BHARAT OMAN REFINERIES LIMITED. BINA REFINERY

Transcription

1 FEASIBILITY STUDY FOR MINIMIZATION OF KEROSENE FROM BHARAT OMAN REFINERIES LIMITED. BINA REFINERY REPORT NO. VOLUME 1 OF 1 MARCH -2017

2 FEASIBILITY STUDY FOR MINIMIZATION OF KEROSENE FROM CLIENT BHARAT OMAN REFINERIES LIMITED. BINA REFINERY PREPARED BY ENGINEERS INDIA LIMITED NEW DELHI EIL JOB No. A953 PO No REPORT No. VOLUME 1 OF 1 MARCH -2017

3 COPYRIGHT LENEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM Rev. No. 1 Page 1 of 1 COPYRIGHT This document is copyright protected by EIL and is produced for the client M/S BORL. Neither of this document or any extract from it may be produced, stored or transmitted in any form for any purpose by any party without prior written permission from EIL. Request for additional copies or permission to reproduce any part of document for any commercial purpose should be addressed as shown below: Head of the Department (Process - 2) 5 th Floor, Tower II R&D Complex, Engineers India Limited Sector-16, Gurgaon India Telephone: EIL reserves the right to initiate appropriate legal action against any unauthorized use of its Intellectual Property by any entity.

4 TABLE OF CONTENTS Rev No 1 Page 1 of 1 TABLE OF CONTENTS 1. EXECUTIVE SUMMARY 2. INTRODUCTION 3. SCOPE OF WORK 4. METHODOLOGY 5. DESIGN BASIS 6. REFINERY CONFIGURATION STUDY 7. UTILITIES AND OFFSITE 8. CAPITAL COST AND FINANCIAL ANALYSIS 9. HEALTH SAFETY & ENVIRONMENT 10. RECOMMENDATIONS ANNEXURES I II III IV V VI VII OVERALL PLOT PLAN PROCESS FLOW SCHEME BLOCK FLOW DIAGRAM CRUDE ASSAY BLENDING EQUIPMENT LIST PROJECT IMPLEMENTATION SCHEDULE

5 EXECUTIVE SUMMARY Rev. No. 1 SECTION 1.0 Page 1 of 1 SECTION 1.0 EXECUTIVE SUMMARY

6 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 1 of Executive Summary 1.1 Introduction BORL Refinery was implemented as part of the New Refinery Project and commissioned in June Refinery has been designed for 65: 35 weight blend of Arabian Light and Arabian Heavy for a crude processing capacity of 6.0MMTPA. Presently BORL is augmenting the processing capacity of refinery from 6 MMTPA to 7.8 MMTPA by Debottlenecking of the existing units. Post Revamp, BORL wants to minimize the Kero production due to falling consumption trend and government anticipated policy towards converting some of the State as kerosene Free State, Meantime an industry meeting was held at CHT, Noida on 17th Feb 16 for the reduction of Sulphur in kerosene /ATF. It was deliberated and finalized to reduce the Sulphur content in SKO from present 0.25 wt% to 0.20 wt% and similar reduction of sulphur in ATF specification is also expected. In view of the above, BORL wants to study the various options available to minimize the Kero production and sulphur reduction in Kero/ATF along with following overall objectives: Meeting BS V/VI specifications for MS and HSD. Maximization of Diesel Production. The capital cost estimate accuracy of this study is within ± 20% for final selected case. 1.2 Basic Design Parameters Crude Mix The following crude mix is considered for Kero minimization study Design Crude Case: 100% Arab Mix ( AL: 65, AH:35) Refinery Capacity The study is carried out for 7.8 MMTPA crude processing in Refinery On-Stream hours The stream hour considered for the study is 8280 Hrs/Annum Objectives of the study Nil or Minimization of Kerosene production from the refinery Reduction of Kerosene sulphur Meeting BS V / VI Specifications of MS and HSD. Maximization of Diesel production.

7 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 2 of Product Demand The product demand considered for the study is as below: Table 1.1: Product Demand S.No. Product Minimum (KTPA) Maximum (KTPA) 1. LPG As Produced 2. Naphtha Nil 3. MS BS V/VI As Produced 4. Jet fuel 0.50 MMTPA (max) 5. Kerosene 0.15 MMTPA (max) 6. Diesel BS V/VI As Produced 7. Pet Coke As Produced 8. Sulphur As Produced Feed, Product and Utility Prices Table 1.2: Feed and Product Prices Products 1 Year (Avg Price of Rs / MT )* 3 Year (Avg Price of Rs / MT )* Crude Arab Mix (65:35) Kuwait Basra Light Fuel Coal Products LPG Naphtha MS BS III MS BS VI Jet fuel Kerosene Export Diesel BS III Diesel BS VI Pet Coke Sulphur * Two pricing basis to be considered Pricing Basis: Average sales prices for the years as mentioned above.

8 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 3 of 10 Table 1.3: Utility Prices Utilities UOM Price Raw Water Rs/m3 2 Power (Captive) Rs/KWH 9.1 Imported Power Rs/KWH 6.87 Cooling Water Rs/m DM Water Rs/m3 70 Steam Rs/MT 2875 Nitrogen Rs/Nm Product Specifications Product specifications as provided by BORL. Design basis Table No A.4 of this study report has been followed in the Study. 1.3 Kero Minimization Study Options: Option 1: With Single Draw of Kero product from Crude Column Kerosene minimization by drawing the light cut Kero from the column meeting the specification and dropping the heavy end Kero into Gas Oil internally. Kerosene minimization by increasing the Naphtha FBP from 150Deg C to 170 Deg C and thereby reducing the Kero Cut Range. Drawing the deep cut Gas oil to absorb more kerosene into HSD by blending. Option 2: With two draw of Kero product from Crude Column Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero / ATF specification and Heavy Kero desulfurization in HCU/DHDT. Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero / ATF specification and with new Heavy Kero desulfurization unit. Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero/ATF specification and Drawing the deep cut Gas oil to absorb more heavy kerosene into HSD by blending.

9 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 4 of Key Findings of Study Following are the key findings of LP study: 1. By dropping the Kerosene into Gas oil, DHDT Unit capacity required will be more than the revamped Design Capacity. These cases will also require modifications in Gas Oil Section of CDU (LGO Product Pump and HGO Product Pump). 2. By Lifting the Kerosene into Naphtha, Naphtha Section of CDU (Overhead Naphtha Pump) and NSU (Stabilizer Reboiler, Stabilizer Bottom Air cooler) will also require modifications. 3. By Lifting the light end kerosene into Naphtha and also dropping heavy end kerosene into Gas Oil, Kerosene production from the refinery can be made NIL, but with modifications as required in point number 1 and 2 above. 4. Without KHDS unit, Kerosene produced from CDU cannot be blended with BS VI Diesel even after relaxation of lower density specification because of sulphur constraint in BS VI Diesel. 5. As Per Revised BS VI Diesel Specification, 95% volume recovery has been reduced to 360 Deg C from existing 370 Deg C because of this, cases with gas oil FBP increasing beyond 370 Deg C i.e. 380 and 390 Deg C are not considered for further study. 6. DHDT Unit will be underutilised In case of withdrawing maximum possible kerosene from Column and Hydrotreating the same in new KHDS Unit to blend it with BS VI Diesel. 7. Hydro treated Kerosene produced from New KHDS Unit in all the cases can be blended with BS VI Diesel after relaxation of lower density specification. 8. As Per Revised BS VI Diesel Specification Lower Limit of Density is relaxed, hence Total Kerosene can be blended with Diesel. No need to Split the Kerosene into light and heavy cut. 1.5 Shortlisted Cases for Further Analysis: Based on the selection criteria, the following four (4) cases are shortlisted for further analysis. Case 1A: Withdrawing Minimum Kerosene from column and dropping the rest to Gas Oil Internally (Kero cut: , Gas Oil Cut: ) Case 1D : Kero Minimization by Lifting the Kero to Naphtha and also dropping to Gas Oil (Naphtha Cut: C5-170, Kero cut: , Gas Oil Cut: ) Case 2A: Withdrawing Minimum Kerosene from column and dropping the rest to Gas Oil Internally (Kero cut: , Gas Oil Cut: ) with New Kero Desulphurization Unit (KHDS) Case 2J: Base Case (Naphtha Cut: C5-150, Kero cut: , Gas Oil Cut: ) with New Kero Desulphurization Unit

10 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 5 of Material balance LP runs for the short listed cases have been done for design crude mix meeting all product specifications as mentioned in design basis. The material balance for all the four cases along with base case considered for evaluation are presented below in the Table-1.6. Case No. Table 1.4: Material Balance for Shortlisted cases (KTPA) Base Case 1A 1D 2A 2J Feed (KTPA) Arab Mix Coal Products (KTPA) LPG Naphtha BS VI Regular Gasoline Kerosene Hydrotreated kerosene ATF BS VI Diesel DCU Coke Product Fuel and Loss CPP Fuel Loss Sulphur Table 1.5: Capacity Utilization of existing Units (KTPA) Case No Design Capacity CDU 7800 NHT 1553 CCR 837 ISOM 752 HCU 2625 DHDT 2372 HGU 98 DCU 1822 Base Case 1A 1D 2A 2J 7800 (100%) 1518 (97.7%) 834 (99.6%) 685 (91.9%) 2593 (98.8%) 2273 (95.8%) 93.4 (95.3%) 1640 (90%) 7800 (100%) 1518 (97.7%) 835 (99.8%) 677 (90%) 2593 (98.8%) 2524 (106.4%) 96 (98%) 1641 (90.1%) 7800 (100%) 1553 (100%) 837 (100%) 673 (89.5%) 2593 (98.8%) 2524 (106.4%) 96 (98%) 1641 (90.1%) 7800 (100%) 1521 (97.9%) 837 (100%) 678 (90.2%) 2593 (98.8%) 2524 (106.4%) 97 (99%) 1640 (90%) 7800 (100%) 1522 (98%) 837 (100%) 680 (90.4%) 2593 (98.8%) 2273 (95.8%) 94.3 (96.2%) 1640 (90%)

11 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 6 of Gross Refinery Margin Gross Refinery Margin (product sales-feed stock purchase) for all the four cases along with base case is provided in Table 1.7 below: Table 1.6: Gross Refinery Margin for Shortlisted cases Case No Base case 1A 1D 2A 2J Rs Cr/Annum US $/bbl Design Capacities of New Process Units In Case 2A and 2J, New KHDS unit of capacity 225 KTPA and 500 KTPA respectively will be needed to be installed to make kerosene production as NIL. 1.9 Modifications required in CDU: Table-1.7: Modifications required in CDU Case Case 1A Modifications Required Replacement of LGO Product Pump Replacement of HGO Product Pump Case 1D Case 2A Case 2J Replacement of existing Overhead Naphtha pump with New pump Replacement of existing stabilizer Reboiler with new. Addition of One new Unit in existing Stabilizer Bottoms air cooler Replacement of LGO Product Pump Replacement of HGO Product Pump Replacement of LGO Product Pump Replacement of HGO Product Pump No modification required 1.10 Key Findings of the shortlisted Cases: Case 1A This option considers withdrawal of minimum Kerosene product from crude column & dropping rest into Gas Oil which can be processed in DHT unit. Modifications will be required in Gas Oil section of crude unit which will call for shutdown of the unit.

12 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 7 of 10 This option requires additional 6% capacity increase in DHT unit over and above the debottlenecking project capacity of DHT. BORL is presently operating DHT unit at 130% of design capacity and this capacity will increase to 145% in debottlenecking project by exhausting all the design margins in existing equipment, especially in high pressure section and reactors. Further increase in the DHT capacity is technically not possible. Even if it was possible to revamp DHT unit, this option will produce 213 KTPA Kerosene which must be exported. As the objective of Kerosene minimization is not met and required capacity of DHT exceeds the debottlenecking project capacity, this option is ruled out. Case 1D This option considers lifting part of Kerosene into Naphtha, dropping a part of Kerosene into Gas Oil and thus withdrawing minimum Kerosene Product from crude column. This option requires modifications in naphtha, gas oil section of crude column and naphtha stabilizer column which will call for shutdown of the unit. DHT capacity requirement in this case also increases to 106% of debottlenecking project capacity. This option reduces the Kerosene make to nil but produces 43 KTPA of surplus Naphtha which is a negative value stream and must be exported. This option is not technically possible as desired capacity of DHT exceeds debottlenecking project capacity and requires export of 43 KTPA Naphtha. Case 2A: This is Case 1A with New Kero Hydrodesulphurization unit to hydro treat the excess kerosene. Similar to Case 1A, this option also requires modifications in Gas Oil section of crude unit and required capacity of DHT exceeds the debottlenecking project capacity Hence this option is ruled out. Case 2J: This option considers installing a new KHDS unit which will eliminate Kerosene production from refinery by upgrading entire Kerosene into HSD after desulphurization. HSD product will meet BS-VI specifications after Kerosene blending.

13 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 8 of 10 This will not require modification in the existing units and can be largely implemented independently without affecting normal operation of the refinery. Based on the above analysis, Case 2J is selected for installation of new KHDS unit of 500 TMTA capacity that will eliminate Kerosene production from the refinery New Offsite Facilities No new tankages are required under this project. Post implementation of New KHDS Unit, Kerosene production from the refinery will be Nil for selected case and there will be increase in diesel production. Hence existing Kerosene product tanks 05A, 05B, 05C available in BDT area can be utilized for storing the Diesel products and 05D, 05E can be used to store the high Sulphur Kerosene in case KHDS unit is down. Existing Tankages shall be utilized for all the other products without any operating philosophy change. New pumping facility and line shall be provided to pump the high Sulphur Kerosene which is stored in 05D, 05E tanks at BDT to KHDS unit for reprocessing. Kerosene Reprocessing Pump: Type : Horizontal centrifugal Type of Drive : Electric motor No. of pumps : 1 operating +1 standby Capacity : 100 m3/hr 1.12 New Utility Systems One additional cell of capacity 4000 m3/hr in the existing cooling tower has been considered for selected case Capital Cost Estimation. Key Assumptions: The basic assumptions made for working out the Project cost estimate are as under: Cost estimate is valid as of 1 st Qtr price basis for selected case No provision has been made for any future escalation Project would be implemented on conventional mode. Process units cost estimates are based on reference technology. Any change in technology shall have impact on unit s cost estimates. EPCM services cost provision is as a factor basis and is indicative. Existing facilities of BORL such as land, Infrastructure, Construction site, General facilities and Township shall be used for this project. Site Development and Road & Buildings are not envisaged for this project. Exclusions: Following costs have been excluded from the Project cost estimate:

14 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 9 of 10 Forward escalation Cost towards statutory clearances As indicated above, the estimated project cost for the identified scope and technical details for the selected case works out to as under: Table-1.8: Capital cost of Case 2J Sr No. Case Total Capital Cost in ` Crore 1 Case 2J Note: Validity of Cost estimate is as of 1 st Qtr price basis, accuracy of cost estimation is ± 20% 1.14 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. Table-1.9: IRR of selected case Sr No Case 2J 1 Yr. Average Price Basis 3 Yr. Average Price Basis 1 Capital Cost (Rs Lakhs) Variable Operating Cost (Rs Lakhs) 3 Fixed Operating Cost (Rs Lakhs) Total Operating Cost (Rs Lakhs) Sales Revenue (Rs Lakhs) IRR On Total Capital Pre Tax Post Tax IRR On Equity Pre Tax Post Tax Energy Conservation Efforts Design of all the facilities shall be conceptualized to achieve a high standard of energy efficiency. The experience of the existing refineries and the latest trends in energy conservation in similar industries worldwide shall be incorporated in the project in its design stage itself. This will yield appreciable benefits by reduced energy costs and minimum accountable losses Environmental Impact In order to minimize the impact of the project on the environment, due attention shall be given for implementing effective pollution control measures. The design stage endeavors

15 EXECUTIVE SUMMARY Rev No 1 Section 1 Page 10 of 10 to mitigate the problems related to health, safety and environment at the process technology/source level itself. Special emphasis shall be given in design basis of all new facilities on measures to minimize the effluent generation at source. Liquid effluents The liquid effluents from new facilities will meet the Minimum National Standards as specified under proposed effluent and emission standards for petroleum oil refineries by treating the same in existing Effluent Treatment Plant. Gaseous Emissions All the emission from the Refinery Complex shall meet the stipulated standards under PROPOSED EFFLUENT AND EMISSION STANDARDS FOR PETROLEUM OIL REFINERIES. The total Sulphur Dioxide emissions from the refinery complex after development of proposed additional units will not exceed the present limit of T/day. Low Sulphur Fuel oil / Fuel Gas has been considered for firing in the new furnaces. Heaters/furnaces will be provided with well-proven Low NOx burners to restrict the emissions of Nitrogen Oxides (NOx) to meet the proposed emission standards for Petroleum Oil refineries. From the above it is evident that there will be no additional impact of gaseous emissions on the environment due to new facilities proposed under this study Solid Wastes The solid wastes i.e. Spent Catalysts, General Solid Wastes etc. generated in the new facilities shall be minimised by implementing solid waste implementation management plan Social Benefits The Kerosene Minimization and Sulphur reduction project of BORL Bina Refinery will help BORL to meet the Government target of making the Madhya Pradesh State as Kerosene Free state, to reduce the Sulphur content of whatever the kerosene produced and thereby improving the health condition of people using the Kerosene, to increase the availability of Diesel products in the region. Additionally it is also expected to generate employment both direct and indirect in the Bina region Recommendation Based on the study it is recommended to consider New Kero Hydro Desulphurization Unit (KHDS) of capacity 500 KTPA (Case J) for implementation The estimated Capital cost for this will be Rs Crores with an accuracy of ±20% & price Validity of 1 st quarter Considering the crude and product prices as mentioned in report, Post Tax IRR for this selected case works out to be 38.6% (1 year avg. price) and 31.78% (3 year avg. price). Overall project implementation is scheduled within 30 months from zero date.

16 INTRODUCTION Rev. No. 1 Page 1 of 1 SECTION 2.0 SECTION 2.0 INTRODUCTION

17 0 2.0 INTRODUCTION INTRODUCTION Rev No 1 Section 2 Page 1 of 1 Bharat Oman Refineries Limited (BORL) Refinery was implemented as part of the New Refinery Project and commissioned in June Refinery has been designed for 65: 35 weight blend of Arabian Light and Arabian Heavy for a crude processing capacity of 6.0MMTPA. BORL is currently carrying out low cost debottlenecking project to increase present refinery capacity from 6.0 MMTPA to 7.8 MMTPA by taking advantage of the inherent margins in the system design with fewer additional facilities. BORL has been contributed immensely towards the all-round development of the Bina region due to presence of refinery. Post Revamp, BORL wants to minimize the Kero production due to falling consumption trend and government anticipated policy towards converting some of the State as kerosene Free State. Meantime an industry meeting was held at CHT, Noida on 17 th Feb 16 for the reduction of Sulphur in kerosene /ATF. It was deliberated and finalized to reduce the Sulphur content in SKO from present 0.25 wt% to 0.20 wt% and similar reduction of sulphur in ATF specification is also expected. In view of the above, BORL wants to study the various options available to minimize the Kero production and sulphur reduction in Kero/ATF along with following overall objectives: Meeting BS V/VI specifications for MS and HSD. Maximization of Diesel Production. BORL engaged Engineers India Limited to do a LP study for studying various options to achieve the above said objectives. This report pertains to LP study to establish feasible and viable options to minimize Kero production, sulphur reduction in Kero and maximization of Diesel production. Along with configuration study the report includes details of utilities and off sites, capital cost estimate within an accuracy of ±20% for the final selected case.

18 SCOPE Rev. No. 1 Page 1 of 1 SECTION 3.0 SECTION 3.0 SCOPE

19 SCOPE OF WORK LINEAR PROGRAMMING STUDY FOR Rev No 1 Page 1 of 2 Section SCOPE OF WORK EIL s scope of work involve the following, 3.1 BASE CASE PREPARATION: Base case will be derived from the existing BORL LP Model available with EIL by Updating of the following: a) 7.8 MMTPA 100% Kuwait Crude processing in CDU. b) Revamp Unit Capacity of secondary processing units. c) Feed and Product properties and utility consumption as per Revamp Licensor Package. 3.2 KERO MINIMIZATION STUDY: With Base Case as starting point following LP Cases will be evaluated using PIMS Model to arrive at the optimum solution: With Single Draw of Kero product from Crude Column: Kerosene minimization by drawing the light cut Kero from the column meeting the specification and dropping the heavy end Kero into Gas Oil internally. Kerosene minimization by increasing the Naphtha FBP from 150Deg C to 170 Deg C and thereby reducing the Kero Cut Range. Drawing the deep cut Gas oil to absorb more kerosene into HSD by blending With two Draw of Kero product from Crude Column: Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero/ATF specification and Heavy Kero desulfurization in HCU/DHDT. Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero/ATF specification and with new Heavy Kero desulfurization unit. Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero/ATF specification and Drawing the deep cut Gas oil to absorb more kerosene into HSD by blending. i. A simple economics review of shortlisted options shall be studied w.r.t unit capacities, product slate, initial capital cost, opex, GRM, simple payback etc. and shortlisted options shall be referred/recommended to BORL for review and approval. The shortlisted cases shall include material balance, new unit capacities, utilities and offsite requirements. ii. iii. Estimation of project cost with ± 20% accuracy & Carrying out financial analysis for the final recommended case. Project implementation schedule bar chart shall be prepared for the final recommended case.

20 SCOPE OF WORK LINEAR PROGRAMMING STUDY FOR Rev No 1 Page 2 of 2 Section 3 iv. Overall Block Flow Diagram & Mass balance for Refinery post Kero Minimization will be submitted for the shortlisted options selected by BORL. v. For selected case, preliminary overall plot plan will be generated in compliance with OISD norms to show only the new facilities. vi. vii. Additional utility required for new facility will be established and which will be firmed up based on existing utilities & offsite facility. The Configuration Study report shall include the following contents: 1. Introduction 2. Scope of Work 3. Methodology 4. Basis of study Basic Design Parameters Objectives of Study Key Considerations Product Demand ( As furnished by Client) Feed, Product and Utility prices Product Specifications 5. Refinery Configuration Study Development of New Configurations from Base case LP Model Configuration Study Considering Various Options Preliminary Review of Study Summary of Results Key Observations of the Study Criteria for Short listing of Options Details of shortlisted options 6. Utilities and Offsite for additional facilities 7. Capital cost and Financial Analysis 8. Indicative overall plot plan 9. Conclusion and Recommendation 3.3 LIST OF DELIVERABLES INCLUDING PRESENTATION/ REVIEW MEETINGS: a. LP configuration review presentations. b. Final results presentation. c. Draft study report (without cost data.) d. Final study report - 6 copies e. Soft copies of Draft and Final study report (Excluding financial model). 3.4 EXCLUSIONS FROM EIL S SCOPE OF WORK: Following is excluded from EIL s scope of work. a. Licensor study of any unit. b. PFDs, P&IDs, Schematics of any new unit/revamped unit. c. Equipment layout of any new unit or revamped unit. d. Adequacy checks of any equipment s of the unit. e. Financial model in Microsoft Excel format.

21 METHODOLOGY Rev. No. 0 Page 1 of 1 SECTION 4.0 SECTION 4.0 METHODOLOGY

22 METHODOLOGY Rev. No. 0 Page 1 of 1 SECTION METHODOLOGY ADOPTED FOR THE STUDY This study is a refinery configuration study wherein various objective e.g. minimize the kerosene production, sulphur reduction in Kero/ATF, meeting BS-V/VI specifications for MS and HSD and maximization of diesel production. Therefore, Linear Programming was adopted for optimization. The Kuwait Crude and Arab Mix (65:35) crude were used for Base case establishment. Crude Assays of Kuwait Crude and Arab Mix Crude were taken same as in Debottlenecking Project. After analysis, Arab Mix (65:35) crude was chosen for further LP development in this Kero Minimization study. The yields and property data for new licensed unit KHDS was taken as per EIL data bank for similar licensed unit. Since there are many existing units which are to be integrated, the yield / property and utility data for these units were taken as per Design Basis of different units Debottlenecking Project. PRO II simulation was done to check the adequacy of CDU/VDU/NSU Unit and to generate data for further adequacy checking of individual equipments in Naphtha Overhead Circuit, Gas Oil circuit and adequacy checking of crude column and Naphtha Stabilizer column. Additional Power, Fuel Oil/gas, Steam and cooling water for new KHDS Unit was calculated and evaluation was done to find out whether any new Utility system is required or not.

23 DESIGN BASIS Rev. No. 2 Page 1 of 1 SECTION 5.0 SECTION 5.0 DESIGN BASIS

24

25 DESIGN BASIS Rev. No. 2 Page 1 of 45 Section 5.0 DESIGN BASIS LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM BORL: EIL: Revised & Issued for Report LG GN SA Revised & Issued for Report LG GN SA Issued for Report LG GN SA

26 DESIGN BASIS Rev. No. 2 Page 2 of 45 Section 5.0 Rev. No. Date Purpose Prepared by Reviewed by Approved by 5.0 DESIGN BASIS Design basis considered for Kero Minimization LP study in 7.8 MMTPA BORL Refinery is detailed in this chapter. 5.1 Basic Design Parameters for BORL Refinery Kero minimization LP study Study to be done by EIL DFR PFR Other Project Execution Methodology LSTK CONV HYBRID Project Duration Required in Months Other Studies By By EIL Others Remarks 1 Market survey/study report (Demand and supply Not included in present scope analysis) 2 Rapid Environmental impact study Not included in present scope 3 Site evaluation/selection Existing refinery area 4 Evaluation/Selection of licensors Not included in present scope 5 Rapid Risk analysis Not included in present scope 6 Soil investigation Not Applicable 7 Hydrological survey Not applicable Contour survey Not applicable Route survey (for transport of ODC materials from As per existing data. various ports / industrial areas of the country.) Marine Survey-effluent dispersion study As per existing data. 8 Health assessment /inspection reports (For Revamp) Not applicable. 9 Downtime assessment report (For Revamp) Not applicable Plant Location Village City State Nearest Rly Station(kms) Agasod BINA M.P Bina Land Availability Details Plot Area 1. Khasra Map, Land Survey map to be furnished. 2. Soil investigation, site details like Extent/cost of land filling/ piling data, if available may be furnished. 3. Land Rate (Rs per acre) As Existing Soil investigation as per existing plant. However land development cost to be included if new facility is envisaged. Road Length of connecting road (between site and existing main road). Kms 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). As per existing plant Rerouting of any existing facilities not evaluated in this study. Not applicable Met Data (By Customer) As per existing plant

27 DESIGN BASIS Rev. No. 2 Page 3 of 45 Section Land availability Not applicable Grid power availability Nearest Dist: Sagar Level: 220kV 100 MVA

28 DESIGN BASIS Rev. No. 2 Page 4 of 45 Section Raw Material Name Crude Mix: Design Case: Arab Mix (65:AL 35: AH) Assay Date: 20 Nov 2008,15 May 2009 Check Case: Kuwait (KUWAIT304) Assay Date: 11 May 2008 & Basra Light (BASRL300) Assay Date: 01 Jan 2011 Source Capacity to be considered On stream Hours Crude Assay Assay attached as Annexure E. Pipeline Base Case:7.8 MMTPA Kero Minimization Study Case: 7.8 MMTPA 8280 Hours/annum Design Case: Arab Mix (65:AL 35: AH) Assay Date: 20 Nov 2008,15 May 2009 Check Case: Kuwait (KUWAIT304) Assay Date: 11 May 2008 & Basra Light (BASRL300) Assay Date: 01 Jan Products (*) Name Annual Capacity Market Place (preferred) Product names, its maximum and minimum demands, prices and their specifications are detailed in Annexure A, Tables A.1 to A.5. (*) Study shall be based on factory rate (Refinery complex B/L) price for all products. Determination of preferred market place and logistics requirement there off are outside EIL s scope of work Plant Units Process Capacity Utilities to be Capacity Catalyst / chemicals Units generated Name Quantity Unit Rate Details of existing process units are provided in Annexure B. The yields and Utilities considered for existing units are based on design values from their respective BDEPs. For the new proposed units, EIL in-house data will be used. The Catalyst & Chemicals consumption data for new units will be based on EIL in house data Offsite, raw material / product and other storages: Optimal storage for new facilities will be considered based on existing best practices in refinery project. Details of existing Tank data is detailed in Annexure - C Raw Material Intermediate Products Finished Products

29 DESIGN BASIS Rev. No. 2 Page 5 of 45 Section 5.0 Name State Liquid / solid No of days of storage Name State Liquid / solid No of days of storage Name State Liquid/ solid No of days of storage Hook up connection (not applicable for grass root projects) Name Distance of connection from existing facilities Not Applicable Product Evacuation By Railway / Truck/ Pipeline Product Name All Products % of product to be moved by rail As per existing % of product to be moved by road % of product to be evacuated through Pipeline % of product to be evacuated through Coastal movement sea tankers. Length of rail to be laid/ distance between plant and railway siding Details of any major crossing (river/road/rail) coming on the way to Railway station to be considered as part of Project cost. As per existing As per existing Utilities Raw Water For Plant Operation Source Distance from river Raw water Analysis ( (if available) As per existing plant As per existing plant As per existing plant Electric Power For Plant Operation Distance from Plant: Level of Generation Contract Demand Charges Energy charges Minimum energy charges (as % of Contract Demand) In case this is not available, whether a system is to be designed /included in execution. Source As per existing plant Volts Frequency Rate Rs./kwhr NA NA NA NA Construction Power Available Volts KM away Rate (Rs./Kwhr) Contract Demand Charges Yes 415/230 V AC LT supply Within existing refinery Power available within the plant will be used as construction power.

30 DESIGN BASIS Rev. No. 2 Page 6 of 45 Section 5.0 Energy charges Minimum energy charges (as % of Contract Demand) Construction Water Available KM away Yes Within existing refinery Cooling Water New requirement shall be supplied from existing facility Nitrogen system New requirement shall be supplied from existing facility Compressed Air system New requirement shall be supplied from existing facility D M Water, BFW, Drinking water, Fuel New requirement shall be supplied from existing facility ETP Effluents generated from the new facilities shall be routed to existing ETP Flare Flare Relief from the new facilities shall be routed to existing flare system Steam System New requirement shall be supplied from existing facility Condensate System Condensate from New facilities shall be routed to existing system Warehouse Not applicable ENVIRONMENTAL REQUIREMENT Effluent Specifications Liquid Effluent MINAS (Minimum National Standards)/State Pollution Board Standards. Required facilities for Zero Liquid effluent discharge shall be considered. Gaseous Effluent MOEF (Ministry of Environment and Forest) guidelines/state Pollution Board. SO2 emission: TPD Sold Waste Disposal of hazardous waste as per guidelines Stack height (Limitation to be As per existing specified) Location of effluent discharge As per existing refinery standard & its distance from B/L of plant Note: Details to be furnished below in case State Pollution Board specifications exist Green Belt Requirement*

31 DESIGN BASIS Rev. No. 2 Page 7 of 45 Section 5.0 As advised by State Government during site selection visit REIA (in case of DFR) / rapid risk analysis (in case of FR The Green belt forms an integral part of the approach to improve the environmental quality and aesthetics of the plant area. Existing green belt area shall be maintained. Rapid risk analysis is excluded from EIL s scope of work BUILDING REQUIRED (PLANT & NON PLANT) : Not Applicable Name Type Area in M 2 Administrative Building Warehouse(Chemical, Spares, Product, Cement) Workshop Canteen Lab Control room with rooms for operating supervisors and conference rooms Training Center Substations Fire station Operator Cabins Service Buildings Security Cabins Any other building as required TOWNSHIP: Not Applicable % 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 Provision for power, water and sewage disposal CONSTRUCTION AIDS : Not Applicable Yes/No Yes/No Heavy crane to be purchased by owner (If yes, please specify capacity of range proposed and hiring charges) Whether Hydra, and medium size crane (up to 35 Tons can be brought by Erection Contractor) Yes/No Capacity range Hiring charges Yes/No XX OWNER EXPENSES DURING PROJECT IMPLEMENTATION : As per EIL standards Expenditure Heads

32 DESIGN BASIS Rev. No. 2 Page 8 of 45 Section 5.0 expenses towards public issue Salaries perks and facilities to be provided by owner to people employed on this job Communication Travel Training PMC fees Contingency any other Total Amount for all the above heads ADDITIONAL INFORMATION, FOR MARGIN MONEY CALCULATION : As per EIL Standards Item 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 Days INFORMATION FOR FINANCIAL ANALYSIS : Refer Annexure - D Project Funding % Expenditure Pattern (Grant Terms Required) Equity Contribution % Equity Composition % Dividend on Equity Equity Expenditure Pattern Grant Equity by BORL Debt Equity before debt or concurrent Promoter Financial Institution Public Foreign Equity Contributors Equity 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 Institutions Suppliers Credit Financial Institutions Terms and Conditions of Debts / Debentures Rupee Portion From FII s and Suppliers' Credits Debentures to Financial Institutions Debentures to Public Front end processing fees Exposure fees

33 DESIGN BASIS Rev. No. 2 Page 9 of 45 Section 5.0 (Foreign Currency and Rupee) Loan Repayment Terms For Debentures to FIs and Public Interest rate on Short Term Loan Capacity Buildup 1 st year 2 nd year 3 rd year 4 th year 5 th year Commitment fees Guarantee fees Interest Rates and Calculation Methodology Moratorium (from Commercial Operations commencement) Number of instalments Frequency of Instalments Coupon rate Redemption Terms OTHER KEY CONSIDERATIONS A. Minimization of kerosene production, Sulphur reduction in Kero / ATF shall be targeted. B. Maximization of diesel production from refinery shall be targeted. C. 100% BS VI, MS and HSD production shall be targeted. D. Dollar Exchange Rate is 1 US $ = 65 INR E. Capital cost estimation with +/- 30% accuracy for the shortlisted options and ±20% for selected case. F. Refinery SOx limit is TPD

34 DESIGN BASIS Rev. No. 2 Page 10 of 45 Section 5.0 Annexure-A Table A.1: Product Demand S.No. Product Minimum (KTPA) 1. LPG As Produced 2. Naphtha Nil 3. MS BS V/VI As Produced 4. Jet fuel 0.50 MMTPA (max) 5. Kerosene 0.15 MMTPA (max) 6. Diesel BS V/VI As Produced 7. Pet Coke As Produced 8. Sulphur As Produced Maximum (KTPA) Table A.2: Feed and Product Prices Products 1 Year (Avg Price of Rs / MT )* 3 Year (Avg Price of Rs / MT )* Crude Arab Mix (65:35) Kuwait Basra Light Fuel Coal Products LPG Naphtha MS BS III MS BS VI Jet fuel Kerosene Export Diesel BS III Diesel BS VI Pet Coke Sulphur * Two pricing basis to be considered, Pricing Basis: Average sales prices for the years as mentioned above.

35 DESIGN BASIS Rev. No. 2 Page 11 of 45 Section 5.0 Table A.3: Utility Prices Utilities UOM Price Raw Water Rs/m3 2 Power (Captive) Rs/KWH 9.1 Imported Power Rs/KWH 6.87 Cooling Water Rs/m DM Water Rs/m3 70 Steam Rs/MT 2875 Nitrogen Rs/Nm3 1.2 Table A.4: Product Specifications The product specifications (Manufacturing Specifications) adopted for this Project are given as under. A. Liquefied Petroleum Gas (LPG): TEST Vapour 40 C, KPa Free-Water Hydrogen Sulphide, ppmw (1) SPECIFICATION Max (152 psi) Note: 1. "Pass" test indicates Hydrogen Sulfide not more than 5 ppm. 2. Product shall contain minimum 10 ppm Mercaptans as Sulphur at the first dispatching location to ensure the detection of odor. Nil Pass Mercaptan sulphur, ppmw (2) Max. 150 Copper Strip Corrosion (Bomb) 1 38 C Volatility : Evaporation Temperature for 95%v, C Max. No. 1 Strip Max. 2

36 DESIGN BASIS Rev. No. 2 Page 12 of 45 Section 5.0 B. Naphtha- Not Applicable TEST UNIT SPECIFICATION Distillation IBP, Min Deg. C FBP, Max Deg. C 160 Sulphur (Total), Max ppm 100 Aromatics, Max % vol. 10 Olefins, Max % vol deg.c gm/ml Lead Content, Max ppm 1 Residue on Evaporation, Max 100 ml Deg. C, Max. Kg/cm2 0.7 Net Cal Value, Min Kcal/kg Chlorides, Max ppm 0.2 Arsenic & Other (Sb,V,Hg,P) Catalyst Poisons ppm Absent C/H ratio Paraffins + Naphthenes % vol Water Content ppm Absent

37 DESIGN BASIS Rev. No. 2 Page 13 of 45 Section 5.0 C. BS VI Gasoline: CHARACTERISTICS UNIT BS VI Colour, visual Orange 15 0 C kg/m Distillation : a) Recovery upto 70 0 C (E 70) % volume b) Recovery upto C (E 100) % volume c) Recovery upto C (E150) % volume 75 min. d) Final Boiling Point (FBP), max 0 C 210/190* e) Residue, max. % volume 2 a) Research Octane Number (RON), min 91 / 91.6* b) Motor Octane Number (MON), min. 80 / 81.5* Gum content (solvent washed), max. mg/100 ml 5 Oxidation stability, min. minutes 360 Sulphur, total, max. mg/kg 10 / 8* Lead content (as Pb), max. g/l Reid Vapour Pressure 38 o C, max. kpa 60/58* Vapour Lock Index (VLI)** a) Summer, max (May to July) 750 b) Other months, max 950 Benzene Content, max. % volume 1 / 0.96* Copper strip corrosion for 3 50 o C max. rating Class 1 Olefin content, max. % volume 21 / 18* Aromatics content max. % volume 35 / 34* Oxygen content, max % mass 2.7 Oxygenates Content : % volume a) Methanol, max % volume NIL b) Ethanol, max. % volume 5 c) Iso-propyl alcohol, max. % volume 10 d) Iso-bytyl alcohol, max % volume 10 e) Tertiary-butyl alcohol, max % volume 7 f) Ethers containing 5 or more carbon atoms per molecule, max % volume 15 g) Other Oxygenates, max % volume 8 * For Rail and Road dispatch (Manufacturing Specification) ** VLI= 10 RVP (kpa) + 7* E70 ( o C) 3 months summer and 9 months winter period is considered.

38 DESIGN BASIS Rev. No. 2 Page 14 of 45 Section 5.0 D. BS VI Diesel CHARACTERISTICS UNIT BS VI Ash, max. % mass 0.01 Carbon residue (Ramsbottom) on 10% residue, max. % mass 0.3 without additives Cetane number (CN), min. 51 Cetane Index (CI), min. 46 Distillation : 95% vol. Recovery at 0 C, max. 0 C 370/360* Flash point : a) Abel, min. 0 C 35/37** Kinematic 40 0 C cst C kg/m3 845 Max Total sulphur, max. mg/kg 10 / 8 * Water content, max. mg/kg 200 Cold filter plugging point (CFPP) a) Summer, max 0 C 18 b) Winter, max 0 C 6 Total contaminations, max. mg/kg 24 Oxidation stability, max. g/m3 25 Polycyclic Aromatic Hydrocarbon (PAH), max. % mass 11 / 8* Lubricity, corrected wear scar diameter (wsd 60 0 C, max. Copper strip corrosion for C, max. microns 460/440* rating Class-1 FAME content Max %v/v 7.0 * For Rail and Road dispatch (Manufacturing Specification) ** Considered for LP E. SUPERIOR KEROSENE Acidity, inorganic Burning Quality : TEST SPECIFICATION a) Char value. mg/kg of oil consumed Max. 20 b) Bloom on glass chimney Not darker than grey Colour (Saybolt), Min. +10 Copper Strip corrosion for 3 hrs. at 50 C Not worse than No. 1 Distillation : a) Percentage recovery below 200 C Min. 20 b) Final boiling point, C Max. 300 Flash Point (Abel), C Min. 39 TEST Nil SPECIFICATION

39 DESIGN BASIS Rev. No. 2 Page 15 of 45 Section 5.0 Smoke Point, mm. Min. 18* Total Sulphur, %wt. Max. 0.19*** (#) Conforms to BIS : * For supplies of Defence & railway signal lamps, smoke point of the product shall be minimum 22 mm. Under the emergency IS Specifications for kerosene, smoke point for general supplies has been relaxed to minimum 18 mm. ** For supplies to Defence, total sulphur content percentage by weight of the product shall be 0.20 max. *** Manufacturing specification # CHT is reviewing the requirement of Sulphur reduction in kerosene to the level of 1000, 500, 10 PPM. Based on final confirmation from CHT, BORL will confirm the level of Sulphur reduction required during the course of this study. Same shall be taken care appropriately in the new Unit design. F. AVIATION TURBINE FUEL TEST SPECIFICATION 15 C, kg/m3 Min. 775 Appearance Max. 840 Clear Mercaptan Sulphur, %w Max /0.0018* Copper Strip Corrosion(2 hr@ 100 C) Max. No.1 strip Sulphur, Total %w Max. 0.20/0.19* Flash Point (Abel), C Min. 39 Viscosity -20 Deg C, MM2/S Max. 8.0 Freezing Point, C Max. -47 Total Acidity, mg KOH/g Max Aromatics, %v Max Olefins, %v Max. 5 Smoke Point, mm Min. 19 Naphthalene content, %v Max. 3.0 Calorific Value, net Cals/kg Min. 10,225 Existent Gum (Steam Jet), mg/100 ml Max. 7 10% volume C Max. 205 FBP, C Max 300 Anti-Oxidant (Active Ingredient) mg/litre Min 17- Max Doped Fuel, pico-siemens/meter Min 50- Max 600 Lubricity, mm max Max # Specific energy, MJ/kg min Product of API gravity and Aniline point Min 4800 CONFORMS TO BIS SPEC IS: and DEFSTAN 91-91/ISSUE 4 # The requirement to determine lubricity as per IS applies only to ATF containing more than 95% hydroprocessed material where atleast 20% of this is severely hydro processed. Defence requirement to be met at 0.65 mm, Max. To meet this requirement, approved Lubricity Additive as mentioned in of IS:1571, 2001 to be added by appropriate agency before being inducted into the aircraft. * Manufacturing spec.

40 DESIGN BASIS Rev. No. 2 Page 16 of 45 Section 5.0 ANNEXURE B Table B.1. Existing Unit capacities Units Design capacity (MMTPA) CDU /VDU 7.8 NHT ISOM CCR HCU/DHDT 2.625/2.372 DCU HGU ATF MEROX SRU (TPD) 3 * 243 SWS I / SWS II (TPH) 161 / 59 ARU (TPH) 453 LPG ATU / CFC FGATU 0.19 Table B.2: TBP Cut Points-CDU/VDU (Processing 100% Kuwait Crude) Stream TBP Cut Points ( o C) LPG C3+C4 SRN C5-150 Kero Gas oil VGO VR + Slop 565+ Table B.3 CDU/VDU/NSU Utilities (Per ton of feed basis) Utility CDU/VDU Fired duty (MMKcal/ MT of Feed) 0.14 Power (KWH/MT of feed) MP Steam (MT/MT of feed) 0.03 LP Steam(MT/MT of feed) 0.01 Cooling Water ( M 3 /ton) 6.39

41 DESIGN BASIS Rev. No. 2 Page 17 of 45 Section 5.0 a. Naphtha Hydrotreater Unit NHT Capacity (MMTPA) Licensor UOP Feed To NHT Straight Run Naphtha HCU light Naphtha HCU heavy Naphtha Design Case 1081KTPA of SR Naphtha+ 273 KTPA of HCU Lt. naphtha+199 KTPA of HCU heavy naphtha On- Stream Hours 8280 Table B.4: NHT Unit Feed Feedstock Feed A Feed B Feed C Crude source 65:35 AL: AH Naphtha source Straight run naphtha Hydrocracker light naphtha Feed rate Total sulphur, wt ppm 500 <5 5 Total nitrogen, wt ppm 2 <1 0.5 PONA Wt% Vol% Vol% P O N A ASTM D-86 Distil, ( C) IBP 10% % % % % EBP Hydrocracker heavy naphtha Table B.5: NHT Yield Pattern Stream Yield (wt %) Feed 100 Make up gas 0.19 Total Products Off gas 0.57 Light Naphtha to Depentanizer 44.58

42 DESIGN BASIS Rev. No. 2 Page 18 of 45 Section 5.0 Stream Yield (wt %) NSU bottoms Total Products Value Light Naphtha from NSU Sulfur, wwpm Nitrogen, wwpm Metals, wbbp Chlorides, wppm NSU bottoms Sulfur, mg/kg Nitrogen, mg/kg Table B.6: NHT Product Properties: 0.1 max 0.1 max 0.5 max 0.5 max Utility Power HP Steam MP Steam LP steam Fired duty Cooling Water b. Penex Unit Table B.7: NHT Utilities (Per Ton of Feed Basis) Value kwh/mt 0 MT/MT MT/MT 0 MT/MT MMKcal/MT PENEX Capacity(MMTPA) Licensor UOP Light naphtha feedstock from the Feed To Penex Depentanizer bottoms On Stream Hours 8280 Note: The Depentanizer feed consists of 691KMTA light naphtha from Naphtha Splitter overhead plus 61 KMTA desulfurized hydrocracker light naphtha from a Sulphur Guard bed. The Depentanizer produces two products a bottom product sent as feed to the Penex Unit reactor section and an overhead exported from the Naphtha Complex as a light naphtha product to HGU. Table B.8: PENEX Unit Feed Property Value Feed Rate, KMTA 633 Total sulphur, mg/kg 0.1 max Total nitrogen, mg/kg 0.1 max Benzene content, wt% 2.02

43 DESIGN BASIS Rev. No. 2 Page 19 of 45 Section 5.0 Table B.9: PENEX Yield Pattern Stream Yield (wt %) Yield (wt %) SOR EOR Feed from NHT HCU Light naphtha Make up gas LPG (from CCR) Total Products Make up gas to NHT Fuel gas LPG Depentanizer ovhd Isomerate Total Table B.10: ISOMERATE Properties Products Value Isomerate SOR/EOR RONC, min 87.0 MONC, min 85.0 Aromatics, vol% 0 Olefins, vol% 0 Benzene, vol% 0 Sulfur, wppm 0.5 RVP, kpa 91.6/92 Specific gravity % 70 C 91 % 100 C 99 % 150 C 100 FBP 102.2/102.9 Table B.11: PENEX Utilities (Per Ton of Feed Basis (Note 1)) Utility Value Power HP Steam MP Steam LP steam Fired duty 50.9 kwh/t T/T T/T T/T 0 MMkCal/T Note 1: Feed quantity considered = Depentanizer feed= (691+61) ktpa=752 ktpa

44 DESIGN BASIS Rev. No. 2 Page 20 of 45 Section 5.0 c. Continuous catalytic reforming (CCR) unit CCR Capacity(MMTPA) Licensor UOP Feed To CCR Heavy Naphtha from Naphtha splitter bottoms On Stream Hours 8280 Table B.12: CCR Unit Feed Property Value Feed Rate, KMTA 837 Specific gravity Total sulphur, mg/kg 0.5 max Total nitrogen, mg/kg 0.5 max PONA Wt% P 63.9 O 0 N 26.6 A 9.5 Distillation, C IBP % % % % % 137 EP 171 Table B.13: CCR Yield Pattern Stream Yield (wt %) Feed (NSU bottoms) 100 Total Products Make-up gas to Penex 1.3 Net gas to PSA in HGU 5.4 LPG to Penex 3.04 Reformate Total 100.0

45 DESIGN BASIS Rev. No. 2 Page 21 of 45 Section 5.0 Table B.14: CCR Product Properties Products Value Reformate RONC, min 98.0 MONC, min 87 Aromatics, vol% Olefins, vol% 1.2 Benzene, vol% 1 Sulfur, wppm 0.5 RVP, kpa 15 Specific gravity % 70 C 2 % 100 C 9 % 150 C 84 FBP 192 Utility Power HP Steam MP Steam LP steam Fired duty Cooling Water d. Delayed Coker Unit Table B.15: CCR Utilities (Per Ton of Feed Basis) Value kwh/t DCU Capacity(MMTPA) Licensor CLG Feed to DCU Vacuum Residue 0 T/T T/T T/T MMkcal/T (100% fuel gas firing) Design Case Feed Case 1: 45:55 wt% AM VR Feed Case 2:Mix of 48% AM VR (65:35 blend of AL:AH) and 52% Oman VR On Stream Hours 8280 Table 4.B.16: DCU Yield Pattern Stream Yield (wt %) (Note-1) Feed Case 1 Feed Case 2 Feed Products Coker Sour off gas Coker sour LPG Coker Naphtha (C6-140 C) Light Coker Gas oil ( C) Heavy Coker Gas oil (370 C+) Coke Total

46 DESIGN BASIS Rev. No. 2 Page 22 of 45 Section 5.0 Notes 1. Product yields are provided based on Basic Design Engineering Package. In LP model, with change in feed composition appropriate shift in yield will be considered. Table B.17: DCU Product Properties STREAM PROPERTIES Value Feed Case 1 Feed Case 2 Naphtha (C6-140) Specific Gravity Sulphur,wppm RVP D323, kpa (max.) PONA, vol% Paraffins, vol% Aromatics, vol% Naphthenes, vol % Olefins, vol% Benzene content, wt % Nitrogen Total, ppmw ASTM D86 ( C), vol% IBP (1%) % % % % % % % EBP Light Coker gas oil (LCGO) Specific Gravity Sulfur, wt% Total metals (Ni+V), wppm Nil Nil Cetane index CCR, wt% <0.2 <0.2 Flash point, C Pour point, C Nitrogen Total, wppm Aromatics, vol% Olefins, vol% ASTM D86 ( C), vol% at 760 mmhg

47 DESIGN BASIS Rev. No. 2 Page 23 of 45 Section 5.0 STREAM PROPERTIES Value Feed Case 1 Feed Case 2 IBP (1%) % % % % % % % EBP Heavy coker gas oil (HCGO) Specific Gravity Total metals (Ni+V), wppm CCR, wt% Asphaltenes (C7 insolubles) max Nitrogen total, wppm Sulphur wt%, max ASTM D86 ( C), vol% at 760 mmhg IBP (1%) % % % % % % % EBP Green Petroleum Coke Lumps, inch <4 Sulfur, wt% 6.66 Nitrogen, wt% 0.94 VCM, wt% max. 12 Moisture, wt% <

48 DESIGN BASIS Rev. No. 2 Page 24 of 45 Section 5.0 Table B.18: DCU Utilities (Per Ton of Feed Basis) Utility Value Power KWH/MT HP Steam MT/MT MP Steam MT/MT LP steam MT/MT Fired duty MMKcal/T Cooling water M3/MT e. HYDROGEN GENERATION UNIT HGU Capacity(KTPA) 98.1 Licensor Technip Design Case 1:HCU Middle cut naphtha Design Case 2: Hydrotreated Mixed pentane Feed Design Case 3: Natural gas On Stream Hours 8280 Table B.19: Yield Pattern HCU Middle cut naphtha Hydrotreated Mixed pentane Natural gas Streams Feed Quantity+ Fuel (TPD) Feed (wt%) Total (wt%) Products Hydrogen (wt%) Fuel and Loss (wt%) TOTAL (wt%) Utility Table B.20: HGU Utilities (Per Ton of Product H2 Basis) Value Power 445 KwH/MT HP Steam (-)2.701/ (-)2.018/ (-)1.741 MT/MT (Design Case 1/2/3) MP Steam MT/MT LP Steam MT/MT Fired Duty MMKcal/MT (Note 1) Note 1: Fired duty is equivalent to the fuel gas imported in HGU, required for flare header purging. 100% fuel gas firing.

49 DESIGN BASIS Rev. No. 2 Page 25 of 45 Section 5.0 Table B.21: Feed Naphtha Specification Parameter Unit Design Feed/ fuel Alternate Feed/ fuel Feed stock type Hydrocracker Hydrotreater Mix Middle cut naphtha Pentane Specific 15 C 0.748/0/749 (EOR) 0.63 ASTM D86 Distillation IBP C 99 10% C % C C 136 FBP C 184 Paraffins Vol% 46.5 Naphthenes Vol% 48 Aromatics Vol% 5.5 Olefins Vol% 0 Total Sulphur ppmw 5, max 1, max H2S content ppmw Nil Mercaptan sulphur ppmw <5 Chlorine+Chlorides ppmw 1 max Nil Nitrogen content ppmw 1 max Metal content ppbw(max) 50 (total) Nil Molecular Weight Kg/kgmol RVP psia 3 Table B.22: HGU Product Properties Products Value Hydrogen Hydrogen purity, mol% 99.9 min CO+CO2, mole/mol 20 ppm, max Nitrogen, mole/mol 20 ppm, max (Naphtha feed) 650 ppm, max (NG feed) Water, mole 50 ppm, max Chlorine + Chlorides, mole 1ppm max Methane, mol% Balance f. Integrated Full Conversion HCU / DHDT HCU/DHDT Capacity(MMTPA) HCU : DHDT : Licensor CLG Feed to HCU Vacuum Gas Oil 80.5 Wt% Heavy Coker Gas Oil 13.4 Wt% Full Range Coker Naphtha 6.1 Wt% Feed To DHDT LGO +HGO+VD (75.8 Wt %) Light Coker Gas Oil (24.2Wt %)

50 DESIGN BASIS Rev. No. 2 Page 26 of 45 Section 5.0 On Stream Hours 8280 Case: SOR Table B.23: HCU Yield Pattern Distillation, C Feed Properties Elemental Assay Impurities TBP API Gravity 23.3 Sulfur, Wt% 3.16 Asphaltenes, ppm ST/5 20/102 Specific Gravity Nitrogen, ppm 1671 Ni + V, ppm / /90 95/99 354/ / /610 PCI 4200 Silicon, wppm Sodium, ppm Product Wt% (Note LV% 1) (Note 1) H2S NH3 C1 C2 C3 ic4 nc4 Light Naphtha Heavy Naphtha Kerosene Diesel Bottoms C Total Product Yields: Start-of-Run Total Feed Rate = 2,625 KTPA Total Feed Rate = 52,460 BPSD Chemical Hydrogen Consumption = 283 Nm 3 /m 3 Chemical Hydrogen Consumption = 1,671 SCFB Case: EOR Distillation, C Feed Properties Elemental Assay Impurities TBP API Gravity 23.3 Sulfur, Wt% 3.16 Asphaltenes, ppm ST/5 20/102 Specific Gravity Nitrogen, ppm 1671 Ni + V, ppm / /90 95/99 354/ / /610 PCI 4200 Silicon, wppm Sodium, ppm

51 DESIGN BASIS Rev. No. 2 Page 27 of 45 Section 5.0 H2S NH3 C1 C2 C3 ic4 Product nc4 Light Naphtha Heavy Naphtha Kerosene Diesel Bottoms Wt% (Note 1) Product Yields: Start-of-Run LV% (Note 1) C Total Total Feed Rate = 2,625 KTPA Total Feed Rate = 52,460 BPSD Chemical Hydrogen Consumption = 280 Nm 3 /m 3 Chemical Hydrogen Consumption = 1,657 SCFB Case: SOR Table B.24: DHDT Yield Pattern Distillation, C Feed Properties Elemental Assay Impurities TBP API Gravity 34.0 Sulfur, Wt% ST/5 121/187 Specific Gravity Nitrogen, ppm 518 Ni + V, ppm Nil 10/ /90 95/99 216/ / /407 Product Yields: Start-of-Run Product Wt% (Note LV% 1) (Note 1) H2S NH3 C1 C2 C3 ic4 nc4 Light Naphtha Heavy Naphtha Kerosene Diesel C Total Silicon, wppm 0.25 Total Feed Rate = 2,372 KTPA Total Feed Rate = 50,681 BPSD Chemical Hydrogen Consumption = 86.9 Nm 3 /m 3 Chemical Hydrogen Consumption = 514 SCFB

52 DESIGN BASIS Rev. No. 2 Page 28 of 45 Section 5.0 Case: EOR Distillation, C Feed Properties Elemental Assay Impurities TBP API Gravity 34.0 Sulfur, Wt% ST/5 121/187 Specific Gravity Nitrogen, ppm 518 Ni + V, ppm Nil 10/ /90 95/99 216/ / /407 Product Wt% (Note LV% 1) (Note 1) H2S NH3 C1 C2 C3 ic4 nc4 Light Naphtha Heavy Naphtha Kerosene Diesel C Total Product Yields: Start-of-Run Silicon, wppm 0.25 Total Feed Rate = 2,372 KTPA Total Feed Rate = 50,681 BPSD Chemical Hydrogen Consumption = 97 Nm 3 /m 3 Chemical Hydrogen Consumption = 574 SCFB Table B.25: Product Properties Low Pressure Separator Off gas (CLPS) Properties Specifications SOR EOR Hydrogen Sulfide, Mol ppm 22 (Max.) Ammonia, Mol ppm 5 (Max.) <5 <5 Component Analysis, Mol% Report H2 H2S NH3 N2 C1 C2 C3 ic4 nc4 C5+ H2O Chloride Content, Mol ppm 1 (Max.) <1 <1

53 DESIGN BASIS Rev. No. 2 Page 29 of 45 Section 5.0 Sponge Absorber Offgas Properties Specifications SOR EOR Hydrogen Sulfide, Wt% Report Ammonia, wppm Report 1,729 1,586 Component Analysis, Mol% Report H2 H2S NH3 C1 C2 C3 ic4 nc4 C5+ H2O Chloride Content, Mol ppm 1 (Max.) <1 <1 Liquefied Petroleum Gas (LPG) Properties Specifications SOR EOR Vapor Pressure at 40C, kg/cm 2 (g) 10.7 (Max.) <10.7 <10.7 Free Water, wppm Nil Nil Nil Hydrogen Sulfide, wppm Nil Nil Nil Total Sulfur, wppm 150 (Max.) <150 <150 Copper Strip Corrosion (1 38C) No. 1 Strip (Max.) No. 1 No. 1 Evaporation Temperature for 95 Vol%, C 2 (Max.) <2 <2 C 2 and Lighter Content, Wt% 0.2 (Max.) <0.2 <0.2 n-pentane/i-pentane, Mol% 1 (Max.) <1 <1 Mercaptan Sulfur, ppm 5 (Max.) <5 <5 Unsaturated Hydrocarbons, Wt% 1 (Max.) <1 <1 Residue on Evaporation, Wt% 0.05 (Max.) <0.05 <0.05 Light Naphtha (C 5 90 o C) Properties Specifications SOR EOR 15C, kg/m 3 Report Reid Vapor Pressure 0.7 kg/cm 2 (a) Max. <0.7 <0.7 Total Sulfur Content, wppm 5 (Max.) <5 <5 Doctors Test Negative Negative Negative Mercaptan Sulfur, wppm 5 (Max.) <5 <5 RON (Clear) Report MON Report PNA, Vol% Report

54 DESIGN BASIS Rev. No. 2 Page 30 of 45 Section 5.0 Properties Specifications SOR EOR Paraffins (Est.) Naphthenes (Est.) Aromatics (Est.) Distillation, ASTM 760 mm Hg, C IBP EP Report Benzene Report <1 <1 Total Nitrogen Content, wppm 1 (Max.) <0.5 <0.5 Chlorides + Chlorine, wppm 5 (Max.) <5 <5 Free Water, wppm Nil Nil Nil Middle Cut Naphtha (90 119C) (Note 1) Properties Specifications SOR EOR 15C, kg/m 3 Report Total Sulfur, wppm 5 (Max.) <5 <5 Total Nitrogen, wppm 1 (Max.) <0.5 <0.5 Flash Point, Abel, C Report <10 <10 RON Report MON Report Benzene, Vol% Report <1 <1 Distillation, ASTM 760 mm Hg, C IBP EP Report 145 (Max.) Chlorine + Chlorides, wppm 5 (Max.) <5 <5 Kinematic 40 C, cst Report PNA, Vol% Paraffins Naphthenes Aromatics Report Note: 1. Cut point of 119 C comes from targeting a maximum EP of 145 C D

55 DESIGN BASIS Rev. No. 2 Page 31 of 45 Section 5.0 Splitter Bottoms Naphtha ( C) Properties Specifications SOR EOR 15C, kg/m 3 Report Total Sulfur, wppm 5 (Max.) (Note 1) <5 <5 Total Nitrogen, wppm 1 (Max.) <0.5 <0.5 Flash Point, Abel, C Report <10 <10 RON Report MON Report Benzene, Vol% Report <1 <1 Distillation, ASTM 760 mm Hg, C IBP EP Report 185 (Max.) Chlorine + Chlorides, wppm 5 (Max.) <5 <5 Kinematic 40 C, cst Report PNA, Vol% Paraffins Naphthenes Aromatics Report Note: 1. Blended heavy naphtha sulfur content shall be at 0.5 wppm (max.) after treatment in sulfur sorber Superior Kerosene ( C) Properties Specifications SOR EOR 15C, kg/m 3 Report Acidity, Inorganic Nil Nil Nil ASTM D C 20 Vol% (Min.) >90 >90 ASTM D86 FBP, C 300 (Max.) Flash Point, Abel, C 42 (Min.) Smoke Point, mm 22 (Min.) Aromatic Content, Vol% Report 5 9 Olefins, Vol% Report <0.1 <0.1 Total Sulfur, wppm 8 (Max.) <8 <8 Appearance Clear Bright Clear Bright Clear Bright Distillation, ASTM 760 mm Hg, C IBP Report

56 DESIGN BASIS Rev. No. 2 Page 32 of 45 Section 5.0 Properties Specifications SOR EOR EP Kinematic Viscosity, 100 C Report Report Mercaptan Sulfur 5 (Max.) <5 <5 Naphthenes, Vol% 3 (Max.) <3 <3 Water Tolerance, ml 1 (Max.) <1 <1 Pour Point, C Report <-60 <-60 Cetane Number Report Cetane Index Report ATF ( C) (Note 1) Properties Specifications SOR EOR 15C, kg/m Appearance Clear Bright Clear Bright Clear Bright Water Tolerance, ml 1 (Max.) <1 <1 Mercaptan Sulfur 5 wppm (Max.) <5 <5 Total Sulfur 8 wppm (Max.) <8 <8 Copper Strip Corrosion (2 100C) Not Worse Than Silver Strip Corrosion 0 (Max.) 0 0 ASTM D86 10% Recovery, C 205 (Max.) ASTM D86 FBP, C 300 (Max.) Flash Point, Abel, C 42 (Min.) Smoke Point, mm 25 (Min.) Aromatic Content, Vol% 20 (Max.) 5 9 Olefins, Vol% 5 (Max.) <0.1 <0.1 Kinematic Viscosity, 100C 8.0 (Max.) Report Report Mercaptan Sulfur, wppm 3 (Max.) <3 <3 Naphthenes, Vol% 3 (Max.) <3 <3 Cetane Number Report Cetane Index Report Pour Point, C Report <-60 <-60 Freezing Point, C -47 (Max.) <-60 <-60 Distillation, ASTM 760 mm Hg, C IBP 10% Vol Recovered 50% 90% FBP Report 205 (Max.) Report Report 300 (Max.) Residue, Vol% 1.5 (Max.) <1.5 <1.5 Loss, Vol% 1.5 (Max.) <1.5 <1.5 Color, Saybolt 10 (Min.) >10 >10 Note: 1. Superior kerosene and ATF will be produced in blocked out mode, i.e., once at a time

57 DESIGN BASIS Rev. No. 2 Page 33 of 45 Section 5.0 ULSD From Diesel HDT ( C) Properties Specifications SOR EOR Ash, Wt% 0.01 <0.01 <0.01 Carbon Residue (Ramsbottom) on 10% Residue, Wt% 0.3 (Max.) <0.3 <0.3 Cetane Number 55 (Min.) Cetane Index 48 (Min.) Pour Point, o C 3 (Max.) <3 <3 Copper Strip Corrosion (3 100 o C) Not Worse Than C, kg/m ASTM D86 95 Vol% Recovery, C 360 (Max.) <360 <360 Distillation, ASTM 760 mm Hg, C IBP EP Report Flash Point, Pensky-Martens, C 66 >66 >66 Kinematic Viscosity, 100C Report Sulfur Content, wppm 8 (Max.) <8 <8 Water Content, wppm 200 (Max.) <100 <100 Cold Filter Plugging Point, C 6 <6 <6 Total Sediments, Wt% 0.05 (Max.) <0.05 <0.05 Aromatics, Wt% Report Polyaromatics, Wt% 6 (Max.) <6 <6 Stability, mg/100 ml 1.6 (Max.) <1.6 <1.6 Total Nitrogen, wppm 250 (Max.) <10 <10 Unconverted Oil Properties Specifications SOR EOR kg/m 3 Report Distillation, ASTM 760 mm Hg, C IBP EP Report Pour Point, C Report Kinematic Viscosity, 100C Report Sulfur, wppm 50 (Max.) <50 <

58 DESIGN BASIS Rev. No. 2 Page 34 of 45 Section 5.0 HCR Diesel Pool (Light Diesel + Heavy Diesel From Hydrocracker) Properties Specifications SOR EOR Ash, Wt% 0.01 (Max.) <0.01 <0.01 Carbon Residue (Ramsbottom) on 10% Residue, Wt% 0.3 (Max.) Without Additives <0.3 <0.3 Cetane Number 51 (Min.) Cetane Index 48 (Min.) ASTM D86 95 Vol% Recovery, C 360 (Max.) <360 <360 Distillation, ASTM 760 mm Hg, C IBP EP Report Flash Point, Pensky-Martens, C 66 >66 >66 Kinematic Viscosity, 40C C, kg/m Total Sulfur, wppm 8 (Max.) <8 <8 Water Content, wppm 200 (Max.) <100 <100 Cold Filter Plugging Point (CFPP), C 6 C (Max.), Winter 18 C (Max.), Summer <6 <6 Total Contaminations, wppm 24 (Max.) <24 <24 Oxidation Stability, g/m 3 25 (Max.) <25 <25 Polycyclic Aromatic Hydrocarbon (PAH), wppm 8 (Max.) <8 <8 Lubricity, Corrected Wear Scar Diameter (WSD 600C, Max. Note: 1. Subject to lubricity additives 460 <460 (Note 1) Table B.26: HCU/DHDT Utilities (Per Ton of Feed Basis) Utility Value Power HP Steam MP Steam LP steam Fired duty Cooling Water KWH/MT 0.19 MT/MT -0.1 MT/MT MT/MT 0.29MMKcal/T 23.3 M3/MT <460 (Note 1)

59 DESIGN BASIS Rev. No. 2 Page 35 of 45 Section 5.0 g. Sulphur Recovery Unit SRU Capacity(TPD), MAX 243 *3 Licensor Feed EIL H2S REMOVED FROM AMINES On Stream Hours 8280 Mole % Recovery 99.9 Table B.31: SRU Block Utilities (Per Ton of Product Basis) Utility Value Power HP Steam MP Steam LP Steam Fired Duty Cooling Water Combined SRU Block Kwhr/MT 0 MT 0 MT/MT 3.11 MT/MT 0.94 MMKcal/MT (100% fuel gas firing) M3/MT

60 DESIGN BASIS Rev. No. 2 Page 36 of 45 Section 5.0 ANNEXURE C Existing Utility and Offsite System Detail Table C.1: Existing Utility System Detail System Facility Post Revamp Cooling water system 1. Cooling tower cells : 7W + 1S Cells of 4000 m3/hr each. 2. Recirculating cooling water pumps Type : Horizontal centrifugal Type of Drive : Electric motor (4)+ 1 Turbine No. of pumps : 4 operating +1 standby Capacity : 8000 m 3 /hr 3. Side stream filter: Two Side stream filters each of Capacity : 240 m3/hr 4. Cooling water make-up: 782 m3/hr Steam & Power Three numbers Extraction Type Steam Turbine of 33 MW each. Three numbers (Two operating + one stand by) CBFC boilers each of 225 TPH capacities (VHP Level). One Utility Boiler of 160TPH capacity Grid back up - 20 MW (As per design) (Currently BORL is withdrawing 47 MW power from Grid. DG Set:-4 MW (To meet emergency power) For study 47 MW shall be generated from CPP and rest imported from Grid. CFBC Boilers shall be operated by firing purchased coal and DCU coke in the ration 50:50. Evaporation ratio for Coal and DCU Coke to steam generation shall be considered as 3.0 and 7.5 respectively. MP+LP BFW requirement of Process Units is supplied from CPP. HP BFW is supplied by HGU. Boiler Feed Water Nitrogen System MP+LP BFW pump Type : Horizontal centrifugal Type of Drive : Electric motor. No. of pumps : 1 operating +1 standby Capacity : 197 m 3 /hr Gaseous = 2 Chains of 1500 Nm3/hr Capacity Liquid = 225 Nm3/hr (Gas equivalent) Liquid= 225 Nm3/hr(From New Train)

61 DESIGN BASIS Rev. No. 2 Page 37 of 45 Section 5.0 Nitrogen Storage: Number of vessel = 3 Capacity of vessel = 167 m 3 (Liquid capacity) Nitrogen vaporizers 1. Dedicated Vaporizer for CCR-regeneration unit: Type of vaporizer = Steam heated water bath vaporizer No. of vaporizers = Two (1 operating and 1 standby) Capacity, Nm 3 /hr = 500 Nm3/hr = 625 Kg/hr 2. Vaporizer for other units: Vaporizer capacity: = kg/hr Type of Vaporizer: Steam heated water bath vaporizer No. of vaporizer: Two (one operating+ one standby) Treatment of Raw Water Two Raw water treatment plant of capacity 1500 m3/hr Treated water pumps: Type : Horizontal centrifugal Type of Drive : Electric motor. No. of pumps : 5 operating +2 standby Capacity : 550 m 3 /hr Raw Water System Drinking Water Pumps: Type : Horizontal centrifugal Type of Drive : Electric motor. No. of pumps : 1 operating +1 standby Capacity : 204 m 3 /hr Fire Water Make-up Pumps Type : Horizontal centrifugal Type of Drive : Electric motor. No. of pumps : 1 operating +1 standby Capacity : 180 m 3 /hr Raw / Treated water reservoirs: Two raw water reservoir of total capacity 96,200 m3 (33450 & m3) existing Treated water reservoir (comprising two compartments of equal capacity) of capacity 22,800 m3, L.P. AIR Compressor: 3W + 1 S compressor of capacity 8825 Nm3/hr. each Compressed Air System L.P. Air Receiver: Existing Instrument Air Dryer: Three number Air Dryer of Capacity 5000 Nm 3 /hr each.

62 DESIGN BASIS Rev. No. 2 Page 38 of 45 Section 5.0 HP Air Compressor: Existing HP Air Receiver : Existing + Similar New DM Plant Capacity: 1 X 500 M3/Hr of RO System DM water storage. Number of Tanks : Nominal Capacity : 9000M3 RO DM plant DM water transfer pumps for process units : Type : Horizontal centrifugal electric motor driven No. of pumps : 1 operating + 1 stand by Rated capacity : 250 m 3 /hr each DM water transfer pumps for CPP: Type : Horizontal centrifugal electric motor driven No. of pumps : 3 operating + 1 stand by Rated capacity : 185 m 3 /hr each CPU Capacity: Three chains of design capacity 50 m 3 /hr each. With Provision to operate all the three chains simultaneously. CPU Feed Tank: Tank Nominal capacity (80% filling) = Number of Tanks = m3 CPU CPU Feed Pumps: Type : Horizontal centrifugal electric motor driven. No. of pumps : 2 operating + 1 stand by Rated capacity : 50 m 3 /hr. each Polished Condensate Tank: Nominal capacity = 3500 m3 (80% filling) Number of Tanks = Polished Condensate Pumps: Type : Horizontal centrifugal electric motor driven No. of pumps : 3 operating + 1 stand by Rated capacity : 95 m 3 /hr each Fuel Gas and Fuel Oil System Calorific value of FG (LHV)= Kcal/kg Calorific Value of Refinery Fuel Oil (LHV)= 9850 Kcal/kg Refinery Fuel Oil Sulphur= 0.5 wt% (max)

63 DESIGN BASIS Rev. No. 2 Page 39 of 45 Section 5.0 S.No Table C.2: Feed / Intermediate Tankage Summary Service Numbers of Tanks Pumpable Volume M 3 Type of Tank Tank Size D x H, Meter 1 CRUDE FR 68 X 20 2 VGO CR 40 X 14 3 HCGO CR 26 X11 4 VR (DCU FEED) CR 40 X12 5 DHDT FEED CR 38 X NHT FEED FR/CR (Note-1) 52 X CCR FEED CR 24 X 11 8 HGU FEED DR 20 X 14 9 DRY SLOP FR 18 X 12 1O Black SLOP CR 14 X ISOMERATE DR 20 X14 12 REFORMATE FR 30 X15 13 CDU/VDU IFO CR 14 X REFINERY IFO CR 14 X12 15 CRUDE/ WATER CR 14 X10 16 HCU LT NAPHTHA DR 20 X14 17 LCGO & CR 24 X12 & 38 X MTBE DR 20 X COKER NAPHTHA CR 24 X 11 Note-1: New NHT Feed Tank to be cone Roof Tank Sr. No. Table 4.C.3: Details of storage tanks in BDT area Pumpable Volume in KL (Vol in between LLL and HLL of tank) Service Product Type Tank Size of tank* 1 01A HSD - EURO III CR 34m x 18m 2 01B HSD - EURO III CR 34m x 18m 3 01C HSD - EURO III CR 34m x 18m 4 01D HSD - EURO III CR 34m x 18m 5 01E HSD - EURO III CR 34m x 18m 6 01F HSD - EURO III CR 34m x 18m 7 02A HSD - EURO IV CR 34m x 18m 8 02B HSD - EURO IV CR 34m x 18m 9 02C HSD - EURO IV CR 34m x 18m

64 DESIGN BASIS Rev. No. 2 Page 40 of 45 Section 5.0 Sr. No. Service Product Pumpable Volume in KL (Vol in between LLL Type of tank* Tank Size 10 02D HSD - EURO IV CR 34m x 18m 11 02E HSD - EURO IV CR 34m x 18m 12 02F HSD - EURO IV 6885 CR 26m x 14.5m 13 03A MS - EURO III FR 34m x 16m 14 03B MS - EURO III FR 34m x 16m 15 03C MS - EURO III FR 34m x 16m 16 03D MS - EURO III FR 34m x 16m 17 03E MS - EURO III FR 34m x 16m 18 03F MS - EURO III 5400 FR 26m x 14.5m 19 04A MS - EURO IV FR 34m x 16m 20 04B MS - EURO IV FR 34m x 16m 21 04C MS - EURO IV FR 34m x 16m 22 04D MS - EURO IV FR 34m x 16m 23 04E MS - EURO IV FR 34m x 16m 24 04F MS - EURO IV 5400 FR 26m x 14.5m 25 05A SKO 5300 FR 26m x 14.5m 26 05B SKO 5300 FR 26m x 14.5m 27 05C SKO 5300 FR 26m x 14.5m 28 05D SKO 5300 FR 26m x 14.5m 29 05E SKO 5300 FR 26m x 14.5m 30 06A ATF 9900 CFR 33m x 16m 31 06B ATF 9900 CFR 33m x 16m 32 06C ATF 9900 CFR 33m x 16m 33 06D ATF 9900 CFR 33m x 16m 34 06E ATF 9900 CFR 33m x 16m 35 06F ATF 9900 CFR 33m x 16m 36 07A NAPHTHA 5300 FR 26m x 14.5m 37 07B NAPHTHA 5300 FR 26m x 14.5m 38 07C NAPHTHA 5300 FR 26m x 14.5m 39 07D NAPHTHA 5300 FR 26m x 14.5m 40 08A SLOP 5300 CR 11m x 11m 41 08B SLOP 910 CR 11m x 11m 42 DU1H(UG Tank) HSD - III/IV 95 UG 11m x3.2m 43 DU2M (UG Tank) MS - III/IV 84 UG 11m x3.2m 44 DU3S (UG Tank) SKO 95 UG 11m x3.2m 45 DU4A (UG Tank) ATF 95 UG 11m x3.2m 46 DU5N (UG Tank) NAPHTHA 84 UG 11m x3.2m 47 UG Tank ETHANOL 84 UG 11m x3.2m 48 UG Tank ETHANOL 84 UG 11m x3.2m 49 UG Tank SLOP 18 UG 6.5m x2m

65 DESIGN BASIS Rev. No. 2 Page 41 of 45 Section 5.0 Table - C.4: Details of Offsite Pumps SERVICE NO. OF PUMPS RATED CAPACITY M 3 /Hr PRESSURE AT UNIT B/L, Kg/cm 2 g CRUDE VGO HCGO VR DHDT FEED NHT FEED CCR FEED HGU FEED DRY SLOP BLACK SLOP ISOMERATE REFORMATE CDU IFO REFINERY IFO CRUDE WATER HCU LT NAPHTHA LCGO MTBE COKER NAPHTHA FLUSHING OIL Table - C.5: details of rail loading pumps Products No of Wagons for No. of Pumps. Rated capacity of pump design OP. SB each Pump (M3/Hr.) Naphtha 50 BTPN HSD Euro IV 50 BTPN MS Euro III 50 BTPN MS Euro IV 25 BTPN ATF 50 BTPN SKO 25 BTPN

66 DESIGN BASIS Rev. No. 2 Page 42 of 45 Section 5.0 Table-C.6: Details of White oil road loading pumps Products No. of Pumps Rated Capacity of Operating Standby each pump (m3/hr) HSD-IV HSD-V MS-IV MS-V SKO ATF NAPHTHA Unloading wagon Pumps Table-C.7: Details of sick wagon/tanker unloading pumps: Type Rated Capacity ( m3/hr) Destination HSD( Euro IV & V) Centrifugal 45 HSD UG Vessel / HSD IV Product Receipt Line MS ( Euro IV & V) Centrifugal 45 MS UG Vessel / MS IV Product Receipt Line SKO Centrifugal 45 SKO UG Vessel / SKO Product Receipt Line ATF Centrifugal 45 ATF UG Vessel / ATF Product Receipt Line HSD( Euro IV & V) MS ( Euro IV & V) SKO Naphtha ATF Submerged Centrifugal Submerged Centrifugal Submerged Centrifugal Submerged Centrifugal Submerged Centrifugal 150 HSD Euro IV Tank / Road loading 150 MS Euro IV Tank / Road loading 150 SKO Tank / Road loading 150 Naphtha Tank / Road loading 150 ATF Tank / Road loading Table - C.8: Details of product rundown lines from refinery Product Receipt Pipeline Size Remarks MS-Euro III/IV 8 ( Common) Existing line HSD-Euro III 12 Existing line HSD- Euro IV 10 Existing line ATF 8 Existing line SKO 8 Existing line

67 DESIGN BASIS Rev. No. 2 Page 43 of 45 Section 5.0 Product Receipt Pipeline Size Remarks PCK 6 New Line Naphtha 6 Existing line LPG 6 Existing line LPG ( off spec) 4 Existing line Besides indicated above three more lines are provided from Marketing Terminal to Refinery. 1. Slop Return line (WO) LPG reprocessing line ETP Water to Refinery ETP - 6

68 DESIGN BASIS Rev. No. 2 Page 44 of 45 Section 5.0 Annexure - D Parameters for Financial Analysis 1 Construction Period 30 months 2 Project Life 20 years 3 Debt / Equity Ratio 2:1 4 Expenditure Pattern Equity before debt 5 Loan Repayment period 9 years 6 Moratorium Period 1 Year 7 Upfront Fee - 8 Interest on Long Term 9.5% 9 Capital Phasing (Total) 1 Year 20% 2 Year 40% 3 Year 40% 4 Year 10 Capacity Build up 11 1 st year 80% 2 nd year onwards 100% Corporate Tax surcharge+3% educational cess 12 MAT Not applicable

69 DESIGN BASIS Rev. No. 2 Page 45 of 45 Section 5.0 ANNEXURE E Crude Assay s

70 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 1 of 1 SECTION 6 SECTION 6 REFINERY CONFIGURATION STUDY

71 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 1 of 22 SECTION DEVELOPMENT OF REFINERY CONFIGURATION The development of the refinery configuration is described in the following sections. 6.1 STUDY APPROACH The methodology adopted for arriving at the most optimum Kero Minimization and sulphur reduction option is as below: LP Model of the existing refinery which was available with EIL is considered as starting point This LP model is updated based on revamp design data available with EIL. Base case of the Kero minimization LP study is established. The base case LP model is updated with New Kero desulphurization unit and various options of Kero minimization, Sulphur reduction cases are studied Around 16 cases are analyzed to find out the best option which shall meet the objectives of LP study. Option screening is been carried out based on Incremental GRM and minimum modifications in existing process units Shortlisted Configuration option will be subjected to further detailed study and rigorous financial analysis. 6.2 LP MODEL DEVELOPMENT GENERAL EIL has used PIMS (Process Industry Modeling Systems) LP Software to develop a comprehensive LP Model for this project. LP Model of the existing refinery which was available with EIL is considered as starting point. This LP model is updated based on revamp design data and Base case of the configuration study is established. Liner Programming (LP) is a mathematical technique for determining the optimum allocation of resources to obtain 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 for 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 2500 equations and/or inequalities and more than 2500 variables. The Equations represent: Feed availability, Plant capacity and possible stream routings.

72 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 2 of 22 SECTION 6 The Variables represent: Amount of feeds purchased and products made, operating variables and actual stream disposition. The Objective function 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 two things greatly affect the final results of the LP Model. 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 LP model architecture 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 feed/utilities allowed for purchasing and also products allowed for sales. The prices of these streams are also defined in these tables. The feed, product and utility prices as provided by BORL are defined in these tables. Feed and utilities were purchased on weight basis. Some of products were sold on weight basis and some were sold on volume basis. The same has been modeled in LP accordingly Sub Model Tables Sub models are the building blocks for an LP model. All the process units, Utility producing units are represented by various Sub models. The optimizer tool optimizes the interaction between various Sub models and other tables and hence creates a flow between sub models. This flow between sub models eventually results in an optimized configuration scheme. The LP modeling software used for this configuration study requires the data pertaining to yields, utilities, catalyst & chemical consumption in a certain format. Using this data which is

73 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 3 of 22 SECTION 6 entered in MS-Excel in tabular format, the LP model generates matrix. The entries in these matrixes are then used for forming equations which are optimized to give the routings which are economically most viable. a) Process Unit Sub-models The process unit sub models are created in the excel format itself. These models might be weight based or volume based. Typically the yields shall be provided in the following format: Base yield per unit of feed. Delta yield as required for changing the yield per unit of feed based on a property. b) Crude Assay & Distillation Unit Crude/vacuum unit is not a Sub model in LP, but is defined in Assay tables. For the sake of simplicity it is described as a sub model. The assay data is generated using Crude Manager Software which generates yields & properties for various cut points as envisaged. Crude and Vacuum unit units are modeled in single sub model. Utilities for all the units are also considered. c) Utility Sub Model Utility sub model produces all the utilities required by process units. Utility requirements for each process unit are defined in respective process sub model. All the utilities required for each of the configurations are produced in utility model. Accurate utility estimates are essential to predict the fuel & oil loss of the refinery complex and also operating costs. Utilities typically tracked in by LP model are: Power, KWh. Steam (MP, LP levels). Fuel (fuel gas or fuel oil in terms of tons). Catalyst & chemicals. Utility requirements are entered in 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). d) Captive Power Plant Power & steam are generated in captive power plant (CPP) sub model. e) Refinery Fuel Balance

74 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 4 of 22 SECTION 6 Refinery fuel is another important utility tracked by LP model. Refinery Fuel requirement is met by internal fuel oil and refinery fuel gas. Fuel requirement is defined in each process sub model and hence total Refinery fuel requirement is know in terms of tons/hr. f) Sulphur Recovery Unit Sulfur recovery unit (SRU) is modeled to track H2S produced from various process units. Sulfur recovery of 99.9% is considered for this study along with Tail gas treating unit to reduce the overall SOx emissions 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 Refinery Economics Material balances and operating capacities are developed for each study configuration using LP model. Refinery gross margin (GRM) is the difference between sales revenue and feedstock purchase cost. The refinery variable operating costs are estimated by LP model. Variable operating cost includes the cost of providing catalyst and chemicals, cost of purchasing utilities like raw water and power. Refinery net margin (NRM) is the difference between GRM and operating cost. 6.3 BASE CASE LP MODEL DEVELOPMENT The first step is to develop an LP model for the existing Bina Refinery post Debottlenecking Project using the post revamp design data as per data compiled in agreed Design Basis for Linear Programming (LP) study for Minimization of Kerosene from Bina Refinery. The schematic sketch of the existing Bina Refinery post debottlenecking project for Base Case is depicted below in figure 6.1:

75 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 5 of 22 SECTION 6 FIGURE-6.1

76 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 6 of 22 SECTION 6 Key Considerations in Base Case: Following are the key considerations for base case:- Crude mix and crude disposition are considered in base case as per Annexure A of agreed Design basis For respective crudes that are processed in CDU, the product yields and product properties are based on the assay obtained from the Spiral Crude Manager Software and same are provided in Annexure-E of agreed Design Basis. Product yields, Product properties and utility consumption of the existing units are considered as per Annexure-B of the design basis. BS VI MS and Diesel have been considered for sales. SOx has been limited to TPD Base Case is developed for follwoing crudes which are normally being processed in Refinery: Base Case A: - Kuwait Crude Base Case B: - Arab Mix (65:35) Crude MATERIAL BALANCE: The material balance of both the options of the base case is provided in Table 6.1 below: Table 6.1: Material Balance of Base case Base Case A- Kuwait Crude Base Case B- AM crude Feed KTPA KTPA Kuwait Arab Mix Coal Total Product KTPA KTPA LPG Naphtha 0 0 Gasoline BS- VI Total Light Distillates Wt% on Crude Kerosene ATF HSD BS VI Total Middle Distillates Wt% on Crude

77 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 7 of 22 SECTION 6 Base Case A- Kuwait Crude Base Case B- AM crude DCU Coke SULPHUR Total Heavy Distillates Wt% on Crude Fuel & Loss Wt% on Crude CPP FUEL CAPACITY UTILIZATION OF EXISTING PROCESS UNITS: The Capacity Utilization of existing process units is provided in Table 6.2 below: Table 6.2: Capacity Utilisation of Base Case Unit Design capacity (MMTPA) Base Case A- Kuwait Crude Base Case B AM crude CDU/VDU (100%) 7.8 (100%) NHT (98.3%) (97.7%) ISOM (94.3%) (91.1%) CCR (100%) (99.6%) HCU/DHDT 2.625/ /2.357 (96.6%/99.4%) 2.593/2.273 (98.8%/95.8%) DCU (103.2%) 1.640(90%) HGU 98 KTPA 92.8 (94.7%) 93.4 (95.3%)

78 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 8 of 22 SECTION ECONOMIC ANALYSIS FOR BASE CASE: Based on 1 year Avg. Price ( ) Based on 3 year Avg. Price ( ) Case A Case B Case A Case B Gross Margin (Rs Cr/Annum) US $/bbl of Crude USD= Rs 65 Kerosene is 4.8 wt% in Kuwait Case and 6.6 wt% in Arab Mix Case; hence for further study Arab Mix Case has been selected as Base Case to minimize the Kerosene.

79 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 9 of 22 SECTION KERO MINIMIZATION STUDY: As described above the refinery operation with Arab Mix crude processing is finalised as the base case for LP study. With Base Case as starting point, following LP Cases were evaluated using PIMS Model to arrive at the optimum solution: Option 1: With Single Draw of Kero product from Crude Column Kerosene minimization by drawing the light cut Kero from the column meeting the specification and dropping the heavy end Kero into Gas Oil internally. Kerosene minimization by increasing the Naphtha FBP from 150Deg C to 170 Deg C and thereby reducing the Kero Cut Range. Drawing the deep cut Gas oil to absorb more kerosene into HSD by blending. Option 2: With two draw of Kero product from Crude Column Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero/ATF specification and Heavy Kero desulfurization in HCU/DHDT. Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero/ATF specification and with new Heavy Kero desulfurization unit. Separate draw of Light Kero & Heavy Kero cut from the crude column with LK meeting the Kero/ATF specification and Drawing the deep cut Gas oil to absorb more kerosene into HSD by blending VARIOUS LP CASES ANALYSED FOR KEROSENE MINIMIZATION STUDY: In order to arrive at the most optimum Kero minimization alternative following cases are analysed. Table 6.3: Various options analysed for Kero Minimization Options Description A. With Single Draw of Kero product from Crude Column: No New Processing Units Case 1A Withdrawing Minimum Kerosene from column and dropping the rest to Gas Oil Internally Kero Cut : Gas Oil : Case 1B Case 1A with Deep Cut Gas Oil ( ) Case 1C Case 1A with Deep Cut Gas Oil ( ) Case 1D Kero Minimization by Lifting the Kero to Naphtha Naphtha Cut : C5-170 Kero : Gas Oil :

80 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 10 of 22 SECTION 6 Case 1E Case 1D with Deep Cut Gas Oil Gas Oil : Case 1F Case 1D with Deep Cut Gas Oil Gas Oil : Case 1G Base Case with Deep Cut Gas Oil ( ) Case 1H Base Case with Deep Cut Gas Oil ( ) With New Process Units Case 2A Case 1A with New Kero Desulphurization Unit Case 2B Case 1B with New Kero Desulphurization Unit Case 2C Case 1C with New Kero Desulphurization Unit Case 2D Case 1D with New Kero Desulphurization Unit Case 2E Case 1E with New Kero Desulphurization Unit Case 2F Case 1F with New Kero Desulphurization Unit Case 2G Withdrawing Maximum possible Kerosene from column and Desulphurizing externally Kero Cut : Gas Oil : Case 2H Case 2G with Kero Cut : & Gas Oil : Case 2I Case 2G with Kero Cut : & Gas Oil : Case 2J Base Case with New Kero Desulphurization Unit Kero Cut : Gas Oil : Case 2K Base Case with New Kero Desulphurization & with Deep Cut Gas Oil ( ) Case 2L Base Case with New Kero Desulphurization & with Deep Cut Gas Oil ( ) B. With Two Draw of Kero product from Crude Column No New Processing Units Case 3A Case 3B Drawing the Light and heavy Kerosene from the crude column Min ATF Demand Light Kero meeting the ATF specification & Heavy Kero Processing in DHDT Drawing the Light and heavy Kerosene from the crude column Max ATF Demand Light Kero meeting the ATF specification & Heavy Kero Processing in DHDT With New Process Units Case 4A Case 4B Case 4C Case 4D Drawing the Light and heavy Kerosene from the crude column Min ATF Demand Light Kero meeting the ATF specification & Heavy Kero Processing in new Kero Desulphurization Unit Case 4A with Deep Cut Gas Oil Drawing the Light and heavy Kerosene from the crude column Max ATF Demand Light Kero meeting the ATF specification & Heavy Kero Processing in new Kero Desulphurization Unit Case 4C with Deep Cut Gas Oil

81 REFINERY CONFIGURATION STUDY Rev. No. 1 Page 11 of 22 SECTION SUMMARY OF RESULTS The material balance and unit capacities for all cases were evaluated by LP model. The economic parameters like gross refinery margin (GRM) and US$/bbl. of crude processed were estimated Feed and product rates for cases studied are presented in Table 6.4. Material balance represented in table is optimized by LP model based on economics. Existing Units capacities Utilization and New Unit Capacity for cases studied are presented in Table -6.5 Economic analysis for cases studied are presented in Table 6.6. This analysis is based on prices given in agreed Design Basis.

82 REFINERY CONFIGURATION STUDY Rev. No. 0 Page 12 of 22 SECTION 6 Table 6.4: Material Balance with single draw of Kero from crude column Case No 1A 1D 1E 1F 2A 2D 2E 2F 2G 2J Feed ( KTPA) Arab Mix Coal Products ( KTPA) LPG Naphtha BS VI Regular Gasoline Kerosene Hydrotreated Kerosene ATF BS VI Diesel DCU Coke Product Fuel and Loss CPP Fuel Sulphur

83 REFINERY CONFIGURATION STUDY Rev. No. 0 Page 13 of 22 SECTION 6 Table 6.5: Capacity Utilisation of existing process units and New KHDS unit Case No Design Capacity Base Case 1A 1D 1E 1F 2A 2D 2E 2F 2G 2J CDU NHT CCR ISOM HCU DHDT HGU DCU Kero Desulphurization Unit Table 6.6: Gross Refinery Margin with single draw of Kero from crude column Case No Base case 1A 1D 1E 1F 2A 2D 2E 2F 2G 2J Gross Refinery Margin (GRM) Rs Cr/Annum US $/bbl * 1 US $= 65 Rs

84 REFINERY CONFIGURATION STUDY KEY OBSERVATIONS OF THE STUDY The key observations from the results of configurations study as presented in Tables 6.4 to 6.6 are as follows: With Single Draw of Kerosene product from the Crude Column: 1. With No New Processing Unit: Rev. No. 0 Page 14 of 22 SECTION 6 In case of more dropping of Kerosene as compared to Base Case in Gas oil (Case 1A, 1D, 1E and 1F) i.e. by decreasing the IBP of Gas Oil (by 20 Deg C from 230 to 210 Deg C) or reducing the FBP of Kerosene (by 20 Deg C from 230 to 210 Deg C) (Case 1A, 1D); or by increasing the FBP of Gas oil ( by 10 or 20 Deg C from 370 to 380 or 390 Deg C)(Case 1E, 1F); then DHDT Unit capacity required will be more than the revamped Design Capacity (Design Capacity as envisaged under Debottlenecking Project). DHDT unit capacity required will be 111.8% and 117.2% of Design capacity in Cases 1E and 1F respectively, whereas it will be 106.4% of Design Capacity in cases 1A and 1D. In case of more dropping of Kerosene as compared to Base Case in Gas oil (Case 1A, 1D, 1E and 1F) i.e. by reducing the FBP of Kerosene (by 20 Deg C from 230 to 210 Deg C) and also by increasing the FBP of Gas oil (by 10 or 20 Deg C from 370 to 380 or 390 Deg C) will require modifications in Gas Oil Section of CDU (LGO Product Pump and HGO Product Pump). In case of more lifting of Kerosene as compared to Base Case in Naphtha (Case 1D, 1E and 1F) i.e. by increasing the FBP of Naphtha or increasing the IBP of Kerosene (by 20 Deg C from 150 to 170); then Naphtha Section of CDU (Overhead Naphtha Pump) and NSU (Stabilizer Reboiler, Stabilizer Bottom Air cooler) will require modifications. By Lifting the light end kerosene into Naphtha i.e. by increasing the FBP of Naphtha (by 20 Deg C from 150 to 170) (Naphtha Cut range of C5 170) and also dropping heavy end kerosene into Gas Oil (Case 1D, 1E, 1F) (Kero cut: , Gas Oil Cut: /380/390) Kerosene production from the refinery can be made minimum, but with modifications as required in above points. Without KHDS unit, Kerosene ( wt% sulphur) produced from CDU cannot be blended with BS VI Diesel even after relaxation of lower density specification because of sulphur constraint in BS VI. As Per Revised BS VI Diesel Specification, 95% volume recovery has been reduced to 360 Deg C from existing 370 Deg C because of this, cases with gas oil FBP increasing beyond 370 Deg C i.e. 380 and 390 Deg C (Case 1B, 1C, 1G and 1H) are not considered for further study.

85 2. With New Processing Unit (KHDS): REFINERY CONFIGURATION STUDY Rev. No. 0 Page 15 of 22 SECTION 6 In case of more dropping of Kerosene as compared to Base Case in Gas oil (Case 2A, 2D, 2E, 2F) i.e. by reducing the FBP of Kerosene (by 20 Deg C from 230 to 210 Deg C) and also by increasing the FBP of Gas oil (by 10 or 20 Deg C from 370 to 380 or 390 Deg C), DHDT Unit capacity required will be more than the revamped Design Capacity (Design Capacity as envisaged under Debottlenecking Project) and also this will require modifications in Gas Oil Section of CDU as well. DHDT unit capacity required will be 111.8% and 117.2% of Design capacity in Cases 2E and 2F respectively, whereas it will be 106.4% of Design Capacity in cases 2A and 2D In case of withdrawing maximum possible kerosene from Column and Desulphurizing externally (Cases 2G) i.e. by Increasing FBP of Kerosene (by increasing FBP of Kerosene by 20 Deg C from 230 to 250 Deg C); then DHDT Unit will be operating at less capacity as compared to Design Capacity. In case of more lifting of Kerosene as compared to Base Case in Naphtha and Gas Oil (Case 2D, 2E and 2F) i.e. by increasing the FBP of Naphtha (by 20 Deg C from 150 to 170 Deg C) then Naphtha Section of CDU (Overhead Naphtha Pump) and NSU (Stabilizer Reboiler, Stabilizer Bottom Air cooler) will require modifications. By Lifting the light end kerosene into Naphtha i.e. by increasing the FBP of Naphtha (by 20 Deg C from 150 to 170) (Naphtha Cut range of C5 170) and also dropping heavy end kerosene into Gas Oil (Case 2D, 2E, 2F) (Kero cut: , Gas Oil Cut: /380/390), Kerosene production from the refinery can be made minimum, but with modifications as required in above points. In this case Kerosene yield from the crude column is just enough to saturate the ATF Maximum demand. Hydro treated Kerosene produced from New KHDS Unit in all the cases can be blended with BS VI Diesel after relaxation of lower density specification. But as per pricing of the products which is considered for this study, economics is not favoring the same due to lower price of BS VI diesel over Kerosene/ATF. As Per Revised BS VI Diesel Specification, 95% volume recovery has been reduced to 360 Deg C from existing 370 Deg C because of this, cases with gas oil FBP increasing beyond 370 Deg C i.e. 380 and 390 Deg C (Case 2B, 2C, 2H, 2I, 2K and 2L) are not considered for further study With Two Draw of Kerosene product from the Crude Column: This option requires major Modification in Kero section of Crude distillation column, Preheat circuit, and Kerosene Product circuit ( Exchangers and Pumps) As Per Revised BS VI Diesel Specification Lower Limit of Density is relaxed, hence Total Kerosene can be blended with Diesel. No need to Split the Kerosene.

86 6.4.4 INFERENCES OF STUDY REFINERY CONFIGURATION STUDY Rev. No. 0 Page 16 of 22 SECTION 6 As per Option A (with single draw of Kerosene product from the crude column without any New KHDS Unit) to minimize the kerosene from the complex, modifications in Gas Oil, Naphtha Sections of CDU and also revamp of DHDT will be required. KHDS unit required to blend Kerosene in BS Diesel VI (with relaxed lower density criteria) will be approx. of capacity 500 KTPA (Case 2J) or 225 KTPA (Case 2A). Two draw of Kerosene from Crude Column need not to be taken in light of changed Diesel Specifications as per latest Gazette Notification from Government of India. It is analyzed from the study that in all the typical cases (Case 2A to 2L) with new KHDS unit and single draw of Kero from Crude column, BS VI meets all operational criteria with density in the range of kg/m CRITERIA FOR SELECTING THE SHORTLISTED CASES The following issues have been addressed while screening out the cases of Kero Minimization LP study 1. Minimum or No modification required in the existing processing Units 2. Maximum Utilization of existing Process Units without considering new units. 3. Minimization of kerosene production by blending with BS VI Diesel 4. Product slate in line with the Objectives considered for the study Based on above criteria for screening of the options, following four Cases are selected for detailed analysis. Case 1A: Withdrawing Minimum Kerosene from column and dropping the rest to Gas Oil Internally (Kero cut: , Gas Oil Cut: ) Case 1D : Kero Minimization by Lifting the Kero to Naphtha and also dropping to Gas Oil (Naphtha Cut: C5-170, Kero cut: , Gas Oil Cut: ) Case 2A: Withdrawing Minimum Kerosene from column and dropping the rest to Gas Oil Internally (Kero cut: , Gas Oil Cut: ) with New Kero Desulphurization Unit (KHDS) Case 2J: Base Case (Naphtha Cut: C5-150, Kero cut: , Gas Oil Cut: ) with New Kero Desulphurization Unit

87 6.5 DESCRIPTION OF SHORTLISTED CASES REFINERY CONFIGURATION STUDY Rev. No. 0 Page 17 of 22 SECTION PROCESS SCHEME WITHOUT NEW UNIT i.e. KHDS (CASE 1A AND 1D) Case 1A: Withdrawing Minimum Kerosene from column and dropping the rest to Gas Oil Internally (Kero cut: , Gas Oil Cut: ) Case 1D: Kero Minimization by Lifting the Kero to Naphtha and also dropping to Gas Oil (Naphtha Cut: C5-170, Kero cut: , Gas Oil Cut: ) The scheme for these cases is shown below in Figure 6.2. In these cases there is no change in process flow scheme with respect to Base Case except for Naphtha Cut, Kero Cut and Gas Oil Cut in CDU. There is no new KHDS unit for this case. In these cases Kerosene produced from CDU cannot be blended with BS VI diesel, due to higher sulphur content in straight run Kero. Figure 6.2

88 REFINERY CONFIGURATION STUDY PROCESS SCHEME WITH NEW KHDS UNIT (CASE 2A AND CASE 2J) Rev. No. 0 Page 18 of 22 SECTION 6 Case 2A: Withdrawing Minimum Kerosene from column and dropping the rest to Gas Oil Internally (Kero cut: , Gas Oil Cut: ) with New Kero Desulphurization Unit (KHDS) Case 2J: Base Case (Naphtha Cut: C5-150, Kero cut: , Gas Oil Cut: ) with New Kero Desulphurization Unit The scheme for this case is shown below in Figure 6.3. In this case there is New KHDS Unit with respect to Base Case. Crude cuts has been changed for Kero ( Deg C) and Gas Oil ( Deg C) in Case 2A with respect to base case. There are no changes in crude cut for Case 2J with respect to base case. Straight run Kerosene from CDU will be feed of KHDS Unit. Hydrotreated Kerosene from KHDS of sulphur content 8 ppm (wt) Unit can be blended with Diesel or send to Kerosene pool. Figure 6.3

89 REFINERY CONFIGURATION STUDY RESULTS OF SHORTLISTED CASES The material balance and unit capacities for all cases were evaluated by LP model. Rev. No. 0 Page 19 of 22 SECTION 6 Feed and product rates for selected cases are presented in Table- 6.7 Capacity utilization of existing process unit and capacity of New KHDS Unit for selected cases are presented in Table-6.8 Economic analysis for selected cases are presented in Table 6.9 Case No. Table 6.7: Material Balance for Shortlisted Cases Base Case 1A 1D 2A 2J Feed (KTPA) Arab Mix Coal Products (KTPA) LPG Naphtha BS VI Regular Gasoline Kerosene Hydrotreated kerosene ATF BS VI Diesel DCU Coke Product Fuel and Loss CPP Fuel Loss Sulphur Note-1: All Hydrotreated Kero shown in above Table for Case 1D, can be blended with Diesel (Post Relaxation of Lower Density specification of BS VI Diesel). Economics is not favoring the same due to higher price of Kero over Diesel. If all Kero is blended with Diesel, in Case 1D specific gravity of Diesel will be

90 REFINERY CONFIGURATION STUDY Table 6.8: Capacity Utilization of existing process units and New KHDS unit for shortlisted Cases Rev. No. 0 Page 20 of 22 SECTION 6 Case No Design Capacity CDU 7800 NHT 1553 CCR 837 ISOM 752 HCU 2625 DHDT 2372 HGU 98 DCU 1822 Base Case 1A 1D 2A 2J 7800 (100%) 1518 (97.7%) 834 (99.6%) 685 (91.9%) 2593 (98.8%) 2273 (95.8%) 93.4 (95.3%) 1640 (90%) 7800 (100%) 1518 (97.7%) 835 (99.8%) 677 (90%) 2593 (98.8%) 2524 (106.4%) 96 (98%) 1641 (90.1%) 7800 (100%) 1553 (100%) 837 (100%) 673 (89.5%) 2593 (98.8%) 2524 (106.4%) 96 (98%) 1641 (90.1%) 7800 (100%) 1521 (97.9%) 837 (100%) 678 (90.2%) 2593 (98.8%) 2524 (106.4%) 97 (99%) 1640 (90%) 7800 (100%) 1522 (98%) 837 (100%) 680 (90.4%) 2593 (98.8%) 2273 (95.8%) 94.3 (96.2%) 1640 (90%) Table 6.9: Gross Refinery Margin for Selected Cases Case No Base case 1A 1D 2A 2J Rs Cr/Annum US $/bbl * 1 US $= Rs KEY OBSERVATIONS OF SHORTLISTED CASES There is no modification in Naphtha Section of CDU for Cases 1A, 2A and 2J Modifications are required in Naphtha Section of CDU/NSU (Overhead Naphtha Pump, Stabilizer Reboiler, Stabilizer Bottom Air cooler) for Case 1D Modifications required in Gas Oil Section of CDU (LGO Product Pump, HGO Product Pump) for Cases 1A, 1D and 2A. No modification in Gas Oil section for Case 2J. DHDT unit capacity required will be 106.4% of Design Capacity in Cases 1A, 1D and 2A In Case 2A and 2J (with KHDS Unit) Kero production is Zero. In these two cases, all the Hydrotreated Kero can be blended with Diesel (with no lower density specification for Diesel).

91 REFINERY CONFIGURATION STUDY In Case 1A and 1D (without KHDS), Kero production will be 256 and 43 KTPA respectively. In Case 1D, CCR is processing only the NHT Heavy Naphtha. Hence feed N+2A is Vol% which is 1.68 Vol% lower than the design value, because of which, there will be slight decrease in reformate yield and increase in Hydrogen yield from CCR. KHDS unit capacity required will be 225 and 500 KTPA for Case 2A and 2J respectively. Rev. No. 0 Page 21 of 22 SECTION CONCLUSIONS Without New KHDS Unit (Cases 1A and 1D) a. Under these two options following modifications are required in existing units: i. In Case 1D, modification in existing CDU unit are required like: replacement of Overhead Naphtha Pump, LGO Product Pump and HGO product pump, addition of one new section in parallel in Stabilizer bottom air cooler and replacement of existing Stabilizer Reboiler with a new one. ii. In Case 1A LGO Product Pump and HGO product pump need to be replaced. iii. This option requires additional 6% capacity increase in DHT unit over and above the debottlenecking project capacity of DHT. BORL is presently operating DHT unit at 130% of design capacity and this capacity will increase to 145% in debottlenecking project by exhausting all the design margins in existing equipment, especially in high pressure section and reactors. Further increase in the DHT capacity is technically not possible. iv. Even if it was possible to revamp DHT unit, this option will produce 213 KTPA Kerosene and 43 KTPA Naphtha which must be exported With New KHDS Unit (Cases 2A and 2J) a. Under these two options following modifications are required in existing units: i. In Case 2A LGO Product Pump and HGO product pump need to be replaced. ii. DHDT capacity in Case 2A is 106% of Design Capacity (as envisaged under debottlenecking project) which may not be feasible. b. New KHDS unit of capacity 225 KTPA and 500 KTPA need to be installed in Case 2A and 2J respectively in order to meet the desired products profile. New KHDS unit of 500KTPA is preferable from economics point of view (more diesel production in case 2J). c. All the kerosene produced can be blended with HSD product which will meet BS- VI specifications.

92 6.6 Recommendation REFINERY CONFIGURATION STUDY Rev. No. 0 Page 22 of 22 SECTION 6 Based on the study it is recommended to consider New Kero Hydro Desulphurization Unit (KHDS) of capacity 500 KTPA (Case J) for implementation because of the following advantage over other cases 1. Maximum Utilization of existing process units 2. Flexibility to produce low Sulphur kerosene or NIL kerosene from the refinery 3. Product slate in line with the Objectives considered for the study 4. No Modification required in the existing units and new unit can be largely implemented independently without affecting normal operation of the refinery. The estimated Capital cost for this will be Rs Crores with an accuracy of ±20% & price Validity of 1 st quarter Considering the crude and product prices as mentioned in report, Post Tax IRR for this selected case works out to be 38.6% (1 year avg. price) and 31.78% (3 year avg. price).

93 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 1 of 1 SECTION 7.0 SECTION 7.0 UTILITY AND OFFISTE DESCRIPTION

94 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 1 of 7 SECTION UTILITY DESCRIPTION This chapter provides details of utility requirements and description of new utility system envisaged for refinery post implementation of new Kero Desulphurization Unit The following utility systems are reviewed for study: 1. Cooling Water System 2. Steam and Power System 3. Internal Fuel Oil & Fuel Gas System 4. Raw Water System 5. DM Water System 6. Compressed Air System 7. Nitrogen System 8. Condensate System Utility consumption for Kero Desulphurization Unit has been estimated considering following basis: In-house data for new units. Utility system for refinery post Kero Desulphurization Unit is arrived considering the new requirement is supplied from existing utility system. The details of existing utility systems installed in the refinery are given in Annexure C of Section 5 Design Basis. 7.1 REFINERY UTILITIES SUMMARY In LP study, there are four short-listed cases: Case 1A (Kero Cut: , Gas Oil cut: , No new KHDS Unit) Case 1D (Kero Cut: , Gas Oil cut: , No new KHDS Unit) Case 2A (Kero Cut: , Gas Oil cut: , New KHDS Unit) Case 2J (Kero Cut: , Gas Oil cut: , New KHDS unit) ADDITIONAL UTILITY REQUIREMENT For Case 1A and 1D: In Case 1A and 1D there is no change in existing units utilities because there is only rearrangement of product profile and no revamp of units is required. Also there is no New KHDS unit in these two cases. Hence, no new utility system is required for these two cases.

95 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 2 of 7 SECTION 7 For Case 2A and 2J: In Case 2A and 2J there will a new KHDS unit of capacity 225 KTPA and 500 KTPA respectively. Additional utility requirements for these two cases in given below in Table 7.1: Table-7.1: Additional Utilities Requirement S.N System Units Case 2A Case 2J 1 Cooling water m3/hr Power kw Fired duty MMKcal/hr Raw Water m3/hr DM water m3/hr Steam TPH Plant Air Nm3/hr Instrument Air Nm3/hr Nitrogen Gas Nm3/hr Condensate system TPH UTILITY BALANCE POST KHDS UNIT Refinery utility balance after KHDS unit implementation is given below in table 7.2 Table 7.2: Utility Balance Post KHDS unit: S.No System Units Demand Post KHDS Unit Availability Case 2A Case 2J Post RCEP 1 Cooling m3/hr water 2 Power MW (Grid) 3 Fuel Gas Kg/hr Fuel Oil Kg/hr Raw Water m3/hr x 2 6 DM water m3/hr Steam TPH Compressed Nm3/hr Air x 2

96 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 3 of 7 SECTION 7 9 Nitrogen Nm3/hr x 2 10 Condensate system TPH x 2 *Fuel Gas LHV= Kcal/kg, Refinery Fuel Oil LHV= 9500 Kcal/kg COOLING WATER SYSTEM Total CW requirement post KHDS Unit as shown in Table 7.2 above: For Case 2A= m3/hr ( ) For Case 2J= m3/hr ( ) Cooling tower design capacity post KHDS unit required is about m3/hr. One additional cell same as existing Cell of capacity 4000 m3/hr will be required for augmentation of refinery cooling tower. Hence total no of cells in post KHDS unit will be (8W+1S) each of capacity 4000 m3/hr. The type of cooling towers will be counter/ cross flow type with flameproof motors. Cooling tower shall be specified to cool water from 45 C to 33 C. Height of cooling tower is 18 m. Cooling Tower fan shall be made of FRP and motor shall be suitable for Area Classification Zone-2. Oil skimmer will be provided in the sump to remove floating oil to OWS. HC, H2S detector will be provided at the cooling tower top. The indication /alarm for the detectors shall be provided in MCR in offsite panel. The basin of each cell will have provision to isolate for maintenance. Blow down from this cooling tower shall be routed to RO/DM FEED. Recirculating cooling water pumps: Post RCEP there will be (4W+1S) pumps of capacity 8000 m3/hr each, which shall be adequate for post KHDS requirements also POWER SYSTEM Total Power requirement post KHDS requirement will be MW (for Case 2A) and MW (for case 2J) as shown in Table 7.2 above. Post KHDS implementation power available from CPP will be same as existing i.e. 47 MW. The balance power 70.9 MW (Case 2A) and 71.3 MW (Case 2J) shall be sourced from Grid power.

97 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 4 of 7 SECTION FUEL OIL AND FUEL GAS SYSTEM The fuel requirement for the BINA Refinery project would be met by fuel oil and fuel gas generated internally from various process units. Furnaces within process units would operate partially by fuel gas system and partially by fuel oil system. For CPP, the CBFC boilers are operated on 50:50 pet coke and Indonesian coal as primary fuel and HSD will continue as start up fuel. Utility boiler is designed to run on Fuel Gas/Fuel Oil or both. As there is common requirement of fuel oil sulphur specification of 0.5%, currently only one type of fuel oil is used in the refinery for CDU/VDU and rest of the refinery units. IFO and RFO systems are interconnected in the CDU unit. Post RCEP Fuel gas and Fuel oil system is found adequate for the purpose of this study also. There are minor increment in fired duty as can be seen from Table 7.1 and Table 7.2 above which can be accommodated in post RCEP Fuel Gas and Fuel Oil systems without any modification RAW WATER SYSTEM Raw water is being made available at the refinery battery limit from the Betwa River. Raw water from river is pumped to refinery through pipeline. At existing refinery, raw water reservoir along with filtration and pumping facilities have already been provided. A raw water reservoir is provided to ensure uninterrupted supply of raw water. The raw water from the reservoir is pumped, treated and filtered in a raw water treatment plant (RWTP) Since no major augmentation is required for Refinery Cooling Tower, the existing raw water system will be adequate as can be seen in Table 7.2 above as well DM WATER SYSTEM DM water system comprises of RO system, storage and pumping facilities in the existing refinery to meet the total demand for the process unit requirement as well as CPP requirements. There is no addition DM water requirement post KHDS unit implementation as can be seen from Table 7.1 and Table 7.2 above. Hence no change in DM water system is envisaged under this study.

98 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 5 of 7 SECTION STEAM SYSTEM The steam shall be produced in the captive power plant. The fuel to CPP will be 50:50 pet coke and Indonesian Coal. Steam is consumed in the refinery at three levels, viz. High Pressure (HP) Steam, Medium Pressure (MP) Steam and Low Pressure (LP) Steam. Steam is also generated at all three levels within process units/facilities. As it is evident from the Table 7.1 and Table 7.2 above there are no additional steam requirement post KHDS unit implementation. Hence, steam system is same as post RCEP project COMPRESSED AIR SYSTEM Compressed air required for all of the above uses is generated at a centralised location in the plant and distributed to the various users through headers. This system was designed to supply compressed air to the various users at the required conditions, quality and quantity. As can be seen from Table 7.2 above compressed Air requirement post KHDS implementation can be met with the post RCEP project compressed air system. Hence, no modifications are envisaged in compressed air system for KHDS implementation NITROGEN SYSTEM High purity Nitrogen is required in the refinery for two purposes: Continuous requirement (During catalyst regeneration, Blanketing of surge drums and storage tanks, Purging of compressor seals) and intermittent requirement (Purging of systems during start-ups and shut-downs, Catalyst Regeneration). The nitrogen generated in the cryogenic air separation plant is distributed to the various users through existing distribution systems. Adequacy of the existing distribution system was checked and found adequate for post KHDS implementation flow as well CONDENSATE SYSTEM Steam is being used in the complex as process steam, motive fluid for steam turbine drives, ejector, heating etc. Condensate results from the steam reboilers, condensate steam drives etc. Within each unit, suspect and pure condensate will have segregated collection system. The units having condensing steam drives

99 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 6 of 7 SECTION 7 shall have separate headers for suspect, pure and surface condensates. During normal operation, the suspect condensate and tracer condensate shall be treated in a Centralized Condensate Polishing Unit (CPU) before use. However, the pure condensate and surface condensate shall be directed to polished condensate tanks. Since there is no new generation of condensate from KHDS unit as given in Table 7.1. Hence, Condensate system post RCEP shall be adequate after KHDS implementation as well. 7.2 AMINE SYSTEM Lean Amine requirement of new KHDS unit is 625 Kg/Hr (for 500 KTPA KHDS) same shall be taken from lean amine header coming to HCU/DHDT Unit, Similarly, Rich amine generated shall be routed to rich amine header of HCU/DHDT. Existing ARU is found to be capable of taking care of this additional requirement. 7.3 HYDROGEN REQUIREMENT Make up Hydrogen requirement of New KHDS unit of 500 KTPA capacity is about 190 kg/hr of 99.9 mol% purity at 20kg/cm2g pressure. This hydrogen shall be taken from existing Hydrogen header. Existing Hydrogen unit has sufficient margin to take care this additional requirement. 7.4 OFFSITE DESCRIPTION The offsite facilities of existing refinery consists of a) Tank Farm b) Interconnection of process lines between process units c) Product Run down lines from refinery to Dispatch Terminal TANK FARM Tank Farm facilities are designed to store and transfer feed, intermediate and finished products. The storage capacities are based on the crude, intermediate and finished products material balance vis-à-vis number of days of stock requirements. The summary of existing feed, intermediate and product storage tanks in tables C.2 and C.3 of section 5 of this LP study report.

100 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 7 of 7 SECTION 7 No new tankages are required under this project. Post implementation of New KHDS Unit, Kerosene production from the refinery will be Nil for selected case and there will be increase in diesel production. Hence existing Kerosene product tanks 05A, 05B, 05C available in BDT area can be utilized for storing the Diesel products and 05D, 05E can be used to store the high Sulphur Kerosene in case KHDS unit is down. Existing Tankages shall be utilized for all the other products without any operating philosophy change. New pumping facility including OSBL line shall be provided to pump the high Sulphur Kerosene which is stored in 05D, 05E tanks at BDT to KHDS unit for reprocessing. Kerosene Reprocessing Pump: Type : Horizontal centrifugal Type of Drive : Electric motor No. of pumps : 1 operating +1 standby Capacity : 100 m3/hr INTERCONNECTION OF PROCESS LINES BETWEEN PROCESS UNITS Since there is no change in capacities of units in comparison to capacities envisaged under RCEP project, there will not be any change in sizes of existing interconnecting process lines. New interconnecting offsite lines shall be considered for New KHDS Unit. Size and number of lines shall be finalized during design stage PRODUCT RUN DOWN LINES FROM REFINERY TO MARKETING TERMINAL Final Products are received to Marketing Terminal from Refinery through piping. The maximum length of each pipe from Refinery to Bina Dispatch Terminal is 2.5 Kms. These pipes are above ground lines on Pipe sleepers. Since there is no change in capacities of units in comparison to capacities envisaged under RCEP project, there will not be any change in sizes of existing product run down lines from refinery to marketing terminal. Existing Kerosene rundown line shall be utilised to route the desulphurized kerosene from new KHDS to marketing terminal to blend it with diesel.

101 UTILITY AND OFFSITE DESCRIPTION Rev. No. 1 Page 8 of 7 SECTION 7

102 PROJECT COST ESTIMATE Rev. No. 1 Page 1 of 1 SECTION 8 SECTION 8.0 PROJECT COST ESTIMATE

103 PROJECT COST ESTIMATES LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM A953-FR Rev No 0 Section 8 Page 1 of 8 CHAPTER 8 PROJECT COST ESTIMATE Copyright EIL All rights reserved

104 PROJECT COST ESTIMATES LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM A953-FR Rev No 0 Section 8 Page 2 of INTRODUCTION Bharat Oman Refineries Limited (BORL) Refinery was implemented as part of the New Refinery Project and commissioned in June Refinery has been designed for 65: 35 weight blend of Arabian Light and Arabian Heavy for a crude processing capacity of 6.0MMTPA. BORL is currently carrying out low cost debottlenecking project to increase present refinery capacity from 6.0 MMTPA to 7.8 MMTPA by taking advantage of the inherent margins in the system design with fewer additional facilities. Meantime an industry meeting was held at CHT, Noida on 17th Feb 16 for the reduction of Sulphur in kerosene /ATF. It was deliberated and finalized to reduce the Sulphur content in SKO from present 0.25 wt% to 0.20 wt% and similar reduction of sulphur in ATF specification is also expected. In view of the above, BORL wants to study the various options available to minimize the kero production and sulphur reduction in Kero/ATF along with following overall objectives: Meeting BS V/VI specifications for MS and HSD. Maximization of Diesel Production. BORL engaged Engineers India Limited to do a LP study for studying various options to achieve the above said objectives. Capital cost estimate within an accuracy of ±30% has been submitted for four cases. Under this study Case 2J was the final selected case and 500 KTPA New Kero Hydro Desulphurization Unit (KHDS) [EIL & IOCL R&D Technology] was proposed to implement in BORL refinery, BORL now wants the cost estimate with ±20% accuracy for the selected case to facilitate project approval process 8.2 SCOPE Based on equipment list with brief specifications, unit cost estimate has been prepared. Other facilitates such as cooling tower, offsite pumps and pipeline from unit to marketing terminal are also in the scope of work. Based on scope, cost estimate for Case 2J has been prepared with ±20% accuracy. 8.3 PROJECT COST Capital cost estimate for the identified scope works for above cases are as under- Sl.No. Cases Total Capital Cost in ` Crore 1 Case 2J Copyright EIL All rights reserved

105 PROJECT COST ESTIMATES LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM A953-FR Rev No 0 Section 8 Page 3 of 8 Validity of Cost estimate is as of 1 st Qtr 2017 price basis. This Project cost estimate shall be read along with Key assumptions and Exclusions listed at para 8.4 & KEY ASSUMPTIONS The basic assumptions made for working out the Project cost estimate are as under: Cost estimate is valid as of 1 st Qtr 2017 price basis. No provision has been made for any future escalation Project would be implemented on conventional mode. Process units cost estimate is based on equipment list with brief specifications. EPCM services cost provision is as a factor basis and is indicative. Existing facilities of BORL such as land, Infrastructure, Construction site, General facilities and Township shall be used for this project. Site Development and Road & Buildings are not envisaged for this project. 8.5 EXCLUSIONS Following costs have been excluded from the Project cost estimate: Forward escalation Cost towards statutory clearances 8.6 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 +20% based on the methodology used and the quality of the information available for cost estimation. Capital cost estimate is enclosed as Annexure. Process Units The cost estimate for Process units has been prepared based on equipment list with brief specifications and inhouse cost data. Catalyst and Chemicals cost is included under unit cost. A factored approach has been adopted to estimate the cost for piping, electrical, instrumentation, spares and construction costs. These costs may vary depending upon Copyright EIL All rights reserved

106 PROJECT COST ESTIMATES LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM A953-FR Rev No 0 Section 8 Page 4 of 8 the quantum of work assessed during detailed engineering. Piping cost represents ISBL cost for Process unit. Electricals cost includes equipment cost for unit sub-station, MCC, PCC, cables etc. within ISBL. Utilities & Off-sites Cost for Cooling Water System is considered based on in-house cost data. One cooling tower cell of 4000 m3/hr is installed in series with existing cooling tower in refinery, no additional cost towards electrical and instrumentation are envisaged. Cost for Kerosene Reprocessing Pump is based on technical inputs and inhouse cost data Cost estimate includes the cost of kerosene reprocessing pipeline from unit to marketing terminal. Scope of Factors The factors used under Process units are for the following items: Civil and structural items for foundations, technical structures, pipe-racks materials and labour Installation of Equipment Piping materials supply and installation. Electrical & Instrumentation materials supply and installation. Insulation, Painting and fireproofing materials supply and installation. The factors exclude the following items: Piling works Any unusual construction requirements Indirect Costs, Exchange Rates The cost estimate is based on following Exchange Rates & Indirect costs: Exchange Rate Not applicable Ocean Freight Port Handling Inland freight Insurance Not applicable Not applicable 5% of ex-works cost of indigenously sourced equipment 1% of Total cost Copyright EIL All rights reserved

107 PROJECT COST ESTIMATES LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM A953-FR Rev No 0 Section 8 Page 5 of 8 Statutory Taxes and Duties Provision for statutory taxes & duties has been made as under: Custom Duty Excise Duty Central Sales Tax Not applicable 12.5% of ex-works cost of indigenously sourced equipment. 2% on ex-works cost of indigenously sourced equipment including excise duty. State Entry Tax 1% Service Tax on Engineering Service Tax on work contract VAT on Contracts 15.0% on Engineering Services (14%+ 0.5% swatch Bharat Cess + 0.5% Krishi Kalyan Cess 6.0% (15% of 40%) on Contract Value 7.5% (12.5% of 60%) on Contract Value Land and Site Development Existing land is adequate for the project. Considering graded site is available, no cost provision has been made for site development. Licensors fee Provision for Basic engineering and license fee has been made based on in-house information. Cost includes provision for service 15.0%. Project Management, Detailed Engineering, Procurement Services & Construction Supervision A provision in the cost estimate has been kept towards the services of project management, detailed engineering, procurement services & construction supervision assistance as factor of project cost. This fee is indicative in nature. Cost includes provision for service 15.0%. Piling Piling is not required for the site. Roads & Buildings New roads & buildings are not envisaged for this project as existing shall meet the requirement. Copyright EIL All rights reserved

108 PROJECT COST ESTIMATES LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM A953-FR Rev No 0 Section 8 Page 6 of 8 Effluent Treatment Plant Existing Effluent Treatment Plant shall meet the requirement of this project. Infrastructure facilities Existing infrastructure facilities shall meet the requirement of this project Construction Site Facilities Power and Water shall be available at the battery limit of the plant by BORL. Further cost provision has not been made. General Facilities Existing General facilities shall meet the requirement of this project. Township Additional manpower is not envisaged for this project. Hence, no cost provision is considered. Owners Construction Period Expenses Cost provision for owner s construction period expenses has been made as per inhouse norms for items such as project management, salaries & wages, feasibility reports, training requirement, legal expenses, vehicles hire / rentals / maintenance, stationary, postage, travel etc. during project construction period. Start-up & Commissioning A provision has been made for chemicals & consumables, vendor servicemen, technician & operators required during start-up and commissioning period as factor of Plant and machinery cost. Contingency Provision for contingency has been 10% of capital cost excluding interest during construction. This provision has been kept to take care of inadequacies in estimate basis definitions (including design and execution) and inadequacies in estimating methods and data elements. Working Capital Margin Working Capital Margin is excluded Interest during construction Interest during construction period required for the project has been worked out based on following: Debt - Equity ratio : 2:1 Copyright EIL All rights reserved

109 PROJECT COST ESTIMATES LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM A953-FR Rev No 0 Section 8 Page 7 of 8 Rate of interest : 9.0% Construction period Expenditure Pattern : 30 months : Equity before debt Details are given in Financial Analysis under Chapter 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 viability of the project. The basis of financial analysis is as under: 1 Construction Period 30 months 2 Project Life 20 years 3 Debt / Equity Ratio 2:1 4 Expenditure Pattern Equity before debt 5 Loan Repayment period 9 years 6 Moratorium Period 1 Year 7 Upfront Fee - 8 Interest on Long Term Debt 9.5% 9 Capital Phasing (Total) 1 Year 20% 2 Year 40% 3 Year 40% 4 Year 10 Capacity Build up 11 1 st year 80% 2 nd year onwards 100% Corporate Tax surcharge+3% educational cess 12 MAT Not applicable Annual operating cost has been computed considering costs towards crude prices, utilities and fixed operating cost (Salaries & wages are excluded, General Administrative expenses@ 0.5% of plant & machinery, Repair & 1% of Plant & Machinery and Insurance & 0.5% of the capital cost). Annual Sales Revenue is Copyright EIL All rights reserved

110 PROJECT COST ESTIMATES LINEAR PROGRAMMING (LP) STUDY FOR MINIMIZATION OF KEROSENE FROM A953-FR Rev No 0 Section 8 Page 8 of 8 based on product slate for various configurations and prices as provided by Client. Details of annual operating cost and Sales revenue is enclosed as Annexure. Operating cost and Sales revenue is based on differential basis. Financial Analysis of project has been worked out as per above details. Based on above methodology, Capital cost estimate, Operating cost, Sales revenue on differential basis and financial analysis has been carried out for the following cases and the results are summarized below: All cost in Rs lacs Sr No Case 2J 1 Yr Average Price 3 Yr Average Price 1 Capital Cost Variable Operating Cost Fixed Operating Cost Total Operating Cost Sales Revenue IRR on Total Capital Pre-Tax Post-Tax 7 IRR on Equity Pre-Tax Post-Tax 43.87% 35.97% 38.60% 31.78% 50.84% 41.71% 45.00% 36.99% Enclosures: Capex, Opex & Sales Revenue 1. Project cost Summary (1 Sheet) 2. Unit Cost summary (1 Sheet) 3. U&O Summary (1 Sheet) 4. Annual Operating cost & Sales Realization 1 yr Avg (2 sheets) 5. Annual Operating cost & Sales Realization 3 yr Avg (2 sheets) Copyright EIL All rights reserved

111

112 JOB NO. A953 DOCUMENT NO. A953-CE PROJECT LP STUDY FOR MINIMIZATION OF KEROSENE REVISION NO. 0 CLIENT BORL DATE 9-Feb-17 COST ENGINEERING DEPARTMENT PAGE NO. 1 of 1 Cost are in Rs Lakhs ANNUAL OPERATING COST (1 Yr Avg Price) Base Case Case 2 J S.No. DESCRIPTION / CASES Unit Prices (RS./MT) Prices (Rs./Unit) Quantity in '000 Amount Quantity in '000 Amount Diff Amount A VARIABLE COST 1 CRUDE ARAB MIX MT FUEL COAL UTILITIES RAW WATER SUB-TOTAL A 59 B FIXED OPERATING COST 1 SALARIES & WAGES Nos. Excluded 2 REPAIR & MAINTENANCE 1.0% of Plant & Machinery GENERAL ADMINISTRATION 0.5% of Plant & Machinery 82 4 INSURANCE & TAXES 0.5% of Total Capital Cost 1 16 SUB-TOTAL B 3 63 TOTAL 4 21 Format no F5 Rev.4

113 JOB NO. A953 DOCUMENT NO. A953-CE PROJECT LP STUDY FOR MINIMIZATION OF KEROSENE REVISION NO. 0 CLIENT BORL DATE 9-Feb-17 COST ENGINEERING DEPARTMENT PAGE NO. 1 of 1 S.No. DESCRIPTION / CASES Unit ANNUAL SALES (1 Yr Avg Price) Prices (RS./MT) Prices (Rs./Unit) Quantity in '000 Base Case Amount Quantity in '000 Case 2J Amount Cost are in Rs Lakhs Diff Amount A SALE OF PRODUCTS 1 MIXED LPG NAPHTHA SALES BS VI GASOLINE KEROSENE HYDROTREATED KERO ATF MT BS VI DIESEL SULPHUR DCU COKE PRODUCT FUEL & LOSS CPP FULE LOSS TOTAL Format no F5 Rev.4

114 JOB NO. A953 DOCUMENT NO. A953-CE PROJECT LP STUDY FOR MINIMIZATION OF KEROSENE REVISION NO. 0 CLIENT BORL DATE 9-Feb-17 COST ENGINEERING DEPARTMENT PAGE NO. 1 of 1 Cost are in Rs Lakhs ANNUAL OPERATING COST (3 Yr Avg Price) Base Case Case 2 J S.No. DESCRIPTION / CASES Unit Prices (RS./MT) Prices (Rs./Unit) Quantity in '000 Amount Quantity in '000 Amount Diff Amount A VARIABLE COST 1 CRUDE ARAB MIX MT FUEL COAL UTILITIES RAW WATER SUB-TOTAL A 60 B FIXED OPERATING COST 1 SALARIES & WAGES Nos. Excluded 2 REPAIR & MAINTENANCE 1.0% of Plant & Machinery GENERAL ADMINISTRATION 0.5% of Plant & Machinery 82 4 INSURANCE & TAXES 0.5% of Total Capital Cost 1 16 SUB-TOTAL B 3 63 TOTAL 4 23 Format no F5 Rev.4

115 JOB NO. A953 DOCUMENT NO. A953-CE PROJECT LP STUDY FOR MINIMIZATION OF KEROSENE REVISION NO. 0 CLIENT BORL DATE 9-Feb-17 COST ENGINEERING DEPARTMENT PAGE NO. 1 of 1 S.No. DESCRIPTION / CASES Unit ANNUAL SALES (3 Yr Avg Price) Prices (RS./MT) Prices (Rs./Unit) Quantity in '000 Base Case Amount Quantity in '000 Case 2J Amount Cost are in Rs Lakhs Diff Amount A SALE OF PRODUCTS 1 MIXED LPG NAPHTHA SALES BS VI GASOLINE KEROSENE HYDROTREATED KERO ATF MT BS VI DIESEL SULPHUR DCU COKE PRODUCT FUEL & LOSS CPP FULE LOSS TOTAL Format no F5 Rev.4

116 PROJECT : LP STUDY FOR BORL, BINA COST ENGINEERING DEPARTMENT PLANT & MACHINERY (CASE-2J) SL. ALL COST IN RS. LAKHS JOB NO. A953 D E S C R I P T I O N NO. CLIENT M/s BORL Fc Ic Sc TOTAL LOCATION Bina 1 EQUIPMENTS/SYSTEMS CAPACITY 500 KTPA 1.1 COLUMNS WITH INTERNALS VESSELS REACTORS HEAT EXCHANGERS TYPE OF ESTIMATE 1.5 AIR COOLERS Feasibility Report 1.6 PUMPS & DRIVES COMPRESSOR BID VALIDITY 1.8 REBOILER FURNACE PACKAGES MISCELLANEOUS UNIT KHDS 1st Quarter of 2017 SUB-TOTAL (1) BULK MATERIALS NOTES 2.1 PIPING ELECTRICAL CUSTOMS DUTY * NA 2.3 INSTRUMENTATION EXCISE DUTY 12.50% CST 2.00% Entry Tax 1.00% SUB-TOTAL (2) SERVICE TAX 15% on Engg. Services 3 SPARES SERVICE TAX on Contracts 4 CATALYST & CHEMICALS VAT on Contracts 6.0% (15% of 40% on Contract Value) 7.5% (12.5% of 60% on Contract Value) 5 ERECTION SUB-TOTAL (1 TO 4) MECHANICAL ELECTRICAL INSTRUMENTATION SUB-TOTAL (5) CIVIL WORKS INSULATION, PAINTING, FIRE PROOFING & CHEMICAL CLEANING PREPARED BY REVIEWED BY Sanjiv Kumar SUB-TOTAL (1 TO 7) APPROVED BY 8 INDIRECT COSTS Sanjiv Kumar 8.1 OCEAN FREIGHT 8.2 CUSTOMS DUTY 8.3 PORT HANDLING 8.4 INLAND FREIGHT EXCISE DUTY CENTRAL SALES TAX OCTROI / ENTRY TAX WORKS CONTRACT TAX/VAT ON S/c DOCUMENT NO. A953-CE SERVICE TAX REVISION NO INSURANCE DATE : 09-Feb-17 SUB-TOTAL (8) PAGE : 1 T O T A L C O S T FILE NAME Format no F2 Rev.0/ PROJECT MANAGER Dr. Shobha Agarwal Rohini S U M M A R Y Battery Limit Unit Cost

117 Job No. : Project : Client : A953 LP Kerosene BORL CASHFLOW STATEMENT - 1 YEAR AVG PRICE Total Capital Equity IRR (Pretax) 43.87% 50.84% Rev. No. 0 IRR (Posttax) 38.60% 45.00% Page No. of 1 * All cost in Rs Lakhs S NO. DESCRIPTION CASH INFLOW A EQUITY B. DEBT 9311 CONSTRUCTION PERIOD OPERATING PERIOD C. OPERATING REVENUE D. SALVAGE VALUE 1156 CASH OUTFLOW E. MAIN INVESTMENT F. FINANCING CHARGES 421 TOTAL INVESTMENT G. OPERATING COST H. ANNUAL FIXED COST I. ANNUAL VARIABLE COST J. INTT. ON SHORT TERM LOAN K. TOTAL COST L. GROSS MARGIN(C+D-H-I-J) M. DEPRICIATION (AS PER C.A.) N. AMMORTIZATION (SEC. 35D) O. NET MARGIN(L-M-N) P. INTT. ON LONG TERM DEBT Q. PROFIT BEFORE TAX(O-P) R. TAX S. PROFIT AFTER TAX(Q-R) T. NET CASH FLOW U. LONG TERM DEBT REPAYMT ON TOTAL CAPITAL BEFORE TAX AFTER TAX ON EQUITY BEFORE TAX AFTER TAX

118 Job No. : Project : Client : A953 LP Kerosene BORL CASHFLOW STATEMENT - 3 YEAR AVG PRICE Total Capital Equity IRR (Pretax) 35.97% 41.71% Rev. No. 0 IRR (Posttax) 31.78% 36.99% Page No. of 1 * All cost in Rs Lakhs S NO. DESCRIPTION CASH INFLOW A EQUITY B. DEBT 9311 CONSTRUCTION PERIOD OPERATING PERIOD C. OPERATING REVENUE D. SALVAGE VALUE 1156 CASH OUTFLOW E. MAIN INVESTMENT F. FINANCING CHARGES 421 TOTAL INVESTMENT G. OPERATING COST H. ANNUAL FIXED COST I. ANNUAL VARIABLE COST J. INTT. ON SHORT TERM LOAN K. TOTAL COST L. GROSS MARGIN(C+D-H-I-J) M. DEPRICIATION (AS PER C.A.) N. AMMORTIZATION (SEC. 35D) O. NET MARGIN(L-M-N) P. INTT. ON LONG TERM DEBT Q. PROFIT BEFORE TAX(O-P) R. TAX S. PROFIT AFTER TAX(Q-R) T. NET CASH FLOW U. LONG TERM DEBT REPAYMT ON TOTAL CAPITAL BEFORE TAX AFTER TAX ON EQUITY BEFORE TAX AFTER TAX

119 COST ENGINEERING DEPARTMENT PROJECT :LP STUDY FOR MINIMIZAATION OF KEROSENE FROM UTILITIES & OFFSITES (CASE 2J) NO. D E S C R I P T I O N ALL COSTS ARE IN RS. LAKHS JOB NO. A953 Fc Ic Sc. TOTAL CLIENT BORL 1 MAJOR ITEMS LOCATION Bina 1.1 RAW WATER SYSTEM Existing CAPACITY 1.2 COOLING WATER SYSTEM UNIT U&O 1.3 DM WATER SYSTEM Existing 1.4 COMPRESSED AIR & NITROGEN SYSTEM Existing 1.5 STORAGE TANKS 1.6 FLARE SYSTEM Existing TYPE OF ESTIMATE 1.7 FIRE FIGHTING / PROTECTION SYSTEM Feasibility Report 1.8 OFFSITE PUMPS MISC. EQUIPMENTS EXECUTION METHODOLOGY Conventional SUB-TOTAL (1) BULK MATERIALS 2.1 PIPING ELECTRICAL INSTRUMENTATION ESTIMATE VALIDITY 1st Quarter of 2017 NOTES SUB-TOTAL (2)... 3 SPARES 3 3 CUSTOMS DUTY * NA 4 CHEMICALS EXCISE DUTY 12.50% SUB-TOTAL (1 to 4) CST 2.00% Entry Tax 1.00% 5 ERECTION SERVICE TAX 15% on Engg. Services MECHANICAL SERVICE TAX on Contracts 6.0% (15% of 40% on Contract Value) ELECTRICAL VAT on Contracts 7.5% (12.5% of 60% on Contract Value) INSTRUMENTATION SUB-TOTAL (5) CIVIL WORKS INSULATION AND PAINTING PROJECT MANAGER SUB-TOTAL (1 TO 7) Dr. Shobha Agarwal 8 INDIRECT COSTS 8.1 OCEAN FREIGHT PREPARED BY Rohini 8.2 CUSTOMS DUTY 8.3 PORT HANDLING REVIEWED BY Sanjiv Kumar 8.4 INLAND FREIGHT EXCISE DUTY 3 3 APPROVED BY Sanjiv Kumar 8.6 CENTRAL SALES TAX OCTROI / ENTRY TAX 8.8 VAT ON WORKS CONTRACT SERVICE TAX ON WORKS CONTRACT LABOUR CESS Not Applicable 8.11 INSURANCE SUB-TOTAL (8) REVISION NO. 0 T O T A L C O S T FILE NAME Format no F2 Rev.0/ DOCUMENT NO. DATE : PAGE : 1 S U M M A R Y Battery Limit Unit Cost A953-CE

120 HEALTH SAFETY & ENVIRONMENT Rev. No. 0 Page 1 of 1 SECTION 9 SECTION 9.0 HEALTH SAFETY & ENVIRONMENT

121 HEALTH SAFETY & ENVIRONMENT MINIMIZATION 0 OF KEROSENE FROM Rev. No. 0 Page 1 of 2 SECTION HEALTH AND 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, following HSE related studies shall be done 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 9.1 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.

122 HEALTH SAFETY & ENVIRONMENT MINIMIZATION 0 OF KEROSENE FROM Rev. No. 0 Page 2 of 2 SECTION 9 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. Some of the measures to be taken are as follows: Solid Waste - It is recommended to dispose off solid waste such as spent catalyst, tank bottom sludge and ETP sludge in secured landfills outside the refinery complex. Liquid waste - A fully fledged Effluent Treatment Plant (ETP) based on the state-of the art Reverse Osmosis (RO) technology has been considered in the configuration to treat various liquid effluents generated in the refinery complex. Gaseous Effluents - Atmospheric emissions related to the proposed facilities emanate mainly from the stacks located in various process units and in the CPP. - SOx Control - In order to control SOx emissions according to NEMA guidelines, it is proposed to use internal fuel oil with maximum sulphur of 0.5 wt%. This will limit SOx emissions from individual stacks within the approved limits of TPD. - NOx Control - Low NOx burners have been recommended to reduce NOx emission from all furnaces. - 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.

123 RECOMMENDATIONS Rev. No. 0 Page 1 of 1 SECTION 10.0 SECTION 10.0 RECOMMENDATIONS

124 RECOMMENDATIONS Rev. No. 1 Page 1 of 2 SECTION CONCLUSIONS & RECOMMENDATIONS 10.1 CONCLUSION: Financially all the four shortlisted cases are giving the better GRM comparing with the Base case GRM Case 1A This option considers withdrawal of minimum Kerosene product from crude column & dropping rest into Gas Oil which can be processed in DHT unit. Modifications will be required in Gas Oil section of crude unit which will call for shutdown of the unit. This option requires additional 6% capacity increase in DHT unit over and above the debottlenecking project capacity of DHT. BORL is presently operating DHT unit at 130% of design capacity and this capacity will increase to 145% in debottlenecking project by exhausting all the design margins in existing equipment, especially in high pressure section and reactors. Further increase in the DHT capacity is technically not possible. Even if it was possible to revamp DHT unit, this option will produce 213 KTPA Kerosene which must be exported. As the objective of Kerosene minimization is not met and required capacity of DHT exceeds the debottlenecking project capacity, this option is ruled out. Case 1D This option considers lifting part of Kerosene into Naphtha, dropping a part of Kerosene into Gas Oil and thus withdrawing minimum Kerosene Product from crude column. This option requires modifications in naphtha, gas oil section of crude column and naphtha stabilizer column which will call for shutdown of the unit. DHT capacity requirement in this case also increases to 106% of debottlenecking project capacity. This option reduces the Kerosene make to nil but produces 43 KTPA of surplus Naphtha which is a negative value stream and must be exported. This option is not technically possible as desired capacity of DHT exceeds debottlenecking project capacity and requires export of 43 KTPA Naphtha.

125 RECOMMENDATIONS Rev. No. 1 Page 2 of 2 SECTION 10.0 Case 2A: This is Case 1A with New Kero Hydrodesulphurization unit to hydro treat the excess kerosene. Similar to Case 1A, this option also requires modifications in Gas Oil section of crude unit and required capacity of DHT exceeds the debottlenecking project capacity Hence this option is ruled out. Case 2J: This option considers installing a new KHDS unit which will eliminate Kerosene production from refinery by upgrading entire Kerosene into HSD after desulphurization. HSD product will meet BS-VI specifications after Kerosene blending. This will not require modification in the existing units and can be largely implemented independently without affecting normal operation of the refinery RECOMMENDATIONS It is recommended to consider New Kero Hydro Desulphurization Unit (KHDS) of capacity 500 KTPA (Case J) for implementation because of the following advantage over other cases 1. No modification required in any of the existing processing Units 2. Maximum Utilization of existing process units 3. Flexibility to produce low Sulphur kerosene or NIL kerosene from the refinery 4. Product slate in line with the Objectives considered for the study The estimated Capital cost for this will be Rs Crores with an accuracy of ±20% & price Validity of 1 st quarter Considering the crude and product prices as mentioned in report, Post Tax IRR for this selected case works out to be 38.6% (1 year avg. price) and 31.78% (3 year avg. price).

126 Annexure I Rev. No. 1 Page 1 of 1 ANNEXURE 1 ANNEXURE I OVERALL PLOT PLAN

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128 Annexure II Rev. No. 1 Page 1 of 1 ANNEXURE II ANNEXURE II PROCES FLOW SCHEME

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132 Annexure III Rev. No. 0 Page 1 of 1 ANNEXURE III ANNEXURE III BLOCK FLOW DIAGRAM

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138 ANNEXURE IV Rev. No. 0 Page 1 of 1 ANNEXURE IV ANNEXURE IV CRUDE ASSAY

139 Crude Summary Report Reference: ARBLT332 + ARAHV277 Crude: Arab Mix BORL General Information Molecules (%wt on crude) Whole Crude Properties Reference: ARBLT332 + ARA methane + ethane C (g/cc) Name: Arab Mix BORL propane 0.24 API Gravity Traded Crude: Unknown isobutane 0.15 Total Sulphur (% wt) 2.32 Origin: Unknown n-butane 0.76 Pour Point ( C) Sample Date: - isopentane C (cst) Assay Date: - n-pentane C (cst) Issue Date: - cyclopentane 0.07 Nickel (ppm) 9.2 Comments: C 6 paraffins 2.35 Vanadium (ppm) 29.1 C 6 naphthenes 0.39 Total Nitrogen (ppm) 1207 benzene 0.08 Total Acid Number (mgkoh/g) 0.07 C 7 paraffins 2.37 Mercaptan Sulphur (ppm) C 7 naphthenes 0.62 Hydrogen Sulphide (ppm) 6.2 toluene 0.33 Reid Vapour Pressure (psi) 4.1 Cut Data Atmospheric Cuts Vacuum Cuts Start ( C) IBP C End ( C) FBP FBP FBP Yield (% wt) Yield (% vol) Cumulative Yield (% wt) Volume Average B.P. ( C) C (g/cc) API Gravity UOPK Molecular Weight (g/mol) Total Sulphur (% wt) Mercaptan Sulphur (ppm) Total Nitrogen (ppm) Basic Nitrogen (ppm) Total Acid Number (mgkoh/g) C (cst) C (cst) C (cst) C (cst) C (cst) C (cst) 1765 RON (Clear) MON (Clear) Paraffins (% wt) Naphthenes (%wt) Aromatics (% wt) Pour Point ( C) Cloud Point ( C) Freeze Point ( C) Smoke Point (mm) Cetane Index Naphthalenes (% vol) Aniline Point ( C) Hydrogen (% wt) Wax (% wt) C 7 Asphaltenes (% wt) Micro Carbon Residue (% wt) Rams. Carbon Residue (% wt) Vanadium (ppm) Nickel (ppm) Iron (ppm)

140 Yield Distribution Reference: ARBLT332 + ARAHV277 Crude: Arab Mix BORL Cumulative Yield 700 Weight Yield Volume Yield TBP C % distilled

141 Crude Summary Report Reference: KUWAT304 Crude: Kuwait Exp Bld '07 General Information Molecules (%wt on crude) Whole Crude Properties Reference: KUWAT304 methane + ethane C (g/cc) Name: Kuwait Exp Bld '0 propane 0.18 API Gravity Traded Crude: Kuwait isobutane 0.16 Total Sulphur (% wt) 2.74 Origin: Kuwait n-butane 0.75 Pour Point ( C) Sample Date: 17 December 2007 isopentane C (cst) Assay Date: 11 May 2008 n-pentane C (cst) 9.44 Issue Date: 14 May 2008 cyclopentane 0.08 Nickel (ppm) 11.3 Comments: C 6 paraffins 2.35 Vanadium (ppm) 30.3 C 6 naphthenes 0.44 Total Nitrogen (ppm) 1540 benzene 0.07 Total Acid Number (mgkoh/g) 0.04 C 7 paraffins 2.17 Mercaptan Sulphur (ppm) C 7 naphthenes 0.64 Hydrogen Sulphide (ppm) 4.0 toluene 0.31 Reid Vapour Pressure (psi) 3.6 Cut Data Atmospheric Cuts Vacuum Cuts Start ( C) IBP C End ( C) FBP FBP FBP Yield (% wt) Yield (% vol) Cumulative Yield (% wt) Volume Average B.P. ( C) C (g/cc) API Gravity UOPK Molecular Weight (g/mol) Total Sulphur (% wt) Mercaptan Sulphur (ppm) Total Nitrogen (ppm) Basic Nitrogen (ppm) Total Acid Number (mgkoh/g) C (cst) C (cst) C (cst) C (cst) C (cst) C (cst) 2615 RON (Clear) MON (Clear) Paraffins (% wt) Naphthenes (%wt) Aromatics (% wt) Pour Point ( C) Cloud Point ( C) Freeze Point ( C) Smoke Point (mm) Cetane Index Naphthalenes (% vol) Aniline Point ( C) Hydrogen (% wt) Wax (% wt) C 7 Asphaltenes (% wt) Micro Carbon Residue (% wt) Rams. Carbon Residue (% wt) Vanadium (ppm) Nickel (ppm) Iron (ppm)

142 Yield Distribution Reference: KUWAT304 Crude: Kuwait Exp Bld '07 Cumulative Yield 700 Weight Yield Volume Yield TBP C % distilled

143 BLENDING Rev. No. 0 Page 1 of 1 ANNEXURE V ANNEXURE V BLENDING

144 BLENDING A953-RP Rev No 0 Page 1 of 10 Annexure V Case 1A Product Pool Blending Summary 1. GASOLINE BS VI Component to Blend TPD CASE 1A Specifications RON MON SPG SUL RVP ARO BEN OLE E70 E100 E ppmw psi vol% vol% vol% vol% vol% vol% vol% ISOMERATE DPO REFORMATE HCU HY. NAPHTHA HDT HVY. NAPHTHA TOTAL Copyrights EIL- All rights reserved

145 BLENDING A953-RP Rev No 0 Page 2 of 10 Annexure V 2. KEROSENE: CASE 1A Component to Blend TPD SPG SUL ppmw FLASH POINT C SMOKE POINT mm SR KEROSENE HCU KEROSENE Total > Copyrights EIL- All rights reserved

146 BLENDING A953-RP Rev No 0 Page 3 of 10 Annexure V 3. DIESEL BS VI CASE 1A Specifications TPD SUL FLASH POINT Viscosity % SPG CTI Component to Blend ppmw C C 360 C (vol%) DHDT DIESEL HCU HVY. GAS OIL Total Copyrights EIL- All rights reserved

147 BLENDING A953-RP Rev No 0 Page 4 of 10 Annexure V Case 1D Product Pool Blending Summary 1. GASOLINE BS VI Component to Blend TPD CASE 1D Specifications RON MON SPG SUL RVP ARO BEN OLE E70 E100 E ppmw psi vol% vol% vol% vol% vol% vol% vol% ISOMERATE DPO REFORMATE HDT. HY. NAPHTHA TOTAL Copyrights EIL- All rights reserved

148 BLENDING A953-RP Rev No 0 Page 5 of 10 Annexure V 2. KEROSENE: CASE 1D Component to Blend TPD SPG SUL ppmw FLASH POINT C SMOKE POINT mm HCU KEROSENE Total Copyrights EIL- All rights reserved

149 BLENDING A953-RP Rev No 0 Page 6 of 10 Annexure V 3. DIESEL BS VI CASE 1D Specifications TPD SUL FLASH POINT Viscosity % SPG CTI Component to Blend ppmw C C 360 C (vol%) DHDT DIESEL HCU HVY. GAS OIL HCU HVY. NAPHTHA Total Copyrights EIL- All rights reserved

150 BLENDING A953-RP Rev No 0 Page 7 of 10 Annexure V Case 2A Product Pool Blending Summary 1. GASOLINE BS VI Component to Blend TPD CASE 2A Specifications RON MON SPG SUL RVP ARO BEN OLE E70 E100 E ppmw psi vol% vol% vol% vol% vol% vol% vol% ISOMERATE DPO REFORMATE HCU HY. NAPHTHA HDT. HY. NAPHTHA TOTAL Copyrights EIL- All rights reserved

151 BLENDING A953-RP Rev No 0 Page 8 of 10 Annexure V 2. DIESEL BS VI CASE 2A Specifications TPD SUL FLASH POINT Viscosity % SPG CTI Component to Blend ppmw C C 360 C (vol%) DHDT DIESEL HCU HVY. GAS OIL HCU Kero KHDS Kero Total Copyrights EIL- All rights reserved

152 BLENDING A953-RP Rev No 0 Page 9 of 10 Annexure V Case 2J Product Pool Blending Summary 1. GASOLINE BS VI Component to Blend TPD CASE 2J Specifications RON MON SPG SUL RVP ARO BEN OLE E70 E100 E ppmw psi vol% vol% vol% vol% vol% vol% vol% ISOMERATE DPO REFORMATE HCU HY. NAPHTHA HDT. HY. NAPHTHA TOTAL Copyrights EIL- All rights reserved

153 BLENDING A953-RP Rev No 0 Page 10 of 10 Annexure V 2. DIESEL BS VI CASE 2J Component to Blend Specifications TPD SUL FLASH POINT Viscosity % SPG CTI ppmw C C 360 C (vol%) DHDT DIESEL HCU HVY. GAS OIL HCU Kero KHDS Kero Total Copyrights EIL- All rights reserved

154 Copyright EIL All rights reserved

155 EQUIPMENT LIST Rev. No. 0 Page 1 of 1 ANNEXURE VI ANNEXURE VI EQUIPMENT LIST

156 0 EQUIPMENT LIST Rev No 0 Annexure VI Page 1 of 1 EQUIPMENT LIST FOR KHDS: S. NO. TAG NO DESCRIPTION COLUMN AND REACTORS 1 XX-R-101 REACTOR 2 XX-C-101 STRIPPER COLUMN 3 XX-C-102 RECYCLE GAS AMINE ABSORBER VESSLES 1 XX-V-101 MAKE UP H2 COMPRESSOR KOD 2 XX-V-102 FEED COALESCER VESSEL 3 XX-V-103 FEED SURGE DRUM 4 XX-V-104 HP SEPARATOR 5 XX-V-106 AMINE KOD 6 XX-V-107 STRIPPER REFLUX DRUM 7 XX-V-108 A/B SALT FILTER VESSEL 8 XX-V-109 A/B CLAY FILTER VESSEL HEAT EXCHANGERS 1 XX-E-101 MAKE UP COMPRESSOR SPILL BACK COOLER 2 XX-E-102 FEED/REACTOR EFFLUENT EXCHANGER 3 XX-E-104 REACTOR EFFLUENT WATER COOLER 4 XX-E-105 STRIPPER FEED BOTTOM EXHCNAGER 5 XX-E-106 STRIPPER OVERHEAD CONDENSER 6 XX-E-107 OFF GAS CONDENSER 7 XX-E-108 PRODUCT RUNDOWN COOLER AIR COOLERS 1 XX-E-103 REACTOR EFFLUENT AIR COOLER HEATERS 1 XX-EH-101 FEED/STRIPPER REBOILER HEATER PUMPS 1 XX-P-101 A/B FEED PUMPS 2 XX-P-102 A/B STRIPPER REFLUX PUMPS 3 XX-P-103 A/B BOTTOM CIRCULATION PUMPS 4 XX-P-104 A/B PRODUCT TRANSFER PUMPS FILTERS 1 XX-G-101 A/B FEED FILTERS COMPRESSORS 1 XX-K-101 A/B MAKE UP H2 COMPRESSOR 2 XX-K-102 RECYCLE GAS COMPRESSOR

157 PROJECT IMPLEMENTATION SCHEDULE Rev. No. 0 Page 1 of 1 ANNEXURE VII ANNEXURE VII PROJECT IMPLEMENTATION SCHEDULE

158 STIPULATION OF PROPOSED PROJECT SCHEDULE KERO JOB FROM GENERAL EIL will be Process unit Licensor and Preparation of BDEP for unit - KERO HYDRO DESULPHURIZATION UNIT (KHDS) Zero date has been considered as Kick off meeting date with Client and finalization of design Basis. Investment approval for the Project by the BORL Board has been considered before zero date. Following activities / facilities has been considered to be made available by BORL at zero date on requirement basis. Site grading work (incl. Road, drain, b/wall, culverts if any) Soil Investigation work Construction Power Construction Water Site Office, Central warehouse/ Open storage yard. PROJECT IMPLEMENTATION STAGE Finalization of Basic Design Engineering Package and Issue of Residual process package. Following Units, Utilities & Offsite facilities has been considered for execution. MAJOR PROCESS UNITS KERO HYDRO DESULPHURIZATION UNIT (KHDU) : 500 KTPA UTILITY SYSTEMS Cooling water system : Addl. 1 nos. Cooling Tower of Cap M3/HR 1. Tendering cycle time duration is considered as 3 and 4 months for item rate contracts and package contracts respectively. 2. Ordering cycle of category-ii equipment / materials is considered as 3 and 3.5 months for indigenous and global MRs respectively and for Category I equipment / material, 2.5 & 3 months for indigenous & global MRs respectively. 3. Provision for air freighting of imported items shall be made depending on schedule requirement. 4. 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. 5. 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 (~3 Months/year). Adequate monsoon protection shall be kept in scope of respective contractors.

159 STIPULATION OF PROPOSED PROJECT SCHEDULE KERO JOB FROM PHILOSOPHY OF EXECUTION KERO HYDRO DESULPHURIZATION UNIT (KHDU) 1. Site free from encumbrances to be handed at zero date. 2. Project execution mode is EPCM. However following packages considered as LSTK Contracts : Cooling water system Addl. 1 nos. Cooling Towers 3. Power required for this unit shall be drawn from existing facility for Plant start-up based on feasibility studies. 4. All statutory approvals (CEA, PESO, EIA, AAI etc.) for establishment of new facilities have been considered in scope of Client. 5. Total 4 Nos (1 UG + 3 AG) of Piping MTOs have been considered. 6. Clubbing of MRs Covering requirement of unit and offsite shall be maximized. 7. Provision of air freighting for imported items shall be made depend on schedule requirement. 8. Procurement of structural steel, cement, cable trays, cable ducts, lighting fixtures etc have been considered under respective contractor scope. 9. The erection of heavy equipment considered in respective Package contractor / Mechanical contractor scope. 10. 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. 11. Modularization shall explored to the extent possible considering: Better schedule Control Reduced Overall Cost Improved quality and productivity Reduced Site Safety risk Reduced Project Execution Risk Weather impact mitigated Maximize Quality through off site Fabrication Minimize Site Labor Requirements Reduced inventory management at site 12. ROU / ROW & clearances if any from forest department considered in Client s scope.

160 S. NO DESCRIPTION REMARKS I PRE-PROJECT ACTIVITIES KOM WITH CLIENT 1 START DATE OF PROJECT (ZERO DATE) 2 PRE PROJECT FACILITY BY BORL PRE PROJECT FACILITY INLCUDING GRADED SITE, CONSTRUCTION POWER /WATER TO BE FACILITATED BY BORL II PROJECT IMPLIMENTATION STAGE MECH. COMPLETION UNIT A KERO HYDRO DESULPHURIZATION UNIT (KHDS) KTPA 1 PROCESS PACKAGE HAZOP REVIEW 1 RESIDUAL BASIC ENGINEERING OVERALL PLOT PLAN MTO UG 30% MODELLING 60% MODELLING 90% MODELLING FEILD ENGG. 2 DETAILED ENGINEERING EQUIPMENT LAYOUT 1ST MTO INTERMEDIATE MTO FINAL MTO < MAJOR CIVIL/STRL. DRAWINGS > PROJECT COMPLETION INCLUDING COMMISSIONING 3 PROCUREMENT 3.1 LLIs COMPRESSORS R R DURATION: MONTHS REACTORS / TOWER R R DURATION: MONTHS 3.2 OTHER EQPTS/ MATERIALS R R DURATION: MONTHS 3.3 BULK PROCUREMENT (COMMON) UG BULK - PIPING 1ST MTO R R R R 2ND MTO R R FINALMTO R R DURATION: 4-8 MONTHS BULK - ELECTRICAL / INSTRUMENTATION R R DURATION: 6-10 MONTHS DCS R SITE WORK DURATION: 8-10 MONTHS + 6 M SITE WORK 4 CONSTRUCTION 4.1 CIVIL/ STRL/ UG PIPING T DURATION: 14 MONTHS 4.2 HEATER PACKAGE T DURATION: 12 MONTHS 4.3 COMPOSITE WORKS (MECH / PIPING/) T DURATION: 15 MONTHS; INCLUDING HOOK UP WORKS 4.4 ELECTRICAL & INSTRUMENTATION WORKS T DURATION: 8 MONTHS B 1 UTILITY FINALIZATION OF UTILITY PACKAGE FOR COOLING TOWER 2 COOLING WATER PACKAGE T CAPACITY 4000 M3/HR DURATION: 18 MONTHS C COMMISSIONING 1 Commissioning and Start up LEGEND: T TENDER R Mat Requisition AWARD/ LOI MATERIAL DELIVERY (PART) MATERIAL DELIVERY (FULL) ACTIVITY PROJECT : BORL Kero Minimization LP study LOCATION : BINA MP ISSUED WITH DFR TSS SK PM PROPOSED PROJECT SCHEDULE FOR KERO JOB FROM A SO001 A CLIENT: BORL DATE PURPOSE PREP CHKD/ REVWD APVD DOCUMENT NO. REV 1 / 1