Presented to: ALTONA ENERGY PLC. Non-Confidential … CTM Report June 2013.pdf · Feasibility SStudy For Coal to Methanol l (CTM) Plant t ALTONA ENERGY PLC. Presented to: For: JUNE

FFeeaassiibbiilliittyy SSttuuddyy FFoorr CCooaall ttoo MMeetthhaannooll ((CCTTMM)) PPllaanntt

ALTONA ENERGY PLC.

Presented to:

For:

JUNE 2013 Rev A

Non-Confidential Version FINAL REPORT

Jacobs UK Ltd.Tower Bridge Court 226, Tower Bridge Road London SE1 2UP, UK Tel: 00 44 20 7403 3330

CONTENTS

1.1 EXECUTIVE SUMMARY 4

1.2 INTRODUCTION 5

2.1 CTM PLANT DESIGN 7

2.2 6,200 MTPD METHANOL PLANT DESIGN 8 2.2.1 Basis of Study 8 2.2.2 Process Description 8 2.2.3 Plant Models 19

3.1 IMPLEMENTATION CONSIDERATIONS 21 3.1.1 Overview of CTM Plant Process 21

3.2 PHASE 1A IMPLEMENTATION PLAN 22

3.3 PHASE 1B IMPLEMENTATION PLAN 23

3.4 PRELIMINARY CTL PLANT LAYOUT 24

4.1 PROJECT COST ESTIMATE 26 4.1.1 Basis of Project Cost Estimate 26 4.1.2 Phased Capital Investment 26 4.1.3.1 Capital Cost 27 4.1.3.2 Operating Cost Considerations 28

5.1 DISCUSSIONS & RECOMMENDATIONS 30

5.2 PLANT DESIGN FEATURES 31

5.3 PLANT PERFORMANCE 34

5.4 CO2 CONSIDERATIONS 36

5.5 CONCLUSIONS 38

APPENDIX A CTM PLANT BLOCK FLOW DIAGRAM 40

APPENDIX B PLANT MODELS 41

SECTION 1 EXECUTIVE SUMMARY & INTRODUCTION

Feasibility Study for Coal to Methanol Plant, Final Report Rev A Page 4 of 42 MAY 2013 This document, and the opinions, analysis, evaluations, or recommendations contained herein are for the sole use of the contracting parties. There are no intended third party beneficiaries, and Jacobs shall have no liability whatsoever to third parties for any defect, deficiency, error, omission in any statement contained in or in any way related to this document or the services provided.

1.1 EXECUTIVE SUMMARY

Altona Energy Plc are In the process of reviewing options for the installation of a 45,000 BPD Coal to Liquids (CTL) Facility in South Australia. This installation was to be completed in 3-Phases:

Phase 1: 15,000 BPD FT Liquids Phase 2: 30,000 BPD FT Liquids Phase 3: 45,000 BPD FT Liquids

Altona considers that projected lower growth in power demand on the South Australian grid and a resultant likely delay in the construction and funding of new power transmission lines, including a high voltage line to connect the Arckaringa Project, could obviate the proposal to export excess power generated from the Phase 2 30,000 BPD CTL facility in the short to medium term.

The introduction of a Coal to Methanol (CTM) Plant was identified by Altona Plc as an option which could overcome this restriction whilst introducing economic benefits overall. Using the 2006 CTL study as a basis, Jacobs UK Ltd completed a review into the installation of a CTM Plant alongside the Phase 1 15,000 BPD CTL Plant.

The review concludes the following:

• A CTM Plant with a nominal capacity of 6,200 MTPD is possible

• The CTM Plant will utilise ~95% of the CTL Plant power export

• The Methanol Synthesis Loop purge gas can be used to increase the CTL Plant capacity by ~ 5% or increase overall power production by ~79MW.

• The total CTM Plant CAPEX is US $ MM 1,480 +/- 40%


1.2 INTRODUCTION

1.2.1 Background Jacobs U.K. Ltd. has been contracted to conduct a feasibility study for Altona Energy Plc on the integration of a Coal to Methanol (CTM) Plant with a 15,000 BPD Coal to Liquids (CTL) plant. Uncertainties regarding the funding and timing of expansion of the grid and power transmission connections to the original CTL plant proposal mean that the large scale export of power from the site may have to be postponed. There are several potential synergies between the CTL and CTM which would effectively replace the power exports for the time being, especially as market conditions for methanol are favourable and make methanol production a viable supplement to the naptha and diesel fraction produced in the CTL plant. The overall Altona facility is to be developed in the following phases;

Phase 1A: Initial capacity of 15,000 BPD FT Liquids Phase 1B: Increase capacity with ~6,200 MTPD of Fuel Grade Methanol

The CTL / CTM plant is to utilise ConocoPhilips (Phillips 66) Gasification for syngas generation. Rentech’s Fisher-Tropsch technology will produce crude FT products. The crude FT products, defined as C5 and higher hydrocarbons and consisting of naphtha, diesel and waxes (soft wax and hard wax) are upgraded, using UOP hydrotreating and hydrocracking technology, to naphtha and diesel products. Johnson Matthey’s Low Pressure Methanol technology will be used to produce Fuel grade Methanol

1.2.2 Scope The scope of the study will review the integration and performance of the Coal to Methanol Plant (Phase 1B) when installed alongside the Phase 1A Coal to Liquids installation. The agreed deliverables for the study and hence contents of this report are:

Design Basis Heat and Mass balances Block Flow Diagram Process Description Major Equipment List Performance Summary Utility Summary ± 40 % Installed Cost Estimate High Level Fischer Tropsch Technology Review (Appendix F)


SECTION 2 COAL TO METHANOL (CTM) PLANT DESIGN


2.1 CTM PLANT DESIGN

This section of the report describes the process design of the 6,200 MTPD CTM plant. The 6,200 MTPD plant represents the Phase 1B Altona installation and will be located next to the Phase 1A CTL plant. Phase 1B has an identical front end flowsheet to the Phase 1A CTL plant. Those units identical to CTL are:

• Coal Handling and Preparation • Gasification Unit • Slag Handling and Water Clean Up • Syngas Conditioning • CO2 Drying and Compression (Rectisol Unit)

The new / modified process units introduced to make-up the Phase 1B flowsheet are:

• Syngas Reconditioning (Sweet Shift Unit) and Syngas Compression • CO2 Removal and CO2 Compression and Drying (aMDEA Unit) • Methanol Synthesis & Distillation • Steam & Power Generation System

The CTM plant is to be fully integrated with the Phase 1A 15,000 BPD CTL plant and make the best use of the utility exports. The primary utility export is the 285 MW excess power generated within Phase 1A which is to be used to power the main compressors of the CTM plant


2.2 6,200 MTPD METHANOL PLANT DESIGN

2.2.1 Basis of Study This design basis of this study is identical to that used for the original Feasibility Study for the Expandable CTL Plant completed in October 2006.

2.2.2 Process Description This section of the report describes the process flow configuration of the CTM plant. General The CTM plant consists of:

Process Area - a Coal Handling and Preparation Unit, a ConocoPhillips Gasification Unit, Syngas Conditioning Unit, CO2 Drying / Compression, Syngas Reconditioning Unit, Make Gas Compression and Circulation, Methanol Synthesis Unit, Distillation Unit, Steam & Power Unit

Offsite Area Utilities Area

2.2.2.1 CTM Plant Process Area

Coal Handling and Preparation Coal Storage and Handling Unit This unit is already installed as part of Phase 1A. For more details, refer to the 2006 Feasibility Study. Coal Preparation Unit From Coal Storage, the crushed and screened coal is milled and slurried with water. The slurry is stored and continuously stirred before being pumped to the Gasification Unit.


Gasification Unit Air Separation Unit Atmospheric air is compressed to a low pressure using an electric driven compressor and fed to the Air Separation Unit (ASU) where oxygen is separated from atmospheric air cryogenically. Following separation, the oxygen product with a purity of 99.5 vol % is pumped to high pressure as a cryogenic liquid and vaporised against a stream of condensing high pressure air within the ASU main heat exchanger. The majority of the gaseous oxygen product is fed to the Gasification Unit at pressure. The remainder (approximately 1%) is let down in pressure and routed to the Claus Unit where it is used for sulphur production. A small amount of N2 from the ASU is used for purging and inerting of the CTL plant. Gasification Unit The coal slurry pumped from the Coal Handling and Preparation Unit is fed to the ConocoPhillips Gasifier. The ConocoPhillips Gasifier is an upflow, entrained two-stage gasifier. Oxygen from the ASU is used to gasify the slurry at high temperatures. The coal is converted to synthesis gas (syngas), containing primarily H2 and CO, together with some steam, CO2, N2, CH4, and Ar. The sulphur in the coal is converted to H2S with some COS, whilst the chlorine present is converted to HCl. Small amounts of HCN and NH3 are also produced. A small amount of carbon remains as soot. The syngas, exiting the gasifier is cooled by raising and superheating high pressure steam and heating up BFW. Char produced in the gasifier is separated and returned back to the gasifier. The resulting char-free syngas is routed to the Syngas Conditioning Section for further processing. The generated steam is sent to the steam turbine. The coal ash, converted to molten slag, flows downwards where it comes into contact with water. This solidifies the slag which is collected at the bottom of the gasifier, crushed and removed through a lock-hopper system together with approximately equal quantities of water. This is sent to the Slag Handling Unit for treatment.


Slag is sent across the plant’s battery limit for disposal. The separated water (black water) is routed to the Black Water Flash Section for treatment. Dissolved gases are released and sent to the Flare System and the liquid (grey water) is clarified and filtered. Particulates (fine slag) are separated and sent across the plant’s battery limit for disposal. The filtered grey water solution is pumped and distributed to various parts of the Gasification Unit. Syngas Conditioning Unit Syngas Pre-Treatment Unit Raw syngas, supplied from the Gasification Unit is fed to the Mercury Adsorber where any mercury present within the gas is removed by an absorbent. On leaving the adsorber, the syngas is introduced to a COS Reactor where the COS, present in the gas is converted to H2S and the resulting COS free syngas is fed to the Syngas Cooling Train. The Syngas Conditioning Unit has been equipped with a Shift Reactor to enable the hydrogen to carbon monoxide ratio of the conditioned syngas to be adjusted. For this scenario, the syngas from the Mercury Adsorber is split into two streams. One portion is heated in the feed / product exchanger and introduced to the high temperature Shift Reactor where CO in the stream reacts with the water vapour present to produce H2 and CO2. The shifted syngas exiting the CO Shift Reactor is cooled in the feed / product exchanger. This stream joins the other portion of the syngas and the mixture is routed to the COS Reactor as described before. Syngas Cooling Train The pretreated syngas is cooled down through a series of exchangers to a final temperature of 50 °C and sent to the Acid Gas Removal Unit. The heat released from this cooling provides:

Heat to generate LP steam. Heat BFW for LP Steam generation. Reboil for Acid Gas Removal Unit. Heat DMW to Deaerator.

The process condensate produced by cooling of the syngas is removed in two stages in K.O. Drums. The separated process condensates are combined together and routed to the Coal Preparation Unit as slurry water.


Acid Gas Removal Unit The raw syngas is first cooled against the treated syngas and sent to the H2S Absorber where it is contacted with a small amount of cold methanol to remove HCN and NH3 and other trace impurities. The gas then flows via a chimney tray to the main section of the absorber where the H2S and COS are removed by contacting with cold CO2 preladen methanol solvent from the CO2 Absorber. The use of the CO2 preladen methanol solvent ensures that practically none of the CO2 gas in the syngas is removed across the H2S Absorber. The desulphurised gas leaving the top of the H2S Absorber is routed to the CO2 Absorber where it is washed with cold, heat regenerated methanol. The treated syngas leaving the top of the absorber is heated against the raw syngas and sent to the Syngas Purification Unit. The laden solvent streams from the H2S and CO2 Absorbers are fed to the MP Flash Columns where it is flashed at medium pressure to release valuable H2 together with part of the CO2. This is recompressed and returned to the raw syngas. The CO2 laden solvent resulting from flashing of the bottoms of the CO2 Absorber is subcooled and fed to the Reabsorber. Part of the H2S/CO2 laden solvent produced by flashing of the bottoms from the H2S Absorber is flashed in the LP Flash Column and the remainder is sent to the Reabsorber. The CO2 released from the LP Flash Column and Reabsorber is combined and heated, and leaves the Acid Gas Removal Unit as CO2 product gas. The H2S laden solvent exiting the LP Flash Column is pumped to the Hot Regenerator where the H2S enrichment is increased and leaves the top part of the column as Claus gas product. The regenerated methanol from the bottom of the Hot Regenerator is pumped, cooled and returned to the CO2 Absorber. The Claus Product gas from the Acid Gas Removal is processed into liquid sulphur by the common Sulphur Recovery Unit installed with the Phase 1A CTL plant. Syngas Purification The treated gas exiting the Acid Gas Removal Unit is sent to the Desulphuriser where any residual H2S present is absorbed onto a ZnO catalyst. The purified syngas is routed to the Syngas Re-conditioning Section.


CO2 Drying / Compression The CO2 gas from the Acid Gas Removal Unit is compressed to 40 barg and dried using mole sieve. The dried gas is then compressed further to 145 barg cooled to 45 oC and exported across the plant’s battery limit for sequestration. Syngas Reconditioning The purified syngas stream is split in two, with part transferred to the Syngas-reconditioning section. The remainder of the stream bypasses the reconditioning section and re-joins the process at the discharge of the aMDEA unit, upstream of the Syngas compressor. The process stream is heated before passing through a Saturator in which it flows upwards against a downflow of hot circulating water. The syngas becomes partially saturated as some of the water evaporates into the syngas to provide part of the steam required for the sweet shift reaction. The vapour outlet is mixed with more steam from the MP steam header in order to give the desired molar steam to dry gas ratio at the sweet shift reactor inlet. It is then heated in the reactor interchanger while the reactor outlet is cooled. The mixture of steam and syngas is then fed to the shell of the Shift Reactor which is controlled by raising MP steam within the tubes. The outlet of the reactor is further cooled to an intermediate temperature before final cooling and condensation of the un-reacted steam in a Desaturator. The Desaturator is a direct contact condenser having a circulating stream of process condensate that is part of the water circuit; it is kept in heat balance as follows:

• Circulation of a stream of process condensate cooled by preheating Syngas upstream of the Saturator

• Air cooling in Desaturator Water Cooler • Cooling against cooling water in Desaturator Water Trim Cooler

The process condensate is pumped round by the Desaturator Circulation Pump. MP BFW is added to the condensate as makeup. CO2 Removal, Make Gas Compression and Circulation Make gas leaves the Desaturator and flows to an aMDEA unit for CO2 removal and compression. The purified Syngas then combines with the feed gas bypass and flows to the Suction KO Drum and the Syngas Compressor/Circulator which is electrically driven. The make gas is compressed in two stages and combined with


the syngas loop recycle stream. Heat generated by make gas compression is removed between compression stages by cooling by cooling water in the Syngas Compressor Interstage Cooler. Methanol Synthesis Methanol Loop The Methanol Synthesis Loop utilises Davy Process Technology Radial Steam Raising Converters (R-SRCs) in a series loop. The R-SRCs are tubular radial flow reactors with the gas passing over the synthesis catalyst on the shell side. The temperature is controlled by raising steam in the tubes. This steam is exported as IP steam and let down to the LP steam header. Feed gas from the Syngas Reconditioning unit is split into two. The majority is mixed with recycle gas and heated in Loop Interchanger No.1 before entering Methanol Converter No.1 where it flows over methanol synthesis catalyst. The hot gas leaving the converter is cooled in Loop Interchanger No.1. Additional cooling is carried out by the Crude Methanol Condenser No.1 before passing to the Crude Methanol Separator No.1. Here the crude methanol/water mixture is separated from the unconverted gases which are then mixed with the remainder of the feed gas. This gas is then compressed in the Circulator and heated in Loop Interchanger No.2 before entering Methanol Converter No.2. The hot gas leaving the second Converter is cooled in Loop Interchanger No.2. Additional cooling is carried out by the Crude Methanol Condenser No.2 before passing to the Crude Methanol Separator No.2. Here, the crude methanol/water mixture is separated from the unconverted gases which are recycled back to the first Converter A small purge is taken to control the level of inerts in the loop. This purge is washed with cooled Methanol Column bottoms recycled from the distillation section in the Purge Gas Wash Column to remove the methanol to acceptable levels for the Hydrogen Recovery Membrane. The crude methanol streams from the Crude Methanol Separators along with the washed methanol from the Purge Gas Wash Column are reduced in pressure, causing dissolved gases to be released, and then fed to the Crude Methanol Letdown Vessel.


Hydrogen Recovery Section The washed purge gas from the Methanol Synthesis Loop is fed to the Hydrogen Recovery Membrane to recover hydrogen which is recycled back to the Loop to obtain the desired ratio of reactants in the feed to the Methanol Loop. The recovered hydrogen from the membrane is recycled back to the suction of the Syngas Compressor. The carbon-rich non-permeate stream from the Hydrogen Recovery Membrane is exported for use as fuel in the Gas Turbine of Phase 1A CTL plant, displacing Tail Gas, which is recycled within the CTL plant Distillation Column The crude methanol and dissolved gases from the Crude Methanol Separators are fed to the Crude Methanol Letdown Vessel. A wash of cooled Methanol Column bottoms is added to the top of the Crude Methanol Letdown Vessel in order to minimize the methanol losses and increase the weight percent of water in the crude methanol. The crude methanol from the Crude Methanol Letdown Vessel is dosed with caustic soda from the Caustic Dosing Package before flowing into the Methanol Column. In the Methanol Column, light by-products are removed and the heat required to do this is provided by LP steam in the Methanol Column Reboiler. The vapour leaving the top of this column flows to the Air cooled Methanol Column Condenser where the bulk of the vapour condenses and is fed into the Methanol Column Reflux Drum. The remainder of the vapour is condensed within the Methanol Column Trim Cooler, with a small stream of non-condensables being fed to the Vent Eductor. All the liquid which is collected is pumped by the Methanol Column Reflux Pump back to the top tray of the Methanol Column. The Methanol Column bottoms are taken from the base of the Methanol Column, this water is cooled by heating the crude methanol upstream of the column with most recycled back to the Crude Methanol Letdown Vessel. Part of the water is also recycled back to the Purge Gas Wash Column and the remainder, is sent offsite. Refined methanol is drawn from the reflux stream to the Methanol Column and flows through the Methanol Column Product Cooler where it is cooled and sent to storage.


Steam and Power Unit Steam and Power The superheated HP steam from the Gasification Unit is used to drive the Steam Turbine / Alternator Set to generate electricity. The exhaust from the Steam Turbine is cooled in the Turbine Condenser to condense the steam before it is routed to the Water Purification Unit for polishing. MP steam blowdown from the Syngas Conditioning Unit is flashed in a Boiler Blowdown Flash Vessel. The vapour from the Flash Vessel is sent to the LP steam header and the liquid is routed to the Water Purification Section of the plant. LP steam from the Syngas Conditioning Section and letdown IP steam from the Methanol Synthesis section are fed to the LP header. Primary LP steam users include:

• Acid Gas Removal Unit Reboilers • aMDEA Unit Reboilers • Distillation Reboilers

Condensate The steam condensates generated within this section of the plant (mainly flashed boiler blowdown) are routed to the Deaerator. Turbine condensate is routed to the Water Purification Section for further processing.

2.2.2.2 CTM Plant Offsites Area The Offsites of the CTM Plant consists of the following areas:

Crude Methanol Storage / Transfer Section Product Methanol Storage / Transfer Section Water Purification

Crude Methanol Storage / Transfer Section This section consists of a Crude Methanol Storage Tank and a Transfer Unit.


The Crude Methanol Product Storage is used to store crude Methanol during normal operation and acts as a buffer between the methanol loop section and the distillation unit. The Crude Product Methanol Storage and Transfer Unit is furnished with two pumps (one standby) to transfer the crude methanol to the distillation column. Product Methanol Storage / Transfer Section The finished methanol product is stored in a Methanol Product Tank. The methanol product is exported from the plant by road, pipeline (to be confirmed) and rail via a Product Loading Station. Water Purification Unit The Water Purification Unit comprises of three sections namely Water Filtration Plant (in Phase 1A Offsites), Demineralisation Plant and Condensate Polishing Plant. In the Demineralisation Plant, filtered water is processed into semi-demineralised water using Cartridge Filters, Reverse Osmosis Unit and Ion Exchanger Units and sent to the Condensate Polishing Plant. In the Condensate Polishing Plant steam condensates from condensing steam turbines are added to the de-ionised water in the Semi-Demin Water Tank and the mixture is pumped through 3 parallel Mixed Bed where the water is polished to high-pressure boiler feed water quality. The product is fed to the Demineralised Water Tank. The demineralised water is pumped using Demin Water Pumps via the Demin Water Heater in the Syngas Conditioning Section to the Deaerator Column in the Steam and Power Section. Effluent Treatment Plant The effluent treatment system is installed as part of Phase 1A. Flare System The flare system is installed as part of Phase 1A.


2.2.2.3 CTM Plant Utilities Area Electricity Electricity supply to the plant will be from three sources namely:

Alternator within the CTM Plant Emergency Power Generation Unit Phase 1A Power Plant

The power from the Alternators and Emergency Power Generation Unit will be generated at 13,800 V and 60 Hz and any surplus power will be stepped up to 115,000 V and 60 Hz for export. Although provisions have been made to import / export power from the Local Electricity Company it is envisaged that power import will not be required since the CTL/CTM Phase 1 Plant is self-sufficient in power and capable of starting up from cold using the power from Plant 1A. During normal operating conditions, the power generated by the alternators is sent to the Electricity Substation where sufficient power is stepped down to the voltage levels required by the users in the plant. The plant is equipped with a diesel driven Emergency Power Generation Unit to supply electricity during an emergency or for plant start-up from cold. This only supplies electricity to selected essential users during an emergency. Raw Water System Raw water will be supplied to the plant’s battery limits. This will be used for producing demineralised water, utility water, fire water and as make up for the Cooling Tower System. This system is part of the CTL Plant in Phase 1A. Cooling Tower Package The plants cooling water is provided by a Cooling Tower Package and provides sufficient cooling for key parts of the process and mechanical packages. This system is part of the CTL Plant in Phase 1A. The Cooling Tower Package sizing needs to be increased to take into consideration the significantly larger cooling water demand of the CTM Plant.


Potable Water The potable water system is installed as part of Phase 1A. Utility Water The utility water system is installed as part of Phase 1A. Nitrogen A small Nitrogen Generation Unit produces nitrogen for purging during plant start-up, providing blanketing of storage tanks, maintenance and for general usage. This will be supplemented by nitrogen from the Air Separation Unit. Instrument / Plant Air The Instrument and Plant Air Generation System for the CTM plant consists of four identical new units each capable of producing 4680 Nm3/h of instrument and plant air respectively. Fire Water Distribution System The Fire Water Storage And Pumping System is installed as part of Phase 1A. A distribution system with monitors and hydrants is required for the CTM plant.


2.2.3 Plant Models The models for the following plants are contained in Appendix B:

• 30,000 BPD CTL • 15,000 BPD CTL + 6200 TPD Methanol

Both plant configurations have the same overall plant dimensions of 710 metres by 1088 metres, giving a total plant area of 773,000 square metres.


SECTION 3 CTL / CTM PLANT IMPLEMENTATION CONSIDERATIONS


3.1 IMPLEMENTATION CONSIDERATIONS

The objective of the 2006 CTL project was to design a self-sufficient CTL Plant capable of being expanded in three phases to a final capacity of 45,000 BPD over a period of 10 years. The external restrictions imposed on the CTL plant for the exporting of its excess power, and the potential economic benefits of methanol, have meant that a viable solution to overcome these restrictions may lie with the introduction of the CTM plant. This section provides an overview of how the installation could be implemented.

3.1.1 Overview of CTM Plant Process The proposed self-sufficient CTM Plant consists of three main parts, namely:

Process : consisting of coal handling & preparation unit,

gasification unit, syngas conditioning and reconditioning section, Methanol Synthesis, Methanol Distillation and steam & power section.

Offsites : consisting of crude and product storage / loading

facilities.

Utilities : consisting of substation & emergency generator, cooling water system, instrument & plant air unit, nitrogen unit and fire water system.

Feasibility Study for Coal to Methanol Plant, Final Report Rev A Page 22 of 42 MAY 2013

3.2 PHASE 1A IMPLEMENTATION PLAN

Phase Coal Handling & Preparation

ASU Gasification Syngas Condition

CO2 Drying / Compressing

FT Unit

Product Upgrade

Steam & Power

Offsite Utilities

1A 1 x 80,000 MT Storage 1 Coal Preparation Unit

2 x 4200 MTPD ASU

3 Gasifiers 1 Unit for 15,000 BPD 1 Claus Unit for 45,000 BPD

1 Unit for 15,000 BPD



1 GT + 1 ST for 15,000 BPD

Crude Storage 1 set for 45,000 BPD Product Storage 1 NAP Tank, 1 HTD Tank, 1 HCD Tank Water Purify 300% Tanks, 100% for rest Auxiliary Boiler 1 Boiler Chiller Unit Unit for 50% of 45,000 BPD Tempered Unit Unit for 50% of 45,000 BPD Effluent Unit Unit for 45,000 BPD Flare Unit Unit for 15,000 BPD

Electricity 1 Emergency unit for 15,000 BPD 1 Substation unit for 15,000 BPD Raw Water 1 x 45,000 BPD Portable Utility Size for 22,500 BPD N2 Generation Unit 1 x 22,500 BPD Plant / Inst. Air Unit 1 SET x 22,500 BPD Fire System 1 x Storage / Transfer Unit 1 x Fire Water System


3.3 PHASE 1B IMPLEMENTATION PLAN

Phase Coal Handling & Preparation

ASU Gasification Syngas Condition

CO2 Drying / Comp

Syngas Re-Condition

CO2 Removal & Comp

Steam & Power

Offsite Utilities

1B 1 Coal Preparation Unit

1 x 4200 MTPD ASU

3 Gasifiers + 1 Spare

1 Unit for 6,200 MTPD (15,000 BPD equivalent)No Claus Unit

1 Unit for 6,200 MTPD (15,000 BPD equivalent)

1 Unit for 6,200 MTPD

1 Unit for 6,200 MTPD

1 Steam System for 6,200 MTPD including 1 x 81MWe ST with alternator

Crude Storage Crude Methanol and Rerun Tanks Product Storage Methanol Product Storage Tanks Water Purify No Tanks, 100% for rest Effluent Unit No Unit Flare Unit No Flare

Electricity 1 Emergency unit for 6,200 MTPD (15,000 BPD equivalent) 1 Substation unit for 6,200 MTPD (15,000 BPD equivalent) N2 Generation Unit 1 x 7,500 BPD Equivalent (30,000 BPD for Phase 1A & 1B) Plant / Inst. Air Unit 1 x 7,500 BPD Equivalent (30,000 BPD for Phase 1A & 1B) Fire System No Storage / Transfer Unit 1 x Fire Water System Cooling Water 1 unit for 6,200 MTPD


3.4 PRELIMINARY CTL PLANT LAYOUT

Slag Silos / Loading Area

Water Purification

Coal Handling Preparation

Syngas Condition 1 & Reconditioning

Syngas Condition 2

Methanol Unit

FT Unit

Crude / Product Storage Tanks

Admin / Lab Warehouse/Workshop etc

Steam Systems and Power Island

ASU 1

ASU 2

ASU 3

ASU 4

Flare Effluent Treatment

FT Product Upgrading

Gasification Island

Utilities Cooling Water


SECTION 4 PROJECT COST ESTIMATE


4.1 PROJECT COST ESTIMATE

4.1.1 Basis of Project Cost Estimate The capital cost estimates have been computed by several methods. One method involved working up the cost of equipment and applying standard factors. These factors are based on our experience in constructing petrochemical plant of this nature and in the region where the plants will be located. The other method took existing equipment estimates and scaled them on a capacity factor basis. These capacity factors are based on Jacobs experience. The costs of equipment were developed by Jacobs based on calculated equipment sizes and quotations obtained from vendors for similar equipment items. All costs factored from previous quotations and then adjusted for time frame and major design differences (i.e. size, metallurgy etc.). The cost estimates presented are on 4th Quarter 2010 basis with an accuracy of ± 40%. The costs exclude owners costs, contractor profits, import duties and taxes, inflation and contingencies.

4.1.2 Phased Capital Investment The 2006 / 2010 estimate was based on the original Phase 1 – 3 approach, increasing the overall site production step wise as each new phase is brought on line (15,000 BPD, 30,000 BPD and 45,000 BPD). This approach was supported by a step wise capital investment program, where several of the larger process units and utilities were installed at Phase 1, yet sized for all 3 phases The revised rationale introduces 3 additional Phases: 1B, 2B and 3B, which represent the 6,200 MTPD CTM streams. The original phased capital investment rationale is still applicable, with the following changes:

Original Revised Phase 1 (15,000 BPD) Phase 1A (15,000 BPD)

Phase 2 (30,000 BPD) Phase 1B (+ 6200 MTPD)

Phase 3 (45,000 MPD) Not Included There are minor exceptions to this, which are detailed in the notes below the estimate table. 4.1.3 Project Cost Estimate


4.1.3.1 Capital Cost

A breakdown of the project cost estimate associated with each of the two phases of expanding the CTL plant is given in the table below:

CTL / CTM Plant CAPEX

Plant Section Units Phase 1A 15,000 BPD

Phase 1B 6,200 MTPD

Direct Cost

Coal Handling & Prep. US $ MM 102 (3) 78

Gasification Unit US $ MM 676 695

Syngas Conditioning (8) US $ MM 203 (4) 126

CO2 Drying & Comp. US $ MM 18 18

FT Synthesis US $ MM 87 N/A

Product Upgrade US $ MM 52 (5) N/A

Syngas Re-conditioning US $ MM N/A 84

CO2 Removal & Comp. (9) US $ MM N/A 14

Methanol Synthesis US $ MM N/A 173

Methanol Distillation US $ MM N/A 36

BFW, Steam & Power US $ MM 254 24

Utility US $ MM 50 (6) 17 (6)

Offsites US $ MM 70 (7) 33 (7)

Infrastructure & Off-Plots US $ MM 0 0

Total Direct Cost US $ MM 1,513 1,298

Total Indirect Cost (1) US $ MM 73 72

Total Engineering Cost(2) US $ MM 115 106

Commissioning & Start-up US $ MM 6 4

Contingencies US $ MM 0 0

Total US $ MM 1,706 1,480

Note: 1. Indirect cost includes cost of equipment transportation, heavy lift, fabrication shop, warehouse and

construction management. 2. Engineering cost includes licence & know-how fees, basic engineering cost and detail engineering

cost. 3. Phase 1A CAPEX includes $24m for 80,000 MT coal storage unit for Phases 1A and Phase 1B 4. Phase 1A CAPEX includes $78m for the 45,000 BPD Claus Unit for Phases 1A, 1B and 2A. $26m

can be apportioned to Phase 2A.


5. Phase 1A CAPEX includes $52M for the 45,000 BPD Product Upgrading Unit for Phases 1A, 2A and 3A. $17m each can be apportioned to Phases 2A and 3A.

6. Phase 1A Utilities CAPEX includes the following provisions: i. $10m for 22,500 BPD Potable Utility. Additional 7,500 BPD equivalent included

in Phase 1B. ii. $2m for 22,500 BPD N2 Generation Unit. Additional 7,500 BPD equivalent

included in Phase 1B. iii. $0.7m for 22,500 BPD Plant / Inst Air. Additional 7,500 BPD equivalent included

in Phase 1B. iv. $3.1m for the increased cooling water capacity in Phase 1B.

7. Phase 1A Offsites CAPEX includes the following provisions: i. $3m for 45,000 BPD Crude CTL storage. $1m each can be apportioned to

Phases 2A and 3A. ii. $6m for 22,500 BPD Chiller Water Unit, $2m can be apportioned to Phase 2A. iii. $0.5m for 22,500 BPD Tempered Water Unit, $0.2m can be apportioned to

Phase 2A. iv. $12m for 45,000 BPD Effluent Unit, $4m each can be apportioned to Phase 1B

and 2A. 8. Rectisol for H2S/CO2 removal. 9. aMDEA for CO2 removal.

4.1.3.2 Operating Cost Considerations

Altona Energy Plc have requested an estimate on the staffing requirements for the Phase 1B CTM plant. Staffing of the CTL / CTM plant and average annual salaries at plant start up are based on:

- Phase 1A: 23 Professionals on an average annual salary of US $ 99,000.

112 Supervisors and Operators on an average annual salary of US $ 72,000. 47 Others (Sec., Security, Drivers, Labourers, etc) on an average annual salary of US $ 50,000.

- Phase 1B: 7 Professionals on an average annual salary of US $ 99,000. 32 Supervisors and Operators on an average annual salary of US $ 72,000. 10 Others (Sec., Security, Drivers, Labourers, etc) on an average annual salary of US $ 50,000.


SECTION 5 DISCUSSIONS & RECOMMENDATIONS


5.1 DISCUSSIONS & RECOMMENDATIONS

This section of the report highlights the operability, safety, design features, construction and environmental issues raised in Sections 3 and 4 associated with the new process units introduced in Phase 1B relating to the CTM plant. Issues relating to the existing process units are discussed within the 2006 report. The section also compares the overall plant performance (i.e. energy consumption, utility exports, emissions and effluents) and discusses the effect of the Methanol Plant on the Phase 1 overall performance and economics.


5.2 PLANT DESIGN FEATURES

Coal Handling and Preparation Unit This unit is discussed within October 2006 Report.

Gasification Unit This unit is discussed within October 2006 Report. The current O2 requirement for Phases 1A and 1B is ~ 12,460MTPD. This will be provided over 3 x 4200 ASU units. It maybe necessary make provisions for a spare, or review increasing the unit capacity to ensure plant up-time and cover maintenance periods. Syngas Conditioning Unit This unit is discussed within October 2006 Report. Syngas Re-conditioning Unit Syngas Pre-Treatment

The Sweet Shift Reactor employs a Johnson Matthey Katalco 71-5 type Catalyst. The conditions for the sweet reaction are milder than those employed for the sour shift. This enables both lower temperatures and lower grade metallurgy when compared to the sour shift system. The use of sweet shift systems is a well-proven technology and Jacobs do not envisage any problems with this system. The reactor system design maybe further refined to give reduced reactor sizes and minimize steam injection. Any modifications may result in reducing downstream equipment size as well. Syngas Saturation / Desaturation The re-conditioned syngas cooling train consists of a series of exchangers and vessels. The former cools the syngas down by preheating the saturator inlet and process water within the desaturator circuit. This saturator / desaturator arrangement has been proven within several Jacobs Methanol plants and enables


the most efficient use of low-grade heat. It has also been applied around sweet shift systems in town gas plants. CO2 Removal Unit The Activated (a)MDEA process is a licensed process from BASF, a reputable Company with significant experience in the design, and operation of amine based CO2 Removal Units. The advantage of this process is its associated low CAPEX compared with other available processes for Acid Gas Removal such as Selexol and Rectisol. Due to the upstream installation of a selective Acid Gas Removal unit in the Syngas Conditioning Section, however, there may be potential benefits with the addition of an extra absorber unit. We therefore recommend that the integration of these two CO2 removal steps is evaluated in the next phase of the project.

Methanol Synthesis Unit The Methanol Synthesis will utilize the Johnson Matthey (JM) Low Pressure Methanol Synthesis technology and a Davy Process Technology (DPT) flowsheet. DPT have some 40 years experience in the Methanol business and at present DPT designs account for some 40% of the world’s methanol capacity.

Steam and Power Section

The configuration of the Steam and Power Section is very similar to that of a typical Methanol Plant and we do not envisage any problems in designing and operating this section. Offsites Crude / Methanol Storage Tanks The specified tank sizes and transfer rates are based on good engineering practices. This will be reviewed with Altona Energy at the next phase of the study to ensure that they meet their sales and marketing philosophy. Water Purification Unit Jacobs have significant experience in water purification for most chemical industry application. We therefore do not consider the designing, constructing and operating of the unit as problematic.


Chiller And Tempered Water System Not required as part of Phase 1B. Effluent Treatment Unit Not required as part of Phase 1B. Raw Water System The Raw Water is imported across the site battery limits and is outside the scope of this study. Due to the large increase in cooling water demand as a result of the introduction of the CTM plant, a review must be undertaken on the capacity of the Raw Water system. It is anticipated that the CTM plant requires 3.5 times the cooling water demand of the Phase 1A CTL plant. Utilities

Since the majority of the equipment in this section of the plant are vendor package equipment and are common to most chemical processing plants, we do not envisage any problems in designing / operating them. When specifying this equipment however it is important to include design margins and accurately specify the operating envelop of the equipment as these vendor package units generally have low design margins. One specific addition to the utility system for the CTM plant is the cooling water system. The cooling water system capacity for Phase 1B is significantly larger than for Phase 1A. To ensure that the site cooling water system can provide the correct amount of cooling to both systems, the cooling tower, circulation pumps and dosing systems all need sizing for both systems.


5.3 PLANT PERFORMANCE

A summary of the performance of each phase of the CTL / CTM plant is given in the table below:

CTL / CTM Plant Performance Parameter Units Phase 1A Phase 1B

IMPORTS

Feedstock Coal Feed (1) MTPD 14880 14880 O2 Feed MTPD 6230 6230 Utilities Electricity (2) MW 0.0 266 Raw Water MTPD 0.0 4420 EXPORTS

Products FT Products (3) BPD 15,000 N/A Methanol Product (7) MTPD N/A 6200 CO2 Product MTPD 6480 11123 Sulphur MTPD 151 151 Utilities Electricity (4) MW 281 0(8)

Water MTPD 360 0 PERFORMANCE Feed / Product Basis GJ/bbl Confidential N/A Feed / Product Basis GJ/MT N/A Confidential Overall Energy/Prod. Basis(5) GJ/bbl Confidential N/A Overall Energy/Prod. Basis GJ/MT N/A Confidential EMISSIONS / EFFLUENTS Slag & Fly Ash (6) MTPD 1594 1594 Emissions (As CO2) MTPD 9336 1842 (9)

Notes: 1. Coal flow is based on As-Received basis. 2. No electricity import is required during normal operating conditions. 3. FT Products consists of 81 vol % Diesel and 19 vol % Naphtha. 4. Excess electricity available for export. 5. Electricity to energy conversion is based on an efficiency of 35 %. 6. Slag is a glassy non-leachable material. This will be stored and disposed off periodically. 7. Fuel Grade Methanol 8. 76MW generated and used within the CTM plant 9. Assumes complete combustion of Methanol Purge within the Gas Turbine.


The total CTM Plant power import requirement is ~ 274MW which represents 97% of that available from the CTL plant, leaving a small excess of ~ 7MW Further investigation would be required to optimise the tail gas recirculation rate within the FT Unit. This will increase production by a small percentage while requiring increased capital expenditure associated with the increased recirculation (i.e. CO2 removal, larger circulator). It maybe more appropriate to not recycle more tail gas and send both the FT tail gas and the Methanol Loop purge to the Phase 1A gas turbine, so to generate a slight surplus in power, in the region of ~79MW. This could be used for mine dewatering in addition to other site applications. The Raw Water import presented is the deficit of the water circuit, once the process condensate and excess distillation bottoms water have been considered. The large increase in import is down to the increase in size of the cooling water circuit. The increased size of the cooling water circuit directly increases the losses and therefore make-up of the system. The burden of this make-up is placed on the Raw Water system. It may be possible to utilise any water removed as a result of the mine dewatering. An alternative use for the distillation bottoms water maybe to direct it to the Phase 1A gas turbine. This unit already receives the water generated by the FT Unit which acts to dilute the temperatures within the gas turbine. Transferring the distillation bottoms to the gas turbine in this fashion and would enable a heating value to be gained from the residual organics contained within the water.

Feasibility Study for Coal to Methanol Plant Report, Final Issue Page 36 of 42 APRIL 2013 This document, and the opinions, analysis, evaluations, or recommendations contained herein are for the sole use of the contracting parties. There are no intended third party beneficiaries, and Jacobs shall have no liability whatsoever to third parties for any defect, deficiency, error, omission in any statement contained in or in any way related to this document or the services provided.

5.4 CO2 CONSIDERATIONS

A summary of the CTM plant specific CO2 balance is presented in the table below:

55..44..11 SSppeecciiffiicc CCOO22 BBaallaannccee OOnn FFTT LLiiqquuiiddss PPrroodduuccttiioonn BBaassiiss

CO2 GAS (KG/H) FT LIQUIDS PRODUCTION (BBL/H) SPECIFIC CO2 GAS (KG/BBL)

PLANT SECTION

PRODUCED CAPTURED EMITTED TO ATMOSPHERE PRODUCED CAPTURED EMITTED TO

ATMOSPHERE ISBL GASIFICATION & SYNGAS CONDITIONING

283,500 269,500 13,500 227 216 11

FT & PRODUCT UPGRADE UNIT 226,500 0 9,000 181 0 7

POWER ISLAND 130,000 0 348,000 104 0 278 OSBL UTILITIES & OFFSITES 18,500 0 18,500 15 0 15

TOTAL 658,500 269,500 389,000 1,250 527 216 311


55..44..22 SSppeecciiffiicc CCOO22 BBaallaannccee OOnn MMeetthhaannooll PPrroodduuccttiioonn BBaassiiss

CO2 GAS (KG/H) METHANOL PRODUCTION (MTPH) SPECIFIC CO2 GAS (KG/MTPH)

PLANT SECTION

PRODUCED CAPTURED EMITTED TO ATMOSPHERE PRODUCED CAPTURED EMITTED TO

ATMOSPHERE ISBL GASIFICATION & SYNGAS CONDITIONING

283,500 269,500 13,500 1,097 1,043 52

SYNGAS RE-CONDITION 242,000 193,437 0 937 749 0

METHANOL SYNTHESIS -33,500 (1) 0 0 -130 0 0

POWER ISLAND 0 0 44,764 (2) 0 0 173 OSBL UTILITIES & OFFSITES 18,500 0 18,500 72 0 72

TOTAL 510,500 462,937 76,764 258 1,976 1,792 297 Note 1: CO2 is consumed in the converter by reacting with Hydrogen to produce Methanol.

Note 2: Power Island Emissions are that from the full combustion of the Methanol Plant purge. Overall however there will be mitigation through increased carbon efficiency from the

extra recycle within the FT process.


5.5 CONCLUSIONS

This Feasibility study has reviewed the introduction of a 6,200 MTPD Coal to Methanol Plant (Phase 1B), which will be installed alongside a 15,000 BPD Coal to FT Liquids Plant (Phase 1A). The CTM plant has many identical process units to that used for the CTL namely:

• Coal Handling and Preparation • Gasification Unit • Slag Handling and Water Clean Up • Syngas Conditioning • CO2 Drying and Compression

The new / modified process units introduced to make-up the Phase 1B flowsheet are:

• Syngas Reconditioning (Sweet Shift Unit) and Syngas Compression • CO2 Removal and CO2 Compression and Drying • Methanol Synthesis & Distillation • Steam & Power Generation System

These new and / or modified process units all use equipment and technologies that have proven applications within industry. The DPT / JM methanol technology used is the basis of ~ 40% of the world’s methanol capacity, and is therefore deemed a robust and justified technology selection. Locating and operating the CTL / CTM plants alongside each other enables several benefits with respect to utility integration. The excess power from the CTL train is consumed within the CTM plant, with a small excess available. In addition the purge gas from the CTM stream is used to increase CTL production by displacing FT Tail gas from Gas Turbine fuel and freeing it up for recycle. The estimate of US$ MM 1,480 represents that associated with a CTL plant flowsheet that has been modified to incorporate a CTM plant. Significant benefit could be gained by revisiting the CTM plant design, so that the entire process is fully integrated. These include:

• Combining the two CO2 removal and compression process units on Phase 1B. The use of the aMDEA unit provides significant capital cost benefits, and provides a simpler flowsheet. Benefits maybe gained however by integrating the upstream Rectisol Unit.


• Increasing the size of the Phase 1A steam turbine to operate with steam from both CTL and CTM Plants, removing the requirement for Phase 1B steam generator and turbine set

In addition, there exists several opportunities to reduce overall power excesses whilst increasing plant revenues. These options include:

• Combining FT tail gas and Methanol Loop purge as a feed to a Purge Gas Reactor to increase Methanol Production.

• Using excess power and water in an electrolysis plant to generate both Hydrogen and Oxygen. The hydrogen can be used with the product CO2 to generate more Methanol, while the oxygen can be used within the Gasification Section and reduce the burden on the ASUs.

Jacobs has significant experience in developing and assessing conceptual design proposals and are perfectly placed to do so in this instance. Furthermore, Jacobs with their experience in coal gasification, synthesis conditioning, FT synthesis, Methanol Synthesis, power generation and refineries would be able to manage, engineer, procure and oversee constructing and commissioning of the plant


APPENDIX A CTM PLANT BLOCK FLOW DIAGRAM

CTM PLANT BLOCK FLOW DIAGRAM

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- Coal Handling and PreparationCoal Handling and Preparation

COALCOAL SLOT STORAGE

COAL RECLAIMER

COAL CRUSHER & SCREEN

SCREENED COAL STORAGE

COAL WET MILL UNIT

DMW

DEDUSTING SYSTEM

VENT

PROCESS COND.FROM SYNGAS COND.

COAL SLURRY TANK & PUMP

PREPARED COAL

TO GASIFICATION UNIT

Original CTL Process UnitOriginal CTL Process Unit

1

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- Gasification UnitGasification Unit

BFW FROM STEAM & POWER SECTION

O2

SLAG / WATER SLURRYTO WATER CLEAN UP

BLACK WATER TO WATER CLEAN UP

HP STEAM TO STEAM & POWER SECTIONAIR

AIR SEPARATION

UNIT

N2

O2 TO CLAUS UNIT

PREPARED COAL FROM PREP. UNIT

HOT CANDLE FILTER

BLOW DOWN TO OFFSITE

RAW SYNGAS TO CONDITIONING UNIT

GREY WATERFROM WATER CLEAN -UP

PROCESS CONDENSATE FROM SYNGAS COMP.


2

3

54

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- Slag Handling & Water CleanSlag Handling & Water Clean--UpUp

DRAG CONVEYOR & SLUG SUMP

FLOCCULANTS

OFFGASTO FLARE UNIT

COARSE SLAG PRODUCT

SLAG / WATER SLURRYFROM GASIFIER

BLACKWATER FROM SYNGAS SCRUBBER

VACUUM PACKAGE

ROTARY FILTER

GREY WATER TANK

SLAG SCREEN

VACUUM FLASH DRUM

LP FLASH DRUM

LP SETTLER

LOCK-HOPPER

GREY WATERTO GASIFIER

FINE SLAG PRODUCT

MAKE UP WATER


6

7

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- Syngas ConditioningSyngas Conditioning

MERCURY ABSORBER

COS REACTOR

SYNGAS COOLING

&

ACID GAS REMOVAL UNIT

CLAUS SULPHUR RECOVERY UNIT

RAW SYNGASFROM GASIFIER

CO2 GASTO DRYING/COMP.

TREATED SYNGASTO SHIFT UNIT

SULPHUR PRODUCTO2FROM ASU

FLUE GASTO ATMOSPHERE

ZNO

PROCESS CONDTO GASIFIER

PROCESS CONDTO COAL PREP.

HTS

REACTOR

LP STEAM TO STEAM & POWER SECTION

BFW FROM STEAM & POWER SECTION


8

13

9

12

10

11

4

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- COCO22 Drying & CompressionDrying & Compression

CO2 GAS LP STAGE

COMPRESSIONCO2 PRODUCT GAS

PROCESS COND.

CO2 GAS HP STAGE

COMPRESSION

CO2 GAS DRIER

CO2 GASFROM CONDITIONING UNIT.

0.1 barg40 0C

145 barg45 0C


14

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD –– Shift UnitShift Unit

FEED GAS FROMCONDITIONING UNIT

SHIFT REACTOR

MP STEAM DRUM

TO MP HEADER

FEED GAS BYPASS

MP STEAMFROM HEADER

SATU

RA

TOR

DES

ATU

RA

TOR

MP BFWMAKE-UP

WATERCOOLER

AIR CONDENSER

SYNGAS TO CO2 REMOVAL UNIT

New Process UnitNew Process Unit

15

40.24%

BFW

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD –– CO2 Removal and Syngas CO2 Removal and Syngas CompressionCompression

SYNGAS FROMSHIFT UNIT

FEED GAS BYPASS

WATER COOLER

CO2 PRODUCT GAS

CO2 REMOVAL AND COMPRESSION

UNIT

MDEA

FLA

SH V

ESSE

L

HYDROGEN FROM RECOVERY MEMBRANE

FLA

SH V

ESSE

L

SYNGAS TO METHANOL LOOP

PROCESS CONDENSATE TO TREATMENT


M

SYNGAS COMPRESSOR / CIRCULATOR UNIT

16

17

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- Methanol SynthesisMethanol Synthesis

SYNGAS FROM COMPRESSOR

CRUDE METHANOLTO LETDOWN VESSEL

PURGE TOWASH COLUMN

WATERCOOLER

AIR CONDENSER

METHANOL CATCHPOT

WATERCOOLER

AIR CONDENSER

METHANOLCONVERTER

(SYNGAS COMPRESSOR/) CIRCULATOR

IP STEAM

DRUM

IP STEAM

DRUM

TO IP LETDOWN

METHANOLCONVERTER

METHANOL CATCHPOT


18

BFW BFW

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- Methanol SynthesisMethanol Synthesis

MEMBRANE

PURGE TO PHASE 1A GAS TURBINE

RECOVERED HYDROGEN FOR RECYCLE

METHANOLPRODUCT

DIS

TILL

ATI

ON

REBOILER

WATER BOTTOMS

PURGE

WASHCOLUMN

CRUDE METHANOL

WATER COOLER

LP STEAM

LP CONDENSATE


19

20

21 WATERCOOLER

AIR CONDENSER

WATER COOLER

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- Steam & Power Generation Steam & Power Generation SystemSystem

Steam Turbine / Alternator Set

32 barg, 350 °C

6 barg, 165 °C

76 MW (NET)

115 barg, 500 °C

CONDENSER

LP STEAMFROM SYNGAS COND.

DE-AERATORHP BFW

DMW FROM OFFSITES

MP BFW

LP BFW

CONDENSATETO OFFSITES

USERS

- AGR UNIT

-MDEA UNIT

-DISTILLATION UNIT

BLOWDOWN TO OFFSITE

29 barg, 234 °CBOILER B/DFROM PLANT

MP STEAM CONDFROM USERS

5 barg, SATURATED

130 barg, 106 °C

39 barg, 106 °C

9 barg, 106 °C

DRY TOWERCW

CW

HP STEAMFROM GASIFICATION UNIT

IP STEAMFROM MEOH CONV.

18.1 barg, 210 °C

LP BFW FOR DESUPERHEATER

USERS

- ASU UNIT

- SHIFT UNIT

MP STEAMFROM SRU UNIT

Modified Process UnitModified Process Unit

PHASE 1B CTM PLANT PHASE 1B CTM PLANT -- OffsitesOffsites

CRUDE STORAGE / TRANSFER• Crude Product Storage Tanks• Rerun Tanks• Vent Scrubber

PRODUCT STORAGE / TRANSFER• Methanol Product Storage Tanks• Rail & road transfer facilities for Methanol products• Road transfer facilities for Sulphur products

WATER PURIFICATION• Water Filtration Plant• Water Demineralisation Plant• Condensate Polishing Plant

EFFLUENT TREATMENT• Plant Effluent

TEMPERED WATER• Tempered Water Unit

PHASE 1B CTM PLANT BFD PHASE 1B CTM PLANT BFD -- UtilitiesUtilities

ELECTRICITY• Emergency Generator (Diesel Fuelled)• Substation

COOLING WATER• Evaporative Cooling Tower

PLANT / UTILITY WATER• Separate Tank and Pumps To Supply Plant and Utility Water

NITROGEN• Vaporisation System To vaporise Nitrogen supplied by ASU• Stand alone units to produce Nitrogen backup

PLANT / INSTRUMENT AIR• Multiple Sets Of Units With Stand By

FIRE WATER• Fire Fighting System.


APPENDIX B PLANT MODELS

PLANT MODELS

Tank FarmTank Farm

FT Product

Upgrading

FT Product

Upgrading

Gas Turbine

& HRSG

Gas Turbine

& HRSG

CTM PowerCTM Power

FlareFlareSyngas Re-conditioning

& CO2 Removal

Syngas Re-conditioning

& CO2 Removal

Methanol SynthesisMethanol Synthesis

Air Separation

Units

Air Separation

Units

Cooling WaterCooling WaterSyngas

Conditioning

Syngas

Conditioning

Gasification

Island

Gasification

Island

Coal Storage

and Handling

Coal Storage

and Handling

FT UnitFT Unit

15,000 BPD CTL + 6,200 TPD CTM Plant Model

Tank FarmTank Farm

FT Product

Upgrading

FT Product

Upgrading

Gas

Turbines &

HRSG

Gas

Turbines &

HRSG

FlareFlare

FT UnitsFT Units

Air Separation

Units

Air Separation

Units

Cooling WaterCooling WaterSyngas

Conditioning

Syngas

Conditioning

Gasification

Island

Gasification

Island

Coal Storage

and Handling

Coal Storage

and Handling

Original 30,000BDP CTL Plant Model

Documents

Presented to: ALTONA ENERGY PLC. Non-Confidential … CTM Report June 2013.pdf · Feasibility SStudy For Coal to Methanol l (CTM) Plant t ALTONA ENERGY PLC. Presented to: For: JUNE