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Annexure-I
SUB: Brief description of the proposed facilities at Paradip Refinery (PDRP)
1.0 INTRODUCTION
1.1 Objective
This document gives brief description of the Paradip Refinery Project, including feedstocks, products, processing units and other connected facilities including utilities and offsites.
2.0 EXISTING FACILITIES
2.1 Overview
Though the Paradip Refinery Project is essentially a grass-roots project, nevertheless the project site has already seen some initial development in the form of a crude oil tank farm, which was recently constructed within the refinery boundary.
In addition, two other existing facilities - a nearby marketing terminal and a jetty facility at Paradip Port Trust - are to be modified to accommodate the additional feed and product movements which will result from the construction of the new refinery complex. In paradip port a new south dock is proposed, to take care of some of the PDRP Products throughout the year and crude unloading during monsoon period when SPM-2 may not be operable due to bad weather. The associated loading /unloading pipelines proposed to be laid in between southern side of the refinery and proposed south dock complex.
These existing facilities are described in the following paragraphs.
2.2 Refinery Site and IOCL Pipelines Division Tank Farm
The site selected for the Paradip Refinery Project was previously scheduled as the location for the 9 MMTPA Eastern India a refinery project refinery project - the 9 MMTPA Eastern India Refinery Project. Certain site preparation and civil works were partially completed before this project was abandoned, including ground improvements and the construction of some refinery roads, buildings, drains and boundary walls.
Recently, a new IOCL Pipelines Division Tank Farm, comprising 18 crude oil storage tanks, was constructed in the extreme south corner of the refinery plot area. This tank farm is owned and operated by IOCL Pipelines Division. It is proposed to receive and store crude oil imported from a Single Point Mooring (SPM) via a sub-sea pipeline for subsequent transfer by pipeline to the Barauni and Haldia refineries. This use will continue in future though it will be interconnected with additional crude storage tanks to be installed as part of the PDRP.
2.3 Marketing Terminal
The existing IOCL Marketing Terminal is located approximately 7 kilometers north of the refinery site. The terminal receives oil products via pipelines from Paradip Port - the route length of the pipelines is approximately 10.5 km. The IOCL Marketing Terminal is located adjacent to two other terminals (belonging to BPCL and HPCL) to which it is connected for the purposes of product transfer.
The Terminal receives oil products imported via Paradip Port. These are stored in the terminal and then loaded into road and rail tankers for despatch to customers.
The Terminal is to be further expanded in order to cater for the receipt of products from the new refinery and to handle increased road tanker movements, which will result from the implementation of the PDRP.
2.4 Paradip Port Trust
The Paradip Port Trust facilities are located at Paradip Port, approximately 11 km north-east of the refinery site.
Paradip is one of the major Ports of India and is the main terminal for sea borne trade in the area. The existing port facilities serve diverse industries including oil products, fertilizers, metal ores, grains, and coal. The port also handles general cargoes and containers and incorporates an integrated fishery harbour.
Indian Oil Corporation has recently installed a Single- Point Mooring (SPM-1) approximately 20 km off the coast to allow import of crude oil from Very LargeCrude Carriers (VLCCS) via sub-sea pipeline directly to the new Pipelines Division Tank Farm (note: this pipeline does not pass through the port area).A second SPM (SPM-2) and sub sea pipeline is also proposed for crude unloading for PDRP.
3.0 PARADIP REFINERY PROJECT (PDRP)
3.1 Overview
It is planned to implement the Paradip Refinery Project in two separate phases of work:
Phase 1: Paradip, Refinery Project - The Phase-1 project involves construction of a complete grass roots oil refinery and a first phase of petrochemical production units, plus all related utility and offsites facilities and supporting infrastructure. Crude oil processing capacity is 15 million tonnes per annum (15 MMTPA).
Phase 2: Naphtha Cracker Project - The Phase-2 project involves construction of a naphtha cracker complex and associated utility and offsite facilities in future. This is not a part of this write-up.
3.2 PDRP Phase 1 - Paradip Refinery Project
The Paradip Refinery Project involves the construction of an integrated refinery/petrochemical complex designed to produce a range of distillate oil and petrochemical products from 15 MMTPA of crude oil feedstock:
LPG Kerosene Dual Purpose kerosene Naphtha Motor spirit High speed diesel Paraxylene Styrene Polypropylene Petroleum coke Sulphur
Total upgrading of the heavy oil components present in the crude oil feed is accomplished within the refinery in Fluid Catalytic Cracking (FCC) and Delayed Coking units. Here, the heaviest distillate oils are mostly upgraded to diesel and
lighter products while excess carbon is rejected in the form of petroleum coke. Any unconverted heavy oils are consumed as internal fuel oil within the refinery.
Sulphur is produced as a byproduct of the desulphurisation processes in the refinery.
A listing and their respective process licensors and/or designers has been described in section 4.
The PDRP also includes all associated utility, offsite and infrastructure facilities to support the operation of the refinery complex.
Complete utility facilities designed to meet the refinery’s demands for cooling water, fuels, power, steam, water, instrument and plant air, inert gas, etc.
Offsite facilities including tankage for feedstocks plus intermediate and final products as well as systems for import and export of feed and products by various means including pipeline, road, rail and ship.
Other offsite facilities including flare, effluent treatment, firewater, jetty topsides, interconnecting piping and pipelines, etc.
Infrastructure required to support the PDRP (e.g. roads, buildings, etc.).
3.3 PDRP Phase 2- Naphtha Cracker Project
Phase 2 of the PDRP is anticipated to be based around a naphtha cracker complex with the aim of increasing the production of petrochemical products.
4.0 PROCESS LICENSORS AND DESIGNERS
The PDRP process units have been designed by technology providers according to the following list.
Unit Designer / Licensor
‘Open-Art’ UnitsAtmospheric Vacuum Unit (AVU)Hydrogen Compression & Distribution (HCDS)Sour Water Stripper (SWS)Amine Regeneration (ARU)
Licensed Process UnitsSR LPG TreaterNaphtha Hydrotreater (NHDT)CCR PlatformerCCR RegeneratorSulfolaneBenzene / Toluene FractionationTransalkylation (Tatoray)Xylene FractionationParaxylene Separation (Parex)Xylene Isomerisation (lsomar)Kerosene Treater (KTU)Diesel Hydrotreater (DHDT)VGO Hydrotreater (VGO HDT)Fluid Catalytic Cracker (FCC)Ethylene Recovery / Ethyl benzene / Styrene Monomer (ER / EB / SM)FCC LPG TreaterPropylene Recovery (PRU)
Foster WheelerFoster WheelerFoster WheelerFoster Wheeler
UOPUOPUOPUOPUOPUOPUOPUOPUOPUOPMerichemShell Global SolutionsAxensABB Lummus / IOCLABB Lummus
MerichemBasell
Polypropylene (PPU)FCC Light Naphtha TreaterDelayed Coker (DCU)Coker LPG TreaterAlkylation (incl. Di-olefin Saturation)Butane lsomerisation (Butamer)Hydrogen Generation (HGU)Sulphuric Acid Regeneration (SAR)Flue Gas Desulphurisation (FGD)
‘Package’ Units (LSTK basis)Sulphur Recovery Units (SRU)Tail Gas Treating (TGT)
BasellMerichemFoster WheelerEILExxon MobilExxon Mobil / UOPHaldor TopsoeMECSCansolv
Black & Veatch Black & Veatch
5.0 FEEDSTOCKS
5.1 Crude Oil
The refinery will process imported crude oil. The selected potential crude oil feed stocks are :
• Kuwait Export
• Maya
• Oman Export
• Ratawi
• Basrah Light
• Kuito
Refinery will have sufficient design flexibility to be able to process a range of crude oil feedstocks at the design crude capacity of 15 MMTPA, and the following cases were selected to represent the required design envelope:
Base crude case : Kuwait Export
Light/sweet crude case : 50% Oman Export / 50% Basrah Light
Heavy / sour crude case : 60% Kuwait Export / 40% Maya
In general terms, the sweet/light crude case determines the capacity of the upper part of the crude distillation section within the AVU and of the downstream units processing naphtha and lighter cuts, whereas the heavy/sour crude case sets the design capacity for sections of the plant processing heavy cuts and residue.
5.2 Benzene
Benzene shall be partly imported to the refinery in addition to its own production from aromatic block as supplementary feedstock for producing Ethylbenzene (EB).
6.0 PRODUCT DEMANDS
The configuration of the Refinery and the capacities of the facilities is based on the maximum product demand envisaged for domestic and export markets which is given below.
Product‘000 tonnes per annum (KTPA)
Domestic Export
LPG No limit Nil
Naphtha Nil 1501
Paraxylene 800 400
Styrene 300 300
Poly Propylene 450 400
MS Regular 100 Nil
MS Premium Nil No limit
DPK 870 800
HSD 821 No limit
Actual production rates resulting from the chosen refinery configuration are given in Section 7.
7.0 REFINERY CONFIGUATION AND MATERIAL BALANCES
7.1 Introduction
The design of the process units is based on the following design feed cases.
60% Kuwait Export / 40% Maya - to represent a “heavy sour” crude blend design case
50% Oman / 50% Basrah Light - to represent a “light sweet” crude blend design case
100% Kuwait Export - representative of ‘normal’ operation
In effect, the first two crude cases set the “design envelope” for the refinery.
The material balance for each of these cases is presented in the tables below; data is presented on the following basis:
Annualised basis (thousands of tonnes per annum, KTPA).
Imported electric power.
Steam boilers firing vacuum residue fuel (with FGD).
7.2 60% Kuwait Export / 40% Maya Crude Blend
The overall material balance is as follows:
FEEDS KTPAKuwait Export 9,000Benzene import 66Basrah 0Oman 0Maya 6,000Total 15,066
PRODUCTS KTPALPG 675Export Naphtha 459Regular Gasoline 100Premium Gasoline 1,372Domestic Kero 870Export Kero 285HSD (10 ppm S) - Domestic 821HSD (10 ppm S) - Export 4,435Coke 1,156Polypropylene Domestic 450Polypropylene Export 194Paraxylene Domestic 800Paraxylene Export 266Styrene Domestic 300Styrene Export 300Sulphur Product 350Refinery Fuel 2,106Loss 127Total 15,066
7.3 50% Oman / 50% Basrah Light Crude Blend
The overall material balance is as follows:
FEEDS KTPAKuwait Export 0Benzene import 38Basrah 7,500Oman 7,500Maya 0Total 15,038
PRODUCTS KTPALPG 765Export Naphtha 599Regular Gasoline 100Premium Gasoline 1,514Domestic Kero 870Export Kero 280HSD (10 ppm S) - Domestic 821HSD (10 ppm S) - Export 4,551Coke 635Polypropylene Domestic 450Polypropylene Export 220Paraxylene Domestic 800Paraxylene Export 334Styrene Domestic 300Styrene Export 300Sulphur Product 292Refinery Fuel 2,119Loss 88Total 15,038
7.4 100% Kuwait Export Crude
The overall material balance is as follows:
FEEDS KTPAKuwait Export 15,000Benzene import 3Basrah 0Oman 0Maya 0Total 15,003
PRODUCTS KTPALPG 716Export Naphtha 617Regular Gasoline 100Premium Gasoline 1,591Domestic Kero 854Export Kero 0HSD (10 ppm S) - Domestic 821HSD (10 ppm S) - Export 4,471Coke 813Polypropylene Domestic 450Polypropylene Export 214Paraxylene Domestic 800Paraxylene Export 400Styrene Domestic 300Styrene Export 300Sulphur Product 331Refinery Fuel 2,150Loss 75Total 15,003
7.5 Nameplate Capacities for Process Units
7.5.1 Introduction
The nameplate capacities for individual process units have been determined based on the annual material balances presented above plus consideration of appropriate on-stream factors - for determination of stream-days - and design margins - to allow for design uncertainties and operational flexibility.
7.5.2 Turnaround Frequency and On-stream Factor
The refinery is designed to operate continuously for a minimum period of five (5) years between major turnarounds, albeit that some process units may require ‘interim’ shutdowns for catalyst regeneration, etc.
7.5.3 Unit Capacities
Unit capacities are presented in the table below and are quoted on an annualised mass flow basis of feedstock.
Corresponding unit ‘nameplate capacities’ which reflect throughput per operating day considering on-stream factors, etc., are defined in the design basis documents for each unit.
Unit KTPA Capacity BasisAtmospheric Vacuum Unit 15,000SR LPG Treater 210Naphtha Hydrotreater 3,960CCR Platformer 2,980Paraxylene 1,200 PX productKerosene Treater 1,200Diesel Hydrotreater 5,200VGO Hydrotreater 5,400Fluid Catalytic Cracker 4,170FCC LPG Treater 1,850FCC Light Cat Naphtha Treater 400Alkylation / Butane Isomerisation 650 Alkylate productPolypropylene 707 PP productStyrene Monomer 600 SM productDelayed Coker Unit 4,100Coker LPG Treater 165Sulphuric Acid Re-generation Unit 185 TPDHydrogen Generation Unit 72.8 Hydrogen product (Note A)Anime Regeneration - Train 1 454.6 m3/hr Amine circulationAmine Regeneration - Train 2 898.5 m3/hr Amine circulationSour Water Stripper - Train 1 397.7 m3/hr Sour water feedSour Water Stripper -Train 2 227.2 m3/hr Sour water feedSulphur Recovery Units 3 x 525 TPD Sulphur productTail Gas Treating Note BNotesA. Expressed as 100% hydrogen. The centralized hydrogen compression and distribution system
(HCDS) is designed to distribute 165.8 KTPA of hydrogen to consumers.
B. Tail gas treating (TGT) is part of SRU. TGT is configured as 2 x 100% trains.
8.0 REFINERY PROCESS UNITS
8.1 Atmospheric Vacuum Unit (AVU)
The AVU processes crude oil to produce a range of straight-run distillate products plus vacuum residue intended for further processing within the refinery.
The AVU comprises a classical arrangement of three main distillation sections which are designed as a single, integrated plant:
Crude distillation section (CDU)
Naphtha stabilisation section (NSU)
Vacuum distillation section (VDU)
Primary separation of crude oil is achieved in the crude distillation section (CDU). This section incorporates desalting to reduce the salt content of the crude oil. The main products from the CDU are:
A naphtha stream which passes to the naphtha stabilisation section for further processing.
Kerosene which is normally routed to the Kerosene Treating Unit, however provision is made to route a portion to the Diesel Hydrotreating Unit in case of high sulphur content.
Atmospheric gas oils (light and heavy) which are combined and routed to the Diesel Hydrotreating Unit.
Atmospheric residue which is sent forward to the vacuum distillation section.
The naphtha and lighter materials from the CDU pass to the naphtha stabilisation section (NSU) where they are separated into products, namely:
Sour fuel gas which is sent to fuel gas via amine treating.
LPG which is first treated to remove H2S and mercaptans in a separate SR LPG Treater unit before it is returned to the NSU section for splitting into separate propane and butane products. The butane fraction is routed as feedstock to the Alkylation unit and/or to LPG product storage. The propane fraction is routed to LPG blending and product storage.
Stabilised naphtha is sent to hydrotreating and/or product blending.
The vacuum distillation section recovers additional distillate materials from the atmospheric residue feed by distillation under vacuum. The main products are:
Vacuum diesel which is sent to Diesel Hydrotreating and/or to refinery fuel oil blending.
Vacuum gas oil which is sent to the VGO Hydrotreater.
Heavy vacuum gas oil which is normally combined with VGO and sent to VGO Hydrotreater but may be routed instead to the Delayed Coker in case of high asphaltenes content.
Vacuum residue, the bottom product, which is sent to the Delayed Coker Unit.
The fuel gas treating section in the AVU receives sour waste gases from the AVU and the Naphtha Hydrotreater Unit and treats them with amine solvent to remove hydrogen sulphide (H2S) in order to produce sweet gas for blending into the refinery’s fuel gas distribution system.
8.2 SR LPG Treating Unit
The Saturated LPG Treating Unit receives straight-run LPG from the AVU plus LPG from the VGO Hydrotreater. This combined stream is processed in SR LPG treating unit to remove H2S and mercaptans in an amine wash and caustic Merox system. The treated LPG is then returned to the AVU for splitting into separate propane and butane fractions.
8.3 Kerosene Treater Unit
The Kerosene Treater Unit (KTU) processes straight-run kerosene from the AVU to produce a sweet kerosene product. The unit employs extractive mercaptans oxidation technology.
8.4 Diesel Hydrotreater Unit
The Diesel Hydrotreater Unit (DHDT) processes straight-run gas oil (diesel) streams from the AVU plus the Coker Light Gas Oil (CLGO) product from the Delayed Coker unit and a portion of the Heavy Cat Naphtha (HCN) and Light Cycle Oil (LCO) from the FCC Unit in order to produce an ultra low-sulphur diesel product.
The primary product - high speed diesel (HSD) with max. 10 ppm wt sulphur content - is routed to diesel product storage and blending. The unit also produces a small naphtha by-product stream which is routed to the Naphtha Hydrotreater Unit.
Provision is also made within the DHDT for the co-processing of a portion of straight-run kerosene from the AVU and for its subsequent recovery in an adjoining kerosene splitter section. The flexibility to hydrotreat a portion of kerosene in this manner enables the refinery to meet the total sulphur specification for kerosene product when processing crude blends (e.g. Kuwait/Maya) which have a high sulphur content.
8.5 VGO Hydrotreating Unit (VGO HDT)
The VGO Hydrotreating Unit (VGO HDT) pre-treats the vacuum gas oil feed to the downstream Fluid Catalytic Cracker Unit (FCC) in order to reduce the sulphur content of VGO sufficiently to satisfy downstream product quality requirements and to minimise the sulphur dioxide content of flue gases emitted to atmosphere from the FCC regenerator.
The feed to the VGO HDT comprises straight-run VGO from the AVU and Coker Heavy Gas Oil (CHGO) from the Delayed Coker Unit.
The primary product from the VGO HOT is hydrotreated VGO containing less 600 ppm wt (max) sulphur; this stream is fed directly to the FCC unit for conversion.
A secondary product is a hydrotreated diesel cut (sulphur content 10 ppm wt max.) which is routed to diesel product storage and blending.
Other by-products from the VGO HDT include:
Off-gases - routed to the refinery fuel gas system.
MP hydrogen-rich gas - routed to HCDS for recovery.
LPG - routed to the LPG Treater and Splitter unit.
Stabilised naphtha - routed to naphtha and gasoline product storage and blending.
8.6 Fluid Catalytic Cracking Unit (FCC)
The Fluid Catalytic Cracking Unit (FCC) converts vacuum gas oil feedstocks into more valuable lighter oil products and petrochemical feedstocks. The design of the unit is primarily tailored to maximise the yields of ethylene and propylene for use as feedstocks to downstream petrochemical production units. Cat cracked naphtha is the main secondary product.
The main feedstock is hydrotreated vacuum gas oil received directly from the VGO HDT. The unit also processes a small light naphtha by-product stream produced in the Delayed Coker unit.
The FCC produces the following main products:
Offgas - this stream is rich in ethylene. It is treated for the removal of H2S and CO2 within the FCC unit before being routed as feedstock to the Ethylbenzene/Styrene Monomer complex where the ethylene is recovered, purified and then converted into styrene.
Unsaturated LPG - this sour stream contains a proportion of propylene. It is first routed for treatment to remove of H2S and sulphur compounds in the FCC LPG Treater Unit before being sent as feedstock to the Propylene Recovery / Polypropylene complex.
Light cat naphtha - the LCN stream is a high octane gasoline blending component. It is sent to the Light Cat Naphtha Treating Unit for sweetening prior to rundown to gasoline storage and blending.
Medium cat naphtha - the MCN stream is routed to the Naphtha Hydrotreater Unit.
The FCC also produces a number of by-products:
Heavy cat naphtha - HCN is routed to the Diesel Hydrotreating Unit
Light cycle oil - LCO is routed either to refinery’s internal fuel oil system or as feedstock to the Diesel Hydrotreating Unit.
Clarified oil - this material is routed to the refinery’s internal fuel oil system, or as feedstock to the Delayed Coker Unit.
8.7 FCC LPG Treating Unit
Unsaturated, sour LPG produced within the FCC unit requires treatment to remove hydrogen sulphide (H2S), carbonyl sulphide (COS), carbon disulphide (CS2) and mercaptan (R-SH) contaminants before it can be passed forward to the Propylene Recovery / Polypropylene Units (PRU/PPU)
The FCC LPG Treatment Unit uses successive amine and caustic washes in a classical ‘sweetening’ process to remove these sulphur bearing contaminants from the LPG. The sweet LPG product is then routed to the PRU/PPU.
8.8 FCC Light Naphtha Treating Unit
FCC light cat naphtha requires treatment to remove mercaptans before it can be sent for blending into the gasoline pool, therefore a FCC Light Naphtha Treating unit is provided to sweeten the naphtha.
8.9 Alkylation and Butane Isomerisation
This section comprises two separate process units: a Sulphuric Acid Alkylation Unit and a Butane Isomerisation Unit.
The Alkylation process is designed to produce a high-octane gasoline blending component - alkylate - which will be used, via blending, to raise the octane number of the refinery’s product gasoline pool. The unit incorporates a di-olefin saturation (DIOS) section.
The main feedstocks to the unit are:
Sweet, saturated C4 (primarily n-butane and isobutane) from the AVU.
Sweet, saturated LPG (primarily propane, n-butane and isobutane) from the CCR P!atformer Unit.
Sweet, unsaturated C4 (primarily butylenes and isobutane) from the Propylene Recovery Unit.
The Alkylation process is catalysed by sulphuric acid and achieves the chemical combination of isobutane with the C4 olefins (butylenes) to form an iso-octane rich alkylate product.
Because the LPG feed streams contain insufficient isobutane to alkylate all the available olefins in the unsaturated LPG feed, a separate Butane Isomerisation Unit is included in the process scheme; this converts n-butane to isobutane and hence satisfies the isobutane demand.
The primary product from the Alkylation and Butane lsomerisation unit is stabilised, high-octane (96 RON) ‘alkylate’ which is routed to storage and/or to gasoline blending.
Propane is recovered as a by-product stream and sent to LPG product storage and blending.
The concentrated sulphuric acid catalyst is gradually degraded in the alkylation process and a slipstream is continuously withdrawn, regenerated and returned to maintain acid strength and purity. The acid regeneration is achieved in a separate facility within the refinery.
8.10 Delayed Coker Unit (DCU)
The Delayed Coker Unit (DCU) upgrades vacuum residue feedstock received from the AVU to produce a range of cracked, distillate oil products which, after further refining in downstream units, are suitable for blending into final products and/or as petrochemical feedstocks. Delayed coking is a thermal cracking process and excess carbon is rejected in the form of petroleum coke which is produced in significant quantities.
The feed stream to the DCU is vacuum residue produced in the vacuum distillation section of the AVU. In addition, to enable the refinery to process heavy crude oils with a high asphaltenes /metals content, provision is made for the heaviest side cut (HVGO) from the vacuum distillation column to be blended in to the DCU feed. This provides the refinery with a convenient means of limiting the asphaltenes (and/or metals) content of the VGO feedstock sent forward to the VGO Hydrotreater within acceptable limits; the impact on the DCU operation is insignificant.
The DCU produces a range of cracked distillate products which are routed as follows:
Fuel gas - this is sweetened within the DCU and then routed to the refinery fuel gas system.
Coker LPG - this is routed via the Coker LPG Treating Unit to the Propylene Recovery / Polypropylene Unit.
Coker light naphtha - this is routed to the FCC unit.
Coker heavy naphtha - this is sent as feedstock to the Naphtha Hydrotreater Unit.
Light coker gas oil / coker diesel - LCGO is routed as feedstock to the Diesel Hydrotreater Unit.
Heavy coker gas oil - HCGO is routed as feedstock to the VGO Hydrotreater Unit.
The other main product from the DCU is petroleum coke. This is conveyed to a coke storage and handling area prior to despatch to external customers.
8.11 Coker LPG Treating Unit
Unsaturated, sour LPG produced within the Delayed Coker Unit requires treatment to remove hydrogen suiphide (H2S), carbonyl sulphide (COS), carbon disulphide (CS2) and mercaptan (R-SH) contaminants before it can be passed forward to the Propylene Recovery / Polypropylene Units (PRU/PPU).
The Coker LPG Treatment Unit uses amine and caustic washes in a classical ‘sweetening’ process to remove these sulphur bearing contaminants from the LPG. The sweet LPG product is then sent forward to the PRU/PPU.
8.12 Hydrogen Generation Unit (HGU)
The Hydrogen Generation Unit (HGU) utilises steam-methane reforming of hydrocarbon feedstock to produce a hydrogen-rich gas product which is purified in a Pressure Swing Adsorption unit(PSA unit) to yield hydrogen with a minimum purity of 99.9 mol% hydrogen.
The HGU operates in turndown mode during normal refinery operation because the majority of the hydrogen demand is satisfied by hydrogen production from the Platformer. Maximum demand for hydrogen from the HGU occurs during a shutdown scenario in which the CCR Platformer is shutdown, but the Diesel Hydrotreater, VGO Hydrotreater and Polypropylene units continue in operation at 50% turndown.
The preferred hydrocarbon feedstock to the HGU is the ‘raffinate’ by-product stream from the Sulfolane Extraction process in the Aromatics complex. However, provision is made for the unit to accept other sweet naphtha streams and LPG as alternative feedstocks. Natural gas is also foreseen as a potential future feedstock and limited provisions are made in the HGU design to facilitate a future introduction of NG feed.
Hydrogen products from the Platformer and HGU are routed to a centralised Hydrogen Compression and Distribution System (HCDS) which serves the refinery.
8.13 Hydrogen Compression and Distribution System
Hydrogen treat gas used within the refinery is derived from two main sources:
The CCR Platformer Unit (which provides a base load supply during normal operation)
The Hydrogen Generation Unit (which supplies the balance to satisfy total demand)
Both of these streams are routed to the Hydrogen Compression and Distribution System (HCDS).
The HCDS also receives hydrogen rich off-gases from the Styrene Monomer and VGO Hydrotreater units these streams contain sufficient hydrogen to warrant recovery and a small PSA section is employed for this purpose.
The various purified hydrogen streams (minm. purity 99.9 mol%) are then combined and distributed to all hydrogen consuming units within the refinery. Three distribution pressure levels (LP/MP/HP) are provided to align with user requirements: the two higher pressure levels are achieved via a two-stage compression system.
The hydrogen distribution pressures are set to eliminate the need for separate hydrogen make-up compressor systems within any of the consuming units.
8.14 Sour Water Stripper Units (SWS)
Sour waters produced within the refinery complex are treated to remove contaminant hydrogen sulphide and ammonia in the sour water stripper units. The sour gases (hydrogen sulphide and ammonia) recovered from the sour water streams are routed to the sulphur recovery unit for recovery of elemental sulphur.
The sour water stripper is configured as two separate trains in order to segregate the treatment of sour waters from different sources; the routings of the most significant sour water streams are indicated in the table below:
SWS Train 1(Phenolic)
AVU
FCC
DCU
SWS Train 2(Hydroprocessing)
Naphtha HDT
Diesel HDT
VGOHDT
SWS Train 1 will process sour water streams from the other process units. Some of these streams will be contaminated with traces of phenols, cyanides and other contaminants which are by-products of thermal cracking reactions. Re-use of stripped water from these sources within the hydroprocessing units is to be avoided; instead it is preferred to route these stripped waters as wash water for desalting since this provides an opportunity for phenols and cyanides to be re-absorbed into crude oil, thus minimising the duty of the effluent treatment plant.
SWS Train 2 will process ‘clean’ sour waters from the hydroprocessing units and other units which do not involve thermal cracking reactions. These sour waters are relatively ‘clean’ - they contain minimal other contaminants - and, after stripping, are suitable for partial recycle for use as wash water within the hydroprocessing units.
The two sour water stripper units will operate in segregated mode; however, they shall be interconnected to provide a limited degree of load sharing in case one unit is required to shutdown for emergency maintenance.
8.15 Amine Regeneration Units (ARU)
Lean amine solvent (DEA) is used in absorber and extractor columns within the refinery to remove hydrogen sulphide from gas and LPG streams. Carbon dioxide is also scrubbed from FCC off gases fed to the EB/SM unit. The rich amine solvent is returned to a centralised amine regeneration system where hydrogen suiphide gas is recovered and routed to sulphur recovery and regenerated lean solvent is recycled to users.
The Amine Regeneration system is configured as two separate trains in order to segregate the amine solvent which has contacted ‘cracked’ streams originating in the FCC and Coker (Train 1) from amine which is used within the main hydroprocessing units (Train 2).
The two-amine regeneration units will operate in segregated mode; no inter-connections are provided.
8.16 Sulphur Recovery Units (SRU) and Tail Gas Treating (TGT)
The Sulphur Recovery Unit (SRU) takes acid gas feed from the ARU , SWS and SO2 rich stream ex FGD and converts hydrogen sulphide (H2S) into elemental sulphur using a modified version of the classic Claus sulphur recovery technology. The SRU is also equipped with sulphur degassing systems and amine-based Tail Gas Treating (TGT) units in order to achieve a very high percentage recovery of sulphur present in the acid gas feeds. Tail gas incineration is used to convert residual traces of H2S in the tail gas into SO2. Ammonia present in the acid gas feed from the SWS is destroyed in the burners of the SRU.
The SRU is configured as 3 x 50% units in order to provide a very high availability factor. The TGT section and tail gas incinerators are each configured as 2 x 100% units for the same reason.
Feed streams to the SRU are acid gases from the Amine Regeneration Units, and sour gases from the Sour Water Stripper units, plus sulphur dioxide from the Flue Gas Desulphurisation unit.
Sulphur product is exported in both liquid and solid (granular) forms.
8.17 Sulphuric Acid Regeneration Unit (SAR)
Concentrated sulphuric acid is used as a catalyst within the Alkylation Unit. The acid is slowly degraded in the alkylation process so a continuous purge of spent acid is removed and sent for regeneration in an on-site regeneration facility.
The Sulphuric Acid Regeneration Unit processes the spent acid to produce a regenerated acid stream which is returned to the Alkylation unit. The process involves thermal decomposition of the spent acid to sulphur dioxide, then conversion to sulphur trioxide and back into sulphuric acid.
9.0 PETROCHEMICAL PROCESS UNITS
9.1 Aromatics Complex
The Aromatics Complex comprises the following process units.
Naphtha Hydrotreater (including naphtha fractionation) CCR Platformer CCR Regenerator section Sulfolane Benzene / Toluene Fractionation Transalkylation (Tatoray) Xylene Fractionation (incl. Reformate splitter) Paraxylene Separation (Parex) Xylene Isomerisation (Isomar)
Incoming naphtha feeds (full range naphtha from the AVU plus naphtha streams. from the FCC and Coker and a small benzene/toluene stream from the EB/SM unit) are pre-treated in the Naphtha Hydrotreater and then fractionated into three separate hydrotreated naphtha products. The light and heavy cuts are sent to naphtha/gasoline blending while the heart-cut is fed forward via the CCR Platformer into an integrated arrangement of classic aromatics units.
The primary products from the aromatics units are:
Paraxylene - sent to product tankage
Benzene - an intermediate product which is subsequently consumed as feedstock for the Ethylbenzene/Styrene Monomer complex.
Excess A9/A10 aromatics stream from Xylene fractionation - sent to gasoline blending.
By-products include:
A raffinate stream from the Sulfolane unit - used as preferred feedstock to the Hydrogen Generation Unit or as a gasoline blending component.
A heavy aromatics stream from Xylene fractionation - to refinery fuel oil.
A hydrogen-rich gas stream from the Platformer PSA unit which is routed to the refinery’s Hydrogen Compression and Distribution System.
9.2 Ethylene Recovery / Ethylbenzene / Styrene Monomer Unit (ER / EB/ SM)
The EB/SM complex converts benzene and ethylene feedstocks into styrene monomer product. There are three main elements to the process scheme: ethylene recovery and purification, ethylbenzene production and styrene monomer production.
The feedstocks are 1) sweet ethylene-rich gas from the FCC unit and 2) benzene either directly from the benzene fractionation section within the Aromatics complex or imported benzene from storage.
The EB/SM complex produces a single main product - styrene monomer - which is routed to product storage.
By-products comprise a small benzene/toluene by-product stream is routed back to the Aromatics complex, a hydrogen-rich offgas stream which is routed to the HCDS for hydrogen recovery, and off gases which are routed to fuel gas.
9.3 Propylene Recovery & Polypropylene Units (PRU/PPU)
The Propylene Recovery Unit (PRU) and Polypropylene Unit (PPU) receive treated, unsaturated LPG feeds from the FCC and the Delayed Coker units. The propylene content is first extracted and purified to yield propylene in the PRU section. The propylene is then fed forward into the polypropylene unit for manufacture of homopolymer polypropylene product.
The unsaturated LPG feed streams containing propylene are derived from the FCC Unit and the Delayed Coker Unit. Both feed streams are pre-treated for removal of H2S, COS and mercaptans, etc. in upstream LPG Treating units. The polypropylene process also consumes hydrogen gas, which will be supplied from the Hydrogen Compression and Distribution System.
The primary product from the PRU/PPU is polypropylene homopolymer. However, the PPU design includes provisions for a future upgrade to allow the production of random copolymer, terpolymer and impact copolymer at a later date.
Each polypropylene product is capable of being produced in different grades according to the end-use. End-uses for homopolymer include injection moulding, blow moulding, thermoforming sheet, tape/raffia, fibre and films.
The PRU/PPU also produces a number of by-products:
Propane from PRU section - routed to LPG product storage.
Unsaturated C4s from PRU section - routed to Alkylation Unit and/or to LPG product storage.
Offgas from PPU section - routed to fuel gas system.
10.0 OFFSITE SYSTEMS
10.1 Crude Oil Import, Storage, Blending and Pumping
Crude oil is imported to the refinery by marine tankers. Normally, crude oil is proposed to unload from Very Large Crude Carriers (VLCC) via an existing SPM and sub- sea pipeline (operated by IOCL) into new crude oil storage tanks located within the, refinery. A second SPM and sub-sea pipeline are to be
installed to increase crude handling capacity. The onshore pipelines from the two SPMs will be interconnected to provide flexibility for import of crude from either SPM to either of the crude tank farm ..
However, to cater for periods when the SPM cannot be used due to bad weather, provision is made for crude oil import by a new crude pipeline from crude tankers moored at the new southern jetty at Paradip Port.
10.2 Intermediate and Finished Product Storage, Blending and Pumping
Storage and transfer facilities are provided for some intermediate and all finished liquid products produced within the refinery complex. Materials to be stored and handled include oil products (ranging from LPG through to vacuum residue) plus petrochemical products such as Benzene, Paraxylene and Styrene. Other materials to be stored and handled include internal fuel oil and various slop oils. Solid products and sulphur.
In-line blending of component rundowns from individual units into final product tanks is used to achieve required finished product specifications; this applies particularly to gasoline and diesel products.
The required storage volumes for finished products are based on despatch volumes and other factors. The storage capacities for intermediate products are based either on licensors recommendations or determined based on the refinery shutdown philosophy.
Pumping capacities for final products are based on despatch requirements determined by the destination - the marketing terminal, the jetty, or direct to road tankers - as appropriate. Transfer rates for intermediate products are determined by process requirements.
10.3 LPG Refrigerated and Pressurized Storage
LPG is to be stored in pressurized form in mounded bullets and refrigerated in atmospheric storage tank. Refrigerated LPG is to be dispatched through ship from port and pressurized LPG through road tanker from refinery. Facility also to be provided for transfer pressurized LPG to Marketing Terminal.
10.4 Sulphur Storage, Handling, Forming and Despatch
Liquid sulphur is produced by the Sulphur Recovery Units and routed to liquid sulphur storage tanks prior to despatch by pipeline and/or road tankers to nearby customers. Provision shall also be made to produce a solid granular sulphur product.
10.5 Polypropylene Storage and Transfer
Solid polypropylene product - in pellet form - is produced in the Polypropylene unit. The polypropylene storage and transfer system receives the raw product and prepares batches of homogenised polypropylene product for storage in bulk silos. The homogenised product is then either bagged and palletised for despatch by truck, or conveyed into bulk containers for export by sea.
10.6 Marketing Terminal and Jetty Systems
The following provisions are made for transfer/export of liquid oil products fromthe refinery:
By pipelines to jetty - the majority of liquid products are despatched by pipelines to new marine loading facilities at Paradip Port.
By pipelines to IOCL Marketing Terminal - small proportions of liquid products (LPG, HSD, Kerosene, DPK and MS) shall be sent by separate pipelines to the existing IOCL Marketing Terminal for subsequent despatch by road and rail.
By inland pipelines - piping connections within the refinery shall be provided to enable HSD, DPK and MS products to be transferred directly to inland pipelines operated by IOCL Pipelines Division.
By road truck - Provision shall be made for dispatch LPG, Coke, Polypropylene, Sulphur & Benzene by road from the refinery.
10.7 Flare & Blowdown Systems
The refinery flare and Blowdown system collects and safely disposes of liquid and gaseous releases from the refinery complex. The peak release rates occur as a result of abnormal and emergency situations which may affect the whole refinery (e.g. power failure), but the system also handles small continuous releases of waste materials arising from normal operation.
Several separate flare collection and disposal systems are provided for the refinery complex in order to segregate releases based on consideration of origin (composition), pressure and flowrate.
Gaseous releases are burnt at the flare tip; liquid releases are collected in knock-out drums and returned for recovery. A brief description on flare and blow down system is attached as Annexure-I
10.8 Effluent Treatment
Waste water streams arise in the refinery from a number of different sources, including process operations, maintenance, rainfall and sanitary waste. The waste water streams are normally segregated at source according to their origin These wastewaters then pass separately to the Effluent Treatment Plant where treatment occurs according to the particular need. Typical treatment steps include oil separation, neutralisation, bio-treatment, solids removal and water recovery. In order to minimise the refinery’s demand for fresh water from external supplies, as much treated effluent water as possible is recycled for re-use within the refinery. The residual reject water is disposed off to sea via an outfall.
10.9 Oily Spent Caustic Treatment
Wet air oxidation is used to treat oily spent caustic streams arising from refinery operations. The treated stream is discharged to the Effluent Treatment Plant.
10.10 Waste Disposal
Various liquid and solid wastes arise from the operation of the refinery complex, including spent catalysts, ETP sludge, waste oils, used filter cartridges, ash, municipal waste and other waste materials. The treatment and disposal of these waste materials shall be carefully managed.
10.11 Wastewater Drainage and Collection System
Several separate wastewater drainage systems are provided in order to allow segregation at source of wastewaters arising from different sources. Segregation is made according to the anticipated composition of the water. Such segregation allows the routing of different waste water streams to appropriate treatment steps within the effluent treatment scheme. Individual drainage and collection systems comprise sewers, collection ponds, sumps and transfer pumps.
10.12 Fire Protection System
The fire protection system for the refinery complex includes automatic fire and gas detection systems at appropriate locations within the refinery plus various fire fighting facilities. The latter includes firewater supply and distribution systems, foam systems, carbon dioxide systems, fixed and mobile fire fighting equipment. Safety equipment, fireproofing and fire training facilities are also specified. Details Fire Protection Facilities is enclosed as Annexure-III .
10.13 Coke Handling and Despatch System
Petroleum coke is produced in substantial quantities in the Delayed Coker Unit. Coke dewatering, crushing and sieving will be accomplished on-plot within the DCU battery limit. The coke is then transferred by conveyor to be stored within the refinery in open coke piles before it is loaded into trucks.
The coke handling and despatch facilities include the coke stockpiles with their associated stacker and declaimer systems plus all necessary coke hoppers, conveyors, silos, and truck loading systems. Facilities are also required to suppress dust and to handle contaminated water run-off from the coke piles and coke handling areas.
10.14 Catalyst and Chemicals Storage and Handling
The catalyst and chemicals storage and handling system handles the supply of catalyst and chemicals used within the refinery complex.
Most of the refinery and petrochemical process units employ catalysts to promote reactions and/or absorbents to remove impurities; most of the materials employed are solids. The catalyst handling system is required to manage supplies of a large number of different catalysts and absorbents, including any associated support media (e.g. inert balls). The system handles both the receipt and storage of fresh materials and the disposal of spent materials. Reserve stocks of catalysts and absorbents are held in a warehouse according to the process requirements.
Similarly, many process, utility and offsite systems employ specific chemicals; examples include anti-foam, corrosion inhibitor, amine, DMDS, lubricating oils, etc. Many of these materials are handled in liquid form, though others may be solids (e.g. activated carbon) or gases (e.g. ammonia). The chemicals storage and handling system manages the supply of these materials to users. Reserve stocks are held in a warehouse.
11.0 UTILITY SYSTEMS
11.1 Raw Water Receipt and Treatment
The fresh water requirements of the refinery complex are met by extracting river water from the Mahanadi River at Cuttack and transporting it to the refinery site by pipeline. The facilities at Cuttack include water lift, pre-settlement and pumping systems.
The raw water receipt and treatment system at the refinery handles the receipt, storage and treatment of raw river water to produce a treated water supply to consumers within the refinery. The system includes raw water reservoirs, water treatment systems, clarified water reservoirs and all associated transfer and supply pumps.
Uses for treated water include the following:
Feed to demineralised water plant
Make-up to cooling water system
Supply to service water system
Supply to drinking water system
Supply to firewater system
11.2 Demineralised Water System
The demineralised water system receives treated raw water feed and recovered water from ultra-filtration, and produces demineralised water for supply to the refinery’s boiler feed water system and other consumers.
The system comprises a reverse osmosis plant, mixed bed demineralisation polisher and demineralised water storage. System capacity is determined based on make-up requirements to the BFW system and other minor consumers, after taking account of condensate recovery.
11.3 Drinking and Service Water System
Treated water from the raw water treatment system is used as make-up to the drinking and service water systems.
The service water system takes treated raw water for supply to hose stations, etc. by dedicated service water pumps and a distribution pipe network. Water for gardening is also supplied from this system.
Drinking water shall be supplied to the refinery complex and its township. Treated raw water used for drinking is chlorinated and then distributed to consumers via dedicated pumps and a distribution pipe network.
11.4 Recirculating Cooling Water System
Fresh cooling water is supplied to consumers within the refinery.
A recirculating system is employed, complete with cooling towers, pumps and distribution piping. Four separate dedicated systems/networks are provided; the allocation of process and other consumers to each network is based on geographical and logistical considerations.
Treated raw water is used for make-up to replace blowdown and evaporative losses. Chemical treatment is used to inhibit biological growth, fouling and corrosion.
11.5 Steam, Condensate & BFW System
The primary purpose of the steam, condensate and BFW system is to supply steam to meet the refinery demand. The system comprises of the following main elements:
Deaerators for BFW preparation from demineralised water feed.
HHP Steam generation in dedicated boilers fired by high-sulphur residual fuel.
Steam letdown and HP/MP/LP distribution systems.
Condensate recovery and conditioning system.
Steam is variously used by process consumers (eg. for stripping steam and process heating), in steam turbines, for atomisation of fuel oil, and for general heating and tracing.The steam demand of the refinery is met primarily by the generation of HHP steam in fired boilers. HHP steam is then let-down to other users levels (HP/MP/LP) via an optimum combination of back pressure turbines and let-down stations. Steam generated from waste heat within the process units is used to augment these supplies.
The steam generation system includes associated boiler feed water (BFW) deaerator and chemical dosing systems. Demineralised water and polished condensate are fed to the BFW section which prepares de-aerated and treated BFW for use in the CPP plus other waste heat boilers and process steam generators. BFW is distributed to consumers at two pressure levels, HP and MP, according to the user requirements
The steam boilers are configured on an N+2 basis to ensure adequacy of supply when one boiler is shutdown for maintenance and another is shutdown due to failure.
The boilers are fuelled by heavy residual fuel (vacuum residue + cutter stock) and employ flue gas desulphurisation (see below) to limit S02 emissions to atmosphere.
Condensate collection systems (operating at HP, MP, LP and LLP pressure levels) collect steam condensate from producers. Separate collection systems are required for clean condensate and suspect condensate. Suspect condensate undergoes a ‘polishing’ treatment prior to re-use as BFW. The BFW deaeration and chemical treatment systems are part of the CPP.
11.6 Gas Turbine Generators
The major part of the refinery’s electrical power demand is met by power import via overhead transmission lines from external generation facilities (Tata JV).
However, this supply is augmented by on-site power generation using gas turbine generator sets fuelled by distillate fuel (primarily naphtha).
On-site power generation capacity is approx. 60 MW. In normal operation the GTG sets will operate to supplement imported power. In case of loss of imported power, then the GTG sets will provide emergency power for the operation of essential plant and to facilitate the safe shutdown of the refinery.
Heat recovery steam generators (HRSG) are also provided in the gas turbine exhausts to maximise efficiency.
11.7 Flue Gas Desulphurisation
Flue gas desulphurisation is provided for the steam boilers in order to minimise sulphur dioxide emissions due to the combustion of residual fuel in the boilers.
The flue gas desulphurisation system utilises a circulating solvent to scrub sulphur dioxide from the flue gases. The sulphur dioxide released from the solvent regeneration facilities is fed to the Sulphur Recovery Facilities for recovery of elemental sulphur.
11.8 Plant and Instrument Air System
Compressed air is used in the refinery as plant air, service air and instrument air.
Atmospheric air is raised up to system pressure by motor driven air compressors. Plant and service air is distributed directly to users via a header network.
Instrument air requirements are met via a dedicated air dryer system and instrument air header network.
To facilitate safe refinery shutdown in case of general power failure, a reserve supply of air is held in a dedicated HP air receiver; this supply is released to the instrument air dryers if system pressure declines.
11.9 Nitrogen Generation System
Inert nitrogen gas is typically used in the CCR catalyst regeneration unit and for various blanketing and purging duties during normal operation, also for system pressurisation and purging during start-up and shutdown.
A cryogenic nitrogen generation unit (air separation plant) is provided to generate both gaseous and liquid nitrogen to support normal plant operation. Nitrogen gas is distributed to users via a distribution network. Liquid nitrogen is rundown to the liquid Nitrogen storage facility.
The liquid nitrogen storage facility holds a reserve of liquid nitrogen which is vaporised and used to meet intermittent peak nitrogen demands which arise during start-up, shutdown, catalyst regeneration, etc. This system also provides an independent, continuous supply of nitrogen gas to the CCR section of the Platformer unit as required by the process licensor. The liquid nitrogen system design also provides for the import of liquid nitrogen from road tankers to supplement supplies during periods of high demand.
A high-pressure cryogenic liquid nitrogen pump and vaporiser system is provided to enable pressuring of the VGO HDT unit for leak testing with nitrogen at startup.
11.10 Fuel Gas and Fuel Oil Systems
Fuel Gas
Waste gas streams (off-gases) produced within refinery are collected for use as refinery fuel gas within fired heaters, boilers, etc. Amine scrubbing facilities are provided within the process units to ensure that any potentially sour streams are scrubbed to remove H2S before entering the fuel gas system.
The fuel gas system comprises a collection header network, fuel gas mixing drum and a distribution header network. An LPG vaporiser is provided to allow fuel gas supplies to be supplemented by vaporised propane / LPG during startup and normal operation.
Fuel gas, being a clean waste gas stream, is the preferred source of low sulphur fuel in the refinery. It is burnt preferentially in fired heaters within the process units. However, there is insufficient fuel gas available to meet the refinery fuel demand so fuel oil is used as a supplementary fuel.
Fuel Oil
Three separate liquid fuel supply systems are provided:
low-sulphur naphtha/diesel fuel supply to gas turbines
low-sulphur fuel oil supply to process furnaces
heavy high-sulphur fuel oil supply to steam boilers
Due-to SO2 emission restrictions, only low sulphur fuel oil components can be utilised without the provision of flue gas desulphurisation facilities.
The gas turbine generators (GTG) are normally fuelled by a blend of low sulphur naphtha by-products derived from the aromatics complex, with diesel as a backup fuel supply.The low sulphur fuel oil used in process furnaces is a blend of LCO and clarified oil from the FCC unit plus heavy aromatics from the Aromatics complex. Diesel product is used to supplement the supply as necessary.
A separate heavy fuel oil system is provided for the steam boilers. This system is fed mainly by vacuum residue from the AVU. Flue gas desulphurisation is provided for the boiler plant to limit atmospheric emissions of sulphur dioxide.
11.11 Flushing Oil System
The flushing oil system supplies gas oil (diesel) as a flushing medium to instruments and pump seals during normal operation, as well as providing a means of flushing lines and equipment containing heavy/waxy hydrocarbons during preparations for maintenance.
The system comprises a storage tank and pump plus associated distribution piping network.
12.0 ENVIRONMENTAL DESIGN BASIS
All emissions to the environment shall meet national regulations, local environmental requirements, and project-specific environmental conditions. These environmental design requirements are
Emissions to air - a SO2 emission cap of 1,000 kg/hr for the whole complex.
Discharges to sea - a cap on the quantity and quality of process effluent discharged to the sea.
Solid waste - an on-plot landfill site for the disposal of solid waste generated by the project.
13.0 REFINERY SHUTDOWN PHILOSOPHY
A refinery shutdown philosophy has been prepared to define the manner in which individual sections of the refinery can be shutdown for maintenance and/or major turnaround. Operating strategies to be adopted in case of emergency shutdown situations are also described.
In summary, the refinery is planned to be shutdown for a major turnaround every 5 years, with intermediate, partial shutdowns for catalyst replacement or regeneration as necessary.The philosophy for major turnarounds, on a 5 year cycle, is that the entire processing complex will be shutdown at one time for maintenance.
14.0 INSTRUMENTATION SYSTEM
Refinery operations are controlled from several locations:
One central process control room caters for the process units.
A separate control room is provided for the utility facilities.
One ‘Oil Movements and Storage (OM&S) control room deals with crude receipt and blending, plus dispatch of liquid products
A separate control room is provided for the Effluent Treatment Plant.
A Jetty Control Room is expected to be provided at Paradip Port
A Distributed Control System (DCS) provides regulatory control for all facilities, using Foundation Fieldbus for monitoring and for non-critical control loops and conventional hardwired systems for critical control loops.
Other ‘specialised’ instrumented control systems include process compressors controls, controls for turbine driven generator sets, burner management systems, machinery monitoring systems and custody transfer metering.
15.0 ELECTRICAL SYSTEM
The primary source of electric power for the refinery complex is power imported from a new power plant to be built in joint venture between Tata Power Company and IOCL. The new power plant will be located at Naraj Marthapur, located approximately 120 km from Paradip.
Imported power is supplemented by on-site gas turbine driven power generators.
