DETAILED FEASIBILITY REPORT FOR NUMALIGARH...

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

Document No.

A310-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A310-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A310-RP-0241-0001

Rev. No. A

of 125

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.



Document No.

A310-RP-0241-0001

Rev. No. A

of 125

Chapter 1

EXECUTIVE SUMMARY


DFR on Numaligarh Refinery Expansion Project


Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

- 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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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%




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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%




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

CHAPTER 2 INTRODUCTION




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.

.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

CHAPTER 3 SCOPE OF THE DFR




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 4

DESIGN BASIS




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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)




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125


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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125


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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Attachment-I

Crude Assay for Arab Light




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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


Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 5

PROJECT LOCATION AND PLOT PLAN STUDIES




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 6 PROJECT DESCRIPTION




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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


0.557


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






Sulfur (TPD) 368

Fuel and Loss 0.657 (9.17 %)

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Overhead Circuit:

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

Vacuum Diesel Section:

Vacuum Diesel is drawn and pumped by Vacuum Diesel Product+CR+IR Pump and is divided into 2 streams, namely, Vacuum Diesel IR, Vacuum Diesel CR+Product. Vacuum Diesel IR is returned back under flow control to the Vacuum Column. The product stream is cooled in the Vacuum Diesel Product + CR Trim Cooler. The vacuum diesel CR stream is reformed to vacuum column, whereas vacuum diesel product is sent to storage. Provision for routing hot vacuum diesel stream to DHT directly is also provided.

Gas Oil Section:

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

Light Vacuum Gas Oil Section (LVGO):

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

Heavy Vacuum Gas Oil section (HVGO):

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

Wash section:

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

Vacuum Residue Section (VR):

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Product Rundown Section

Hotwell vacuum slop oil:

Hotwell vacuum slop oil from Hotwell is pumped by Hotwell Slop Oil Pumps through a coalescer and routed to distillate hydrotreater unit header. Sour water from coalescer is routed to sour water rundown line.

Vacuum diesel Product:

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

LVGO product:

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

HVGO product:

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

Slop distillate product:

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

Vacuum residue product:

(Vacuum Residue + Quench) from Vacuum Column bottom is pumped by VR + Quench Pump to crude preheat train for heat recovery in Crude/VR + Quench exchangers. The VR + Quench stream is then split into two streams. One stream as VR quench is returned back to the Vacuum Column and other stream VR product is routed to Delayed Coker Unit after heat recovery. VR product is further cooled to required rundown temperature before routed to storage.

Tempered Water System (TW)

The cooling of the high pour point products like Vacuum residue & VGO is done by tempered water to prevent exchanger congealing and to reduce exchanger maintenance. Tempered




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

water is pumped from Tempered Water Drum by Tempered Water Pumps to VR/TW cooler and VGO/TW cooler.

Steam Generation Section

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

Blowdown

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

Chemical Dosing Facility

This system caters to CDU/VDU units.

Demulsifier

Demulsifier chemical is unloaded into demulsifier drums. The drum is provided with a mixer which can be used for preparation of desired concentration levels of the chemical.

Demulsifier injection is done at the inlet of First stage desalter.

Filming Amine

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

Neutralising Amine

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

Caustic Solution

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

6.3.2 Naphtha Hydrotreating Unit (NHT)

Naphtha feed to NHT passes through a surge drum and a charge pump. It is then combined with a H2-rich gas stream from the recycle gas compressor. The combined feed enters the




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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

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

Hydrocarbon liquid from the receiver is sent back to the stripper as total reflux. Hydrotreated sweet naphtha from stripper bottom is cooled in stripper feed/bottom exchanger and then sent to naphtha/gasoline pool.

6.3.3 Naphtha Isomerisation Unit

Application: The par-isom process is an innovative application using high- performance non chlorided-alumina catalysts for light naphtha isomerisation. The process uses PI-242 catalyst, which approaches the activity of chloride alumina catalysts without requiring organic chloride injection. The catalyst is regenerable and is sulphur and water tolerant. Description: The fresh C5 /C6 feed is combined with make-up and re-cycle hydrogen which is directed to a charge heater, where the reactants are heated to reaction temperature .The heated combined feed is then sent to the reactor. Either one or two reactors can be used in series, depending on the specific application. The reactor effluent is cooled and sent to a product separator where the recycle hydrogen is separated from the other products. Recovered recycle hydrogen is directed to the recycle compressor and back to the reactor section. Liquid product is sent to a stabilizer column where light ends and any dissolved hydrogen are removed. The stabilized isomerate product can be sent directly to gasoline blending.

6.3.4 Continuous Catalyst Regeneration Reforming Unit (CCR)

The Catalytic Reforming Unit processes the heavy naphtha stream to make it more suitable for the production of motor gasoline. The nominal design charge capacity of this unit is 0.631 MMTPA of heavy naphtha.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

The reforming process involves chemically rearranging the hydrocarbon molecules to produce higher-octane materials. [The octane number is a key measure of motor gasoline performance. The Catalytic Reforming Unit can produce reformate of up to 102 research octane number (RON-Clear).] Hydrogen gas is produced as a byproduct of reforming, and is used as feed to the Naphtha Hydrotreater Unit, Diesel Hydrotreating Unit, Hydrocracker Unit and Isomerization Unit. The heavy naphtha feed stream is mixed with recycle hydrogen, preheated by exchange with reactor effluent, heated to reaction temperature in the charge heater and sent to the first of a series of three to four reactors. Each reactor is preceded by a gas-fired feed heater to maintain a constant inlet temperature profile for the individual reactors (as reforming reactions that take place in the reactors are predominantly endothermic). Effluent from the last reactor is heat exchanged with the combined feed, condensed in the product trim cooler and sent to the separator. The reformed naphtha product (reformate) is separated from the by-product hydrogen. A portion of the hydrogen is compressed and recycled to be mixed with heavy naphtha feed material. The remaining hydrogen is compressed for use in other refinery processing units. The reformate product is fractionated in the debutanizer for separation of light ends, which are sent to the Gas Concentration Plant for recovery. The reformate liquid product is sent to storage, for use in motor gasoline blending.

The Catalytic Reforming Unit reactor catalyst is continuously regenerated in the Catalytic Reforming Unit Catalyst Regenerator. The regeneration section of the reformer provides a continual stream of clean coke-free active catalyst that is returned back to the reactors. Continuous circulation of regenerated catalyst helps maintain optimum catalyst performance at high severity conditions for long on-stream periods of reforming operation.

Catalyst regeneration takes place in dedicated equipment and uses nitrogen, air, and perchloroethylene as regenerating agents. The Catalyst Regenerator performs two principal functions - solid catalyst regeneration and circulation. Spent catalyst from the final Catalytic Reforming Unit reactor vessel is conveyed to the Catalyst Regenerator, where it is regenerated in four steps: 1) coke burning with oxygen, 2) oxychlorination with oxygen and chloride, 3) catalyst drying with air/nitrogen, and 4) reduction of catalyst metals to "reduced" oxidation states. Exiting the Catalyst Regenerator, the regenerated catalyst is conveyed back into the first Catalytic Reforming Unit reactor.

Small quantities of hydrochloric acid and chlorine are generated in the Catalyst Regenerator. The vent gas from the Catalyst Regenerator is scrubbed in two stages with caustic solution and water in the Vent Gas Wash Tower for removal of acid gases, in particular hydrochloric acid. From the Wash Tower, the cleaned vent gas is discharged to the atmosphere.

6.3.5 Diesel Hydrotreating Unit (DHT)

A blend of straight run and cracked distillate materials are filtered in a feed filter and fed to a surge drum. From this drum, the feed is pumped under flow control and is mixed with make-up/recycle hydrogen streams. The combined feed is then preheated in a reactor feed/effluent




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

exchanger and then brought up to the required reaction temperature in a charge heater. The heated feed is first routed to the HDS reactor that operates down flow, and includes three beds in order to limit the temperature increase inside the reactor. Cold quenches are injected at inter bed sections. The HDS reactor effluent is quenched and sent to the HDT reactor that operates in down flow and has two beds. The HDT reactor effluent is used to exchange heat first with the stripper feed in the stripper feed preheater and then with the reactor feed in the reactor feed/effluent exchanger. Final cooling is achieved first in reactor effluent air condenser and then in trim condenser. To avoid ammonium salt deposits and the risk of corrosion, wash water is injected at the inlet of reactor effluent air cooler. The wash water is a mixture of recycled water from cold HP separator and stripped water from SWS. Trim cooler effluent is collected in the cold HP separator, which is a V-L-L separator. The sour water is partly recycled back as wash water, the hydrocarbon liquid is sent to the cold MP separator and the hydrocarbon vapor goes to HP amine absorber knock out drum. At the amine absorber, H2S is removed by amine wash. The sweetened gas is recycled back to the recycle gas compressor at the reaction section inlet. A stream of hydrogen-rich gas from battery limits through makeup gas compressor meets the recycle gas stream. The cold MP separator is also a V-L-L separator. Vapor is sent to the stripper overhead line, sour water withdrawn from the boot is routed to SWS and the hydrocarbon liquid is routed to the stripper. The stripper is steam stripped to obtain hydrotreated diesel with correct flash point. The overhead vapors are partly condensed in an air cooler followed by a trim cooler. The stripper reflux drum is a 3-stage separator. Sour water is sent to SWS, vapor is routed to LP amine absorber and liquid hydrocarbon is partly sent back to the stripper as reflux. The stripper bottom is cooled with stripper feed in a feed/bottom exchanger. It is then cooled in air/trim coolers before being routed to the storage. Net liquid from stripper reflux drum is sent to a stabilizer to remove any hydrogen sulfide and to adjust the butane content in order to minimize the RVP. The stabilizer has a steam reboiler. Vapor from the stabilizer is sent to LP amine absorber. Stabilized naphtha from stabilizer bottom is heat exchanged with stabilizer feed in a feed/bottom exchanger. It is then cooled in air/trim coolers before being routed to the storage.

6.3.6 Full Conversion Hydrocracker Unit

A Full Conversion Hydrocracker Unit, HCU is proposed to treat the VGO from the crude units. The Hydrocracker unit shall process SR VGO feedstock to produce distillates of required product specifications. The unit is described as follows. The feed is taken from the battery limits, preheated by sequential heat exchange with feed/ diesel exchangers to reduce the feed viscosity for effective filtration. The preheated feed is filtered in the feed filters and is fed to the first stage feed surge drum. From this drum, feed is pumped upto the reactor loop pressure and is mixed with make-up/recycle gas. The combined feed stream is heated by the first stage reactor feed/ effluent exchangers and brought up to reaction temperature by the reaction furnace. The heated feed is first routed to




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

the first stage reactor. In the first stage reactors the heated feed is hydrotreated and partially converted to products. Cold recycle gas quench is provided in between the reactor beds to control the amount of temperature rise and the rate of reaction. The first-stage reactor effluent consists of light vaporized hydrocarbons, distillate oils, heavy unconverted oil and excess hydrogen which is not consumed in the first reaction stage. The first stage reactor effluent is cooled by heat exchange with a series of heat exchangers which is used to preheat the feed and then used to produce steam.

The first stage reactor effluent is then flashed in the hot high pressure separator (HHPS), where the effluent vapour is separated from the liquid stage. The HHPS liquid is either let down by a high pressure let down control valve or sent to the first stage hot high pressure power recovery turbine which is used to drive the first stage reactor feed pump. The first stage HHPS liquid is combined with the second-stage HHPS liquid and sent to the hot low pressure separator (HLPS) where most of the dissolved gases are flashed off from the liquid before being sent to the fractionation section. The hydrogen rich HHPS is used to heat the recycle gas and it is cooled in the reactor effluent air cooler before routing it to the Cold high pressure separator (CHPS). Wash water is injected at the inlet of the air cooler to prevent the deposition of ammonium bisulfide salts in the air cooler tubes. The hydrogen rich gas from HLPS is mixed with the CHPS liquid at the downstream of CHPS and is routed to the Cold low pressure separator (CLPS). The hydrogen rich gas from CHPS goes to the HP amine absorber knock out drum and from there it is routed to the HP amine absorber. In the HP amine absorber, the H2S is removed from the gas using amine solution and the sweetened gas is routed to the inlet of the recycle gas compressor. The make-up hydrogen from the makeup gas compressor combines with the recycle gas at the inlet of recycle gas compressor. The Vapours from CLPS are routed to LP amine absorber and the treated gas is routed to off plot hydrogen recovery unit. The sour water from both CHPS and CLPS are routed to the sour water break tank in the unit. The hydrocarbon liquid from CHPS is let down in pressure by using either let down valves or by using the PRT and is mixed with the HLPS vapour and is routed to the CLPS. The CLPS liquid is then fed to the product stripper to remove the H2S. The product stripper overhead is cooled in the product stripper overhead air cooler before sending to the product stripper reflux drum. The reflux drum gases and part of the condensed liquid are sent to the deethanizer overhead condenser in the light ends recovery section. The remainder of the liquid returns to the product stripper as reflux by the product stripper reflux pumps. The sour water from the reflux drum is sent to the sour water stripper unit. The product stripper bottom is heated by a sequential heat exchange with reactor effluent and finally in the fractionator feed furnace before it is entering to the fractionator. Overhead from the fractionator is totally condensed in the fractionator overhead air cooler and the condensed liquid is then sent to the fractionator overhead accumulation drum. Fractionator bottom product is pumped by the fractionator bottoms pumps and cooled. The fractionator bottoms product can be sent to the second-stage feed surge drum or to the offplot after further cooling. The cracked products from the reaction section are recovered in the fractionation section and most of the unconverted feed is sent to the second-stage reactor for cracking into light products.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

The fractionator bottom is cooled by heat exchange through a series of exchangers and the partially cooled fractionator bottoms flows into the second stage feed surge drum from which it is pumped up to reactor loop pressure by the second-stage reactor feed-pumps. The oil feed is combined with a mixture of make-up hydrogen and hydrogen-rich recycle gas and the combined oil and gas is heated in the exchangers and brought upto the reaction temperature by second stage reaction furnace. The second stage reactor effluent is cooled by heat exchange with other hydrocarbon streams and then flashed in the second stage HHPS. The hydrogen rich gas from the second stage HHPS will combine with hydrogen rich gas of first stage HHPS and the hydrocarbon liquid of second stage HHPS will combine with hydrocarbon liquid of first stage HHPS. The light streams from the stripper reflux drum is sent through the de ethanizer overhead cooler to the de ethanizer reflux drum. The vapour from the de ethanizer reflux drum is fed to the bottom of the sponge absorber and the liquid from the de ethanizer reflux drum is pumped to the top of the de ethanizer. The de ethanizer bottoms products is sent to the debutanizer. The debutanizer stabilizes naphtha and separates LPG as the overhead liquid product. The debutanizer overhead vapor is totally condensed in the debutanizer overhead cooler and then sent to the debutanizer reflux drum. The debutanizer bottoms product is sent to the naphtha splitter. The naphtha splitter overhead is totally condensed by an air cooler exchanger before being sent to the reflux drum. The light naphtha from the reflux drum is sent to a trim cooler before going to offplot. Some of the light naphtha is pumped back to the stripper as reflux. A portion of the heavy naphtha is using as sponge oil. The heavy naphtha product from the unit is routed to the offplot storage via the heavy naphtha product cooler. The LPG after caustic wash flows through the water washer and through LPG coalescer and then sent to the offplot storage.

6.3.7 Delayed Coker Unit

The feed to Delayed Coker unit is vacuum residue from vacuum column . The feed is received in the coker feed surge drum and pumped further by coker feed pumps. Coker feed is successively preheated against product/ pump around stream and then flow into the bottom of the coker fractionator. The feed is joined by the bottom liquid of the fractionator i.e. recycle oil. The introduction of the relatively cool coker feed into the fractionator bottom reduces the tendency for coke formation in the bottoms. The combined coker feed and heavy recycle liquid are pumped from coker fractionator to coker heaters. The prime function of the heaters is to quickly heat the feed to the required reaction temperature while avoiding premature coke formation in the heater tubes. The heated liquid is fed to coke drum. In the coke drum, the hot feed cracks to form coke and cracked products. An anti foam chemical is injected into the filling coke drum when it is nearly full to prevent foam carry over to the coker fractionator. The cracked product leaves from the top of the coke drum as a vapor stream to coker fractionator. Hot coker drum vapor effluent is quenched with heavy coker gas oil to stop the cracking and polymerization reactions and to thereby prevent coke formation in the vapor line to the coker fractionator. The coker fractionator separates the coke drum effluent vapor into light naphtha, heavy naphtha, light coker gas oil, heavy coker gas oil, Coker Fuel Oil and a heavy recycle stream.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

The quenched coke drum effluent vapor flows upward through the baffle trays and bubble cap trays, with cooling accomplished by contact with down flowing reflux liquid. Heavy recycled liquid is condensed and overflow the bottom tray to mix with fresh coker feed in the tower bottom. Coker fuel oil is drawn as product, which is pumped to storage after, cooled down by generating MP steam and by circulating LCGO product. All HCGO draws are taken from the same draw tray. The reflux and HCGO pump around are pumped by common pump. The reflux returns directly to the tower and balance HCGO is used as pump around stream and to quench the reactor (coker drum) over head line which is routed to fractionator. The draw off HCGO product from the coker fractionator is flow to the HCGO stripper by gravity flow. It is steam stripped and the vapor is returned to the fractionator. The stripped HCGO product is pumped and is cooled after exchanging heat with feed, generating LP steam and preheating BFW. The cooled HCGO routed to storage. LCGO is withdrawn and split into two streams. The product flows to Light Gas oil stripper and stripped by MP steam. The stripped LCGO is pumped and cooled by rich sponge oil, air cooler and followed by cooling water exchanger. The LCGO product split and part of it routed to battery limit and balance is pumped to higher pressure to use as sponge oil in the sponge absorber. The second stream of LCGO is used as pump around stream. It is pumped and after exchanging heat with feed, generating MP steam it returns back to fractionator column. Overhead vapor from fractionator is cooled and partially condensed in air cooler followed by trim cooler. It enters the fractionator overhead receiver where vapor, hydrocarbon liquid and condensed water are separated. The vapor and condensed HC sent to vapor recovery section and sour water pumped to SWS unit. The vapor recovery section separates the combined vapor and liquid overhead product from the coker fractionator into fuel gas, LPG and naphtha. The wet gases from fractionator are compressed in wet gas compressor, which is two-stage steam turbine driven machine. The gases from this section enter the de ethanizer (primary absorber column). In this column LPG is absorbed from gases. Primary absorber over head vapors from the top section of the absorber flow to sponge absorber where lean sponge oil is fed to absorb the LPG and also reduce the loss of naphtha in fuel gas. The fuel gas from sponge oil absorber top is routed to Gas plant for further amine treatment. The hydrocarbon liquid from wet gas compressor section flows as feed to Primary absorber. In this section ethane and lighter components is stripped from LPG and Naphtha. Dethanizer bottom flows by its own pressure to debutanizer column. The column has thermosyphon reboiler in which heat is provided by LCGO PA stream. The LPG from debutaniser top is further cooled and is routed to LPG amine contactor and amine coalesecer to remove H2S in LPG. The treated LPG is further routed to LPG treating unit to meet corrosion spec etc. Debutanizer bottom i.e. coker naphtha is pumped to offsite after cooling by air cooler followed by trim cooler. The coker naphtha is routed to NHT unit as well as to storage. After completion of drum filling cycle, the coker heater effluent is diverted to the other coke drum by means of inlet switch valve, Steam is injected into the coke filled drum and the resultant vapor (mostly steam) are routed to blow down tower. The blow down tower cools




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

and condensed the steam and hydrocarbon vapors evolved from the coker drum. It is a tray column in which incoming vapors are contacted with warm stream of recirculating quench oil to condense the high boiling hydrocarbon. The condensed hydrocarbon liquid is sent to wet slop tanks and also part of it is used as recirculating quench oil. Non condensable vapor from the blow down over head separator goes to flare. The green coke is removed from coke drum by hydraulics decoking using coke cutting pumps. The green coke along with water used in the cutting process drop into the coke pit where the water drains away through the maze. The drain coke is lifted and after coke size filtering it is sent for OSBL transportation.

Coke Handling System

Coke Feeding and Transport

The petroleum coke on formation in coke drums of delayed coker unit will be cut from the coke drum by coke cutting system using high pressure water jet. Cut coke and water will be directed by chute to discharge coke to a coke pad. The coke will be picked up by a heavy duty grab type bridge crane or pay loaders and fed to a coke hopper fitted with a grizzly having openings of suitable size to protect feeder breaker from oversize lumps. The feeder breaker will be located below the coke hopper. Feeder breaker will feed the coke (lump size –75 mm approx.) to a troughed belt conveyor system for onward transportation to Stockyard. An electronic weigh scale will register coal throughput to stockpile.The conveyor system will be provided with suitable covered gallery having walkways on both sides.

6.3.8 Solvent Deasphalting Unit

In SDA process deashphalted oil (DAO) product is extracted from vacuum residue with an LPG solvent. DAO is further processed in hydrocracker unit. The asphalt product is further routed to storage. Vacuum residue (VR) is routed to feed surge drum at a temperature of 200 C. The feed pump boosts the VR t oa pressure sufficient to discharge it to feed/asphaltene exchanger and on to asphaltene separator. The vacuum residue is mixed with a small volume of solvent to lower the viscosity before being cooled in the feed/asphaltene exchanger. Then the resid is mixed with additional solvent in the solvent/feed static mixer prior to entering the top of the distributor of the Asphaltene separator. The asphatene separator operates at a pressure of 46 kg/cm2g and at temperature of about 55 ~ 70 C.Asphaltenes are insoluble in the solvent and hence drop out of the separator. This asphaltene along with the entrained solvent is preheated before entering Asphaltene flash drum where much of the entrained solvent is flashed from asphaltene product. The lighter DAO product is soluble in the solvent. This DAO/solvent solution, containing the majority of the solvent, exists the top Asphaltene separator as rich solvent. The DAO/solvent solution is heated to supercritical conditions by exchanging heat with recovered lean solvent and also with hot oil from closed loop hot oil system. The heated rich solvent enters the DAO separator. The recovered supercritical solvent leaves the DAO




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

separator as lean solvent. The DAO/solvent solution is with drawn from the separator before entering the DAO flash drum, where much of the entrained solvent is flashed from DAO product.

DAO/solvent from flash drum is fed to the DAO stripper where the remaining solvent is tripped by using superheated steam. DAO product is with drawn from the bottom of the DAO stripper, cooled before routed to storage or hydrocracker unit.

6.3.9 Bitumen Blowing Unit

The purpose of Bitumen blowing unit is to convert vacuum residue to bitumen which are used in road construction etc. Feed to BBU, vacuum residue from VDU, is heated upto the reaction temperature in the charge heater. The hot feed, under flow control, goes to the bitumen blowing drum. Air from air compressor is blown under flow control into the contents of the drum. Blown vapors are quenched in the top section of the bitumen blowing drum using BFW and LP steam to remove the exothermic reaction heat. The quenched vapors go to the wash column. The washed vapors are sent to charge heater.

The circulating gas oil stream is pumped by wash column bottoms pump. A bleed stream of this cooled blown distillate is sent to storage and the remaining portion of the cooled liquid is pumped to the top of the wash column. Hot bitumen product from the bottom of the bitumen blowing drums flows to the surge drum. From here hot bitumen is pumped by bitumen pumps to bitumen product cooler. Product bitumen is cooled in bitumen cooler with generation of LP steam. The cooled bitumen product is routed to storage.

6.3.10 LPG Treating Unit

LPG Amine Treater

Sour LPG is routed to LPG Amine Absorber along with 40wt% MDEA solution for bulk H2S removal. Lean amine from Amine Regeneration Unit is routed to LPG Amine Absorption section. Lean Amine is split into two streams. About 20% of amine is mixed with sour LPG in LPG-Lean Amine (static mixer)’ There is approximately 3-5 deg C rise in temperature of mixed stream coming out of the static mixer due to heat of absorption. The mixed stream is thus cooled in LPG amine cooler to 40 Deg.C and then fed to LPG amine absorber. In the static mixer, MDEA reacts with the above impurities to form amino salts, which go along with rich amine from the column bottom. Balance 80% of the Amine is routed to column top. LPG rises from column bottom to top through amine, which forms the dispersed stage and is routed to Amine settler drum. Any carryover of amine from the column settles down in this vessel. From Amine settler drum, treated LPG is routed to Caustic wash section. An Amine sump is also provided where the amine drain from LPG AAU equipment are collected.

Caustic Wash Section

The caustic wash is based on Continuous Film Contactor (CFC) technology. Initially, fresh caustic solution at ambient temperature is charged into the CFC separator through the CFC caustic wash columns. After taking about 50% level in the CFC separators, the caustic




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

solution is circulated within the system by using caustic circulation pumps for specified time to ensure proper wetting of the fibres, which are provided in the caustic wash columns. LPG, pre-washed by amine absorption located in the upstream proceeds through LPG filters to remove solids larger than 300 microns. The LPG stream is then fed to the top of the wash column, where it contacts the circulated NaOH solution. The caustic solution flows downward, adhering to the fibres, until it enters the aqueous stage where it disengages from the fibres. The LPG flows co-currently with the caustic in the spaces between the fibres and disengages upon entering into the hydrocarbon stage in the CFC separator. The CFC separator system would be single stage or two stage depending upon the feed quality.

Caustic Regeneration Section

In the Regeneration column rich caustic solution is contacted with dry air, which is dispersed through a distributor located at the bottom of the column. Dry compressed air from air compressor supplies oxidation air. Both caustic solution and air flow co-currently in upward direction inside the Regenerator. In contact with air, sodium sulfide is converted to sodium thiosulphate and sodium hydroxide, Sodium mercaptides are converted to disulfide oil (DSO) in presence of water and catalyst .Catalyst in liquid form is added to the system once in a day through catalyst addition vessel. A slip stream of the circulated solvent entering DSO Extraction column is fed intermittently to the regeneration Column. The solvent acts as de-emulsifier in the Regeneration Column, Mixture of dry air, aqueous caustic solution and Naphtha flow upwards through perforated plate and then to chimney tray and caustic solution overflows. In this process vapour disengages liquid at the top of Regeneration Column, and off gas goes by pressure control through PV/PIC. The off gas is diluted with Fuel gas and sent to nearby furnace/heater via off gas Knockout drum .The liquid stream from chimney tray is fed to top of the DSO extraction column where it contacts with the main stream of fresh solvent (Hydrotreated Naphtha) and the recycled solvent. Fresh solvent is introduced into the column on flow control. The solvent is also recycled via pump and introduced at the top of DSO extraction column. In this process, the recycled Naphtha mixes with caustic and enters the DSO extraction column top. A stream of solvent and DSO is discharged to B/L.

The combined caustic solution and Naphtha travel down co-currently in the contactor and extracts DSO into solvent stage. The main stream of regenerated caustic is pumped by caustic recirculation pump via Filter to caustic wash column .The purge aqueous caustic stream is taken out from the bottom of solvent separator and sent to spent caustic tank by level control. The purge caustic stream would be needed to maintain the sodium thiosulphate level in the regenerated caustic. To compensate for the loss of caustic a fresh 20 wt% caustic solution is added to the circulated regenerated caustic stream through pump into the Caustic wash column.

6.3.11 Fuel Gas Treating Unit

The basic purpose of the unit is to remove H2S from fuel gas. Sour fuel gas generated in various units is combined and routed to sour fuel gas knock out drum. Liquid particles in the fuel gas are separated in this drum. From the drum, the gases are routed to the bottom of the fuel gas amine absorber.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Lean amine from ARU is introduced on the top the absorber. H2S from the sour gas gets absorbed in to the lean amine. The rich amine flows out under level control to ARU for regeneration. From the top of the absorber, the sweetened fuel gas under absorber pressure control is passed to sweet fuel gas separator, where any amine entrained in the gas is trapped and sweet fuel gas is routed to fuel gas system. Liquid collected in the sweet fuel gas separator is periodically drained to the amine sump. Rich amine from column bottom is routed to ARU for regeneration.

6.3.12 Hydrogen Generation Unit

The Hydrogen Generation Unit design is based on catalytic reforming and pressure swing adsorption (PSA) system to produce 99.9 mole% pure hydrogen gas.

Hydrogen is produced by steam reforming of Natural Gas.NG after mixing with recycled hydrogen and superheated steam enters the reformer furnace. Superheated steam is again added at the outlet of pre-reformer to adjust the steam-carbon ratio, and the mixture is heated. The superheated feed-steam mixture is distributed through multi-tubular reactor consisting of high alloy reformer tubes containing nickel-based catalyst. To carry out the reactions producing CO, CO2 and H2, heat is supplied by a number of burners burning PSA purge gas andnatural Gas.

The reformed gas after being cooled undergoes shift conversion in shift converters. These are cylindrical fixed bed reactors containing iron/chromium oxide or copper/zinc oxide catalyst. Shift conversion reaction converts most of CO into CO2 and H2 in presence of the catalyst. The heat removed from the converted process gas is used to vaporize and further heat the feed, and preheat boiler feed water and demineralized water (make-up).

Hydrogen is purified to remove inert gas impurities like CO2, CO, CH4, N2 and water vapor by high-pressure adsorption of these impurities on molecular sieves, active carbon and alumina gel in Pressure Swing Adsorption (PSA) system. All adsorbed gases are removed during desorption and regeneration of the beds, and used as reformer fuel. Desorption of impurities is done at low pressure and purge gas is used as fuel.

6.3.13 Sour Water Stripper Unit

Refinery Sour Water Stripper

Refinery Sour Water Stripper is designed to treat sour water from CDU/VDU, HGU, DCU and intermittent sour condensate from SRU & TGTU. The H2S recovered is sent to SRU for reduction to elemental merchant-grade Sulphur. The Ammonia-rich stream is considered to be disposed off by burning in the SRU Ammonia Incinerator. The stripped water from Single Stage SWS is sent to CDU desalter make-up, and to ETP for disposal. Sour water from above described units is received from a common line in a sour water surge drum floating on acid gas flare header back pressure. This surge drum is a three stage (V-L-




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

L) separator. Flashed hydrocarbon vapors are separated and routed to acid gas flare. Oil carryover, if any, is skimmed off from drum and drained to OWS. Sour water from the surge drum is pumped by single stage SWS feed pump to single stage stripper column under surge drum level control cascaded to flow controller through feed/bottom exchanger. The feed/bottom exchanger preheats the sour water feed. The stripper is equipped with a LP steam heated reboiler and a pump around circuit consisting of recirculating pumps and air cooler. Column overhead temperature is controlled by varying flow through air cooler/by-pass in pump around circuit using a three-way control valve. Column overhead pressure is controlled by controlling flow of sour gas (NH3+H2S) to SRU. This sour gas can also be routed to acid gas flare when SRU is under maintenance. The sour gas line to SRU should be steam jacketed. The steam flow to reboiler is controlled by a flow ratio controller that resets steam flow in accordance with sour water feed to column. Stripped water containing NH3 and H2S less than 50 wt.ppm each is pumped by stripped water pumps under level control. It is cooled in feed/bottom exchanger, before routing to CDU desalter. A water-cooled exchanger, which is designed to cool stripped water from

single stage and two-stage stripper, is also provided to cool the stripped water to 40 C if the water is to be sent to the WWTP. In order to prevent evolution of H2S/NH3 while draining sour water to an open sewer, a closed blow down drum (CBD) system is envisaged. The CBD system consists of a CBD drum and a CBD pump. The CBD drum is connected to the acid gas flare in order to route all H2S/NH3 rich vapors that may evolve during equipment draining to flare. Provision is kept for pumping all the drain liquid collected in CBD drum back to sour water surge drum for stripping.

Hydroprocessing Sour Water Stripper

Hydroprocessing Sour Water Stripper Unit-II is designed to treat sour water from DHDT and NHT. The stripped water from two stage stripper is sent separately to DHDT and NHT or to ETP. Hot Sour water from DHDT and NHT is mixed with ammonia rich recycle (to keep H2S in solution & for constructive recovery), cooled in a water cooler to 37 0C, and received in a surge drum, a three stage (V-L-L) separator. Any hydrocarbon that flashes is separated out and joins ammonia stripper overhead line to be routed to incinerator. The entrained oil, if any, is skimmed off from drum and drained to OWS. The sour water is sent to sour water storage tanks under level control. The day tanks and stripper feed pumps are normally located behind SRU ammonia incinerator vent stack. The sour water day tanks serve the following purposes: A floating skimmer (with swivel joints and steam traced “try” lines are provided to skim off separated oil. The tanks are blanketed with nitrogen to keep off air/oxygen. The tanks release vapors containing H2S, ammonia (during out breathing if ammonia rich recycle stream is not available) through a fisher assembly to join SRU ammonia incinerator vent stack to release these vapors at safe height.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

The sour water from tanks is pumped to the 1st stage H2S stripper column under flow control through feed/bottom exchanger where the incoming sour water feed is preheated against 2nd stage bottoms, i.e., stripper water. The feed enters the column feed tray. A slip stripped water stream quantity is taken from the inlet of feed/bottom exchanger and sent as hot wash water under flow control to the 1st stage stripper column. The temperature of this wash stream is very important for column steady performance. H2S stripper is equipped with MP steam heated kettle reboiler to provide the reboiling duty required. This column normally operates at a top pressure of 7.0 Kg/Cm2g and pressure is controlled by PIC in overhead vapour line. The stripping section removes most of the H2S coming in sour water feed. The overhead wash section condenses most of the steam and almost pure H2S is produced at the column top. This H2S gas is routed to SRU for Sulphur Recovery, in a steam traced line. The MP steam flows to reboiler. Condensate withdrawal scheme are same as the single stage stripper column. MP condensate is routed to SRU condensate handling system. The sour water from the H2S stripper bottom, containing almost all ammonia and small quantity of unrecovered H2S, is fed to second stage ammonia stripper column under level control. The ammonia stripper overhead is floating with the SRU ammonia incinerator header back pressure. The sour water is fed at the 2nd stage stripper feed tray. Alternate feed tray is also provided for operational flexibility. The section below feed tray is stripping section with two pass trays.

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

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

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

6.3.14 Amine Regeneration Unit

The function of Amine Regeneration units is to remove the acid gases (H2S and CO2) from the rich amine streams produced in the refinery processing units.

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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

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

6.3.15 Sulfur Recovery Unit (With Tail Gas Treatment Unit)

Feed to SRU comprises of acid gas from ARU and sour gas from SWSU. Acid gas from ARU passes through acid gas knock out drum, to remove any liquid carryover, before feeding to main burner. Similarly, any liquid carryover in sour gas from SWSU is removed in sour gas knock out drum. The air to main burner is supplied by an air blower, which also supplies air to Super Claus stage and sulfur degassing. The air to the main burner is exactly sufficient to accomplish the complete oxidation of all hydrocarbons and ammonia present in the feed gas and to burn as much H2S as required to obtain desired concentration. The heat generated in the main burner is removed in the waste heat boiler by generating steam. Then the process gas is introduced into the first condenser in which it is cooled, sulfur vapor condensed and is separated from gas.

Upstream of 1st Claus reactor, the process stream from waste heat boiler is heated in 1st steam reheater to obtain optimum temperature for the catalytic conversion. The effluent gases from 1st reactor passes onto 2nd sulfur condenser where sulfur vapor is condensed and uncondensed process gases pass to the 2nd steam reheater. Heated vapors are again subjected to conversion in the 2nd Claus reactor followed by cooling in the 3rd sulfur condenser. Then the process gas passes to the 3rd steam reheater and the 3rd Claus reactor. To obtain a high sulfur recovery the process gas is passed to the 4th and last catalytic stage, indicated as the Super Claus stage. The process gas is heated in the 4th steam reheater, and mixed with preheated air. Proper mixing is achieved in a static mixer. In Super Claus stage, H2S is selectively oxidized into sulfur. The gas then passes to the 4th and last condenser.

Sulfur condensed in condensers is routed via sulfur locks to sulfur cooler and drained into sulfur degasification vessel. Stripping air is supplied to the spargers located at the bottom




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

side of the vessel. This strips off H2S from liquid sulfur and oxidizes the major part of H2S to sulfur. Air leaving the stripping columns, together with H2S released from sulfur degasification vessel, is routed to TGT Unit

Tail Gas Unit

Tail gas enters the hydrogenation reactor preheated at 130 oC. H2 reducing gas is mixed with Claus tail gas in the preheat effluent stream via a controller which is reset by the SO2 concentration in the downstream of the hydrogen reactor. The effluent is preheated under temperature controller by an electrical heater. A pre-sulfiding line is provided to activate the TGU catalyst using acid gas from the acid gas KOD. This line is not used for normal operation. The hot preheated effluent passes through the catalyst bed of the hydrogenation reactor where SO2 and other sulfur compounds are converted to H2S. Due to exothermic reaction, the gas temperature increase over the reactor to. The reactor inlet temperature should be held reasonably steady to provide stable conditions in the reactor. To avoid excessive outlet temperature, the inlet gas may be controlled at somewhat lower temperature to compensate for more SO2 and/or S in the tail gas feed. However, excessively low reactor inlet temperature will result in poor conversion. The SO2 monitor at the reactor effluent is observed to maintain an excess of ~3% H2. In addition, if the circulating water in the quench loop shows the presence of finally divided sulfur this indicated incomplete reaction and the SO2 has reached the column to form sulfur via the Claus reaction: 2H2S + SO2 3S + 2H2O This behavior should be monitored as the presence of the sulfur not only means the reaction is incomplete but the column can be plugged. Monitoring the pH of the quench water provides a pre-warning to an impending problem. The pH should be maintained near 7.0. Hot reactor exit gas must be cooled before entering the absorber. A first stage gas cooling is accomplished by generating steam at the TGU waste Heat Boiler, decreasing the process gas temperature. BFW is fed to the shell side of the TGU-WHB on level control and low pressure steam is generated. When the steam flow and/or BFW flow rate changes, the water level in the steam generator vary. Rising level in the generator indicated that the BFW flow rate is exceeding the rate of steam generation. In this case, signal to the level control valve will decrease. If the steam generation exceeds the BFW rate, level will decrease. In this case, signal to the level control will increase. The process gas enters to the quench column. The quench water recirculating loop consists of the quench water pump, filter and water cooler. The cooler remove the heat from the column, cooling the inlet gas. The water flow to the top of the column is controlled after being filtered by quench water filter. Decreasing the water flow rate will increase the bottom temperature. Increasing the water rate will increase the load in the quench water circulation pumps and flow through the quench water cooler and column.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

The quench column recirculation system has the provision to adjust the pH by addition of ammonia to the column recirculation line. The pH of the quench water to the water pump is monitored and kept at a value between 7 and 9 in an effort to prevent corrosion and inhibit colloidal sulfur formation. The water system should be visually inspected for cloudiness. Low pH will indicate incomplete reduction of sulfur compounds. Sour water condense from the inlet feed is removed from the quench water loop via a level controller from the quench column and is sent offsite to sour water storage. The rate depends on the water in the Claus tail gas, water produced in the hydrogenation reactor and the amount of water overhead in the quench column. The overhead line from the quench column flows to the absorber. The absorber is a packed column and is designed to absorb practically all the H2S in the recirculating Amine solvent. The absorber over head is routed to the incinerator. The absorber bottom liquid is pumped by the rich solvent pump to common amine regenerator section. The purpose of the incinerator system is to oxides all the sulfur compounds in the tail gas to SO2 and to vent the oxidized stream at high temperature and at a high elevation.

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

The effluent is discharged to the incinerator stack. The stack height of 60 meters is set to ensure dispersion of SO2 and to meet ground level concentration limits. Effluent tail gas from the TGU absorber is thermally oxidized with air to convert reaming sulfur compounds to SO2. Fuel gas and excess air are combusted at high temperature at the incinerator burner. Then it is mixed with the absorber overhead tail gas in the primary oxidation chamber. The fuel gas and air rates are adjusted to control the temperature of the mixed and oxidized tail gas stream. The air is supplied by a dedicated incinerator air blower. Excess air is used to ensure sufficient oxygen is present to oxides the sulfur and other sulfur compound. Oxidation reaction are as follows: H2S + 3/2 O2 SO2 + H2O 2COS + 23 O2 2 CO2 + 2SO2 CO + ½ O2 CO2 CS2 + 3 O2 2SO2 + CO2 Sn + nO2 n SO2 The incinerator effluent temperature is measured and used to adjust the flow rate of fuel gas to maintain the desired operating temperature of 768oC. The incinerator is refractory lined with an external thermal shroud to control the shell temperature. Skin thermocouples are provided to monitor the shell temperature. The shell temperature should be maintained between 149 – 350oC.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

The air blower is designed to provide supply of air and stack while providing a minimum of 2% excess O2 at an operating temperature of 768oC. Ambient air is drawn through the inlet filter to remove solid debris and to protect against water during heavy rainfall. The combustion gas from the burner and combustion chamber flow into the incinerator where adequate residence time is provided for combustion. The incinerator stack vents the effluent to the atmosphere. A SO2/O2 analyzer is provided to determine the SO2 and O2 in the effluent stream.

6.4 Material Balance 6.4.1 Overall Material Balance is provided below in table no. 6.4.1

Table-6.4.1 Overall material balance

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


0.557


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






Sulfur (TPD) 368

Fuel and Loss 0.657 (9.17 %)




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

6.5 Utilities Description

6.5.1 Raw Water System Raw water shall be made available from the nearby Dhansiri river .Present raw water intake limit is 1200 M3/hr from river out of which, existing refinery draws 700 M3/Hr. After installation of new refinery train, this limit will need to be increased.. The capacity of untreated raw water reservoir required is reported in table No. 6.5.1.1 and corresponds to about 2 days of normal demand. After the Expansion of refinery, existing two reservoirs of 12000m3 capacity each will be dismantled and raw water requirement of existing refinery will also be met by new reservoirs. Hence, two nos. of new reservoirs catering the total requirement of refinery will be provided. The reservoir is provided to ensure uninterrupted supply of raw water to the refinery. The raw water from the reservoir shall be softened, treated for organic and biological matter, pH adjusted and filtered in a raw water treatment plant to obtain treated raw water. The treated water would be stored in two nos. of reservoirs. Two nos. of raw water treatment plant is envisaged. Raw water from raw water reservoirs will be pumped to the various consumers in the refinery to meet its processing and other requirements and also to the township for its domestic use. Raw water shall be used as follows: i. Cooling tower make-up ii. Service water iii. DM Plant feed iv. Fire water system make up v. Drinking water system / Raw water requirement vi. Pump bearing /seal cooling

Raw water requirement and various components associated with raw water system are reported in the table No. 6.5.1.1.

Table-6.5.1.1 Consumption and configuration of raw water system

A) Raw water requirement (with 10% margin), m3/Hr

1265

B) Reservoirs (2 no.), for total 2 days.

Cap : M3 (Each) 44200

C) Treatment plant (2 no.)

Capacity of plant : m3/ hr each 1340

D) Treated water reservoir (2 nos) :

Cap : M3 (Each) 7600

E) Pumps

1. CW Makeup 2w+1s




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Type : Centrifugal Centrifugal

Capacity : m3/hr (Each) 400

2. Service water 2w+1s



3. DM water plant Feed 2w+1s



4. Fire water 1w+1s

Type : Centrifugal


5. Fire water jockey pump 1w+1s

Type : Centrifugal

Capacity :m3/hr (Each) 5

6. Drinking water 2w+1s



6.5.2 Cooling Water System

The cooling water system envisaged for the refinery complex is closed loop recirculation type. Single cooling water system will cater to the requirements of process units, offsite & CPP within the complex. The cooling water system includes cooling towers, pumps, cooling water treatment facilities and other auxiliary items.

Cooling water requirement

The cooling water requirement of various process units is given in Table-6.5.2.1

Table-6.5.2.1 Cooling water requirement (M3/HR)

S. No. Units CW requirement (M3/Hr)

1. CDU / VDU 4268

2. NHT 919

3. ISOM 462




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

S. No. Units CW requirement (M3/Hr)

4. CCR 2419

5. DHDT 1985

6. HCU 6669

7. DCU 1593

8. BBU 37

9. SDA 572

10. LPG treating 26

11. HGU 536

12. SWS 382

13. ARU 867

14. SRU 59

15. TGTU 663

15. Utility & Offsites 2112

16. Miscellaneous 1000

Total requirement 24569

With 10% design margin 27026

Cooling Tower

This cooling water system will meet total cooling water demand of various process units viz., CDU/VDU, NHT, ISOM, CCR, DHDT, HCU, DCU, BBU, SDA, HGU, LPG treating units, SWSU/ARU/SRU,CPP, Utilities and Offsites. Refinery cooling water system will comprise of cooling tower, cooling water transfer pumps and cooling water distribution network.

Different components of cooling water system have been reported in the following table.

Table-6.5.2.2 Configuration of cooling water system

A) Cooling Tower

No. of cells : 7W +1S

Cap./ cell: m3 /hr 4000

B) Recirculating Pumps

Type : Centrifugal

No.of pumps : 4W+2S

Capacity : m3/hr 7000




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

C) H2SO4 dosing pump

No.of pumps : 1w+1s

Type centrifugal

Capacity : lits/hr 80

D) H2SO4 unloading/transfer pump

No.of pumps : 1w+1s

Type : centrifugal

Capacity : 5 m3/hr

E) H2SO4 Storage tank Dimension : 3M DIA X 4M HT

F) H2SO4 Dosing vessel

Type : Horizontal

Dimension : 0.8 m dia & 1 m length

G) Vendor package

1. Chlorination system, kg/hr (1W+1S)

25

2. Side stream filter m3/hr(2W+0S.). 280

Cycles of concentration

Both the cooling water systems will be designed to operate at 5 cycles of concentration.

Side stream filters Side stream filters with total capacity based on 1.0 - 2% of the cooling tower capacity will be provided so as to maintain the suspended solids contents within the stipulated limits in the recirculating cooling water.

Total Side stream filtration capacity for Refinery cooling tower: 2 nos. side stream filters each of capacity 280 m3/hr, all operating simultaneously.

Emergency Cooling Water

To cater the cooling water requirement of HCU and DHT recycle gas compressor during emergency, one steam driven pump of 2400 m3/hr capacity will be provided. This pump shall come into act on loss of cooling water supply from main cooling water pumps. During normal operation, the steam turbine driven pump shall be maintained in hot condition.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

6.5.3 De Mineralised Water and CausticSystem

DM water in the refinery complex is required as Boiler feed water make-up, process water for dilution, reaction and washing. Caustic in many process units for various uses.

DM Water Requirement

The demand summary of DM water requirement in various units is given in Table-6.5.3.1

Table-6.5.3.1 DM water requirement (m3/hr)

S. No. Units DM Water requirement (M3/Hr)

1. CCR 6

2. HGU 108

3. Sulpher Block 12

4. Steam, power & BFW system 112

Total DM Water Requirement 238

Requirement with 10% margin 261

DM Plant Specifications

DM water for the refinery is produced in an ion exchange resin based system. The configuration of the DM plant is reported in table No. 6.5.3.2

Table-6.5.3.2 Configuration of DM water and Caustic system

A) Ion exchange resin based DM Plant

Cap.: M3/Day 6400

No. of chains : 2W+1S

Chain capacity, M3/Hr 160

B) 46 % Caustic storage tank (2 Nos.)

Type : Cone roof

Nominal Capacity : 60 m3

dimension : 4.2 m dia & 4.3 m height

C) Caustic Unloading pump

No.of pumps : 2 (1W+1S)

Type : Centrifugal

Capacity : M3/Hr 15




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

D) Caustic dilution/transfer pump

No.of pumps : 2 (1W+1S)

Type : Centrifugal

Capacity : M3/Hr 25

E) DM Water storage tank (2 nos.)

Type : Cone roof with N2 blanketing

Nominal Capacity : 3800 m3

Dimension : 21 m dia & 11 m height

F) DM WaterTransfer pumps

No.of pumps : (Process) 1W+1S

Type : Centrifugal

Capacity : m3/hr 265

6.5.4 Compressed Air System

The Compressed air is required in the complex for following usages:-

i. As instrument air ii. As plant air iii. As service air for hose stations and for other requirements of the complex.

Compressed Air Requirement

The requirement of plant air and instrument air in the complex are given in Table 6.5.4.1

Table-6.5.4.1 Compressed air requirement (NM3/HR)

S. No. Units Instrument Air Plant Air

1. CDU / VDU 774 460 (intermittent)

2. NHT 92 0

3. ISOM 240 0

4. CCR 240 200

5. DHDT 502 0

6. HCU 1000 0

7. DCU 1750 0

8. BBU 200 0

9. SDA 400 0

10. LPG treating 100 200

11. HGU 306 0




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

S. No. Units Instrument Air Plant Air

12. SWS 100 0

13. ARU 100 0

14. SRU 300 0

15. Utility & Offsites 738 600 (intermittent)

16. Miscellaneous 200 0

17. Plant Air hoses 0 1700

Net Compressed Air Requirement 7042 3160

Generation with 10% margin 7746 3476

The configuration of the compressed air system is reported in table No. 6.5.4.2

Table-6.5.4.2 Configuration of Compressed air system

A) System capacity :

Plant air, Nm3/hr 3160

Instrument air, Nm3/hr 7042

System details :

B) Centrifugal Compressor (Common for Nitrogen & IA/PA system)

Type : Centrifugal, non lubricated

Nos. 3W+1S

Drive : Electric motor

Capacity : 10000 NM3/HR

Discharge Pressure : 8.0 kg/cm2g

C) LP air receiver

No. 1

Type : Vertical

Height : 12000 mm

Dia: 5000 mm

D) HP air receiver

No. 1

Type : Vertical

Height : 12000 mm

Dia: 4500 mm

E) HP air compressor




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Nos. 1W+0S

Type : Reciprocating

Drive : Motor

Capacity : 250 Nm3/hr

Discharge Pressure : 31.5 kg/cm2g

F) Instrument Air Dryer

Nos. 2W+0S

Type : Dual bed Adsorption

Capacity : 5000 NM3/HR

6.5.5 Nitrogen system

The inert gas (Nitrogen) is required in the refinery for initial purging, dry out and for catalyst regeneration. The inert gas is also required in Offsite for blanketing and in flare header purging. Nitrogen plant is provided to cater to the inert gas requirement of the complex. I. Continuous requirement: The continuous supply of Nitrogen will be required for

the following purposes: a) Seal purging of compressors in unit b) Blanketing of tankages II. Intermittent requirements a) Start-up & Shutdown of unit b) Catalyst Regeneration in plants

The configuration of the Inert gas system is reported in table No. 6.5.5.1

Table-6.5.5.1 Configuration of Inert gas system

A) System capacity :

Nitrogen (Gaseous/ Liquid) , Nm3/hr 1500/225

System details :

B) Cryogenic Nitrogen plant

Nos. of chains 1

Gaseous Nitrogen Capacity 1500 nm3/Hr

Liquid Nitrogen capacity 225 Nm3/Hr (Equivalent , Concurrent)

C) Cryogenic Nitrogen storage

Capacity (Each vessel) : 167 M3 (liquid capacity)




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Storage Pressure : 7.0 kg/cm2g

No. of vessel : Three

Type : Cryogenic double wall pressurised storage

D) No. of vaporisers 1w +1S

Capacity of vaporisers 8100 Nm3/hr

Type Atmospheric

6.5.6 Steam System

The steam shall be produced in the boilers and HRSGs of the steam and power generation system. The fuel to steam and power generation system shall be a Natural Gas. Steam is distributed to the refinery consumers at three levels, viz: HP, MP and LP. Steam is consumed in various units for:

- Process use (Chemical reaction, Stripping steam,etc.)

- Fuel Oil heating

- Internal fuel oil atomization,

- Steam tracing of lines (congealing service)

- Tankage heating

- Deaerator

- Intermittent requirement like snuffing, decoking, soot blowing, purging etc.

- Running of steam turbine drives.

Steam Requirement The steam requirement of the complex is given in Table 6.5.6.1

Table-6.5.6.1 Steam requirement (T/HR)*

S. No. Units HP MP LP

1. CDU / VDU 0 35 10

2. NHT 19 25 -9

3. ISOM 9 33 1

4. CCR -4 3 -6

5. DHDT 24 2 -5

6. HCU 22 -15 -20

7. DCU 9 3 0

8. SDA 13 18 5

9. BBU 0 0 1

10. HGU -60 0 1




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

11. SWS 0 3 29

12. ARU 0 0 62

13. SRU 0 -73 -1

14. TGTU 0 0 11

15. Utility & Offsites 6 5 5

Total requirement 37 40.5 84.1

* Negative sign indicates generation

The configuration of the steam generating components of the steam and power generation system is reported in table No. 6.5.6.2

Table-6.5.6.2 Configuration of steam generation system

A) Utility Boilers (Note-1) No.: 1

Capacity : TPH 110

Steam level VHP

B) HRSG (Note-2)

No. 2 (Note-2)

Capacity : TPH 110/120 (Note-2)

Note-1:- Steam boiler is required to run during normal operation at a lower capacity to meet steam demand of Hydrocracker unit in case of Power failure, It will operate at full capacity of 110 TPH to take care of the case of one HRSG not operating. Note-2 :- (A) One new HRSG of 110 TPH capacity associated with new frame-VI GTG being installed in proposed CPP and generating VHP steam. (B) One existing spare HRSG of 120 TPH capacity associated with existing Frame VI GTG in existing CPP and generating HP steam. The spare GTG and HRSG will run continuously after refinery capacity expansion.

6.5.7 Power System

Table-6.5.7.1 below gives the power requirement of the various units under normal operating conditions.

Table-6.5.7.1 Power consumption (KW)

S. No. Units Power Consumption (KW)

1. CDU / VDU 6911

2. NHT 2341

3. ISOM 2036




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

S. No. Units Power Consumption (KW)

4. CCR 6123

5. DHDT 6499

6. HCU 18007

7. DCU 3700

8. SDA 1433

9. BBU 274

10. LPG treating 176

11. HGU 3717

12. SWS 429

13. ARU 1075

14. SRU 3638

15. TGTU 668

16. Utilities 11253

17. Offsites 1600

18. Miscellaneous 4000

Total unit wise power consumption 73881 Power requirement of the refinery shall be met by GT & STG. One spare GT available at the existing refinery shall be used continuously. In case of one GT failure power shedding will have to be resorted to in the refinery.

Table-6.5.7.2 Configuration for power generation system

A) GTG (Note-1) Nos. 2 (Note-1)

Capacity : MW 35.56

B) STG No.: 1

Capacity : MW 12

Note -1: One new frame-VI GTG being installed in proposed CPP along with one existing spare frame VI GTG available in existing CPP. The spare GTG will run continuously after refinery capacity expansion.

6.5.8 Boiler Feed Water

Boiler feed water requirement of various units is given below in Table-6.5.8.1. This BFW will be produced in the CPP and exported to the respective units.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Table-6.5.8.1 Boiler Feed Water requirement (TPH)

S. No. Units BFW requirement (TPH)

1. CDU / VDU 17

2. NHT 5

3. ISOM 2

4. CCR 30

5. DHDT 9

6. HCU 51

7. DCU 10

8. BBU 1

9. ARU 4

10. SRU 94

11. Utility & Offsites 1


6.5.9 Condensate System

Steam is being used in the refinery as process steam motive fluid for the steam turbine drives, for heating etc. Condensate results from the condensing steam turbine drives, steam re-boilers and steam heated exchangers. Within each individual units suspect condensate and pure condensate shall be segregated. Surface condensate from condensing type steam turbine drives shall be considered pure condensate and used for steam generation directly. Depending upon the steam and process side pressure levels in exchangers, each unit shall have separate header for these two types of condensates. The suspect condensate, if contaminated shall be required to be treated in centralised condensate polishing unit before use. Pure condensate shall be directly used for steam generation. The condensate being generated which shall be recovered can be categorized under following headings:-

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

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

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

Condensate Generation

Condensate generation summary for various units is given below in Table-6.5.9.1




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Table-6.5.9.1 Condensate generation (TPH)*

S. No. Units Suspect Condensate generation (TPH)

Pure Condensate generation (TPH)

1. MS Block -16.5 -81.5

2. HCU -11 -7.9

3. DHDT -10 -15.2

4. DCU -2.4 -9.4

5. SDA -25.9 0

6. LPG MEROX -0.3 0

7. SWS 0 -32

8. ARU 0 -61.8

9. SRU 0 -5.2

10. TGTU 0 -11.2

11. Utility & offsites 0 -6

Total requirement -66.1 -224.1

*Negative indicates generation.

Condensate Recovery System

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

Table-6.5.9.2 Configuration for condensate polishing system

A) No. of chains 1W+1S

Capacity per chain, TPH 70

B) Exchangers

Condensate cooler 1

Polished/unpolished condensate exchanger

1

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

Mixed bed (Per chain) 1w + 1s

C) Storage tanks

1. Unpolished condensate tanks No. units 1W+1S

Dimension : 12M DIA X 6 M HT

MOC : CS with epoxy coated.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

2. Polished condensate tanks

No. units 1W+1S

Dimension : 12M DIA X 6 M HT

D) Pumps

1. Unpolished Condensate Pumps

No.of pumps : 1W+1S

Type : Centrifugal

Capacity : m3/hr 70

2. Polished Condensate Pumps

No.of pumps : 1W+1S

Type : Centrifugal

Capacity : m3/hr 70

6.5.10 Internal Fuel Oil and Fuel Gas System

The fuel requirement of refinery complex would be met by the internal fuel oil and the fuel gas systems. Fuel is consumed mainly in Process units. Total requirement of fuel in all the furnaces within the process units would be met mostly by fuel gas system and partly by internal fuel oil systems. All the furnaces shall be designed for dual firing.

Fuel Demand

Fired heat duty of all new units, is indicated in the Table-6.5.10.1

Table-6.5.10.1 Fired heater duties (MMKCAL/HR)

S. No.

Units Fired Heater Duties (MMKCAL/HR)

1. CDU / VDU 126

2. NHT 6

3. ISOM 1

4. CCR 31

5. DHDT 20

6. HCU 50

7. DCU 26

8. SDA 11

9. BBU 1


Fuel Availability

The fuel System will consist of the following:-




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

FUEL GAS SYSTEM

A) Fuel Gas KOD (1 No.)

Type Vertical

Height 2.9 M

Dia 1.1 M

FUEL OIL SYSTEM

B) Fuel Oil Day tank (1 no.)

Type : Cone roof

Nominal Capacity : 1300 M3

Dimension : 15 M DIA X 7.5 M HT

c) Fuel Oil Transfer pump No.of pumps : 2 (1W+1S)

Type : Screw

Capacity : M3/Hr 72

Head : M 167

D) Fuel Oil Heater

Nos. 1

E) Fuel Oil Prefilter

Nos. 1W+1S

F) Fuel Oil Afterfilter

Nos. 1W+1S

6.5.11 Flare System

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

Cooling water failure

Power failure

Combined cooling water and power failure

External fire

Any other operational failure

Blocked outlet

Reflux failure

Local power failure

Tube rupture

Etc




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

The flare loads from the new refinery will be connected to a new flare. A preliminary configuration of the various components of the flare system is indicated in table No. 6.5.11.1.

Table-6.5.11.1 Components of flare system

A) Stack details:-

Stack dia 66 INCH

Stack length 95 M

Stack MOC KCS

Sour Stack dia 20 INCH

Sour Stack length 95 M

Sour Stack MOC SS-304L

B) Header details:-

Header dia 66 inch

Header MOC CS

Sour Flare Header dia 20 inch

Sour Flare Header MOC CS

C) Flare KOD

Type HORIZONTAL

Dimension 22 M (length)/ 4.5 m (dia)

MOC KCS

Sour Flare KOD

Type HORIZONTAL

Dimension 4.5 M (length)/ 1.5 m (dia)

MOC KCS

D) Fuel gas KOD

Type Vertical

Dimension 4.4 M (height)/ 1.3 M (dia)

E) Water Seal Drum

Type : Vertical

Dimension 13 M (height)

7.4 M (dia)

F) Flare KOD bottom pumps

No.of pumps : 1W+1S

Type : Vertical barrel type

Capacity : m3/hr 30

Head : m 94

MOC : Casing & Impeller : CS




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

6.6 Offsite System

Storage and Transfer Data

This section describes the storage and pumping facilities for feed, intermediate and finished product based on the material balance for the refinery configuration The philosophy and facilities for storage and transfer is discussed below. Offsite facilities are divided into three sections:

Crude oil storage and transfer

Intermediate Feed / Intermediate product storage and transfer

Finished product storage and transfer

Feed Storage and Transfer

Additional crude tanks, finished product storage tanks and Intermediate feed storage tanks and pumps considered for cost estimate are provided in Table 6.6.1 and 6.6.2 respectively.

The basis for the offsite facilities are described in subsequent sections below.

Crude Receipt, Storage and Transfer

1. Crude will be transported from Dhamra port through new pipeline (outside scope of DFR) to additional train.

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 each 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.

Intermediate Feed Storage and Transfer

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

2. Intermediate unit feed flow control will be within the respective unit battery limit.

3. Pump minimum flow bypass is to be considered for intermediate feed system though simultaneous feeding from storage and upstream unit has not been




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

considered. In case of heavy services, LVGO, HVGO, CGO, VR, offsite piping shall be kept flushed when not in service. The light service pumps like light naphtha and Raw LPG are to be considered for minimum flow bypass to avoid cavitations.

4. For all intermediate services unless it is mentioned in the respective section, one suction line will be considered.

5. No. of days storage: 5 days storage for VGO & VR has been considered. All other

intermediate products storage have been considered for 3 days

Finished Product Storage and Transfer Philosophy

1. Finished product tankage in the refinery has been designed to cater only to the minimum operational flexibility in the refinery and subsequent testing/certification/ despatch to marketing terminal. It is assumed that the despatch to marketing terminal can be carried out at any hour during the day.

2. LPG storage for additional train and existing refinery will be provided as mounded

bullets.

3. No pump minimum flow bypass is to be considered for finished product system since transfer to marketing terminal is a planned operation. For all finished product services one suction line is to be considered.

4. Philosophy for storage of products: 10 days storage for products has been

considered at refinery. Re allocation of existing tanks service (for e.g. MS to HSD, etc.) has been considered.

5. Adequacy of above existing product storage has been checked for the combined

production of existing refinery and additional train Additional storage required has been reported. New storage facilities for storage of new products which presently are not in existing product lines have been provided.

6. Two additional manual Blending station will be added at the marketing terminal.

7. Details of existing finished product storage facilities at the refinery provided by NRL

and the same are listed below in table no.6.6.1 below




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Table : 6.6.1 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


RCO 2 7860 12 29


VD 2 12800 14 34


CD 2 2800 10 19


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/Reformer

2 5000 12 25.5

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

The new facilities for crude, intermediate and finished products are reported in Table No. 6.6.2.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Table : 6.6.2 Details of new feed, intermediate and finished product storage facilities

Service Capacity, M3

No. Of tanks considered

Volume per tank (M3)

Tank height considered

Tank diameter calculated

Tank type Operating Temp, Deg C

Design Temp, Deg C

Roof Design Pressure (mm WG)

Remarks

Crude 416932 8 52116 14.4 69 Floating Roof

AMB 65 150 8 tanks at port terminal

Crude 120000 3 40000 14.4 60 Floating Roof

AMB 65 150 3 tanks at Refinery

Vac Residue 28216 2 14108 14.5 35 Floating Roof

100 120 150 2 tanks to be provided

NHT feed 12361 2 6181 13 25 fixed cum Floating Roof

AMB 65 150 2 tanks to be provided

Isomerate 5900 2 2950 10.5 19 fixed cum Floating Roof


Reformate 9681 2 4841 14.5 21 fixed cum Floating Roof


VGO 39758 2 19880 14.5 42 Conical Roof


DHT feed 31255 2 15628 13.5 38 Conical Roof


LPG 15915 6 2814 70 7 Mounded Bullet

AMB 65 15 Kg/Cm2g

6 mounded bullets to be provided

Bitumen 7500 2 3750 12 20 Conical Roof





Document No.

A555-RP-0241-0001

Rev. No. A

of 125

The offsite pumps lists have been provided in table no.6.6.3 below

Table: 6.6.3 Details of offsite pumps

Service No. of pumps

Flow (m3/hr)

Head (m)

Motor Rating (HP)

MOC Type

Crude transfer pumps Crude Transfer Pumps

2+1 426 61 250 CS Centrifugal

Intermediate pumps NHT Feed pumps


CCR Feed pumps


Isomerate Feed pump


DHDT Feed pumps


VGO feed pumps


VR Pumps 1+1 188 100 200 CS screw

Product transfer pumps

LPG product transfer pumps


Bitumen transfer pumps

1+1 150 100 100 CS screw

6.7 Product Dispatch Facilities

Existing Facilities:

A. Road Loading Facilities:

LPG: 5 bays truck loading gantry at Numaligarh.

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

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

No black oil dispatch

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




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

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 (One rake is of 47 wagons). 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 (One rake is of 47 wagons). This facility is operated during all the three shifts. Rail wagon loading rate is 72 m3/Hr per bay.

C. Pipeline Facilities :

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. Adequacy checking of this pipeline and its augmentation is to be done by OIL and hence is excluded from this present study.

New Facilities:

Adequacy of above existing product dispatch facilities has been checked for the combined production of existing refinery and additional train.

Augmentation of LPG dispatch facilities considers dispatch through road transport

only. No railway dispatch of LPG has been considered. Two additional road loading gantries to be provided at NRL refinery.

NRL can load two rakes of white oil products simultaneously from its two spur gantry

at NRMT. One rake can be released within 5 hours from time of placement. As per practical experience, NRL could load 4 rakes in a day.

However, to reduce logistic cost, evacuation of MS and HSD produced from the new

train through NSPL (Numaligarh Siliguri pipeline) and thereafter ex Siliguri terminal by rail has been proposed by NRL. Currently Siliguri terminal has a single spur gantry for white oil products which will be converted to double spur gantry to handle additional load.

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.

For loading Bitumen on to road tankers, two new road loading gantries will be




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

considered for the same.

6.8 SULPHUR BALANCE

Sulphur recovery unit (SRU) capacity is estimated by sulphur balance calculation. This section provides the sulphur balance. Sulphur balance for selected case is provided in Table 6.8.1.

Table: 6.8.1 Sulphur Balance

Feed TPD S (wt% ) TPD Arab light 5400 1.83 98.82 Arab heavy 12600 2.83 356.58 Sr Kero from Existing Refinery CDU

1323 0.03 0.4


1671 0.12 2.0

Total Sulphur in feed

457.8

Products TPD S (wt %) TPD

Mixed LPG's 774 0 0.00 BS IV Domestic Gasoline

2658 0.0001 0.00

EURO IV Export Gasoline

342 0.0001 0.00

Aviation turbine fuel 159 0.0008 0.00 EURO V Domestic Diesel

276 0.001 0.00

EURO IV Domestic Diesel

9942 0.0045 0.44

EURO IV Export Diesel 3306 0.0045 0.15

Bitumen 600 5.44 32.64

Fuel grade coke 1092 5 54.6

Internal fuel oil 456 0.5 2.28 Sulphur in products and fuel

90

Table: 6.8.2 SRU capacity for selected case

Sulfur Balance (in TPD) Total Sulphur in Feed 457.8 Total Sulphur in Products & fuel 90 SRU Capacity Required ~370 Considering 15 % Margin ~420




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Sulphur content in product and fuel is considered as per LP solution for the selected case

Sulfur Recovery Units has been considered with Tail Gas Treating (TGT) facilities. Total sulphur recovery is 99.9%.

Based on the above., two trains of sulphur recovery unit of 210 TPD capacity each is required

6.9 Hydrogen Balance

This section describes refinery hydrogen balance for the selected case.

Main consumers of hydrogen in the refinery are hydro processing units, Diesel Hydrotreater Unit (DHT), Naphtha Hydrotreater Unit (NHT) , Isomerisation Unit (ISOM) and full Conversion Hydrocracker unit (HCU) are the major consumers of hydrogen. Sulphur Recovery Unit with Tail Gas Treating will also consume small quantity of hydrogen.

CCR is a net exporter of hydrogen. Hydrogen produced in the CCR unit is first utilized in NHT and the remaining is routed to hydrogen network through recovery PSA.

For meeting the hydrogen demand of various units, hydrogen balance is performed to estimate the new Hydrogen Generation Unit capacity.

Natural Gas is considered as both fuel and feed for the Hydrogen Generation Unit.

Table 6.9.1 shows estimated hydrogen consumption for selected case at operating capacity. For various process units EIL in-house data is considered.

Table 6.9.1: Selected Case Hydrogen Consumption (KTPA)

Process Units Hydrogen consumption

NHT 3

ISOM 3

DHT 30

HCU 62

TOTAL CONSUMPTION ~98




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Table 6.9.2 shows the Hydrogen Generation facilities of the additional train.

Table 6.9.2: Selected Case Hydrogen Generation (KTPA)

Process Units Hydrogen consumption

CCR 22

Additional HGU Capacity Required ~78

Hydrogen Quality

Hydrogen Consumption reported in Table 6.9.1 is based on the hydrogen quality as given in Table 6.9.3. This quality will be specified for the hydrogen generated from all generators, i.e., CCR and HGU.

Table 6.9.3: Hydrogen quality specifications

S No. Parameter

Specification

1.

Hydrogen purity, vol % 99.9 minimum

2.

CO + CO2, 20 ppm v, max

3.

Nitrogen, 20 ppm v, max

4.

Water, 50 ppm v,max

5.

Chlorine + chlorides, 1 ppm v, max

6.

Methane, vol % Balance




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

ATTACHMENT-I

BLOCK FLOW DIAGRAM OF CASE A




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 7 ENVIRONMENTAL CONSIDERATIONS




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

This section is not included in this Detailed Feasibility Report.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 8 PROJECT IMPLEMENTATION & SCHEDULE




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

This section is not included in this Detailed Feasibility Report.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 9 PROJECT COST ESTIMATE




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

9 PROJECT COST ESTIMATE

9.1 Scope

Cost estimates have been prepared for selected case A of the 6.0 MMTPA additional refinery train consisting of Process units, Captive Utilities & Off-sites and associated facilities coming up at the NRL refinery site as a part of the project.

9.2 Project Cost

Capital cost estimate for the identified scope works for the above case is Rs 14703.00 Crore.

Validity of Cost estimate is as of 1st Quarter 2014 price basis.

This Capital cost estimate shall be read alongwith Key assumptions and Exclusions listed at para 9.3 & 9.4

9.3 Key Assumptions

The basic assumptions made for working out the capital cost estimate are as under:

Cost estimate is valid as of 1st Quarter 2014 price 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.

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 of plant and machinery cost 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 60.0

9.4 Exclusions

Following costs have been excluded from the Project cost estimate:

Land (existing shall be used)

Forward escalation

Exchange rate variation

Cost towards statutory clearances




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

9.5 Estimation Methodology

As indicated in para 9.2 above, the estimated project cost for the identified scope and technical details for selected case A works out to as under-

Cases Fc Ic Total Capital (Rs Cr)

CASE A 1328.47 13374.53 14703.00

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 estimates are enclosed as Annexures.

Process Units

The cost estimate for Process units has been prepared based on analogous reference of similar unit executed by EIL and cost has been adjusted for capacity and updated to the present day price level. A factored approach has been adopted to estimate the cost for piping, electrical, instrumentation, spares and construction costs.

Utilities & Off-sites and Steam & Power System The cost for various utilities & off-site facilities are based on analogous reference of similar system / facility executed by EIL and cost has been adjusted for capacity and updated to the present day price level. The estimated cost for various utilities & off-site facilities is for following systems / facilities:

Raw water system

Cooling water system

DM water system / CPU

Compressed Air and N2 system

Fuel Oil system / Fuel gas system

Crude Storage at Dhamra Port & Refinery / product storage and pumping, Intermediate storages and mounded bullets including product dispatch facilities both at refinery & Siliguri Marketing Terminal.

Flare system

Fire Fighting system




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Steam & Power system

The cost estimates for utilities / off sites facilities and Steam & Power system have been prepared based on system capacities and in-house engineering information and recent in-house cost data available for similar facilities implemented in other projects. The cost for piping, & electrical items & Structural Steel works for Utilities & Off-sites is as per the respective MTO’s. The cost for instrumentation items, spares and construction costs is on factor basis.

Dismantling & Relocation A lump-sum cost of Rs. 10 Cr. provision has been made for dismantling & Relocation of items based on information provided by NRL.

Scope of Factors

The factors used under Process units / Utilities & off-sites are for the following items:

Installation of Equipment

Piping & Electrical materials installation.

Instrumentation materials supply and installation.

Insulation, Painting and fireproofing materials supply and installation.

Catalysts & Chemicals Provision for first fill of catalysts & chemicals required is based on process input added with indirect as per in-house norms.

Indirect Costs, Exchange Rate

The cost estimate is based on following Exchange Rate & Indirect costs:

Exchange Rate 1 US$=Rs.60.0

Ocean Freight 5.0% of FOB cost of imported equipment

Port Handling 2.0% of FOB cost of imported equipment

Inland freight 7.0% of FOB cost of imported equipment and ex-works cost of indigenously sourced equipment

Insurance 1% of total cost

Provision for ocean freight is for supplies by marine transportation / ships only. No provision has been kept for any special transportation means such as Air freighting or usages of barges.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Statutory Taxes and Duties

Provision for statutory taxes & duties has been made as under:

Customs Duty 22.85% of CIF cost of imported equipment (5% Basic Customs Duty + 12.00% CVD+ 3% Education Cess and 4% SAD).

Excise Duty 12.36% of ex-works cost of indigenously sourced equipment.

Central Sales Tax / VAT 2%

VAT on Contracts 7.5% (@12.50% on 60% site work)

Service Tax 12.36% on Services

Entry Tax 2%

Royalty, Know-How, Process Design / Basic Engineering Fees

A cost provision for Royalty, Know-how, Process Design, Licensor’s expatriate and Basic Engineering has been made in the cost estimate based on in-house information. Cost includes provision for R&D cess, withholding tax and service tax.

Project Management, Detailed Engineering, Procurement Services & Construction Supervision

A cost provision in the cost estimate has been kept towards the services of project management, detailed engineering, procurement services & construction supervision assistance as factor of plant and machinery cost. This fee is indicative in nature. Cost includes provision for service tax @ 12.36%.

Land and Site Development

Land is existing, so no provision for it has been made.

Cost estimate for site development has been made towards site grading, boundary wall, pavements etc as per MTO generated for this project.

Crude / Product Transfer facilities

A lumpsum cost of Rs. 2790.70 Cr. has been taken in the cost estimate for pipeline based on information provided by NRL.

Buildings Cost provision has been made for Road & Buildings based on approximate sizes and in-house cost data.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Effluent Treatment Plant

Cost provision has been made for RO based Effluent Treatment Plant based on in-house cost data. The facilities include treatment of Oily effluent, sanitary effluent, Spent caustic effluent and contaminated rain water.

Infrastructure facilities

A cost of Rs. 50 Cr. for Infrastructure has been considered in the cost estimate based on information provided by NRL.

Construction Site Facilities

A lump-sum cost provision has been made for items such as Construction Power, Construction Water, labour camp and Construction equipment etc.

Township

A cost of Rs. 100 Cr. for Township has been considered in the cost estimate based on information provided by NRL.

Owners Construction Period Expenses

Cost provision for owner’s construction period expenses has been made as per in-house norms for items such as project management, salaries & wages, environment clearances, feasibility reports, fund raising, recruitment, 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 on plant and machinery cost.

Contingency

Provision for contingency has been made @ 10% of capital cost excluding Pipeline, Interest during construction & Working Capital margin. 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 requirement is based on feedstock, intermediate and product storages, Pipeline, catalyst & chemicals, cash requirement for salaries & wages and utilities,




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

accounts payable & receivables. 25% of working capital has been capitalized as margin money.

Interest during construction

Interest during construction period required for the project has been worked out based on following:

Debt - Equity ratio : 2:1

Rate of interest : 12.0%

Construction period : 4 years

Details are given in Financial Analysis under Chapter 10

Based on the above assumptions and exclusions, Project cost summary for case A is attached as attachment I.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

ATTACHMENT-I

Project Cost Summary

PROJECT: NRL EXPANSION

COST ENGINEERING DEPARTMENT

Case-12CAPACITY JOB NO. A555

Fc Ic Total PROJECT NRL Expansion Project

1 LAND Existing CLIENT NRL

CAPACITY 6 MMTPA

2 SITE DEVELOPMENT 82 90 82 90 LOCATION NUMALIGARH

3ROYALTY / KNOW-HOW / BASIC

ENGINEERING196 76 94 54 291 30

4 EPCM SERVICES 632 90 632 90

4.1 SERVICE TAX ON EPCM SERVICES 78 23 78 23

5 PLANT & MACHINERY

A Main Processing Unit

A1 CDU/VDU 6.000 MMTPA 29 84 589 28 619 11

A2 NHT 0.968 MMTPA 15 23 200 35 215 58

A3 CCR 0.612 MMTPA 41 45 619 36 660 82

A4 ISOM 0.348 MMTPA 7 00 78 11 85 10

A5 HCU 1.988 MMTPA 134 71 944 39 1079 10

A6 DHDT 2.896 MMTPA 73 89 422 42 496 32

A7 SDA 0.755 MMTPA 5 50 126 02 131 52

A8 BBU 0.204 MMTPA 13 94 65 09 79 03

A9 DCU (Conventional) 1.144 MMTPA 208 47 659 22 867 69

EXCHANGE RATES

B Auxillary Units 1 USD = INR 60.0

B1 Hydrogen Generation Unit 1 x 78 KTPA 133 88 538 56 672 44

B2 Sulphur block (SRU/ARU/SWS) 2 X 210 TPD 78 87 358 20 437 06 CUSTOMS DUTY * 22.85%

B3 LPG treating Unit 18.0 TPH 1 63 16 61 18 24 EXCISE DUTY 12.36%

B4 Dismantling & Relocations 10 00 10 00 CST 2.00%

CATALYSTS & CHEMICALS 203 68 76 15 279 82 SERVICE TAX 12.36% on Engg. Services

SUB-TOTAL (UNIT) 948 09 4703 74 5651 83 VAT ON CONTRACTS 7.50%

6 UTILITIES & OFFSITES 20 63 1308 65 1329 29 ENTRY TAX 2.00%

7 CAPTIVE POWER PLANT 11 59 592 46 604 05

8 PILING 64 32 64 32

SUB-TOTAL (PLANT & MACHINERY) 980 32 6669 17 7649 49

9WORKSHOP & LABORATORY

EQUIPMENT5 00 5 00

10 ROADS & BUILDINGS 88 70 88 70

11 EFFLUENT TREATMENT PLANT 147 00 147 00

12 INFRASTRUCTURE 50 00 50 00

13 CONSTRUCTION SITE FACILITIES 26 10 26 10 Rajiv Agarwal

14 TOWNSHIP 100 00 100 00

PREPARED BY Sheina / S. Baishnab

15OWNER'S CONSTRUCTION PERIOD

EXPENSES11 50 65 00 76 50

REVIEWED BY Sanjiv Kumar

16 START UP & COMMISSIONING 19 12 57 37 76 49

TOTAL ( 1 to 16) 1207 70 8096 92 9304 62 APPROVED BY K K Chopra

17 CONTINGENCY 120 77 809 69 930 46

PROJECT COST

18 PIPELINE (Excl. IDC)* 2790 70 2790 70

19 WORKING CAPITAL MARGIN 920 96 920 96

TOTAL ( 1 to 18) 1328 47 12618 27 13946 75

20 INTEREST DURING CONSTRUCTION 756 26 756 26 Document No. A555-DR-6842-0001

RVISION NO. 0

DATE 4-Mar-14

PAGE 1 of 1

TOTAL PROJECT COST 1328 47 13374 53 14703 00 FILE NAMED:\Sheina\Refinery\DFR\A555_DFR_NRL_Exp

n\[A555_Cost Estimate_Units.xls]12

Format No. 5-6842-1000-F1 Rev 4

* Pipeline cost including IDC is Rs 3000 Crore

1st Quarter'2014

EXECUTION METHODOLOGY

Conventional

S U M M A R Y

* Basic Duty 5.0% + CVD 12% + E. Cess 3% + SAD 4%

PROJECT COST SUMMARY

ESTIMATE VALIDITY

PROJECT MANAGER

Sl. NO. D E S C R I P T I O N ALL COSTS ARE IN Rs. LAKHS

TYPE OF ESTIMATE

DFR




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 10 FINANCIAL ANALYSIS




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

10. FINANCIAL ANALYSIS

Based on capital cost, operating cost and sales revenue, financial analysis have been carried out for calculating internal rate of return (IRR) with a view to establish profitability of the project. The basis of financial analysis is as under:

1 Construction Period 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%

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

Annual operating cost has been computed considering costs towards crude prices, utilities and fixed operating cost (Salaries & wages, Repair & Maintenance @ 1% of Plant & Machinery, Administrative expenses@ 0.5% of plant & machinery and Insurance & taxes @ 0.5% of the capital cost). Annual Sales Revenue is based on product slate for various configurations and prices as provided by Client. Details of annual operating cost and Sales revenue are enclosed as Attachment I. Operating cost and Sales revenue for all the cases are 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 and financial analysis has been carried out for the Case A and the results are summarized below:




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

All cost in Rs Lakh

Sl.No. Description Values

1 Capital Cost 14703 00

2 Variable Operating Cost 22898 29

3 Fixed Operating Cost 244 42

4 Total Operating Cost 23142 71

5 Sales Revenue 25893 02

6 IRR (Pre Tax) on Total Capital 15.12%

7 IRR (Post Tax) on Total Capital 13.07%

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 (Note 1) 3) Case-A with 1.3 MMSCMD availability of NG (Note 2) 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 Note 1: Naphtha is considered for Hydrogen Generation Unit operation. Note 2: For Hydrogen Generation unit operation, Natural gas available is 66 TMT while balance requirement is met by LPG

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%




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

ATTACHMENT-I Annual Operating Cost and Sales Revenue

DOCUMENT NO. A555-FR-6842-0001

JOB NO. A555 REVISION NO. 0

PROJECT NRL Expansion Project DATE 5-Mar-14

CLIENT NRL PAGE NO. 1 of 1

COST ENGINEERING DEPARTMENT

Cost are in Rs. Lakhs

Base case Quantity in '000 Amount

A VARIABLE COST

1 CRUDE

1.1 Arab Light MT 33 461 18 00 6022 98

1.2 Arab Heavy MT 31 191 42 00 13100 22

1.3 LNG MT 18 587 4 93 916 35

1.4 SR kero from existing refinery MT 41 451 1 44 596 89

1.5 SR LGO from existing refinery MT 38 486 5 57 2143 68

2 PIPELINE

2.1 piasa/MT/KM 16 72000 00 115 20 6MM TPAx 1200 km

3 UTILITIES

RAW WATER m3 3.23 92 00 2 97 Rs.3.23 /MT

SUB-TOTAL A 22898 29

B FIXED OPERATING COST

1 SALARIES & WAGES Nos.

@ Rs. 19.65 for management

& 8.43 for non management

Lakhs/ Person / Annum

400 56 16

2 REPAIR & MAINTENANCE 1.0% of Plant & Machinery 76 49

3 GENERAL ADMINISTRATION 0.5% of Plant & Machinery 38 25

4 INSURANCE & TAXES 0.5% of Total Capital Cost 73 51

SUB-TOTAL B 244 42

TOTAL 23142 71Format no. 5-6842-2000-F5 Rev.4

ANNUAL OPERATING COST

S.No. DESCRIPTION / CASES

Prices (Rs./Unit)

Remarks

Case 12

Unit

JOB NO. A555 DOCUMENT NO. A555-FR-6842-0001

PROJECT NRL Expansion Project REVISION NO. 0

CLIENT NRL DATE 5-Mar-14

COST ENGINEERING DEPARTMENT PAGE NO. 1 of 1

Cost are in Rs. Lakhs

S.No. DESCRIPTION / CASES

Base Case Quantity in '000 Amount

REFINERY PRODUCT

1 MIXED LPG'S MT 400 24 2 58 1032 63

2 NAPHTHA EXPORT MT 336 26

3 EURO IV DOMESTIC GASOLINE MT 492 37 8 86 4362 40

4 EURO IV EXPORT GASOLINE MT 392 91 1 14 447 92

5 EURO V DOMESTIC DIESEL MT 423 50 92 389 62

6 EURO IV DOMESTIC DIESEL MT 419 27 40 31 16900 77

7 EURO IV EXPORT DIESE MT 406 19 3 85 1563 83

8 BITUMEN MT 345 43 2 00 690 86

9 SULFUR MT 49 92 1 23 61 40

10 LOW S FUEL OIL MT

11 ANODE GRADE COKE MT

12 ATF MT 424 70 53 225 09

13 PITCH MT Not for Sale

14 AROMATICNAPHTHASELL MT

15 COKE MT 60 00 3 64 218 49

TOTAL 25893 02

Format no. 5-6842-2000-F6 Rev.4

Case 12

Unit

SALES REVENUE

Remarks

Prices

(Rs /Unit)




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 11 CONCLUSIONS & RECOMMENDATION




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

11. 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 (306 TMT) natural gas the IRR again

improves to 11.02 %.

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.




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

Chapter 12 ANNEXURES




Document No.

A555-RP-0241-0001

Rev. No. A

of 125

ANNEXURE-1 OVERALL PLOT PLAN

KEY PLAN

NOTES :-N

3-1641-0500 REV.2 A0-1189 x 841

REFERENCE DRAWING TITLEREF. DWG. NO.

APPDCHKDREVISIONSDATE

SCALE REV.DWG. NO.DEPT.DIVN.UNITJOB NO.

BY

uqekyhxM+ fjQkbZujh fyfeVsM

LkEiwZ.k {ks= foU;kLk

SOLVENTDEOILING UNIT

WA

RE

HO

US

E

SLA

BB

ING

&

PA

CK

ING

UN

IT &

FINISHING UNIT

S.NO. TANK NO. SERVICE NO. OFTANKS

FLASHPOINT

NOM/STOR.CAPACITY(M )3 TYPE SIZE

DIA*H

40-TT-FR-101 A/B/C/D

44-TT-FR-102 A/B/C

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

44-TT-FR-104 A/B

44-TT-FR-105 A/B/C & 104C

44-TT-FR-106 A/B/C

41-TT-CR-107 A/B

41-TT-CR-108 A/B

41-TT-CR-109 A/B

41-TT-CR-110 A/B

41-TT-CR-113 A/B

41-TT-FR-114 A/B/C

41-TT-CFR-115 A & 115B

41-TT-CFR-115C

4

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

CRUDE OIL

NAPTHA

ATF

SKO

HSD

FUEL OIL(IFO)

VAC.RES.

RCO

VAC.DIST.

COK. DIST.

SLOPS(WET)

DRY SLOPSH2U FEED

NAPHTHA

3

3

2

4

3

2

2

2

2

2

1

3

1

22.6

22.6

38

35

35/38

>66

170

66

66

>66

44

<23

<23; >105

-

50000/49580

16880/15100

2530/1720

25900/2310023000/20700;

1200

7925/7400

7860/7820

12800/12541

2800

300

3130/2600

3650; 3850

16880/3650

F.R.

F.R.

C.F.R.

F.R.

F.R.

C.R.

C.R.

C.R.

C.R.

C.R.

C.R.

F.R.

C.F.R.

70.0*14.4

40.0*13.5

18.0*10.0

48.0*14.4

45.0*14.5 ;48.0*14.4

13.0*9.2

29.0*12.0

29.0*12.0

34.0*14.0

19.0*10.0

8.0*6.0

20.0*10.0

20.0*14.5; Do

40.0*13.5

SNO. SPHERE/BULLET NO. SERVICENO. OF

SPHERE/BULLETFLASHPOINT CAPACITY(M )3 SIZE

DIA. (M)

1.

40-TS-101A/B/C

44-VV-0032.

1. L.P.G.

L.P.G. 1

3

-

- 2117

70.6

TTL=9M

I.D.=3M

44-TT-FR-117 A/B15. ISOMERATE / 2 <23 5000 F.R. 25.5*12.0

44-TT-FR-118 A/B16. 2 <23 5000 C.F.R. 25.5*13.0REFORMATE

25900/23100

HYDRO-

SUB-STN.60x24

CHAIN LINK FENCINGTO BE DISMANTLED

WA

X C

/R59

x19.

1CW

TP

102

FOR MVGO / HVGOPROPOSED WAX EXCHANGERS

107X85

CT

CE

LLH

2SO

4 D

OS

ING

CWPH

CH

AN

NE

L CT

CE

LL

P I

P E

S

L E

E P

E R

(NE

W)

85x290

Vh-bZ-Q-vkj-

HCU

90x7

5

MAIN CONTROLROOM110x70

FLARE

VGO

VGO

DHT FEED

ISOMERATE

VR

VR

ETP

CRUDE CRUDE

CRUDE

CONSTRUCTIONYARD

ALTERNATE PROPOSED LOCATION FOR SECURED LAND FILLAREA=8870m2

CO

NS

TRU

CTI

ON

YA

RD

S/S

-2

CW

TP

DCU150x145

COKE STORAGEYARD

180x125

& CPUAREA FOR DM

POWER PLANT115x140

S/S-9

SR

RS

/S

SRR-5S/S-5

PR

OP

OS

ED

CT

CA/IG50x70

205x130

HGU120x85

SDA60x50

CDU/VDU/LPG TREATING UNIT

200x140

SRR-1DHT

120x89

S/S-1

S/S-3

PROPOSED FUEL OIL TANK

1. RAW WATER RESERVOIR & PH

2. FIRE WATER RESERVOIR & PH

3. NRL HSD & CONSUMER PUMP (PROPOSED DM & CPU LOCATION)

4. WEIGH BRIDGE (PROPOSED POWER PLANT LOCATION)

5. SOLID WASTE DISPOSAL YARD

6. INCINERATOR

7. CSS-4

8. CAUSTIC SOLUTION TANK (PROPOSED RWTP LOCATION)

9. BIOREMEDIATION UNIT

10. SLUDGE PIT

11. BANK & POST OFFICE PROPOSED COKE

12. EXCHANGE BUILDING STORAGE YARD

13. CRAFT TRAINING CENTRE

14. MICROWAVE TOWER

15. LPG SPHERE

16. LPG BULLETS

17. LPG TRUCK LOADING

PROPOSED SULPHUR BLOCK

PROPOSED HCU LOCATION

PROPOSED CA/IA LOCATION

PROPOSED CA/IG PLANT LOCATION

PROPOSED COOLING TOWER LOCATION

PROPOSED DCU LOCATION

S/S-4

BB

U11

5x65

DETAILED FEASIBILITY REPORT FOR NUMALIGARH...

Documents

Transcript of DETAILED FEASIBILITY REPORT FOR NUMALIGARH...