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DETAILED FEASIBILITY REPORT FOR

NUMALIGARH REFINERY EXPANSION PROJECT

(DRAFT)

NUMALIGARH REFINERY LIMITED

ASSAM

REPORT NO. : A555-RP-0241-0001 Volume 1 of 1 March, 2014

This report is prepared for M/S NRL and it is for use by M/S NRL

and or their assigned representatives/ organizations only.

The matter contained in the report is confidential

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

TEFR on Refinery Capacity Expansion Project

Numaligarh Refinery Limited

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INDEX 1 EXECUTIVE SUMMARY 1.1 Background……………………………………………………………… ……… 7 1.2 Objective and basis of Study…………………………………………………. 7 1.2.1 Objectives ……………………………………………………………... 7 1.2.2 Basis …………………………………………………………………… 8

1.3 Refinery Configuration ………………….……………………………………. 11 1.4 Salient Features of Configuration..…………..……………………………… 13 1.4.1 Unit Capacities ……………………………………………………..… 13 1.4.2 Product Slate …………………………………………………………. 13 1.4.3 Utility System Capacities……………………………………..……… 15 1.4.4 Offsite Facilities……………………………………..………………. .. 16 1.4.5 Crude Receipt Facilities ………………………………………………. 18 1.4.6 Product Dispatch Facilities……………..……………………….…… 18

1.4.7 Effluent Treatment Plant…..………….……………………………….. 19 1.4.8 Plot Plan Study and Land Requirement……………………………. 19 1.5 Capital Cost Estimates …………………………..…………………….…….. 19 1.6 Financial Analysis ……………………………………………………………. 20 1.6.1 Sensitivity Analysis ………………………….………………………. 21

1.7 Conclusion & Recommendations ……..…..……………………………….... 22

2 INTRODUCTION 2.1 Background………………………………………………………………………. 24 2.2 Refinery Configuration Study 2.2.1 Objective of DFR……………………………………………….…….. 24 2.2.2 Elements of NRL Configuration Study………………………………. 24 3 SCOPE OF THE DFR…………………………………………………………………. 26 4 DESIGN BASIS 4.1 Introduction……………………………………………………………………… 28 4.2 Basis of Study 4.2.1 Basic Design Parameters…………………………………………….. 28 4.2.2 Objectives of the Study……………………………………………….. 29 4.2.3 Product Demand……………………………………………………….. 29 4.2.4 Feed, Product and Utility Prices……………………………………… 31 4.2.5 Product Specifications……… ………………………………………… 31 4.2.6 Other considerations and Client Requirements for Study…………. 35 4.2.7 Exclusions……………………………………………………………… 37 4.2.8 Emission Norms……………………………………………………….. 37 Attachment-I: Crude Assay for Arab Light…………………………………………… 38 Attachment-II: Crude Assay for Arab Heavy…………………………………………. 39 Attachment-III: Table for Product Price………………………………………………… 40 Attachment-IV:Details of existing Finished Product Storage Facilities…………….. 41




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5 PROJECT LOCATION AND PLOT PLAN STUDIES 5.1 Project Location………………………………………………………………… 44 5.2 Plot Plan Studies………………………………………………………………… 44 6 PROJECT DESCRIPTION 6.1 Introduction 6.1.1 Description of Existing Facilities……………………………… ……… 46 6.1.2 Existing Refinery Feed and Product Slate…………………………… 47 6.2 Project Configuration 6.2.1 Unit Facilities…………………………………………………………… 47 6.2.2 Processing Options Considered for Expansion Study ……………. 48 6.2.3 Analysis of Case A……………………………………………………. 48 6.3 Process Description 6.3.1 Crude/Vacuum Distillation Unit……………………………………….. 52 6.3.2 Naphtha Hydrotreating Unit (NHT)…………………………………… 58 6.3.3 Naphtha Isomerization Unit (ISOM)………………………………….. 59 6.3.4 Continuous Catalyst Regeneration Reforming Unit (CCR)………… 59 6.3.5 Diesel Hydrotreating Unit (DHT)……………………………………… 60 6.3.6 Full Conversion Hydrocracker Unit (HCU)…………………………… 61 6.3.7 Delayed Coker Unit (DCU)……………………………………………. 63 6.3.8 Solvent Deasphalting Unit (SDA)…………………………………….. 65 6.3.9 Bitumen Blowing Unit (BBU)………………………………………….. 66

6.3.10 LPG Treating Unit……………………………………………………… 66 6.3.11 Fuel Gas Treating Unit………………………………………………… 67 6.3.12 Hydrogen Generation Unit (HGU)……………………………………. 68 6.3.13 Sour Water Stripper Unit (SWS)……………………………… ……… 68 6.3.14 Amine Regeneration Unit (ARU)……………………………………… 70 6.3.15 Sulfur Recovery Unit (with Tail Gas Treating Unit)…………………..71 6.4 Material Balance…………………………………………………………………. 74 6.5 Utilities Description 6.5.1 Raw Water System…………………………………………………….. 75 6.5.2 Cooling Water System………………………………………… ……….76 6.5.3 Demineralized Water and Caustic System………………………...… 79 6.5.4 Compressed Air System………………………………………………. 80 6.5.5 Nitrogen System………………………………………………………… 82 6.5.6 Steam System…………………………………………………………... 83 6.5.7 Power System…………………………………………………………… 84 6.5.8 Boiler Feed Water……………………………………………… ……… 85 6.5.9 Condensate System…………………………………………… ……… 86 6.5.10 Internal Fuel Oil and Fuel Gas System……………………… ……… 88 6.5.11 Flare System…………………………………………………… ……… 89 6.6 Offsite System……………………………………………………………………91 6.7 Product Dispatch Facilities…………………………………………………….. 95 6.8 Sulfur Balance…………………………………………………………………… 97 6.9 Hydrogen Balance……………………………………………………… ……… 98 Attachment-I: Block Flow Diagram for case A…………..………………….……..… 100




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7 ENVIRONMENTAL CONSIDERATIONS

8 PROJECT IMPLEMENTATION AND SCHEDULE 9 PROJECT COST ESTIMATE

9.1 Scope…………………………………………………………………………… 107 9.2 Project Cost………………………………………..…….…………………… .. 107

9.3 Key assumptions……………………………..…………………………………. 107 9.4 Exclusions…………………………………..…………………………………… 107 9.5 Estimation Methodology …………………………………………………….. .. 108

Attachment-I: Project Cost Summary ………………………………..…….. .. 113 10 FINANCIAL ANALYSIS……………………………………………………………….. 116

Attachment-I: Annual Operating Cost and Sales Revenue……………..….. ……….118

11 CONCLUSION & RECOMMENDATIONS……… ………………..…………. 122

12 ANNEXURES

Annexure-1: Project Plot Plan…………………….…………………………………… 124

Copyright

This document is copyright protected by EIL and is produced for the client M/s NRL. Neither this document nor 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 the document for any commercial purpose should be addressed as shown below: Head of Department Process Department Engineers India Limited 1, Bhikaiji Cama Place R.K. Puram New Delhi-110066 India Phone : +91-11-26109038 +91-11-26196181 EIL reserves the right to initiate appropriate legal action against any unauthorized use of its Intellectual Property by any entity.



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Chapter 1

EXECUTIVE SUMMARY


DFR on Numaligarh Refinery Expansion Project


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1. EXECUTIVE SUMMARY

1.1 Background Numaligarh Refineries Limited (NRL) a subsidiary of Bharat Petroleum Corporation

Limited (BPCL) presently operates a 3 MMTPA refinery at Golaghat, Assam. The refinery produces MS and HSD primarily conforming to BS-III/IV specifications by processing Assam Mix Crude. The refinery is presently executing Naphtha Splitter unit (NSU) for preparing the petrochemical naphtha for BCPL and also a wax project.

NRL intends to install a parallel new fuel refinery for crude processing capacity of 6

MMTPA. MS from the new train shall meet BS-IV/ Euro IV grade requirement whereas HSD from the new train shall meet BS-IV/ Euro IV & BS-V / Euro V grades.

With this intent NRL appointed EIL to prepare a Techno-Economic Feasibility Report

(TEFR) for Refinery Capacity Expansion. After screening of the various options in the

configuration study, the following configuration had been shortlisted

Case A (Case 12 of TEFR): Full conversion hydrocracker Unit (HCU) as secondary

processing unit and BBU/SDA/DCU as the bottoms upgradation,

NRL has appointed EIL to prepare a detailed Feasibility Report (DFR) for the refinery

augmentation based on the Case A shortlisted option with cost estimate basis of +/- 20 % accuracy.

The executive summary documents the result of the study.

1.2 Objective & Basis of Study 1.2.1 Objectives

The major objectives of the study for Refinery capacity expansion are:

Presently, the existing refinery is producing 1.356 MMTPA of Euro-III grade

HSD. To upgrade some amount of Euro-III to Euro-IV grade, 144 KTPA of Lt.

Kero and 557 KTPA of LGO streams from existing CDU unit were identified as

feed to be processed in the new refinery for up gradation.

MS from new train to comply BS-IV / Euro IV requirement

HSD from new train to comply BS-IV & BS-V requirement in a 50:50 ratio,

though the demand may call for lower requirements for BS V.

The new train will meet requirement of minimum distillate as 70% MS+HSD

No SKO to be produced. ATF to be produced after meeting HSD but limited to

specified domestic demand




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Bitumen to be produced as value added products

Coke production to be minimised

Minimise additional raw water requirement by installing water recycling

scheme

Complying to overall SOx emission limit for the refinery and meeting other

pollution control norms

No specific petrochemical feed stock will be aimed from this refinery.

1.2.2 Basis

The basis of configuration study in line with the objectives have been detailed out as follows:-

Additional train capacity

6 MMTPA of crude.

Crude Mix

Design Case : 30% Arab Light-70% Arab Heavy

Following additional streams from existing refinery will also be fed to new

expansion refinery for product upgradation.

St. Run Light LGO: 557 KTPA St. Run Light Kero: 144 KTPA

Crude assay : The crude assay followed are attached as attachment I and II

in the design basis (Chapter no. 4)

On stream factor : 8000 operating hours per year

Feed, product and utility prices: For the base case crude and product

prices based on 5 years average (April 2008-March 2013) has been

considered. Feed and product prices are indicated in the table below (Table

1.2.2.1 & 1.2.2.2). The crude price indicated accounts for the transportation

cost through pipeline indicated by NRL.




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Table 1.2.2.1 Feed Price

Crude Net Price (Rs/MT)

5 years average (2008-2009 to 2012-2013)

Arab Light 33,461

Arab Heavy 31,191 Sr Kero from Existing Refinery CDU

41,451

Sr LGO from Existing Refinery CDU

38,486.10

Utility Raw water (un-treated) Rs 3.23 /MT

Natural Gas

Rs 18587/MMBTU (based on 8.4

US$/MMBTU & 5 years average of exchange

rate)

Table 1.2.2.2 Product Prices

Products Net Price

Liquified Petroleum Gas (LPG) 40,024

Naphtha 33,626

Domestic Regular Motor Spirit, MS (BS-IV) 49,237

Export Motor Spirit, MS (BS-IV)/ Euro IV 39,291

ATF 42,470

Domestic High Speed Diesel, HSD (BS-IV) 41,927

Domestic High Speed Diesel, HSD (BS-V) 42,350

Export High Speed Diesel, HSD (BS-IV/

Euro IV) 40,619

Pet Coke (Fuel Grade) 6,000

Sulphur 4,992

Bitumen 34,543




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Limits on Product Demand : As provided by NRL and reported in Table No. 1.2.2.3

Table 1.2.2.3 Product Demand

S No. Product Additional Product Demand

from new train (MTPA)

1. Export Naphtha As Produced, to be minimized

2. Domestic regular Motor

Spirit, MS (BS-IV) 886,000 (Max) (Note-1)

3. Export Motor Spirit, MS (BS-

IV)/ (Euro-IV) In excess of domestic requirement

4. SKO 0

5. ATF 53,000 (Max)

6. Domestic High Speed

Diesel, HSD (BS-IV) 4,031,000 (Max) (Note-2)

7. Domestic High Speed

Diesel, HSD (BS-V) 92,000 (Max) (Note-2)

8. Export High Speed Diesel

(BS-IV)/ (Euro IV) In excess of domestic requirement

9. Coke As Produced, to be minimized

10. Bitumen 200,000 (Max) (Note-3)

Notes:- 1. 100% BS-IV regular MS.

2. Total MS and HSD from refinery will be minimum 70% of crude. The refinery will

have capability of producing BS-IV and BS-V grades in a 50:50 ratio. However,

product sales limits for HSD will be as reported in the above table. For export

HSD only BS IV/Euro IV price to be considered.

3. Bitumen production will be considered for all twelve months in a year.

Crude Receipt Facility:

Crude Pipeline : Imported crude will be received through cross country pipeline from Dhamra port (Excluded from study scope). However, lumpsum cost of




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3,000 Crores is considered in capex and financial analysis for pipeline.

Crude Storage: The new crude being high sulphur has dedicated storage within refinery. Three tanks of 40,000 M3 will be located at Numaligarh. Balance storage will be provided at Dhamra Port.

Product dispatch facility

For white oils (MS/HSD/SKO/ATF): presently, the white oils are dispatched by both road and rail loading facilities from existing dispatch facilities at Numaligarh and Siliguri.

In addition to rail and road loading, one 16” cross country pipeline from Numaligarh to Siliguri owned by Oil India Limited (OIL) is used for handling MS/HSD/SKO with 1.721 MMTPA capacity.

Additional Product dispatch facilities to be installed at Siliguri after utilising available capacity at Numaligarh Marketing terminal and pipeline. Adequacy of above existing product dispatch facilities has been checked for the combined production of existing refinery and additional train. Addition/ augmentation for product dispatch facility is done accordingly.

Products Storage: As the expansion refinery will be processing high sulphur

crude independent intermediate product storages have to be considered.

However for final product storage integration with existing facilities is to be

considered for optimisation.

Utilities: The utility system for new train shall be independent. However, for

CPP one standby GT/HRSG in refinery is to be considered as operating.

Raw Water: Additional water requirement will be available from river Dhansiri.

Present refinery’s raw water intake limit is 1200m3/hr from river. Existing refinery

draws 700 m3/hr. Net additional maximum expected demand is around 700

m3/hr.

Natural Gas : Natural gas will be made available. Design case for configuration

study will consider natural gas as fuel for CPP and feed & fuel for HGU.

However a sensitivity case for 50 % natural gas availability is also presented in

the report.

1.3 Refinery configuration

The following units were identified for Case A option

Primary processing Option

- 6.0 MMTPA of crude to CDU/VDU

Light ends Processing options




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- Naphtha Hydrotreater/ Continuous Catalytic Reformer Unit (CCR)/

Naphtha Isomerisation Units (NHT/ISOM)

Secondary Processing options

- Full Conversion Hydrocracker Unit (HCU)

Residue Upgradation options

- Solvent Deasphalting Unit (SDA)

- Delayed Coking Unit (DCU)

- Bitumen Blowing Unit (BBU)

Auxiliary Units

- Hydrogen generation Unit (HGU)

- SRU/SWS/ARU/TGTU

- LPG treating Unit

- For the entire cases CPP configuration (Captive power plant) with

combination of GT/HRSG and boiler (as required) to meet steam,

power requirement of the units were considered.

The schematic diagram for the new refinery is presented in figure 1.3.1

Figure 1.3.1: Schematic diagram for the new refinery




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The technology considered in selected configuration are also commercially proven and has multiple licensing options.

1.4 Salient Features of configuration

1.4.1 Unit Capacities

The unit capacities for the new train for the design crude mix are summarised in table 1.4.1.1 below.

Table 1.4.1.1 Unit Capacities

Unit Capacities in MMTPA Design Case (30 AL:70 AH)

CDU /VDU/NSU 6 NHT/CCR/ISOM 0.97/0.612/0.348 DHT 2.896 HCU 1.988 DCU 1.144 SDA 0.755 BBU 0.20 SRU(TPD) (Includes SWS single & two stages, ARU & TGTU)

420

HGU (KTPA) 78

As integration with existing units has not been considered, none of the existing units required revamp.

1.4.2 Product Slate

The estimated product slate of the additional train for the optimum case studied for the design crude mix is summarised in table 1.4.2.1 below. The graphical representation for both the case is also given below in fig 1.4.2

Table 1.4.2.1 Product Slate

Feed Purchase (MMTPA) Design Case (30 AL:70 AH) Arab Light 1.8 Arab Heavy 4.2 Natural Gas 0.493 SR Kero from Existing Refinery CDU

0.144

SR LGO from Existing Refinery CDU

0.557

Product Sales (MMTPA)

LPG 0.258 BS IV domestic Gasoline 0.886




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Feed Purchase (MMTPA) Design Case (30 AL:70 AH) BS IV Export gasoline 0.114

Light Distillate 1.258(17.56%)

ATF 0.053 Euro-IV domestic HSD 4.031 Euro-V domestic HSD 0.092 Euro-IV Export HSD 0.385

Middle Distillate 4.561(63.67%)

Bitumen 0.2 Pet Coke (High sulfur) 0.364

Heavy distillate 0.564 (7.87%)

Sulfur (TPD) 368

Fuel and Loss 0.657 (9.17 %)

Figure 1.4.2: Graphical representation for selected case product yields

17.56

63.87

7.87

1.739.17

Design case product yields (%)

Light Distillate

Middle Distillate

Heavy Distillate

Sulphur

Fuel & Loss




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1.4.3 Utility System Capacities The capacities and configuration of the utility facilities required to be installed for the

additional train are summarized in table 1.4.3.1 below

Table 1.4.3.1 Utility System Capacities

Sr

No. Utility System Capacity

1 Raw water System

Design Capacity :- 1265 M3/Hr of treated raw

water.

2 nos. of treatment plant of 1340M3/Hr

of capacity each.

2 nos. of raw water reservoirs of 44,200

M3 capacity each for two days water

storage.

2 nos. of treated raw water reservoirs of

7,600 M3 capacity each for two days

water storage.

2 CW system for process

units

Design Capacity: - 28000 M3/Hr of recirculating

Cooling water.

7W+1S CT cells of capacity 4,000

M3/Hr each

4W+2S CW re circulating pumps of

7000 M3/Hr each.

3 DM Water System

Requirement :- 6400 M3/Day of DM Water

2W+1S ion exchange resin based DM

chains of 160 M3/Hr chain capacity.

5 Steam, power & BFW

System (Note-1)

1 UB producing 110 TPH of VHP steam.

One new HRSG generating 110 TPH of

VHP steam associated with new frame

VI GTG

One existing spare frame VI GTG with

associated HRSG producing 120 TPH

of HP steam.




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Sr

No. Utility System Capacity

One 12 MW STG

6 Condensate System

Design Capacity :- -70 M3/Hr of suspect

condensate

1W+1S CPU chains of 70 M3/Hr chain

capacity.

7 Compressed air System

Requirement :- 7042 Nm3/Hr of Instrument Air

& 3160 Nm3/hr of Plant Air.

3W+1S LP air compressor of 10,000

Nm3/ hr capacity each (Common for

nitrogen and compressed air system)

8 Inert Gas system

(Cryogenic system)

1 cryogenic plant generating 1500

Nm3/Hr of Gaseous Nitrogen and 225

Nm3/Hr (equivalent, concurrent) liquid

nitrogen capacity.

9 Flare System

66” Main flare stack

20” Sour flare stack

10 Fuel Oil & fuel Gas

System 271.4 MMKcal/Hr of fuel fired

Note-1

Existing frame VI GTG associated with HRSG producing 120 TPH of VHP steam

generation will be used for the expansion. However, a future GTG/HRSG provision

will be reviewed during DFR/ implementation stage.

1.4.4 Offsite Facilities

1. Philosophy for storage of crude: 21 days storage for crude is considered.

Three tanks of 40,000 m3 nominal capacity to be installed at refinery. Balance

storage to be provided at Dhamra port.

2. Philosophy for storage of products: 10 days storage for products is

considered at refinery. Re allocation of existing tanks service (for e.g. MS to




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HSD, etc.) may be considered if it leads to reduction in new tanks requirement.

3. Philosophy for storage of intermediate products: 5 days storage for VGO &

VR is considered. All other intermediate products storage will be considered for

3 days.

The details of offsite storage facilities required to be installed for the additional train

for crude, products and intermediate products are summarized in table 1.4.4.1 below.

Excess capacity in existing product tankages have also been considered for the

expansion refinery.

Table 1.4.4.1 Offsite Facilities

Sr No. Service Numbers

Required Capacity (M3)

1 Crude storage Tank at

Refinery 3 40,000

2 Crude storageTank at

Dhamra Port 8 50,000

3 VR (Feed to BBU/SDA) 2 14,110

4 NHT feed 2 6,200

5 Isomerate 2 2,950

6 Reformate 2 4,850

7 HCU feed 2 19,900

8 DHT feed 2 15,650

9 LPG (Note 1) 5 (mounded

bullets) 2,814

10 Bitumen 2 3,750

11 Pitch (Fore Case-13 only) 2 2,269

Notes

1. 6 nos. of bullets have been considered including existing refinery LPG

production. For cost estimate for the new train, 5 Nos. of bullets have been

considered.




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2. Suitable pumping and blending system corresponding to feed, product and

intermediate product system also have been considered.

3. Coke yards for the existing and new DCUs shall be segregated. New DCU coke

yard is proposed, with storage capacity for around 21 days of production.

1.4.5 Crude Receipt Facilities

Crude will be transported from Dhamra port through new pipeline (outside scope of DFR ) to additional train. However, a lumpsum capex for the same of Rs 3000 Crores is considered. OPEX for pipeline operation shall be 16 paisa/MT/K.M. over the pipeline length.

1.4.6 Product Dispatch Facilities

Additional product dispatch facilities, required, both at Numaligarh and Siliguri are

summarized in Table 1.4.5.1 below

Table 1.4.6.1 Product Dispatch Facilities

Sr

No.

Products to be

dispatched Facilities Required Location

1 White Oils (MS/HSD) One additional rail loading

gantry to be installed Siliguri

2 LPG

Additional two numbers of

road loading gantries to be

installed

Numaligarh

3 Bitumen

Additional three numbers of

road loading gantries to be

installed

Numaligarh

4 Sulphur New truck loading facilities Numaligarh

Part of white oils (MS/SKO/HSD) are transported from Numaligarh to Siliguri by the

multiproduct Numaligarh Siliguri pipeline operated by Oil India Limited. Adequacy

and if required, upgradation of this pipeline to carry the additional production from the

refinery for dispatch from Siliguri will be taken up by NRL with OIL.

The petroleum coke handling system shall consist of handling, storage and dispatch

of petroleum coke from refinery through rail and trucks. The rail loading area shall

take care 100% of daily coke production i.e. approximately 1100 TPD (Average). The

provision for mechanised Truck Loading Station has also been kept to cater 240 MT

per day for the emergency requirement and to take care of local demands. Provision

for future expansion of truck loading capacity has also been considered.




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1.4.7 Effluent Treatment Plant

A new effluent treatment plant will be installed to treat the effluent generated from the additional train. This effluent treatment plant will also incorporate facilities for reclaiming water from the effluent for reuse in the refinery.

1.4.8 Plot Plan Study and land requirement

All new facilities required for the additional train can be accommodated within the

vacant space in the existing refinery’s plot area without any need for acquiring extra

land.

During joint plot plan review, the following considerations emerged, which have been

duly addressed in the attached plot plan

The new flare system can be located close to the existing refinery flare.

Accommodation of additional Raw water storage under the flare area proposed.

Existing secured land fill space should not be utilized for locating any new facility.

However, proposed secured land fill space location to be reviewed and if

required, it can be shifted to a new location in the refinery.

Location of new DCU close to existing DCU proposed.

LPG bullets of new refinery train will be sized to cater to existing refinery

requirements also. Accordingly, existing LPG spheres will be dismantled /

decommissioned.

Post office, bank to be relocated close to the marketing terminal.

Control room, including requirement of existing to be located near existing MCR

area.

1.5 Capital Cost Estimates

The capital cost estimate provided is based on the following.

The cost estimate has an accuracy of +/- 20%.

Validity of cost estimate is as of 1st quarter 2014 cost basis.

No provision has been made for any future escalation

No provision has been made for any exchange rate variation.

It has been assumed that all units and utilities / off-sites facilities would be

implemented on conventional mode.

EPCM services cost provision is as a factor basis of plant and machinery cost




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and is indicative.

All costs are reflected in INR and all foreign costs have been converted into

equivalent INR using exchange rate of 1USD=Rs 60

Pipeline cost has been considered as lumpsum. Cost of pipeline including

IDC was considered as 3000 Crores. No contingency on pipeline capex was

considered.

Township expansion expenses considered as 100 Crores.

Infrastructure cost considered as 50 Crores.

Workshop expenses considered as 5 Crores

Dismantling cost considered as 10 Crores

Working capital requirement is based on feed stock, intermediate and product

storage, pipeline, catalyst and chemicals, cash requirement for salaries and

wages and utilities, accounts payable and receivables. 25 % of working

capital has been capitalized as margin money.

Cenvat on the project was considered as Rs 655 Crores based on revised

cost of the project as well as exclusion of Cenvat on Pipeline

Cenvat Credit shall be availed in two equal instalment in 1st and 2nd year of

operation

1.6 Financial Analysis

The operating cost, sales revenue and financial analysis have been carried out for

calculating internal rate of return (IRR) with a view to establish profitability of the

project. The basis of financial analysis is as under:-

Table 1.6.1 Basis of financial analysis

1 Construction Period 4 years

2 Project Life 20 years

3 Debt / Equity Ratio 2:1

4 Expenditure Pattern Equity before debt

5 Loan Repayment period 5 years

6 Moratorium Period 1 Years

7 Interest on Long Term Debt 12%

8 Capital Phasing (Total Capital)

1 Year 5%

2 Year 15%




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3 Year 35%

4 Year 40%

1 Year of Operation 5%

10 Capacity Build – up

1st year 80%

2nd year onwards 100%

11 Corporate Tax Rate @ 30%+ 5.0% surcharge+ 3%

Education cess

12 MAT @ 18.5%+ 5.0% surcharge+ 3%

Education cess

Based on the above, capital cost estimate, operating cost, sales revenue and

financial results are tabulated below:

Table 1.6.2 Financial analysis for selected case

Sl. No. Description Values

1 Capital Cost (Crores) 14703

2 Variable Operating Cost (Crores) 22898

3 Fixed Operating Cost (Crores) 244

4 Total Operating Cost (Crores) 23142

5 Sales Revenue (Crores) 25893

6 Net Revenue (Crores) 2751

7 IRR (Pre Tax) on Total Capital (%) 15.1

8 IRR (Post Tax) on Total Capital

(%) 13.1

1.6.1 Sensitivity Analysis:

Sensitivity Analysis has been carried out for following cases and tabulated below:

1) Case-A with no availability of NG 2) Case-A with 1.05 MMSCMD availability of NG 3) Case-A with 1.3 MMSCMD availability of NG. 4) Case-A with +10% variation of capex amount 5) Case-A with +20% variation of capex amount 6) Case-A with +30% variation of capex amount




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1.7 Conclusions & Recommendations

The selected configuration for the proposed refinery is robust and proven.

The configuration also synergizes the SR Kero and SR LGO streams from existing

refinery, with the proposed facilities to add value to the streams

The capital investment for the new 6.0 MMTPA refinery planned to be set up by NRL at

Numaligarh is estimated to be Rs 14703 Crores.

Based on the selected Case A of refinery configuration (Full conversion hydrocracker

Unit (HCU) as secondary processing unit and BBU/SDA/DCU as the bottoms up

gradation), the post tax IRR is 13.07% on total capital considered.

The IRR for the project is highly sensitive to natural gas availability.

For 1.05 MMSCMD availability of natural gas, the IRR falls from 13.07 % for base case

to 8.99%. However, with the availability of 1.3 MMSCMD natural gas the IRR again

improves to 11.02 %.

Therefore, it is imperative for this project that natural gas should be available for its

implementation.

The project is therefore financially attractive for NRL to implement and further

strengthen NRL’s position in the Indian Refining industry with particular focus on

North-East region.

Sl. no.

Description

1.05 MMSCMD

NG Availability

CASE

No NG Availability

CASE

1.3 MMSCMD

NG Availability

CASE

BASE CASE SENSTIVITY

+10% -10% +20% -20% +30% -30%

1

IRR (Pre

Tax) on

Total Capital

10.45% 5.43% 12.68% 13.74% 16.74% 12.55% 18.67% 11.55% 21.04%

2

IRR (Post

Tax) on

Total Capital

8.99% 4.77% 11.02% 11.90% 14.43% 10.87% 16.06% 9.91% 18.04%




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CHAPTER 2 INTRODUCTION




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2 INTRODUCTION 2.1 Background

Numaligarh Refinery Limited (NRL), a group company of Bharat Petroleum Corporation Limited operates a 3.0 MMTPA refinery which is located at Numaligarh, Dist. Golaghat, Assam. The overall refinery configuration at Numaligarh refinery consists of Crude and Vacuum Distillation Unit; Full conversion Hydrocracker unit; Delayed Coker unit; MS block comprising Naphtha Hydrotreating unit, Semi-Regenerative Reformer and Isomerization unit; and other associated facilities such as Hydrogen Generation Unit (HGU), Sulfur Recovery Unit, Sour Water Stripper (SWS) etc. The refinery is producing MS and HSD primarily conforming to Euro III/IV specifications by processing of Assam Mix crude.

2.2 Refinery Configuration Study

In view of the projected demand growth of petroleum products in the country and also to retain its profitability and competitiveness in the long run. NRL intends to install a parallel new train for imported sour crude processing capacity of 6.0 MMTPA.

NRL has solicited the service of Engineers India Limited for carrying out the Detailed

Feasibility Report (DFR) for the Refinery capacity expansion project.

2.2.1 Objective of DFR The NRL DFR is carried out for the capacity expansion of the NRL refinery from 3.0

MMTPA to 9.0 MMTPA by installing a parallel new train of 6.0 MMTPA capacity for imported sour crude processing. The configuration of the parallel new train is fixed based on economic optimization.

2.2.2 Elements of NRL configuration Study

NRL configuration study was carried out based on a linear programming (LP) model developed by EIL. This model is based on in-house information of various process units like yields, utilities, catalysts, chemicals etc.

A total of sixteen (16) cases covering various options for secondary and bottoms

processing were considered for the proposed additional train. These were screened jointly by EIL & NRL in various meetings to arrive at the most optimum configuration.

The present study is based on the selected configuration and identified as Case A.

Case A: Full conversion hydrocracker Unit (HCU) as secondary processing unit and BBU/SDA/DCU as the bottoms upgradation.

.




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CHAPTER 3 SCOPE OF THE DFR




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3 SCOPE OF THE DFR

NRL intends to increase their existing refinery capacity of 3.0 MMTPA to 9.0 MMTPA by installing a parallel new train for crude processing capacity of 6.0 MMTPA. With this intent, the feasibility study has been carried out for a design crude mix of 30% Arab Light and 70% Arab Heavy.

Key considerations for the DFR are as follows:

Sourcing of crude to refinery is excluded from the scope of the study

MS to be produced with BS-IV specification.

HSD to be produced with BS-IV/V specification in a 50:50 ratio.

No SKO production.

ATF production after meeting HSD demand.

Bitumen to be produced up to a maximum limit.

Coke production to be minimized.

Refinery configuration to be developed based on maximization of IRR.

Crude and intermediate products storage of the existing refinery and new refinery train to be segregated.

Product storage will be combined for the two refinery trains. Accordingly, requirement of new tanks will be minimized.

One spare GT/HRSG available at refinery will be utilized for expansion on continuous basis. Except for this, utility systems of new train will be segregated.

Natural gas will be considered as CPP fuel and HGU feed & fuel.

All the new facilities will be located within the vacant plot area in the refinery.

New product dispatch facilities will be installed at the Siliguri marketing terminal.

The DFR addresses the following:

Capital and Operating cost estimation of Case A.

Financial analysis of case A from the point of view of IRR.




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Chapter 4

DESIGN BASIS




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4 DESIGN BASIS

4.1 Introduction

Numaligarh Refinery Limited (NRL), a group company of Bharat Petroleum Corporation Limited operates a 3.0 MMTPA refinery which is located at Numaligarh, Dist. Golaghat, Assam. The refinery is producing MS and HSD primarily conforming to Euro III/IV specifications by processing of Assam Mix crude.

The overall refinery configuration at Numaligarh refinery consists of Crude and Vacuum Distillation Unit; Full conversion Hydrocracker unit; Delayed Coker unit; MS block comprising Naphtha Hydrotreating unit, Semi-Regenerative Reformer and Isomerization unit; and other associated facilities such as Hydrogen Generation Unit (HGU), Sulfur Recovery Unit, Sour Water Stripper (SWS) etc.

NRL intends to install a parallel new train for crude processing capacity of 6.0 MMTPA. MS from the new processing train should meet BS-IV grade. HSD from the new processing train shall meet BS-IV and BS-V grade and shall be produced in a 50:50 ratio. With this intent NRL has appointed EIL to prepare a Detailed Feasibility Report (DFR) on Refinery capacity expansion. This section presents the basis for the above DFR.

4.2 Basis of study

4.2.1 Basic Design Parameters:

4.2.1.1 Additional Train Capacity: The capacity of the installed parallel new train will be for a crude processing capacity of 6.0 MMTPA.

The Capex and Opex will be considered based on 6 MMTPA additional train

capacity.

4.2.1.2 Crudes: 100% imported crudes will be considered for the parallel train. Sourcing of crude is excluded from the scope of the study.

Design Crude Mix: 30% Arab Light-70% Arab Heavy

4.2.1.3 Crude Assays: Crude assay adopted for additional train is attached as Attachment-I for Arab Light Crude (ARAL335s) and Attachment-II for Arab Heavy Crude (ARBH278s).

4.2.1.4 Additional train On-stream hours: 8000 hrs/ Annum. 4.2.1.5 Following additional streams from existing refinery will be fed to new expansion

refinery for product upgradation.

St. Run Light LGO: 557 KTPA

St. Run Light Kero: 144 KTPA




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4.2.2 Objectives of the study

The major objectives of the configuration study are:

i. Maximization of value added product (as identified) keeping HSD (Domestic +Export) & MS (Domestic + Export) production at least to the tune of 70% of crude. MS produced from the additional crude processing train to meet minimum BS-IV specifications. HSD produced to meet BS-IV/BS-V specifications in a 50:50 ratio. However, HSD sales will be as per BS-IV/V maximum demands indicated in the table below, i.e., in case of lower demand of BS-V HSD, same will be sold as BS-IV HSD.

ii. No additional SKO production. ATF limited production after meeting the diesel

requirements.

iii. Bitumen to be produced as value added product.

4.2.3 Product Demand

The present refinery product slate is given below. The target production from

additional train is indicated.

Table 4.2.3.1 Table for Product Demand

S No. Product

Present Product slate (MTPA) (Existing Refinery)

Additional Product Demand from new train (MTPA)

1. Liquefied Petroleum Gas (LPG)

57,000 As Produced

2. Export Naphtha 1,28,000 As Produced

3. Petrochemical Naphtha 1,60,000 As Produced

4. Regular Motor Spirit, MS (BS-III)

1,77,000 0

5. Domestic regular Motor Spirit, MS (BS-IV)

48,000 886,000 (Max) (Note-1)

6. Export Motor Spirit, MS (BS-IV)

- BS-IV MS produced in excess of 886,000 shall be exported

7. ATF 54,000, 53,000 (Max)

8. Kerosene 2,10,000 0

9. Domestic High Speed Diesel, HSD (BS-III)

13,56,000 0

10. Domestic High Speed Diesel, HSD (BS-IV)

3,50,000 4,031,000 (Max) (Note-2)

11. Domestic High Speed Diesel, HSD (BS-V)

- 92,000 (Max) (Note-2)




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S No. Product

Present Product slate (MTPA) (Existing Refinery)

Additional Product Demand from new train (MTPA)

12. Export High Speed Diesel (BS-IV)

-

HSD produced in excess of Domestic High Speed Diesel will be exported. (Note-2)

13. Sulfur 4,500 As Produced

14. Coke 80,000 As Produced, to be minimised

15. Anode Grade Coke (Note 4)

- As Produced

16. Pitch (Note 5) - As Produced, to be minimized

17. Bitumen - 200,000 (Max) (Note-3)

18. Low Sulfur Fuel Oil (Note 4)

- 150,000 (Max)

Notes:-

1. 100% BS-IV regular MS

2. Subject to minimum 70% MS+HSD production. HSD produced from the refinery will be of BS-IV and BS-V grades in a 50:50 ratio. However, considering the product saleability point of view (Based on 2020-21 demand) the revenue calculation of the refinery will be done with the following basis:-

Maximum 3.314 MMTPA BS-IV HSD domestic sales

Maximum 0.092 MMTPA BS-V HSD domestic sales

Any additional Diesel produced (BS-IV or BS-V) will be sold at export diesel prices.

With the above, part of BS-V diesel will be sold as BS-IV diesel.

3. Total Bitumen quantity shall be capped at 0.2 MMTPA. Bitumen production will be considered for all twelve months in a year.




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4.2.4 Feed, Product & Utility Prices

Crude Prices: These are as follows:-

Table 4.2.4.1 Table for Feed Price

Crude

Net Price (Rs/MT) 5 years average (2008-2009 to 2012-2013)

3 years average (2010-2011 to 2012-2013)

1 year average (2011-2012 to 2012-2013)

Arab Light

33,461 38,138 45,162

Arab Heavy

31,191 35,759 42,407

Natural

Gas

18,587 (~8.4

US$/MMBTU)

18,988 (~8.4

US$/MMBTU)

20,967 (~8.4

US$/MMBTU)

Product Prices: These are as per Attachment -III Note: 5 years average prices of Feed and Products are considered for

financial analysis of DFR

Utility Price:

Table 4.2.4.2 Table for Utility Price

Utility Price

Raw water (un-treated) Rs 3.23 /MT

Natural Gas 8.4 US$/MMBTU (1 US$ = Rs. 48.27 (5 years average), 49.31 (3 years average), 54.45 (1 year average)

Note: 5 years average exchange rate of US $ is considered for natural gas price required for financial analysis of DFR

4.2.5 Product Specifications

The product specifications adopted for this study are tabulated below.




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Table 4.2.5.1 Table for Product Specifications

Product Unit Specification Target

Specification LPG Vapor pressure at 40 °C, max

KPa 1050 1050

Odor, min 2 2 C2 minus content, max wt% 0.2 0.2 C5 plus, max wt% 2 2 Total volatile sulfur, max wtppm 200 200

Copper strip corrosion, max No. 1 No. 1 Hydrogen sulfide wtppm Nil Nil Mercaptans wtppm Nil Nil Free water Nil Nil Evaporation temperature for 95 vol%,max

°C 2 2

Naphtha (LAN) Petrochemical

Colour Saybolt +25 +25 Density @15°C gm/ml 0.67-0.7 0.67-0.7 Sulfur, max wtppm 500 500 Total Paraffins, min vol% 75 75 Olefins, max vol% 0.2 0.2 Aromatics, max vol% 6 6 Iso/Normal Paraffins 1.2 1.2 Naphthenes vol % By balance By balance IBP (ASTM D86), min Deg C 35 35 FBP (ASTM D86), max Deg C 160 160 RVP, max Psig 11 11 Chlorides, max ppmw 1.0 1.0 Lead, max ppbw 100 100 Mercury, max ppbw 1 1 Arsenic, max ppbw 5 5 Export Naphtha (As obtained )

Regular Gasoline (BS-V) (Anticipated)

Specific gravity min 0.72 0.72 max 0.775 0.775 Sulfur, max wtppm 10 10 RON, min 95 95.5 MON, min 85 85.5 Reid vapor pressure, max kPa 60 60 FBP, max °C 210 210 Aromatics, max vol% 35 34.5 Benzene, max vol% 1 0.9 Olefins content, max vol% 21 21




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Specification Oxygen content, max Wt% 2.7 2.7 Regular Gasoline (BS- IV) (As per amendment no. 1 march 2010 to IS 2796 : 2008 motor gasoline ― specification)

Specific gravity min 0.72 0.72 max 0.775 0.775 Sulfur, max wtppm 50 45 RON, min 91 91.5 MON, min 81 81.5 Reid Vapor pressure, max (Note 1)

KPa 60 60

FBP, max °C 210 210 Aromatics, max vol% 35 34.5 Benzene, max vol% 1 0.9 Olefins, max vol% 21 21 Oxygen content, max wt% 2.7 2.7 Oxygenates content, max Methanol vol% nil Nil Ethanol vol% 5 5 Iso-propyl alcohol vol% 10 10 Iso-butyl alcohol vol% 10 10 Tertiary- butyl alcohol vol% 7 7 Ethers with 5 or more carbon atoms

vol% 15 15

Other Oxygenates vol% 8 8 ATF

Specific gravity min 0.775 0.775 max 0.84 0.84

Aromatics, max vol% 22 22 Olefins, max vol% 5 5 Sulfur total, max wt% 0.25 0.25 10% recovery, max °C 205 205 FBP, max °C 300 300 Flash point (Abel), min °C 38 38 Freeze point, max °C (-) 47 (-) 47 Smoke point mm 21 21 Diesel (BS –V)(Anticipated)

Specific gravity min 0.82 0.82 max 0.845 0.845

Sulfur, max Wtppm 10 10 Viscosity at 40 °C

min cSt 2 2




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Specification max cSt 4.5 4.5

95% recovery, max °C 360 360 Flash point (Abel), min °C 35 35 Cetane number, min 51 51.5 Cetane index, min 46 46 Poly aromatic hydrocarbon, max

wt%

11 11

Cold filter plugging point, max

Summer °C 18 18 Winter °C 6 6 Diesel (BS –IV) (As per amendment no. 2 march 2010 to IS 1460 : 2005 automotive diesel fuel specification)

Specific gravity min 0.82 0.82 max 0.845 0.845 Sulfur, max Wtppm 50 45 Viscosity at 40 °C min cSt 2 2 max cSt 4.5 4.5 95% recovery, max °C 360 360 Flash point (Abel), min °C 35 35 Cetane number, min 51 51.5 Cetane index, min 46 46 Poly aromatic hydrocarbon, max

wt% 11 11

Cold filter plugging point, max

Summer °C 18 18 Winter °C 6 6 Low Sulphur Fuel Oil Flash point °C 66 66 Pour point, max °C 10 10 Total Sulfur, max wt% 3.5 3.5 Kinematic Viscosity at 50 °C, max

cst 80 80

Sediment, max wt% 0.25 0.25 Ash, max wt% 0.1 0.1 Acidity (inorganic) mg KOH/gm

Nil Nil

Water content, max vol% 1 1




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4.2.6 Other considerations and client requirements for study

4.2.6.1Crude Receipt

1 Crude will be transported from Dhamra port through new pipeline (outside scope of DFR ) to additional train. However, a lumpsum capex for the same of Rs 3000 Crores to be considered. OPEX for pipeline operation shall be 16 paisa/MT/K.M. and pipeline length will be considered as 1200 K.M.

2 Custody transfer arrangement for crude at refinery intake needs to be provided.

3 Crude storage for the additional train will be segregated from existing refinery crude storage.

4 No. of days storage: 21(based on 6 MMTPA). Three tanks of 40,000 m3 nominal

capacity to be installed at refinery. These three tanks would correspond to around 6 days of crude storage capacity. Balance storage to be provided at Dhamra port subject to minimum storage corresponding to one Suez Max capacity.

4.2.6.2Product Dispatch

Existing Facilities:

A. Road Loading Facilities:

1. LPG : 5 bays truck loading gantry at Numaligarh. 2. All white oils ( MS/HSD/SKO/ATF) : 14 bays truck loading gantry (3 dedicated for ATF) at Numaligarh

3. White oils (MS/HSD/SKO) : 8 bays truck loading gantry at Siliguri. These facilities are operated only in day shift (8 hours per shift).

4. No black oil dispatch.

5. Size of the road loading tanker : 18 KL (Max)

6. Road tanker loading rate : 72 m3/Hr

B. Rail Loading Facilities : 1. 2 spur rail loading gantry at Numaligarh, each capable of handling maximum

50 BTPN (about 65 KL capacity per wagon) of MS/Naphtha, SKO and HSD exists. Loading time per rake is 5 hours. This facility is operated during all the three shifts. Rail wagon loading rate is 72 m3/Hr per bay.

2. Single spur rail loading gantry at Siliguri capable of loading full rake of MS,

SKO and HSD capable of handling maximum 50 BTPN (about 65 KL capacity per wagon) exists. Loading time per rake is 5 hours. This facility is operated during all the three shifts. Rail wagon loading rate is 72 m3/Hr per bay.




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C. Pipeline Facilities :

1. One cross country pipeline from Numaligarh to Siliguri (654 Km) exists. The pipeline is owned by Oil India Limited (OIL). This is a 16” pipeline with the current pumping capacity of 1.721 MMTPA with one pumping station at Numaligarh. This pipeline handles MS/SKO/HSD.

D. New Facilities :

Adequacy of above existing product despatch facilities will be checked for the combined production of existing refinery and additional train and additional facilities to be recommended.

Augmentation of LPG dispatch facilities will consider dispatch through road transport only. No railway dispatch of LPG needs to be considered.

Facilities required for dispatch of new products which presently are not in existing product slate will be provided.

4.2.6.3 Offsite Storage Facilities:

1. Details of existing finished product storage facilities at the refinery provided by NRL and the same are listed in Attachment IV.

2. Storage of intermediate products for additional train will be dedicated.

3. LPG storage for existing refinery as well as additional train will be provided as mounded bullets. The existing spheres will be decommissioned.

4. Philosophy for storage of products: 10 days storage for products will be

considered at refinery. Re allocation of existing tanks service (for e.g. MS to HSD, etc.) may be considered if it leads to reduction in new tanks requirement.

5. 5 days storage for VGO & VR will be considered. All other intermediate products

storage will be considered for 3 days.

6. One additional manual Blending station will be added at the marketing terminal. 7. Facilities required for storage of new products which presently are not in existing

product line will be provided.

4.2.6.4 Utility facilities

1. Utility facilities for additional train will be independent from utility facilities of existing refinery except for CPP, whereby one spare GTG/HRSG available in the existing CPP will be brought in to continuous service. The GTG is a frame VI machine and the HRSG produces up to 120 TPH of HP steam. GTG fuel are Natural Gas/ Fuel Gas/ Naphtha/HSD whereas HRSG auxiliary fuels are natural Gas/Fuel Gas/ Naphtha/HSD/IFO.

2. CPP and HGU fuel to be considered as natural gas in new facility of additional




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train as well as existing GTG/HRSG. Natural gas LHV to be considered as 8000-8500 Kcal/Scm.

3. Present refinery’s raw water intake limit is 1200m3/hr from river. Existing refinery

draws 700 m3/hr. After installation of new refinery train, the additional untreated raw water requirement needs to be minimised. For this, water recycle schemes need to be considered.

4. New CPP will be considered for power generation for additional train. However,

one spare GTG/HRSG available in existing CPP will be utilised. Additionally, one VHP steam utility boiler of 110 TPH capacity will be provided to take care of HRSG down case.

5. Provision for township expansion to be kept in the capital cost estimate.

6. All the facilities for additional train need to be located within the vacant space available inside the existing overall plot plan of the refinery.

7. The study report should indicate project cost with an accuracy of +/-20%.

8. Crude pipeline lumpsum cost of Rs. 3000 Crores to be added to refinery cost. ROU to have provision for product pipeline.

9. No oxygenates dosing of gasoline with imported additives is to be considered for the study.

10. Configuration will consider 50 % BS-IV HSD and 50% BS-V HSD production.

11. Configuration will consider 100% BS-IV MS production. However, additional facilities required for producing upto 50% of additional train MS as BS-V MS in future, shall be identified and provision in the plot plan shall be kept for the same.

12. An order of magnitude reduction in capex in case of 5 MMTPA additional train capacity with the same configuration will be indicated by EIL in the report.

4.2.7 Exclusions

The following items are specifically excluded from the scope of current DFR.

Preparation of detailed engineering drawings, data sheets.

Environmental Impact Assessment/ Risk assessment studies.

Evaluation of existing refinery facilities.

Market Study.

Health checking and condition assessment of existing hardware.

4.2.8 Emission Norms

SOx emission from new refinery train will be limited to 330 Kg/hr.




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Attachment-I

Crude Assay for Arab Light




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Attachment-II Crude Assay for Arab Heavy

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

DFR on Refinery Capacity Expansion Project


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Attachment-III Table for Product Price

Products

Prices

5 years average price (Rs/MT)

3 yrs avg price (Rs/MT)

1 yr avg price (Rs/MT)

Net Price (Price with Excise Benefit)

Price without price benefit

60:40 Import: Export Parity

Full Export parity

Liquified Petroleum Gas (LPG)

40,024 40,024 40,024 35,816 45,057 53,946

Naphtha 33,626 33,626 33,626 33,626 38,607 44,996

Petrochemical Naphtha

33,626 33,626 33,626 33,626 38,607 44,996

Domestic Regular Motor Spirit, MS (BS-IV)

49,237 42,551 48,631 46,813 55,104 64,595

Export Motor Spirit, MS (BS-IV)

39,291 39,291 39,291 39,291 45,029 54,025

ATF 42,470 40,981 42,470 41,029 47,207 56,167

Kerosene 41,451 41,451 41,451 39,583 46,175 55,142

Domestic High Speed Diesel, HSD (BS-IV)

41,927 39,770 41,353 39,633 46,601 55,369

Domestic High Speed Diesel, HSD (BS-V)

42,350 40,194 41,777 40,057 47,024 55,792

Export High Speed Diesel, HSD (BS-IV)

40,619 40,619 40,619 40,619 45,274 53,073

Pet Coke (Fuel Grade)

6,000 6,000 6,000 6,000 6,000 6,000

Anode Grade Coke

13,098 11,902 13,098 13,098 11,902 13,098

Sulphur 4,992 4,992 4,992 4,992 6,430 7,104

Bitumen 34,543 34,543 34,543 34,543 31,711 34,552

Note1: Net price with excise benefit as indicated above shall be used for the basis of the study.




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Attachment –IV

Details of existing finished product storage facilities Tank details of OM&S Unit

Sl no

Tag no Roof Type Service Cond.

No of tanks

Nominal Cap, M3

Height, mts

Dia, mts

1 44-TT-FR-102 A/B/C Floating Roof Naphtha 3 16880 13.5 40

2 44-TT-CFR-103 A/B/C

CFR ATF 3 2530 10 18

3 40-TT-FR-104 A/B Floating Roof SKO 2 25900 14.4 48

4 44-TT-FR-105 A/B/C Floating Roof HSD 3 23000 14.5 45

5 44-TT-FR-104C Floating Roof HSD 1 25900 14.4 48

6 44-TT-FR-106 A/B/C Floating Roof IFO 3 1200 9.2 13

7 41-TT-CR-107 A/B Cone Roof VR 2 7925 12 29

8 41-TT-CR-108 A/B Cone Roof RCO 2 7860 12 29

9 41-TT-CR-109 A/B Cone Roof VD 2 12800 14 34

10 41-TT-CR-110 A/B Cone Roof CD 2 2800 10 19

11 41-TT-CR-113 A/B Cone Roof Wet Slops 2 300 6 8

12 41-TT-FR-114 A/B/C Cone Roof Dry Slops 3 3130 10 20

13 41-TT-CFR-115 A CFR H2U Feed 1 3850 14.5 20

14 41-TT-CFR-115 B CFR FLO 1 3850 14.5 20

15 41-TT-CFR-115 C CFR Naphtha 1 16880 13.5 40

16 41-TT-FR-117 A/B Floating Roof Isom/Refor 2 5000 12 25.5

17 41-TT-FR-118 A/B CFR MS 2 5000 13 25.5




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Tank details of NRMT

Sl no

Tag no Roof Type Service Cond.

No of tanks

Nominal Cap, M3

Height, mts

Dia, mts

1 45-TT-FR-001A Floating Roof MS/NAP 1 3730 13.5 20.0 2 45-TT-FR-001B Floating Roof MS/PYGA

S/NAP 1 3730 13.5 20.0

3 45-TT-FR-001C Floating Roof MS/NAP 1 3730 13.5 20 4 45-TT-FR-002 Floating Roof MS/NAP 1 3140 13.0 18.5 5 45-TT-FCR-

003A/B/C FCR ATF 3 3440 14.0 20.0

8 45-TT-FR-004A FR NAPHTHA

1 29210 14.0 55.0

9 45-TT-FR-004B/C FR MS/NAP 2 29210 14.0 55.0 11 45-TT-FR-005A/B/C FR HSD 3 27700 14.0 53.0 14 45-TT-FCR-006A FCR MS/MTBE 1 2410 13.5 16.0 15 45-TT-CR-006B/C CR HSD 2 2410 13.5 16.0 17 45-TT-FCR-

008A/B/C FCR SKO 3 3730 20.0 14.5




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Chapter 5

PROJECT LOCATION AND PLOT PLAN STUDIES




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5 PROJECT LOCATION AND PLOT PLAN STUDIES

5.1 Project Location

The existing refinery of NRL for a crude processing capacity of 3.0 MMTPA is located at Numaligarh, Dist. Golaghat, Assam. The independent parallel train for crude processing capacity of 6.0 MMTPA will also be located within the existing refinery premises.

5.2 Plot Plan Studies

Based on the plot plan studies carried out during TEFR, the overall plot plan for the new refinery train is attached as Annexure-1.




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Chapter 6 PROJECT DESCRIPTION




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6. PROJECT DESCRIPTION

6.1 Introduction

6.1.1 Description of existing facilities

Numaligarh Refinery Limited (NRL), a group company of Bharat Petroleum Corporation Limited operates a 3.0 MMTPA refinery which is located at Numaligarh, Dist. Golaghat, Assam. The refinery is primarily designed to process 100% Assam mix crude. The refinery is producing MS and HSD primarily conforming to Euro III/IV specifications by processing of Assam Mix crude.

The overall refinery configuration at Numaligarh refinery consists of Crude and Vacuum Distillation Unit; Full conversion Hydrocracker unit; Delayed Coker unit; MS block comprising Naphtha Hydrotreating unit, Semi-Regenerative Reformer and Isomerization unit; and other associated facilities such as Hydrogen Generation Unit (HGU), Sulfur Recovery Unit, Sour Water Stripper (SWS) etc. Supporting process units include a Fuel gas treating unit and an Amine Regeneration Unit. The list of existing units along with current capacity & respective licensor is as per Table 6.1.1.1 below

Table 6.1.1.1: Existing Unit Capacity

Unit Design Capacity (MMTPA) Licensor

CDU/VDU 3.0 EIL

NHT/ NSU 0.271/0.16 Axens

CRU 0.168 Axens

ISOM 0.0555 Axens

HCU 1.45 Chevron

DCU 0.306 EIL

CCU 0.115 EIL

HGU 0.0486 HALDOR TOPSOE

SRU 19.3 TPD EIL

SWS 20.3 m3/hr EIL

ARU 23.2 TPH Rich Amine EIL

FGSU 6.514 TPH EIL

New NSU 160 KTPA EIL

Wax Plant 0.05 EIL & AXENS




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6.1.2 Existing Refinery Feed and Product slate

The feed for the existing 3 MMTPA refinery is Assam mix crude as tabulated below in table No. 6. 1.2.1

Table 6.1.2.1: Existing Feed for the Refinery

Feed Design Capacity (MMTPA)

Assam Crude 3

The product slate of the refinery consists of Regular Gasoline meeting Euro-III and Euro-IV

specifications, ATF, kerosene, and diesel fuels meeting Euro-III and Euro-IV specifications. The Delayed Coker Unit produces petroleum coke, a solid by-product that is sold as anode grade coke. Sulphur is also a product from the Oxygen Enrichment process based Sulphur recovery unit. The existing product slate from the refinery is depicted in table 6.1.2.2 below.

Table 6.1.2.2: Design product slate of existing refinery

Products Design Capacity (MMTPA)

Liquefied Petroleum Gas (LPG) 57,000

Naphtha Domestic sales 1,28,000

Petrochemical Naphtha Export 1,60,000

Regular Gasoline (Euro III) Domestic 2,07,000

Regular Gasoline (Euro IV) Domestic 48,000

ATF Domestic 60,000

Kerosene Domestic 2,10,000

Diesel, (Euro III) Domestic 13,56,000

Diesel, (Euro IV) Domestic 3,50,000

Sulfur 4,500

Coke 80,000

6.2 Project Configuration

6.2.1 Unit Facilities NRL intends to install a parallel new train for crude processing capacity of 6.0 MMTPA. MS

from the new processing train should meet BS-IV grade. HSD from the new processing train shall meet BS-IV and BS-V grade and shall be produced in a 50:50 ratio.

The feasibility study is based on the following crude mix. Design Case: 30% Arab Light-70% Arab Heavy




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6.2.2 Processing Options Considered for Expansion Study

The following processing options have been considered for Case A

Primary processing Option

- 6.0 MMTPA of crude to CDU/VDU

Light ends Processing options

- Naphtha Hydrotreater/Naphtha Isomerisation Units (NHT/ISOM)

Secondary Processing options

- Full Conversion Hydrocracker Unit (HCU)

Residue Upgradation options

- Solvent Deasphalting Unit (SDA) followed by Delayed Coking Unit (DCU)

- Bitumen Blowing Unit (BBU) .

6.2.3 Analysis of Case A

This section analyses the results of case A

Schematic diagram

The schematic diagram for case A is given in figure 6.1.The Block flow diagram for the base case is attached herewith as attachment- I.




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Figure 6.1: Schematic diagram

Unit Capacities

The unit capacities is given in Table no. 6.2.3.1

Table 6.2.3.1: Unit capacities

Unit Capacities in MMTPA Design Case (30 AL:70 AH)

CDU /VDU/NSU 6 NHT/CCR/ISOM 0.97/0.612/0.348 DHT 2.896 HCU 1.988 DCU 1.144 SDA 0.755 BBU 0.20 SRU(TPD) (Includes SWS single & two stages, ARU & TGTU)

420

HGU (KTPA) 78




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Product Yield

The product yields is given in Table No. 6.2.3.2

Table 6.2.3.2: Product yields

Feed Purchase (MMTPA) Design Case (30 AL:70 AH) Arab Light 1.8 Arab Heavy 4.2 Natural Gas 0.493 Sr Kero from Existing Refinery CDU

0.114

Sr LGO from Existing Refinery CDU

0.557

Product Sales (MMTPA)

LPG 0.258 BS IV domestic Gasoline 0.886 BS IV Export gasoline 0.114

Light Distillate 1.258(17.56%)

ATF 0.053 Euro-IV domestic HSD 4.031 Euro-V domestic HSD 0.092 Euro-IV Export HSD 0.385

Middle Distillate 4.561(63.67%)

Bitumen 0.2 Pet Coke (High sulfur) 0.364

Heavy distillate 0.564 (7.87%)

Sulfur (TPD) 368

Fuel and Loss 0.657 (9.17 %)

The graphical representation of the product yields is provided in figure 6.2 below.




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Figure 6.2: Graphical representation for product yields

17.56

63.87

7.87

1.739.17

Product yields (%)

Light Distillate

Middle Distillate

Heavy Distillate

Sulphur

Fuel & Loss




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6.3 Process Description

Introduction

A brief process description along with a flow schematic for each of the process units

envisaged as part of the shortlisted refinery configurations are provided in this section.

1. Crude/Vacuum Distillation Unit with naphtha stabilizer.

2. Naphtha Hydrotreating Unit

3. Isomerisation Unit

4. Continuous Catalytic Regeneration reforming Unit.

5. Diesel Hydrotreating Unit

6. Full Conversion Hydrocracker Unit

7. Delayed Coker Unit

8. Solvent Deasphalting Unit

9. Bitumen Blowing Unit

10. LPG Treating Unit

11. Fuel gas treating unit

12. Hydrogen Generation Unit

13. Sour Water Stripper

14. Amine Regeneration Unit

15. Sulphur Recovery Unit (With Tail Gas Treatment Unit)

Schematic Flow Diagrams for all the above process units are attached herewith

6.3.1 Crude/Vacuum Distillation Unit

Crude / Vacuum Distillation Unit With Naphtha Stabiliser

Crude Charge and Preheat Train-I

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

Desalter

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




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Crude Preheat Train-II and Preflash

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

Crude Preheat Train-III

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

Crude Heater

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

Crude Distillation Column

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

Crude Column Overhead Circuit

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

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

Light/Heavy Naphtha Section

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

Kerosene Section

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

Light Gas Oil Section

LGO product and LGO CR stream is drawn as a single stream from crude column. One stream as LGO product flows to the LGO Stripper under LGO stripper level control where it is




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stripped using MP steam under flow control and the stripped vapours are returned back to the Crude Column.

Heavy Gas Oil Section

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

Reduced Crude Oil Section

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

Crude Column Circulating Refluxes

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

LGO CR:

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

HGO CR:

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

Product Rundown Section

Light/Heavy Naphtha Product Circuit

Light/heavy naphtha from light/heavy naphtha stripper bottoms are pumped by Light/Heavy naphtha Product pumps to Naphtha Air cooler followed by naphtha Trim Coolers after heat recovery in preheat train. The cold light naphtha stream is routed to gasoline pool and cooled heavy naphtha product ex-product cooler is finally routed to naphtha/diesel pool.

Kero Product Circuit

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

LGO Product Circuit

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




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HGO Product Circuit

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

RCO Product Circuit

Normally, Reduced Crude Oil (Crude Column residue, RCO) from Crude Column is pumped to vacuum unit without any cooling.

Naphtha Stabilizer

Naphtha Stabiliser Column

The unstabilised naphtha consisting of all the fuel gas, LPG and Naphtha components is pumped to Naphtha stabiliser column after preheating in the stabiliser feed/bottom exchanger. The overhead products are partially condensed in the Stabiliser Overhead Condenser. Fuel gas and LPG are withdrawn from the overhead circuit. Fuel gas is routed to Fuel Gas ATU and LPG is routed to LPG Treater. Stabilser column is a reboiled column using CDU hot stream as reboiling medium. Stabilised Naphtha product from Stabiliser Column bottom is pumped in Stabilised Naphtha PDT pumps and routed to NHT Unit. Stabilised Naphtha is further cooled in the exchanger to required rundown temperature before routing the same to the storage.

Vacuum Distillation Unit

Vacuum Heater

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

Vacuum Distillation Column

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

Stripping section

Documents

DETAILED FEASIBILITY REPORT FOR NUMALIGARH ...environmentclearance.nic.in/writereaddata/Online/TOR/10...DETAILED FEASIBILITY REPORT FOR NUMALIGARH REFINERY EXPANSION PROJECT (DRAFT)