cost estimate with an accuracy of ± 30%.

Avg. price of 2014-17 of feed and product to be considered.

1.3 Basis of Study

1.3.1 Refinery Throughput 18 MMTPA

1.3.2 Crude Mix The study has been carried out for the following crude mix for expansion case and base case, considering additional crude processed as high sulphur crude.






Table 1.3.1: Crude Mix

Sl. No

Crude Name Base Case- KTPA

Expansion Case- KTPA

1 North Gujarat crude 3700 3700

2 South Gujarat crude 1700 1700

3 Mangla crude 800 800

4 Kuwait crude 7600 7500

5 Basra Crude 0 4300 Total Crude 13700 18000

1.3.3 Crude Assay The crude assays utilized for the study are attached in Annexure 1.

1.3.4 Refinery On-Stream Hours 8000 hrs/annum.

1.3.5 Feed and Product P rices The feed and product prices considered for the study is provided below in table 1.3.2A & B. The prices are based on average prices during FY 2014-17.

Table 1.3.2A Feed Prices (Rs/MT)

Crude 3 Year Avg. price (FY 2014-17)

North Gujarat (NG) 26637 South Gujarat (SG) 31086 Rajasthan Crude 24926 Basrah Lt crude 26625 Kuwait 27067 LNG/RLNG 31770 Methanol 24248 Benzene 38628

The cost of imported grid power is 8.32 Rs/ Kwhr.

Table 1.3.2B Product Prices (Rs/MT)

Product 3 Year Avg. price

(FY 2014-17)

LPG 32972






Product 3 Year Avg. price

(FY 2014-17)

Propylene 46608 Polypropylene 82459 Naphtha Export 32287 PNCP Naphtha 32287 Food Grade Hexane 57562

MS BS-VI (Normal grade)- Domestic 42659

MS BS-VI (Normal grade)-Export 40992

MS BS-VI (Premium grade grade) 42659

HY. REFORMATE TO IOCL GR 34117

MTO 48493

SKO 36962 PCK 36376 ATF 36714 LAB 87103 HSD BS-VI 36376 LAB Hy alkylate 56230 FO sales 22478 Bitumen VG-10 21107 Bitumen VG-30 23558

HS Coke 4108 Sulphur 7977

1.3.6 P roduct Specifications The total diesel and gasoline fuels produced from refinery after implementation of the project shall conform to BS-VI specifications. The major specifications of products shall be:

LPG-RVP 1050 KPA

Regular grade BS-VI Gasoline ( 91 RON)*-10 ppmw sulphur**

Premium grade BS-VI Gasoline (95 RON)*** - 10 ppmw sulphur**

Diesel BS-VI -10 ppmw Sulfur**






* Manufacturing spec. of 91.2 has been considered for BS-VI Gasoline.

** Manufacturing spec. of 8 ppm has been considered for both gasoline and Diesel.

*** Manufacturing spec. of 95.5 has been considered for Premium grade Gasoline.

1.3.7 Production Limits The limits on various products have been considered as per Table 1.3.3 below:

Table 1.3.3: Production Limits (KTPA)

Product Maximum Quantity

(KTPA) Fixed Quantity

(KTPA)

Naphtha Shall be minimized -

PNCP Naphtha 0 BS VI MS (Normal grade)-Domestic 2200

BS VI MS (Normal grade)-Export (As produced)

BS VI MS (Premium grade)- 462

SKO 0

ATF 650 -

MTO 120

LDO Nil -

Bitumen 480 - Fuel Oil Sales 0 -

1.3.8 Other Constr aints &Considerat ions

The base case for this study has been considered as BS-VI products at 13.7 MMTPA capacity which incorporates following facilities in the existing refinery configuration:

a. Facilities to meet BS-IV specif ications include the revamp of existing DHDT, DHDS and VGO hydrotreater units.

b. Facilities to meet BS-VI specif ications include new units of DHDT, FCCG-HDS and HGU along with the revamp of existing MS Block wherein 30% revamp of existing CCR and 20 % revamp of ISOM unit has been considered.

A new AVU of 15.0 MMTPA has been considered after dismantling AU-I and AU- II, AU III, AU IV, VDU & FPU I creating additional Crude processing capacity of 4.3 MMTPA to maximize operational eff iciency.






The existing CRU has been considered as not operational and the heavy naphtha feed to CRU shall be processed in new MS block

To improve the operating efficiency, the old HGU I unit shall be considered as not operating if balance capacity is available in BS VI HGU to meet the hydrogen demand Zero Fuel Oil sales have been considered.

The addit ional Power requirement for expansion over the available capacity of 135 MW from existing refinery shall be met by import from grid.

Plant Fuel System

RLNG has been considered as fuel for the following facilities in the 100% BS-VI configuration.

a. + HRSG.

b. Feed/Fuel to existing HGU-III, BS VI HGU

Internally generated Fuel Oil (Sul<0.5 wt %) and fuel gas have been considered as fuel for refinery furnaces along with natural gas.

1.4 Refinery Configuration Options

Based on the above considerations, a comprehensive LP model was developed to analyze the various configuration options agreed in the design basis for the refinery expansion to 18.0 MMTPA. Since the result of draft FR issued during Aug-2016(wherein diesel maximization was considered) showed poor IRR value (as diesel price is much lower compared to gasoline price), emphasis has been given to production of higher price petrochemical product/feedstock and gasoline fuel. A total of five configuration options were studied in detail covering total persona of various secondary processing options, alternate option for bottom processing, and production of petrochemical product.

1.4.1 Primary Processing Units . A new CDU/VDU of 15.0 MMTPA capacity has been considered after

dismantling of AU I, AU II, AU III, AU IV, FPU I & VDU and by creating an addit ional capacity of 4.3 MMTPA. The dismantling of existing AUs, FPU I and VDU has been considered to replace old small units with a new higher capacity unit to increase the efficiency and ease of operation. Existing AU V (Design capacity: 3.0 MMTPA) and FPU II units have been retained.

1.4.2 Secondary Processing Unit In the report submitted in Aug-2016, wherein HCU along with SDA was the configuration considered which resulted in poor IRR because of high diesel production, which is not so favorably priced. Considering that gasoline and petrochemical feedstock fetches a higher price secondary processing option have been considered with FCC and INDMAX units producing higher yield of gasoline and petrochemical feedstock like






propylene. Additionally, MS block units have been considered in all cases to upgrade naphtha (from expansion and existing which is being exported) to gasoline.

Based on the above following secondary processing options have been considered.

Low CCR INDMAX FCC unit (INDMAX with VGO feed ) High CCR INDMAX FCC unit (INDMAX with VGO+VR feed) to handle

addit ional VR Conventional FCCU

1.4.3 Bot tom P rocessing Unit The result of the FR issued during Aug-2016 shows that SDA-DCU combination option to process the additional VR generated does not fetch much uplift in the economics, robust technologies like an Ebullated hydrocracker unit (EB HCU) with a conversion upto 75% into distillates is considered for bottom up gradation. The DCU capacity is considered to be saturated in all the cases analyzed for utilizing existing unit capacity fully.

1.4.4 Treating Units Gasoline -Gasoline treatment unit shall be considered as required to treat INMDAX FCC gasoline to meet the BS VI specif ication.

Diesel/Kero -Diesel or kerosene treating units shall be considered as required. Revamp of BS VI DHDT may be considered for treating addit ional diesel produced.

1.4.5 Polymer Units A Polypropylene unit is considered as an additional case to polymerize propylene available from INDMAX FCC unit to improve the sales revenue.

1.4.6 Auxiliary Unit Hydrogen Generation Unit As suff icient quantity of hydrogen generation is expected from new CCRU and due to balance capacity available in BS VI HGU, a new HGU unit is not considered.

Sulphur Block Additional sour water and sour gas generation due to high sulphur crude under expansion project warrant incremental sulphur removal which shall be met by new sulphur block units.

In view of above considerations following 5 different configuration options have been analyzed targeting a higher IRR.






Table 1.4.1 Configuration Options Analyzed

Sl. No Case Description (Note 1)

1. Base case + Low CCR INDMAX FCC+ PPU+ Ebulated Bed HCU 2. Base case+ High CCR INDMAX FCC+ PPU (Note-2)

3. Base case+ Low CCR INDMAX FCC+ Propylene sales+ Ebulated Bed HCU

4. Base case+ High CCR INDMAX FCC+ Propylene sales (Note-2) 5. Base case+ Conventional FCCU+ Ebulated Bed HCU

Notes:

1. It may be noted that the requirement of treating and auxiliary units are equally applicable to all options.

2. Preliminary analysis shows that the requirement of a bottom up

gradation facility can be ruled out in case of High CCR INDMAX FCC consideration and by utilization of DCU at full capacity on VR feed.

1.5 Shortlisting of Configuration

The summary table indicating GRM, Preliminary Capex estimate and Preliminary IRR estimate for various configuration options is presented in Table 1.5.1 below.

Table 1.5.1: Configuration Option results

CONFIG. OPTIONS

CASE 1- EB HCU+

LOW CCR

INDMAX+ PPU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB HCU+ LOW CCR INDMAX+

PROPYLENE SALES

CASE 4-HIGH CCR INDMAX+

PROPYLENE SALES

CASE 5- EB HCU+

FCCU

GRM

(US $/barrel) 12 12.3 10.7 10.8 10.6

Preliminary Capex estimate

(Rs crore) 15540 14850 13970 13120 12810

Preliminary IRR estimate (Post Tax On Capex)

16% 17.5% 13.5% 14.7% 14.3%






1.5.1 Observations

Based on the above summary, preliminary analysis indicates that for options with Polypropylene production (Case 1 & 2) GRM is much higher as compared to other cases and bring better return on investment. However case 1 with low CCR INDMAX results in an additional bottom processing facility (Ebullated bed HCU), result ing a much higher Capex than case 1. At the same time the capacity of this facility is below the economic threshold capacity of EB HCU. Therefore higher investment in case 1 with approximately same GRM results in poor IRR as compared to case 2.

1.5.2 Conclusion Based on the results presented in sections above, configuration option with High CCR INDMAX and PPU emerges as the most optimum configuration within the ambit of various constraints considered . Hence this option is recommended to be taken for further analysis for Capex estimation of +30% accuracy along with IRR.

1.6 Selected configuration overview

A detailed Feasibility for the selected option i.e. High CCR INDMAX +PPU has been carried out and results are presented as follows.

1.6.1 New Unit capacities and Revamp of Existing units The capacities of new units envisaged for selected option scenario with revamp of existing units have been provided in the table 1.9.1 below.

Table 1.6.1: New Unit capacities & Revamp of existing units

UNIT CAPACITY IN KTPA-SELECTED CASE

NEW CDU/VDU 15000

HIGH CCR INDMAX (WITH PRU, LPG

TREATMENT & FGD) 2400

PPU 400

GDSU 650

NHT/NSU 2050

CCRU 1600

ISOM UNIT 925






UNIT CAPACITY IN KTPA-SELECTED CASE

KHDS 850

SRU- TPD 300

SWS-TPH 330

ARU-M3/HR 300

REVAMP UNITS

BS VI GDSU

Revamp for processing feed

with sulhur spec higher than design feed (Quality Revamp)

1.6.2 Feed and Product slate The feed and product slate for High CCR INDMAX with PPU scenario along with base case condition has been provided in the table below.

Table 1.6.2: Selected case Material Balance FEED/

PRODUCT BASE CASE (100%

BS VI at 13.7) SELECTED

CASE

FEED

NORTH GUJARAT 3700 3700

SOUTH GUJARAT 1700 1700

MANGALA 800 800

KUWAIT 7500 7500

BASRAH LT. 0 4300

RLNG 614 774

METHANOL 11 11

BENZENE 18 18

TOTAL 14343 18803

UTILITY PURCHASE






FEED/ PRODUCT

BASE CASE (100% BS VI at 13.7)

SELECTED CASE

IMPORT POWER IN MW

0 63

PRODUCT SALES

LPG 500 1045

POLYPROPYLENE 0 402

NAPHTHA EXPORT 986 0

LAB 120 120

FGH 14 14

BS VI GASOLINE (NORMAL GRADE)-

DOMESTIC

1398 1738

BS VI GASOLINE (PREMIUM GRADE)

462 462


EXPORT

0 2527

HY REFORMATE TO IOCL GR

60 0

SKO 500 0

MTO 0 120

ATF 400 650

PCK 70 140

BS VI HSD 6804 8013

SULPHUR 102 200

BITUMEN 430 480

FO SALES 408 0

COKE 663 993

LAB HY. ALKYLATE 0 8






FEED/ PRODUCT


SELECTED CASE

TOTAL 12918 16913

FUEL & LOSS 10.40% 10.50%

1.7 Block Flow Diagrams

The block f low diagram (A510-79-41-00-0141) indicating the integration of the new process units into the existing refienry is attached in Annexure II to the report.

1.8 Utility Systems

Following new Utility systems shall be implemented along with the new process units. These are after considering integration & centralization with existing utility system in consultation with IOCL.

Table 1.8.1: New Utility systems

New Utility System Description

Raw water system The additional raw water requirement shall be met by a new bore well of 11 MGD capacity.

Recirculating Cooling water

A new cooling tower system with 4W +1S cells of capacity4000 m3/hr, 2w+1s pumps of capacity 9000m3/hr in place of Abandoned cooling tower, to cater to new AVU. A new cooling tower system with 8W +1S cells of capacity 4000 m3/hr,4w+1s pumps of capacity 9000m3/hr in the New Bajwa land, to cater to INDMAX FCC, FCC GDS, PPU & new MS block. Augmentation of South block cooling towers by addition of one cell and pump to cater to KHDS and new sulphur block.

DM Water

A new RO based DM water plant of total capacity 550m3/hrwith three trains, each of capacity 275m3/hr (2W+1S), in integration with new ETP is envisaged.

Steam Two new Boiler of capacity 150 TPH is envisaged. No standby boiler considered in place of unutilized boilers.

Power Additional requirement of 63 MW shall be met from existing import facil ity.







Condensate handling A new Condensate Polishing Unit with a capacity of 415 TPH (1W+1S) is envisaged.

Internal Fuel Oil and Fuel gas Additional fuel gas requirement shall be met from fuel gas generation from new process units and balance shall be met by RLNG

Compressed Air System A new compressed air system with a total capacity of 16400 Nm3/hr. 2w+1s compressor of 8200 Nm3/hr capacity envisaged.

Nitrogen A new Nitrogen plant of capacity 5000 Nm3/hr with l iquid N2 storage of 500 m3 is envisaged.

1.9 Offsite System

The offsite facilit ies of the refinery shall be augmented by adding following new storage tank and pump.

Table 1.9.1: New storage tanks

Sl. No Service No of

Tanks Type Liquid stored

capacity of each tank (KL)

1 MTO product 1 InternalFloating

Roof 5000

2 NHT feed tank 2 Internal Floating

Roof 12,000

3 KHDS Feed tank 2 InternalFloating

Roof 5,000

4 LPG Mounded Bullet 6 Mounded

3500

5 Propylene Mounded bullet 3 Mounded

3500

Table 1.9.2: New pumps

Sl. No Service No of

pumps Flow

(m3/hr) Type

1 MTO product Transfer Pumps 1W+1S 350 Centrifugal

Motor driven

2 NHT feed Pumps 2W+1S 200 Centrifugal Motor driven

3 KHDS feed Pumps 1W+1S 135 Centrifugal Motor driven

4 PPU feed Pump 2W+1S 50 Centrifugal Motor driven






1.10 Flare System

A new hydrocarbon f lare system is envisaged as a part of this project in place of existing new flare as advised by IOCL. This f lare will be catering loads only from new AVU, INDMAX-FCC, MS Block, FCC-GDS, KHDS and offsite Bullets. The flare system with 90flare header and main flare KOD has been considered.

New acid flare shall be required for handling sour gases. Sour gases to be

gases after KOD shall be routed to stack in a dedicated burning tip.

1.11 Effluent Treatment Plant

A new integrated ETP of feed capacity 385 m3/hr. has been considered for handling the additional waste generated post expansion. A full-fledged state of the art Reverse Osmosis (RO) based DM Plant is integrated with ETP, to maximize recycle of waste streams and minimize water consumption. 1.12 Roads and Buildings

Consideration of new roads and building has been made as per the input provided by M/s IOCL, additional considerations for roads and buildings such as control rooms, substations etc. has been made based on the preliminary MTO provided by in-house engineering. 1.13 Land Requirement

All the facilities proposed under this project shall be located in the existing plot as well as in in new lands under acquisition by IOCL. Additional Y2 plot and Bajwa land to be procured for this Project. The unit wise plot area required for the new facilit ies is indicated in table 1.11 shown below.

Table 1.13.1: Process Unit Plot Dimensions

Units Plot Dimensions,

M 2

NEW AVU WITH LPG/ATF TREATMENT 43200

INDMAX FCC WITH PRU, GDSU & LPAG TREATMENT 44550

MS BLOCK UNITS 29000

KHDS 5000






PPU 23400

SRU INCLUDING TGTU, SWS & ARU 15000

Refer plot plan attached as Annexure IV to this report showing location of new units.

1.14 Manpower Requirement

With the implementation of the expansion project, the complexity of the existing refinery will increase. Therefore, to strengthen the organization, it is recommended to have manning levels to reflect an effective operations and maintenance that would be required to support the normal operation of the refinery. For this IOCL envisages additional manpower strength of around 334 persons in various categories.

1.15 Capital Cost

The cost of the project has been calculated based on the unit capacities. The project cost estimates for Refinery expansion project includes the following:

Cost of New units & revamp of existing units Cost of New Utility Systems Cost of new Offsite facilities ( Storage tank and Piping) Enabling Cost: For installation of several new Process units several old

units/facilities needs to be dismantled or relocated. List of enabling job has been considered based on IOCL input and Plot Plan finalization.

Cost estimates are based on accuracy of +30% and is valid upto third quarter of 2016.

The project cost is based on the execution on conventional mode.

1.16 Financial Parameters:

Based on capital cost, operating cost and sales revenue, financial analysis have been carried out for calculating Internal Rate of Return (IRR) and other financial parameters. The parameters considered for performing financial analysis is tabulated below. Financial study has been considered based on incremental raw material cost and incremental revenue of BS VI at 18.0 MMTPA over BS VI at 13.7 MMTPA.

Table 1.16.1: Financial Parameters Sl.No Financial Parameter Values Considered

1 Construction Period 42 months 2 Project Life 15 years 3 Debt / Equity Ratio 1 : 1 4 Expenditure Pattern Equity concurrent to Debt 5 Loan Repayment period After moratorium period in 8 years






6 Moratorium Period 2 Years 7 Interest on Long Term Debt 9.35% 8 Capital Phasing (Total Capital) 1 Year 10.0% 2 Year 35.0% 3 Year 45.0% 4 Year 10.0%

9 Capacity Build up 1st year 60% 2nd year 90% 3rd Year onwards 100%

10 Corporate Tax Rate @ 30%+ 12.0% surcharge+ 3% Education cess

11 MAT @ 18.5 %+ 12.0% surcharge+ 3% Education cess

1.17 Financial Results

Financial results are given below

Table 1.17.1: Financial Parameters S.No Item Selected Case

1 Capital Cost 15075 35

2 Variable Operating Cost 12196 51

3 Fixed Operating Cost 232 84

4 Total Operating Cost 12429 34

5 Sales Revenue 17325 26

6 IRR on Total Capital

Pre-Tax 20.48%

Post-Tax 16.20%

7 IRR on Equity

Pre-Tax 26.50%

Post-Tax 20.34%

1.18 Conclusion

IOCL intends to enhance the crude processing capacity of its Gujarat Refinery from present 13.7 MMTPA to 18.0 MMTPA with the consideration of production of 100% BS VI quality gasoline and diesel products from the refinery. The feasibility study of the expansion project has been carried out for processing of addit ional Basrah Lt Crude. Following new facilit ies are required to increase the existing refinery capacity from 13.7 to 18.0 MMTPA with the objective to produce BS VI quality products.






New AVU with LPG/ATF treating Unit New INDMAX Unit including PRU and LPG treatment unit New Polypropylene Unit New MS Block including NHT/CCR/ISOM units New Gasoline Desulphurization Unit New KHDS Unit New Sulphur Recovery Unit along with TGTU New Sour Water Stripping Units ( Single/Two Stage) New Amine Regeneration Unit Associated Utility facility and offsite facilities

The addit ion of these facilities along with expansion from 13.7 to 18.0 MMTPA results in enhancement of GRM of the refinery. The Capex required for expansion is estimated to be 15075 Cr with +30% accuracy, which gives a very attractive post tax IRR of 16.2% on total capital. The resulting configuration enhances the refinery capability to produce more diesel and gasoline along with petrochemical production. At the same time long term objectives of zero fuel oil, zero kerosene and minimization of naphtha is achieved. Therefore expansion of refinery form current capacity of 13.7 to 18.0 MMTPA is highly recommended.



Rev. No. A

REVISED D RAFT FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO


SECTION 2.0

INTRODUCTION






2.0 INTRODUCTION

Indian Oil Corporation Limited (IOCL) operates one of its largest oil refineries at Koyali (near Vadodara) in Gujarat, Western India. The refinery was commissioned in the year 1965 with a nameplate capacity of 3.0 MMTPA. Over the years, the capacity of the refinery has gradually been increased to 13.7 MMTPA with augmentation of old primary Atmospheric Units (AU-I, AU-II and AU-III) and addition of new primary units viz. Atmospheric Unit-IV in 1978 and AU-V in 1999 as well as augmentation of AU-IV in 2000. Secondary processing facilities viz. Fluidized Catalytic Cracking Unit (FCCU) and Hydro-cracking Unit (HCU) were added in the years 1982 and 1993 respectively to improve the distillate yield. Diesel Hydro-desulphurization Unit (DHDS) and Hydrogen Generation Unit (HGU) were added in 1999 to meet BS-2000/BS-II quality of HSD. MS Quality Improvement Project comprising of Continuous Catalytic Reforming Unit (CCRU) and revamp of DHDS were carried out in the years 2006 and 2007 respectively to meet BS-II/BS-III MS and HSD quality respectively.

Further, under the Residue Upgradation Project (RUP) and MS/HSD quality improvement Project Delayed Coking Unit (DCU), Vacuum Gas oil Hydro-Treater Unit (VGO-HDT), Diesel HydrotreaterUnit (DHDT), Hydrogen Generation Unit-III (HGU-III), Sulphur Recovery Unit (SRU), Isomerisation Unit (ISOM), ATF & LPG Merox units were commissioned in 2010-11. At present, Gujarat Refinery has capacity to process 13.7 MMTPA of crude oil, with crude basket comprising of 55% high sulphur crude (7.6 MMTPA) and 45% low sulphur indigenous crude (6.1 MMTPA).In addition to BS-III/BS-IV fuel products, the refinery also has the capability to produce a wide range of specialty products such as benzene, toluene, MTBE, MTO, Food Grade Hexane & LAB.

The existing refinery consists of the following facilities:

Crude & Vacuum Distillation Unit (CDU/VDU)

Coker LPG Merox Unit FCC LPG Merox Unit ATF Merox Unit MS Block SR-CRU Lab Plant UDEX MTBE Butene-1 Plant Hydrogen Generation Unit

(HGU-I/II/III) Diesel Hydro-treater Unit

(DHDT)

Diesel Hydro-Desulphurization (DHDS)

VGO-HDT Fluidized Catalytic Cracking

(FCC) FCC Gasoline Splitter Hydrocracker Unit (HCU) Delayed Coker Unit (DCU) Vis-Breaker Unit (VBU) Bitumen Blowing Unit (BBU) Sulphur Block Utilities & Offsite Including

Captive Power Plant






In current refinery operations, refinery produces Gasoline and Diesel conforming to BS-III & BS-IV specifications. Currently refinery is executing projects to upgrade the entire gasoline and diesel to BS-IV specif ication by revamp of existing DHDT, DHDS and VGO hydrotreater units. Further, with objective of meeting the guidelines established in Auto Fuel Policy 2025, wherein refinery would be required to manufacture 100% BS-VI fuels,IOCL is gearing uo to execute BS VI project under which a new DHDT unit, a FCC Gasoline Desulphurization unit and a new HGU are envisaged along with MS block revamp. M/s IOCL is now considering expansion of the refinery, with an objective to increase the processing capacity from current 13.7 MMTPA to 18.0 MMTPA. The expansion project also aims at substitution of existing smaller capacity atmospheric unit and vacuum units with a large Atmospheric Vacuum unit (AVU) to enhance the efficiency of operation.

M/s EIL had carried out the job of configuration study and had prepared a feasibility report for capacity expansion of Gujarat refinery from 13.7 to 18.0 MMTPA as entrusted by M/s IOCL. The report was issued to IOCL on July 2013. This configuration study however had envisaged production of BS-III/IV auto fuels from the refinery with incremental HSD production complying to BS IV auto fuel specification (no incremental motor spirit production was envisaged). However in view of Auto Fuel Policy 2025 by MOP& NG, M/s IOCL intended to update the study carried out in 2013 with additional facilities required for meeting 100% BS VI auto fuel production. Accordingly another Feasibility Report for capacity expansion of IOCL Gujarat refinery from 13.7 to 18.0 MMTPA has been submitted to IOCL during Aug-2016 by M/s EIL. This report was prepared based on agreed design basis considering a new HCU and SDA as additional processing units (as recommended by FR prepared during July-2013), crude/product prices as provided by IOCL and BS VI product quality for gasoline and diesel. But the IRR arrived for this option was lower than the hurdle values due to current price scenarios and revised base case. IOCL has now assigned EIL, the job to carry out a revised configuration study for capacity expansion of Gujarat refinery from 13.7 to 18.0 MMTPA by exploring alternate configuration options. This report documents the results of the study. It may be noted that a feasibility report for 100% BS VI at current refinery capacity of 13.7 MMTPA was issued to IOCL in January 2016. The same has been considered as base case for carrying out this expansion study from 13.7 to 18.0 MMTPA as well as for FR prepared during Aug-2016.



Rev. No. A



SECTION 3.0

SCOPE OF WORK






3.0 SCOPE OF WORK

The broad scope of work for the subject study is to develop an alternate refinery configuration using LP modelling for expansion of refinery from 13.7 to 18.0 MMTPA, in order to increase the IRR value as compared to that estimated in the FR issued on Aug-2016. It includes the following

The base case for this study is considered as the configuration finalized under 100% BS VI at 13.7 MMTPA, report submitted in January 2016, with additional diesel and gasoline production complying with BS VI specifications.

Development of the LP model and carry out configuration study for 18.0 MMTPA capacity with the consideration of new AVU of capacity 15.0 MMTPA, various secondary conversion technologies like low CCR INDMAX, High CCR INDMAX, conventional FCCU etc., MS block for Naphtha up gradation, Ebullated Bed Hydrocracker for bottom up gradation and value added products like polypropylene.

Carry out CAPEX Cost estimation at ± 30% accuracy level, along with calculation of IRR for based on 3 years avg. price of crude and products FY 14-17.

Estimation of additional utility systems, offsite systems, flare systems and to carry out costing of these additional facilities.

Project implementation strategy and project schedule along with bar chart.

Recommendations.

Updating of the Plot plan for additional facilit ies.



Rev. No. A



SECTION 4.0

DESIGN BASIS

Format No. 5-0000-0200 F1 Rev. 0 Copyrights EIL All rights reserved

Document No. A510-RP-79-41-0004

Rev. No A Page 28 of 284

REVISED D RAFT FEASIBILITY REPORT

FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO FU EL

PRODUC TION

Study to be done by EIL FR* DFR NA Other Execution Methodology for Project CONV Project Duration Required in Months

4.1 Other Studies By EIL By Others Remarks

4.1.1 Market survey/study report (Demand and supply analysis)

Not Applicable

4.1.2 Rapid Environmental impact study Not Applicable 4.1.3 Site evaluation/selection Not Applicable 4.1.4 Evaluation/Selection of licensors Not Applicable 4.1.5 Rapid Risk analysis Not Applicable 4.1.6 Soil investigation Not Applicable 4.1.7 Hydrological survey Not Applicable

Contour survey Not Applicable Route survey (for transport of ODC materials from various ports / industrial areas of the country.)

Not Applicable

Marine Survey-effluent dispersion study Not Applicable 4.1.8 Health assessment /inspection reports (For

Revamp) Not Applicable

4.1.9 Downtime assessment report (For Revamp) Not Applicable

4.2 PLANT LOCATION Village City State Nearest Rly Station(kms) Koyali (near Vadodara) Gujarat Vadodara

4.3 LAND AVAILABILITY DETAILS(Refer existing plot plan) 4.3.1 Plot Details 4.3.1.1 Plot Area

4.3.1.2. Khasra Map, Land Survey map to be furnished

Refer updated plot plan. Rev.J (dated 10/08/2016)

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

By IOCL (if available)

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

As per existing plant

4.3.3 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).

To be worked out with IOCL






PRODUC TION

4.3.4 Land Rate (Rs per acre) By IOCL 4.3.5 Land availability By IOCL (Bajawa and Y2 plot to be

acquired by IOCL as shown in plot plan. Refer updated plot plan. Rev.J (dated 10/08/2016)

4.3.6 Met Data As per existing plant 4.3.7 Grid power availability Entire additional power consumption in

J-18 expansion to be met with import power from Grid without taking credit of available margin in existing CPP capacity.

4.3.7.1 Nearest distance Not Applicable 4.3.7.2 Level Not Applicable 4.3.7.3 Source Not Applicable

4.4 OBJECTIVES OF THE STUDY A Draft FR for capacity expansion of Gujarat Refinery from 13.7 to 18.0 MMTPA (A510-RP-7941-0003, Rev A) has been submitted to IOCL on August-2016. The Draft feasibility report was prepared based on agreed design basis considering HCU and SDA units, Design cases 1 and 2, crude/product prices as provided by IOCL and BS VI product quality. The IRR for the two cases was coming out to be lower than expected values. Further, IOCL requested EIL to carry out study by exploring alternate configuration options with higher IRR and prepare feasibility report for the capacity expansion from 13.7 to 18.0 MMPTA. The major objectives of the study are:

Develop an alternate refinery configuration using LP modelling for expansion of refinery from 13.7 to 18.0 MMTPA with an expected IRR Value of approximately 13.5 % or higher. The base case for the study shall be retained as 100% BS VI at 13.7 MMTPA, as considered in the draft FR submitted.

Establish the product slate and unit capacities for various configuration options for the design crude mix.

Total Diesel and gasoline production shall conform to BS-VI quality.

Estimate additional utilities requirement for selected option.

Maximum utilization of existing hardware and minimum shutdown time

Capital cost estimation with +/- 30% accuracy for the selected option.

4.5 Raw Material

Name Crude Mix

LNG/RLNG Methanol Benzene

Source Pipeline Pipeline Tankers Tankers






PRODUC TION

Composition

As confirmed by IOCL only Design case 2 crude mix of FR submitted (dated Aug -2016) shall be considered for this study. Refer Annexure I, Table 1

Refer Annexure I,

Table 2

Not required

Not required

4.6 Crude Assay

Crude assay for imported crudes shall be as per EIL data base. However for the indigenous crudes refer Annexure II, document No.2 for detailed crude assay of South Gujarat, North Gujarat and Mangla crudes as provided by IOCL.

4.7 On-stream Hours The on-stream factor shall be considered as 8000 hours of operation per annum.

4.8 Crude and other feed stream Price Avg. prices of FY 2013-16 as provided by IOCL shall be considered for crude and other feed prices for this study as considered in the draft FR submitted. Refer Annexure 1, Table 3 for avg. prices for crude and other feeds. The cost of import Power shall be 8.32 Rs/kwhr.

4.9 Products Refer Annexure II, Document No.1 for product slate for 100% BS IV at 13.7 production as provided by IOCL (Base case for 100% BS VI at 13.7 study). Refer Final FR for 100% BS VI auto fuel production at 13.7 MMTPA for the base case product slate of the current study. 4.9.1 Production Limits

i. Entire HSD and gasoline production shall be of BS-VI spec. ii. Domestic gasoline sales shall be capped at 2200 KTPA, balance shall be shown as gasoline

export. iii. SKO production shall be capped at 0 KTPA. iv. ATF production shall be capped at 650 KTPA. v. MTO production shall be considered as 0 KTPA vi. Bitumen production shall be fixed at 480. KTPA.

vii. Naphtha export shall be minimised. viii. PNC naphtha production is not be considered.

ix. Benzene and Methanol import shall be considered. x. No limit on RLNG import. RLNG shall be utilized for the following Purpose in the refinery.

Feed/Fuel to existing HGU-III/ Fuel to existing HGU-I Fuel to new GT. New HGU if considered in this project will be designed for dual feed case

naphtha/RLNG Production Limits to be considered are summarized below in Annexure 1, Table 5. 4.9.2 Major Products and specifications Refer Annexure II, document No 6 for manufacturing and standard specifications BS-VI products as provided by IOCL. 4.9.3 Product Price






PRODUC TION

Avg. prices of FY 2013-16 as provided by IOCL shall be considered for product prices fo r this study as considered in the draft FR submitted. Refer Annexure I, Table 4 for avg. prices for products.

4.10 Plant Units Process Units Capacity

Utilities to be generated Capacity

Catalyst / chemicals Name Quantity Unit Rate

Details of existing process units are provided in Annexure I, Table 6. The following are the configuration options envisaged for this FR. However, EIL will include write up in the FR report on the configuration option finalization to meet the objective of making the project economically viable. Secondary Processing Units

FCC / RFCC : INDMAX Unit is to be considered for these technologies. Typical Indmax unit yields (for low CCR and High CCR cases) are already shared with EIL. For typical properties of various streams from Indmax, EIL will use information as per their FCC/RFCC data bank.

Residue Upgradation Unit Ebullated Bed Hydrocracker Unit along with existing DCU

Value addition Unit Poly Propylene Unit (Option of selling propylene rather than polypropylene shall also be

considered for comparison) The following are new units envisaged for this FR.

1. IOCL desires that, for 18 MMTPA crude processing, a new Crude unit along with only one of

the existing units is to be considered. EIL may chose any of the existing units in order to meet the overall process requirement.

In case, it is still not possible to meet the overall process requirement with only one existing unit, EIL with full justification, will consider one more existing unit.

2. New NSU, ATF & LPG treating units 3. New Hydrogen Generation Unit 4. SR Naphtha caustic wash facilities 5. New MS Block units 6. New Sulphur Recovery Unit 7. New sour water stripper unit and Amine regeneration unit

Yield pattern, utility consumption, catalyst and chemical consumption for existing units are provided in the Annexure II document No. 9, 10, 11 &12 as provided by IOCL. Yield data and key product properties data for INDMAX unit for two cases (Low CCR and high CCR feed) have been provided by IOCL (Refer Annexure II, document No 14). For other new units EIL in-house data shall be used for y ield pattern, utility consumption, and chemical and catalyst data. Revamp of HCU to process sour VGO to be considered as per J- 18 process requirement

4.11 Offsite, raw material/ product and other storages






PRODUC TION

Optimal storage for new facilities may be considered based on existing best practices in refinery project. Refer Annexure II, document No.4 for details of existing tankage facilities available in the refinery. Materials Raw Material Intermediate Products Finished Products Name State

Liquid/ solid

No of days of storage

Name State Liquid/ solid


Name State Liquid/ solid


Following storages shall be considered as part of J-18 project:

1. For crude storage, 1 (one) additional crude tank of 60000 KL shall be considered. 2. Feed storage for New MS Bock 3. Feed storage for secondary processing units 4. storage for MS product 5. storage for diesel product 6. storage for Propylene/Poly propylene product

The capacities of above storage tanks and requirement of any other storage facilities shall be finalized with IOCL.

4.12 Hook up connection Name Distance of connection from existing facilities ____ Integration with existing refinery : For major process and utility piping, based on inputs provided by IOCL

4.13 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.

No additional facilities required for product dispatch.

Length of rail to be laid/ distance between plant and railway siding

NA

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

NA

4.14 UTILITIES

4.14.1 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. 4.14.2 Electric Power For Plant Operation






PRODUC TION

Source Entire additional power consumption in J-18 expansion to be met with import power from Grid without taking credit of available margin in existing CPP capacity. Refer Annexure II, document No.7 for details regarding existing electric power systems in the refinery

Volts & Frequency Power fo r electric drives and lighting shall be as below 6600 Volts ± 6%, 3 phases, 50 Hz ± 4%,

res istance grounded for drives of 161 KW and above.

415 Volts ± 6%, 3 phases, 50 Hz ± 4% for

drives from 0.37 KW to 160 KW, neutral is solidly earthed.

For motors up to 0.37 KW: 230 V ± 4%.

For lighting and instruments, the voltage

must be 240 Volts ± 6%, 50 Hz ± 4%, singe phase AC, grounded.

v) UPS system must be 240 V AC.

Rate Rs./kwhr Rs. 8.32/ kWhr (for imported Power.) Distance ____________ km from Captive Power to be generated _To be worked out in FR________ MW Level of Generation __IOCL_______ KV Contract Demand Charges NA Energy charges NA Minimum energy charges (as % of Contract

Demand) NA

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

4.14.3 Construction Power Available Yes Volts By IOCL KM away Within existing refinery Rate (Rs./Kwhr) Contract Demand Charges Power available within the plant shall be

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

Demand) 4.14.4 Construction Water Available Yes KM away Within existing refinery






PRODUC TION

4.14.5 Cooling water Availability to be established during FR

based on utility consumption and generation data from IOCL). Refer Annexure II, document No.7 for details regarding existing cooling water systems in the refinery.

4.14.6 Nitrogen system Availability to be established during FR

based on utility consumption and generation data from IOCL.

4.14.7 Plant and Instrument Air system Availability to be established during FR

based on utility consumption and generation data from IOCL.

4.14.8 Steam and Power system Availability to be established during FR

based on utility consumption and generation data from IOCL

4.14.9 DM Water Availability to be established during FR


4.14.10 Condensate system Availability to be established during FR


4.14.11 Flare A new hydrocarbon/ acid flare to be

considered for new facilities under J-18 project. ). Refer Annexure II, document No.8 for details regarding existing flare loads in the refinery

4.14.12 ETP A new RO based ETP shall be considered

for handling the additional effluents generated from the new process units coming up under the J-18 project.

4.15 ENVIRONMENTAL REQUIREMENT 4.15.1 Effluent Specifications Liquid Effluent including spent caustic. MINAS/State Pollution Board

Standards. Gaseous Effluent MoE&F guidelines/State Pollution

Board Standards Solid Waste State Pollution Board Standard






PRODUC TION

Stack height (Limitation to be specified) Furnace ht = 14 x Q0.3 (Subject to minimum ht of 60m) Q= SO2 emission in kg/hr.

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 4.15.2 Green Belt Requirement Refer plot plan Rev.F As advised by State Government during site selection

visit.

4.15.3 REIA (in case of DFR) / rapid risk analysis (in case of

FR Not Applicable

4.16 BUILDING REQUIRED -PLANT & NON PLANT Name Type Area in M2 Administrative Building Not Required Warehouse(Chemical, Spares, Product,

Cement) As required

Workshop Not Required Canteen Not Required Lab Not Required Control room with rooms for operating

supervisors and conference rooms As required

Training Center Not Required Substations As required Fire station As required Operator Cabins As required Service Buildings As required Security Cabins As required Any other building as required Not Required

4.17 TOWNSHIP: No additional provision under this project. % of staff to be provided accommodation Housing --------% Hostel---------% Hospital required Yes/No No. of Beds--------- Market Yes/No No. of shops--------- Club with games and sports ground/ complex Yes/No Swimming pool Yes/No Housing for Security establishment Yes/No School up to primary/secondary education Yes/No Provision of park in township Yes/No Provision for power, water and sewage

disposal Yes/No

4.18 CONSTRUCTION AIDS






PRODUC TION

Heavy crane to be purchased by owner No (If yes, please specify capacity of range proposed and

hiring charges) Capacity range------------------ Hiring charges ------------------

Whether Hydra, and medium size crane No (up to 35 Tons can be brought by Erection Contractor) XX

4.19 OWNER EXPENSES DURING PROJECT IMPLEMENTATION Expenditure Heads To be Included in report expenses towards public issue NA Salaries By IOCL (Pending) perks and facilities to be provided by owner to people

employed on this job By IOCL (Pending)

Communication By IOCL (Pending) Travel By IOCL (Pending) Training By IOCL (Pending) legal expenses By IOCL (Pending) PMC fees By EIL Contigency 5% any other By IOCL (Pending) Total Amount for all the above heads Rs-------------------------

4.20 ADDITIONAL INFORMATION, FOR MARGIN MONEY

CALCULATION As per EIL norms.

Item Days Salaries and wages and operating

manhours/manpower envisaged

Repairs and maintenance spare inventory Goods in process Finished goods

Bills Receivable (Outstanding) Cash in hand Trade Credits Inventory level for Catalysts Inventory level for Chemicals

4.21 INFORMATION FOR FINANCIAL ANALYSIS-

(Basis shall be Considered As Per Draft FR issued on Aug-2016.) Project Funding % Grant

Equity Debt

Expenditure Pattern (Grant Terms Required)

Equity before debt or concurrent

Equity Contribution % Promoter Financial Institution Public






PRODUC TION

Equity Composition % Foreign Equity Contributors Equity

Dividend on Equity Equity Expenditure

Pattern Promoter fund followed by F1 and then Public Promoter and F1 equal share and then Public Foreign Equity flow pattern

Debt Composition % Foreign Currency Financial Instituions Suppliers Credit Financial Instituions

Rupee Portion Debentures to Financial Institutions Debentures to Public

Terms and Conditions of Debts / Debentures Suppliers Credits

(Foreign Currency and Rupee)

Front end processing fees Exposure fees Commitment fees Guarantee fees Interest Rates and Calculation Methodology

Loan Repayment Terms

Moratorium (from Commercial Operations commencement) Number of installments Frequency of Installments

For Debentures to Fis and Public

Coupon rate Redemption Terms

Interest rate on Short Term Loan Capacity Buildup 1st year-60%

2nd year-80% 3rd year onwards -100%

Factory Gate Prices Not Applicable

Raw Materials, Chemicals and Catalysts etc. (inclusive of transportation and all taxes and duties). Excise duty rates and countervailing duty rates (for imported items) may be separately indicated for Modvat benefit calculations wherever applicable. Bought out Utilities (inclusive of all burdens). Product and By-product prices (excluding duties and taxes etc.). However, the excise duty rates may be indicated for use in Modvat calculations wherever applicable.

Applicable Tax Benefits Not Applicable Furnish Crude & Individual Product Price (FOB), freight & Insurance cost to be

considered for analysis (also provide basis of pricing). Not Applicable Owner Philosophy for Payment terms. Not Applicable Project Construction period

from zero date (to be 48 months






PRODUC TION

counted from A or B )

A Govt. of India Clearance for financial investment, signing of agreement with process licensor and with engineering contractor

B Availability of Process package for Critical Units.

4.22 Refinery Data - Base Case Refer Annexure II for refinery data for 100% BS IV at 13.7 production as provided by IOCL (Base case for 100% BS VI at 13.7 study). Refer Final FR for 100% BS VI auto fuel production at 13.7 MMTPA for the base case data of the current study.






PRODUC TION

Annexures to Chapter 4






PRODUC TION

ANNEXURE I

Table 1 : Base Case and Design Case Crude Mix

CRUDE TYPE BASE CASE (13.7 BS-VI)

DESIGN CASE (18.0 BS-V)

North Gujarat (NG) 3.7 3.7

South Gujarat (SG) 1.7 1.7

Rajasthan Crude 0.8 0.8

Basrah Light

4.3

Kuwait 7.5 7.5

Total High Sulphur Crude 7.5 11.8

Total Low Sulphur Crude 6.2 6.2

Total Crude 13.7 18.0

Table 2: RLNG Properties

COMPOSITION UNIT HEAVY NG PROCESS

DESIGN LIGHT NG PROCESS

DESIGN Methane (C1) mol-% 78 93 Ethane (C2) mol-% 7.54 2.85 Ethylene mol-% 0.46 0.15 Propane (C3) mol-% 4.77 -- Propylene mol-% 0.23 -- Butanes (C4) mol-% 3 -- Pentanes (C5) & heavier

mol-% 2 --

Non-combustible gases including CO2 and N2

mol-% 4 4

CO2 mol-% 3% by vol. max 3% by vol. max. N2 mol-% 2 2 O2 mol-% 0.2% by Vol. 0.2% by Vol. Total Sulphur including H2S 10 ppmw 10ppmw

H2S 5ppmw 5 ppmw






PRODUC TION

Impurities

Free from dust, gum, sand, oil,

and other delirious solid and/or liquid

matter

Free from dust, gum, sand, oil,

and other delirious solid and/or liquid

matter

Water content / moisture

No water or moisture shall be

dehydrated and shall in no event

contain more than 112 kg of

entrained water per MMSCM gas

No water or moisture shall be

dehydrated and shall in no event

contain more than 112 kg of entrained

water per MMSCM gas

Gross Heating Value kcal/SCM kcal/Nm³ 11578 9323

Net Heating Value BTU/SCM kcal/Nm³ 10516 8409

The crude and Product prices to be considered for this study is as follows.

Table 3: Feed Prices (FY 2013-16)

CRUDE 3 YEAR AVERAGE

North Gujarat (NG) 34143

South Gujarat (SG) 39052

Rajasthan Crude 31686

Basrah Lt crude 34835

Kuwait 35019

LNG/RLNG 46460

Methanol 27203

Benzene 55478

The cost of import Power is -8.32 Rs/kwhr

Table 4: Product Prices (FY 2013-16)

PRODUCT 3 YEAR AVERAGE

LPG 43856 Polymer grade Propylene 56926 Poly propylene 88622 Naphtha Export 42340






PRODUC TION

PRODUCT 3 YEAR AVERAGE

PNCP Naphtha 42340 Food Grade Hexane 67621 Domestic MS BS-VI (Normal grade)

52285

Export MS BS-VI (Normal grade)

Rs. 1200/ KL, Less for average price for Export gasoline (BS VI)

HY. REFORMATE TO IOCL GR 43843 SKO 47711 PCK 46028 ATF 47521 LAB 97308 HSD BS-VI 46028 Bitumen VG-10 26529 Bitumen VG-30 29852 HS Coke 4248 Sulphur 8946

Table 5: Production Limits

PRODUCT MAXIMUM

QUANTITY (KTPA) FIXED QUANTITY

(KTPA)

PNCP Naphtha 0

Propylene/Poly propylene No limit

Domestic Gasoline 2200

Export gasoline No limit

Naphtha export Minimum

SKO 0

ATF 650

MTO Nil

LDO Nil

Bitumen 480 KTPA






PRODUC TION

Table 6: Existing Unit Details

UNIT CAPACITY UNIT PROCESS LICENSOR

REMARKS

AU-I 2 MMTPA OPEN ART

100% SOUTH GUJARAT, SOUTH

GUJARAT & NORTH GUJARAT

(70:30)

AU-II 2.2 MMTPA OPEN ART

100% NORTH GUJARAT ,

SOUTH GUJARAT NORTH GUJARAT & BOMBAY HIGH

IN ANY PROPORTION

AU-III 2.7 MMTPA OPEN ART

Case I: NG 55% + Imp LS 45% , Case

II: NG55% + BH45% , and Case

III: NG100%

AU-IV 3.8 MMTPA OPEN ART SG , IMP (HS

&LS), BH

AU-V 3 MMTPA OPEN ART

50:50 by weight of Light and Heavy Arab

Crude

FPU-1 2.4 MMTPA OPEN ART Feed Preparation

Unit For FCCU

FPU-II 3 MMTPA OPEN ART Feed Preparation

Unit For HCU

VDU 1.2 MMTPA OPEN ART

VBU 1.6 MMTPA OPEN ART

BBU 0.5 MMTPA

LAB 0.12 MMTPA UOP

MSQU 0.6 MMTPA UOP

SR-CRU 0.33 MMTPA Russian

UDEX 0.166 MMTPA UOP

FGH 0.105 MMTPA OPEN ART

FCC 1.5 MMTPA UOP

MTBE 0.21 MMTPA CD TECH






PRODUC TION

UNIT CAPACITY UNIT PROCESS LICENSOR

REMARKS

BUTENE-1 Not in Operation

DHDS 1.7 MMTPA UOP

HGU-2 11000 TPA Haldor Topose

HCU 1.4 MMTPA CHEVRON

HGU-1 38000 TPA Linde

ISOM 0.23 MMTPA UOP, USA

Delayed Coker Unit (DCU)

3.7 MMTPA Foster

Wheeler, USA

Diesel Hydrotreater (DHDT)

2.2 MMTPA AXENS

HGU-3 72500 TPA Haldor Topose

VGO Hydrotreater (VGO-HDT)

2.1 MMTPA UOP LLC

USA

SRU-1 1 x 18 TPD

SRU-2 2 X 35 TPD

SRU-3 2 X 300 TPD BVPI

TGTU 1 X 600 TPD BVPI

SWS-3 & 4 107 T/HR OPEN ART

ARU 750 T/HR OPEN ART

FCC LPG MEROX 225 TMTPA UOP LLC

USA

ATF MEROX 200 TMTPA UOP LLC

USA

COKER LPG MEROX 150 TMTPA UOP LLC

USA

FCC GASOLINE SPLITTER

550 TMTPA






PRODUC TION

Revision in Design Basis during Configuration study

The following are the major revision of the Design Basis data after subsequent meetings and correspondence between IOCL and EIL.

The yield pattern and product properties of VGO-HDT unit has been revised based on revamped case as follows based on IOCL mail dated 17.03.2017.

Table 4.1 VGO-HDT unit -revised yield pattern & key properties Product Yield

(%wt) Properties

Gases 4.21

Naphtha 0.67

Sp gravity-0.755, Sulphur-10 ppmw, Nitrogen-3ppmw, RON-61, MON-50, PONA (Vol%)-

P-60, O-1, N-30, A-9

Kero 7.03 Sp gravity- 0.815, Sulphur-36 ppmw, Nitrogen- 13 ppmw,

Diesel 12.58 Sp gravity- 0.890, Sulphur-49 ppmw, Nitrogen- 116 ppmw,

Bottoms 75.5 Sp gravity- 0.916, Sulphur-234 ppmw, Nitrogen- 265 ppmw,

The crude and Product prices considered for 100% BS VI at 18.0 MMTPA configuration has been revised as avg. price of FY 2014-17 as compared to avg. price of FY 2013-17 considered earlier. in

Table 4.2 Feed Prices

Crude 3 Year Avg. price (FY 2014-17)





Kuwait 27067

LNG/RLNG 31770

Methanol 24248

Benzene 38628

Table 4.3 Product Prices






PRODUC TION

Product 3 Year Avg. price (FY 2014-17)

LPG 32972

Propylene (Polymer grade) 46608 Polypropylene 82459 Naphtha Export 32287 PNCP Naphtha 32287

Food Grade Hexane 57562

MS BS-VI (Normal grade)- Domestic 42659

MS BS-VI (Normal grade)- Export 40992

MS BS-VI (Premium grade)- Export 42659

MTO 48493 SKO 36962 PCK 36654 ATF 36714 LAB 87103 HSD BS-VI 36654 Bitumen VG-10 21107 Bitumen VG-30 23558 HS Coke 4108

Sulphur 7977

Hy Alkylate from LAB 56230

Base case hydrogen consumption/generation data of certain units have been

revised based on IOCL mail dated 29.03.2017, as follows.

Table 4.4 Revised hydrogen Consumption/generation

Unit Consumption/generation as per Base case report

(% of feed by wt) Revised Data

Existing HCU 1.9 2.5

Existing DHDT 2.1 1.5

DHDS 1.0 1.1

VGO HDT 1.5 1.3

ISOM 0.5 0.8






PRODUC TION

BS VI DHDT 2 1 Generation in CCRU 5.4 4.1

The indicative yield pattern of INDMAX FCC unit with the consideration of 100% SR feed is provided by IOCL as below with feed quality considered

Table 4.5 FCC INDMAX yield with 100% SR feed considered

Product Yield (%wt)

Dry gas with inters 8.8

LPG 34

Propylene 17

Gasoline 26.9

Hy naphtha 16.8

HCN 4.7

LCO 9.7

CLO 8.1

Coke & losses 7.8

Table 4.6 Feed definition of INDMAX considered for yield estimation

Component Cut range Wt% in feed Sulphur (wt%) Sp gravity Nitrogen

(ppmw) CCR (%wt)

SR VGO 380-535 63 2.7 0.925 920 0.5

Vac Slop 535-560 19 3.1 0.955 1700 2.7

Vac Residue 560+ 18 5.1 1.038 4200 23.3

Blend 100 3.21 0.95 1660 5.02

The yield pattern of existing FCC has been based on revised feed composition to the unit, as below.






PRODUC TION

Table 4.7 Revised FCCU yield pattern

Product Yield (%wt)

Dry gas with inters 2.7

LPG 13

Gasoline 37

Hy naphtha 16.8

LCO 20

CLO 6.4

Coke & losses 4.1

The production of 120 KTPA of MTO has been considered based on IOCL mail dated 24.05.2017

The execution of new AVU has been considered upfront to other units based on MOM dated 20.05.2017

No new crude tank shall be envisaged for J-18 units based on MOM dated 20.05.2017

The sales LAB hy alkylate has been considered based on IOCL mail dated 20.04.2017

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


Rev. No. A

REVISED DRAFT FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO FUEL

PRODUCTION FOR IOCL GUJARAT REFINERY

SECTION 6.0

PROJECT LOCATION



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FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO FUEL


6.0 PROJECT LOCATION

The capacity expansion from 13.7 to 18.0 MMTPA capacity with 100% BS-VI Auto fuel production project is proposed within the existing refinery complex and nearby Bajwa and Y2 plot of IOCL Gujrat Refinery at Koyali near Vadodara city. The site is approximately located at Latitude 22.37°N and Longitude 73.12°E. The site is well connected by road network, rail network and airport. The nearest city, railway station and airport to the site is Vadodara. Since new units proposed under the project are proposed to be located within Refinery and / or plot area available adjacent to Refinery, existing administration buildingand canteen facilities shall also cater to the requirements of additional manpower for new units. Steam and power for the new units shall be supplied by existing CPP and new utility systems wherever proposed, shall be integrated with existing facilities. The overall plot plan prepared for this project is attached as Annexure-4. The Refinery site can be visualized in Google map which is as given below:



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Rev. No.




SECTION 7.0

PROJECT DESCRIPTION



Rev. No.




SECTION 7.1

PROJECT CONFIGURATION



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7.1 Project Configuration

7.1.1 Introduction

Indian Oil Corporation Limited (IOCL) operates one of its largest oil refineries at Koyali (near Vadodara) in Gujarat. At present, Gujarat Refinery has capacity to process 13.7 MMTPA of crude oil. M/s IOCL is considering increasing the processing capacityfrom current 13.7 MMTPA to 18.0 MMTPA. With this objective EIL carried out the job of configuration study and prepared report for capacity expansion from 13.7 to 18.0 MMTP in July 2013.The above configuration study carried out by M/s EIL has envisaged production of BS-III/IV auto fuels from the refinery with incremental HSD production complying to BS IV auto fuel specification (no incremental motor spirit production was envisaged).

However in view of Auto Fuel Policy 2025 by MOP& NG, M/s IOCL intends to update the study carried out in 2013 with new facilities required for meeting 100% BS VI auto fuel production. Currently the refinery is executing projects for producing 100% BS IV gasoline diesel with the revamp of DHDT, DHDS and VGO-HDT units. Further, the refinery is now considering adding new units to produce 100% BS VI auto fuels at existing capacity of 13.7 MMTPA before going for expansion. A feasibility report for 100% BS VI at current refinery capacity of 13.7 MMTPA was issued to IOCL in January 2016. The study recommended to implement a new DHDT unit, a FCC gasoline de-suphurization unit and a new HGU to produce 100% BS VI diesel and gasoline. The same has been considered as base case for carrying out this expansion study from 13.7 to 18.0 MMTPA. Astudy report submitted in August-2016 considered the option of a new AVU, FC-HCU along with SDA. However due to poor price of diesel, it was found that IRR was much below the hurdle rate. Therefore IOCL assignedEIL to carry out additional options to improve refinery economics. Following cases have been studied:

EB HCU+ Low CCR INDMAX FCC+ PPU

High CCR INDMAX FCC+ PPU

EB HCU+ Low CCR INDMAX FCC+ Propylene sales

High CCR INDMAX FCC+ Propylene sales

EB HCU+ Conventional FCCU

The prime objective of this study is to determine the facilities required to process 18.0 MMTPA crude, producing 100% BS VI products.IOCL desires that, for 18 MMTPA crude processing, a new Crude unit along with only one of the existing crude unit is to be considered, thus a new CDU/VDU of 15.0 MMTPA capacity has been considered after dismantling of AU I, AU II, AU III, AU IV, FPU I & VDU and by creating an additional capacity of 4.3 MMTPA. Besides this the objective of minimum naphtha sales, zero kerosene production and no fuel oil sales are also need to be met.

Based on the LP modelling carried out meeting these objectives, following are the proposed major units.



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Proposed major units are as follows.

AVU with LPG treating

High CCR INDMAX FCC unit with LPG Treatment

Propylene Recovery Unit (PRU)

Gasoline Desulphurization Unit

MS Block consisting of NHT, CCR and ISOM Units New Kero Hydro Desulphurization Unit

New Sulphur Recovery Unit and TGTU

New Sour Water stripper Units

New Amine Regeneration Unit

7.1.2 Description of existing facilities

A brief description about the processing facilities in the existing refinery is provided under subsection.

7.1.2.1 Crude Mix- Existing refinery

The existing refinery is being operated at a capacity of 13.7 MMTPA using a mixture of low sulphur Indigenous crude & high sulphur imported crude. The crude basket also includes Rajasthan Mangla crude to the tune of approx. 6%, being blended in the crude pipeline itself, no separate facilities have been brought in the refinery infrastructure to handle Mangla crude.

Table 7.1.1below gives a break-up of the crude basket being used in the existing refinery by weight & weight percentage.

Table 7.1.1 Crude Mix- Existing Refinery

Crude Quantity (MMTPA)

Percentage (% )

North Gujarat (NG) 3.7 27

South Gujarat (SG) 1.7 12.4

Rajasthan Mangla 0.8 5.8

Sub-total indigenous 6.2 45.3

Kuwait 7.5 54.7

Total crude 13.7 100



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7.1.2.2 Existing Processing facilities

Atmospheric & Vacuum Units

The existing refinery consists of 5 atmospheric columns. The metallurgy of AU-I,II & III is suitable for processing low sulphur-high TAN indigenous crudes whereas AU-IV & V are capable of handling high sulphur imported crudes along with indigenous low sulphur crudes.

In conjunction with the aforementioned crude units, the refinery consists of 3 vacuum units used for preparing feed for secondary processing units. Out of these 3 vacuum units, FPU-I & VDU are designed for handling RCO derived from AU’s processing high sulphur crude, whereas FPU-II is designed for handling low sulphur RCO only.

MS-Block

The existing refinery comprises of a MSQU (Motor Spirit Quality Upgradation) & SR-CRU unit for producing gasoline of Euro-IV quality. The MSQU block consists of a Naphtha Hydro-treater unit (NHT) which prepares the feed i.e. straight run naphtha for ISOM & CCR units. The isomerate from ISOM unit and reformate from CCR & SR-CRU are blended to prepare BS-III &BS-IV gasoline products. The refinery also consists of a MTBE unit which is used as an additive during blending for BS-IV gasoline production.

Hydrotreater Block

The existing refinery consists of secondary Hydro-processing units which include – Diesel Hydrotreater (DHDT), Diesel Hydro-Desulphurization, VGO-Hydrotreater and Full Conversion Hydrocracker units.in addition to this a new DHDT unit and a FCC gasoline desulphurization unit are being implemented in the refinery as part of 13.7 BS VI project.

The units DHDT, DHDS & VGO-HDT aim at removing sulphur, nitrogen and metals in the presence of a catalyst at elevated temperatures & pressure, from a feed comprising of straight run gas oils & some cracked feed component. The reaction chemistry also leads to cracking of the feed to a certain degree thereby giving yields of lighter products like naphtha & LPG along with slight improvement in cetane number thereby producing diesel meeting Euro-IV specification.

On the contrary, full-conversion hydrocracker is used for increasing the middle distillate yield by cracking the feed into lighter components, as well as removing sulphur, nitrogen, metals and other contaminants. The products obtained from hydro-cracker units do not require any further treatment for meeting the finished product specifications.

Fluidized Catalytic Cracker

The existing refinery employs a FCC designed to process a low sulphur vacuum gas oil feed at a design capacity of 1.8 MMTPA. The unit processes hydro-treated VGO from VGO-HDT in the presence of a catalyst to break the long chains of hydrocarbon in a series of endothermic reactions thereby



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increasing the yield of lighter products. The cracked gas oils thus obtained from the unit are routed to hydro-treating units for further treatment & compliance of BS-III/IV specifications.

The catalyst used in FCC reactor is in a fine particle form. The contact of catalyst with hydrocarbon in a fluidized state at elevated temperatures leads to deposition of coke on its surface, which is the carbonaceous material present in the feed characterized by its CCR (Conradson Carbon) content. This coke deposited on the catalyst particles during cracking reactions is burned off in the regeneration cycle of catalyst thereby recovering the catalyst activity. The burning of coke particles leads to generation of SOx.

Bottom Upgradation Facility

The refinery in its existing configuration processes 13.7 MMTPA of crude, which after undergoing atmospheric & vacuum distillation gives a VR yield of approx 15%. The VR thus obtained is subjected to further processing for deriving marketable products of economic value.

The existing refinery under bottom upgradation facilities comprises of the following units:

Vis-Breaker Unit (VBU): The prime purpose of this unit is to prepare component for blending in fuel oil pool. VBU utilizes VR as its feed and produces Vis-Breaker Tar as the major product (approx 92%). Other products include fuel gas, naphtha & gas-oil. Due to the strategic location of refinery, readily available overseas/local market, the unit is being operated at 1.6 MMTPA for manufacturing fuel oil for export, local & internal use.

Bitumen Blowing Unit (BBU): This unit is used for processing VR obtained from vacuum units to manufacture bitumen that is further used as a raw material for road carpeting. Due to a readily available market for bitumen sales the unit is being operated to produce 750 KTPA of bitumen.

Delayed Coker Unit (DCU): Another major unit in the bottom upgradation facility is DCU. This unit processes the VR feed by subjecting it to a delayed coking process at low pressures which leads to the formation of coke (low value product). The hydrocarbon vapors removed from the coking drums are further subjected to fractionation. The subsequent fractionation of these vapors produces fuel gas, LPG, Naphtha & Coker Gas Oil. The coker gas oil thus obtained is further processed in hydro-treater/hydrocracker block before being routed to product pools.

Merox Unit

The existing refinery consists of the following Merox units for treating the LPG produced in secondary units. These units process the feed for meeting RSH/Sulphur specification required for marketing LPG.

FCC LPG Merox

Coker LPG Merox



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FCC Gasoline Merox – treats the FCC gasoline cuts, before routing them to reformate stream obtained from MSQU for blending in MS product pools.

SRU Block

As per the environmental norms it is essential to meet the SOx emission limits which are specific to an area. In order to meet these limits, the secondary hydro-processing units are equipped with amine absorbers for removing H2S present in the off-gases. These sour gases comprising mainly of H2S are scrubbed using lean amine. The rich amine thus obtained from these units is sent to an Amine Recovery Unit (ARU), which gives acid gas & lean amine as its products.

The sour water produced in FC-HCU & FPU/VDU is routed to Sour Water Stripper Unit. Stripped water & off-gas are the products obtained from SWS.

The acid gas from ARU & off-gases from SWS are then routed to Sulphur Recovery Unit (SRU) for recovering sulphur. The flue gas which exits the stack contains sulphur as low as 10ppm.

The existing refinery consists of 3 Sulphur Recovery Units, the largest having 2 trains of 300 TPD each along with TGTU of 600 TPD. The overall sulphur design recovery is 99.9%.

Specialty Units

The existing refinery comprises of certain units which were envisaged and employed due to local market availability for their products. These units include MTBE, UDEX, LAB, Butene-1 & FGH (Food Grade Hexane). The MTBE produced is used for blending with isomerate& reformate in order to improve octane number. The use of MTBE as octane booster eliminates the requirement of a bigger MS-Block for Euro-IV gasoline production.

Hydrogen Generation Units

The existing refinery consists of hydro-processing units downstream of the crude unit, which makes it necessary for the existing complex to incorporate hydrogen generation unit. The existing refinery in order to meet the hydrogen requirement of these secondary processing units employs 3 hydrogen generation units – HGU-I, II & III. While HGU-I & III are designed to operate on naphtha & natural gas as feed, HGU-II can be operated only on naphtha. The HGU block also includes a PDS section which is used for preparing the naphtha obtained from other units as feed for HGU by removing sulphur and other contaminants. In addition to this a new Hydrogen Generation unit of same capacity as of HGU III with PDS section is being implemented in the refinery, as part of 13.7 BS VI project.

7.1.3 New Process Units

The design capacities of new process units envisaged under this study is provided in Table 7.1.2 below.



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Table7.1.2: Design Capacities of new units

New Processing Units

Sl. No Unit Design Capacity

(KTPA)

1 New AVU 15000

2 LPG Treatment Unit 200

3 High CCR INDMAX FCC Unit with PRU & Cracked LPG treatment unit

2400

4 PPU 400

5 NHT/NSU 2400

6 CCRU 1600

7 ISOM UNIT 925

8 KHDS UNIT 850

9 Gasoline Desulphurization Unit 630

10 New SRU and TGTU 300 TPD

11 New Sour Water Stripper Unit (single stage) 330TPH

12 Amine Recovery Unit 300TPH

7.1.4 Revamped Units

Table7.1.3: Details of Revamped Existing Units

Revamp Units

Sl. No Unit Revamp Details

1. BS VI GDSU Revamp for processing high sulphur feed.

7.1.5 Utilities System

The following utility systems are considered in this FR for meeting additional utility requirements of new:

Raw water system

RO based DM water system

Steam, power and BFW system



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Condensate system

Compressed air system

Nitrogen system

Internal Fuel oil and Fuel gas system Following new Utility systems shall be implemented along with the new process units. These are after considering integration & centralization with existing utility system in consultation with IOCL.

Table 7.1.4: New Utility systems


Raw water system

The additional raw water requirement shall be met by a new bore well of 11 MGD capacity.

Recirculating Cooling water

A new cooling tower system with 4W+1S cells of capacity4000 m3/hr,2w+1s pumps of capacity 9000m3/hr in place of Abandoned cooling tower. A new cooling tower system with 8W+1S cells of capacity 4000 m3/hr,4w+1s pumps of capacity 9000m3/hr in the New Bajwa land. Augmentation of South block cooling towers by addition of one cell and pump

DM Water

A new RO based DM water plant of total capacity 550m3/hrwith three trains, each of capacity 275m3/hr (2W+1S), in integration with new ETP is envisaged.

Steam

Two new Boiler of capacity 150 TPH is envisaged. No standby boiler considered in place of unutilized boilers.

Power Additional requirement of 63 MW shall be met from existing import facility.

Condensate handling A new Condensate Polishing Unit with a capacity of 415 TPH (1W+1S) is envisaged.

Internal Fuel Oil and Fuel gas

Additional fuel gas requirement shall be met from fuel gas generation from new process units and balance shall be met by RLNG

Compressed Air System

A new compressed air system with a total capacity of 16400 Nm3/hr. 2w+1s compressor of 8200 Nm3/hr capacity envisaged.

Nitrogen A new Nitrogen plant of capacity 5000 Nm3/hr with liquid N2 storage of 500 m3 is envisaged.



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7.1.6 Offsite facilities

The offsite facilities of the refinery shall be augmented by adding following new storage tank and pump.

Table 7.1.5: New storage tanks

Sl. No

Service No of Tanks

Type Liquid stored

capacity of each tank (KL)

1 MTO product

1 InternalFloating

Roof 5000

2 NHT feed tank

2 Internal Floating

Roof 12,000

3 KHDS Feed tank

2 InternalFloating

Roof 5,000

4 LPG Mounded Bullet

6 Mounded

3500

5 Propylene Mounded bullet

3 Mounded

3500

Table 7.1.6: New pumps

Sl. No

Service No of

pumps Flow

(m3/hr) Type

1 MTO product Transfer Pumps

1W+1S 350 Centrifugal

Motor driven

2 NHT feed Pumps 2W+1S 200 Centrifugal

Motor driven

3 KHDS feed Pumps 1W+1S 135 Centrifugal

Motor driven

4 PPU feed Pump 2W+1S 50 Centrifugal

Motor driven

7.1.7 Flare System

A new hydrocarbon flare system is envisaged as a part of this project in place of existing new flare as advised by IOCL. This flare will be catering loads only from new AVU, INDMAX-FCC, MS Block, FCC-GDS, KHDS andOffsites Bullets. The flare system with 90’’ diameter flare stack with water seal drum, molecular sieve, flare header and main flare KOD has been considered.

New acid flare shall be required for handling sour gases. Sour gases to be flared shall be collected in a 20” pipe header connected to Acid gas KOD. Sour gases after KOD shall be routed to stack in a dedicated burning tip.



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SECTION 7.2

REFINERY COFIGURATION STUDY



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REVISED DRAFT FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO


7.2 Refinery Configuration Study

Increasing demand for distillates, projected higher demand for the next decade, depressed refining margins, declining markets for HSFO, need for higher profitability, potential markets for product export and incentives available thereon, are some of the major drivers for refinery expansion. Therefore, the main purpose of the Refinery’s Expansion project is to:

Increase refining capacity to achieve better economies of scale

To meet the increasing the demands of petrochemical feedstock or petrochemical products

Improve the yield of clean products significantly vis-à-vis black products

The capability of better handling of heavy bottom streams enhances the economic potential of most refineries. Upgrading heavy oil streams in the refinery is an increasingly prevalent means of extracting maximum value from each barrel of oil processed. The best alternative for a given project is site specific, and depends on local economics, including disposition of by-products and many other factors such as:

Expansion requirements

Existing refinery configuration

Capacity

Crude slate

Current product quality

Product specifications

Product requirements

Degree of residue conversion

Outlet for HSFO

Need for power

A draft FR for capacity expansion of IOCL Gujarat refinery from 13.7 to 18.0 MMTPA has been submitted to IOCL during Aug-2016. The draft feasibility report was prepared based on agreed design basis considering a new HCU and SDA units, Design cases 1(with Mangala as additional crude) and Design case 2 (with Basrah Lt has additional crude), crude/product prices as provided by IOCL and BS VI product quality for gasoline and diesel. The base case considered for the study was 100% BS VI products at 13.7 MMTPA as compared to base case of J18 study carried out during July-2013, wherein base case consisted of BS-III+ BS IV



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products. But the IRR arrived in the FR submitted during Aug-2016 for the both the cases analyzed was lower than the hurdle values. The poor financial results and infeasibility of configuration option with HCU and SDA at the current position is due the improved base case and current price scenario.

Further, IOCL assigned EIL the job to carry out a revised configuration study for capacity expansion of Gujarat refinery from 13.7 to 18.0 MMTPA with the objective of improving profitability and better return on investment. The limit considered for gasoline sales has been relaxed by keeping no limit on export gasoline sales. The prime objective of this study is to develop alternate refinery configuration using LP modeling for refinery expansion with an estimated IRR value above the hurdle limit. Zero kerosene sales and minimization of naphtha sales after expansion are also considered as key objectives the study besides zero fuel oil make.

The base case for this study has been retained as BS-VI at 13.7 MMTPA, which incorporates following facilities in the existing refinery. Facilities under BS-IV project

30 % Revamp for the existing DHDT unit from 2.2 to 2.86 MMTPA

30% Revamp for the existing DHDS unit from 1.7 to 2.2 MMTPA

30% Revamp for the existing VGO-HDT unit from 2.1 to 2.73 MMTPA

Facilities under BS-VI project

A new DHDT unit of 2.0 MMTPA Capacity

A new FCC Gasoline Desulphurization unit of 700 KTPA capacity

A new HGU of 72.5 MMTPA capacity

30% revamp of NHT-CCR unit, 20% revamp of ISOM unit

7.2.1 Refinery Configuration Options

Based on the above considerations, a comprehensive LP model was developed to analyze the various configuration options agreed in the design basis for the refinery expansion to 18.0 MMTPA Since the result of draft FR issued during Aug-2016(wherein diesel maximization was considered) showed poor IRR value (as diesel price is much lower compared to gasoline price), emphasis has been given to production of higher price petrochemical product/feedstock and gasoline fuel. A total of five configuration options were studied in detail covering total persona of various secondary processing options, alternate option for bottom processing, and production of petrochemical product. For all the configuration option analyzed, a major endeavor in the model development had been given to maximize the utilization of existing units.



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a. Primary Processing Units

. A new CDU/VDU of 15.0 MMTPA capacity has been considered after dismantling of AU I, AUII, AUIII, AU IV, FPU I & VDU and by creating an additional capacity of 4.3 MMTPA. The dismantling of existing AUs, FPU I and VDU has been considered to replace old small units with a new higher capacity unit to increase the efficiency and ease of operation. Existing AU V (Design capacity: 3.0 MMTPA) and FPU II units have been retained.

b. Secondary Processing Unit

In the report submitted in Aug-2016, wherein HCU along with SDA was the configuration considered which resulted in poor IRR because of high diesel production, which is not so favorably priced. Considering that gasoline and petrochemical feedstock/product fetches a higher price secondary processing option have been considered with FCC and INDMAX units producing higher yield of gasoline and petrochemical feedstock like propylene. Additionally, MS block units have been considered in all cases to upgrade naphtha (from expansion and existing which is currently being exported) to gasoline.

Based on the above following secondary processing options have been considered.

Low CCR INDMAX FCC unit (INDMAX with VGO feed )

High CCR INDMAX FCC unit (INDMAX with VGO+VR feed) to handle additional VR

Conventional FCCU

c. Bottom Processing Unit

The result of the FR issued during Aug-2016 shows that SDA-DCU combination option to process the additional VR generated does not fetch much uplift in the economics, robust technologies like an Ebullated hydrocracker unit (EB HCU) with a conversion upto 75% into distillates is considered for bottom up gradation. The DCU capacity is considered to be saturated in all the cases analyzed for utilizing existing unit capacity fully.

d. Treating Units

Gasoline -Gasoline treatment unit shall be considered as required to treat INMDAX FCC gasoline to meet the BS VI specification.

Diesel/Kero -Diesel or kerosene treating units shall be considered as required. Revamp of BS VI DHDT may be considered for treating additional diesel produced.



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e. Polymer Units

A Polypropylene unit is considered as an additional case to polymerize propylene available from INDMAX FCC unit to improve the sales revenue.

f. Auxiliary Unit

Hydrogen Generation Unit –As sufficient quantity of hydrogen generation is expected from new CCRU and due to balance capacity available in BS VI HGU, a new HGU unit is not considered. Sulphur Block –Additional sour water and sour gas generation due to high sulphur crude under expansion project warrant incremental sulphur removal which shall be met by new sulphur block units. In view of above considerations following 5 different configuration options have been analyzed targeting a higher IRR.

Table 7.2.1Configuration Options Analyzed

Sl. No Case Description (Note 1)

1. Base case + Low CCR INDMAX FCC+ PPU+ Ebulated Bed HCU

2. Base case+ High CCR INDMAX FCC+ PPU (Note-2)

3. Base case+ Low CCR INDMAX FCC+ Propylene sales+ Ebulated Bed HCU

4. Base case+ High CCR INDMAX FCC+ Propylene sales (Note-2)

5. Base case+ Conventional FCCU+ Ebulated Bed HCU

Notes:

1. It may be noted that the requirement of treating and auxiliary units are equally applicable to all options.

2. Preliminary analysis shows that the requirement of a bottom up

gradation facility can be ruled out in case of High CCR INDMAX FCC consideration and by utilization of DCU at full capacity on VR feed.

7.2.2 Configuration Study approach



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The approach adopted in this study is as below:

Model of BS VI at 13.7 MMTPA is considered as the base case LP model.

Development of LP model for 100% BS VI at 18.0 MMTPA with a new CDU/VDU of 15.0 MMTPA, AU V and FPU II.

Low sulphur North Gujarat crude has been considered as feed to AU V unit to ensure the availability of low sulphur VGO to feed existing HCU and to ensure the availability of low sulphur VR and Vac slop streams as blend components to IFO.

Model for secondary processing options, treating and auxiliary units are developed and incorporated in the LP run for respective option analyzed.

LP model runs are taken at three year avg. prices of crude and products.

Configuration screening is carried out based on gross refining margins, preliminary capital cost involved, preliminary estimation of IRR and pros& cons of each new technology considered.

Selected configuration option was subjected to further detailed study and rigorous financial.

7.2.3 LP Model

General EIL use PIMS (Process Industry Modeling Systems) LP Software to develop the comprehensive LP Model of Refinery. Liner Programming (LP) is a mathematical technique for determining the most optimum allocation of resources to achieve a particular objective when there are alternative uses for the resources. Optimizing the operation of refinery or the determination of the optimal configuration is a typical application of linear programming. The refinery is described by a set of given equations and/ or inequalities (m) involving variables (n), and solved by finding the non-negative values of these variables which satisfy the equations and inequalities and also maximize the objective function or profit. This analysis involved the creation of a model that represented nearly 2000 equations and/or inequalities and more than 2000 variables. The Equations represent: Feed availability, plant capacity and possible stream routings.



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The Variables represent: Amount of feeds purchased and products made, operating variables and actual stream disposition. The Objective function is being maximized, typically product value less raw material and operating costs.

Overview of LP model

The following sections briefly describe the input data (and its source) and alternate stream dispositions. These greatly affect the final results of the LP Model. The LP model developed uses mostly weight based units and some volume based units to better handle the material balance around the refinery complex. The whole model operates on a weight basis. The architecture of the LP model can be broadly defined by the following key components. As a matter of convention these are labeled as ‘Tables’.

Buy & Sell tables (Feeds, Products & Utilities)

Assay tables/Distillation tables (Crude assay and crude unit product yields & properties)

Sub-model tables.

Blends tables(Product blend specifications, Blend mix)

Various other tables for defining various constraints and inputs are available but are not detailed in this report. The following pages describe briefly the importance of the above tables in the overall LP optimization.

Buy & Sell Tables These tables define the maximum & minimum quantities of feeds/utilities permitted for purchase and also that of products permitted for sales. The prices of these streams are also defined here. Products which are selling on volume basis in actual Refinery operations, prices were given in Rs/KL and products which are selling on weight prices were given on Rs /MT basis.

Sub-model Tables

Sub-models are the building blocks of an LP model. All the process units and utility producing units are represented by various Sub-models. The optimizer tool optimizes the interaction between the various sub-models and other tables and thereby creates a “flow” between sub-models. This flow between sub-models eventually results in an optimized configuration scheme. Given below are the major sub-models in LP.



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Process Unit Submodels Process unit sub-models require yields which are either in weight or volume basis. Weight based yields have been used for all the process submodels. Typically the yields will be given in the following format:

Base Yield for every unit

Delta yields as required.

Crude Assay & Crude/Vacuum distillation Unit The Crude/vacuum unit is not a sub-model in LP but is defined in Assay tables. However, for the sake of simplicity it is described as submodel. Spiral Crude manager has been used to generate yields and properties for various cut points as envisaged. Crude and Vacuum units are modeled in single submodel. Utilities for all the units are also considered.

Utility Submodel The Utility submodel produces all the utilities required by process units. Utility requirements for each process unit are defined in respective process submodel.Accurate utility estimates are essential to predict the fuel & loss of the refinery complex and also operating costs. In this study the utility requirements considered are annualized operating utility requirements. Utilities typically tracked in by LP model are:

Power, (KWh)

Steam (MT)

Fuel (fuel gas or fuel oil in terms of MMkcal/hr or tons)

Utility requirement is entered in the LP model in one of the following ways.

Unit of feed (weight or volume, for example for power KWH/ton of feed processed)

Unit of product (weight or volume, for example in H2 plant KWH/ton of H2 produced)

Captive Power plant Power & steam are generated in the captive power plant (CPP) submodel. Power plants such as GT, STGand Utilityboilers are modeled based on data furnished by IOCL and in-house data available.However, the final power and steam balances are carried outside the LP model.

Refinery fuel balance Refinery fuel is another important utility tracked by the LP model. Refinery Fuel requirement is met by refinery fuel gas and internal fuel oil .Fuel requirement is



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defined in each process sub-model and hence total refinery fuel requirement is known in terms of MT of fuel oil equivalent/Annum.

Sulphur Recovery unit One additional Sulphur recovery unit is modeled alongwith other process units to track H2S produced from various process units. Sulphur recovery of SRU is considered as 99.9 % for this study. However, the final sulphur balance and estimation of SRU capacity are carried outside the LP model.

Product Blending

The following blend tables are configured as part of LP model development:

Blend Mix: Defines the streams that are allowed for blending to produce the desired product.

Blend properties: Defines the properties of various blend streams identified for blending in Blend Mix table

Blend specs: Defines the product specifications required to be achieved by LP model.

7.2.4 Refinery economics

For each case as estimated by LP model are as follows:

The refinery gross margin which is equal to product revenues minus feedstock costs is calculated for base case and expansion cases. Incremental GRM i.e. Expansion cases GRM minus base case GRM is used for economic analysis.

The refinery variable operating costs estimated by LP model. variable operating cost include the cost of providing catalyst and chemicals in support of ongoing refinery operations

The cost of purchasing utilities is normally included in variable operating costs. However all the utilities required for this project are generated internally.

Total project cost for J-18 expansion is estimated outside LP model using in-house spread sheet based model.

The components involved in estimation of total project cost are:

Plant & Machinery

Offsite & Utilities

Plant & Machinery

EPCM Charges

Licensor Royalty Charges



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BDEP Charges

1st Charge Of Catalyst

Contingency

Financing Charges

The basis for each of the above components used is explained below:

Capital cost for the new unit estimated based on large in-house data/ licensers data and appropriately applying capacity factors for each case.

Based on the above the total new process units cost is estimated.

Utilities & offsite costs are estimated based on LP run results and outside LP run based on in-house data bank.

Summation of Process unit costs and utilities & offsite costs result in Plant & Machinery cost.

Miscellaneous costs including roads, buildings are estimated based on preliminary MTO generated.

Licensor Royalty charges, BDEP fees and costs for 1st charge of catalyst are estimated based on in-house data.

Contingency of 10% is considered reasonable at this stage of the study.

7.2.5 Base Case configuration

Key Considerations

Crude mix and crude disposition are considered in base case as per the input data provided by IOCL.

For respective crudes that are processed in the Crude units, the product yields are based on the input data provided by IOCL and the details of the same are provided in Annexure C to chapter 4, Design Basis. TBP cut points corresponding to these yields are established using in-house tools.

Crude assay for North Gujarat, South Gujarat and Mangla crudes are based on data provided by IOCL. For Kuwait crude, latest recommended assay data available in Chevron Library is considered.

For further details and considerations pertaining to Base case, reference can be made to the finalized configuration of FR prepared for BS VI at 13.7 MMTPA, dated January 2016.Further to this, the following modifications have been made in the base case later on.



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Hydrogen balance has been updated based on IOCL input on operating

data and licenser data for VGO-HDT (BS IV project) and BS VI DHDT (BS VI project).

25% of the total gasoline production has been considered as premium grade.

7.2.6 Key considerations for refinery configuration at 18.0 MMTPA

Major considerations involved in the development of LP model for 100% BS-VI products at 18.0 MMTPA for aforementioned cases and further analysis of LP run results are described hereunder.

A new CDU/VDU of 15.0 MMTPA capacity has been considered after dismantling of AU I, AU II, AU III, AU IV, FPU I & VDU and by creating an additional capacity of 4.3 MMTPA.

The TBP cut points of new CDU/VDU is considered same as that of existing AU IV & VDU. The cut range for heavy naphtha product is retained at 140-152 0C to meet design Kerosene feed requirement of LAB unit. Hence new CDU/VDU shall be operated in block out mode to produce heavy naphtha with a cut range of 140-180 0C to feed to new MS block and to produce MTO product with a distillation range: IBP: 1450C FBP: 215 0C.

All efforts have been taken to minimize naphtha sales by routing existing naphtha blend components to new MS block along with naphtha produced from capacity expansion.

No PNCP Naphtha sale is considered.

Part of Hy reformate stream routed to IOCL GR in base case has been considered as blend component of gasoline pool in expansion case.

All efforts have been kept to avoid any requirement of a new DHDT unit by consideration of BSVI DHDT revamp. A kerosene hydrodesulphurization unit (KHDS) with lower hydrogen requirement shall be considered to treat kerosene streams before blending to diesel pool.

Zero kerosene sales is considered.

As per IOCL request, Revamp of existing LAB unit from 120 to 165 KTPA had been considered in the initial analysis of configuration study. However the revamp consideration has been later excluded from J-18 and not considered in detailed study of selected case. Further an additional case has been carried out with addition of a new LAB unit of 150 KTPA capacity along with the selected case.

For all the configuration option analyzed, a major endeavor in the model development had been given to maximize the utilization of existing units. As a result of this existing DCU, VGO-HDT and FC HCU units have been fully saturated.



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Based on preliminary analysis EB HCU for bottom processing has not been considered in the option with High CCR INDMAX FCC unit as VGO processing unit. The VR is routed to INDMAX unit.

No Fuel Oil sales is considered for 18.0 MMTPA configuration.

The capacity utilization of BBU is restricted to 480 KTPA based on projected demand of the product.

As advised by IOCL the maximum capacity utilization of existing HGU III and BS VI HGU is considered as 90% of the design capacity.

To improve the operating efficiency, the old HGU I unit shall be considered as not operating if balance capacity is available in BS VI HGU to meet the hydrogen demand.

Coke make has been considered based on yield given by DCU licensor for % CCR of the feed mix of pitch and VR.

The existing CRU had been considered as operating in initial analysis of the configuration study, however the same has been considered as not operating during the detailed study of the final selected case. The heavy naphtha feed to CRU shall be processed in new MS block.

The crude and Product prices considered for 100% BS VI at 18.0 MMTPA configuration has been revised as avg. price of FY 2014-17. The avg. price of feed and products have been tabulated below.

Table 7.2.2 Feed Prices (Rs/MT)

Crude 3 Year Avg. price

(FY 2014-17)





Kuwait 27067

LNG/RLNG 31770

Methanol 24248

Benzene 38628

The cost of import power is 8.32 Rs/ Kwhr

Table 7.2.3 Product Prices (Rs/MT)



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Product 3Year Avg. price

(FY 2014-17)

LPG 32972

Propylene 46608

Polypropylene 82459

Naphtha Export 32287

PNCP Naphtha 32287

Food Grade Hexane 57562

MS BS-VI (Normal grade)- Domestic

42659

MS BS-VI (Normal grade)-Export 40992

MS BS-VI (Premium grade grade) 42659

HY. REFORMATE TO IOCL GR

34117

SKO 36962

MTO 48493

PCK 36376

ATF 36714

LAB 87103

HSDBS-VI 36376

LAB Hy alkylate 56230

FO sales 22478

Bitumen VG-10 21107

Bitumen VG-30 23558

HS Coke 4108

Sulphur 7977

The additional Power requirement for expansion over the available capacity of 135 MW from existing refinery shall be met by import from grid.

Details of new Units:



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New CDU/VDU New CDU/VDU is considered to be processing the following different crude mix.

Table 7.2.4Crude mix in New CDU/VDU

Crude Crude- KTPA

South Gujarat 1700

North Gujarat 700

Mangla 800

Kuwait 7500

Basrah Lt 4300

Total Thr’put 15000

The TBP Cut points and yields considered in new AVU is provided in table 7.2.4 below.

Table 7.2.5 TBP cut points and Yield pattern for new CDU/VDU

Stream TBP Cut Points

(oC) Yield

(% Wt.)

Gases+ LPG C1-C4 1.2

Stabilized naphtha C5-140 13.3

Hy. cut naphtha (Note-1) 140-152 1.6

SKO (Note-1) 152-231 11.6

HSD 231-352 19.2

Vac diesel 352-381 4.9

VGO 381-535 22.5

Vac Slop 535-560 2.8

VR 560+ 23.1

Note-1:

The cut range of hy naphtha and SKO while maximizing hy naphtha cut to feed to MS bock shall be 140-180 0C and 180-2310C respectively. Corresponding yields are 5.8 and 7.4 % respectively. Block out mode operation may be considered for the same.



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Ebullated Bed Hydrocracker (EB HCU)

EB HCU process is a commercially proven technology for conversion (in the range of 70-75%)and up gradation of vacuum residue. Theprocess uses catalytic ebullated bed reactor. The catalyst used in the reactor is held in a fluidized state through the upward lift of liquid reactants (feed oil and recycle) and hydrogen gas. Catalyst is replaced periodically in the reactor without shutdown. Typical feed to an ebullated bed hydrocracker unit is vacuum residue with relatively high CCR and contaminant metals.

The process operates at high severity and utilizes a daily replacement of catalyst to remove contaminant metals and maintain a constant bulk reactor activity level. This results in production of constant product quality and yield selectivity. All the products from the unit required further processing and treatment. Unconvertedoil from this unit can be used as fuel oil or alternatively processed in the existing DCU. Currently the technology is being licensed by M/s Chevron and M/s Axens. The unit is configured to accept VR from new CDU/VDU and FPU II, CLO from existing FCC and INDMAX FCC unit in the LP model.

INDMAX FCC unit

INDMAX FCC is an indigenous technology developed by IOCL to produce high yield of propylene and gasoline by processing various petroleum fractions. The gasoline product of INDMAX FCC is characterized with high octane value and light olefin compounds. The specialty catalyst system of INDMAX FCC unit is featured with low coke and dry gas make with high metal tolerance and selectivity towards light olefins. The unit can process heavy fractions up to a feed carbon residue of 6 wt. % CCR. INDMAX FCC unit while designed for low carbon residue feed, up to 1.5 % wt. % CCR unit is considered as Low CCR INMDAX, while if it can accept heavy feed up to 6 wt. % CCR it is considered as High CCR INDMAX FCC unit. In the current configuration study both Low CCR and High CCR INDMAX units are considered for VGO oil up-gradation. In Low CCR INDMAX option, Ebullated Bed Hydrocracker (EB HCU) has been considered for bottom up gradation and INDMAX FCC shall accept only VGO cut streams. In LP model options provision for processing of VGO and Vac slop from new CDU/VDUEB HCU VGO and HCGO is kept in Low CCR INDMAX FCC unit.But for High CCR INDMAX FCC option for processing VR from new



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CDU/VDU is also provided along with above streams except EB HCU VGO, as EB HCU unit is not considered in this case. The INDMAX process like a conventional FCC unit basically cracks the high-boiling, high molecular weight hydrocarbons into lower-boiling, lower molecular weight olefinicand aromatic hydrocarbons in presence of catalyst. The cracked LPG product from this unit is treated in LPG Merox unit. Gasoline diesel products shall be treated to meet the product blend spec. requirement. Heavy CLO product shall be further processed in the DCU or EB HCU. Due to high sulphur nature of feed considered, the flue gas generated in the unit shall be desulphurized to meet emission requirement.

Diesel/kero treating units

The diesel/ kero treating units processes the diesel/ kero cuts to remove sulphur and to meet BS VI specification of diesel pool. As zero kerosene product has been considered all treated kerosene streams is considered as blend components in either diesel or ATF product. The requirement of a new diesel hydro treating unit shall be avoided by consideration of a new KHDS unit to process additional kerosene produced from expansion and existing kero streams being treated in DHDT/DHDS units. The capacity thus made available in existing DHDT/DHDS and balance capacity available in BS VI DHDT shall be utilized to process SR diesel generated form expansion, LCO product from INDMAX FCCU and diesel stream form EB HCU. Further to this, revamp of BS VI DHDT shall also be considered, if required.

MS Block Units

MS Block units have been considered to upgrade naphtha streams to produce gasoline product meeting the BS VI spec. The objective also aims for minimum naphtha product sales from the refinery. MS block consists of a common NHT/NSU which shall accept all naphtha streams available and hydro treat the streams to remove sulphur, nitrogen etc. Hydro treated naphtha stream shall be further spitted to light (C5-90 TBP) and heavy streams (90-180 TBP)to process in an Isomerization and Continuous Catalytic reformer unit (CCRU). Light naphtha streams are processed in the ISOM unit to improve octane numbers by the use of isomerization reaction to converts normal paraffins into their isomers. Some hydrocracking occurs during the reactions resulting in a loss of gasoline and production of light gas. Hydrogen is used to suppress

http://en.citizendium.org/wiki/Molecular_weight

http://en.citizendium.org/wiki/Hydrocarbons

http://en.citizendium.org/wiki/Hydrocarbons



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the dehydrogenation and coking. In the current configuration 95% yield of isomerate with RON of 86 is considered form the ISOM unit. The Continuous Catalytic Reforming Unit (CCRU) processes the heavy naphtha stream to make it more suitable for the production of motor gasoline. The reforming process involves chemically rearranging the hydrocarbon molecules to produce higher-octane materials. The octane number is a key measure of motor gasoline performance. Hydrogen gas is produced as a byproduct of reformingand is used as feed to distillate Hydrotreater Unit. CCRU is considered to deliver reformate yield of 90% with a RON of 98 in the current configuration. The LP run model is provided with option of feeding the flowing streams into the MS block units. SR naphtha Existing DHDT & DHDS naphtha BS VI DHDT naphtha HCU naphtha VGO Hydrotreater naphtha DCU naphtha EB HCU naphtha LAB wild naphtha LAB stripper O/H Lt reformate from existing MSQU FGH Raffinate

Gasoline Desulphurization Unit

A gasoline desulphurization unit is considered for removal sulphur from INDMAX FCC unit to meet BS VI spec. of gasoline product. The unit ensures selective hydrogenation of sulphur containing compounds with minimum olefins saturation. This ensures minimum loss of octane number across the unit. In LP model only INDMAX FCC gasoline is considered as feed to the unit. A RON loss of 3-4 units has been kept across the unit due high sulphur nature of INDMAX FCC gasoline feed. The treated gasoline is characterized with a sulphur content of 8 ppm.

Polypropylene Unit

A polypropylene unit converts propylene obtained from INDMAX FCC unit into a sellablepolypropylene polymer in pellet forms.

New Sulphur Recovery Unit



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One additional Sulphur recovery unit is modeled to track H2S produced from additional process units. Sulphur recovery of all the SRUs is considered as 99.9 % for this study along with Tail Gas Treating Unit to reduce the overall SOx emissions. However, the final sulphur balance and estimation of SRU capacity are carried outside the LP model.

7.2.7 Results of Configuration study

Results of configuration study is summarized and classified based on LP run carried out for each cases. This section includes the preliminary results summarized including feed and product slate, utility purchase, capacity utilization of existing units and capacities of new units required.

Table 7.2.7: Feed & Product slate for different cases

CONFIG. OPTIONS

BASE CASE (100%

BS VI at 13.7)

CASE 1- EB

HCU+

LOW CCR

INDMAX+ PPU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB

HCU+

LOW CCR

INDMAX+ PROP. SALES

CASE 4-HIGH CCR

INDMAX+ PROP. SALES

CASE 5- EB

HCU+

FCCU

FEEDPURCHASES IN KTPA

NORTH GUJARAT 3700 3700 3700 3700 3700 3700

SOUTH GUJARAT 1700 1700 1700 1700 1700 1700

MANGALA 800 800 800 800 800 800

KUWAIT 7500 7500 7500 7500 7500 7500

BASRAH LT. 0 4300 4300 4300 4300 4300

RLNG 614 856 786 854 784 882

METHANOL 11 11 11 11 11 11

BENZENE 18 35 35 35 35 35

TOTAL 14343 18902 18832 18900 18830 18928



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CONFIG. OPTIONS

BASE CASE (100%

BS VI at 13.7)

CASE 1- EB

HCU+

LOW CCR

INDMAX+ PPU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB

HCU+

LOW CCR

INDMAX+ PROP. SALES

CASE 4-HIGH CCR

INDMAX+ PROP. SALES

CASE 5- EB

HCU+

FCCU

UTILITY PURCHASE

IMPORT POWER IN MW

0 71.3 65.9 55.9 47.8 63.6

PRODUCTS SALES IN KTPA

LPG 500 1027 1030 1027 1030 939

POLYPROPYLENE 0 338 396 0 0 -

PROPYLENE 0 0 0 341 399 -

NAPHTHA EXPORT 986 0 0 0 0 0

LAB 120 165 165 165 165 165

FGH 14 14 14 14 14 14


DOMESTIC

1398 2200 2200 2200 2200 2200


462 0 0 0 0 0

BS VI GASOLINE -EXPORT

0 2349 2548 2349 2548 2614


60 0 0 0 0 0

SKO 500 0 0 0 0 0



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CONFIG. OPTIONS

BASE CASE (100%

BS VI at 13.7)

CASE 1- EB

HCU+

LOW CCR

INDMAX+ PPU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB

HCU+

LOW CCR

INDMAX+ PROP. SALES

CASE 4-HIGH CCR

INDMAX+ PROP. SALES

CASE 5- EB

HCU+

FCCU

MTO 0 140 140 140 140 140

ATF 400 650 650 650 650 650

PCK 70 140 140 140 140 140

BS VI HSD 6804 8263 7901 8263 7901 8481

SULPHUR 102 200 200 200 200 200

BITUMEN 430 480 480 480 480 480

FO SALES 408 0 0 0 0 0

COKE 663 994 1007 994 1007 1052

TOTAL 12918 16972 16883 16975 16886 17087

FUEL & LOSS 10.40% 10.72% 10.83% 10.70% 10.80% 10.23%

Table 7.2.8: Unit capacities for different cases

CONFIG. OPTIONS

BASE CASE (100% BS VI

at 13.7)

CASE 1- EB HCU+

LOW CCR

INDMAX+ PU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB HCU+

LOW CCR

INDMAX+ PROP. SALES

CASE 4-HIGH CCR

INDMAX+ PROP. SALES

CASE 5- EB HCU+

FCCU

EXISTING/BS VI UNITS



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CONFIG. OPTIONS


at 13.7)

CASE 1- EB HCU+

LOW CCR

INDMAX+ PU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB HCU+

LOW CCR

INDMAX+ PROP. SALES

CASE 4-HIGH CCR

INDMAX+ PROP. SALES

CASE 5- EB HCU+

FCCU

AU I 1400 0 0 0 0 0

AU II 1400 0 0 0 0 0

AU-III 2600 0 0 0 0 0

AU-IV 4300 0 0 0 0 0

AU-V 4000 3000 3000 3000 3000 3000

FPU-II 2867 2019 2019 2019 2019 2019

VDU 1200 0 0 0 0 0

FPU-I 2500 0 0 0 0 0

MSQU 780 780 780 780 780 780

ISOM SPLITTER 496 496 496 496 496 496

MSQU SPLITTER

445 445 445 445 445 445

ISOM 276 276 276 276 276 276

CRU 335 335 335 335 335 335

UDEX UNIT 125 125 125 125 125 125

FGH UNIT 97 97 97 97 97 97

MTBE 220 220 220 220 220 220

LAB UNIT 120 165 165 165 165 165



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CONFIG. OPTIONS


at 13.7)

CASE 1- EB HCU+

LOW CCR

INDMAX+ PU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB HCU+

LOW CCR

INDMAX+ PROP. SALES

CASE 4-HIGH CCR

INDMAX+ PROP. SALES

CASE 5- EB HCU+

FCCU

EXISTING DHDT UNIT

2717 2860 2860 2860 2860 2860

DHDS UNIT 1935 2165 2092 2165 2092 2143

FCC 1800 1800 1800 1800 1800 1800

VGO-HDT UNIT 2565 2730 2730 2730 2730 2730

Existing HCU 1433 1400 1400 1400 1400 1400

DCU 3314 3700 3700 3700 3700 3700

HGU PDS 239 256 258 256 258 253

BBU 432 480 480 480 480 480

HGU I 32 0 0 0 0 0

HGU II 0 0 0 0 0 0

HGU III 62 65.3 65.3 65.3 65.3 65.3

FCC GDS UNIT 668 700 700 700 700 700

BS VI DHDT UNIT

1395 2000 2000 2000 2000 2267

BS VI HGU 16 44.8 27.5 44.8 27.5 46.5

SRU 102 102 102 102 102 102

NEW UNITS



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CONFIG. OPTIONS


at 13.7)

CASE 1- EB HCU+

LOW CCR

INDMAX+ PU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB HCU+

LOW CCR

INDMAX+ PROP. SALES

CASE 4-HIGH CCR

INDMAX+ PROP. SALES

CASE 5- EB HCU+

FCCU

NEW CDU/VDU

15000 15000 15000 15000 15000 15000

LOW CCR INDMAX

2025 - 2025 - - 2025

HIGH CCR INDMAX

- 2350 - 2350 - -

FCCU - - - - 2100 -

EBULLATED BED HCU

600 - 600 - 600 600

GDSU 375 625 375 625 650 375

PRU 338 400 - - - 338

NHT/NSU 2100 2050 2100 2050 2150 2100

CCRU 1250 1225 1250 1225 1300 1250

ISOM UNIT 950 975 950 975 1025 950

KHDS 700 700 700 700 700 700

SRU (TPD) 300 300 300 300 300 300

REVAMP FOR EXISTING UNITS

BS VI GDSU REVAMP FOR PROCESSING FEED

WITH SULHUR SPEC HIGHER THAN DESIGN FEED (QUALITY REVAMP)

LAB UNIT REAVAMP FROM 120 TO 165 KTPA



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CONFIG. OPTIONS


at 13.7)

CASE 1- EB HCU+

LOW CCR

INDMAX+ PU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB HCU+

LOW CCR

INDMAX+ PROP. SALES

CASE 4-HIGH CCR

INDMAX+ PROP. SALES

CASE 5- EB HCU+

FCCU

BS VI DHDT UNIT

- - - - -

REVAMP FOR

ADDITIONAL CAPACITY

OF 275 KTPA

7.2.8 Economic summary

The following table shows the gross refinery margin in Rs crore/annum and US$/bbl based on total product sales at the prices indicated in the basis of study.

Table 7.2.9: Preliminary Economic summary

CONFIG. OPTIONS

CASE 1- EB HCU+

LOW CCR INDMAX+

PPU

CASE 2-HIGH CCR

INDMAX+ PPU

CASE 3- EB HCU+

LOW CCR INDMAX+

PROPYLENE SALES

CASE 4-HIGH CCR INDMAX+

PROPYLENE SALES

CASE 5- EB HCU+

FCCU

GRM

(US $/barrel) 12 12.3 10.7 10.8 10.6

Expected Capex (Rs

crore) 15540 14850 13970 13120 12810

Expected IRR (Post Tax On

Capex) 16% 17.5% 13.5% 14.7% 14.3%

7.2.9 Short listing of single case for Detailed analysis



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Based on the above summary, preliminary analysis indicates that for options with Polypropylene production (Case 1 & 2) GRM is much higher as compared to other cases and bring better return on investment. However case 1 with low CCR INDMAX results in an additional bottom processing facility (Ebullated bed HCU), resulting a much higher Capex than case 1. At the same time the capacity of this facility is below the economic threshold capacity of EB HCU. Therefore higher investment in case 1 with approximately same GRM results in poor IRR as compared to case 2.

Based on the results presented in sections above, configuration option with High CCR INDMAX and PPU emerges as the most optimum configuration within the ambit of various constraints considered. Hence this option is recommended to be taken for further analysis for Capex estimation of +30% accuracy along with IRR. The revamp consideration of existing LAB unit was not further considered in the selected case, however an additional case analysis was carried out with the addition of a new LAB unit of 150 KTPA. Further, existing CRU is considered as not operating in further analysis and heavy naphtha feed of CRU is considered as feed in the new MS block envisaged. Premium gasoline sales same as that in Base case is considered in the selected configuration.

7.2.10 Material Balance for selected case and additional case (With new LAB unit)

Table 7.2.10: Selected case Material Balance & additional case

FEED/ PRODUCT


SELECTED CASE

ADDITIONAL CASE

(WITH NEW LAB)

FEED

NORTH GUJARAT 3700 3700 3700

SOUTH GUJARAT 1700 1700 1700

MANGALA 800 800 800

KUWAIT 7500 7500 7500

BASRAH LT. 0 4300 4300



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FEED/ PRODUCT


SELECTED CASE

ADDITIONAL CASE

(WITH NEW LAB)

RLNG 614 774 840

METHANOL 11 11 11

BENZENE 18 18 74.3

TOTAL 14343 18803 18925

UTILITY PURCHASE

IMPORT POWER IN MW

0 63 77

PRODUCT SALES

LPG 500 1045 1041

POLYPROPYLENE 0 402 402

NAPHTHA EXPORT 986 0 0

LAB 120 120 270

FGH 14 14 14


DOMESTIC

1398 1738 1738


462 462 462


EXPORT

0 2527 2490



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FEED/ PRODUCT


SELECTED CASE

ADDITIONAL CASE

(WITH NEW LAB)


60 0 0

SKO 500 0 0

MTO 0 120 120

ATF 400 650 650

PCK 70 140 140

BS VI HSD 6804 8013 7942

SULPHUR 102 200 200

BITUMEN 430 480 480

FO SALES 408 0 0

COKE 663 993 993

LAB HY. ALKYLATE 0 8 18

TOTAL 12918 16913 16961

FUEL & LOSS 10.40% 10.50% 10.91

7.2.11 New Unit capacities& Revamp of Existing Units

Table 7.2.11: New Unit capacities & Revamp of existing units

UNIT CAPACITY IN KTPA-

SELECTED CASE

CAPACITY IN KTPA-ADDITIONAL CASE

(WITH NEW LAB)

NEW CDU/VDU 15000 15000

HIGH CCR INDMAX 2387 2387



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UNIT CAPACITY IN KTPA-

SELECTED CASE

CAPACITY IN KTPA-ADDITIONAL CASE

(WITH NEW LAB)

PRU 400 400

GDSU 638 638

NHT/NSU 2050 2313

CCRU 1581 1478

ISOM UNIT 922 947

KHDS 838 -

LAB UNIT - 150

SRU- TPD 300 300

SWS-TPH 330 330

ARU-M3/HR 300 300

REVAMP UNITS

BS VI GDSU

REVAMP FOR PROCESSING FEED

WITH SULHUR SPEC HIGHER THAN DESIGN FEED

(QUALITY REVAMP)

-

7.2.12 Preliminary financial analysis between selected case and additional case

A preliminary analysis was carried out between selected case and additional case with a new LAB unit of 150 KTPA capacity based on licensor input on capital cost of new LAB. It was found that with a new LAB unit additional Capex is in the order of 3500 Crore, and due to which the IRR drops by around 2%. Based on which, NO new LAB unit is not considering for further analysis of J-18 study. Hence the case with New AVU (15.0 MMTPA) +HIGH CCR INDMAX+MS BLOCK+GDSU+KHDS+PPU is retained as selected case for detailed analysis



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7.2.13 Refinery Hydrogen Balance for selected case

The hydrogen balance for final selected case and base case are tabulated below. Base case hydrogen balance has been updated based on IOCL input on operating data and licenser data for VGO-HDT (BS IV project) and BS VI DHDT (BS VI project).

Table 7.2.12: Hydrogen Balance for selected case

UNIT Selected case

In KTPA Base case in KTPA

Generation

HGU I 0 32.3

HGU II 0 0

HGU III 65.3 65.3

BS VI HGU 16.7 16

OFF GAS PSA 5 5

Existing MSQU 32 32

New CCRU 54.3 -

TOTAL 173.3 147.0

Consumption

Existing HCU 35.3 36

DHDS 23 20

Existing DHDT 43.3 41

ISOM 2.3 2.3

PDS 6 5.3

VGO-HDT 28 26

LAB UNIT 1.3 1.3



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UNIT Selected case

In KTPA Base case in KTPA

BS VI GDSU 1 0.7

BS VI DHDT 16.3 14.3

New NHT 3 -

New ISOM 4.7 -

New GDSU 2 -

KHDS 7.3 -

TOTAL 173.3 147.0

7.2.14 Potential for Additional premium gasoline production

The potential for additional production of premium grade gasoline was analyzed and it was found that the refinery shall be capable of producing 100% domestic gasoline in the premium grade after implementation of expansion project with the following considerations.

Higher reformate RON of 103 units as against present value of 98

Higher isomerate RON of 89 units as against present value of 87



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FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO FUEL


SECTION 7.3

PROCESS DESCRIPTION



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FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA WITH 100% BS-VI AUTO


7.3 Process Description

7.3.1 Introduction

A brief process description along with a flow schematic for each of the following new process units envisaged as part of refinery expansion from 13.7 to 18.0 MMTPA with revised configuration are provided in this section.

1. Crude and Vacuum Distillation Unit

2. INDMAX FCC Unit with Propylene Recovery

3. Kerosene Hydrodesulphurization (KHDS) Unit

4. Naphtha Hydrotreater unit (NHT)

5. Continuous Catalytic Reformer Unit (CCRU)

6. Isomerization Unit

7. Gasoline Desulphurization Unit (GDSU)

8. Polypropylene Unit (PPU)

9. Sulphur Recovery Unit (SRU)

10. Sour Water Stripper Unit (SWS)

11. Amine Regeneration unit

Schematic Flow Diagrams for all the above process units are attached in Annexure III

7.3.2 Crude/Vacuum distillation Unit

The typical scheme for Crude Distillation Unit is shown in Annexure III. (A510-79-41-00-1051) in Annexure III.

Crude Distillation Unit

Crude Charge and Preheat Train-I

Crude from offsite storage is received at CDU/VDU plant battery limit. The crude is subsequently heated in preheat exchangers by hot streams of CDU/VDU. Crude picks up heat in the preheat exchangers before being routed to Crude desalter.

Desalter

A 2-stage electrostatic Crude Desalter to be provided for removal of salt and water from the crude to desired level. The principle of desalting operation requires mixing of preheated wash water in a mixing valve with the crude under controlled conditions and to extract impurities.

Crude Preheat Train-II and Preflash

The crude from Desalter outlet is routed to the 2nd train of pre heat exchangers. Crude picks up heat from hot streams of CDU/VDU and routed to Preflash drum. The liquid separated in the Preflash drum is pumped to crude preheat train-III.

Crude Preheat Train-III



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The pre flashed crude is heated in 3rd preheat train exchangers. Crude picks up heat from hot streams of CDU/VDU and finally routed to crude heater.

Crude Heater

The preheated crude is fed to the crude heater and equally distributed to the heater passes through pass balancer control valve. The total crude flow to the unit signal is sent to the crude throughput controller, which sends signal to the furnace flow controllers.

Crude Distillation Column

Heated and partially vaporised crude enters crude column through feed nozzle. The column has five side draws, namely, Light Naphtha (SN), Heavy Naphtha (HN), Kerosene (Kero), Light Gas Oil (LGO) and Heavy Gas Oil (HGO).

Crude Column Overhead Circuit

The overhead system consists of a two stage condensing system with wash water circulation.

Sour water separated in reflux drum is partly returned as wash water for atmospheric column overhead vapours. All the salt are dissolved in wash water and are purged out of the system through sour water purge stream to sour water stripper unit. Additionally Filming Amine is also injected in the crude column overhead line in order to protect the overhead line.

Light/Heavy Naphtha Section

Naphtha is drawn as side product to side stripper. Stripper is provided with thermosiphon reboiler to knock off light ends from naphtha. The CDU hot stream is used as heating medium in reboiler. The bottom product of light/heavy naphtha stripper is pumped to naphtha product cooler. The cooled product ex-product cooler is finally routed to storage. The light hydrocarbon vapours leaving the naphtha stripper is returned to the crude column.

Kerosene Section

Kerosene product is drawn from crude column. The kero product flows to the kero stripper under stripper level control. Kero stripper is a reboiled stripper using CDU hot stream as reboiling medium. The light hydrocarbon vapours leaving the kero stripper are returned to the crude column.

Light Gas Oil Section

LGO product and LGO CR stream is drawn as a single stream from crude column. One stream as LGO product flows to the LGO Stripper under LGO stripper level control where it is stripped using MP steam under flow control and the stripped vapours are returned back to the Crude Column below.

Heavy Gas Oil Section

HGO product & HGO CR are drawn as a single stream from the Crude Column. One stream as HGO Product flows to the HGO Stripper under stripper level control where it is stripped using MP steam under flow control and stripped vapours are returned back to the Crude Column.

Reduced Crude Oil Section

Stripped RCO from the column bottom is sent to the Vacuum Heater under level control of atmospheric column bottom cascaded with the pass flow controller of Vacuum Heater. MP steam under flow control is introduced as stripping steam of the Crude column.

Crude Column Circulating Refluxes



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Crude Column is provided with three Circulating Reflux streams for optimum vapour-liquid internal traffic and heat recovery.

KERO CR:

Kero CR is drawn along with Kero product and is pumped by Kero CR pump. The heat available in Kero CR is removed in crude preheat exchangers. LGO CR:

LGO CR is drawn along with LGO product and is pumped by LGO CR Pump. The heat available in LGO CR is removed in crude preheat exchangers and reboiler.

HGO CR:

HGO CR is drawn along with HGO product and is pumped by HGO CR Pump. The heat available in HGO CR is removed in crude preheat exchangers and reboiler.

Product Rundown Section

Light/Heavy Naphtha Product Circuit

Light/heavy naphtha from naphtha stripper bottom is pumped by Light naphtha Product pump for heat recovery and then to Naphtha Air cooler followed by naphtha Trim Cooler before sending it for storage.

Kero Product Circuit

Kero product from Kero Stripper bottom is pumped by Kero Product pump. After heat recovery, Kero product is further cooled in product coolers to required rundown temperature and routed to storage.

LGO Product Circuit

LGO Product from LGO Stripper is pumped by LGO product Pump for heat recovery, After Heat Recovery LGO product is further cooled in product coolers to required rundown temperature and routed to storage.

HGO Product Circuit

HGO Product from HGO Stripper is pumped by HGO Product Pump. After heat recovery, HGO product is further cooled in product coolers to required rundown temperature and routed to storage.

RCO Product Circuit

Normally, Reduced Crude Oil (Crude Column residue, RCO) from Crude Column is pumped to vacuum unit with out any cooling. However, provision is kept to cool the hot RCO stream in crude preheat circuit and coolers to facilitate to operate Crude unit alone with out Vacuum unit and route the RCO stream to storage.

Naphtha Stabilizer

Naphtha Stabiliser Column

The unstabilised naphtha consisting of all the fuel gas, LPG and Naphtha components is pumped to Naphtha stabiliser column after preheating in the stabiliser feed/bottom exchanger.

The overhead products are partially condensed in the Stabiliser Overhead Condenser. Fuel gas and LPG are withdrawn from the overhead circuit. Fuel gas is routed to Fuel Gas ATU and LPG is routed to LPG Treater.



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Stabiliser column is a reboiled column using CDU hot stream as reboiling medium. Stabilised Naphtha is further cooled in the exchanger to required rundown temperature before routing the same to the storage.

Vacuum Distillation Unit

Vacuum Heater

Hot RCO from Crude column bottom is pumped by RCO pumps to Vacuum heater.

Each coil outlet of vacuum heater joins the transfer line and is routed to Vacuum distillation column. The mixed vapour & liquid stream from the heater is introduced to the Flash zone of Vacuum column.

Vacuum Distillation Column

Heated & partially vaporised RCO from Vacuum Heater enters the Vacuum Column. An open ended tangential entry device and a large empty space above flash zone ensure optimal vapour liquid separation.

Stripping section:

The heavy hydrocarbons are stripped on valve trays. Subsequently the residue is quenched by the vacuum residue product (Quench) to prevent after cracking in the bottom compartment of the column. The various side streams taken out from Vacuum Column are Vacuum Diesel, LVGO, HVGO and Slop Distillate.

Overhead Circuit:

Overhead vapour from vacuum column goes to the vacuum system. The vacuum system is designed with a two stage ejector and a vacuum pump as the third stage. Sour water from Hotwell is pumped by Hotwell Sour water pumps. Sour water ex-Hotwell flows under interphase level-cascaded flow control for further treatment in sour water stripper unit.

Vacuum Diesel Section:

Vacuum Diesel is drawn and pumped by Vacuum Diesel Product + CR + IR Pump and is divided into 2 streams, namely, Vacuum Diesel IR, Vacuum Diesel CR + Product. Vacuum Diesel IR is returned back under flow control to the Vacuum Column. The product stream is cooled in the Vacuum Diesel Product + CR Trim Cooler

Gas Oil Section:

Gas oil is collected in collector tray and pumped by Gas oil IR pumps under level control along with LVGO CR through spray nozzle distributor.

Light Vacuum Gas Oil Section (LVGO):

LVGO from collector tray is pumped by LVGO Product + CR + IR Pump and is divided into 3 streams, namely, LVGO IR, LVGO CR and LVGO product. LVGO IR is returned back under flow control to the Vacuum Column LVGO CR is cooled in crude/LVGO CR Exchanger before returning back to the Vacuum Column along with Gas oil IR.

Heavy Vacuum Gas Oil section (HVGO):

HVGO from Collector tray is pumped by HVGO Product pumps and HVGO CR + IR Pumps HVGO CR+ IR streams are split into two streams namely HVGO CR & HVGO IR. HVGO product after exchanging heat with crude in crude preheats exchangers is combined with LVGO and the combined VGO is cooled in tempered water cooler before being routed to storage.



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Wash section:

Slop from bed collector tray flows by gravity to the Slop Drum. Slop from this drum is pumped by Slop Distillate Pump and is divided into 2 streams. Vapours rising from flash zone are condensed by HVGO IR and collected as slop in collector tray. This liquid provides the required washing in this section.

Vacuum Residue Section (VR):

(Vacuum Residue + Quench) from Vacuum Column bottom is pumped by VR + Quench Pump to crude preheat train for heat recovery in Crude/VR+Quench exchangers. The VR + Quench stream is then split into two streams and one stream as VR quench is returned back to the Vacuum Column under flow control cascaded with vacuum column bottom stream temperature controller.

Product Rundown section

Hot well vacuum slop oil:

Hot well vacuum slop oil from Hot well is pumped by hot well Slop Oil Pumps through a coalescer and routed to downstream unit for further processing. Sour water from coalescer is routed to sour water rundown line.

Vacuum diesel Product:

Vacuum Diesel from collector tray is drawn and pumped by Vacuum Diesel Product + CR + IR Pump and is divided into 2 streams namely Vacuum Diesel IR, Vacuum Diesel CR + Product. Hot Diesel stream after heat recovery is routed to DHT/DHDS and cold stream after cooling to required rundown temperature is sent to the storage.

LVGO Product

LVGO from collector tray is pumped by LVGO Product + CR + IR Pump and is divided into 3 streams namely LVGO IR, LVGO CR and LVGO product. LVGO is combined with HVGO after heat recovery and the combined stream namely Vacuum Gas oil (VGO) is routed to downstream unit. VGO is further cooled in cooler to required rundown temperature before routed to storage.

HVGO Product

HVGO product from Collector tray is pumped by HVGO Pump. Subsequently HVGO is combined with LVGO after heat recovery and the combined stream namely Vacuum Gas oil (VGO) is routed to downstream unit.VGO is further cooled in cooler to required rundown temperature before routed to storage.

Slop distillate product:

Slop from collector tray flows by gravity to the Slop Drum. Slop from this drum is pumped by Slop Distillate Pump and is divided into 2 streams. One stream is returned under flow control back to Vacuum Column as over flash while the second stream as Slop Product is mixed with Vacuum residue.

Vacuum residue product:

(Vacuum Residue + Quench) from Vacuum Column bottom is pumped by VR + Quench Pump to crude preheat train for heat recovery in Crude/VR + Quench exchangers. The VR + Quench stream is then split into two streams. One stream as VR quench is returned back to the Vacuum Column and other stream VR product is routed to residue processing units such as SDA, BBU after heat



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recovery. VR product is further cooled to required rundown temperature before routed to storage.

Tempered Water System

The cooling of the high pour point products like Vacuum residue & VGO is done by tempered water to prevent exchanger congealing and to reduce exchanger maintenance. Tempered water is pumped from Tempered Water Drum by Tempered Water Pumps to VR/TW cooler and VGO/TW cooler.

Steam Generation Section

Make-up BFW is preheated by VR + Slop rundown stream in VR + Slop/BFW preheater. This make-up BFW then splits into two parts. One of the make-up BFW stream is fed to LP steam drum. The other Make up BFW stream is fed to MP steam drum.

Blowdown

Blowdown from MP steam drum is flashed in a LP flash drum. The flashed condensates from this LP flash drum and blowdown from LP steam drum is sent to Steam Blowdown Drum where it is quenched with service water before draining it to storm sewer.

Chemical Dosing Facility

This system caters to CDU/VDU units.

Demulsifier

Demulsifier chemical is unloaded into demulsifier drums. The drum is provided with a mixer which can be used for preparation of desired concentration levels of the chemical. Demulsifier injection is done at the inlet of First stage desalter.

Filming Amine

Filming amine is unloaded into Filming amine drum. The drum is provided with a mixer, which can be used for preparation of desired concentration levels of the chemical. It is injected in the column overhead circuit to prevent corrosion.

Neutralising Amine

Neutralising Amine chemical is unloaded into Neutralising Amine drum. The drum is provided with a mixer, which can be used for preparation of desired concentration levels of the chemical. It is injected in the column overhead circuit for pH adjustment and to prevent corrosion.

Caustic Solution

Caustic solution is required in the unit for caustic make-up to Vent Gas Caustic Scrubber. 10 wt% caustic solution is obtained from OSBL, which shall be used for make-up in Vent Gas Caustic scrubber. 5 wt.% Caustic solution might be required in the unit to be injected into crude line downstream of desalter.

7.3.3 INDMAX FCC with Propylene Recovery Unit

The typical scheme for INDMAX FCC unit and PRU is shown provided in Annexure III (A510-79-41-00-1052& 53) in Annexure III.

INMAX FCC is a fluidized catalytic process for selectively cracking a variety of feed stocks to light olefins.



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INMAX FCC is similar to conventional FCC in terms of basic process employed. But the cracking are higher in INDMAX unit. The objective of this process is maximization of LPG with higher selectivity towards propylene. LPG yield is typically 36-40 percent and propylene is typically 20 wt%. Dry gas produced from this unit is rich in ethylene.

Hence, INDMAX unit provide opportunity for establishing downstream petrochemical units. Propylene is recovered from LPG in downstream PRU and sent to downstream Polypropylene unit. There is potential to use the dry gas rich in ethylene for the production of styrene monomer after reacting with benzene to form ethyl benzene.

To achieve the higher conversions, unit operates at higher severity with high reactor temperature, higher quantity of dispersion steam in the reactor and higher catalyst to oil ratio. The catalyst employed is zeolitic in nature. High ZSM-5 to the extent of ~ 15% is added to achieve the desired conversions and propylene make. Some licensors offer the catalyst impregnated with ZSM-5.

The INDMAX unit reactor regenerator system utilizes a reactor/riser, catalyst stripper, 1st stage regeneration vessel, 2nd stage regeneration vessel, catalyst withdrawal well and catalyst transfer lines. Fresh feed, from upstream VGO HDT Unit, is finely atomized with dispersion steam and injected into the riser through feed injection nozzles over a dense catalyst phase. The small droplets of feed contact the freshly regenerated catalyst and instantly vaporize. The oil molecules mix intimately with the catalyst particles and crack into lighter and more valuable products.

As the reaction mixture travels up the riser, the catalyst, steam and hydrocarbon product mixture passes through a riser termination device. This device quickly disengages the catalyst from steam and product vapors. Reactant vapors are then ducted to the top of the reactor near the reactor cyclone inlets, while catalyst is discharged into the stripper through a pair of catalyst dip legs. The vapors with entrained catalyst pass through single-stage high-efficiency cyclones. Reactor products, inerts, steam and a minute amount of catalyst flow into the base of the main fractionator and are separated into various product streams.

Below the dense catalyst bed in reactor vessel, a steam ring strips off volatile hydrocarbon material from reacted catalyst particles. Stripped catalyst leaves the reactor vessel through catalyst withdrawal pipes and enters the 1st stage regenerator through a catalyst distributor that disperses the catalyst onto the bed surface. Catalyst and combustion air flows counter currently in the 1st stage regenerator vessel. Partially regenerated catalyst exits near the bottom of the vessel through a hollow stem plug valve. A lift line conveys the catalyst into the 2nd stage regenerator vessel utilizing lift air. CO-rich flue gas from the regenerator vessel exits through two-stage high efficiency cyclones.

A mushroom grid evenly distributes the catalyst in 2nd stage regenerator vessel. Any carbon remaining in the catalyst is completely burned off with an excess amount of air in this regeneration stage. This results in high temperatures. Several design features like external cyclones and a catalyst cooler are



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incorporated to minimize any mechanical and/or physical temperature limitation. Hot regenerated catalyst flows into a withdrawal well, through regenerated catalyst slide valves and into the "wye" section at the base of riser. Here, it meets the hot feed. The INDMAX FCC gas recovery section employs a low pressure drop main fractionator design with warm reflux overhead condensers to condense the large amount of steam used in the convertor. A large wet gas compressor is required relative to FCC operation because of high amount of dry gas and LPG. The absorber and stripper columns, downstream of the wet gas compressor are specifically designed for enhanced C3 recovery at relatively gasoline rates.

In addition to the above three products, the product fractionator separates the catalytically cracked material into heavy naphtha, light and heavy cycle oils and catalyst slurry. The heavy cycle oil is recycled back to the reactor. The catalyst slurry contains some lighter hydrocarbon oil, clarified oil, which is subsequently separated and may be recycled back to either the reactor or to the internal fuel oil pool.

The flue gas handling system downstream of the INDMAX regenerator requires considerations no different than those of as FCC system. It consists of a flue gas slide valve to control the differential pressure between the reactor and regenerator followed by an orifice chamber. Heat is recovered by flue gas cooler in the form of high-pressure superheated steam. Flue gas is de-sulphurized before sending out.

7.3.4 Kerosene Hydrodesulphurization Unit

The typical PFD for KHDS unit is shown in diagram no A510-79-41-00-1054 to 1056 in Annexure III.

Feed and make up gas compressor section

The kerosene feed to the unit is routed to the Feed Surge drum through a feed filter to remove any carry over rust and polymeric components in feed followed by a feed coalescer vessel, wherein drain water is taken out through the boot. The pressure in the feed surge drum is maintained by fuel gas blanketing. The feed from the surge drum is pumped to the Feed / Reactor Effluent Exchanger.

Make up Hydrogen from offsite supplies the chemical hydrogen, solution losses and the mechanical loss of hydrogen to the unit. Make up H2 is routed to the Makeup H2 compressor KOD to separate any liquid. It is then compressed in the Makeup H2 compressor and routed to the feed.

Reactor Section

The preheated feed (including recycle and makeup gas) is brought to reactor temperature in the Feed heater. The reactor inlet temperature is controlled by fuel firing.

The feed from heater is then routed to the reactor from the top(down flow). The effluent from the reactor is routed to the Feed/Reactor Effluent Exchanger. The cooled effluent from cooler is again heat exchanged with the Reactor Effluent



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Water Cooler and then routed to the HP Separator. The separator is designed for 2 phase separation of gas and kerosene liquid. The vapour phase gas is routed to a Recycle Gas Amine Absorber, where the H2S is absorbed in lean MDEA. Lean amine from the Amine Regeneration Unit is routed to the scrubber on flow control. The rich MDEA is routed back to the Amine Regeneration Unit. The treated gas from the top of the absorber is routed to the Amine KOD where entrained amine solution is removed from the gas. The gas from the top of KOD is compressed in the Recycle Gas Compressor and fed to the feed along with makeup gas.

The liquid kerosene is routed to the stripper column, before heat exchanging with Stripper feed bottom exchanger.

Stripper Section

The liquid Kerosene from the separator drum is routed to the stripper column through a Stripper feed/bottom exchanger. The stripper overhead vapors are condensed in the Stripper overhead condenser. The overhead condenser minimizes the loss of C3, C4 and C5 products to the fuel gas system. The Condenser outlet is routed to Stripper Reflux Drum. The off gas is cooled by the off gas condenser and routed to OSBL. The condensed overhead liquid is partly refluxed back to the stripper on flow control cascaded with level in the Stripper reflux drum and balance routed as Naphtha product to outside battery limit on flow control cascaded with stripper column overhead temperature. A part of the bottom product is routed to Feed / Stripper Reboiler heater via pump and is finally recycled back to the stripper.

The bottom product from the stripper is pumped by to the Stripper feed/bottom exchanger XX-E-105 followed by Product rundown cooler and then finally to storage on flow control cascaded with level column level control. The product is Hydrotreated Kerosene. The Hydrotreated Kerosene is routed to storage through Salt filters XX-V-108A/B andClay filters XX-V-109A/B to remove any residual moisture and to ensure water specifications in the final product.

.

7.3.5 Naphtha Hydrotreater Unit

The typical scheme for NHT unit is shown in schematic flow diagram no A510-79-41-00-1057 in Annexure III.

Naphtha Hydrotreater Section

Naphtha feed to NHT passes through a surge drum and a charge pump. It is then combined with a H2-rich gas stream from the recycle gas compressor. The combined feed enters the reactor feed/effluent exchanger, where the feed is heated. The heated feed is brought up to the reaction temperature in a feed charge heater. The hot feed down-flows through a fixed-bed reactor where the catalyst reacts with the feed to remove sulphur as H2S, in presence of H2.The reactor effluent is cooled first in the reactor feed/effluent exchanger and then in the product air cooler. Wash water is injected into the reactor effluent upstream of the product air cooler so that any salt build up in the condenser may be washed out. Reactor effluent flows out of the condenser at a low temperature to ensure complete recovery of naphtha and enters the separator



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The separator is provided with a mesh coalescer to ensure complete separation of vapor, hydrocarbon liquid and sour water. Sour water is sent to SWSU, H2-rich vapor is recycled back to the reactor through recycle gas compressor. A H2-rich makeup stream is fed into the recycle stream through a makeup gas compressor. Liquid hydrocarbon from separator is heated by heat exchange with stripper bottoms in stripper feed/bottom exchanger and enters the stripper near its top. A steam reboiler provides stripper heat duty. Overhead vapor from the stripper pass onto the stripper trim cooler partly condenses and separates into three phases in the stripper receiver. Net overhead gas from the stripper receiver is passed onto the refinery fuel gas system after amine treatment to remove all H2S. Sour water from the receiver is sent to SWSU. Hydrocarbon liquid from the receiver is sent back to the stripper as total reflux. Hydrotreated sweet naphtha from stripper bottom is cooled in stripper feed/bottom exchanger and then sent to naphtha/gasoline pool.

Naphtha Splitter Section

The Hydro treated Naphtha from Naphtha Hydro treating unit passes through a surge drum and a charge pump. The feed enters the splitter column and is fractionated. The heat to the fractionator is provided by a Reboiler. The Overhead vapors are condensed in the overhead cooler into a Reflux drum. The overhead Light Naphtha is partially pumped as reflux to the column and partially taken as Light Naphtha Product. The Heavy Naphtha from the bottom of the splitter column is taken as Heavy naphtha Product. The Light Naphtha becomes feed for Isomerization Unit while as Heavy naphtha becomes feed to CCR Unit.

7.3.6 Continuous Catalytic Reformer Unit

The typical scheme for CCRU unit is shown in schematic flow diagram no A510-79-41-00-1058 in Annexure III.

The Catalytic Reforming Unit processes the heavy naphtha stream to make it more suitable for the production of motor gasoline. The reforming process involves chemically rearranging the hydrocarbon molecules to produce higher-octane materials.The octane number is a key measure of motor gasoline performance. Hydrogen gas is produced as a byproduct of reforming, and is used as feed to the Naphtha Hydrotreater Unit, Distillate Hydrotreater Unit. The heavy naphtha feed streams are mixed with recycle hydrogen, preheated by exchange with reactor effluent, heated to reaction temperature in the charge heater and sent to the first of a series of three to four reactors. Each reactor is preceded by a gas-fired feed heater to maintain a constant inlet temperature profile for the individual reactors (as reforming reactions that take place in the reactors are predominantly endothermic). Effluent from the last reactor is heat exchanged with the combined feed, condensed in the product trim cooler and sent to the separator. The reformed naphtha product (reformate) is separated from the by-product hydrogen. A portion of the hydrogen is compressed and recycled to be mixed with heavy naphtha feed material. The remaining hydrogen is compressed for use in other refinery processing units.



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The reformate product is fractionated in the debutanizer for separation of light ends. The reformate liquid product is sent to storage, for use in motor gasoline blending. The Catalytic Reforming Unit reactor catalyst is continuously regenerated in the Catalytic Reforming Unit Catalyst Regenerator. The regeneration section of the reformer provides a continual stream of clean coke-free active catalyst that is returned back to the reactors. Continuous circulation of regenerated catalyst helps maintain optimum catalyst performance at high severity conditions for long on-stream periods of reforming operation. Catalyst regeneration takes place in dedicated equipment and uses nitrogen, air, and perchloroethylene as regenerating agents. The Catalyst Regenerator performs two principal functions - solid catalyst regeneration and circulation. Spent catalyst from the final Catalytic Reforming Unit reactor vessel is conveyed to the Catalyst Regenerator, where it is regenerated in four steps:

Coke burning with oxygen,

Oxychlorination with oxygen and chloride,

Catalyst drying with air/nitrogen, and

Reduction of catalyst metals to "reduced" oxidation states.

Exiting the Catalyst Regenerator, the regenerated catalyst is conveyed back into the first Catalytic Reforming Unit reactor. Small quantities of hydrochloric acid and chlorine are generated in the Catalyst Regenerator. The vent gas from the Catalyst Regenerator is scrubbed in two stages with caustic solution and water in the Vent Gas Wash Tower for removal of acid gases, in particular hydrochloric acid. From the Wash Tower, the cleaned

7.3.7 Isomerization Unit

The typical scheme for ISOM unit is shown in schematic flow diagram no A510-79-41-00-1059 in Annexure III.

The fresh C5 /C6 feed is combined with make-up and re-cycle hydrogen which is directed to a charge heater , where the reactants are heated to reaction temperature .The heated combined feed is then sent to the reactor. Either one or two reactors can be used in series, depending on the specific application.

The reactor effluent is cooled and sent to a product separator where the recycle hydrogen is separated from the other products .Recovered recycle hydrogen is directed to the recycle compressor and back to the reactor section. Liquid product is sent to a stabilizer column where light ends and any dissolved hydrogen are removed. The stabilized Isomerate product can be sent directly to gasoline blending.

7.3.8 Gasoline Desulphurization Unit

The typical scheme for GDSU unit is shown in schematic flow diagram no A510-79-41-00-1060 in Annexure III.



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The feed for this unit is naphtha produced in FCC unit. The objective of this unit is to reduce the sulfur content of the feedstock whilst minimizing the octane number losses. The FCC gasoline is processed in two steps:

Firstly, the FCC gasoline is processed in a selective hydrogenation unit (SHU), which converts selectively diolefins into olefin and light mercaptans into heavier sulfur compounds.

The second step is a selective hydrodesulfurization unit (HDS Unit), which converts heavy sulfur compounds into H2S and produces the heavy cut gasoline.

Selective Hydrogenation Unit (SHU) Section:

The unit feed is coming directly from upstream FCC unit which will be routed to SHU reaction section through feed surge drum. The feed is preheated in the SHU feed/effluent exchanger. The hydrogen make-up comes from the source is mixed with the feed under feed flow ratio control and the resulting mixture is heated to meet the required reactor inlet conditions. The SHU reactors are two identical down flow single bed reactors. Both reactors are designed to operate in the lead/trail position or in a single reactor configuration to enable on-line catalyst replacement. The reactor effluent is cooled down and partially condensed before entering splitter.

The purpose of the splitter is to separate SHU reactors effluent to produce light (LCN) cut naphtha and a heavy cut naphtha (HCN). Splitter overhead LCN is routed to rundown product storage and splitter bottom HCN is pumped to hydrodesulphurization (HDS) section.

Hydrodesulphurization (HDS) section:

The HDS hydrocarbon liquid feed is combined with the recycled hydrogen rich gas coming from the recycle gas compressors and is pre-heated and completely vaporized in the HDS feed/effluent exchangers before entering in HDS reactors. The HDS reactors are operates in down flow mode and in total vapor mode. The effluent from the reactor is cooled in the HDS feed/effluent exchangers and finally in HDS effluent air condenser. The liquid hydrocarbon phase is routed to the stabilizer and the vapor hydrocarbon phase is routed to recycle gas compression section after amine treatment of recycle gas. The stabilizer bottoms product is cooled in the stabilizer feed/bottom exchangers and mixed with LCN stream from splitter. The combined product is cooled down in the air cooler followed by trim cooler before routing it to storage.

7.3.9 Polypropylene Unit

The typical scheme for PPU unit is shown in schematic flow diagram no A510-79-41-00-1061 in Annexure III.

Fresh propylene from OSBL is fed through propylene dryer to the reactor along with the required catalyst, co-catalyst, hydrogen and stereo-modifier. For



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production of two special grades with small ethylene content, ethylene vapor is also fed to the reactor.

The polymerization reactors each have a nominal volume of 75 m3 with identical stirrer and drive systems. Polymerization itself is carried out in a gas phase stirred reaction. Heat removal is managed by evaporative cooling. Liquid propylene entering the reactor vaporizes and thereby removes the exothermic reaction energy. Reaction gas is continuously removed from the top of the reactor and filtered. Reactor overhead vapor (“Recycle Gas”) is condensed and pumped back to the reactor as coolant. Non-condensable gases (mainly H2 and N2) in the recycle gas are compressed and also returned to the reactor.

The polypropylene product powder is blown out of the reactor under reactor operation pressure. The carrier gas and powder pass into the powder discharge vessel where powder and gas are separated. The carrier gas is routed through a cyclone and filter to remove residual powder, then scrubbed with white oil and sent to compression.

Powder from the discharge vessel is routed via rotary feeders to the purge vessels which are operating in parallel. Nitrogen is used to purge the powder off residual monomers. The overhead gas from the purge vessels is sent to a common membrane unit for monomer/nitrogen recovery. As refrigerant for the membrane unit fresh Propylene is used.

The recovered nitrogen is sent back to the purge vessels for further use. The condensed monomers from the purge gas are combined with the filtered carrier gas, and then sent to scrubbing and subsequently to carrier gas compression.

The PP powder from the purge vessels is pneumatically conveyed by a closed loop nitrogen system to the powder silos. The powder product from these silos is fed to the extruder where polymer powder and additives are mixed, melted, homogenized and extruded through a die plate, which is heated by hot oil. The extruding section is electrically/steam heated.

Pelletizing of the final product is carried out in an underwater pelletizer where the extruded polymers - after passing the die plate - are cut by a set of rotating knives. The polymer/ water slurry is transported to a centrifugal dryer where polymer and water are separated. Water is recycled to a pellet water tank, for which demineralized water is used as make-up.

The cooled pellets (~60°C) are pneumatically conveyed to the pellet blending silos by an air conveying system. After homogenization in the blending silos the pellets are conveyed to the bagging and palletizing system.

The stream of carrier gas (including recovered monomers from the membrane system) from compression is split: half of the carrier gas is fed back to the reactors. The balance/remainder is sent to an OSBL PRU unit for subsequent purification of the propylene. In addition this balance carrier gas can be sent to the fuel gas system in case of INDMAX unit shut-down.

7.3.10 Sulphur Recovery Unit

The typical scheme for sulphur recovery unit is shown in schematic flow diagram no A510-79-41-00-1062&63 in Annexure III

Acid gas from ARU passes through acid gas knock out drum, to remove any liquid carryover, before feeding to main burner. Similarly, any liquid carryover in sour gas from SWSU is removed in sour gas knock out drum.



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The air to main burner is supplied by an air blower, which also supplies air to Super Claus stage and sulfur degassing. The air to the main burner is exactly sufficient to accomplish the complete oxidation of all hydrocarbons and ammonia present in the feed gas and to burn as much H2S as required to obtain desired concentration. The heat generated in the main burner is removed in the waste heat boiler by generating steam. Then the process gas is introduced into the first condenser in which it is cooled, sulfur vapor condensed and is separated from gas.

Upstream of 1st Claus reactor, the process stream from waste heat boiler is heated in 1st steam reheater to obtain optimum temperature for the catalytic conversion. The effluent gases from 1st reactor passes onto 2nd sulfur condenser where sulfur vapor is condensed and uncondensed process gases pass to the 2nd steam reheater. Heated vapors are again subjected to conversion in the 2nd Claus reactor followed by cooling in the 3rd sulfur condenser. Then the process gas passes to the 3rd steam reheater and the 3rd Claus reactor. Following reactions takes place inside the Claus reactor.

H2S + 3/2 O2 SO2 + H2O + Heat

2H2S + SO2 2H2O+ 3/n Sn + Heat

2NH3 + 3/2 O2 3H2O + N2

The sulfur formed remains in vapor phase and goes in polymeric reaction, which forms polymeric sulfur in vapor phase. The predominate reactions are:

3S2 S6 + Heat

4S2 S8 + Heat

Some of these combustion reactions also take place in the burner section of the reaction furnace. The lists of reactions taken place in the reaction furnace are given below:

CH4 + 2O2 CO2 + 2 H2O

CO2 + H2S COS + H2O

COS + H2S CS2 + H2O

2H2S 2H2 + S2

COS + H2O H2S + CO2

The unconverted H2S from the clause reactor is sent to the TGTU unit. Sulfur condensed in condensers is routed via sulfur locks to sulfur cooler and drained into sulfur degasification vessel. Stripping air is supplied to the spargers located at the bottom side of the vessel. This strips off H2S from liquid sulfur and oxidizes the major part of H2S to sulfur. Air leaving the stripping columns, together with H2S released from sulfur degasification vessel, is routed to TGT.Unit. Liquid Sulphur from pit is pumped by sulphur pumps to Sulphur Yard.

Tail Gas Treating Unit

The Tail Gas Treating Section is required for the removal of sulphur compounds (H2S, SO2, COS, CS2, elemental sulphur) from the tail gas from the Claus Section. This is achieved by catalytic reduction of sulphur compounds to



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hydrogen sulfide and the subsequent absorption of hydrogen sulfide in a regenerable absorption medium (Amine).

Rich amine is subsequently treated in Amine Regeneration Section in order to release the absorbed hydrogen sulfide which is recycled back to the Claus section for further recovery of elemental sulphur. The H2S recycled allows an overall sulphur recovery efficiency of 99.9% to be achieved.

Tail gas enters the hydrogenation reactor preheated at 130°C. H2 reducing gas is mixed with Claus tail gas in the preheat effluent stream via a controller which is reset by the SO2 concentration in the downstream of the hydrogen reactor. The effluent is preheated under temperature controller by an electrical heater. A pre-sulfiding line is provided to activate the TGU catalyst using acid gas from the acid gas KOD. Thus line is not used for normal operation.

The hot preheated effluent passes through the catalyst bed of the hydrogenation reactor where SO2 and other sulfur compounds are converted to H2S. Due to exothermic reaction, the gas temperature increases. The reactor inlet temperature should be held reasonably steady to provide stable conditions in the reactor. To avoid excessive outlet temperature, the inlet gas may be controlled at somewhat lower temperature to compensate for more SO2 and/or S in the tail gas feed. However, excessively low reactor inlet temperature will result in poor conversion. The SO2 monitor at the reactor effluent is observed to maintain an excess of ~3% H2. In addition, if the circulating water in the quench loop shows the presence of finally divided sulfur this indicates incomplete reaction and the SO2 has reached the column to form sulfur via the Claus reaction:

2H2S + SO2 3S + 2H2O

This behavior should be monitored as the presence of the sulfur not only means the reaction is incomplete but the column can be plugged. Monitoring the pH of the quench water provides a pre-warning to an impending problem. The pH should be maintained near 7.0.

Hot reactor exit gas must be cooled before entering the absorber. A first stage gas cooling is accomplished by generating steam at the TGU waste Heat Boiler, decreasing the process gas temperature. BFW is fed to the shell side of the TGU-WHB on level control and low pressure steam is generated. When the steam flow and/or BFW flow rate changes, the water level in the steam generator varies. Rising level in the generator indicates that the BFW flow rate is exceeding the rate of steam generation. In this case, signal to the level control valve will decrease. If the steam generation exceeds the BFW rate, level will decrease. In this case, signal to the level control will increase.

The process gas enters the quench column. The quench water recirculating loop consists of the quench water pump, filter and water cooler. The cooler removes the heat from the column, cooling the inlet gas. The water flow to the top of the column is controlled after being filtered by quench water filter. Decreasing the water flow rate will increase the bottom temperature. Increasing the water rate will increase the load in the quench water circulation pumps and flow through the quench water cooler and column.

The quench column recirculation system has the provision to adjust the pH by addition of caustic to the column recirculation line. The pH of the quench water to the water pump is monitored and kept at a value between 7 and 9 in an effort to prevent corrosion and inhibit colloidal sulfur formation. The water system should



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be visually inspected for cloudiness. Low pH will indicate incomplete reduction of sulfur compounds.

Sour water condensed from the inlet feed is removed from the quench water loop via a level controller from the quench column and is sent offsite to sour water storage. The rate depends on the water in the Claus tail gas, water produced in the hydrogenation reactor and the amount of water overhead in the quench column.

Downstream of these reactors, additional recovery of reduced sulfur is accomplished in an amine absorber column that uses an aqueous methyl di-ethanolamine (MDEA) solvent to scrub H2S from the TGTU tail gas. The overhead stream from this contactor, containing very low sulfur levels, is sent to the tail gas thermal oxidizer for disposal. The rich MDEA solvent is regenerated in the TGTU amine stripper and H2S is returned to the inlet of the Claus SRU trains to be recovered. Regenerated MDEA solvent is recirculated back to the TGTU amine absorber column.

Tail gas from TGU is routed to the incinerator where residual sulfur is converted to SO2 and discharged into the atmosphere.

The overhead line from the quench column flows to the absorber. The absorber is a packed column and is designed to absorb practically all the H2S in the recirculating Amine solvent. amine absorber column that uses an aqueous methyl di-ethanolamine (MDEA) solvent to scrub H2S from the TGTU tail gas. The overhead stream from this contactor, containing very low sulfur levels, is sent to the tail gas thermal oxidizer for disposal. The rich MDEA solvent is regenerated in the TGTU amine stripper and H2S is returned to the inlet of the Claus SRU trains to be recovered. Regenerated MDEA solvent is recirculated back to the TGTU amine absorber column.

The purpose of the incinerator system is to oxidize all the sulfur compounds in the tail gas to SO2 and to vent the oxidized stream at high temperature and at a high elevation.

The incinerator system included the two primary sections:

In the incinerator burner, fuel gas is burnt with excess air to a temperature over 1650oC. The temperature is sufficient to heat the tail gas from TGU to ~768oC. This temperature is sufficient to oxidize the residual H2S and sulfur compound, while minimize NOx and SO3 formation.

The effluent is discharged to the incinerator stack. The stack height of 60 meters is set to ensure dispersion of SO2 and to meet ground level concentration limits.

Effluent tail gas from the TGU absorber is thermally oxidized with air to convert reaming sulfur compounds to SO2. Fuel gas and excess air are combusted at high temperature at the incinerator burner. Then it is mixed with the absorber overhead effluent tail gas in the primary oxidation chamber. The fuel gas and air rates are adjusted to control the temperature of the mixed and oxidized tail gas stream. The air is supplied by a dedicated incinerator air blower. Excess air is used to ensure sufficient oxygen is present to oxides the sulfur and other sulfur compound. Oxidation reactions are as follows:

H2S + 3/2 O2 SO2 + H2O

2COS + 3 O2 2 CO2 + 2SO2

CO + ½ O2 CO2



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CS2 + 3 O2 2SO2 + CO2

Sn + nO2 n SO2

The incinerator effluent temperature is measured and used to adjust the flow rate of fuel gas to maintain the desired operating

temperature of 768oC. The incinerator is refractory lined with an external thermal shroud to control the shell temperature. Skin thermocouples are provided to monitor the shell temperature. The shell temperature should be maintained between 149 – 350oC.

The air blower is designed to provide supply of air and stack while providing a minimum of 2% excess O2 at an operating temperature of 768oC. Ambient air is drawn through the inlet filter to remove solid debris and to protect against water during heavy rainfall.

The combustion gas from the burner and combustion chamber flow into the incinerator where adequate residence time is provided for combustion. The incinerator stack vents the effluent to the atmosphere. A SO2/O2 analyzer is provided to determine the SO2 and O2 in the effluent stream

7.3.11 New Sour Water Stripper

The typical scheme for Sour water stripper unit is shown in Annexure III (A510-79-41-00-1064) in Annexure III.

New Sour Water Stripper unit is designed to treat sour water from CDU/VDU, INDMAX FCC unit, KHDS unit, GDSU and intermittent sour condensate from SRU & TGTU.The stripped water from single stage stripper is sent back separately to units or to ETP.

Hot Sour water from aforesaid units is mixed with ammonia rich recycle (to keep H2S in solution & for constructive recovery), cooled in a water cooler to 37 0C, and received in a surge drum, a three stage (V-L-L) separator. Any hydrocarbon that flashes is separated out and joins ammonia stripper overhead line to be routed to incinerator. The entrained oil, if any, is skimmed off from drum and drained to OWS. The sour water is sent to sour water storage tanks under level control. The day tanks and stripper feed pumps are normally located behind SRU ammonia incinerator vent stack. The sour water day tanks serve the following purposes:

A floating skimmer (with swivel joints and steam traced “try” lines are provided to skim off separated oil. The tanks are blanketed with nitrogen to keep off air/oxygen. The tanks release vapors containing H2S, ammonia (during out breathing if ammonia rich recycle stream is not available) through a fisher assembly to join SRU ammonia incinerator vent stack to release these vapors at safe height.



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The sour water from tanks is pumped to the 1st stage H2S stripper column under flow control through feed/bottom exchanger where the incoming sour water feed is preheated against 2nd stage bottoms, i.e., stripper water. The feed enters the column feed tray. A slip stripped water stream quantity is taken from the inlet of feed/bottom exchanger and sent as hot wash water under flow control to the 1st stage stripper column. The temperature of this wash stream is very important for column steady performance.

H2S stripper is equipped with MP steam heated kettle reboiler to provide the reboiling duty required. This column normally operates at a top pressure of 7.0 Kg/Cm2g and pressure is controlled by PIC in overhead vapour line. The stripping section removes most of the H2S coming in sour water feed. The overhead wash section condenses most of the steam and almost pure H2S is produced at the column top. This H2S gas is routed to SRU for Sulphur Recovery, in a steam traced line.

The MP steam flows to reboiler. Condensate withdrawal scheme are same as the single stage stripper column. MP condensate is routed to SRU condensate handling system. The sour water from the H2S stripper bottom, containing almost all ammonia and small quantity of unrecovered H2S, is fed to second stage ammonia stripper column under level control.

The ammonia stripper overhead is floating with the SRU ammonia incinerator header back pressure. The sour water is fed at the 2nd stage stripper feed tray. Alternate feed tray is also provided for operational flexibility. The section below feed tray is stripping section with two pass trays.

The required reboiling duty for this column is supplied by the LP steam heated kettle reboiler, LP steam flow/condensate withdrawal control scheme s similar to the other two columns. The FRC cascading is with sour water feed to H2S stripper to maintain a constant rate of steam to sour water feed. This ratio should be sufficient to bring down ammonia content below 50 ppmw in stripped water from column bottoms. LP condensate is routed to SRU condensate handling facility.

The overhead pump-around circuit consists of circulating reflux pumps and circulating reflux air cooler. The pump takes suction from chimney tray and circulates at a constant rate under flow control (cascaded with column top temp.).This circulating reflux is fed at the column top. The ammonia (with small H2S quantity) coming out from column top is routed to SRU ammonia incinerator through a steam jacketed line.

An ammonia-rich slip stream from pump-around circuit (before air cooler), under flow control, serves as recycle stream to be mixed in hot sour water feed, before feed mix cooler, during normal operation.



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7.3.12 Amine Regeneration Unit

The function of Amine Regeneration units is to remove the acid gases (H2S and CO2) from the rich amine streams produced in the refinery processing units. Refer schematic flow diagram provided in Annexure III (A510-79-41-00-1065) in Annexure III.

Rich amine from various absorber units is received in a flash column. Rich amine is allowed to flash in the column to drive off hydrocarbons. Some H2S also gets liberated. The liberated H2S is again absorbed by a slip steam of lean amine solution making counter current contact with liberated gases over a packed bed.

From the flash column, the rich amine is pumped by rich amine pumps under flow control to amine regenerator, after preheating in lean amine/rich amine exchanger. In lean amine/rich amine exchanger, the heat is supplied to rich amine by hot lean amine on shell side from the bottom of amine regenerator under level control. The lean amine from lean amine/rich amine exchanger is further cooled in lean amine cooler and routed to amine storage tank. Another part of lean amine from lean amine cooler is used as slip steam to cartridge filter to remove solid particles picked up amine in the system. It is also used to remove foam causing hydrocarbon substances and thereafter routed to amine storage tank.

In amine regeneration column, reflux water enters the column top and descends down. This prevents amine losses into the overhead and ensures complete removal of H2S. The reboiler vapors from the bottom of the tower counter currently contacts the rich amine and strips off H2S. The overhead vapors from regenerator are routed to regenerator overhead condenser, where most of the water vapors condense and are pumped by amine regenerator reflux pumps as reflux to the column. The acid gases are routed to the SRU. In case the pressure goes high, acid gases are released to the acid flare. Reboiler heat by LP steam is supplied to the column through amine regenerator reboiler.



Rev. No. A



SECTION 7.4

UTILITY DESCRIPTION



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7.4 Utility Description

This chapter provides details of utility requirements and description of new utility system envisaged with addition of new process units. The utility requirements have been arrived after considering centralization & integration of existing utility system with new utility system. The following utility systems are reviewed for FR: 1. Raw Water System 2. De-mineralized Water System 3. Cooling water system 4. Compressed Air System 5. Nitrogen System 6. Steam, Power & BFW System 7. Condensate System 8. Internal Fuel Oil & Fuel Gas System

Additional utility consumption has been estimated considering following basis:

Operating data of existing Units.

In-house data for new units and envisaged units under BS VI at 13.7 MMTPA.

The details of existing utility systems installed in the refinery are given in Annexure II to chapter 4, Design Basis.

7.4.1 Utility Summary

The incremental utilities required for additional facilities for refinery expansion to 18.0 MMTPA is tabulated below in Table 7.5.1

Table 7.4.1 Utility summary for new facilities

Sl. No System Units

Additional requirement

1 Cooling water Consumption m3/hr 52000

2 DM Water m3/hr 555

3 Service water m3/hr 40

4 Instrument Air Nm3/hr 10900

5 Plant air Nm3/hr 5500

6 Nitrogen Liquid N2 storage

Nm3/hr M3

5000 500

7 Boiler Feed water TPH 600



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Sl. No System Units

Additional requirement

8 Steam TPH 300

9 Power MW 63

10 Condensate generation TPH

415

7.4.2 Raw Water system

Additional raw water required for the new facilities envisaged for refinery expansion shall be around 1600 m3/hr. As advised by IOCL a new bore well of capacity 11 MGD is considered to meet the additional requirement. A new raw water treatment plant of equivalent capacity is also envisaged for the expansion project to treat the bore well water.

Raw water shall be used for following purposes for additional facilities:

As feed to the DM water system

As make up water for additional cooling water requirements

As service water for process units or operating hose stations for various miscellaneous uses in the plant.

As fire water make up

7.4.3 DM water system

DM water in refinery is required for the following major purposes:

As process water (for solution preparation, etc.) in some process units.

As boiler feed water make-up for the generation of steam

As dilution water for the preparation of caustic solution

During start-up of the Sour Water Stripping units

For jacket cooling of some compressors, if required.

A new RO/DM plant of capacity 560 m3/hr consisting of three chains (2w+1s), integrated with new ETP is envisaged under this project. The normal feed to the plant shall be ETP treated water and cooling tower blow down, balance requirement shall be met by treated raw water. The following are the details of the DM water system.

Table 7.4.2: DM Water system details

A) No. of chains 1W+1S

A) Capacity m3/hr 560



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No of Chains 2w + 1s Chain capacity m3/hr 280

B) Storage tanks

DM water storage tanks No. units 2 MOC : CS with epoxy coated.

C) Pumps 1. DM water transfer Pumps No.of pumps : 2W+1S Type : Centrifugal Capacity : m3/hr 280

7.4.4 Cooling Water System

Cooling water is mainly used as cooling medium in coolers and condensers in process units, utilities & off sites. Refer annexure II to the design basis for details pertaining to existing cooling water system facilities in the refinery complex.

Two new re-circulating cooling water systems are envisaged under this project. A new cooling water system is considered in place of abandoned cooling tower, to meet the requirement of new CDU/VDU. Another system is considered in the new Bajwa land to feed INDMAX-FCC, FCC-GDS, PPU and new MS block. For catering to requirement of KHDS and Sulphur block, a new cell and pump shall be added in south Block cooling tower. The cooling water system shall be consisting of the following.

Table 7.4.3: Re-circulating Cooling Water system details

A) Cooling tower 1W+1S

No of cells 4w+1S in abandoned cooling tower area 8W+1S in new Bajwa land

Cap./ cell: m3 /hr 4000

B) Pumps

Type Centrifugal

No of Pumps 2W+1S in abandoned cooling tower area 4W+1S in new Bajwa land

Cap. m3 /hr 9000

Type of drive Electric Motor driven



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C) H2SO4dosing system

D) Chlorination

E) Side stream filters

7.4.5 Compressed Air System

Compressed air is required for following main requirements:

As instrument air to operate the various instruments in the facility and also for the purging of some control panels.

As scouring air (plant air) for regenerating pressure sand side stream filters of cooling water systems, etc.

As service air for operating hose stations for various miscellaneous uses in the plant, including providing breathing air to personnel during vessel entry, etc.

Compressed air required for all the above uses is generated at a centralized

location in the plant and distributed to the various users through headers. Two

qualities of compressed air are produced and distributed.

a) Plant air comprising compressed air cooled to ambient temperature. Quality of

plant air and service air are same. This air though not containing any entrained

water droplets is saturated with the water vapours at supply condition.

b) Instrument air comprising compressed air cooled to ambient temperature and

drier to remove water vapour to meet stringent atmospheric dew point

requirements

Consumption Requirement

Plant Air: Continuous requirement of plant air is envisaged in the INDMAX FCC unit with a total requirement of ~5500 in the new facilities.

Instrument Air:

Total requirement of instrument air for additional facilities is~10900NM3/hr

The above requirements of plant air and instrument air shall be met by compressed air system with following details.

Table 7.5.7 Compressed Air system Details

A) LP Air compressor Air 2W+1SS



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Capacity : Nm3 /hr 8200 Discharge pressure : 8.0 kg/cm2(g)

B) LP Air receiver : 1 No

Type Vertical

Height 15000 mm

Diameter 4300 mm Design pressure 10.5 kg/cm2(g)

C) Dryer ( 2 Nos)

Capacity 11000 NM3/HR

Type: Dual bed Adsorption, No purge loss

7.4.6 Nitrogen System

The inert gas (Nitrogen) is required in the refinery for initial purging, dry out, as dry seal for rotating machineries and for catalyst regeneration. The inert gas is also required in Offsite for blanketing and in flare header purging.

Requirements:

The continuous/intermittent supply of Nitrogen will be required for the following purposes:

Reactor section dry out

Purging of system during start-ups and shutdowns

During catalyst regeneration

Continuous purging of compressor seals

Blanketing of surge drums and storage tanks

Flare header purging in offsite

Process related activities such as reactor section dryout, system purging, catalyst regeneration etc. require high purity nitrogen (>99.5% purity). To meet the nitrogen demand for new facilities under this project a new nitrogen plant of 5000 Nm3/hr capacity is envisaged. For liquid nitrogen storage facility of 500 m3 is also considered.

7.4.7 Boiler Feed Water system

Boiler feed water is used in refinery as feed water to steam generating systems and as injection water as per requirement. The additional BFW shall be met by installing a new De-aerator system of capacity 600 m3/hr.



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7.4.8 Steam and Power System

There are mainly 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.)

As a heating medium

Internal fuel oil atomization,

Steam tracing of lines (congealing service)

Tankage heating

Deaerator

Intermittent requirement like snuffing, decoking, soot blowing, purging, flushing of lines/equipment etc.

As motive fluid in steam ejectors in ejectors & steam turbines

Air conditioning units for the Control rooms and the administrative building

Refer annexure B to the design basis for details pertaining existing steam and power systems in the refinery. Steam Requirement The steam requirement of the new facilities is ~300 TPH. Two new utility boiler of capacity 150TPH is envisaged to be installed in place existing unutilized boilers in the TPS area, to cater the net HP steam requirement of additional facilities. The steam requirement at MP and LP level can be provided through PRDS systems or by running turbine drives like existing Boiler Feed Water pumps. The new steam system shall be integrated to existing steam system in refinery. Power System: Additional 63 MW requirement shall be met with power import form existing grid import facilities. No new facilities are considered under this project

7.4.9 Condensate System

Steam is being used in the refinery as process steam motive fluid for the steam turbine drives, for heating etc. Condensate results from the condensing steam turbine drives, steam re-boilers and steam heated exchangers. Within each individual units suspect condensate and pure condensate shall be segregated. Surface condensate from condensing type steam turbine drives shall be



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considered pure condensate and used for steam generation directly. Depending upon the steam and process side pressure levels in exchangers, each unit shall have separate header for these two types of condensates. The suspect condensate, if contaminated shall be required to be treated in centralised condensate polishing unit before use. Pure condensate shall be directly used for steam generation. The condensate being generated which shall be recovered can be categorized under following headings:-

a) Condensate coming from the exchangers, which may be consuming eitherMP or LP steam. Individual units generating HP or MP level condensate shall flash it to LP level, cool the condensate to the required temperature of 90 degC and supply the condensate at their respective B/L.

b) Condensate obtained from the steam drives in the process unit.

The condensate recovered as per point number (a) shall be either pure or suspect condensate. Pure condensate shall be directly utilized for steam generation. In order to utilize the suspect condensate collected for steam generation, it shall be routed through a condensate polishing unit.

Condensate Recovery System

Both the process and surface condensate in the refinery shall be recovered and routed back to the steam generation system. Pure condensate from steam turbines surface condensers, expected to be clean will be utilized directly for steam generation. Condensate polishing is envisaged for the process condensate from reboilers etc. Condensate contamination will be detected by stipulating on-line conductivity/pH analysers with automated provision for drainage.

A new condensate polishing unit of 415 TPH with the following details is envisaged for the process condensate generated from new facilities.

Table-7.4.4: New condensate polishing system

A) No. of chains 1W+1S

Capacity per chain, TPH 210

B) Exchangers

Condensate cooler 1

Polished/unpolished condensate exchanger

1



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Activated carbon filters (Per chain) 2w + 2s

Mixed bed (Per chain) 1w + 1s

C) Storage tanks

1. Unpolished condensate tanks

No. units 1W+1S

Dimension : 11.6 M DIA X 17.4 M HT

MOC : CS with epoxy coated.

2. Polished condensate tanks

No. units 1W+1S

Dimension : 11.6 M DIA X 17.4 M HT

MOC : CS with epoxy coated.

D) Pumps

1. Unpolished Condensate Pumps

No.of pumps : 1W+1S

Type : Centrifugal

Capacity : m3/hr 210

2. Polished Condensate Pumps

No.of pumps : 1W+1S

Type : Centrifugal

Capacity : m3/hr 210

7.4.10 Internal Fuel Oil/ Fuel Gas system

All the major firing duty requirement of expansion has been considered with fuel gas firing. But all the furnaces shall be designed for dual firing. Additional fuel gas requirement shall be met from fuel gas generation from new process units and balance shall be met by RLNG. The existing fuel network shall be integrated with the new fuel network.



Rev. No. A



SECTION 7.5

OFFSITE DESCRIPTION



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7.5 Offsite Description

This section describes the storage and pumping facilities for feed/intermediate and finished product based on the material balance, unit capacities, block flow diagrams of refinery complex for the selected refinery configurations. Storage capacity is based on the process unit feed/ products rates, criticality of operation, emergency operation, catalyst regeneration/ replacement schedule etc. The philosophy and facilities for storage and transfer is discussed below.

Offsite facilities are divided into three sections:

Crude oil storage and transfer.

Intermediate Feed / Intermediate product storage and transfer.

Finished product storage.

7.5.1 Crude oil storage and transfer

As the additional crude purchase for expansion can be handled in existing crude storages, no new crude tanks are envisaged for expansion.

7.5.2 Intermediate feed storage and transfer

Two new intermediate tanks have been considered for feeding new NHT unit and KHDS unit. The propylene product shall be stored in mounded to feed into PPU. One bullet it envisaged for storage of offspec product so that this shall be reprocessed in the PRU section. The feed tank requirement of other units shall be met by converting existing Kerosene and naphtha tanks as no sales of these products are considered after expansion.

Table 7.5.1: New Intermediate feed storage tanks

Sl. No

Service No of Tanks

Type Liquid stored

capacity of each tank (kL)

1 NHT feed tank 2 Internal

Floating Roof

12,000

2 KHDS feed Tank 2 Internal

Floating Roof

5,000



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Sl. No

Service No of Tanks

Type Liquid stored


3 Propylene storage.

3 Mounded 3,500

The above storage facilities shall be provided with transfer pumps as below

Table 7.5.2: New Intermediate feed pumps

Sl. No

Service No of

pumps Flow

(m3/hr) Type

1 NHT feed Pumps 2W+1S 200 Centrifugal

Motor driven

2 KHDS feed Pumps 1W+1S 135 Centrifugal

Motor driven

3 PPU feed pump 2W+1S 50 Centrifugal

Motor driven

7.5.3 Finished product storage and transfer

As additional gasoline and HSD products can be stored by converting existing naphtha and kerosene tanks, no new gasoline and HSD tanks are envisaged. However new storage facilities are considered for LPG and MTO products.

Table 7.5.3: New Finished product storage

Sl. No

Service No of Tanks

Type Liquid stored


1 MTO product 1 Internal Floating

Roof 5000

2 LPG Mounded Bullet 6 Mounded 3,500

The above storage facilities shall be provided with transfer pumps as below.

Table 7.5.4: New Finished product pumps

Sl. No

Service No of

pumps Flow

(m3/hr) Type

1 MTO product Transfer Pumps

1W+1S 350 Centrifugal

Motor driven



Rev. No. A

Page 231 of 284



Sl. No

Service No of

pumps Flow

(m3/hr) Type

2 LPG Transfer Pumps 1W+1S 300 Centrifugal

Motor driven



Rev. No. A



SECTION 7.6

FLARE SYSTEM



Rev. No. A

Page 233 of 284



7.6 Flare System Description

The flare system will be provided for safe disposal of combustible, toxic gases, which are relieved from process plants and offsite during start-up, shutdown, and normal operation or in case of an emergency such as:

Cooling water failure

Power failure

Combined cooling water and power failure

External fire

Any other operational failure

Blocked outlet

Reflux failure

Local power failure

Tube rupture

Reactor Depressurization

Additional Flare load shall be generated from new units with the following capacities and offsite mounded bullets

Table 7.6.1 New Unit capacities

Sl. No UNIT

Design Capacity

(KTPA)

1 New AVU with LPG treating 15000

2 INDMAX FCCU with PRU & LPG treating 2400

3 NHT unit 2400

4 CCRU 1600

5 ISOM unit 925

6 KHDS unit 850

7 GDSU 650



Rev. No. A

Page 234 of 284



Sl. No UNIT

Design Capacity

(KTPA)

8 New SRU 300 TPD

9 New Sour Water Stripper Unit 330 TPH

10 Amine Recovery Unit 300 TPH

The existing new flare shall be replaced by a new flare to cater additional load generated from expansion. A total estimated load of 1470 TPH has been considered from expansion facilities. A new flare system with 90’’ diameter flare stack with water seal drum, molecular sieve, flare header and main flare KOD has been considered.

Sour gases from new SRU unit shall be routed to separate Acid Flare System. These sour gases after KOD shall join the new Flare Stack near the burner tip through Riser pipe. A 20” pipe header shall be required to handle these sour gases. Sour gases after Acid gas KOD shall be routed to new Flare stack in a dedicated burning tip.

A preliminary configuration of the various components of new flare system is indicated below in Table 7.7.1

Table-7.6.2Components of New Flare System

A) Main Flare Stack details:-

Stack dia 90 INCH

Stack length 165 M

Stack MOC KCS

B) Main Flare Header details:-

Header dia 90 inch

Header MOC CS

C) Main Flare KOD

Type HORIZONTAL

Dimension 27.0 M (length)/ 9m (dia)

MOC KCS

D) Main Flare KOD bottom pumps

No.of pumps : 1W+1S

Type : Vertical barrel type



Rev. No. A

Page 235 of 284



Capacity : m3/hr 30

MOC : Casing & Impeller : CS

E) Sour Flare Riser details:-

Sour Flare Riser dia. 20 INCH

Sour Flare Riser length 110 M

Sour Flare Riser MOC SS-304 WITH MP STEAM TRACING

F) Sour Flare Header details:-

Header dia. 20 inch

Header length : ~1000 m

Header MOC CS + PWHT

G) Acid Flare KOD:-

Type HORIZONTAL

Dimension 6.0 M (length)/ 2m (dia)

MOC KCS + PWHT+ HIC

H) Flare KOD bottom pumps

No. of pumps : 1W+1S

Type : Centrifugal

Capacity : m3/hr 5

MOC : Casing & Impeller : SS 316L



Rev. No. A



SECTION 8.0

ENVIRONMENTAL CONSIDERATIONS

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

REVISED DRAFT FEASIBILITY REPORTFOR CAPACITY EXPANSION FROM 13.7 TO 18.0 MMTPA

WITH 100% BS-VI AUTO FUEL PRODUCTION FOR IOCL GUJARAT

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Document No. A510-PFR-1742-1501

Rev. No. 0 Page 237 of 284

8.0ENVIRONMENT CONSIDERATION

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. The proposed capacity expansion from 13.7 to 18.0 MMTPA and revising the product slate to 100% BS VI auto fuels against BS III + BS IV considered earlier is a step in the direction of spurring industrial activity. Notwithstanding this fact, it has been considered essential to adopt environmental protection measures and adhere to legislations such that the ecology and the environment 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.The quality and quantity of effluent considered in this section are preliminary estimates based on in-house data and are required to be confirmed during design stage.

8.1 Indian Environmental Legislation

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 given in Table 8.1.

Table 8.1:Indian Environmental Legislation

Legal Instrument Relevant articles/provisions

TheEnvironment (Protection) Act, 1986, amended up to 1991

Section 7: Not to allow emission or discharge of environmental pollutants in excess of prescribed standards Section 8: Handling of Hazardous substances Section 10: Power of entry and inspection Section 11: Power to take samples Section 15 – 19: Penalties and procedures

The Air (Prevention and Control of Pollution) Act 1981, as amended upto 1987.

Section 21: Consent from State Boards Section 37: Penalties and Procedures

The Water (Prevention and Control of Pollution) Act, 1974, as amended upto 1988.

Section 24: Prohibition on disposal Section 25: Restriction on New Outlet and New Discharge Section 26: Provision regarding existing discharge of sewage or trade effluent

Environment (Protection) Rules, 1986 (Amendments in 1999, 2001, 2002, 2002, 2003, 2004, March 2008 )

Rule 3: Standards for emissions or discharge of environmental pollutants Rule 5: Prohibition and restriction on the location of industries and the carrying on process and operations in different areas Rule 13: Prohibition and restriction on the handling of hazardous substances in different areas




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Legal Instrument Relevant articles/provisions

Rule 14: Submission of environmental statement

Hazardous Wastes (Management and Handling) Rules, 2008, amended up to 2009

Rule 4:Responsibility of the occupier and operator of a facility for handling of wastes Rule 8: Disposal sites Rule 20: Responsibility of waste generator

Manufacture storage and import of hazardous chemicals rules 1989 amended 2000

Rule 4: Responsibility of operator

EIA Notification 2006 and subsequent amendments

Requirements and procedure for seeking environmental clearance of projects

Noise Pollution (Regulation and Control) Rules, 2000, amended up to 2010.

Ambient noise standards and requirements of DG sets

MoEF notification dated March 18, 2008 vide circular no G.S.R 186(E) for Oil Refinery Industry

Revised standards for emissions or discharge of environmental pollutants

MoEF notification dated November 9, 2012 vide circular no G.S.R 820(E) for Petrochemical (Basic and Intermediaries) Industry

Revised standards for emissions or discharge of environmental pollutants

The proposed configuration study shall be designed taking into account the above-referred legislations/rules and as per the directives of Environmental Clearance documents. Besides this, the proposed effluent and emission standards for Petroleum Refineries will also be compiled for this Project.

A brief description of the environmental protection measures proposed to be adopted in the project both in the operation and construction phase with respect to the various components of the environment like air, water, noise, land, etc., are given in the subsequent sections.

8.2 Pollution Control Measures

In order to minimize the impact of the project on the environment, due attention is being given for implementing effective pollution control measures. The design stage endeavors to mitigate the problems related to health, safety and environment at the process technology/source level itself. The design basis for all process units lays special emphasis on measures to minimize the effluent generation at source.

During the operation of the plant, the major areas of concern will be stack emissions and fugitive emissions of hydrocarbons from the process units and storage tanks along with disposal of treated effluent. Handling, treatment and disposal of hazardous wastes will also be an area of concern. The specific control measures related to gaseous emissions, liquid effluent treatment/discharges, noise generation, solid waste disposal, etc., along with relevant




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stipulated standards are described below.

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. Standards applicable to this project are classified into three categories.

Ambient Air Standards

Emission Standards

VOC control, Emission and Monitoring

8.2.1.1 Emission Standards

The emission from the new facilities envisaged in this PFR will be conforming to the standards stipulated by Ministry of Environment, Forests& Climate Change(MoEFCC) vide their notification GSR 186(E) dated 18th March 2008. The standards for emissions from furnace and boilers are given in Table 8.2.

Table 8.2: Standards for Emissions from Furnaces and Boilers*

Sl. No.

Parameter Limiting concentration in mg/Nm3, unless stated

Existing refineries

New refineries/ furnaces/ boilers

1 Sulphur Dioxide (SO2)

Gas firing 50 50

Liquid firing 1700 850

2 Oxides of Nitrogen (NOx)

Gas firing 350 250


3 Particulate Matter (PM)

Gas firing 10 5


4 Carbon Monoxide (CO)

Gas firing 150 100


5 Nickel + Vanadium (Ni+V)

Liquid firing 5 5

6

Hydrogen Sulphide (H2S) in fuel gas

Liquid / gas firing

150 150

7

Sulphur content in liquid fuel, weight %

Liquid / gas firing 1.0 0.5




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*As per MoEF notification dated March 18, 2008 vide circular no G.S.R 186(E) for Oil Refinery Industry.

The refinery complex is designed to meet all statutory requirements .Some of the major features of these environmental measures are as follows: (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 MMKcal/hr or more shall have continuous systems for monitoring of SO2 and NOx. Manual monitoring for all the emission parameters in such furnaces/ boilers shall be carried out once in two months.

(3) All the emission parameters in furnaces/ boilers having heat input less than 10 million KCal/hr will be monitored once in a quarter.

(4) In case of continuous monitoring, one hourly average concentration values shall be met 98% of the time in a month. Any concentration value obtained through manual monitoring, if exceeds the limiting concentration value, shall be considered as noncompliance.

(5) Data on Ni + V content in the liquid fuel (in ppm) shall be reported. Ni + V content in the liquid fuel shall be monitored once in six months, if liquid fuel source & quality arenot changed. In case of changes, measurement is necessary after a change.

In addition to the above, the particulate matter in emissions from stacks should not exceed the maximum permissible limit of 5 mg/Nm3.

The refinery complex is designed to meet all the statutory requirements. Some of the major features of these environmental measures are as follows:

Low sulphur fuels will be used for internal fuel purpose.

Heaters/furnaces will be provided with well proven Low NOx burners to reduce the emissions of Nitrogen Oxides (NOx).

Under normal circumstances, there will be no continuous/intermittent point releases of volatile hydrocarbon streams. However, if during startup/shut down or an emergency situation any hydrocarbon streams are released, they will be directed to an elevated flare for complete combustion. This will eliminate the possibility of forming an explosive mixture due to sudden release of unburned hydrocarbons to the atmosphere.

The flares elevation will be such that there will be no impact of thermal radiation on the operating personnel in the refinery. To ensure complete combustion of released hydrocarbons through flares, a pilot burner shall always be burning with the aid of fuel gas. Further, to ensure smokeless and non-luminous flaring, the steam provision at the flare tip is also envisaged.

The heights of various stacks will be determined taking into consideration the "Guidelines for Minimum Stack Height" as per notification by MoEF dated 19th May 1993, which fixes the minimum stack height based on emission of Sulphur Dioxide.




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This is as given below: H=14(Q) 0.3

Where H = Stack Height in m, Q = Sulphur Dioxide emission in kg/hr.

If, the Pollution Control Board specifies any minimum stack height, the higher of the two will be selected.

The refinery complex is designed in such a way that the total emissions from the refinery complex will meet all the applicable standards/stipulations.

The total Sulphur Dioxide emissions from the refinery complex after development of proposed additional units and capacity expansion will not exceed the present limit of 940 kg/hr). Break -up of Sulphur –Dioxide emission, both process and emission due to fuel use, from the refinery complex are given below.

The estimated SOx emissions in different cases are given in Table 8.3.

Table 8.3: SOx balance after Expansion Project

8.2.1.2Ambient 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 in Table 8.4.

Table 8.4: National Ambient Air Quality Standards

(GSR 826(E) dated 16 November 2009)

Sl. No.

Pollutant Time Weighted Average

Concentration in Ambient Air

Industrial, Residential,

Rural & other areas

Ecologically Sensitive

Area

Methods of measurement

1.0 Sulphur Dioxide (SO2)

Annual Average*

50 µg/m3 20 µg/m3 -Improved West and Gaeke

24 hours** 80 µg/m3 80 µg/m3 -Ultraviolet

Fluorescence

S.No SOURCE SOx (kg/hr)

1 Existing FCC 150

2 SRU 52

3 Internal Fuel Oil 312

4 Fuel gas 20

5 INDMAX FCC with FGD 240

6 New SRU 54

Total 828




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Sl. No.

Pollutant Time Weighted Average

Concentration in Ambient Air

Industrial, Residential,

Rural & other areas

Ecologically Sensitive

Area

Methods of measurement

2.0 Oxides of

Nitrogen as NO2

Annual Average*

40 µg/m3 30 µg/m3 -Modified Jacob & Hochheiser (Na-

Arsenite)

24 hours** 80 µg/m3 80 µg/m3 Chemiluminiscence

3.0 Particulate

Matter , Size<10 µ

Annual Average*

60 µg/m3 60 µg/m3 -Gravimetric -TOEM

24 hours** 100 µg/m3 100 µg/m3 -Beta attenuation

4.0 Particulate

Matter , Size<2.5 µ

Annual Average*

40 µg/m3 40 µg/m3 -Gravimetric -TOEM

24 hours** 60 µg/m3 60 µg/m3 -Beta attenuation

5.0 Ozone O3

8 hours** 100 µg/m3 100 µg/m3 -UV Photometric

Chemilminescence

1 hour 180 µg/m3 180 µg/m3 Chemical method

6.0 Lead(Pb)

Annual Average*

0.5 µg/m3 0.5 µg/m3 AAS/ICP method after sampling on EPM 2000 or equivalent filter paper

24 hours** 1.0 µg/m3 1.00 µg/m3 -ED-XRF using Teflon

filter

7.0 Carbon

Monoxide (CO)

8 hours** 2 mg/m3 2 mg/m3 Non Dispersive

Infra red(NDIR)

1 hour 4 mg/m3 4.0 mg/m3 Spectroscopy

8.0 Ammonia

(NH3)

Annual Average*

100 µg/m3 100 µg/m3 Chemiluminescence

24 hours** 400 µg/m3 400 µg/m3 Indophenol blue

method

9.0 Benzene Annual

Average*

05 µg/m3 05 µg/m3 Gas chromotography based continues analyzer

Adsorption and Desorption followed by GC analysis

10.0 Benzo(a)Pyrene (BaP)

Annual Average*

01 ng/m3 01 ng/m3 Solvent extraction followed by HPLC/GC analysis

11.0 Arsenic (As)

Annual Average*

06 ng/m3 06 ng/m3 AAS/ICP method after sampling on EPM 2000 or equivalent filter paper

12.0 Nickel (Ni)

Annual Average*

20 ng/m3 20 ng/m3 AAS/ICP method after sampling on EPM 2000 or equivalent filter paper




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* Annual Arithmetic mean of minimum 104 measurements in a year taken twice a

week 24 hrs. at uniform interval. ** 4 hourly/8 hourly values should be met 98% of the time in a year. However, 2% of

the time, it may exceed but not on two consecutive days.

Whenever and wherever monitoring results on two consecutive days of monitoring exceed the limits specified above for the respective category, it shall be considered adequate reason to initiate regular or continuous monitoring and further investigation.

8.2.1.3 VOC Control, Emission and Monitoring

Fugitive emissions are primarily due to intermittent/continuous leakage or evaporation of Volatile Organic Carbons (VOCs) from processing/storage area of the refinery.

The major sources of such fugitive emissions of VOCs in the refinery are the main processing area, the storage tank farm area for crude oil & products and the loading/unloading gantry area. These fugitive emissions originate from the static and dynamic compressor joints and seals used in flanges, pumps, valve packings and connection joints to the atmosphere like sampling, relief valves, etc. In order to minimize the fugitive emissions, the following measures will be taken during engineering:

Minimum number of flanges, valves, etc.

High grade gasket material for packing

Usage of state-of-the-art low leakage valves preferably with bellow seals

Usage of pumps with Double Mechanical seals for light hydrocarbon services

Provisions of floating roof storage tanks

Provisions of double seal in some of storage tanks

Provision of covering the oil-water separation units in ETP

Provision of seals in the drains and manholes

Storage of General Petroleum Products:

Requirements on type of storage tanks shall be as follows:

Table 8.5: Types of Storage Tanks

Sl. No.

Total Vapor Pressure KPa

Tank Capacity, m3

Type of Storage Tank

1 > 10 4 – 75 Fixed Roof Tank (FRT) with pressure valve vent

2 10 – 76 75 – 500 Internal Floating Roof Tank (IFRT) or External Floating Roof Tank (EFRT) or Fixed Roof Tank with vapour control or vapour balancing system

3 10 – 76 > 500 Internal Floating Roof Tank or External Floating Roof Tank or Fixed Roof Tank with vapour




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Sl. No.

Total Vapor Pressure KPa

Tank Capacity, m3

Type of Storage Tank

control system

4 > 76 > 75 Fixed Roof Tank with vapour control system

Notes: 1. Requirement for seals in Floating Roof Tanks:

I. IFRT & EFRT are to be provided with double seals with minimum vapor recovery of 96%.

II. Primary seal shall be liquid or shoe mounted for EFRT and vapour mounted for IFRT. Maximum seal gap width will be 4 cm and maximum gap area will be 200 cm2/m of tank diameter.

III. Secondary seal will be rim mounted. Maximum seal gap width will be 1.3 cm and maximum gap area will be 20 cm2/m of tank diameter.

IV. Material of seal and construction should ensure high performance and durability.

2. Fixed Roof Tanks will have vapor control efficiency of 95% and vapor balancing efficiency of 90%.

3. Inspection and maintenance of storage tanks should 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 will be examined.

VOC EMISSION STANDARD:

(I) Standards for emissions from storage of volatile liquids are as follows.

Table 8.6:Standards for emissions from storage of volatile liquids

Sl. No.

Item Standards

1 Applicable products Gasoline, Naphtha, Benzene, Toluene, Xylene

2 Type of loading: (i) Road tank truck (ii) Rail tank wagon

(i) Bottom loading (ii) Top submerged

3 Leak testing for Vapour collection Annual leak testing

Emission control for Road tank truck/ Rail tank wagon loading

4 Gasoline and Naphtha: (i) VOC reduction, % or (ii) Emission, gm/m3

(i) 99.5 or (ii) 5

6 Benzene: (i) VOC reduction, % or (ii) Emission, mg/m3

(i) 99.99 or (ii) 20




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Sl. No.

Item Standards

7 Toluene/Xylene: (i) VOC reduction, % or (ii) Emission, mg/m3

(i) 99.98 or (ii) 150

(II) Standards for VOC emissions from wastewater collection and treatment:

a) All contaminated and odorous wastewater streams should be handled in closed systems from the source to the primary treatment stages (oil-water separator and equalization tanks).

b) The collection system should be covered with water seals (traps) on sewers and drains and gas tight covers on junction boxes.

c) Oil-water separators and equalization tanks should be provided with floating/ fixed covers. The off-gas generated should be treated to remove at least 90% of VOC and eliminate odor. The system design should 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 should be designed and operated for safe maintenance of the collection and primary treatment systems.

d) Wastewater from aromatics plants (benzene and xylene plants) should be treated to remove benzene/ aromatics to a level of 10/20 ppm before discharge to effluent treatment system without dilution.

VOC Monitoring:

The standards call for stringent monitoring programme in form of LDAR which is described below:

a) Approach: The approach for controlling fugitive emissions from equipment leaks is to 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 an allowable time frame.

b) Components to be covered: The 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 in. are to be covered.

c) Applicability: The LDAR programme would be applicable to components (given at 2 above) for following products/ compounds: (i) hydrocarbon gases; (ii) Light liquid with vapour pressure @ 200C > 1.0 kPa; and (iii) Heavy liquid with vapour pressure @ 200C between 0.3 to 1.0 KPa.

d) While LDAR will not be applicable for heavy liquids with vapour pressure < 0.3 kPa, it will be desirable to check for liquid dripping as indication of leak.




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e) Leak definition: 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).

Table 8.7: Estimates of equipment leak emissions

Sl. No Component

General Hydrocarbon (ppm)

Benzene (ppm)

Till 31st Dec.2008

w.e.f January 01,2009

Till 31st Dec.2008

w.e.f January 01,2009

1 Pump/ Compressor

10000 5000 3000 2000

2 Valves/ Flanges 10000 3000 2000 1000

3 Other components

10000 3000 2000 1000

f) In addition any component observed 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.

g) Monitoring requirements and repair schedule: Following frequency of monitoring of leaks and schedule for repair of leaks shall be followed:

Table 8.8: Monitoring Schedule of VOC emission

Sl. 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

Immediately Immediately




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Sl. No.

Component Frequency of monitoring Repair schedule

10 Any component with visible leaks

Immediately Immediately

11 Any component after repair/ replacement

Within five days -

h) 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.

i) Emission inventory: The refinery shall prepare an inventory of equipment components in the plant. After the instrumental measurement of leaks, emission from the components will be calculated using stratified emission factors (USEPA) or any other superior factors. The total fugitive emission will be established.

j) 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.

k) Data on time of measurement & 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.

l) The pressure relief and blow down systems should discharge to a vapor collection and recovery system or to flare.

m) Open-ended lines should be closed by a blind flange or plugged.

n) Totally closed-loop should be used in all routine samples.

o) Low emission packing should be used for valves.

p) High integrity sealing materials should be used for flanges.

8.2.1.4 Odour Control

Odour from the refinery complex originates due to fugitive emissions of hydrocarbons, the burning of Sulphur containing fuels, the presence of Sulphides and VOCs in the effluent, the addition of mercaptans to LPG to detect its leakage, etc. Therefore, the design measures suggested as part of controlling stack and fugitive emissions are applicable for odour control as well.

8.2.2 Noise Environment

Ambient Standard for Noise, specified by Central Pollution Control Board (CPCB) is

provided in Table 8.9.

Table 8.9: Noise (Ambient Standards)




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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 a.m and 9 p.m. (2) Nighttime is reckoned in between 9 p.m and 6 a.m. (3) Silence zone is defined as areas upto 100 meters around such premises

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 abovementioned categories" by the competent authority and the corresponding standard shall apply.

Comprehensive measures for noise control will be followed at the design stage in terms of

Noise level specification of various rotating equipment as per Occupational Safety and Health Association (OSHA) standards.

Equipment layout considering segregation of high noise generating sources.

Erecting suitable enclosures, if required, to minimize the impact of high noise generating sources.

Sizing the flare lines with low Mach number to have lower noise levels.

Green belt of appropriate width all around the refinery towards noise attenuation.

8.2.3 Water Environment

8.2.3.1 Effluent Treatment Plant

A new Effluent Treatment Plant (ETP) is envisaged to treat additional effluents (desalter effluent, stripped sour water, spent caustic streams, floor washes, tank farm drains, contaminated rain water, sanitary sewage and other process & non-process effluent streams) streams generated from the refinery expansion project. The treated effluent from ETP shall meet all applicable statutory norms. The treated effluent shall be further treated in a effluent recycle plant to produce DM water thus reducing dependency of refinery on fresh water intake and conserving fresh water natural resources.

The proposed ETP shall broadly consist of the following sections/ treatment chains:




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Process (Oily) Effluent Treatment Section

Spent Caustic Effluent Treatment Section

Contaminated Rain Water (CRW) Treatment Section

Sewage Treatment Plant (STP)

Slop Oil Handling Section

Sludge Handling Section

Chemicals Handling Section

A brief description of above sections/treatment chains is given below:

Process (Oily) Effluent Treatment Section

Desalter effluent, stripped sour water, floor washes and other miscellaneous process effluent streams shall be treated in this section. Design capacity of this section shall be 385 m3/hr (with 10% margins) of process (oily) effluent. The section shall consist of oil removal, biological treatment and polishing sections:

Oil Removal Section: comprising of feed effluent equalization & storage, API Oil Separator (for removal of suspended solids & free oil of droplet size > 150 micron by gravity separation), TPI Oil Separator (for removal of suspended solids & free oil of droplet size > 60 micron by gravity separation) and Dissolved Air Floatation (for removal of suspended solids & emulsified oil of droplet size < 60 micron by pressurized dissolved air & removal of oil scum by scrapper on top).

Biological Treatment Section: A state of the art biological treatment section comprising of Sequential Batch Reactor (SBR) is envisaged for reduction in BOD, COD, Sulphide, Phenol & other biologically degradable components. SBR is a fill and draw batch aerobic suspended growth (activated sludge) process incorporating all the features of extended aeration plant. Reactor operation takes place in certain sequence in cyclic order with each cycle consisting of Anoxic Filling tank, Aeration, Sedimentation/ clarification, Decantation and Sludge withdrawal. This process also effectively removes nutrients and has very high BOD & TSS removal efficiencies.

Polishing Treatment Section:The biologically treated effluent from SBR unit shall be pumped to the Dual Media Filters (DMF) for removal of residual floating BOD & COD along with other suspended matter and then routed to the Activated Carbon Filters (ACF) for final polishing of the contaminants including odor and traces of organics. The treated effluent shall be further treated in a recycle (RO-DM) plant for DM water production.

Spent Caustic Effluent Treatment Section

Spent caustic effluents streams shall be equalized and stored in a tank with necessary hold up. The equalized spent caustic shall be treated either by chemical oxidation (by dosing hydrogen peroxide) or by a combination of wet air oxidation and hydrogen




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peroxide dosing. The treated spent caustic shall be further treated in biological treatment section along with process (oily) effluent streams.

Contaminated Rain Water (CRW) Treatment Section

The contaminated rain water shall be treated in a separate CRW treatment chain comprising of feed equalization & storage facilities, TPI Oil Separator for removal of free oil and suspended solids, Dual Media Filters (DMF) for removal of residual suspended matter and Activated Carbon Filters (ACF) for final polishing of the contaminants including traces of oil. The treated CRW shall be disposed to the nearest storm water drain, with a provision to treat in recycle plant to the extent of available surplus capacity in the recycle plant.

Sewage Treatment Plant (STP)

A MBR (Membrane Bio-reactor) based Sewage Treatment Plant (STP) shall be provided. The plant shall comprise of screen chamber (with bar screen & debris retaining grid, and oil & grease trap in the STP inlet channel), Sewage Collection Sump with submersible MBR Feed Pumps, Package Membrane Bio-Reactor Unit (including anoxic tank, aeration tank, permeate transfer and backwashing pump system, air scouring blowers and air diffuser system, and associated cleaning and chemical dosing facilities) to provide treated sewage of the required quantity and quality. The treated sewage shall be stored in a tank and then pumped for use in horticulture after NaOCl dosing for disinfection.

Slop Oil Handling Section

Slop oil recovered from Equalization tank, API Oil Separator & TPI Oil Separator shall be pumped to Refinery slop oil tank.

Sludge Handling Section

Separate mechanical sludge dewatering facilities shall be provided in the Effluent Treatment Plant for thickening and dewatering of sludge generated from oil handling units and SBR system. The dry sludge shall be disposed and the centrate shall be recycled in the ETP.

Chemicals Handling Section

A common chemical storage and dosing facilities shall be provided in the Effluent Treatment Plant. The chemicals envisaged to be dosed include Alum/PAC (for coagulation purpose), DOPE (for deoiling of emulsified oil and enhance formation of flocs in the flocculation tank of DAF system), HCl (for pH adjustment), Caustic (for pH adjustment), Hydrogen Peroxide (as oxidizing agent), Methanol (for carbon dosing as food source for bacteria), Phosphorous source (for phosphorous dosing as food source for bacteria), Soda Ash (for supplement of alkalinity), NaOCl (for disinfection and to prevent bio-fouling), Dewatering Polyelectrolyte (for aiding sludge dewatering), etc.




REFINERY



8.2.3.1 Recycle (RO-DM) Plant

Feed to the Recycle (RO-DM) plant shall comprise of the treated effluent from ETP, Cooling Tower Blow Downs (~200 m3/h), Boiler Blow Downs (~15 m3/h) and other miscellaneous non-process effluent streams. Treated raw water (~225 m3/h) shall be used as balance feed water to the plant to produce required quantity of DM Water (550 m3/h). The design capacity of the Recycle (RO-DM) Plant shall be to produce 550 m3/hr of net DM water production on continuous basis, which shall be utilized as boiler feed water for generation of steam. Multiple chains shall be provided in the Recycle (RO-DM) Plant to have operational flexibility.

RO reject & other wastewater generated from the recycle (RO-DM) plant shall be partly used for horticulture & fire water makeup, and the balance wastewater (maximum 240 m3/hr with TDS of ~8000 ppm) shall be sent for disposal outside refinery complex.

The proposed recycle (RO-DM) Plant shall be a UF-RO-MB based plant. A brief process description of the plant is as follows:

Pre-treatment: The feed effluent (blow down) streams to the plant shall be equalized and stored in feed blow down storage tank and then pumped to high rate solid contact clarifier (HRSCC) for reduction of reactive silica & suspended solids wherein dolomite lime, coagulant & polymer is added in the clarifier and a sludge blanket is formed. This sludge blanket helps in clarifying the liquid and dissolving the impurities within its suspended macro beds of dolomite lime particles. Clarified water from the HRSCC will be stored in the clarified water tank and then pumped to Dual Media Filters (DMF) and further to Activated Carbon Filters (ACF) units for further filtration. The outlet of the ACF is then routed to UF system for removal of residual suspended solids.

Ultra- filtration Stage: The ACF outlet water along with the ETP treated effluent and balance treated raw water shall be processed in UF system for removal of the residual impurities, which are still slipping through the previous filtration stages. Permeate from UF system shall be stored in RO Feed Tank and then pumped to the Reverse Osmosis system.

Reverse Osmosis Stage: The UF permeate water shall be pumped to the Reverse Osmosis system. Reverse Osmosis stage is preceded by dedicated cartridge filters so as to prevent clogging of downstream RO. The Reverse Osmosis (RO) unit essentially works on molecular level. It separates the molecular impurities from the water thus making one stream rich in salt molecules and other stream lean in salts thus reducing the TDS & Silica in the outlet permeate water.




REFINERY



Degasification Stage: Permeate from the RO system shall be de-gassed in a Degasser Tower where the dissolved CO2 shall be removed. Air is fed to the degasser tower by Degasser air blower. The Degassed Water shall be stored in a Degassed water Tank and then pumped to the Polishing Unit (MB).

Mixed Bed (MB) System: Final polishing of reactive silica and TDS shall be carried out through ion exchange resin based MB unit to achieve the desired DM water quality. The DM water from outlet of the MB units shall be routed to the DM water Storage Tanks.

Sludge Handling: Mechanical sludge dewatering facility for recycle plant shall be provided.

Chemicals Handling: The chemicals envisaged to be dosed include Alum/PAC (for coagulation purpose), Dolomite Lime (for increasing pH/alkalinity in the feed to HRSCC), polyelectrolyte (for flocculation purpose), HCl (for pH adjustment & cleaning chemical), Antiscalant (to prevent scaling in RO), Sodium Meta Bi Sulphite (for de-chlorination in RO feed water), Caustic (as cleaning chemical), NaOCl (as cleaning chemical), Dewatering Polyelectrolyte (for aiding sludge dewatering), proprietary RO cleaning chemicals, etc.

A block diagram of the proposed Effluent Treatment Plant (ETP) and Recycle (RO-DM) Plant is given below:




REFINERY



8.2.4 Land Environment

During the design stage itself due care will be taken to select the processtechnologies generating minimum solid wastes so that their handling,treatment and disposal do not cause any serious impact on the existing land environment. Also, efforts will be made to recycle some of the spent catalysts by way of returning to the original supplier for reprocessing.

The solid wastes management plan proposed is briefly described below.The provisions of Hazardous Waste (Management & Handling) Rules, 2008, amended up to 2009, will be complied with.

There are primarily four types of solid wastes generated in a refinery:

1. Spent Catalyst

2. ETP Sludge’s

Backwash/ reject water for

use as horticulture, fire water

makeup and disposal

(240m3/hr, TDS ~ 8000 ppm)

Oily Process Effluents

(350m3/hr)

Spent Caustic (1m3/hr)

CRWS

Municipal Sewage

Dewatered sludge for disposal

Slop Oil to Refinery Slop Oil Tank

Treated CRWS for disposal to

storm water network.

Effluent Treatment

Plant (ETP)

(Design Capacity of Process

Effluent Treatment ~ 385

m3/hr)

CTBD (200m3/hr,

TDS~4000 ppm)

BBD (15 m3/hr,

TDS ~ 200 ppm)

Recycle (RO-DM)

Plant

(Design Capacity ~ 790

m3/hr feed)

ETP Treated Effluent (350m3/hr,

TDS ~ 2500 ppm)

Treated Raw Water (225

m3/hr, TDS ~ 1000 ppm)

Dewatered sludge for disposal

DM Water (550m3/hr)




REFINERY



3. General Solid Wastes

Spent Catalyst

Patented catalysts are used in various refinery process units. Some of the spent catalyst will be sent back to the original supplier for reprocessing. The other catalysts are normally sent to a secured landfill.

ETP Sludge

The oily & chemical sludgeseparated in different units of ETP, viz., API/TPI/DAF shall be dewatered, handled and disposed as per existing practice. The bio sludge from bio-treatment section will be separately dewatered and utilized inside the refinery as manure.

General Solid Wastes

Small quantities of non-hazardous, non-recyclable solid waste consisting of waste refractory, spent insulation, decoking solid waste used filter cartridges, spent charcoal, spent clay and sand will be generated and sent to nearby authorized landfill agency for further disposal.

8.2.5 Construction Phase

The overall impact of the pollution on the environment during construction phase is localised in nature, reversible and is for a short period.

Air

The suspended particulate pollution generated during transportation will be mitigated by covering the vehicles so as to ensure no spillage. Hosing down the wheels of the vehicles with water and providing washing troughs for them would further mitigate the amount of dust generated. In addition, emission of other pollutants from construction machinery using diesel driven prime movers, will be controlled by proper maintenance.

Noise

Noise emissions from construction equipment will be kept to a minimum by regular maintenance. Heavy and noisy construction work will be avoided during night time.

Water

The existing drinking and sanitation facilities at the refinery will be extended to the construction workforce. This is necessary to reduce pollution of any receiving water body and also to prevent hazards due to water borne vectors. Potable water shall be provided to the workers.

Socio Economic

Being the proposed project, small in terms of construction, there will be no permanent impact on the existing socio-economic system around the refinery.

8.2.6 Operation and Maintenance Phase




REFINERY



It is envisaged that with strict adherence to the pollution prevention and control measures during the design stage, the environmental impacts could be moderated to the minimum possible level during the operation phase.

Air

A) In-plant Control Measures

Some of the important operational measures, which can reduce the impact on air environment, are as follows:

Ensuring the operations of various process units as per specified operating guidelines/operating manuals.

Strict adherence to maintenance schedule for various machinery/equipment.

Good housekeeping practices

B) Stack and Ambient Air Monitoring

In order to keep a check on the emissions of SO2, NOx, SPM and CO from reactor/regenerator, boiler and furnace stacks shall be monitored as per statutory regulations. Continuous monitors for emissions shall be installed on all major stacks. Ambient Air Monitoring Stations shall continuously monitor quality of the air in the vicinity of the refinery premises. Sophisticated instruments for measuring Sulfur Dioxide, NOx, Hydrocarbon, and Carbon Monoxide shall be used in these Monitoring Stations.

Noise

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. The exposure of employees working in the noisy area shall be monitored regularly to ensure compliance with the OSHA requirements.

A green belt of appropriate width exists around the refinery. Treated effluent from the wastewater treatment plant will be used for irrigating this belt.This green belt will help to reduce the noise and visual impact upon the surrounding population as much as possible.

Water

A) In-plant Control Measures

Some of the measures, which can be taken up during operational phase of the complex are:

Reducing the actual process water consumption by way of improvement in operation of processing units.

Looking into more options of reusing the treated effluent besides fire water make up or for horticulture development.




REFINERY



Ensuring proper monitoring and maintenance schedule for the effluent treatment

plant.

Providing reuse and recycle of the treated effluent and water.

B) 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 will be carried out regularly. For regular monitoring of the operation of various pollution control facilities, a laboratory with sophisticated instruments and well-trained manpower shall be established. A separate Pollution Control Cell with qualified Chemical Engineers/Scientists also form part of the facility, 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.

Land

To improve the environmental quality following measures are recommended.

The solid waste generated in the form of packaging material etc. shall be sold off for making it suitable for reuse by reprocessing.

The solids wastes identified to be disposed off in the landfill shall be done as per scientifically established procedure for land filling.

In order to improve the aesthetics in the plant surrounding, further plantation shall be carried out the around the plant boundary.

Socio-Economic

Being the proposed project, small in terms investment, there will be no permanent impact on the existing socio-economic system around the refinery.However, IOCL shall take part actively in the overall development of the area.



Rev. No. A



SECTION 9.0

PROJECT IMPLEMENTATION AND SCHEDULE






9.0 INTRODUCTION

The main purpose for realization of IOCL’s capacity expansion from 13.7 to 18.0 MMTPA with 100% BS-VI Auto fuel production project at Gujarat Refinery implementation schedule is to define an 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.

The project shall be implemented through Conventional Mode of Execution (EPCM, Engineering, Procurement contract Management)

9.1 Project Implementation Plan

GENERAL

Project execution has been considered in two phases

PHASE – I: PRE-PROJECT ACTIVITIES

BDEP for Open art unit carried out by EPCM consultant:

Crude Distillation Unit & Vacuum Distillation Unit (CDU/VDU)

Amine Regeneration Unit (ARU)

Sour Water Stripper Unit (SWS)

Process unit Licensor selection and receipt of BDEP for following units:

INDMAX FCC unit

M. S. Block consist of NHT , CCRU & ISOM

KHDS

GDSU

PPU

SR LPG Treating Unit

Sulphur Recovery Unit

Environment clearance shall be available on start of site grading activities.

Licensor selection is under IOCL scope. BDEP shall be made available for

Licensed units.

All As-Built Drawings related to Facilities to be dismantled / Relocated shall be

provided to EIL by IOCL during Kick off Meeting.

24 weeks considered for receipt of final BEDP from Process licensors from

date of award.

Thermal design of equipment is considered under Licensor scope.

Site free from encumbrances to be handed at the start of pre-project activities.






Investment approval for the Project by the Boards of IOCL / Govt. of India

Clearance has been considered as the start date for Pre-Project activities.

Following enabling activities has been considered under pre-project activities.

Dismantling Works

Site grading work (incl. Road, drain, b/wall, culverts)

Geotech & Topographical survey

Construction Power / Construction Water

Site Office.

PHASE - II: PROJECT IMPLEMENTATION STAGE

Finalization of BDEP after Receipt of Basic Design Engineering Package for

licensed unit is considered as Zero Date for Phase-II.

Following Units, Utilities & Offsite facilities has been considered for execution.

MAJOR PROCESS UNITS

New CDU/VDU : 15000 KTPA

SR LPG Treating Unit : 200 KTPA

INDMAX FCC unit : 2400 KTPA

NHT unit : 2325 KTPA

CCRU : 1500 KTPA

ISOM UNIT : 950 KTPA

KHDS : 850 KTPA

GDSU : 650 KTPA

PPU : 400 KTPA

New Sulphur Block : 300 TPD

(SRU)

UTILITY SYSTEMS

UTIITY SYSTEMS

Sl No

Utility system Capacity

1 Recirculating cooling water

4w+1s cells of 4000 m3/hr, 2w+1s pumps of 9000 m3/hr in place of

Abandoned cooling tower. 8w+1s cells of 4000 m3/hr,

4w+1s pumps of 9000 m3/hr in Bajwa land

2 Compressed Air system 2w+1s compressors of 8200 Nm3/hr. Instrument air dryer of 11000 Nm3/hr.

Nitrogen Plant of capacity: 5000 Nm3/hr

3 Steam generation system 2 Boilers of 150 TPH Capacity

4 Condesate Polishing Unit 415 TPH






5 DM Water system 560 m3/hr capacity

6 Raw water system 11 MGD Bore well and associated

treatment facilities

Storage facilities

2 NHT unit feed tank Two Nos of 12,000 kL

3 KHDS unit feed tank Two Nos of 5,000 kL

4 MTO product storage one No of 5,000 kL

5 LPG Mouded Bullet 6 Bullets of 3500 m3

6 Propylene Bullet 3 Bullets of 3500 m3

Flare system

New flare system 90'' dia, 165 m ht stack and associtated

facilities

ETP 385 m3/hr feed

1. Time span of schedules of above phases are considered independent.

2. Tendering cycle time duration is considered as 3 and 4 months for item rate

contracts and package contracts respectively. However, tender cycle for enabling

works tender, like soil investigation, construction power, construction water site

grading etc. is considered as 2 to 3 Months.

3. Ordering cycle of category-II equipment / materials is considered as 3 and 3.5

months for indigenous and global MRs respectively.

4. Provision for air freighting of imported items shall be made depending on schedule

requirement.

5. Duration of Max. 2 weeks is considered for documents requiring Client’s comments

/ approval. Efforts to be made to get the documents approved with-in a week or

across the table.

6. Since the expected zero date is not known, monsoon period is not indicated on the

schedule bar chart. However, the construction activities shall have the Monsoon

period impact (~4 Months/year). Adequate monsoon protection shall be kept in

scope of respective contractors.

7. Project execution mode is EPCM. However following packages considered as

LSTK Contracts :

a. Raw Water Treatment Plant b. RO-DM Plant c. Cooling water system: Cooling Towers






d. ETP e. New Flare System

8. Power supply has been considered from existing facilities.

9. As mechanical completion of CDU / VDU, PP Unit & LPG treating unit has been

planed early, initial utility requirement for pre-commissioning / commissioning may

be drawn from existing facilities, if required.

10. All statutory approvals (CEA, PESO, EIA, AAI etc.) for establishment of new

facilities have been considered in scope of Client.

11. Clubbing of MRs Covering requirement of various units shall be maximized.

12. Piling work considered under Civil / structural contract.

13. Provision of air freighting for imported items shall be made depend on schedule

requirement.

14. Procurement of structural steel, cement, Plate for tanks, cable trays, cable ducts,

lighting fixtures etc have been considered under respective contractor.

15. The erection of heavy equipment considered in respective Package contractor /

Mechanical contractor scope.

16. Composite Works included to get more competitive bids. Composite works

included mechanical, piping, insulation, electrical & instrumentation works.

17. Construction Area for the following shall be arranged by Client :

Structure steel storage, fabrication

Piping shop fabrication

Site fabricated equipment

Office Space & Storage to the working agencies.

LIST OF ENABLING WORK UNDER PHASE-I

1. Dismantling of abandoned Cooling Tower & its associated facilities

2. Relocation of existing GHC store

3. Relocation of inspection Building , GHC maintenance building.

4. Relocation of training centre.

5. Construction of archive & ES building.

6. Relocation of Fire & safety Building and Air monitoring station.

7. Relocation of CGP-1 Mechanical Maintenance building & rebuilding.

8. Shifting of WO TTL inside Refinery ( near Bitumen loading area).

9. Relocation of petcoke loading gantry.

10. Shifting of LMW & HMW TTL gantry to Dumad with associated facilities at






Dumad.

11. Dismantling of WO & BO TTL gantry

12. Relocation of petcoke weigh bridge.

13. Dismantling of 4 No of WO & BO weigh bridge.

14. Dismantling of TTL new and old control rooms & associated facilities.

15. Dismantling of 10 no of spl product tanks & associated facilities.

16. Dismantling of 4 no of LARO product tanks & associated facilities.

17. Dismantling of UDHE store.

18. Dismantling of Marketing Building (behind Gate No 10) & canteen & associated

facilities.

19. Shifting of material from marketing yard & store area next by dismantling of

Gantry 3/4/5/6 and associated facilities.

20. Area development of New purchased Bajwa & Y-2 plot & Barricading.



Rev. No. A




Chapter 10 Project Cost Estimate

& Financial Analysis




REVISED DRAFT FEASIBILITY REPORT FOR CAPACITY EXPANSION FROM 13.7 TO 18.0

MMTPA WITH 100% BS-VI AUTO FUEL PRODUCTION FOR IOCL GUJARAT REFINERY

Chapter 10 Project Cost Estimate






10.0 CAPITAL COST ESTIMATE

10.1 INTRODUCTION

Indian Oil Corporation Limited (IOCL) operates one of its largest oil refineries at Koyali (near Vadodara) in Gujarat, Western India. The refinery was

commissioned in the year 1965 with a nameplate capacity of 3.0 MMTPA. Over the years, the capacity of the refinery has gradually been increased to 13.7

MMTPA with augmentation of old primary Atmospheric Units (AU-I, AU-II and AU-III) and addition of new primary units viz. Atmospheric Unit-IV in 1978 and AU-V in 1999 as well as augmentation of AU-IV in 2000.

At present, Gujarat Refinery has capacity to process 13.7 MMTPA of crude oil, with crude basket comprising of 55% high sulphur crude (7.6 MMTPA) and

45% low sulphur indigenous crude (6.1 MMTPA).In addition to BS-III/BS-IV fuel products, the refinery also has the capability to produce a wide range of specialty products such as benzene, toluene, MTBE, MTO, Food Grade Hexane

& LAB.

In current refinery operations, refinery produces Gasoline and Diesel

conforming to BS-III & BS-IV specifications. M/s IOCL is now considering expansion of the refinery, with an objective to increase the processing capacity from current 13.7 MMTPA to 18.0 MMTPA.

M/s EIL had carried out the job of configuration study and had prepared a feasibility report for capacity expansion of Gujarat refinery from 13.7 to 18.0

MMTPA as entrusted by M/s IOCL. The report was issued to IOCL on July 2013. This configuration study however had envisaged production of BS-III/IV auto fuels from the refinery with incremental HSD production complying to BS IV

auto fuel specification (no incremental motor spirit production was envisaged). However in view of Auto Fuel Policy 2025 by MOP& NG, M/s IOCL intended to

update the study carried out in 2013 with additional facilities required for meeting 100% BS VI auto fuel production. Accordingly another Feasibility Report for capacity expansion of IOCL Gujarat refinery from 13.7 to 18.0

MMTPA has been submitted to IOCL during Aug-2016 by M/s EIL. This report was prepared based on agreed design basis considering a new HCU and SDA as

additional processing units (as recommended by FR prepared during July-2013), crude/product prices as provided by IOCL and BS VI product quality for

gasoline and diesel. But the IRR arrived for this option was lower than the hurdle values due to current price scenarios and revised base case.

IOCL has now assigned EIL, the job to carry out a revised configuration study

and and to prepare Feasibility report which includes Project cost estimation, Operating cost and Financial analysis with ± 30% accuracy level.






10.2 SCOPE

Cost estimates have been prepared for the selected case considering following Process units, Utilities & Off-sites and associated facilities

PROCESS UNIT UOM CAPACITY

CDU/VDU MMTPA 15.0

SR LPG Treater Unit MMTPA 0.200

INDMAX FCC Unit MMTPA 2.40

PRU MMTPA 0.40

CR LPG TREATMENT UNIT MMTPA 0.80

FLUE GAS DESULPHURIZATION UNIT MMTPA 2.40

NHT MMTPA 2.4

ISOM MMTPA 0.925

CCR MMTPA 1.600

KHDS Unit MMTPA 0.85

Gasoline Desulphurization Unit MMTPA 0.65

PPU MMTPA 0.40

SRU TPD 1 X 300

SWS-I TPH 330

ARU TPH 300

Existing Prime-G Revamp KTPA Revamp of 700 KTPA

Unit

UTILITIES & OFFSITES Utilities & Offsite Facilities Raw Water System,

Cooling Water System, RO-DM including CPU,

Compressed Air & Nitrogen System, Storage

tanks including mounded bullets, Flare

System, Effluent Treatment Plant and offsite

Pumps






10.3 PROJECT COST

Capital cost estimate for the identified scope works for the agreed case works out as under:

Capital cost estimate for the selected case is as under:

Case Cost (Rs Crore)

HIGH CCR INDMAX + PP 15075.35

Validity of Cost estimate is as of 2nd Quarter 2017 price level. Details of Project cost is enclosed as Annexure.

This Capital cost estimate shall be read along with key assumptions and exclusions listed at Para 10.4 & 10.5.

10.4 KEY ASSUMPTIONS

The basic assumptions made for working out the capital cost estimate are as under:

Cost estimate is valid as of 2rd Quarter 2017 price level.

No provision has been made for any future escalation.

No provision has been made for any exchange rate variation.

It has been assumed that all Process units and utilities & off-site facilities would be implemented on conventional mode of execution.

EPCM services cost provision is as a factor basis and is indicative.

Existing infrastructure facilities are adequate and no cost provision has been made for the same.

As Constructability plan has not been approved at this Stage, no cost provision has been made towards interlinking, hook ups and hindrances if any.

Following Exchange rates has been considered (wherever applicable) for cost estimation purpose: 1US$ = INR 67.0, 1EURO = INR 75.0.

10.5 EXCLUSIONS

Following costs have been excluded from the Project cost estimate:

Forward escalation

Exchange rate variation

Cost towards statutory clearances, if any

Any unusual construction requirements






10.6 COST ESTIMATION METHODOLOGY

Cost estimate is based on cost information available from EIL’s current in-house cost data and Engineering inputs for cost estimation purpose. In-house cost data has been analyzed and adopted for estimation after incorporating

specific project conditions. Cost data has been updated to prevailing price level using relevant economic indices.

These Cost estimates are subject to identified scope of work and engineering inputs / technical information, the qualifications, assumptions and exclusions

stated herein.

The accuracy of these estimates is targeted at +30% based on the methodology used and the quality of the information available for cost

estimation.

Plant & Machinery

The cost estimate for Process units has been prepared based on analogous reference of similar unit executed by EIL and cost has been adjusted for

capacity and updated to the present day price level.

The cost estimate for INDMAX FCC Unit and PRU Unit is based on the cost data

provided from M/s IOCL.

Cost provision towards BS VI Prime-G Revamp has been made on Lump sum basis as no details of revamp is available.

Catalyst & Chemicals

Provision for first fill of catalysts required is based on in-house assessment of quantities and in-house cost database.

Cost provision for chemicals has been made on lump-sum basis.

Utilities & Off-sites

The cost estimate made under utilities & off-site facilities are for following systems:

Raw Water System with Intake Well, Raw Water Reservoir and Raw Water Treatment Plant

Cooling Water System

RO DM Plant with CPU

Compressed Air system & Nitrogen Plant

Storage Tanks and Mounded Bullets

Flare system

Offsite Pumps






The cost estimate has been prepared based on system capacities, in-house engineering information and recent in-house cost data available for similar

facilities implemented in other projects.

Cost estimate for firefighting /protection system is based on preliminary MTO

provided by engineering department.

The cost estimate for Offsite piping is based on preliminary MTO and in-house database. Cost Estimate for Electrical is based on preliminary MTO and includes

the cables and Substation Facilities. Cost provision towards Instrumentation has been made on factor basis. Lump sum cost provision for DCS and blending

facilities has been made. Cost provision for Civil and Structural works is made on factor basis. Spares and Construction costs has been made on factor basis.

As Constructability plan has not been approved at this Stage, no cost provision

has been made towards interlinking, hook ups and hindrances if any.

Steam Generation

Additional Steam requirement has been envisaged for which cost provision has been made for 2X150 TPH Utility Boiler based on recent in-house cost data.

There is no CPP envisaged under this project. Power import shall be done to cater the Power requirement of the Refinery.

Piling

The Cost estimates for piling works is based on piling quantities (34000 Nos)

and in-house cost data.

Effluent Treatment Plant

Cost provision has been made for Effluent Treatment Plant based on

Engineering information and in-house cost data

Indirect Costs, Exchange Rates and Statutory taxes / duties

Indirect Costs and Exchange Rates

The cost estimate is based on following Exchange Rates & Indirect costs:

Exchange Rate 1 US$ = Rs. 67.0, 1 EURO = Rs. 75.0

Ocean Freight 5.0% of FOB cost of imported equipment

Port Handling 2.0% of FOB cost of imported equipment

Inland freight 5.0% of FOB cost of imported equipment and ex-works cost of indigenously sourced

equipment

Insurance 1% of total 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.

Statutory Taxes & Duties

Provision for statutory taxes & duties has been made as under:

Custom Duty 26.43% of CIF cost of imported equipment (7.5% Basic Customs Duty + 12.5% CVD+ 3% Education Cess and 4% SAD).

Excise Duty 12.5% of ex-works cost of indigenously sourced equipment.

Central Sales Tax 2% of ex-works including excise duty for cost of indigenously sourced equipment.

Service Tax on Engineering

15.0% ( 15% Service Tax + 0.5% Swachh Bharat + 0.5% Krishi Kalyan Cess)

Service Tax on Works Contract

6.0% (15.0% of 40%) on Contract Value

VAT on Works Contracts

8.75% (12.5% of 70%) on Contract Value

Labour Cess 1% on Contract Value

Land

Cost provision has been made for Land as per the input from M/s IOCL.

Site Development

Cost provision based on the information from M/s IOCL has been made under

this head which includes enabling facilities like dismantling works of various facilities including Tanks and buildings and Piping re-routing facilities,

construction of new buildings etc. Cost towards Soil Investigation as provided by M/s IOCL is also included under this head.

Additional cost towards Site Grading, Compound Wall, Drains and RCC

pavements has been made based on preliminary MTO and in-house cost data.

Royalty, Know-How & Basic Engineering

Provision for Royalty, Know-how, Process Design, Licensor’s expatriate and Basic Engineering has been made based on in-house information. Cost includes

provision for withholding tax and service tax.






Project Management, Detailed Engineering, Procurement Services &

Construction Supervision (EPCM Services)

A provision in the cost estimate has been kept towards the services of project

management, detailed engineering, procurement services, construction supervision and commissioning as per information. This fee is indicative in nature. Service tax on EPCM fees has also been considered.

COT, SPM & Pipeline

SPM, COT and Pipeline have not been envisaged.

Roads & Buildings

Cost Provision for Roads & Buildings has been made as per the cost provided by M/s IOCL.

Additional Cost for Roads and Buildings such as Control Rooms, Substations etc

has been made based on the preliminary MTO provided by In-house Engineering. Buildings cost is based on preliminary area.

Infrastructure Facilities

It has been assumed that existing infrastructure facilities shall meet the

requirement of the project and no cost provision has been made under this head.

Construction Site Facilities

Cost provision for Construction Site Facilities has been made @0.25% of Plant

& Machinery for items such as Construction Power, Construction Water and Labor camp etc. M/s IOCL has informed that some amenities shall be available

from BS-VI Construction Facilities during J-18 execution.

General Site Facilities

Cost provision has been made for items such as Laboratory equipment and Office equipment & furniture based on the cost information by M/s IOCL.

Township

Not required.

Owner's Construction Period Expenses

Cost provision for Owner's Construction Period Expenses has been made @ 1.5% of Plant & machinery for items such as project management, salaries &

wages, feasibility reports, training, legal expenses, office & vehicles hire / rentals/maintenance, stationary, postage, travel etc. during project construction period.






Start-up & Commissioning

A cost provision for start-up & commissioning has been made @ 1.5% of plant

& machinery cost.

Contingency

Provision for contingency has been made @ 10% of capital cost excluding interest during construction (I.D.C) and working capital margin. The provision

has been kept to take care of inadequacies in estimate basis definitions (including design & execution) and inadequacies in estimating methods and

data elements.

Working Capital Margin

Not required.

Interest during construction

Interest during construction period required for the project has been worked out based on following:

Debt - Equity ratio : 1:1

Rate of interest : 9.35%

Construction period : 3.5 years

Equity and Debt to be spent concurrently

Based on the above assumptions and exclusions, Project cost summary is enclosed as Annexure.






10.7 FINANCIAL ANALYSIS

Based on capital cost, operating cost and sales revenue, financial analysis have

been carried out for calculating internal rate of return (IRR) with a view to establish profitability of the project. The basis of financial analysis is as under:

1 Construction Period 42 months

2 Project Life 15 years

3 Debt / Equity Ratio 1 : 1

4 Expenditure Pattern Equity concurrent to Debt

5 Loan Repayment period After moratorium period in 8 years

6 Moratorium Period 2 Years

7 Interest on Long Term Debt 9.35%

8 Capital Phasing (Total Capital)

1 Year 10.0%

2 Year 35.0%

3 Year 45.0%

4 Year 10.0%

9 Capacity Build – up

1st year 60%

2nd year 90%

3rd Year onwards 100%

10 Corporate Tax Rate @ 30%+ 12.0% surcharge+ 3% Education cess

11 MAT @ 18.5 %+ 12.0% surcharge+ 3% Education cess

Annual operating cost has been computed based on annual quantities on differential basis considering average prices towards crude, utilities and fixed operating cost (Salaries &

wages, General Administrative expenses@ 0.5% of plant & machinery, Repair &

Maintenance @ 1% of Plant & Machinery and Insurance & taxes @ 0.5% of the capital

cost).

M/s IOCL provided Cost reduction to be considered towards repair and maintenance,

establishments for operation of single CDU/VDU instead of 4 nos, FPUI, VDU & non

operation of HGU .The same has been taken care under Operating Cost.

Annual sales revenue has been worked out based on annual quantities on differential basis considering average prices towards products as provided by Client. Details of

annual operating cost and Sales revenue is enclosed as Annexure.

Financial Analysis of project has been worked out as per above details.






Based on above methodology, Capital cost estimate, Operating cost, Sales revenue and financial analysis has been carried out for agreed case i.e. HIGH CCR INDMAX + PP based on the Crude and Product average prices and the results is summarized below:

S.No ITEM HIGH CCR INDMAX + PP

Case-572

1 Capital Cost 15075 35

2 Variable Operating Cost 12196 51

3 Fixed Operating Cost 232 84

4 Total Operating Cost 12429 34

5 Sales Revenue 17325 26

6 IRR on Total Capital

Pre-Tax 20.48%

Post-Tax 16.20%

7 IRR on Equity

Pre-Tax 26.50%

Post-Tax 20.34%

Enclosures:

Annexure-I

Capex, Opex, Sales Revenue & Financial Results

1. Project Cost Summary (1 sheets)

2. Utilities / Off-sites cost summary (1 sheet)

3. Annual Operating cost (1 sheets)

4. Annual Sales Revenue (1 sheets)

5. Cash flow statement (1 sheets)



Rev. No. A



SECTION 11.0 HEALTH SAFETY & ENVIRONMENT



Rev. No. A

Page 281 of 284



11.1 HEALTH & SAFETY

In order to ensure identification of any hazards associated with the project, which could adversely affect the health and safety of personnel both within and outside the complex, and the environment, a sound Health, Safety and Environment (HSE) policy is proposed to be adopted during the course of project execution with primary objectives as under. a) Provide clearly defined safety system goals for the design aspects of the

project. b) Ensure a safe working environment for all plant personnel. c) Through intrinsic safety in design, eliminate the potential for occurrence of

hazardous scenarios that can result in injuries, environmental damage, business interruptions or loss of assets.

d) Minimize the risk and consequences of an accident which cannot be eliminated by intrinsic safety in design.

e) Maintain satisfactory means of escape and evacuation from any conceivable incident.

f) Minimize the potential for pollution of the environment from accidental spills, venting or flaring of hazardous materials.

In order to ensure the above, it is proposed to carry out the following HSE related studies during the engineering stage:

- Hazard identification (HAZID) study - Hazard and Operability Study (HAZOP) - Quantitative Risk Assessment (QRA) Study - Environmental Impact Assessment (EIA) - Hazardous Area Classification

Other health hazards that are proposed to be studied are as follows: a) Lighting b) Noise c) Thermal Environment

11.2 ENVIRONMENT

Wastes are streams that are not produced for sale or internal consumption. Some of these wastes may be toxic, poisonous, flammable and harmful to the environment. Hence, it is of utmost importance that the wastes generated are disposed off safely. When waste production cannot be avoided, the following design principles shall be adopted to achieve environmental compliance: a) Minimise the waste generation b) Safe disposal facilities within development boundary c) Safe disposal facilities outside the unit.



Rev. No. A

Page 282 of 284



Wastes generated are of three types: a) Solid b) Liquid

i. Aqueous ii. Non-aqueous

c) Gaseous i. Point source gaseous emissions ii. Fugitive emissions

Adequate care will be taken in process design to minimize the quantity of waste produced. In addition, solid, liquid and gaseous wastes generated from various processes in the refinery will be handled in a manner that minimizes their impact on the environment.

In addition a Plant Safety and Environment Cell consisting of qualified and experienced technical personnel from the relevant fields will be in place to ensure effective operation of all pollution control measures and suggest further improvements where necessary.



Rev. No. A



SECTION 12.0

CONCLUSION & RECOMENDATIONS



Rev. No. A

Page 284 of 284



CONCLUSION & RECOMMENDATIONS

IOCL intends to enhance the crude processing capacity of its Gujarat Refinery from present 13.7 MMTPA to 18.0 MMTPA with the consideration of production of 100% BS VI quality gasoline and diesel products from the refinery. The feasibility study of the expansion project has been carried out for processing of additional 4.3 MMTPA Basrah Lt Crude.

Several configuration were studied with various options of secondary processing and bottom up gradation. Based on preliminary analysis, the option with High CCR INDMAX with polypropylene production was found to be most optimum. Following new facilities are required to increase the existing refinery capacity from 13.7 to 18.0 MMTPA with the objective to produce BS VI quality products.

New AVU with LPG/ATF treating Unit

New INDMAX Unit including PRU and LPG treatment

New Poly-Propylene Unit

New MS Block with NHT/ISOM/CCRU

New Gasoline Desulphurization Unit

New KHDS Unit

New Sulphur Recovery Unit along with TGTU

New Sour Water Stripping Units ( Single/Two Stage)

New Amine Regeneration Unit

Associated Utility facility and offsite facilities.

The following are the result of financial analysis

The total Capex estimated with +30% accuracy Rs. 15075.35 crores.

IRR on total capital works out to be 16.20%, post tax.

The present configuration results in high distillate yield and zero fuel oil sales.

The addition of these facilities along with expansion from 13.7 to 18.0 MMTPA results in enhancement of GRM of the refinery. The Capex required for expansion is estimated to be 15075 Cr with +30% accuracy, which gives a very attractive post tax IRR of 16.2% on total capital. The resulting configuration enhances the refinery capability to produce more diesel and gasoline along with petrochemical production. At the same time long term objectives of zero fuel oil, zero kerosene and minimization of naphtha is achieved. Therefore expansion of refinery form current capacity of 13.7 to 18.0 MMTPA is highly recommended.



Rev. No. A


PRODUCTION


ANNEXURE-II



Rev. No. A


PRODUCTION


ANNEXURE-III



Rev. No. A


PRODUCTION


ANNEXURE-IV

LAB REVAMP FEASIBILITY REPORT

Introduction

Linear Alkyl Benzene Unit (LAB) was commissioned in Aug 2004 with a production capacity of 1, 20,000 MTPA of LAB. The LAB Complex includes Kerosene Pre-fractionation Unit, the Distillate Unionfining Unit, the Molex Process Unit (comprising the “Front End Units”), the Pacol Process Unit, the PEP Process Unit, the Detal Process Unit (comprising the “Back End Units”), and the Hot Oil System. In the Front End section n- paraffin is made from Kerosene and this n-paraffin is fed to PACOL unit in Back End Section. Linear Alkyl Benzene(LAB) is produced in Back End Section by reacting treated Pacolate (from PEP) and Benzene using heterogeneous non-corrosive catalyst to form LAB.

Objective: Increasing the capacity of LAB complex to 135% of the original design capacity or 162,000

MTA of LAB product.

Basis

This study identifies which major pieces of equipment will require modification or replacement to achieve the target capacity The basis of the study was a single feed case with a Low molecular weight (“LMW”) LAB product (having a molecular weight in the range of 235-239) and a high molecular weight (“HMW”) LAB product (having a molecular weight in the range of 239-243). As per the feasibility study Front End section of LAB Complex can be revamped for 35% capacity increase over the name plate capacity, while in the BE section of the LAB plant, the capacity increase can be by 40% over the name plate capacity. Hence, LAB production can be increased to 162 KTA with 135 % revamp.

Kerosene fractionation unit

The primary purpose of the Kerosene Pre-fractionation Unit is to prepare a kerosene heart cut (nominally C10-C13 range) that contains the n-paraffins that, after hydroprocessing and selective recovery, will meet the desired molecular weight and light/heavy tail requirements for the LAB product. All equipment was evaluated for both the HMW Case and the LMW Case with a normal paraffin product capacity 130 KMTA. Preliminary evaluation indicates that the HMW Case will govern most of existing equipment sizing. The LMW Case operation will govern the Feed Surge Drum, Feed-Rerun Bottoms Exchanger, Rerun Column Net Bottoms Cooler, Feed Pumps and Rerun Column Bottoms Pumps. The Stripper Column and Rerun Column trays appear to be adequate. However the trays require a more detailed evaluation in the next phase. Rerun Column packing needs to be replaced with higher capacity packing. The Feed-Rerun Pump around Exchanger requires an identical shell in parallel for revamp requirement. The Stripper Column Condenser requires additional rows or bays to meet the revamp requirement. For the Feed–Rerun Bottoms Exchanger, the existing exchanger and one shell of the identical exchanger installed already to meet the revamp requirement. All other equipment appear to be adequate.

Distillate Unionfining Unit

The Distillate Unionfining Process Unit hydrotreats kerosene range material to meet the Molex Process Unit feed specifications. The flow scheme is typical of a hydro-processing unit and consists of a reactor section, makeup gas section and a stripping section. The feed to the unit is a kerosene “heart-cut” (C10-C13 range) from the Rerun Column in the Kerosene Pre-fractionation Unit.

There is nitrogen in the feed at about the 8 wt.-ppm level. Also there is chlorides of up to 3 wt.-ppm in the feed. This unit was not designed for any chlorides in the feed. Chlorides can lead to stress corrosion cracking of the valve trims in the Separator and Stripper overhead. It is recommended to upgrade air cooler tubes and header to Alloy 625. In addition the piping from the air cooler to the Separator will be upgraded to Alloy 625 replacing the 300 series stainless steel valve trims for these services with Monel trims. To achieve the revamp capacity, the Reactor internals need major modifications or replacement. An additional shell of exchange be added in series to the Combined Feed Exchanger in order to retain the existing Product Condenser. The operating pressures of the 3rd

and the 4th stages of the Makeup Gas Compressor needs to be raised in order to reduce the volumetric flow of the inlet gas. For the Stripper Overhead Trim Condenser, replace the existing exchanger to increase the operational flexibility of the Stripper.

Molex Process Unit

The Molex Process is an adsorptive separation method that utilizes molecular sieves for the separation of n-paraffins from branched and cyclic hydrocarbons. The separation occurs in the liquid phase under isothermal conditions. Hydotreated kerosene from Unionfining is feed to the Molex Unit.

All equipment was evaluated for both the High Molecular Weight case (HMW) and the Low Molecular Weight (LMW) case. The majority of the equipment was governed by the HMW case. The feed rate for both cases was set at rates to produce 130 KMTA n-paraffins.

New Raffinate Bottoms Trim Cooler is required. The extract Column bottoms trim cooler can be replaced with Raffinate Bottoms Trim Cooler. The existing trays in Raffinate Column and Extract Column need to be replaced with new UOP SimulFlow Trays and PFMD High Capacity trays, respectively. The Desorbent Stripper needs to be replaced with a new column or the existing shell be retained, the trays replaced with high-capacity ECMD trays and relaxing them desorbent specifications.

The existing tube bundles need to be replaced with High Flux tube bundles within the Raffinate Column Reboiler, Desorbent Stripper Reboiler and Extract Column Reboiler. An additional shell in series is required for the Raffinate Column Bottoms-Desorbent Exchanger. Replacement impellers are required for the Chamber Circulation, Raffinate Column Overhead, Raffinate Column Bottoms, Raffinate Column Side-cut, Desorbent Stripper Bottoms, Extract Column Bottoms, Extract Column Side-cut and Desorbent Pumps. The Charge Pumps need to be operated in parallel. All other equipment appear to be adequate.

Pacol with DeFine Process Unit

The Pacol Process is a fixed bed catalytic process to selectively dehydrogenate a high purity, normal paraffin feed to the corresponding mono-olefin product. A DeFine reactor downstream reduces the di-olefins in the Pacol product. A stripping column is provided to remove light ends from the product before it is sent to the PEP unit.

PEP Process Unit

The Pacol Enhancement Process (PEP) unit is a fixed bed adsorption unit for the selective removal of aromatic components from the Pacol product stream. Existing adsorbers will be adequate for the revamp conditions. However, once the unit is in operation, an

adjustment in cycle time may be required. It is expected that the desorbent and purge rates are to maintain

the same as originally designed. Hence, all the equipment downstream of the adsorbers will be suitable for

the revamp conditions. Due to changes in the Detal Unit, the temperature of the desorbent entering the PEP

Unit has increased. As a result, two new coolers are required to replace the existing Desorbent-Pacolate

Exchanger which will be deleted for the revamp. The design of the coolers will be such that the purge

exchangers (Pacolate-Purge Exchanger and Purge Heater) will be adequate.

Detal Process Unit

The Detal Process is a catalytic process to alkylate benzene with linear olefins to prepare linear

alkylbenzene (LAB).

All equipment were evaluated for both the High Molecular Weight (estimated LAB MW = 240.8) and the

Low Molecular Weight (estimated LAB MW = 237.2) feed cases.

For the revamp study, 20% increase in Detal catalyst volume based on the same paraffin to olefin conversion

in the Pacol Unit was assumed. Also, the Benzene to Olefins ratio remain unchanged, reduced splits in the

Recycle Paraffin Stripper, and the proposed re-use of the Detal’s regenerant.

Benzene effluent as desorbent to the PEP unit (for assessing the Benzene Column). It requires modifications

to Detal Reactor that include either increasing the effective tangent length or replacing existing reactors

with two new reactors. Implementing new benzene flow scheme utilizing spent regenerant benzene as

desorbent in the PEP unit to reduce the benzene circulation load. Retaining all of the columns in the Detal

Unit as-is, with the exceptions of the Benzene Column trays and the contact condensing packing of the

Recycle Paraffin Stripper and Paraffin Column. In order to supply the additional cooling duty required for

revamp operation, the addition of three new water trim coolers is required. These services are the Paraffin

Column, LAB Column, and Finishing Column overheads.

All the exchangers appear to be adequate for the Detal Process Unit with the exceptions of the Reactor

Charge Heater, Benzene Column Reboiler, Paraffin Column Reboiler, LAB Clay Treater Effluent

Exchanger, Finishing Column Reboiler, Finish Column Preheater, Net LAB Trim Cooler, Benzene Column

Condenser, Paraffin Column Overhead Cooler, and Finishing Column Overhead Cooler, which may require

replacement or modification.

Most of the pumps appear to require either replacement or modification for the Detal Process Unit with the

exception of the Desorbent Pumps, Benzene Column Bottoms Pumps, Recycle Paraffin Stripper Bottoms

Pumps, Paraffin Column Bottoms Pumps, LAB Column Bottoms Pumps, and Off-Spec Pump which appear

to be adequate for the revamp operation.

Hot Oil Unit

The Hot Oil System is a heat source for a number of exchangers within the LAB Complex. The transfer of

heat is accomplished by pumping hot oil (Therminol 66) through a recirculation network between the

various complex units. After the exchange of heat, the cooled oil is returned to the Hot Oil Surge Drum.

The accumulative heat loss from the hot oil users is replenished with a fired heater that increases the hot oil

temperature back up to the original supply temperature. No apparent revisions are required to the hot oil

system except for the replacement of the impellers of the Hot Oil Pumps.

Utility The estimated utility requirements after revamp are tabulated below:

The incremental annual utility consumption post revamp will be.

Power = 1300.5 KW

DM water = 1 m3/hr = 8000 MT/year

Cooling water = 459.16 m3/hr = 3673280 m3/year

Fuel = 19590 MT/year

Units Power

( KW)

HP

MT/hr

MP

MT/hr

LP

MT/hr

Condensate

Kg/hr

Cooling Water

m3 /hr

Fuel

MMKCal/hr

Total 9550.5 19 2.4 -19 5400 1219.6 129.25

Prefractionation Adequate

(Yes/No) Comments

Stripper Column Yes Vessel adequate. Trays marginally adequate. More detailed

evaluation of trays in next phase.

Rerun Column Yes

Vessel adequate. Trays marginally adequate. Contact

condenser packing should be replaced. More detailed

evaluation of trays in next phase. Replace contact condenser

packing.

Unionfining Adequate

(Yes/No) Comments

Charge Heater Yes No change foreseen.

Reactor Yes Vessel adequate, but new Internals required.

Stripper Yes Shell and trays are adequate. Review bottom trays with

vendor in next phase

Combined Feed

Exchanger No Add another shell in series

Recycle Gas Compressor Yes Add pilot operated pressure relief valve because of lower

pressure margin.

Make-up Gas

Compressor No

Maximize first two stages, then make up with PSA H2.

Increase operating pressure of 3rd and 4th stages.

Modification to control scheme recommended. Add pilot

operated relief valves because of lower margin.

Molex Adequate

(Yes/No) Comments

Adsorbent Chambers Yes Adequate.

Adsorbent

Chamber Control

System

No change

Rotary Valve Yes Adequate.

Raffinate Column Yes Vessel adequate, but trays must be replaced with high

capacity trays.

Desorbent Stripper No Vessel inadequate

Extract Column Yes Vessel adequate. Replace existing trays with high capacity

trays

Pacol & Define Adequate

(Yes/No) Comments

Charge Heater Yes Replace existing burners

Pacol Reactor Yes

Keep reactor shell. Modify internals to increase catalyst

volume. New catalyst batch size will be 46% higher than the

current batch size.

DeFine Reactor Yes No change

Product Stripper Yes Vessel adequate. Replace bottoms section trays

Combined Feed

Exchanger Yes

Pressure drop across spray bar is high. Replace the spray bar

distributor.

Recycle Gas Compressor Yes Keep compressor. Replace gear box to meet minimum H2/HC

ratio.

PEP Adequate

(Yes/No) Comments

Adsorbers Yes No changes

Desorbent Column Yes No changes

Depentanizer Yes No changes

Detal Adequate

(Yes/No) Comments

Reactors No LHSV inadequate to meet target linearity and catalyst life

expectations.

Benzene Column Yes Implement new benzene flow scheme. Keep shell. Replace

trays with high capacity trays in required sections.

Recycle Paraffin Column Yes Keep shell and trays. Replace packing in contact condenser

section.

Paraffin Column Yes Keep shell and trays. Packing should be reviewed

LAB Column Yes No change

Finishing Column Yes No change

Hot Oil section Adequate

(Yes/No) Comments

All equipment Yes No change

Please note that this UOP information is of confidential nature for use only by personnel within your organization requiring the information. This material shall not be reproduced in any manner or distributed outside your organization for any purpose whatsoever except by written permission of UOP.and except as authorized under agreements with UOP.

Syn Gas, Hydrogen and n Butanol Project Description

Project Description

As a part of integrating its Petrochemicals value chain, IOCL intends to install a complex comprising of Synthesis Gas, Hydrogen generating Unit, Normal Butanol at Gujarat Refinery based on propylene potential from its various refineries, such as Gujarat and Mathura. Feed Propylene will be recovered from FCC LPG and Coker LPG. Normal Butanol will be produced from Propylene, Syn Gas & Hydrogen and Acrylic Acid will be produced from Propylene. Normal Butanol and Acrylic Acid will be utilized for production of Butyl Acrylate.

Synthesis Gas Unit: A new Syn gas unit has been envisaged to produce Syn Gas (capacity=8140 Nm3/h) and Hydrogen (capacity=4290 Nm3/h), the key raw materials for production of Oxo Alcohol. The unit is designed to process both Naphtha / Natural gas feedstock depending on availability.

Normal Butanol Unit: A new Oxo Alcohol Unit with capacity to produce 90 KTA Normal-Butanol (NBA), a major feedstock for Butyl Acrylate production, has been considered. Oxo unit utilizes propylene and Syn gas as feedstock. Iso-butanol (~9 KTA) is a byproduct from the Unit and is intended for merchant sale.

Acrylic Acid Unit: Propylene from PRU along with air are the major feedstocks for the Acrylic Acid unit (90 KTA capacity). Acrylic acid is produced by oxidation of propylene in presence of oxidation catalyst.

Butyl Acrylate unit: NBA and Acrylic Acid undergo esterification in BA unit (150 KTA capacity) to produce Butyl Acrylate, the main product from the project.

Following project configuration has been considered for the project considering feedstock availability, preliminary market inputs and licensor feedback:

Butyl Acrylate

Iso-Butanol

Oxidation Unit

Propylene

Acrylic Acid Esterification Unit

Air

Oxo Unit Syn gas

Propylene Butyraldehyde (Normal and iso)

Hydrogenation Hydrogen N-Butanol

Syn Gas Unit

Naphtha

feasibility report of j-18...

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