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Arif Syed, Davin Nowakowski, Peta Nicholson and Shamim Ahmad 2014, Australian Liquid Fuels Technology Assessment, BREE, Canberra, September.

© Commonwealth of Australia 2014

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Australian Liquid Fuels Technology Assessment

Postal address:

Bureau of Resources and Energy Economics

GPO Box 1564

Canberra ACT 2601

Phone: +61 2 6276 1000, or 61 2 6243 7504

Email: info@bree.gov.au, or arif.syed@bree.gov.auWeb: www.bree.gov.au

AcknowledgementsThe Australian Liquid Fuels Technology Assessment (ALFTA) was undertaken in collaboration with WorleyParsons under contact with BREE. Contributions were also made by ACIL Allen under contract by WorleyParsons. Development of the ALFTA model was supported by a Project Steering Committee and a Project Steering Group comprising members from industry. BREE gratefully acknowledges the guidance and contributions of the Project Steering Committee members, Wayne Calder, Dr Arif Syed and Davin Nowakowski of BREE, Danielle Alexander of the Australian Renewable Energy Agency (ARENA), Professor Thomas Maschmeyer of the University of Sydney, Bruce Godfrey of Wyld Consulting, Dr Alex Wonhas of the Commonwealth Scientific and Industrial Research Organisation (CSIRO) and Jennifer Beckman of the Department of Industry. BREE also acknowledges the valuable contributions of the Stakeholder Reference Group.

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Foreword The Australian Liquid Fuel Technology Assessment (ALFTA) 2014 provides estimates of current and possible future costs of a range of established and emerging liquid fuel production technologies under Australian conditions. The Bureau of Resources and Energy Economics (BREE) engaged the energy consultant WorleyParsons to develop cost estimates for 18 liquid fuel production technologies for this ALFTA project. A Project Steering Committee (PSC) along with a Stakeholder Reference Group (SRG) provided technical advice and inputs in developing the ALFTA modelling framework.

Knowledge of the cost of emerging liquid fuel production technologies will play an important role in determining the future mix of energy supply to meet growing transport fuel demand. Understanding production costs for the wide range of technologies studied will assist in determining the extent to which emerging technologies will be competitive with existing fuel production technologies.

The focus of this work is on generating comparable production cost estimates for liquid fuels anticipated to be used in the transport sector. The ALFTA modelling results indicate that Australia’s transport fuel supply future could well be different to the current conventional petroleum and biofuel mix with alternative liquid fuel technologies becoming more competitive over time.

The levelised cost of fuel (LCOF) estimates are generated from an accompanying 2014 ALFTA model that is free and publicly available via request from the BREE website at www.bree.gov.au .

Wayne Calder

Deputy Executive DirectorBureau of Resources and Energy EconomicsOctober 2014

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ContentsAcknowledgements............................................................................................................................... 2

Foreword............................................................................................................................................... 3

Contents................................................................................................................................................ 4

Tables................................................................................................................................................ 5

Figures............................................................................................................................................... 6

Acronyms and Abbreviations................................................................................................................8

Units of Measure................................................................................................................................. 10

List of Chemical Symbols....................................................................................................................11

Glossary.............................................................................................................................................. 12

Executive Summary............................................................................................................................ 14

1 Introduction.................................................................................................................................. 15

2 Methods and Assumptions..........................................................................................................16

Key points........................................................................................................................................ 16

2.1 Technologies and fuel production paths.............................................................................16

2.2 Macroeconomic assumptions..............................................................................................20

2.3 Technical assumptions........................................................................................................22

2.4 Levelised cost of fuel (LCOF).............................................................................................25

3 ALFTA Technology Assessments................................................................................................30

3.1 Conventional petroleum fuels..............................................................................................30

3.2 Liquid petroleum gas...........................................................................................................31

3.3 Compressed natural gas.....................................................................................................32

3.4 Liquefied natural gas...........................................................................................................33

3.5 Gas to liquids.......................................................................................................................35

3.6 Coal to liquids...................................................................................................................... 37

3.7 Biomass to methanol...........................................................................................................39

3.8 Solar dissociation of CO2 and H2O......................................................................................42

3.9 Conventional bioethanol......................................................................................................43

3.10 Advanced lignocellulosic bioethanol...................................................................................45

3.11 Advanced bioethanol–synthesis gas fermentation.............................................................48

3.12 Biodiesel by transesterification...........................................................................................49

3.13 Hydrothermal upgrade.........................................................................................................50

3.14 HEFA / HVO........................................................................................................................53

3.15 Algal biomass converted via HEFA/HVO............................................................................55

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3.16 Methanol to DiMethyl Ether (DME).....................................................................................57

3.17 Methanol to gasoline...........................................................................................................59

3.18 Fast pyrolysis...................................................................................................................... 60

3.19 Alcohol to jet fuel.................................................................................................................63

3.20 Hydrogenation of bio oil......................................................................................................65

4 Feedstock and Co-product Cost Estimates.................................................................................67

5 LCOF Comparisons.....................................................................................................................69

5.1 Technology tables...............................................................................................................69

5.2 Relative ranking of the ALFTA technologies.......................................................................76

6 Conclusions................................................................................................................................. 79

References.......................................................................................................................................... 80

Appendices......................................................................................................................................... 82

Appendix A: Discount Rates and Correlations for Escalators........................................................82

Appendix B: Production process diagram of liquid fuel technologies............................................84

TablesTable 1 ALFTA technologies..............................................................................................................17

Table 2 ALFTA production paths........................................................................................................18

Table 3 ALFTA technology selection..................................................................................................20

Table 4 Identified economic drivers....................................................................................................21

Table 5 Summary of economic factors...............................................................................................22

Table 6 Regional capital cost factors..................................................................................................23

Table 7 USD/AUD exchange rate projections....................................................................................23

Table 8 Capital cost learning rates by technology type......................................................................24

Table 9 Operation and maintenance escalation rates........................................................................25

Table 10 Operating and maintenance improvement rates.................................................................25

Table 11 Discount rates...................................................................................................................... 27

Table 12 CNG and LNG parameters..................................................................................................33

Table 13 GTL and CTL parameters....................................................................................................38

Table 14 Biomass to methanol and solar dissociation parameters....................................................41

Table 15 Conventional bioethanol, lignocellulosic bioethanol and advanced bioethanol-synthesis gas fermentation parameters..............................................................................................................46

Table 16 Biodiesel by transesterification and hydrothermal upgrade parameters.............................51

Table 17 HEFA/HVO and algal biomass parameters.........................................................................54

Table 18 Methanol to DME and methanol to gasoline parameters....................................................58

Table 19 Fast pyrolysis and hydrogenation of bio oil parameters......................................................61

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Table 20 Feedstock and co-product cost projections by region (Reference Case: Real 2012-2013 A$/GJ)................................................................................................................................................. 67

Table 2 Co-produced fuel cost projections by region (Reference Case: Real 2012-2013 A$/GJ)....68

Table 20 Other co-produced feedstock cost projections by region (Reference Case: Real 2012-2013 A$/GJ)................................................................................................................................................. 68

Table 20 Other feedstock cost projections by region (Reference Case: Real 2012-2013)...............68

Table 24 Cost of petroleum fuels (base case) in East Coast Region (Real 2012-2013 A$/GJ)........70

Table 25 Cost of LPG (base case) in East Coast Region (Real 2012-2013 A$/GJ)..........................70

Table 26 Compressed natural gas plant, LCOF (Real 2012-13 A$/GJ)............................................70

Table 27 Liquefied natural gas plant, LCOF (Real 2012-13 A$/GJ)..................................................71

Table 28 Gas to liquids plant, LCOF (Real 2012-13 A$/GJ)..............................................................71

Table 29 Coal to liquids plant, LCOF (Real 2012-13 A$/GJ).............................................................71

Table 30 Biomass to methanol to DME plant, LCOF (Real 2012-13 A$/GJ).....................................72

Table 31 Biomass to methanol to MTG plant, LCOF (Real 2012-13 A$/GJ).....................................72

Table 32 Solar dissociation to methanol to DME plant, LCOF (Real 2012-13 A$/GJ)......................72

Table 33 Solar dissociation to methanol to MTG plant, LCOF (Real 2012-13 A$/GJ)......................73

Table 34 Conventional bioethanol plant, LCOF (Real 2012-13 A$/GJ).............................................73

Table 35 Advanced lignocellulosic bioethanol plant, LCOF (Real 2012-13 A$/GJ)...........................73

Table 36 Synthesis gas fermentation plant, LCOF (Real 2012-13 A$/GJ)........................................74

Table 37 Biodiesel by transesterification plant, LCOF (Real 2012-13 A$/GJ)...................................74

Table 38 Hydrothermal upgrade to bio-oil to refinery products plant, LCOF (Real 2012-13 A$/GJ).74

Table 39 HEFA/HVO plant, LCOF (Real 2012-13 A$/GJ)..................................................................75

Table 40 Algal biomass via HEFA/HVO, LCOF (Real 2012-13 A$/GJ).............................................75

Table 41 Methanol to DME plant, LCOF (Real 2012-13 A$/GJ)........................................................75

Table 42 Methanol to MTG plant, LCOF (Real 2012-13 A$/GJ)........................................................76

Table 43 Fast pyrolysis to bio oil to refinery products plant, LCOF (Real 2012-13 A$/GJ)...............76

FiguresFigure 1 Compressed natural gas plant, LCOF, East Coast Metropolitan.........................................71

Figure 2 Liquefied natural gas plant, LCOF, East Coast Metropolitan...............................................71

Figure 3 Gas to liquids plant, LCOF, East Coast Metropolitan..........................................................71

Figure 4 Coal to liquids plant, LCOF, East Coast Regional...............................................................72

Figure 5 Biomass to Methanol to DME plant, LCOF, East Coast Metropolitan.................................72

Figure 6 Biomass to Methanol to MTG plant, LCOF, East Coast Metropolitan.................................72

Figure 7 Solar Dissociation to Methanol to DME plant, LCOF, East Coast Metropolitan..................73

Figure 8 Solar dissociation to methanol to MTG plant, LCOF, East Coast Metropolitan...................73

Figure 9 Conventional bioethanol plant, LCOF, East Coast Metropolitan.........................................73

Figure 10 Advanced lignocellulosic bioethanol plant, LCOF, East Coast Metropolitan.....................74

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Figure 11 Synthesis gas fermentation plant, LCOF, East Coast Metropolitan..................................74

Figure 12 Biodiesel by transesterification plant, LCOF, East Coast Metropolitan.............................74

Figure 13 Hydrothermal upgrade to bio-oil to refinery products plant, LCOF, East Coast Metropolitan........................................................................................................................................ 75

Figure 14 HEFA / HVO plant, LCOF, East Coast Metropolitan..........................................................75

Figure 15 Algal biomass via HEFA/HVO plant, LCOF, East Coast Metropolitan..............................75

Figure 16 Methanol to DME plant, LCOF, East Coast Metropolitan..................................................76

Figure 17 Methanol to MTG plant, LCOF, East Coast Metropolitan..................................................76

Figure 18 Fast pyrolysis to bio-oil to refinery products plant, LCOF, East Coast Metropolitan.........76

Figure 19 LCOF for technologies, 2013.............................................................................................77

Figure 20 LCOF for technologies, 2020.............................................................................................77

Figure 21 LCOF for technologies, 2025.............................................................................................77

Figure 22 LCOF for technologies, 2030.............................................................................................78

Figure 23 LCOF for technologies, 2040.............................................................................................78

Figure 24 LCOF for technologies, 2050.............................................................................................78

Figure B1 Conventional petroleum refinery 84

Figure B2 LPG from LNG process......................................................................................................84

Figure B3 Compressed natural gas (CNG)........................................................................................85

Figure B4 Liquefied natural gas (LNG)...............................................................................................85

Figure B5 Gas to liquids (GTL)...........................................................................................................85

Figure B6 Coal to liquids (CTL)..........................................................................................................86

Figure B7 Biomass to methanol..........................................................................................................86

Figure B8 Solar dissociation of CO2 and H2O...................................................................................86

Figure B9 Conventional bioethanol.....................................................................................................87

Figure B10 Advanced lignocellulosic bioethanol................................................................................87

Figure B11 Advanced bioethanol - synthesis gas fermentation.........................................................87

Figure B12 Biodiesel by transesterification........................................................................................88

Figure B13 Hydrothermal upgrade.......................................................Error! Bookmark not defined.

Figure B14 Hydro-processed esters and fatty acids (HEFA) and Hydro-treated vegetable oil (HVO)............................................................................................................................................. 88

Figure B15 Algal biomass converted via HEFA/HVO.........................................................................89

Figure B16 Methanol to dimethyl ether (DME)...................................................................................89

Figure B17 Methanol to gasoline........................................................................................................89

Figure B18 Fast pyrolysis................................................................................................................... 90

Figure B19 Alcohol to jet fuel..............................................................................................................90

Figure B20 Hydrogenation of bio-oil...................................................................................................90

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Figure B21 Bio-oil upgrade.................................................................................................................91

Figure B22 Processing of bio-crude to refined products....................................................................91

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Acronyms and AbbreviationsAETA Australian Energy Technology Assessment

ALFTA Australian Liquid Fuels Technology Assessment

ASU Air Separation Unit - to separate constituent gases, usually oxygen, from

ATR Auto Thermal Reformer

AvGas Aviation Gasoline

BBL Barrels

BFW Boiler Feed Water

BOE Barrels of Oil equivalent

BPD Barrels per day

BPSD Barrels per stream day

BREE Bureau of Resources and Energy Economics

BTL Biomass to Liquids

CCS Carbon Capture and Sequestration

CFB Circulating Fluidised Bed

CIP Clean in Place

CN Cetane number - measure of the ignition characteristics of diesel fuel oil

CNG Compressed Natural Gas

CTL Coal to Liquids

CW Cooling Water

DDGS Distiller's Dried Grains with Solubles

DME DiMethyl Ether

DOE Department of Energy USA

EPC Engineer, Procure, Construct

FAME Fatty Acid Methyl Ester biodiesel - to distinguish from petroleum derived

FCC Fluidised Catalytic Cracking

F-T Fischer-Tropsch - process to convert synthesis gas to liquid fuels

GDP Gross Domestic Product

GJ Giga Joule - 109 Joules

GSP Gross State Product

GST Goods and Services Tax

GTL Gas to Liquids

Ha Hectare

HEFA Hydroprocessed esters and fatty acids

HPU Hydrogen Production Unit

HRJ Hydrotreated Renewable Jet (fuel)

HVO Hydrotreated Vegetable Oil

ISBL Inside Battery Limits - within the plant boundary

LCOF Levelised Cost of Fuel in $/GJ

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LHV Lower Heating Value

LNG Liquefied Natural Gas

LPG Liquid Petroleum Gas

M Million

MDP Metropolitan Delivered Price

MeOH Methanol, chemical formula CH3OH

MONMotor Octane Number - measure of resistance to self-ignition under high speed, high load conditions for gasoline

MSW Municipal Solid Waste

MTG Methanol to Gasoline

MWh Megawatt hour

NCF New CO2 Fuels

NGL Natural Gas Liquids

NGVA Natural Gas Vehicles for America

NREL National Renewable Energy Laboratory

O & M Operations and Maintenance

OSBL Outside Battery Limits - outside the plant boundary

PSAPressure Swing Adsorption -- separation process frequently applied for separation of hydrogen from heavier molecules

PSC Project Steering Committee

RO Reverse Osmosis

RONResearch Octane Number - measure of resistance to self-ignition under low at low speed, low load conditions for gasoline

RVP Reid Vapour Pressure - measure of volatility of gasoline

SMRSteam Methane Reforming - production of a synthesis gas mixture of CO and H from natural gas CH4

SRG Stakeholder Reference Group

SRU Sulphur Recovery Unit

t Metric tonne

TGP Terminal Gate Price

tpy Tons per Year

ULP Unleaded Petrol

VOC Volatile Organic Compounds

wt per cent Per cent by weight

Yr Year

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Units of MeasureEach industry has units that have been traditionally used to measure the output of production plants. Traditional Petroleum industry units are related to barrels of crude oil, while biomass is often measured in dry tonnes.

To allow the direct comparison of the cost of fuel in the LCOF, the output of each fuel will be calculated using units of Giga Joules (GJ), 109 Joules.

Energy source Unit Abbreviation LHV Unit

Crude oil Barrels Bbl 5.8 GJ/bbl

LPG Tonnes t 46 GJ/t

CNG Tonnes t 47.5 GJ/t

LNG Tonnes t 47.5 GJ/t

Diesel Litres L 0.038 GJ/L

Jet Tonnes t 0.031 GJ/L

Petrol Litres L 0.031 GJ/L

Ethanol Litres L 0.027 GJ/L

DME Tonnes t 28.9 GJ/t

Woody Biomass Dry tonnes T 15.6 GJ/t

Natural oils Tonnes t 37 GJ/t

Brown Coal Tonnes t 10 GJ/t

Grain (Wheat) Tonnes t 16 GJ/t

Methanol tonnes t 20 GJ/t

FAME Biodiesel Litres L 0.033 GJ/L

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List of Chemical SymbolsA range of chemical symbols have been used throughout this report. These have been listed here for reference.

Symbol Chemical

CH3OH Methanol

C2H5OH Ethanol

CH3OCH3 Di-methyl Ether (DME)

CO Carbon monoxide

CO2 Carbon dioxide

CO2-e Carbon dioxide equivalent

H2 Hydrogen

H2O Water

H2SO4 Sulphuric acid

NH3 Ammonia

N2 Nitrogen

NaOH Sodium hydroxide (caustic)

NO Nitric oxide

NO2 Nitrogen dioxide

NOx Oxides of nitrogen

O2 Oxygen

S Sulphur

SO2 Sulphur dioxide

SOx Oxides of sulphur

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GlossaryAcid Gas Removal Removal of CO2 and SO2, usually through the use of an amine

solvent

Air Separation Unit (abbr. ASU) For isolation of the various components of air, with oxygen being the most common primary product

Anaerobic digestion A process where bacteria breakdown organic material in the absence of oxygen to produce biogas containing methane

Auto Thermal Reformer (abbr. ATR) Reactor to oxidise natural gas to produce synthesis gas

Battery limit The defined boundary for interfaces between the plant and the external infrastructure.

Bio Crude Bio oil after hydrogenation treatment to reduce oxygen and boost hydrogen content

Bio Oil Product from processes such as Hydrothermal upgrade and fast pyrolysis of biomass. Requires further hydrogenation treatment to reduce oxygen and boost hydrogen content create bio crude before it can be refined into finished fuel products

Carbon Capture and Sequestration (abbr. CCS)

The capture of CO2, usually from a high concentration gas stream, transport and sequestration in a suitable geological structure or reservoir

Clean in Place (abbr. CIP) Use of heat, water and chemicals to clean equipment, such as pipes, vessels and machinery, without disassembly

Distillation Method for separation of liquid mixtures based on the boiling point

Distillers Dried Grains with Solubles (abbr. DDGS)

Nutrient rich co-product of ethanol production, used as an animal feed for its energy and protein content

Fischer Tropsch (abbr. F-T) Process to convert synthesis gas to liquid hydrocarbons

Fluidised Catalytic Cracking (abbr. FCC)

Process to convert heavy hydrocarbon molecules into lighter, higher value products at high temperature using a catalyst

Gasification The production of a synthesis gas from a solid, carbon containing material such as coal or biomass

Higher Heating Value (abbr. HHV) The gross amount of heat released when combusting a fuel, with the combustion products and water vapour returned to their original temperature

Hydrocracking Catalytic Cracking (abbr. HCC)

Process to convert heavier hydrocarbon molecules into lighter, higher value products using hydrogen and a catalyst

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Hydrogen Production Unit (abbr. HPU)

General term for a process that produces Hydrogen and includes specific technologies such as Steam Methane Reforming

Hydrolysis A reaction where a chemical bond is broken by the addition of water, for example, when carbohydrate is broken down into its component sugar molecules

Hydrotreating The addition of hydrogen to break a Carbon to Oxygen, Sulphur or Nitrogen bond

Levelised Cost of Fuel (abbr. LCOF) The cost of fuel production in real dollar terms incorporating all cost amortised over the economic life of the plant. Unit is $/GJ of fuel produced.

Lower Heating Value (abbr. LHV) The net amount of heat released when combusting a fuel, with the heat required to vaporise the water content subtracted

Natural Gas Liquids (abbr. NGL) Co-produced heavier hydrocarbons fractions (propane, butane) resulting from the production of Natural Gas (methane)

Pressure Swing Absorption (abbr. PSA)

Technique for separating gas mixtures using an absorbent material. Often used to separate hydrogen from heavier molecules.

Pyrolysis Heating and decomposition of organic material without oxygen at high temperatures

Reverse Osmosis (abbr. RO) Process for removing minerals and other impurities from water by forcing high pressure feedwater through a semi-permeable membrane

Shift Reaction To adjust the ratio of CO / H2, usually through the addition of water or steam

Steam Methane Reforming (abbr. SMR)

Steam is added to natural gas to produce a syngas mixture of CO and H2

Sulphur Recovery Unit (abbr. SRU) Recovery of sulphur from gas streams into a liquid form

Synthesis Gas (abbr. Syngas) Mixture of CO, H2, H2O and CO2. Ration of CO/H2 can be adjusted through shift reactions

Transesterification The conversion of fat or oil with alcohol, such as methanol, to produce methyl esters or biodiesel

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Executive SummaryThe Australian Liquid Fuels Technology Assessment (ALFTA) project was undertaken by the Bureau of Resources and Energy Economics (BREE) with the Australian Renewable Energy Agency (ARENA) providing partial financial support. BREE engaged the energy consultant WorleyParsons to develop cost estimates for 18 liquid fuel production technologies for the ALFTA project. WorleyParsons engaged ACIL Allen to assist with market projections of feed and fuel price scenarios. The ALFTA project was guided by a Project Steering Committee (PSC) and received inputs from a Stakeholder Reference Group (SRG). These groups provided technical advice, evidence and review of the modelling framework and specific technology cost parameters.

The ALFTA report provides most recent estimates of the current and future costs of a range of present and potential liquid fuel production technologies under Australian conditions. These are from renewable sources, for example, biodiesel as well as non-renewable sources, such as various forms of fossil fuel. The focus of this work was on the use of these liquid fuels as transport fuels.

The ALFTA Levelised Cost of Fuel (LCOF) estimates were developed for the period out to 2050. LCOF estimates are provided for several specific years, being as at 2013, 2020, 2025, 2030, 2040 and 2050. The LCOF is expressed in real Australian dollars per gigajoule of energy content, and is indicative of the gate price at which liquid fuels must be sold for a single plant to break even, taking into account the costs incurred over the life of the plant.

The LCOF estimates are based on specific, consistent and transparent assumptions on technology design basis, plant characteristics and performance parameters. These are clearly set out in the report.

Broadly, these LCOF estimates reflect the following cost components:

Capital stock estimates; Feed and energy, main product and by-product cost estimates; Operations and maintenance (O&M) cost estimates.

The key findings of the report are as follows:

1. There are several currently available technologies from which fuel production is already competitive with conventional petroleum fuels, i.e. have a lower LCOF. With the exception of LPG and CNG, none of these low LCOF alternatives have yet been implemented in Australia. By 2020, multiple emerging technologies are expected to be available at a lower LCOF than petroleum fuels. Examples of these competitive emerging technologies are Coal to Liquids (CTL) and Gas to Liquids (GTL).

2. The two non-renewable technologies of CTL and GTL offer the lowest estimated LCOF over most of the projection period, and they remain cost competitive with the lower cost renewable technologies out to 2050. However, it should be noted that these LCOF estimates do not include carbon pricing or the cost of carbon capture.

3. Advanced biomass fuel technologies in 2020 are some of the most cost competitive sources of liquid transport fuel, and the advanced bioethanols are projected to remain cost competitive out to 2050.

4. Some other renewable technologies such as sugar/starch derived liquid fuels or natural oil derived fuels or solar conversion fuels, which although less competitive for most of the timeframe to 2050, are expected to have LCOF values approaching those of conventional petroleum fuels by 2050.

The results indicate that Australia’s fuel supply future could well be different to the present conventional petroleum and biofuel mix. This has likely implications for government policy to further encourage the domestic fuel production and/or distribution of alternative emerging liquid fuels.

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1IntroductionThe Australian Liquid Fuels Technology Assessment (ALFTA) 2014 provides rigorously and consistently derived cost estimates for liquid fuel production using a wide range of technologies under Australian conditions. It presents cost estimates for 18 conventional and emerging liquid fuel production technologies from 2013 out to 2050. Twelve of the 18 costed technologies require either pre-processing of the feedstock or produce an intermediate product that requires further processing to a final fuel. Cost estimates have been derived for the fuel production path from feedstock to final fuel.

The cost estimates take into account current and projected technical viability, feedstock and co-product prices and availability, capital costs, operating costs, and barriers to development and implementation of production technologies. Equipment components are identified as either locally or internationally sourced for independent cost indexation.

A key comparable cost across technologies, and one of the estimates presented in this report, is the Levelised Cost of Fuel (LCOF), which is expressed in real Australian dollars per gigajoule of energy content. The LCOF is indicative of the price at which liquid fuels must be sold for at the gate of a single plant to break even, taking into account the costs incurred over the life of the plant.

The ALFTA report is supplemented by the ALFTA model used to generate the LCOF estimates. This model is free and publicly available on request from the Bureau of Resources and Energy Economics (BREE) at info@bree.gov.au . The model gives regionally specific cost estimates and provides for users to alter a number of cost parameters to meet user-specific needs and to explore the LCOF estimates’ sensitivity to the user’s input.

The focus of the report and the accompanying model is on the costs associated with the specified fuel production paths and technologies, and does not extend to consider the broader costs of integration into regional or national infrastructure. While the LCOF is an invaluable tool for comparing liquid fuel production costs, incumbent or prospective liquid fuel producers or investors who wish to produce, or otherwise invest in, a fuel production technology, would also need to consider other criteria such as site-specific costs or experience with the technology prior to any final investment decision.

Section 2 of the ALFTA report outlines the Assessment’s assumptions, both economic and technical, and provides an overview of the methods involved in calculating the LCOF and component costs estimates. Section 3 details the studied technologies including a description of each technology and the process involved, specifying the technical basis for the LCOF estimates. Section 4 provides the feedstock costs and co-product price projections for the reference case by region over the outlook period to 2050. Section 5 gives the ALFTA modelling results, that is, the LCOF estimates for 20 liquid fuel technology paths in Australia to 2050, and compares the LCOF estimates across technologies. Section 6 provides concluding remarks.

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2Methods and AssumptionsKey pointsTechnologies and Fuel Production Paths

Eighteen liquid fuel production technologies are examined and 21 corresponding liquid fuel production paths are evaluated.

Macroeconomic assumptions This study considers the technology development and pricing paths under an economic

scenario used in the Australian Energy Technology Assessment (AETA 2013). This is a scenario that projects middle range economic growth assumptions. This scenario is presented in Table 4.

Technical assumptions All fuel production paths are costed on a consistent and transparent basis, with itemisation

of component costs. Capital cost estimates include direct (e.g. engineering, procurement and construction) and

indirect (owners') costs, but exclude integration and decommissioning costs. Projected growth rates of future operating and maintenance cost estimates are provided,

inclusive of both escalation and improvement rates. Future cost estimates draw on projections of the exchange rate, labour productivity,

commodity variation and capital cost learning rates. All feedstock, utility and co-product cost estimates were developed by ACIL Allen.

Levelised Cost of Fuel (LCOF)The LCOF reflects the minimum price at which a liquid fuel producer must sell their product at the gate in order to break even. Key inputs to the ALFTA model used in the calculation of the LCOF for the studied production paths include an amortisation period, discount rate, utilisation rate, emissions factor, CO2 emissions cost, feedstock costs, operating and maintenance costs (including co-products and energy) and capital costs. The LCOF estimates presented in this report reflect the repeal of the carbon pricing policy and these exclude a carbon price.

2.1 Technologies and fuel production pathsOf the 18 liquid fuel production technologies studied in the ALFTA project, six technologies take a feedstock and produce a final fuel. The remaining technologies require either pre-processing of the feedstock or produce an intermediate product that requires further processing to a final fuel. It is the fuel production path that has been evaluated to generate the LCOF estimates and included in the ALFTA model and report. To enable an LCOF to be estimated for an upgraded bio crude oil from technology 13, Hydrothermal Upgrade, suitable for feed into a conventional petroleum refinery, technology 19 has been added.

Table 1 shows the technologies studied in the ALFTA. Technologies 14, 15 and 17 have distinct feed oil properties and therefore involve independent estimation of costs for the hydrogenation step of the fuel production process.

For the identified production technologies, 21 liquid fuel production paths are evaluated. Table 2 shows the production paths evaluated in the ALFTA.

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Table 1 ALFTA technologiesStudy/technology number Technology

1 Conventional Petroleum Fuels

2 Liquid Petroleum Gas

3 Compressed Natural Gas

4 Liquefied Natural Gas

5 Gas to Liquids

6 Coal to Liquids

7 Biomass to Methanol

8 Solar Dissociation of CO2 and H2O

9 Conventional Bioethanol

10 Advanced Lignocellulose Bioethanol

11 Advanced Bioethanol - Synthesis Gas Fermentation

12 Biodiesel by Transesterification

13 Hydrothermal Upgrade

14 Algal Biomass via HEFA/HVO

15 HEFA/HVO

16a Methanol to DME

16b Methanol to Gasoline

17 Fast Pyrolysis

18 Alcohol to Jet

19 Hydrogenation of Bio Oil

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Table 2 ALFTA production paths

Path Front End Process Feedstock Intermediate Product Back End Process Final Fuel Product(s)

No. Name No. Name

A 1 Conventional Petroleum Refining

Crude Oil N/A N/A LPG, Petrol, Diesel, Jet

B 2 Liquid Petroleum Gas Crude Oil / Natural Gas Liquids

N/A N/A LPG

C 3 Compressed Natural Gas Natural Gas N/A N/A CNG

D 4 Liquefied Natural Gas Natural Gas N/A N/A LNG

E 5 Gas to Liquids - F-T Natural Gas Synthesis gas N/A Fischer–Tropsch LPG, Naphtha, Diesel, Jet

F 6 Coal to Liquids - F-T Coal Synthesis gas N/A Fischer–Tropsch LPG, Naphtha, Diesel, Jet

G 7 Biomass to Methanol Biomass Methanol 16a DME DME

H 7 Biomass to Methanol Biomass Methanol 16b MTG Petrol, LPG

I 8 Solar Dissociation - Methanol

CO2, Water Methanol 16a DME DME

J 8 Solar Dissociation - Methanol

CO2, Water Methanol 16b MTG Petrol

K 9 Conventional Bioethanol Starch, sugars Aqueous Ethanol N/A Distillation and drying Ethanol

L 10 Advanced Lignocellulose Bioethanol

Woody biomass Aqueous Ethanol N/A Distillation and drying Ethanol

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Path Front End Process Feedstock Intermediate Product Back End Process Final Fuel Product(s)

No. Name No. Name

M 11 Advanced Bioethanol - Synthesis gas Fermentation

Woody biomass Aqueous Ethanol N/A Distillation and drying Ethanol

N 12 Biodiesel by transesterification

Vegetable oil, tallow N/A N/A FAME Diesel

O 13 Hydrothermal Upgrading Biomass Stabilised bio oil 19 +1 Hydrogenation of Bio Oil + Conventional Petroleum Refining

LPG, Petrol, Diesel, Jet

P 14 Algal Biomass CO2, Water, sunlight Algae oil 15 HEFA / HVO Diesel, Naphtha

Q 15 HEFA / HVO Vegetable oil, tallow N/A N/A Diesel, Naphtha

R N/A Methanol 16a DME DME

S N/A Methanol 16b MTG Petrol, LPG

T 17 Fast Pyrolysis Biomass Stabilised bio crude 1 Conventional Petroleum Refining

Diesel, Jet, Petrol

U N/A Ethanol, Iso-butanol 18 Alcohol to Jet Jet

Source: WorleyParsons

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The 18 technologies studied were included in scope based on Technical Readiness Level (TRL), Commercial Readiness Index (CRI), availability of meaningful industry information and applicability to Australian circumstances.

TRL is evaluated on a scale from 1: basic technology research, to 9: system test, launch and operations. The CRI scale is from 1: hypothetical commercial proposition, to 6: bankable asset class. Australian relevance is on the scale L: low, to H: high. Further details on TRL and CRI can be found on the ARENA website (ARENA 2013).

Table 3 shows the TRL, CRI and Australian relevance ratings for prospective ALFTA technologies. These ratings were developed based on a combination of research undertaken by BREE, WorleyParsons and engagement with technology stakeholders.

Table 3 ALFTA technology selectionTechnical

Readiness LevelCommercial

Readiness LevelAustralia

RelevanceIncluded technologies

Conventional petroleum fuels 9 6 M-H

Liquid petroleum gas 9 6 H

Compressed natural gas 9 4 M-H

Liquefied natural gas 9 3 M-H

Gas to liquids 9 4 L-M

Coal to liquids 9 4 L-M

Biomass to methanol 5-7 1 M

Solar dissociation 4-6 1 M-H

Conventional bioethanol 9 6 L-M

Advanced lignocellulose bioethanol 5-8 1-2 M

Advanced bioethanol - synthesis gas fermentation 4-6 1-3 M

Biodiesel by transesterification 9 6 L-M

Hydrothermal upgrade 3-5 1 M

HEFA/HVO 9 4 L-M

Algal biomass via HEFA/HVO 4-6 1-2 M

Methanol/DME/MTG 9 6 L-M

Fast pyrolysis 6-8 1-2 M

Alcohol to jet 5-7 1 L

Excluded technologies

Oil Extraction (Oil Seed Feed) 8-9 1-2 L-M

Direct Sugar to Hydrocarbons 5-7 1 L

Shale to Liquids 7-8 1-2 M

Direct Injection Coal Engine 6-8 1-2 M

Source: WorleyParsons

2.2 Macroeconomic assumptions

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This study considers technology development and pricing paths under one of the economic scenarios used in the AETA – the medium scenario. This provides for consistency in assessment of technologies between the ALFTA and AETA reports.

The Stakeholder Reference Group considered that this scenario provided a feasible estimate of the future of the economy, including identified and quantified key drivers of change. The scenario is an attempt to quantify the most likely trajectory of the economy, as opposed to business as usual. The identified drivers are listed in Table 4 below.

Table 4 Identified economic driversFactor Scenario Prediction Proxy Variable Impacted Capital Cost

components

National Economic Growth

Medium estimate consistent with current growth

Australian GDP, assume 2.5% year on year growth

Commodity/Construction & Equipment (50% sensitivity)

Exchange Rate Based on scenario selected

Exchange rate (per ACIL Allen supplied data) – Refer Table 7

Australian dollar moving to 0.90 USD/AUD in 2013, falling to 0.75 USD/AUD by 2020.Flat at 0.75 USD/AUD through to 2050

Global economic growth

Global recovery continues with ongoing growth in the demand for Australian commodities, particularly resources

Major equipment supplier countries average GDP growth 2.5%

Equipment (50% sensitivity)

Population growth Moderate growth GDP and specific (output/hour worked) Labour productivity

Commodity/Construction (as per econ growth) and Labour productivity (+0.8% p.a.)

Carbon Price No carbon price included in the LCOF

No Carbon price included – user can input their own carbon price

Commodity (5% weighted average price sensitivity), and major equipment (1% sensitivity)

East Coast LNG export

Commencing 2014 and to consume approximately 2/3 of East Coast gas by 2020

Affects fuel input via gas prices, some sensitivity for commodity prices

See domestic gas prices

Domestic gas prices Increasing connection to international LNG prices via a “net-back” calculation

Affects fuel input via gas prices, some sensitivity for commodity prices

2% commodity sensitivity

Global technology R&D

Moderate Technology-specific development, cost reduction curves (due to selection of technology and build out)

Technology-specific cost reduction curves

Source: WorleyParsons

The economic factors as outlined above are reflected in a number of inputs that impact forward costs for capital and operations and maintenance for a process plant.

The LCOF estimate calculation accounts for these economic factors through forward increases in local equipment, international equipment and labour costs. Rising labour rates are accounted for by an increase in overall Operation and Maintenance (O&M) costs (assumed to be rising at 150 per

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cent of the CPI), while overall O&M productivity improvements reflect, among other things, improved labour productivity (resulting in a decrease in labour costs for plant delivery). A summary of these factors over the forecast period is provided in Table 5 below. The rates are expressed as the total percentage change from 2013 to the specified year.

Table 5 Summary of economic factors

2020 2025 2030 2040 2050Local Equipment Escalation rate 4.8% 7.9% 11.0% 16.7% 22.7%International Equipment Escalation rate 4.1% 6.8% 9.7% 15.4% 21.4%Labour Improvement rate (6.2%) (10.0%) (13.5%) (20.0%) (24.3%)O&M Escalation rate 7.6% 12.4% 17.1% 26.6% 36.1%Source: WorleyParsons

The overall impact of these factors is an escalation of both the capital and operating costs for a plant over time, the extent of which is dependent on the characteristics of the specific technology, since the relative breakdown of capital costs into local equipment, international equipment and local labour is technology specific. Note that these projections do not reflect any unusual market constraints for equipment or materials supply or construction resources. During the last decade, and especially from 2006 until 2009, overall plant construction indices almost doubled due to such constraints.

Carbon price assumptionsThe LCOF estimates presented in this report exclude a carbon price. However, the LCOF model allows users to input a carbon price in $/tonne of CO2-e for 2013, 2020, 2025, 2030, 2040 and 2050. An option has been included in the LCOF model to view the LCOF results for each technology based on inclusion or exclusion of the carbon price.

2.3 Technical assumptionsCapital cost estimates Capital cost estimates were developed with reference to a number of sources depending on the technology basis, the technology maturity, and the extent of experience of Australian industry in deploying the technology. The objective was to ensure that capital cost estimates were derived as consistently as possible across all technologies with consideration given to the variability in the quality of information available.

Capital cost estimates for established technologies where WorleyParsons has direct experience have been developed from WorleyParsons’ in-house data using appropriate cost factors to translate costs to an Australian context. Where emerging technologies are assessed, stakeholder submissions, WorleyParsons’ in-house data, public domain data, and reports have been investigated to provide a contemporary cost base for these technologies.

The primary aims of the approach to developing the capital cost bases for the technologies have been to establish a sound estimate of the magnitude of the capital cost for deployment of the technology (in the year of deployment) and to apply a methodology as consistently as possible for developing cost estimates across the technologies.

In addition to establishing expected capital costs for plants (i.e. the capital cost for an average project in Australia), the impact of regional factors on-costs has been estimated. These factors include different labour cost structures, material transport to site and additional costs associated with remote sites. For the purpose of this study, the country has been broken down into four geographical areas and a capital cost regional factor applied as shown in Table 6 below (Rawlinsons 2013).

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Table 6 Regional capital cost factorsRegion Capital cost factorEast Coast Metropolitan 100%

East Coast Regional 105%

West Coast Metropolitan 105%

West Coast Regional 120%Source: WorleyParsons

The accuracy of cost estimates has been stated for each technology in Section 3 of this report. It should be noted that costs include infrastructure identified within the battery limits, and exclude site-specific information, which may have a significant effect on project costs.

A breakdown of capital costs is provided for each technology based on imported and local equipment installation costs and owners’ costs. The estimates are based on delivery of each technology by a turnkey Engineering, Procurement and Construction (EPC) contractor. Capital cost estimates are thus provided on an ‘as delivered’ basis, including all owners’, EPC, labour and equipment costs. Owners’ costs are all costs outside the EPC contract. Thus, owners’ costs could include owners’ staff salaries, project office costs, Owners’ Engineer and management fees.

Capital costs have been correlated with crude oil prices, with a coefficient of 0.94, based on historical linkages between oil prices and project capital costs, such that a 1 per cent increase in Brent oil prices consequences a 0.94 per cent increase in capital costs (ceteris paribus). This correlation along with other variables including labour productivity growth, commodity variation and capital cost learning rates has been used to estimate capital costs to 2050. Further information on the correlations can be found in the ACIL Allen advisory note in Appendix A.

Forward curve assumptionsExchange rate projectionsExchange rate projections have been developed by ACIL Allen and are shown in Table 7 for the base scenario.

Table 7 USD/AUD exchange rate projections2013 2020 2025 2030 2040 2050

USD/AUD Exchange Rate 0.9 0.81 0.75 0.75 0.75 0.75

Source: ACIL Allen

Productivity rate assumptionsSpecific labour productivity growth (expressed as worker output per hour worked) was used to modify the labour component of the capital cost estimates for each technology. A baseline of 0.8 per cent per annum improvement in output per hour was assumed.

Commodity variationCommodity variation was assumed to vary approximately with the growth rate of GDP. The value and profile for commodity variation was linked to the average GDP/ GSP profile for Australia over the period 2013 to 2050.

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Capital cost learning ratesTo allow for different rates of reduction in capital cost per unit of fuel produced, learning rates for both established and emerging technologies were estimated as shown in Table 8.

Table 8 Capital cost learning rates by technology typeTechnology type 2013 2020 2025 2030 2040 2050

Established – annual 1% 1% 1% 0.2% 0.2% 0.2%Emerging – annual 1.5% 1.5% 1.5% 1% 1% 1%Source: WorleyParsons

The learning rates were developed by WorleyParsons and ACIL Allen, and they underlie the LCOF estimates provided in the Model.

Feedstock, utility and co-product cost estimatesACIL Allen provided feedstock, utility and co-product cost estimates for each of the target years out to 2050. The analysis includes all factors that affect the price of inputs, with the exclusion of a carbon price (which the model allows to be applied separately, although a carbon price is not included in the results within this report). A summary of the feedstock costs used in the ALFTA model is provided in Section 4.

Where possible, the feedstock prices are appropriate to the Australian regions. The basis for this pricing is the selection of the feedstock that is available in the volume required for the technology. Feedstock availability in specific regions has been identified. Where a feedstock is available in an adjacent region (a metropolitan versus a regional location) an estimate of transport costs has been added to the price for the region in question.

The input and co-product prices have been developed utilising the forecast economic scenario conditions, with upper and lower confidence bounds based on the high and low growth global economic scenarios. Input costs are in 2013 dollars.

Operating and maintenance cost estimatesCost estimates for operations and maintenance (O&M) costs are provided, and where possible these are divided into fixed and variable components. These are high-level median estimates based on WorleyParsons’ in-house data, public domain information and stakeholder input. Owners’ operations and maintenance practices for any given specific facility may significantly affect the variability of these costs.

Operating and maintenance costs exclude feedstock costs and costs of carbon emissions, as these are dealt with separately in establishing the LCOF with zero costs of carbon emissions.

Fixed operating and maintenance costs (FOM) are estimated as an annual cost per GJ of capacity and include the following elements for each technology:

direct and home office labour and associated support costs; fixed service provider costs; minor spares and fixed operating consumables; fixed inspection, diagnostic and repair maintenance services; scheduled maintenance for entire plant including balance of plant; and insurance costs.

Insurance and maintenance costs are considered fixed for a given asset.

Variable operating and maintenance costs (VOM) are estimated as a cost per GJ of production and include the following elements:

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chemicals and operating consumables that are production dependent: e.g. water; catalysts; treatment chemicals;

co-products produced as a revenue stream; utility supply – electricity and natural gas; and unplanned maintenance.

Co-product revenues are included as a negative variable cost. Where electricity is exported, this is also included as a negative cost using a wholesale rather than retail price for electricity.

Operation and maintenance escalation ratesProcess industry labour costs (both in-house and service provider) generally increase at rates above the CPI in competition with other industries seeking the same skills, usually in the same geographical area. Spare parts typically escalate at a mix of the metals index and labour rate increases. These escalation pressures dominate the FOM escalation rate.

The VOM escalation rate is also estimated to exceed the CPI, as the CPI is typically a poor indicator of increases in utility and maintenance costs. In each case, a number of the household variables that exert downward pressure on the CPI measure are not present within process industry O&M costs.

The escalation rates estimated in the table below (Table 9) reflect these factors. Escalation rates are kept consistent across all technologies in the LCOF calculation.

Table 9 Operation and maintenance escalation ratesFOM Escalation Rate (%of CPI) 150

VOM Escalation Rate (%of CPI) 150

Source: WorleyParsons

Operation and maintenance improvement ratesIn addition to the O&M escalation rate, a factor has been included to account for improvements in O&M efficiency through equipment and process improvements. This factor has been estimated independently for established and emerging technologies as shown in Table 10 below, and is able to be varied by the user in the LCOF model.

The O&M improvement rates have been established based on estimates of improvement for established and emerging technologies for each doubling of production combined with estimates of technology adoption.

Table 10 Operating and maintenance improvement ratesTechnology Status 2013 2020 2025 2030 2040 2050

Established – annual 0.2% 0.2% 0.2% 0.2% 0.2% 0.2%

Emerging – annual 2.5% 2.5% 2.5% 0.2% 0.2% 0.2%

Source: WorleyParsons

2.4 Levelised cost of fuel (LCOF)Levelised cost is a frequently used technique for comparing the cost of different competing technologies. This section provides an overview of the methods involved in calculating the levelised cost of liquid fuel.

The LCOF reflects the minimum cost at which the liquid fuel producer must sell the produced fuel in order to breakeven. It is equivalent to the long-run marginal cost of liquid fuel at a given point in time because it measures the cost of producing one extra unit of liquid fuel.

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The LCOF, in this study, is calculated using a bottom-up engineering method by costing each constituent part of the total cost of a technology, such as the capital cost, capacity factor, variable and fixed operations and maintenance costs, discount rate, the amortization period (or life span), and feedstock costs.

The calculation of LCOF requires a significant number of inputs and assumptions. The formula for calculating the LCOF and its component parts are defined below.

LCOF=∑t=1

n I t+M t+F t

(1+r )t

∑t=1

n Et

(1+r )t

LCOF = Average lifetime levelised fuel production cost ($/GJ)It = Capital Investment expenditures in the year t ($)Mt = Operations and Maintenance expenditures in the year t ($)Ft = Feedstock expenditures in the year t ($)Et = Fuel Production in the year t (GJ)r = Discount rate (%)n = Life of system + construction period (Amortisation) (year)It = Capital Cost ($/GJ net) x Net Plant Capacity (GJ) Mt = Fixed O&M ($/GJ) x Net Plant Capacity (GJ) + Variable O&M ($/GJ) x Net Plant Capacity (GJ)

x utilisation factor100 + Carbon Price ($/tCO2-e) x Emissions (tCO2-e) x utilisation factor100

Ft = Feedstock Cost ($/GJ) x Net Plant Capacity

Energy Yield100

(GJ) x utilisation factor100

Et = Net Plant Capacity ($/GJ) x utilisation factor100

LCOF key inputsKey inputs that affect the LCOF calculation are as follows:

a. amortisation periodb. discount ratec. utilisation factord. emissions factore. CO2 emissions costf. feedstock costg. variable and fixed O&M (including co-products and energy)h. capital cost

This study provides the estimated LCOF values for liquid fuel production from plants constructed in each of the years 2013, 2020, 2025, 2030, 2040 and 2050. The LCOF values have only been estimated for years where a plant will be commercially available at that time. Where required, costs

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and economic indicators beyond 2050 are used as inputs into the LCOF estimation. In this case, the value of the indicator or input in 2050 is assumed to remain constant in real terms for future years.

All component costs and factors are converted into common units to develop the LCOF in terms of real 2012-2013 A$/GJ.

It is important to note that while a given plant type may be commercially deployed internationally, there may be a lead time associated with local development and deployment of the technology (due to regulatory, physical or commercial constraints). Thus, while this study provides LCOF estimates for technologies that are commercially deployed in a specific year, there may be a significant time delay to facilitate deployment in Australia.

Amortisation periodThe amortisation period for the LCOF calculation defines the period over which the plant must achieve the economic return required. There are a number of approaches that may be taken to establish the value of the amortisation period. This includes:

Life of plant – an estimate of the operating life of a particular technology prior to revamping or decommissioning; and

Finance term – the expected amortization period for finance for a project.

An amortisation period of the construction period plus the plant economic life has been adopted. For example, Technology 5, Gas to Liquids has a construction period of four years and an economic life of 30 years. The amortisation period is therefore 34 years.

All technologies have been analysed on the basis of an economic life of 30 years.

Discount rateThe discount rate applied to the estimation of LCOF reflects a number of factors including:

Cost of capital for the project; and Risk associated with the technology and project.

It is recognised that the commercial discount rate applied to a project will be influenced by factors including technology and market risk, technology maturity and track record. Often, the discount rate will also be influenced by project-specific factors in addition to technology factors, and different organisations will apply different discount rates depending on their appetite for risk. Discount rates are adjustable by the user in the ALFTA model.

This study applies discount rates for established and emerging technologies as follows:

Table 11 Discount rates

Technology type Discount rate Established 9.3%

Emerging 12.1%

Utilisation factorThe utilisation factor of a production plant is dependent on the physical limitations of the plant, available operating hours and supplies of feed and utilities. In order to provide a comparison between technologies, the utilisation factor applied in estimating the LCOF is based on the physical operating constraints of the plant rather than externally imposed market constraints.

The utilisation factor applied for each technology is presented in the discussion for each technology in section 3.

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Emissions factorAn annual estimate of the CO2 emissions for the nominated utilisation is calculated and presented for each technology.

CO2 emissions costThis study does not include a carbon price in estimating the LCOF values as presented in section 6. However, the ALFTA model allows users to input values in $/tonne CO2-e carbon price for 2013, 2020, 2025, 2030, 2040 and 2050. Where a carbon cost is included by an ALFTA model user, it is a variable operating cost that is levied based on the amount of carbon emitted. This simplifies through efficiency and emissions intensity (Department of Industry, Innovation, Climate Change, Science, Research and Tertiary Education 2013) to a carbon cost per GJ of energy content produced. Where a cost of carbon is included by a user, it is identified as a separate cost, independent of variable operations and maintenance costs. A price for emissions should not be applied to CO2 from biomass feedstocks on the basis that carbon emitted is part of a closed loop1. If a process is based on biomass feed and imports fossil-based energy, e.g., natural gas and electricity, then a price for emissions is applied on those imported feedstocks based on their CO2-e emissions factors. Emissions from production and transport of biomass and other sources are not included.

Feedstock costsRefer to section 2.3.

Variable and fixed operations and maintenance costs (VOM, FOM)Refer to section 2.3.

Capital costRefer to section 2.3.

Exclusions from LCOFThe ALFTA model does not include the following technology-specific cost parameters for calculating LCOF estimates, although these may have a significant impact on the delivered price of liquid fuels:

The effects of taxation, such as fuel excise tax and GST; Degradation effects for output from each technology; Interest rate expenses on any debt incurred in undertaking construction and operation of a

processing plant are not an identified cost component in the LCOF calculation: instead, any such costs are assumed to be captured by the discount rate;

Plant decommissioning costs; and Plant residual cost.

Uncertainty analysisA significant number of variables and assumptions are involved in estimating LCOF forecasts. Each variable has an associated uncertainty and this uncertainty increases with the span of forecast period. The ALFTA model provides a separate worksheet on ‘uncertainty’ assumptions for capital costs, fixed and variable O&M costs, and feedstock cost assumptions across technologies over the forecast period to 2050.

While the LCOF estimates are provided in ranges with identified mid-points, the range is derived from a combination of uncertainties associated with the data on capital costs (up to 50 per cent),

1 Biomass feedstocks are assumed to be renewable and therefore any carbon content used in the manufacture of the fuel has a zero rating for greenhouse emissions. Note that this is not a lifecycle greenhouse emissions estimate, that is, it only covers emissions from the production of the fuel not transport to users or end-use combustion.

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fixed and variable O&M costs (15 per cent), and feedstock costs (up to 49 per cent). LCOF ranges are provided in section 5.

Caveats on the use of LCOFA number of costs are included in the LCOF estimates. These costs comprise production costs and costs that directly relate to the production process for liquid transport fuels.

The ALFTA reports the cost of fuels over time from the present to 2050 on a consistent energy basis within the plant boundary.

However, some other costs are not part of and are not included in the ALFTA LCOF estimates.

All liquid fuel costs related to distribution, infrastructure and vehicle fleet modifications are excluded. The LCOF also excludes the effect of mandates, incentives and taxation. The ALFTA report also does not consider electricity or hydrogen fuel cells. Whilst LCOF estimates are provided taking into account the regional cost factors, individual plant level costs are not considered.

The focus of this report is on the costs associated with the studied technologies, and their specified production paths. The ALFTA cost estimates do not extend to consider the broader costs of integration into regional or national infrastructure.

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3ALFTA Technology Assessments

This section of the report details the technologies assessed. It includes a description of each technology and the process involved, and a tabulated basis of the LCOF estimate where applicable, including the quantification of feedstock, capital costs and operating costs.

For the Conventional Petroleum (Section 3.1) and Liquid Petroleum Gas (Section 3.2) technologies, even though Australia currently produces fuel via these routes, the markets are very mature, the price markers are well established, and Australia is a price taker. Therefore, the LCOF estimates are based on the market prices of these two fuels. Alcohol to Jet Fuel technology (Section 4.19) is also not tabulated as insufficient information is available to enable LCOF estimates to be made.

The information on each technology has been collected during the course of this study from information in the public domain, WorleyParsons, Evans and Peck and ACIL Allen’s internal sources as well as submissions from, and discussions with, technology stakeholders.

3.1 Conventional petroleum fuelsPetroleum refining originated in the late 1800s as simple distillation to obtain kerosene for lighting from the first petroleum wells. Kerosene from crude oil displaced whale oil for illumination.

The target market for refining shifted to transportation fuels and especially gasoline/petrol since the growth of the internal combustion engine. Refining technology took several leaps forward, including fluidised catalytic cracking (FCC) which assisted the allied war effort in World War II, catalytic reforming which assisted the significant ramp up in petrol octane levels and thus engine power and efficiency in the 1950s, environmental improvements, including removal of lead and several generations of “cleaner” fuels, and further shifts in the market to increasing importance of diesel and jet fuel and providing petrochemical feedstock. Petroleum refining is a mature industry with multiple technology providers and engineering contractors capable of competing for and building refining facilities, and multiple tiers of owner/operators competing in local, regional and global markets for refined products.

Australian contextAustralia currently has five operating refineries, although one of these refineries is planned for shutdown (BP Bulwer). The currently operating refineries have a combined nominal capacity of 32,600 ML (million litres) per annum. In the 2013-14 financial year (i.e. prior to the closure of Caltex Kurnell), Australia’s refined production was approximately 34,000 ML, around 62 per cent of Australia’s 55,000 ML of refined product consumption for the same period. Australian refiners are smaller, older, less flexible, less complex and less integrated than modern regional competitors, which are 4 to 8 times larger than the largest Australian refinery. The size and geographic dispersion of the Australian market for transport fuel means the Australian refinery operations are not able to get the same economies of scale as overseas refineries in places like Singapore.

Australian refineries use Australian and imported crude oil as feedstock. Australian crude oil production is declining and part of that production is exported anyway. Australian refineries are configured to process crude oil blends that are relatively light; major investments would be required to shift to cheaper heavy, sour blends.

The pricing of oil products in Australia is linked to ex-refinery prices in Singapore and is adjusted for shipping, storage and distribution costs.

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Barriers/OpportunitiesThere are well publicised production hazards, such as explosions and fires. There are also environmental hazards, such as leaks from wells, pipelines and ships as well as controversial frontier developments in arctic, deep water and wilderness areas.

Note that Conventional Petroleum Fuels have been analysed based on international pricing markers.

Process technologyPetroleum refineries convert crude oil feed into finished-product transport fuels. The refinery (Figure B1 in Appendix B) consists of multiple integrated process units, the selection and capacity of which are tailored to the design crude feed characteristics and the target fuel product yields.

Unit processes consist of:

Fractionation or distillation to separate oil fractions or cuts by boiling range; Conversion processes such as cracking, polymerization, reforming, and isomerization; Treating for the removal or conversion of undesirable components; and Blending of multiple finished cuts into commercially saleable products.

Scope within battery limits is covered by the refining margin and includes a process plant, supply of all utilities, all storage requirements, buildings, maintenance facilities, car parking and landscaping (Meyers 2004).

3.2 Liquid petroleum gasHistorically, LPG was not recovered separately and was utilised as refinery or gas plant fuel or butane was blended into petrol up to vapour pressure limits. Since the 1950s, capturing and upgrading “light end” (butane and lighter) components has become the norm for refining and gas processing. Various refinery conversion processes, such as polymerization and alkylation, utilise some light-end feeds to manufacture petrol, while petrochemical processes, such as steam cracking, utilise others to produce ethylene and other olefins. The recovery of the light ends for these upgrades made pools of LPG available which found wide use as bottled gas for heating and for limited application as a transport fuel. LPG recovery and treating has become a universal refining operation and is the norm for larger gas processing and LNG plants. LPG is a by-product from these industry supply chains and the production technology status of LPG is essentially the same.

Australian contextLPG is an internationally traded commodity and Australia exports from various production centres (WA, SA, VIC) and imports to various consumer markets (NSW, QLD). Australia is a net exporter of LPG; nevertheless the domestic price of LPG is still determined by international benchmarks. The appropriate price reference for LPG is the Saudi Aramco Contract Price. Announced or possible refinery closures in Australia will reduce the domestic supply of LPG. In the importing States such as NSW, the supply balance will move more towards import.

Note that LPG has also been analysed based on international pricing markers.

Barriers/OpportunitiesLPG is generally assessed as producing lower greenhouse gases (GHG) (CO2) and air pollutant emissions (CO, NOx, VOC) than petrol in-spark ignition engines. LPG production sustainability

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issues are the same as the main processes from which LPG is produced: crude oil production and refining and natural gas production.

The use of LPG in vehicles typically involves incurring a conversion cost, either through the additional cost of an Original Equipment Manufacturer’s LPG vehicle or through an after-market conversion of a non-LPG vehicle. Conversion may also involve a loss of space for carrying goods, which is effectively an additional cost of using LPG. LPG's penetration of the automotive fuel market has been low. In recent years, its market presence has been weakened by the increasing use of diesel and hybrid technology in vehicles that travel high kilometres per year, such as taxis.

Process technologyPetroleum refineries convert crude oil feed into finished-product transport fuel. LPG is a by-product (A simplified flow scheme of this process is in Figure B2 in Appendix B). In the processing of natural gas, for either pipeline gas or LNG product, LPG is often “extracted” to achieve natural gas product specifications. For pipeline gas, the heating value and dew-point specification limit the quantity of LPG and heavier fractions in the product gas.

For LNG, the liquefaction process and the LNG heating value specification require substantial LPG removal. LPG treating and distillation, to achieve relevant specifications, is part of the source gas plant process. LPG stand-alone operations consist only of terminal and distribution facilities.

3.3 Compressed natural gasNatural gas compression is an integral component in supply to high pressure pipeline gas distribution. Natural gas has become the dominant industrial and domestic fuel gas in most markets since the 1950s or before. The timing of the displacement of historical manufactured gas sources such as coke oven, producer or water gas has depended regionally on the discovery and development of indigenous gas resources or on long-distance pipelines or Liquefied Natural Gas (LNG) imports. Compressed Natural Gas (CNG) for transport filling stations utilises similar dehydration and compression technology as for gas processing but at much smaller scale. CNG for transport fuel can be installed almost anywhere on a conventional natural gas distribution network (depending on network capacity). CNG is well established globally as a transport fuel with around 15 million natural gas vehicles. In Australia, bus fleets in Brisbane and Sydney already utilise CNG in around 500 and 600 buses respectively.

The CNG analysis is based on offtake from existing gas mains and installation of packaged CNG in a metropolitan bus terminal or maintenance facility.

Vendor pricing was obtained for the packaged CNG unit for supply in Australia. Natural Gas Vehicles for America (NGVA) experience in North America was used for unit utilisation (Mika 2013).

Australian contextThe provision of CNG refuelling facilities for a metropolitan bus fleet could be a commercial proposition. The installation of refuelling facilities across the nation for cars and trucks would involve substantial investment and encounter serious commercial difficulties because of uncertainty and the interdependencies between vehicle numbers and the availability of refuelling facilities. Progress is being made in dealing with this problem in the United States, but it is a much larger and denser market than Australia. In the USA, natural gas prices are much lower, the pipeline network is larger and denser, and large subsidies are available for the replacement of heavy diesel trucks with natural gas-fuelled vehicles.

As a result of a strong demand for gas resources to underpin investments in the three LNG plants under construction in Gladstone, gas prices have risen substantially in Australia, both in absolute and relative terms in comparison to refined oil products.

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Barriers/OpportunitiesThe conventional view is that CNG is superior to LNG for vehicles travelling within compact areas such as buses, garbage trucks and metropolitan delivery trucks, but LNG is a better option for very large trucks travelling on high volume, long-haul routes. However, in the United States, this view is under challenge from a private sector consortium that is rolling out CNG stations.

CNG production sustainability issues are the same as for the main process of natural gas production from which CNG is produced.

CNG emissions from filling and engine operations are lower than conventional petroleum fuels for both GHG (CO2) and prescribed pollutants. However, lifecycle GHG emissions from unconventional gas production are contentious with a claimed range of methane emissions from well completion that may exceed conventional production.

Process technology CNG production is compression and high-pressure storage installed to take feed from existing natural gas pipelines or distribution networks. Usually only drying of the feed gas is required. CNG plant scope includes storage of CNG equivalent to five hours compression (A simplified flow scheme of the CNG process is provided in Figure B3 in Appendix B).

The selection of a bus filling station provides greater utilisation than many other applications. Utilisation of plant capacity is still low at about 16 per cent. Greater diversification of offtake, such as sharing with commercial fleet and private vehicles might improve utilisation. CNG LCOF estimation parameters are given in Table 12.

3.4 Liquefied natural gasLiquefied Natural Gas (LNG) production for transport fuel utilises a process that is conceptually similar to the large export LNG plants. However due to the smaller scale, LNG for transport fuel has more in common with the scale and technology of natural gas network peak-shaving LNG plants than the larger export plants. LNG storage for peak shaving is the oldest application of LNG technology and the first commercial LNG plant started operation in 1941 in Cleveland, Ohio. Since then, LNG has become a globally traded commodity with a total liquefaction capacity of around 300 million tonnes per year, which is forecast to approximately double by 2030. LNG is a mature industry with multiple technology providers and engineering contractors capable of competing for, and building, liquefaction export facilities, and multiple owner-operators competing in global markets. The mini-LNG / peak shaving / storage market is similarly competitive. Australia is a global leader in LNG exports.

The LNG analysis is based on offtake from existing gas mains and installation of modularised mini-LNG and storage and load-out at a greenfield filling station. It is assumed the storage is located near a major long-haul truck route. The mini-LNG plant configuration is similar to peak sharing units and the configuration from prior studies and projects has been adopted (TIAX 2012).

Table 12 CNG and LNG parameters

Compressed Natural Gas (CNG) Liquefied Natural Gas (LNG)

Annual Production Rate 3,560 tonnes/yr 200,000 tonne/yr

LHV Product 50 MJ/kg (50 GJ/t) 50 GJ/t

Product Density 0.19 kg/L 0.45 kg/L (-160°C)

Annual Energy Production (LHV)

178,000 GJ/yr 10,000,000 GJ/yr

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Compressed Natural Gas (CNG) Liquefied Natural Gas (LNG)

Nature of Feedstock Natural Gas of pipeline specification

Natural Gas of pipeline specification

Feedstock Supply 3,560 tonnes/yr 208,600 tonne/yr

LHV Feedstock 47.5 GJ/t 47.5 GJ/t

Annual Energy in Feed (LHV) 178,000 GJ/yr 10,400,000 GJ/yr

By-Product(s) None None

Australian Capital City Capital Cost Estimate

$4 million $226 million

Distributed Local Equipment / Construction Costs

30% 30%

Distributed International Equipment Costs

50% 50%

Distributed Labour Costs 20% 20%

Total of Above 100% 100%

Expenditure profile % of capital Cost

2 Years 85% Year 1 and 15% Year 2.

3 Years, 5% Year 1, 30% Year 2 and 65% Year 3

First Year of Commercial Plant Construction

2013 2013

Economic Life 30 years 30 years

Mature On-Line Operation (hours/year)

1,393 8,423

FOM ($/year) $250,000 $8 million

FOM Escalation Rate $250,000 at labour escalation rate $4 million at labour escalation rate

VOM ($/year) (+) Electric power import:700 MWh/yr

$A 1 million/year Catalysts/Chemicals/Water/Waste

(+) Electric Power import: 100 GWh/yr

VOM Escalation Rate (% of CPI) 100% 100%

O&M Improvement Rate (when not covered in FOM and VOM items)

Established technology Established technology

Emissions rate CO2 Scope 2 from Power 16,650 t/yr plus Scope 2 from Power

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)

+/- 30% +/-30%

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Compressed Natural Gas (CNG) Liquefied Natural Gas (LNG)

Capital Cost Improvement Established technology Established technologySource: WorleyParsons 2014

Australian contextProvision of LNG refuelling facilities for a metropolitan bus fleet or on a high-volume heavy truck route could be a commercial proposition. Installation of refuelling facilities across the nation for cars and trucks would involve substantial investment and encounter serious commercial difficulties. In all cases, storage and other supply costs could be expected to exceed those for CNG. This could be more serious in the case of vehicles used intermittently because when the engine is not running to maintain temperature of the LNG, the tanks automatically vent evaporating LNG.

As for CNG, some progress is being made in dealing with this problem in the United States, but as noted, it is a much larger and denser market than Australia, natural gas prices are much lower, and large subsidies are available for replacement of heavy diesel trucks with natural gas-fuelled vehicles. As also noted for CNG, Australian gas prices have risen substantially both in absolute terms and relative to refined oil products, as a result of strong demand for gas resources for export.

Barriers/OpportunitiesLNG is stored cryogenically in heavy insulated tanks on board a vehicle. This is expensive compared to diesel, petrol and CNG storage. Since the energy density of LNG is about 60 per cent that of diesel, larger fuel tanks are required for a range comparable to a diesel-fuelled vehicle, but not as large as for CNG. Since LNG is a liquid, refuelling speed is reasonably comparable to diesel and petrol.

LNG production impacts are similar to those noted for CNG. LNG emissions are similar to those for CNG but more energy input is required for the liquefaction.

LNG for road transport is usually produced in small plants located near regional transport hubs. In this way the plants required are similar to peak-shaving plants in which LNG is used as a way of storing gas for use in periods of high demand or interrupted supply, except that for transport application, the offtake demand probably will not coincide with low utilization by other users.

Process technologyA simplified flow scheme of the LNG production process is shown in Figure B4 in Appendix B. LNG production for transport fuel requires similar processing to LNG export terminals based on natural gas production, except that since the feed is at pipeline specification, many heavier hydrocarbons and impurities have already been reduced. The main processing steps are Gas Conditioning (removal of CO2, sulphur, moisture, mercury), Liquefaction, Refrigeration (to support Liquefaction), Natural Gas Liquids (NGL) Separation (Propane, Butane production if required), and LNG Storage and Loading. A skid/modularised production plant includes all process and utility units. (LNG plant scope includes storage of LNG equivalent to five days’ production). The technology parameters for estimating the LCOF of LNG were presented earlier in Table 12.

3.5 Gas to liquidsWhile there are various technology pathways that are commonly termed Gas to Liquids (GTL), Fischer-Tropsch synthesis of heavy hydrocarbons from synthesis gas is the pathway analysed in this section.

The Fischer-Tropsch (F-T) process for the synthesis of transport fuel from carbon monoxide and hydrogen was industrialised in Germany. Historically, it only found application for conversion of coal in war-time Germany or in embargoed South Africa. However with massive gas discoveries and

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sustained high oil prices, development of projects has proceeded to convert gas to premium drop-in transport fuels as an upgrade alternative to LNG. There are four operational GTL plants in the world: PetroSA MossGas in South Africa (25,000 BPSD, 1993), Shell Bintulu in Malaysia (12,000 BPSD, 1993), Sasol Oryx in Qatar (34,000 BPSD, 2008) and Shell Pearl also in Qatar (140,000 BPSD, 2012). Whilst it is an established technology, GTL is not a mature industry. There are only two commercialised technology providers, Shell and Sasol, and there is not a competitive market for the technology.

The GTL analysis is based on offtake from major gas trunklines, such as those supplying Gladstone LNG plants from inland Coal Seam Gas (CSG) fields. The plant definition assumes a greenfield site and that all required storage and loadout facilities are provided in project scope. The site is independent and generates its own power and desalinated water from excess process energy. The GTL process concept yields and costs are derived from recent and current projects and technology provider publications. The selected capacity is at the lower end of world scale, comparable to Mossgas and Oryx (Sasol 2013).

Australian contextThe existing domestic gas market is already quite tight with most proven reserves of gas (including coal seam methane) being allocated to satisfy existing domestic supply arrangements or to supply plants built (or plants under construction) to service the LNG export market.

Normally a GTL plant would be built as close as possible to the source of the gas to minimise transport and storage costs. If the source of the feedstock was CSG, then it is possible that there would be strong community opposition to such a GTL plant in many parts of Australia.

Assuming that additional gas reserves can be proven and supplied to a GTL plant, the LPG, diesel, naphtha and jet fuels produced by that plant should largely be capable of use as 'drop-in' replacement fuels. Provided the necessary fuel standards are satisfied, then storage, distribution and use of the fuels should be relatively straightforward as they could use existing infrastructure.

The natural gas feed cost is valued at LNG export netback. This is justified since LNG export is a common alternative utilisation of large reserves of natural gas that are required for GTL. In Australia, LNG is established as the predominant exploitation of natural gas.

Barriers/OpportunitiesGTL products have higher GHG well-to-wheel emissions than conventional crude oil. A carbon price would have an impact on the economics of the technology. Any requirement to utilise Carbon Capture and Sequestration (CCS) to manage emissions would add to costs and reduce energy conversion. This is due to the yield of the GTL process being only about 60 per cent of the energy of the feed natural gas stream. This is a substantially lower efficiency than for LNG, which is competing for exploitation of large gas resources. GTL products are premium quality, with zero sulphur, and reduce local emissions from engines (Larivé, 2007).

Process technologyA simplified flow scheme of this GTL process is in Figure B5 in Appendix B. The technology parameters for LCOF estimates of GTL are presented in Table 13.

Natural gas feed is partially oxidised in an Auto-Thermal Reformer reactor (ATR). The reformed gas containing CO, H2, H2O and CO2 is “shifted” to adjust the ratio of CO / H2, and the CO2 is removed by acid gas removal (alkanolamine or physical solvent). Alternatively additional hydrogen may be produced by Steam Methane Reforming (SMR) to adjust the ratio of CO / H2, and also to provide hydrogen to the subsequent product refining operations. Resulting synthesis gas is reacted over catalyst in the Fischer-Tropsch reaction to form long chain paraffins, olefins and oxygenates in the

38

range from LPG to wax. The resulting hydrocarbon fractions are hydrogenated and hydrocracked to form liquid fuel products.

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3.6 Coal to liquidsThere are several process technology pathways that are commonly termed Coal to Liquids (CTL). However, the one path selected for this study is a Fischer-Tropsch synthesis of  heavy hydrocarbons from synthesis gas as analysed in this section.

Over many years, high petroleum prices, volatility in the global market and the relatively low price and abundance of low grade coal has led to considerable interest in making synthetic petroleum from coal. However, apart from investment in early plants for strategic supply reasons, CTL has yet to fully evolve as a commercial proposition. There are only two commercial production plants currently in operation in the world, both operated by Sasol in South Africa.

A relatively recent report examined integration of a Coal to Methanol (CTM) Plant with a 15,000 BPD CTL plant (Kreutz 2008). This has been adapted for this analysis of the CTL plant. Other previously mooted projects appear to be largely “on-hold”.

Australian contextAny plant would most likely be built next to or very near an existing coal resource. This would minimise the need to build new infrastructure for transporting and storing feedstock. There is a significant feed-water requirement.

The conversion of coal to liquids has an extensive history of development and investigation in Australia, particularly in respect of the brown coal deposits in Victoria and the low-grade sub-bituminous coals of South Australia.

Currently Altona Energy is proceeding to develop in a Bankable Feasibility Study for its Arckaringa CTL project in partnership with CNOOC-NEI, a subsidiary of the China National Offshore Oil Corporation (CNOOC).

Barriers/OpportunitiesFuel products from the technology would probably be able to largely use existing infrastructure, although as demand grew it could be necessary to augment that infrastructure.

Future plant proposals would be likely to face significant regulatory and compliance requirements. The resultant environmental impact assessments, stakeholder engagement periods and the planning approval process could potentially cause significant costs and delays for CTL projects.

CTL products have significantly higher GHG well-to-wheel emissions than conventional crude oil. A carbon price would have an impact on the economics of the technology. Any requirement to utilise CCS to manage emissions would add to costs and reduce energy conversion (Larivé, 2007).

Process descriptionA simplified flow scheme of this Coal to Liquids process is in Figure B6 in Appendix B. The parameters for estimating the LCOF of CTL are provided in Table 13.

The process description provided here is based on a brown coal feed to the CTL plant, and venting of CO2. It excludes the capture and storage of CO2. Unconverted synthesis gas and purge gas from the downstream Fisher-Tropsch (F-T) refining is utilised as feed to power generation plant and the net export of electricity.

Brown coal feedstock (approximately 60 wt per cent moisture) is pre-dried to 10 wt per cent moisture content prior to entering a second stage milling and drying unit, where the coal is milled to achieve 100 per cent minus 0.2mm and dried to between 5 - 2 wt per cent suitable for the subsequent entrained-flow gasification step.

The pulverised coal, oxygen and steam are fed into the gasifier where they go through a non-catalytic partial oxidation process to produce synthesis gas. Gasification occurs at

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temperatures of 1,400-1,700°C and pressures of 35-45 bar. After quenching and water bath, the synthesis gas exits the gasifier saturated and containing only a small quantity of ash, which is removed by scrubbing. The crude synthesis gas is then sent to the water gas shift reactor.

F-T conversion takes synthesis gas (CO + H2) to produce a range of middle distillate products plus LPG and naphtha. The finished F-T products are diesel and naphtha blend stocks co-produced in a mixture of 61 per cent diesel, 39 per cent naphtha on a LHV basis.

Unconverted synthesis gas and purge gases from the F-T refining operations are used to generate export electricity. Further heat integration allows for improved overall thermal efficiencies for the plant complex.

Table 13 GTL and CTL parameters

Gas to Liquids (GTL) Diesel Coal to Liquids (CTL) Diesel

Annual Production Rate 520,000 tonne/yr Diesel

1,000,000 tonne/yr total liquid product (including Diesel)

430,000 tonne/yr Diesel

720,000 tonne/yr total liquid product (including Diesel)

720kta ~ 17kbpsd

LHV Product 34.4 MJ/L (44.1 MJ/kg) 34.4 MJ/L

Product Density 0.78 kg/L (20°C) 0.78 kg/L

Annual Energy Production (LHV)

44,100,000 GJ/yr 31,750,000 GJ/yr

Nature of Feedstock Natural Gas of Pipeline Specification

Brown Coal

Feedstock Supply 1,430,000 tonne/yr 5,353,000 tonnes/yr (@ 60% moisture)

LHV Feedstock 47.5 GJ/t 10 GJ/t

Annual Energy in Feed (LHV) 71,500,000 GJ/yr 50,850,000 GJ/yr

By-Product(s) LPG 40,000 tonne/yr

Naphtha 260,000 tonne/yr

Kero/Jet 180,000 tonne/yr

All included in total production above

Naphtha 290,000 tonne/yr

Included in total production above

Australian Capital City Capital Cost Estimate

$3,100 million $3,030 million (2013)

Distributed Local Equipment / Construction Costs

30% 65%

Distributed International Equipment Costs

40% 27%

Distributed Labour Costs 30% 8%

Total of Above 100% 100%

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Gas to Liquids (GTL) Diesel Coal to Liquids (CTL) Diesel

Expenditure profile % of capital Cost

4 Years, 5% Year 1, 15% Year 2, 30% Year 3 and 50% Year 4

4 Years, 5% in Year 1, 15% in Year 2, 30% in Year 3 and 50% in Year 4

First Year of Commercial Plant Construction

2013 2013

Economic Life 30 years 30 years

Mature On-Line Operation (hours/year)

8,423 8,000

FOM ($/year) $90 million $81.3 million

FOM Escalation Rate $61 million at labour escalation rate $15.7 million at labour escalation rate

VOM ($/year) $65 million $15.1 million Catalysts/Chemicals/Water/waste

(-) Electric Power export: 264 GWh/yr

VOM Escalation Rate (% of CPI)

100% 100%

O&M Improvement Rate (when not covered in FOM and VOM items)

Established technology Established technology

Emissions rate CO2 785,000 tonnes/yr 3.35 million tonnes/yr

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)

+/-50% +/-40%

Capital Cost Improvement Established technology Established technologySource: WorleyParsons 2014

3.7 Biomass to methanolBiomass to Methanol is one of several Biomass to Liquids pathways that enable the direct or indirect conversion of biomass into hydrocarbons, which are subsequently upgraded and refined to finished fuel products. The following content relates to the specific path selected for this technology.

The conversion of biomass to methanol via gasification of wood followed by methanol synthesis is not well developed in Australia. Consequently no stakeholder-detailed information is included in the preparation and development of the LCOF for this specific technology. There is one project currently in development for wood to methanol to gasoline. (The project is called TG Energy, and is being developed by TG Australasia). Stakeholder review comments were provided.

However, there is a significant literature discussing the technical and economic prospects of this fuels route, including conventional, commercial and advanced technologies, which are under development. Many process configurations are possible. This study has made reference to work

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undertaken by the National Renewable Energy Laboratory (NREL). Their latest study report of January 2011, “Gasoline from Wood via Integrated gasification and methanol-to-gasoline technologies”, provides a useful summary of current technology status and plant economics. The ALFTA study has adjusted the NREL capital cost estimate (for the mature nth of a kind plant) to give a cost that is more representative of the current technology.

The process configuration established by NREL assumed that 2,000 dry metric tonne/day biomass feedstock would produce 913 metric tonnes per day of methanol.

The NREL study is based upon the conversion of hybrid poplar wood chips delivered at 50 per cent moisture content. ASPEN+ process simulation modelling is undertaken of the developed process flow scheme to produce an intermediate crude methanol product of approximately 96 per cent purity.

The biomass feed is deemed as a suitable analogue to model Australian forest resources. The methanol product is considered a grade suitable for subsequent use either directly as transport fuel blend or indirectly as feedstock to a downstream MTG or DME conversion plant (technologies 16(a) and (b)) discussed below.

The gasification technology presumed for the study is based on the Battelle Columbus laboratory low pressure indirectly-heated circulating fluidised bed technology. Recent advances in gasification technology may offer improved yields and thermal efficiency over those utilised in this work, but there is an absence of qualified process data.

Australian contextPotential feedstock for this technology includes plantation-grown softwood, purpose-grown hardwood species or Municipal Solid Waste (MSW). Australia currently produces around a third of a million tonnes of 'bio-solids' - the solid waste left over after sewage treatment - per year. About 70,000 tonnes of these bio-solids (from major urban sewage works) are currently stockpiled every year. This could be a source of feedstock for this technology. This study focuses on plantation-grown softwood as a feedstock.

Barriers/OpportunitiesNew feedstock collection, distribution and storage infrastructure is likely to be required as demand grows and the throughput of plants is likely to be limited by the economic collection area of the biomass feedstock.

Methanol is already used commercially as a liquid transport fuel in China, though it is not a "drop-in replacement" for petrol. However, blended with petrol, it would be feasible to adapt flex-fuel vehicles within a range of blend rates, such as the E10 ethanol-petrol blend already in use in Australia.

Process descriptionA simplified flow scheme of biomass to methanol is presented in Figure B7 in Appendix B, and the LCOF technology parameters for biomass to methanol are in Table 14.

The following process description is précised from NREL’s study report.

Feed handling and preparation is based on truck delivery of wood chip to storage, feed preparation and drying. The wood is dried with hot flue from the char combustor as feed to the gasifier trains.

The gasification fluidization medium is steam injected at a steam-to-feed ratio of 0.4 kg steam per kg of dry biomass. The gasifier pressure is 1.6 bar. The produced synthesis gas has a H2:CO molar ratio of approximately 1:1 (dry basis).

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Gas clean-up and conditioning of the process synthesis gas incorporates reforming of the tars and hydrocarbons in the synthesis gas to produce additional CO and H2. The synthesis gas is compressed and fed to the shift reactor. The shift reactor is required to meet the desired H2:CO ratio of 2:1 for the downstream methanol synthesis.

Methanol synthesis and recovery involves conventional petrochemical technology with methanol synthesis well supported by licensor technology and catalyst vendors. The methanol stream from the let-down vessel is degassed and the product methanol cooled before being sent to storage. Recovered gases from the methanol let down are expanded though a gas turbine and returned to the degassing column to allow further methanol recovery.

Table 14 Biomass to methanol and solar dissociation parameters

Biomass Methanol (99%) Solar Dissociation Methanol (95%)

Annual Production Rate 240,000 tonnes/yr 172,916 tonnes/yr

LHV Product 19.9 MJ/kg 19.9 MJ/kg

Product Density 0.7915 kg/L (20°C) 0.7915 kg/L (20°C)

Annual Energy Production (LHV)

4,800,000 GJ/yr 3,458,320 GJ/yr

Nature of Feedstock Chipped logs (50% water) plantation-grown softwood or purpose-grown hardwood species

High purity CO2

H2O

Feedstock Supply 520,125 tonnes/yr (dry basis) 250,000 tonnes/yr CO2

272,658 tonnes/yr H2O

LHV Feedstock 15.6 GJ/t N/A

Annual Energy in Feed (LHV) 9,900,000 GJ/yr 272,658 tonnes/yr Oxygen

By-Product(s) None N/A

Australian Capital City Capital Cost Estimate

$250 million $694 million

Distributed Local Equipment / Construction Costs

65% 38%

Distributed International Equipment Costs

27% 40%

Distributed Labour Costs 8% 22%

Total of Above 100% 100%

Expenditure profile % of capital Cost

3 Years, 20% in Year 1, 40% in Year 2 and 40% in Year 3.

2 Years, 30% Year 1 and 70% Year 2

First Year of Commercial Plant Construction

2015 2020

Economic Life 30 years 30 years

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Biomass Methanol (99%) Solar Dissociation Methanol (95%)

Mature On-Line Operation (hours/year)

8,410 2,891

FOM ($/year) $16.2 million $13.9 million

FOM Escalation Rate $9.6 million at labour escalation rate

$5 million at labour escalation rate

VOM ($/year) $A 4.6 million/yr Catalysts/Chemicals/Water/Waste

(-) Electric Power export: 96 GWh/yr

(-) Oxygen sales: 10,000 tonnes/yr

VOM Escalation Rate (% of CPI) 100% 100%

O&M Improvement Rate (when not covered in FOM and VOM items)

Emerging technology Emerging technology

Emissions rate CO2 605,000 tonnes/year -250,000 tonnes/year

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)

±40% +/- 50%

Capital Cost Improvement Emerging technology Emerging technologySource: WorleyParsons 2014

3.8 Solar dissociation of CO2 and H2OThis pathway is based on technology developed by New CO2 Fuels (NCF) and involves producing fuel via a synthesis gas to methanol route from CO2 and water feed using high temperature heat from a solar collector. The synthesis gas is further processed into methanol and subsequent liquid fuel products DiMethyl Ether (DME) and Gasoline (ref technology 16(a) DME and 16(b) MTG discussed below).

Extensive stakeholder input has been received from NCF within the limits of confidentiality for their technology (New CO2 Fuels 2014a; New CO2 Fuels 2014b).

Other developing solar fuels technologies were not selected due to a lack of information and engaged stakeholders.

Australian contextNCF technology requires access to a relatively pure stream of CO2, such as from an acid gas separation system in a natural gas processing plant, ammonia synthesis process, or a coal or biomass gasification plant. Water is also required, although this is likely to be entrained in the acid gas stream in sufficient quantities not to require an additional source.

The NCF is a high temperature thermally and electrically driven dissociation reactor which converts CO2 and H2O into synthesis gas and a separate stream of oxygen. The NCF reactor can be driven from a solar thermal plant and/or excess heat from industrial processors and/or other high

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temperature heat sources. For this study, the solar thermal configuration has been assessed. Australia has some of the best solar resources in the world to locate a solar thermal plant.

The DME and MTG via methanol routes to a final fuel have been selected rather than a Fisher-Tropsch (F-T) pathway. Methanol is a transportable intermediate product that could realise economies of scale if transported to a centralised DME or MTG plant.

The location selection for a 100 per cent solar plant is constrained in the Australian context. The localised oxygen production is of the same order as the largest currently installed Air Separation plants in Australia. However, the natural gas or ammonia plants that are the assumed CO 2 suppliers are not large oxygen consumers. Australia does not currently have any significant gasification-based synthesis gas production that would supply CO2 and consume O2.

Barriers/OpportunitiesThe NCF process uses CO2 as a feedstock and could be an effective CO2 sink.

Oxygen production is normally located directly adjacent to its consumption to avoid transport costs, which, by cylinder or cryogenic truck, are very high. This limits the application and location of NCF plants. In Australia, locations of large oxygen consumers include steel smelters (Port Kembla 150,000 t/y oxygen), titanium dioxide (Kwinana 110,000 t/y) and nickel smelting (Kalgoorlie, 150,000 t/y).

The oxygen production from NCF is greater than the fuel methanol production in quantity and, potentially, value. If a market price of $250 per tonne for oxygen is applied to this “by-product”, then the LCOF of methanol is a large negative cost, due to credit from the oxygen. If the oxygen is assumed to be vented then the LCOF is a large positive cost due to the high unit capital cost for the project. This technology may be just as applicable for its oxygen output as for its synthesis gas output in certain markets.

Process technologyA simplified flow scheme of the production process of solar dissociation methanol is shown in Figure B8 in Appendix B. The technology parameters used in estimating the LCOF of solar dissociation methanol are presented in Table 14. Solar energy is collected in concentrating parabolic dishes that track the sun to maximise output. Heat from the solar energy and electricity are used to dissociate CO2 and H2O at 850°C to form a synthesis gas of CO and H2 plus a separate O2 stream. Waste heat is recovered to provide the electricity required for the reaction through a steam Rankine cycle. A methanol plant is included on site and processes the synthesis gas into methanol. Methanol is then transported to a larger scale facility where it is further processed into the transport fuel products DME or Gasoline.

This study assumes that the process takes place in a region with high solar radiation, greater than 1,800 kWh/m2/yr, with sources of high purity CO2 and water. For the purpose of this study, the most likely applications are natural gas processing facilities and ammonia plants where a stream of high purity CO2 mixed with H2O is currently vented.

Oxygen consumption is assumed as 10,000 tonnes per year valued at the market price of $250 per tonne. This assumes a 50 per cent share of one of the capital city markets, estimated at 20,000 tonnes per year of O2. Solar Fuels dissociation of CO2 is a new technology proven at the laboratory scale with a small scale prototype recently declared to have dissociated CO 2 with an external heat source.

Downstream conversion technologies for the manufacture of methanol and subsequent DME and Gasoline are well understood and technically mature.

3.9 Conventional bioethanol

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Conversion of starch-bearing grain to bioethanol using conventional bioethanol technology is commercially applied in many countries. Wheat, corn, barley, oats, sorghum and rice can all be processed into bioethanol. The technology has been extensively optimized and thus can be considered as a commercially mature technology. One such plant is in operation in Queensland, while a second in New South Wales converts waste starch to ethanol. Molasses is a by-product of the sugar industry which is also fermented to bioethanol in Australia. However, as the supply is very limited, a future source of transport fuels from molasses has not been analysed for ALFTA.

In-house WorleyParsons’ experience for this mature process has been used in preparing the following analysis. The parameters for estimating the LCOF of conventional bioethanol are presented in Table 15.

Australian contextThe feedstock options for first generation biofuels are molasses, a by-product of sugar production, or grains, such as corn, sorghum or wheat. All are available from Australian growers. Prices of all three grains have largely moved in parallel with each other. For this study red wheat, grown specifically for bioethanol manufacture, has been used as the feedstock.

Distiller's Dried Grains with Solubles (DDGS) is a co-product of dry-milled ethanol production. It is utilised as a feed ingredient and as an energy and protein supplement.

Barriers/OpportunitiesAn important consideration for the operation of conventional ethanol plants is the impact their demand for grains can have on food prices. Substantial global growth of ethanol production may have increased the prices of grain, molasses and sugar. These higher prices have flowed through to increases in food prices, including to meat prices, because of the higher cost of stock feed (O’Connell 2011).

GHG full life-cycle emissions may be better than gasoline. The estimated extent of GHG improvement varies considerably between different sources of sugars and starch, land use change, plant feed and cogeneration. Nevertheless, conventional bioethanol production does still release a significant amount of CO2 (Larivé 2007).

Process technologyA simplified flow scheme of the production process of conventional bioethanol is shown in Figure B9 in Appendix B. The technology parameters used in estimating the LCOF of conventional bioethanol are presented in Table 15.

Grain is delivered regularly to site throughout the year by truck and briefly held in storage. From there it goes through two parallel hammer mills which create access to the starch within each grain. Recycled process water, enzymes and other chemicals are blended with the meal and fed to a series of stirred liquefaction tanks in order to bring the starch into solution before the mix is delivered to the saccharification tank. Here the starch is enzymatically converted to glucose. Next the mix is delivered to large semi-batch-operated fermentation tanks and held for two and a half days. Yeast is added and as it grows it converts the glucose to bioethanol. Carbon dioxide is released as a by-product. The bioethanol vapours are then processed in the rectification column to yield an ethanol/water azeotrope of nearly 92.5 per cent ethanol, which is then passed through a molecular sieve dehydration unit to yield a >99.5 per cent bioethanol product. The Stillage Evaporation system concentrates the Thin Stillage into a syrup which is then added to the wet Distiller’s Grains before it enters the rotary drum drier. The resultant DDGS is commonly sold as an animal feedstock.

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Normally, the purified Bioethanol product (99.5 wt per cent) is not released from site without being “denatured”. It is common practice in the USA to add between 2 and 5 vol per cent of gasoline to the bioethanol before it is loaded into road or rail tankers for delivery to customers.

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3.10 Advanced lignocellulosic bioethanolThe conversion of biomass to ethanol via lignocellulosic fermentation is not well developed in Australia. Consequently there is no stakeholder available for detailed participation in the preparation and development of the LCOF for this specific technology. Nevertheless the extensive research and development in the USA has been encouraged and facilitated by the US Department of Energy, particularly by the National Renewable Energy Laboratory (NREL).

NREL has prepared several studies over the last decade assessing the conversion of biomass to ethanol. Their study report of May 2011 on Biomass to Ethanol, sets out a comprehensive process description, flow sheets and summary cost estimate for a commercial n th plant based upon lignocellulosic fermentation to ethanol. This study has been used to develop the LCOF for an Advanced Lignocellulosic Bioethanol plant for Australia (Humbird 2011).

As this technology is still being developed, NREL made several assumptions in their ASPEN process simulation modelling of the process flow scheme. WorleyParsons is not in a position to validate these assumptions so the data on LCOF parameters presented in Table 15 is based on the judgement of NREL.

Australian contextNREL’s study is based upon conversion of corn stover, the biomass left over after the corn cobs have been harvested. It is doubtful that sufficient corn stover could be found in a particular farming region of Australia, and so it will probably be necessary to process a variety of feedstocks.

Barriers/OpportunitiesA challenge of this route is the need to gather sufficient feedstock within a 100 – 150 km radius to supply a suitably-scaled process plant. For this study the feedstock used is woody biomass utilising existing harvesting and transport infrastructure.

The left over lignin from cellulosic biomass is a natural fibre that can be used as an energy-rich boiler fuel. There is potentially enough lignin in plants to provide all the energy needs of an ethanol production facility, with electricity left over for sale to the power grid.

From a GHG accounting perspective, lignocellulosic bioethanol sourced from sustainably harvested plantation forests, will produce zero emissions. Activities to produce the woody biomass, such as planting, maintenance, harvesting and transport, will add to the emissions of the feedstock. The lignocellulosic bioethanol process produces CO2 during the fermentation step.

Process descriptionA simplified flow scheme of the production process of advanced lignocellulosic bioethanol is shown in Figure B10 in Appendix B. The technology parameters used in estimating the LCOF of advanced lignocellulosic bioethanol are presented in Table 15.

The following process description is based on the NREL’s study report (2011).

The central lignocellulose bioethanol plant is serviced throughout the year by a dedicated set of feedstock providers which regularly deliver biomass by truck for 6 days of each week.

Batch hydrolysis of released sugars and their co-fermentation to ethanol is initiated in a continuous high-solids reactor after which the 20 per cent loaded slurry is batched into large stirred tanks where it is held for a further 60 hours. Carbon dioxide is released during fermentation.

The fermentation broth or “beer” is separated into water, anhydrous ethanol and combustible solids. The fully fermented slurry is stripped of its ethanol in the Beer Column and an upper level vapour side draw is fed to the Rectification Column for concentrating the

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ethanol to a level approaching its azeotrope with water at about 92.5 per cent. The overhead vapours of the Rectification Column are treated in Molecular Sieve Absorption beds which yield a finished ethanol product at 99.5 per cent. The top gases from the Beer Column are added to the vented gas from the fermentation tanks before being released to atmosphere. This is the main discharge point of carbon dioxide.

The fresh ethanol is denatured by the addition of a small amount of gasoline, with seven days’ storage provided by two tanks. Ethanol Product is loaded on a 6 day basis into road tankers.

Combustible solids and gaseous wastes from the plant in a tailor made power boiler system which generates steam at 450ºC and 60 bar are managed within the plant. By using a pass-out turbine, the steam drives a turbo-alternator for generating all the power needs of the plant and also delivering sufficient steam for all requirements.

Table 15 Conventional bioethanol, lignocellulosic bioethanol and advanced bioethanol-synthesis gas fermentation parameters

Conventional Bioethanol (99.5 %)

Advanced Lignocellulosic Bioethanol (99.5%)

Advanced Bioethanol - Synthesis Gas Fermentation

Annual Production Rate

200 ML/yr (Undenatured). Note the product is typically exported from site with the addition of 2 to 5 vol% gasoline added - i.e. "denatured"

222 ML/yr (Undenatured)

60,000 tonnes/yr (Undenatured)

LHV Product 21.1 MJ/L 21.1 MJ/L 21.1 MJ/L

Product Density 0.789 kg/L (20°C) 0.789 kg/L (20°C) 0.789 kg/L (20°C)

Annual Energy Production (LHV)

4,220,000 GJ/yr 4,684,000 GJ/yr 1,600,000 GJ/yr

Nature of Feedstock Wheat (chosen as the most common source of starch in Australia)

Solid biomass - grass/straw/forest waste

Wood biomass / municipal waste

Feedstock Supply 497,000 t/yr (10 wt% moisture) 876,000 tonnes/yr (including 20% moisture)

373,200 tpa dry basis (447ktpy @ 20% moisture)

LHV Feedstock 16 GJ/t 15.6 GJ/t 15.6 GJ/t

Annual Energy in Feed (LHV)

7,000,000 GJ/yr 12,400,000 GJ/yr 7,100,000 GJ/yr

By-Product(s) 183,000 t/yr (10 wt% moisture) DDGS

None None

Australian Capital City Capital Cost Estimate

$167 million $420 million $292 million

Distributed Local Equipment / Construction Costs

63% 63% 63%

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Conventional Bioethanol (99.5 %)

Advanced Lignocellulosic Bioethanol (99.5%)

Advanced Bioethanol - Synthesis Gas Fermentation

Distributed International Equipment Costs

15% 15% 15%

Distributed Labour Costs

22% 22% 22%

Total of Above 100% 100% 100%

Expenditure profile % of capital Cost

Two Years: 30% Year 1 and 70% Year 2

Three Years: 8% Year 1, 60% Year 2 and 32% Year 3

Three Years: 30% Year 1, 50% Year 2 and 20% Year 3

First Year of Commercial Plant Construction

2013 2018 2015

Economic Life 30 years 30 years 30 years

Mature On-Line Operation (hours/year)

8,000 8,000 8,410

FOM ($/year) $16.3 million $25.8 million $8.8 million

FOM Escalation Rate $1.7 million at labour escalation rate

$10 million at labour escalation rate

$3.7 million at labour escalation rate

VOM ($/year) $A1.6 million Catalysts/Chemicals/Water

(+) Natural Gas: 1.95 PJ/yr

(+) Electric Power import: 50 GWh/yr

(-) DDGS By-product sold

$32.2 million Chemicals/Water/Waste

(-) Electric power export: 100,000 MWh/yr

$15.3 million Chemicals/Water/Waste

VOM Escalation Rate (% of CPI)

100% 100% 100%

O&M Improvement Rate (when not covered in FOM and VOM items)

Established technology Emerging technology

Emerging technology

Emissions rate CO2 150,000 t/yr plus Natural gas and electricity use

Zero scope 1, scope 2 from electric power

Zero scope 1

Cost confidence level (based on source data accuracy to provide a % band or ranking for

+/-30% +/- 40% +/- 50%

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Conventional Bioethanol (99.5 %)

Advanced Lignocellulosic Bioethanol (99.5%)

Advanced Bioethanol - Synthesis Gas Fermentation

each technology)

Capital Cost Improvement

Established technology Emerging technology,

Emerging technology

Source: WorleyParsons 2014

3.11 Advanced bioethanol–synthesis gas fermentation

Synthesis gas fermentation is the technology process for the conversion of carbon monoxide-containing gas by microbial fermentation to produce biochemicals that are ready for upgrading to drop-in transport fuels, transport fuel additives, or upgrading to petrochemical replacements. For the purposes of this assessment it is assumed that ethanol will be the end product.

The success of this technology relies heavily on receiving consistent ‘clean’ synthesis gas, free of tar, char, ash and other components which inhibit or prevent microbe activity.

Synthesis gas fermentation offers potential advantages to traditional thermochemical conversion in that the derived biofuels include: hydrogen; ethanol; butanol; acetic acid; and butyric acid. Unlike traditional biochemical conversion, all of the biomass is utilised (i.e. including lignin). Moreover, biocatalysts have higher specificity and replenish themselves reducing or preventing the need for catalyst regeneration, there is less dependence on the H2:CO ratio of the synthesis gas, and bioreactors can be operated at ambient pressure and temperature conditions to reduce operating costs.

Commercial development of the synthesis gas fermentation process is constrained by mass transfer of the synthesis gas into the liquid media, expensive media and low product yield. Current research is directed towards improving bioreactor design to enhance mass transfer, genetic modification or isolation of new micro-organisms strains which will be compatible with less expensive media and have increased product yield.

There has been no formal stakeholder input into the basis of technology or cost model. Worldwide, there is significant research and development around synthesis gas fermentation. Currently there are five demonstration plants operating or under construction. It appears that the initial pioneering technology is sufficiently robust to allow an indication of a comparable cost if duplicated in Australia.

Operating large pilot or commercial synthesis gas fermentation plants include Indian River (INEOS) and Lighthouse in Pennsylvania (Coskata), although these may not be currently operating. Both plants are designed to ferment synthesis gas produced via gasification of biomass. The pre-commercial Freedom Pines Bio refinery (LanzaTech, formerly Range Fuels) is under construction. Bluescope Steel (LanzaTech) has a pilot waste gas fermentation plant at the Bluescope Glenbrook steel works in New Zealand, with a capacity of 45 tonnes per annum. Also, LanzaTech has operated two demonstration plants, in partnership, in China.

Published data does not give consistent agreement on the preferred biocatalyst to use or the design of the resultant fermentation reactor and the upgrading process. Further commercial-scale operation is required to optimise the technology and reduce the investment risk. Further advances in metabolic engineering and the synthetic biology of the acetogenic bacteria are also likely to improve yields. Current technology only converts a total of 29 per cent of input energy into ethanol plus surplus power - as compared to 39 per cent for the alternative route of cellulosic hydrolysis & fermentation (Kundiyana 2010).

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Australian contextSynthesis gas fermentation allows the use of non-food biomass and reduced water requirements when compared to conventional thermochemical or biochemical routes. Possible feedstock for use with this technology includes carbon monoxide-containing waste gas produced by the steel manufacturing, oil refining and chemical production industries.

This study focuses on the gasification of woody biomass to provide the synthesis gas for the fermentation process.

Barriers/OpportunitiesIf waste gas was used as the feedstock, then the conversion plant would be located near that gas source. This would require the existing facility to have enough land available to house the conversion plant. The available supply of waste gas as a feedstock is limited by the number of existing plants that generate that waste gas.

Woody biomass sourced from sustainably harvested plantation forest will produce zero GHG emissions. Activities to produce the woody biomass, such as planting, maintenance, harvesting and transport, will add to the emissions of the feedstock.

Process descriptionA simplified flow scheme of the production process of advanced bioethanol–synthesis gas fermentation is shown in Figure B11 in Appendix B, and the corresponding LCOF estimation parameters are presented in Table 15.

The synthesis gas fermentation process requires waste gas or synthesis gas as a feedstock; this necessitates that the process be positioned downstream of a thermochemical conversion facility or waste gas-producing facility.

Synthesis gas or waste gas comprising of carbon monoxide (CO), carbon dioxide (CO2) and hydrogen (H2) is continuously received. It is assumed that synthesis gas is to be cooled and cleaned of any contaminants prior to storage.

The synthesis gas is compressed above atmospheric pressure and then fed into an anaerobic trickle-bed bioreactor.

The utilisation of a packed bed enhances mass transfer between the synthesis gas and the liquid culture. Packing also removes the expense of mechanical agitation.

Raw ethanol is filtered and fed into the distillation column, with ethanol separated from by-products and liquid media. Transport fuel specification ethanol is produced.

3.12 Biodiesel by transesterificationAll natural fats and oils belong to the generic compounds called tri-glycerides, made up of three long-chain fatty acids and a glycerine molecule. The fatty acid components can differ in chain length and degree of saturation, and this variation leads to the differing properties of the oil or fat. The tri-glycerides are reacted with methanol, namely by transesterification, resulting in three separate long-chain fatty acid methyl esters and by-product glycerine. For many oils and fats, these methyl esters boil in the diesel range but the challenge is to make sure the product meets the biodiesel specification. Contaminants in the feedstock have to be removed and the product phase has to be stripped of their by-product components – e.g. water and glycerine from the biodiesel.

This technology is well known and commercially proven. WorleyParsons has adequate in-house experience with Lurgi’s proprietary process to provide all the detail required for this ALFTA study. In 2006, Lurgi built a 150,000 t/yr biodiesel plant in Darwin based on imported palm olein as the feedstock.

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Australian contextAustralia has a limited production of tallow from its abattoir industries. As tallow is commonly used for cooking in various countries, such as India, China and African countries, Australia has enjoyed a strong demand for tallow export. Used cooking oils are a very limited, labour-intensive source for biodiesel manufacture. Variable grade and contamination necessitates careful selection and pre-processing to ensure the biodiesel specification is met.

Various vegetable oil feedstocks could be made available but the growing demand for food from the growing world population will limit the availability of cheaper feedstock for biodiesel manufacture.

For this study, locally grown rapeseed oil has been used as the feedstock for production of biodiesel. Growing oil crops has land use, biodiversity and water impacts.

Barriers/OpportunitiesPalm oil, a good possible feedstock source, has not been considered as a feedstock due to the project stakeholders’ concerns around its market acceptability.

The feedstock is from a plant-based source, so from a GHG accounting perspective, biodiesel by transesterification will produce zero GHG emissions. Activities to produce the actual feedstock, such as planting, maintenance, harvesting and transport will, however, add to the emissions of the feedstock.

Process descriptionThe LCOF estimation parameters for biodiesel transesterification technology are presented in Table16, and a simplified flow scheme of the production process of this biodiesel transesterification technology is shown in Figure B12 in Appendix B.

Refined bleached deodorized rapeseed oil is mixed with an excess of methanol and liquid catalyst in the first reactor and the streams are then allowed to separate. As the reaction is only partially complete, further methanol is mixed with the upper hydrocarbon phase from the first reactor forcing the reaction towards a greater yield of methyl ester. Excess methanol is returned to the first reactor. The hydrocarbon phase is then washed with fresh water and sent to storage as finished biodiesel. The denser water phase from the first reactor along with the wash water from the product washing stage are delivered to the methanol recovery column which returns excess methanol to the front of the process.. The crude glycerine is periodically distilled into refined glycerine.

3.13 Hydrothermal upgradeHydrothermal upgrading (HTU) of biomass is specifically targeted at upgrading wet biomass into combustible liquids and gases. The hydrothermal process is flexible with respect to feedstock and has been demonstrated on a variety of feedstocks. It is assumed for this assessment that the end product of this upgrade is bio oil as feed for hydrogenation to biocrude.

Development of hydrothermal conversion of wet waste biomass streams on the pilot plant scale started in the 1980s with Shell’s HTU process. Since then further development has taken place with the CatLiq process successfully demonstrated at 100 kg/h. In Australia, Licella has a demonstration-scale facility producing bio oil ready for upgrading. NextFuels is also developing a pilot facility in Asia, based on Shell’s hydrothermal process, to convert palm waste to ‘green crude’. This facility is expected to be operational by the third quarter of 2014.

Input to this study is based on material supplied to WorleyParsons by Licella and other confidential information available to WorleyParsons. It has not been assessed for design or operability nor is WorleyParsons in a position to validate the assumptions underpinning the data presented (Licella 2013).

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There remains significant uncertainty related to bio oil quality. Hydrogenation to produce a product better suited to local refineries will add to plant costs. Bio oil from hydrothermal upgrading contains a significant amount of oxygen and is deficient in hydrogen relative to conventional petroleum feeds. The oxygen must be removed by hydrogenation and the hydrogen content increased. This technology has been assessed on the basis that any hydrogen required for this process will be provided by excess gaseous by-products and supplemented by imported natural gas. Table 16 presents the LCOF estimation parameters for hydrothermal upgrade used in this study.

Table 16 Biodiesel by transesterification and hydrothermal upgrade parameters

Biodiesel by transesterificationHydrothermal upgrade (Bio oil feed to hydrogenation)

Annual Production Rate 200,000 tonne/yr 840,000 tonnes/yr (12 plants of 70,000 t/yr each)

LHV Product 37.8 MJ/kg 34.3 GJ/tonne

Product Density 0.86 -0 .89 kg/L (20°C) 0.87 kg/L

Annual Energy Production (LHV)

7,560,000 GJ/yr 28,800,000 GJ/yr

Nature of Feedstock Refined, bleached, deodorised Rapeseed Oil

Woody biomass

Feedstock Supply 200,200 tonne/yr 2,424,000 tonnes/yr (dry basis)

Annual Energy in Feed (LHV) 7,788,000 GJ/yr 15.6 GJ/yr

LHV Feedstock 37 GJ/t 45,600,000 GJ/t

By-Product(s) 21,270 tonnes/yr Glycerin None

Australian Capital City Capital Cost Estimate

$67 million $2,400 million

Distributed Local Equipment / Construction Costs

55% 65%

Distributed International Equipment Costs

17% 27%

Distributed Labour Costs 28% 8%

Total of Above 100% 100%

Expenditure profile % of capital Cost

2 Years, 60% Year 1, 40% Year 2.

3 Years, 30% in Year 1, 50% in Year 2 and 20% in Year 3

First Year of Commercial Plant Construction

2013 2016

Economic Life 30 yrs 30 yrs

Mature On-Line Operation (hours/year)

8,424 8,000

FOM ($/year) $6.6 million $56 million

FOM Escalation Rate $5.2 million at labour escalation rate

$42 million at labour escalation rate

VOM ($/year) (+) 19,118 tonnes/yr Methanol $27.6 million Chemicals/Water/Waste

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Biodiesel by transesterificationHydrothermal upgrade (Bio oil feed to hydrogenation)

(-) 21,270 tonnes/yr Glycerin Sold

$7 million other variable costs

(+) Electrical power: 298 GWh/yr import

(+) Natural Gas: 672,000 GJ

VOM Escalation Rate (% of CPI) 100% 100%

O&M Improvement Rate (when not covered in FOM and VOM items)

Established technology Emerging technology

Emissions rate CO2 Scope 2 from electricity Electricity and gas consumption only

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)

+/-30% +/-50%

Capital Cost Improvement Established technology Emerging technology

Source: WorleyParsons 2014

Australian contextIn Australia there are no large commercial scale plants which utilise this hydrothermal technology. However for the past three years Licella has been operating a pilot plant, north of Sydney. This plant produces bio oil ready for hydrogenation and refining to transport fuels. Licella are now conducting a feasibility study with the aim of producing an investment case for the construction of a 125,000 barrel per year bio crude plant.

The hydrothermal upgrade process is suitable for the conversion of wet organic materials with moisture content in the range 70-95 per cent, which can be renewable or non-renewable. Potential types of feedstock include brown coal, bagasse, water hyacinth, algae or various waste streams.

For this study woody biomass has been selected as the most appropriate feedstock. The primary conversion of biomass will occur at a number of upstream process plants that are located close to the biomass source. The intermediate bio oil will be transported to a larger central upgrading plant that conducts the hydrogenation necessary to feed to a conventional refinery. The scale of the hydrogenation plant has been selected to match the capacity of the Hydrotreated Vegetable Oil (HVO) production, and is also within the range of conventional refining units, at the low capacity end of the range. The hydrogenation plant could be stand-alone and export its product to downstream refineries or be integrated into a new or existing refinery.

Barriers/OpportunitiesHydrothermal upgrade based on a brown coal feedstock is likely to have higher well-to-wheel GHG emissions than conventional petroleum. The use of renewable biomass sources will provide a zero impact for the feedstock from a GHG accounting perspective.

Process DescriptionA simplified flow scheme of the production process of hydrothermal upgrade technology is shown in Figure B13 in Appendix B.

Hydrothermal upgrading of biomass is a process by which primarily wet biomass is catalytically reacted with water at high temperature and pressure conditions. The process produces a bio oil,

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high calorific biogas and water soluble organics. This assessment assumes bio oil is produced for subsequent downstream processing.

Biomass is crushed, then the biomass is combined with water and catalyst to form slurry. Slurry is pressurised before passing through the main heat exchanger where it is heated to

reaction temperature. Pressurised and heated slurry is combined with recirculated slurry. This increases carbon

conversion efficiency and promotes decomposition of biomass solids. Slurry then enters the packed bed reactor where the high pressure, high temperature water

and catalyst react with the biomass. A portion of the reactor product stream is recirculated. The remaining product stream is cooled in the main heat exchanger and then enters a separator where product gas is separated and sent as fuel gas to the trim heater.

The liquid stream from the separator contains bio crude and water soluble organics.

3.14 HEFA / HVOHydroprocessed Esters and Fatty Acids (HEFA) and Hydrotreated Vegetable Oil (HVO) are adapted hydrotreating technologies. Hydrotreating, which generally involves reaction of an oil stream with hydrogen in the presence of a catalyst, is a well-established conventional refining process that has been utilised for many years to improve the quality of a variety of petroleum fractions to achieve several process objectives. These objectives include sulphur removal, improvement of combustion characteristics and yield improvement. The objectives are achieved for some streams by hydrogenation of oxygenates and by removal of resulting water and then saturating the remaining unsaturated hydrocarbons.

These reactions may also be used for conversion of vegetable oil tri-glycerides into saturated, straight-chain hydrocarbons that can be further refined to drop-in transport fuels such as diesel.

In principle, conventional hydrotreating technology can be adapted to the requirements of HEFA and HVO. Leading refining technology providers such as UOP and refinery operators such as Neste are leading the development and application of HVO. Neste, with their own NExBTL process, have started a 170,000 t/y plant at their Porvoo refinery in Finland in 2007, another 190,000 t/y plant in 2009 and two 800,000 t/y plants in Singapore in 2010 and Rotterdam in 2011.

This process is analysed based on open literature descriptions of the Neste Oil NExBTL Renewable Diesel Singapore plant (Qantas, Shell 2013).

Australian contextWhile various vegetable oil feedstocks could be used for HEFA/HVO, the growing demand for food from the growing world population will limit availability of cheaper feedstock for renewable diesel manufacture. Palm oil has not been considered due to its market acceptability, as already noted.

For this study, locally grown rapeseed oil has been selected as the feedstock. Growing oil crops have land use, biodiversity and water impacts.

Natural oil feeds from plant or animal sources are gathered and prepared for processing. The raw oil feed is bleached and pre-treated and the clarified oils are fed to a hydrogenation unit along with hydrogen, which may be made on purpose for this process, integrated within a conventional refinery hydrogen system, or purchased from a utility provider. For this study a stand-alone greenfield plant that produces its own hydrogen from natural gas feed is assumed.

Australia has a limited production of tallow from its abattoir industries and there is strong demand for tallow export. Used cooking oils are a very limited source for biodiesel manufacture.

Barriers/Opportunities

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Hydrotreating vegetable oils or animal fats to produce renewable diesel is an alternative to conventional biodiesel from transesterification. Renewable diesel does not have the various detrimental effects of ester-type biodiesel, such as increased Nitrogen Oxides (NOx) emissions, deposit formation, storage stability problems, more rapid aging of engine oil or poor cold properties. The feedstock is from a plant-based source, so from a GHG accounting perspective this study assumes that the HEFA/HVO feedstock will produce zero GHG emissions. However, the supply chain activities which actually produce the feedstock, such as planting, maintenance, harvesting and transport, will produce GHG emissions.

Process technology A simplified flow scheme of the production process of HEFA/HVO technology is shown in Figure B14 in Appendix B. Table 17 provides the LCOF estimation parameters of HEFA/HVO and algal biomass oil technologies.

The oil / hydrogen feed is reacted in a hydrotreater. The tri-glyceride ester bonds are broken liberating straight-chain hydrocarbon molecules. The oxygen atoms in the fatty acids and glycerol are converted to water, and unsaturated bonds in the fatty chains are saturated to paraffins.

Propane (from glycerol) is separated from the main hydrocarbon fraction. Propane obtained from high pressure off-gas is combined with natural gas feed to hydrogen production. Low pressure off-gas is used as fuel for the process and cold flow properties are improved. Stabilisation and fractionation in a batch distillation unit separates low pressure off-gas, naphtha and diesel products.

Table 17 HEFA/HVO and algal biomass parameters

HEFA/HVO DieselAlgal Oil (tri-glyceride)

Annual Production Rate 804,160 tonnes/yr 50,600 tonnes/yr

LHV Product 34.4 MJ/L (44.1 MJ/kg) 0.034 GJ/L

Product Density 0.78 kg/L (20°C) 0.92 kg/L (20°C)

Annual Energy Production (LHV)

35,463,000 GJ/yr 1,870,000 GJ/yr

Nature of Feedstock Vegetable oil (Rapeseed) Power station stack gas (13% CO2)

Feedstock Supply 968,000 tonnes/yr 360,000 tonnes/yr

Annual Energy in Feed (LHV)

38.91 PJ/y

Includes hydrogen production feed and fuel

N/A

LHV Feedstock 37 GJ/t N/A

By-Product(s) 4,160 tonnes/yr Naphtha

Included in HVO Diesel production rate above

43,100 tonnes/yr animal feed

Australian Capital City Capital Cost Estimate

$1,100 million $83 million

Distributed Local Equipment / Construction Costs

40% 65%

Distributed International Equipment Costs

30% 27%

Distributed Labour Costs 30% 8%

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HEFA/HVO DieselAlgal Oil (tri-glyceride)

Total of Above 100% 100%

Expenditure profile % of capital Cost

3 Years, 5% in Year 1, 30% in Year 2 and 65% in Year 3

3 Years, 30% in Year 1, 50% in Year 2 and 20% in Year 3

First Year of Commercial Plant Construction

2013 2015

Economic Life 30 years 30 years

Mature On-Line Operation (hours/year)

8,423 8,000

FOM ($/year) $54 million $9.7 million

FOM Escalation Rate $24 million at labour escalation rate $6.9 million at labour escalation rate

VOM ($/year) $5 million

(+) Electrical power import: 27.2 GWh/yr

(+) Natural gas: 3.1 PJ/yr

$5.3 million chemicals/water/waste

(+) Electrical power: 844 GWh/yr import

(+) $0.6 million heat supply

VOM Escalation Rate (% of CPI)

100% 100%

O&M Improvement Rate (when not covered in FOM and VOM items)

Established technology Emerging technology

Emissions rate CO2 40,400 tonnes/yr Scope 1. Power only for Scope 2 @ 27.2 GWh/y.

-327,200 tonnes/yr CO2

absorbed, Scope 2 from electricity

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)

+/-50% +/-50%

Capital Cost Improvement Established technology Emerging technology

Source: WorleyParsons 2014

3.15 Algal biomass converted via HEFA/HVOThere is significant literature discussing the technical and economic prospects of developing fuel using algae as a biomass source. There are thousands of different algal strains that could be used for fuel production, and many process configurations are possible.

Algae can be grown in nutrient-rich streams using open pond systems or closed-tube bioreactors or other configurations. Algal growth requires sunlight, water (saline water can be used), CO2, and growth nutrients e.g. nitrogen and phosphorous. Additional CO2 can be introduced into the system to increase the available carbon source to promote algal growth. A number of pilot and demonstration plants are in operation within Australia and around the world.

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For this study a hybrid process configuration has been established, using both solar and electrical energy to provide light for algae growth. The basis of the process is to extract algal oil that is compatible with existing natural oil processes. The algal oil product can be converted to a transport fuel via either technology 12, Transesterification or technology 14, HEFA/HVO. For determining the LCOF to finished renewable diesel fuel, technology 14, HEFA/HVO is utilised.

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Australian contextIn Australia, AlgaeTech has successfully developed its enclosed modular photo-reactor system and their press releases have mooted a 50 ML biofuel production facility at Bayswater power station in NSW. Muradel claims that a demonstration plant in Whyalla SA would be commissioned by the end of 2013 but no updates are available via the Muradel website. In New Zealand, the National Institute of Water and Air (NIWA) has successfully deployed their High Rate Algal Ponds (HRAP) technology at a number of reference sites. Downstream algae extraction remains at demonstration stage with scale up still to be fully assessed.

Barriers/OpportunitiesLand area requirements for an open pond system can be prohibitive with many hectares being required in areas with good sunshine and ideally close to a source of CO2. Enclosed hybrid systems use light-emitting diode (LED) lights powered by electricity to provide energy to the algae. This can add significantly to the operating costs and, depending on the source of electricity, reduce or even cancel out the amount of CO2 utilised by the process.

For the case examined with LED lights and solar energy inputs, the GHG emissions are net positive by 407,000 tonnes per year or 0.22 tonnes CO2-e per GJ.

Process DescriptionA simplified flow scheme of the process of algal oil production technology is shown in Figure B15 in Appendix B. Table 17 provides the LCOF estimation parameters for algal oil.

Algal oil production of 50 million litres per year is based on a proprietary system. Solar radiation is captured, filtered and routed into photobioreactors for algal production and, for this study, this has been augmented by electrical power to increase growth time.

The algae is harvested (recovered), dewatered and then subject to thermal decomposition/solvent extraction to produce an algal oil suitable for upgrading via hydrogenation to middle distillate fuels (Diesel and Naphtha). The process also produces a biomass suitable for animal feed stock or further processing into transport fuel.

WorleyParsons has been unable to validate system losses and the efficiency of photon utilisation and therefore overall energy input. Sunlight availability of 2,200 hours per year to the photo-reactor system has been assumed plus electricity for the LED lighting to the photo-reactors and onsite power demand. This report has applied a 25 per cent energy yield penalty to account for these factors. The major process steps are:

Algae production: The core photobioreactor system involves a modular container system located in an environmentally controlled warehouse with electrical lighting through high efficiency LEDs. Nutrients are formulated via the addition of industrial fertilizers with key additives.

Harvesting and separation: Photobioreactor effluent typically contains low levels of algae biomass with a large excess of water. The primary separation envisaged is via conventional settling / flotation technologies followed by thickening the algal slurry and centrifugal separation to concentrate the algae to up to 30 per cent algae content. This is a proven technology in water and wastewater treatment applications, but not at a commercial scale for algae separation.

Oil extraction: Algae biomass contains predominantly lipids (fats/oils), carbohydrates and proteins and is processed to extract these products. The configuration selected for this study involves thermal decomposition/solvent extraction to produce an algal oil suitable for upgrading via HEFA/HVO to middle distillate fuels (Diesel and Naphtha) and a biomass by-product suitable for animal feed.

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Recovery of bio oil/ product refinement: All the algal oil production systems require methods for recovery of the algal oil, water and fertiliser rich streams. This study selects the use of a centrifuge to recover the algal oil and separate the water and other solids while washing the algal oil.

Chemical treatment and refinement is required for purification of the finished algae oil product.

3.16 Methanol to DiMethyl Ether (DME)The catalytic dehydration of two molecules of methanol to form one molecule of DiMethyl Ether (DME) was first discovered in the 1920s but it only found commercial application in the 1960s when DME became widely used as an environmentally benign aerosol propellant and small 10,000 tpy plants were built in various parts of the world. CSR owned such a unit in Pyrmont, Sydney, but this unit has since been dismantled.

More recently, the fuel replacement potential of DME has become of interest. DME has similar physical properties to LPG and it has found use as a minor blend component supplementing LPG sales to domestic heating and cooking markets. Extensive vehicle testing has proven it could be used as a diesel substitute.

DME technology is offered on a mature commercial scale by several technology contractors. For input to this study an approach was made to one licensor, Lurgi GmbH in Germany. Currently, there is no Stakeholder developing a project in Australia with a view towards production of DME as a domestic transport fuel, or for export.

Australian contextThe concept has yet to manifest itself as an independent broad market distribution system which would be required along with vehicle conversion, much in the same way that LPG was brought into the Australian transport fuel market in the 1970s. It is worth noting that DME generates minimal particulate emissions because the DME molecule has no carbon–carbon bond. It therefore shows promise as a future substitute for city diesel. Trials of the fuel are underway in China, Japan and the USA.

The feedstock to the methanol to DME pathway is imported methanol. Where DME is used as the back-end process for other methanol producing technologies, the relevant cost values from the front-end process are used instead of the imported methanol price.

Barriers/OpportunitiesSimilar to LPG, DME must be stored and transported in pressurised vessels. For widespread use, distribution and vehicle infrastructure will need to be developed for DME; although like for CNG and LNG, this infrastructure could focus on concentrated users such as bus fleets and trucking routes.

Due to the high yield of the DME process, DME is likely to be a lower GHG emissions option than GTL, for example.

Process descriptionA simplified flow scheme of the process of the Methanol to DME production technology is shown in Figure B16 in Appendix B. Table 18 provides the LCOF estimation parameters of methanol to DME and methanol to gasoline production technologies.

Vaporised methanol is preheated under pressure and fed to the catalyst-filled DME reactor which dehydrates the methanol into DME and by-product water. It is necessary to firstly recover the product in the DME distillation column and then distil the excess methanol in the Methanol/Water Column. Methanol is recycled to the DME Reactor.

Rather than requiring purer and more expensive AA Grade Methanol as a feed stock it is possible to configure the DME process to accept a much cheaper crude methanol which typically contains

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around 5 per cent water. Whereas AA Grade Methanol would be fed directly to the DME reactor, a crude methanol stream would be firstly treated in the Methanol/Water column to yield a pure methanol vapour feed for the DME reactor. Such a plant could also accept off-specification AA Grade Methanol. As methanol is by far the most expensive operating cost, processing cheaper feeds will improve the economics of DME production.

Either the plant needs to be located near a suitable port which can facilitate offloading 40,000 tonne methanol tankers, or receive methanol from multiple upstream alternative fuel-processing plants by road transport. The estimate has included two suitable methanol feed tanks. One 3,000 tonne Horten Sphere has been included for product storage as well as three product shift tanks.

Table 18 Methanol to DME and methanol to gasoline parametersDiMethyl Ether (DME) Methanol to Gasoline (MTG)

Annual Production Rate 400,000 tonnes/yr 550,000 tonnes/yr Gasoline

615,000 t/yr total liquid product (including Gasoline)

LHV Product 28.9 MJ/kg 43.6 MJ/kg

Product Density 0.668 kg/L (20°C) 0.78 kg/L

Annual Energy Production (LHV)

11,560,000 GJ/yr 26,814,000 GJ/yr

Nature of Feedstock Crude methanol (5.5% water) Crude methanol (5.5% water)

Feedstock Supply 586,000 tonnes/year 1,670,000 tonnes/year

LHV Feedstock 20 GJ/t 33,600,000 GJ/t

Annual Energy in Feed (LHV) 11,180,000 GJ/yr 20 GJ/yr

By-Product(s) None 65,000 t/yr LPG Included in total production

Australian Capital City Capital Cost Estimate

$155 million $573 million

Distributed Local Equipment / Construction Costs

55% 55%

Distributed International Equipment Costs

14% 14%

Distributed Labour Costs 31% 31%

Total of Above 100% 100%

Expenditure profile % of capital Cost

2 Years, 60% in Year 1, 40% in Year 2

3 Years, 20% in Year 1, 40% in Year 2 and 40% in Year 3

First Year of Commercial Plant Construction

2013 2013

Economic Life 30 years 30 years

Mature On-Line Operation (hours/year)

8,300 8,410

FOM ($/year) $16.7 million $19.1 million

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DiMethyl Ether (DME) Methanol to Gasoline (MTG)FOM Escalation Rate $4.7 million at labour escalation

rate

$6.2 million maintenance at 4% of fixed capital

$6 million at labour escalation rate

VOM ($/year) $1.1 million chemicals/water/waste

(+) Electric power: 6.16 GWh/yr import

$10 million chemicals/water/waste

(+) Electrical power: 40 GWh/yr

VOM Escalation Rate (% of CPI) 100% 100%

O&M Improvement Rate (when not covered in FOM and VOM items)

Established technology Established technology

Emissions rate CO2 Scope 2 electricity only 200,000 tonnes/yr, scope 2 from electricity

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)

+/-30% +/-25%

Capital Cost Improvement Established technology Established technology

Source: WorleyParsons analysis

3.17 Methanol to gasolineThe conversion of methanol to gasoline (MTG) is a well-established technology presenting little technical challenge. The data presented here is based on the experienced judgement of WorleyParsons and derived from integrated facilities incorporating the front-end methanol production step.

Australian contextThe feedstock to the MTG pathway is imported methanol. Where MTG is used as the back-end process for other methanol-producing technologies, the relevant cost values from the front-end process are used instead of the imported methanol price. Apart from the Coogee Energy demonstration Methanol plant in North Laverton, Melbourne, there is no methanol production in Australia.

Barriers/OpportunitiesMTG is a high value refinery blend stock with zero sulphur, very low benzene content and a vapour pressure curve mirroring conventional gasoline. It meets all specifications.

Due to the high yield of the MTG process, MTG is also likely to be a lower GHG emissions option than, for example, a GTL route.

Process descriptionA simplified flow scheme of the process of Methanol to gasoline production technology is shown in Figure B17 in Appendix B. Table 18 provides the LCOF estimation parameters for methanol to gasoline production.

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A generic process scheme is set out below.

The MTG plant is presumed located at or near a port with facilities for offloading tanker deliveries. Methanol is delivered to the plant by pipeline.

Conversion of methanol to gasoline occurs in two stages. In the first stage the crude methanol is partly dehydrated to an equilibrium mixture of DME, methanol and water. The DME mixture is then combined with recycle gas and passed to the gasoline conversion reactors where the reactions to form gasoline take place.

A multi-stage fixed-bed adiabatic swing reactor system is presumed for this study. As the reaction is highly exothermic, recycle gas is used to limit the temperature rise across the reactors.

The reactor effluent exit stream comprises approximately 44 per cent hydrocarbons and 56 per cent water. The stream is further cooled and the gas, liquid hydrocarbon and water phases separated.

The liquid hydrocarbon product contains mainly gasoline boiling range material as well as dissolved hydrogen, carbon dioxide and light hydrocarbons. All the non-hydrocarbons and light hydrocarbons are removed by distillation and the gasoline fractioned into three streams; a heavy gasoline fraction, a light gasoline and a high vapour pressure gasoline used for vapour pressure control. The heavy gasoline fraction (containing durene) is subject to mild hydrofinishing to reduce the durene content and the three product streams are then delivered to intermediate storage for subsequent blending to a finished product. Hydrogen is separated from the product gases.

3.18 Fast pyrolysisPyrolysis of biomass, in its many forms, is centuries old and has been commercially applied in numerous industries. Fast pyrolysis, namely the extremely rapid heating of the biomass is also not new, although it has only had limited application at very large scale. Such rapid heating followed by a sudden quench of the product gases and vapours maximises the yield of liquid hydrocarbons and avoids further cracking of the liquids into more pyrolysis gases. Bio-liquids from fast pyrolysis can be upgraded to usable transport fuels.

To facilitate Stakeholder input on Fast Pyrolysis technology, discussions were held with Enecon (Mr. C. Stucley), the Australian representative of Canada’s Dynamotive Energy Systems. Dynamotive has developed fast pyrolysis technology and is in joint discussion with France’s IFP to commercially implement technology capable of upgrading raw bio oil to finished products such as gasoline and diesel. Despite Enecon’s interest in assisting, the necessary cost and technical data could not be made available within the time frame of this study. Nevertheless, information was derived through interpretation of the very informative US Department of Energy (DOE) study (Jones SB 2009) and the National Renewable Energy Laboratory report (Ringer 2006).

Australian contextThe DOE study was based on hybrid poplar as a feedstock, but the approach can be equally applied to other types of biomass. For this ALFTA study, woody biomass from plantation softwood forests was used as a feedstock.

As for other biomass processing technologies, new feedstock collection, distribution and storage infrastructure is likely to be required as demand grows and the throughput of plants is likely to be limited by the economic collection area of the biomass feedstock. As for the hydrothermal upgrade technology, this study assesses a spoke and hub model of distributed pyrolysis plants. The resulting bio oil is transported to a central hydrogenation plant that further processes the oil into a refinery compatible feedstock.

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Barriers/OpportunitiesAs for other biomass based technologies, Fast Pyrolysis is likely to have lower GHG emissions than that of conventional petroleum fuels.

Process technologyA simplified flow scheme of the process of fast pyrolysis technology is shown in Figure B18 in Appendix B. Fast pyrolysis and hydrogenation of bio-oil production technology parameters are provided in Table 19.

The concept assembled for this process configuration treats a very large quantity of biomass, which would involve significant transport costs. In consultation with Enecon, it was decided to divide the process into five “Satellite” Pyrolysis Plants, each capable of processing 800 t/day of biomass and strategically distributed near the most appropriate sources of biomass, and the crude bio oil would then be transported to a central Upgrading Plant located in a capital city, or equivalent.

The process presented in the DOE study essentially splits into three sections as follows:

Pyrolysis: Biomass is delivered throughout the year to the Plant. Typically the feed has a moisture content of about 50 wt per cent so the first step is to dry it to less than 10 per cent. The dried matter is then ground down in particle size to 2–6mm in order to facilitate the very high heat transfer rates of the downstream process. Heating the pre-dried biomass at a very rapid rate to around 520ºC in the absence of oxygen causes the cellular structure to thermally break down into a mixture of bio-liquids, combustible gases, charcoal and water. The char is firstly removed by cyclone and fed directly to a combustion system which provides heat for the pyrolyser as well as hot combustion gases for the biomass dryer. Next, the bio oil is quenched and condensed by contacting it with cooled recycle bio oil. The residual non-condensables are partly recycled back to fluidise the pyrolyser while the remainder is sent to the combustor for process heating. The product “bio oil” is a stable emulsion of hydrocarbon and 15–30 per cent water.

Upgrading to Remove Oxygen: Crude bio oil contains a significant amount of oxygen(35 – 40 wt per cent) which must be removed by hydrogenation. The hydrogen is sourced from a Steam Reformer which is fed with natural gas as well as the by-product gases from the hydrotreating process. The proposed use of by-product gases reduces the requirement for natural gas during the hydrogenation process but is likely to add to the complexity of the overall process due to increased process integration. The bio oil is firstly pumped to a high pressure, preheated and then catalytically treated with hydrogen to yield a mixture of stabilised hydrocarbons containing less than 2 wt per cent oxygen. Excess hydrogen is recycled via a Pressure Swing Absorption (PSA) plant to the hydrotreaters. By-product water from the crude bio oil is treated and discharged off-site.

Distillation and Hydrocracking: The hydrocarbon liquids are fractionated to yield streams of gasoline, diesel, lighter gases and a heavy stable oil. The heavy oil is converted in a Hydrocracker to more gasoline and diesel plus an off-gas. Collectively the gases are delivered to the steam reformer. Finished gasoline and diesel are stored ready for delivery.

Table 19 Fast pyrolysis and hydrogenation of bio oil parametersFast Pyrolysis Gasoline and Diesel

Hydrogenation of Bio Oil to Syncrude

Annual Production Rate 132 ML/yr Gasoline

163 ML/yr Diesel

800,000 tonnes/yr compatible with refinery feed

LHV Product Gasoline: 44.4 MJ/kg

Diesel: 43.4 MJ/kg

42.5 MJ/kg

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Fast Pyrolysis Gasoline and Diesel

Hydrogenation of Bio Oil to Syncrude

Product Density Gasoline: 0.784 kg/L (20°C)

Diesel: 0.85 kg/L (20°C)

0.87 kg/L

Annual Energy Production (LHV)

10,600,000 GJ/yr 34,000,000 GJ/yr

Nature of Feedstock Solid biomass - grass/straw/forest waste/silviculture

Bio crude, spec:

Oxygen 10-14%

Carbon 79-82%

Hydrogen 6-8%

Sulphur 0.01%

Nitrogen 0.1-0.2%

Feedstock Supply Total 1,330,000 t/yr (including 50% Moisture), processed by 5 separate Pyrolysis Plants each at 266,000 t/yr

857,000 tonnes/yr

LHV Feedstock 15.6 GJ/t 34-36 GJ/t

Annual Energy in Feed (LHV) 15,200,000 GJ/yr (note, energy of hydrogen via SMR included in this quantity)

42,000,000 GJ/yr (including Natural Gas)

By-Product(s) None None

Australian Capital City Capital Cost Estimate

$495 million $732 million

Distributed Local Equipment / Construction Costs

61% 40%

Distributed International Equipment Costs

15% 30%

Distributed Labour Costs 24% 30%

Total of Above 100% 100%

Expenditure profile % of capital Cost

3 Years, 6.5% Year 1, 46.5% Year 2 and 47% Year 3

3 Years, 5% in Year 1, 30% in Year 2 and 65% in Year 3

First Year of Commercial Plant Construction

2018 2013

Economic Life 30 years 30 years

Mature On-Line Operation (hours/year)

8,000 8,000

FOM ($/year) $36 million $39 million

FOM Escalation Rate $24 million at labour escalation rate

$15 million at CPI

$24 million at labour escalation rate

VOM ($/year) $11.5 million chemicals/water/waste

$2.5 million chemicals/water/waste

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Fast Pyrolysis Gasoline and Diesel

Hydrogenation of Bio Oil to Syncrude

(+) Electrical power: 195 GWh/yr import

(+) Natural Gas: 4.2 PJ/yr import

(+) Electrical power: 27 GWh/yr import

(+) Natural Gas: 7 PJ/yr import

VOM Escalation Rate (% of CPI) 100% 100%

O&M Improvement Rate (when not covered in FOM and VOM items)

Emerging technology Established technology, 0.2% annual improvement rate for O&M,

Emissions rate CO2 Natural gas and electricity scope 2 only

674,000 tonnes/yr (includes CO2

from Natural Gas). Power import Scope 2 emissions.

Cost confidence level (based on source data accuracy to provide a % band or ranking for each technology)

+/-50% +/-50%

Capital Cost Improvement Emerging technology Established technology

Source: WorleyParsons analysis

3.19 Alcohol to jet fuelThere is a strong incentive, particularly in the USA, to identify and develop technologies which can produce jet fuel from biomass sources. The US Department of Defence is financially encouraging industry and research organisations to study the various options available.

Two options which have received particular attention involve the conversion of Alcohol to Jet fuel (ATJ):

Ethanol to Jet Fuel, and Isobutanol to Jet Fuel.

However, the first step would be to source the feedstock and, as reviewed elsewhere in this study, two potential routes are available:

Firstly, the production of ethanol from various sources of starch is commercially proven throughout the world. Conversion of lignocellulose, on the other hand, is still proving difficult to yield sufficient ethanol at commercially competitive prices.

Waste gas fermentation of a gas stream rich in carbon monoxide can produce a spectrum of organic chemicals, with ethanol and isobutanol receiving closer attention where the end product is jet fuel. But, as discussed with respect to Technology 12, waste gas fermentation is at the early stages of development. Furthermore, there are no adequate sources of carbon monoxide-rich waste gas available in Australia which would suit this route. A more than adequate supply could be sourced from the gasification of biomass to a synthesis gas rich in hydrogen and carbon monoxide. However strong competition would come from other, more mature, liquid fuel processes such as synthesis of Fischer-Tropsch liquids, methanol, MTG and DME – options which are discussed elsewhere in this report. On the other hand, selective use of the carbon monoxide would leave a hydrogen-rich stream which could find use in the hydrogenation of vegetable oils.

The potential for the supply of ethanol and/or isobutanol for large scale conversion to transport fuels is rather limited in Australia (Qantas & Shell 2013; Lane 2012).

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Stakeholder inputDiscussions were held with one potential stakeholder who is currently in the process of developing a microbiological system that can convert waste gas, namely carbon monoxide, to a variety of organic chemicals including ethanol and higher alcohols. The next step involves dehydrating the alcohols and then polymerisation to longer chain molecules which boil in the jet fuel distillation range.

The proponent has built a 3.8 million litre / year waste gas to ethanol plant in China. Although the company was very positive and keen to contribute to the study, they stated that they had not developed sufficient relevant technical and commercial information which could be used as input for developing LCOF values. Subsequently, they withdrew their interest in participating in this study.

The alternative American technology developer expressed no interest in assisting with the study, possibly because they are not as far advanced in their development program.

Process descriptionEthanol to jet fuelA simplified flow scheme of the process of alcohol to jet fuel technology is shown in Figure B19 in Appendix B.

The process concept here is straightforward. Remove a water molecule from the ethanol molecule to produce ethylene and then polymerise the ethylene to gasoline, jet fuel and diesel fractions. These technologies are commercially well developed. However, there are concerns with regard to the commercial viability of this approach:

Ethanol has gained a strong foothold as a 10 per cent blend (E10) supplement to the gasoline market in Australia and elsewhere in the world. The demand for ethanol may climb further should E85 find widespread use. Ethanol is an attractive gasoline blend component because of its good octane properties and, being an oxygenate, it improves exhaust pipe emissions. ATJ would have to compete with this well-developed end use for ethanol.

It takes about two litres of ethanol to make one litre of jet fuel. Hence, before accounting for capital or operating costs of the conversion, the product jet fuel will already cost twice that of the ethanol. Furthermore, at this ratio, about one quarter of the energy value of the ethanol will be lost during the course of the conversion process.

Perhaps the most significant impediment to converting alcohol to jet fuel is, the “Natural Law of Alternative Commodity Markets” (NLACM) which states “the value of any intermediate products produced in any process must be significantly exceeded by the value of the end product, or the end product will not be produced”. Such is the case with ethanol commanding a better value than jet fuel, but the effect becomes more significant once the ethanol has been converted to ethylene, which returns an even greater value.

Isobutanol to jet fuelThis route is subject to the same market pressures faced by ethanol. Dehydration of isobutanol, followed by oligomerisation of the olefin to diesel and jet fuel, is also at a commercial level of development. However, competition for the isobutanol may come strongly from the gasoline market, as isobutanol might be considered a better blend component in gasoline than ethanol. It has a higher energy density, excellent octane values and has less of an impact on the “front end” vapour pressure of the gasoline blend. At this point in time, however, isobutanol has not penetrated the gasoline market, nor has it achieved an adequate approval standing for such blending. The lag has been brought about by the lack of commercial development in the bio-fermentation of isobutanol. Once this hurdle has been overcome commercially, then the demand by the gasoline and aviation fuel market will grow significantly, although isobutanol to Jet Fuel will also face the aforementioned NLACM hurdle due to the value of isobutene as a petrochemical.

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ConclusionsThe technology for converting Alcohol to Jet Fuel is insufficiently developed to establish the design basis for a commercial plant operation and hence a valid cost of production. Competing market demand for intermediate products may prevent the final stage of producing a Jet Fuel from alcohol sources from ever becoming a commercial reality.

3.20 Hydrogenation of bio oilThe bio crude oil produced by technology 13 Hydrothermal Upgrade is not suitable for use as a blend stock in a conventional petroleum refinery. High oxygen and low hydrogen content requires further processing in a hydrogenation plant.

Australian contextFor this ALFTA study, a plant capacity of 800,000 tonnes per year has been selected as a reasonable scale. This volume is comparable to the HVO technology evaluated for technology 14 and is at the lower end of distillate hydrotreater capacities in Australian refineries (typically1,000,000 – 2,000,000 tpy). The unit cost of the bio crude hydrogenation unit will be greater than a refinery unit due to the greater hydrogenation duty but it will be less than the HVO unit because an intermediate bio crude is the product rather than a refined end-product transport fuel.

To achieve the scale required to match the throughput of the hydrogenation plant, a network of 12 individual Hydrothermal Upgrade plants will be required, each producing 70,000 tonnes per year of bio oil.

Barriers/OpportunitiesThe hydrotreatment process consumes natural gas and therefore contributes to the GHG emissions of the final product fuels.

Process descriptionA simplified flow scheme of the process of Hydrogenation of bio-oil technology is shown in Figure B20 in Appendix B. Hydrogenation of bio oil production technology parameters are provided in Table 19.

Bio oil contains a significant amount of oxygen (10 – 14 wt per cent) which must be removed by hydrogenation. It is also deficient in hydrogen relative to crude oil distillates, bio crude being6–8 wt per cent compared to typical distillates 12 – 14 wt per cent. If the bio crude is fed to a typical catalytic cracker, which is the usual destination for gas oils in Australian refinery configurations, the oxygen will tend to cause increased oxygenation and CO/CO2 in reactor products and the low hydrogen content will result in a greater catalyst coking rate. These effects could constrain throughput of the catalytic cracker or lead to other operability issues and therefore the bio oil needs to be upgraded into a bio crude of comparable properties to normal catalytic cracker feed. Hydrogenation is required to effectively eliminate oxygen and to raise hydrogen into the gas oil typical range. This will require on-purpose hydrogenation, since no Australian refinery hydrogenates catalytic cracker feed, and the hydrogenation conditions will differ significantly from typical distillate hydrotreating such that existing reactors are unsuitable, and there is minimal spare hydrogenation and hydrogen capacity in existing refineries.

The hydrogen is sourced from a Steam Methane Reformer (SMR) which is fed with natural gas and fuelled by natural gas as well as the SMR tail gas and by-product gases from the hydrotreating process. The bio oil is firstly desalted for removal of ash and char that may be entrained in the oil, and then vacuum distilled to partially dewater and remove any residues. The oil feed is pumped to a high pressure, preheated and then catalytically treated with hydrogen in two or more stages to yield stabilised hydrocarbons containing negligible oxygen. The hydrocarbon product is stripped of

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volatile gases and stored or sent directly to subsequent refining. Excess hydrogen is recycled to the hydrotreater reactors. By-product water from the crude bio oil is stripped then treated and discharged offsite.

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4Feedstock and Co-product Cost Estimates

ACIL Allen has provided the feedstock and co-product price forecasts used to calculate the LCOF estimates for the studied technologies.

Table 20 Feedstock and co-product cost projections by region (Reference Case: Real 2012-2013 A$/GJ)

Feedstock (A$/GJ) 2013 2020 2025 2030 2040 2050Cost of Natural Gas

East coast Metropolitan 5.32 7.52 9.04 10.44 10.96 11.45East coast Regional 4.82 7.02 8.54 9.94 10.46 10.95Rest of Australia - Metropolitan 7.32 10.22 11.04 12.44 12.96 13.45Rest of Australia - Regional 6.82 9.72 10.54 11.94 12.46 12.95

Cost of Brown CoalEast coast Metropolitan n/a n/a n/a n/a n/a n/aEast coast Regional 0.81 0.84 0.80 0.84 0.86 0.87Rest of Australia - Metropolitan n/a n/a n/a n/a n/a n/aRest of Australia - Regional n/a n/a n/a n/a n/a n/a

Cost of Fossil Fuel-Based MethanolEast coast Metropolitan 24.44 27.88 27.17 26.99 26.91 26.99East coast Regional 24.99 28.43 27.72 27.54 27.46 27.54Rest of Australia - Metropolitan 24.44 27.88 27.17 26.99 26.91 26.99Rest of Australia - Regional 25.54 28.98 28.27 28.09 28.01 28.09

Cost of Canola (Rapeseed) OilEast coast Metropolitan 34.27 42.73 42.88 43.94 46.19 48.08East coast Regional 34.00 42.46 42.61 43.67 45.92 47.81Rest of Australia - Metropolitan 34.54 43.00 43.15 44.21 46.46 48.35Rest of Australia - Regional 34.00 42.46 42.61 43.67 45.92 47.81

Cost of Woody BiomassEast coast Metropolitan 3.69 3.69 3.69 3.69 3.69 3.69East coast Regional 3.04 3.04 3.04 3.04 3.04 3.04Rest of Australia - Metropolitan 4.33 4.33 4.33 4.33 4.33 4.33Rest of Australia - Regional 3.04 3.04 3.04 3.04 3.04 3.04

Cost of WheatEast coast Metropolitan 19.14 21.92 21.40 21.31 21.33 21.46East coast Regional 18.52 21.29 20.78 20.68 20.70 20.83Rest of Australia - Metropolitan 19.14 21.92 21.40 21.31 21.33 21.46Rest of Australia - Regional 17.89 20.67 20.15 20.06 20.08 20.21

Source: ACIL Allen analysis

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Table 21 Co-produced fuel cost projections by region (Reference Case: Real 2012-2013 A$/GJ)

Co-produced fuels 2013 2020 2025 2030 2040 2050Cost of Crude Oil (Tapis)

East coast Metropolitan 22.42 27.48 28.17 28.86 30.98 32.83East coast Regional 22.42 27.48 28.17 28.86 30.98 32.83Rest of Australia - Metropolitan 22.42 27.48 28.17 28.86 30.98 32.83Rest of Australia - Regional 22.42 27.48 28.17 28.86 30.98 32.83

Cost of LPGEast coast Metropolitan 24.40 31.08 31.04 31.51 32.55 33.45East coast Regional 24.63 31.31 31.27 31.75 32.79 33.69Rest of Australia - Metropolitan 24.40 31.08 31.04 31.51 32.55 33.45Rest of Australia - Regional 24.87 31.55 31.51 31.99 33.03 33.93

Cost of Jet FuelEast coast Metropolitan 56.08 58.62 59.83 61.04 61.94 62.68East coast Regional 56.08 58.62 59.83 61.04 61.94 62.68Rest of Australia - Metropolitan 56.08 58.62 59.83 61.04 61.94 62.68Rest of Australia - Regional 56.08 58.62 59.83 61.04 61.94 62.68

Source: ACIL Allen analysis

Table 22 Other co-produced feedstock cost projections by region (Reference Case: Real 2012-2013 A$/GJ)

Other co-produced feedstocks 2013 2020 2025 2030 2040 2050Cost of Methanol produced from Biomass

East coast Metropolitan n/a 16.90 16.35 15.91 15.48 15.08East coast Regional n/a 15.90 15.32 14.86 14.39 13.96Rest of Australia - Metropolitan n/a 18.54 17.96 17.50 17.02 16.59Rest of Australia - Regional n/a 16.90 16.24 15.70 15.11 14.56

Cost of Methanol produced from SolarEast coast Metropolitan n/a 80.50 74.53 69.00 62.22 55.57East coast Regional n/a 84.03 77.77 71.94 64.77 57.72Rest of Australia - Metropolitan n/a 84.03 77.77 71.94 64.77 57.72Rest of Australia - Regional n/a 94.63 87.48 80.76 72.41 64.18

Source: ACIL Allen analysis

Table 23 Other feedstock cost projections by region (Reference Case: Real 2012-2013)

Other feedstocks 2013 2020 2025 2030 2040 2050Cost of Electricity

Cost of Feed Electricity (generation, transmission, distribution) (A$/GJ) 31.30 31.60 33.60 35.60 41.60 41.70Cost of Feed Electricity (generation, transmission, distribution) (A$/MWh) 112.36 113.29 120.48 127.67 149.43 149.73Wholesale Cost of Exported Electricity (A$/MWh) 69.33 70.26 74.30 84.63 106.40 106.70

Source: ACIL Allen analysis

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5LCOF ComparisonsThis section provides the ALFTA modelling results of LCOF estimates of 18 liquid fuel technologies in Australia for the outlook period to 2050. This section also compares the LCOF estimates across technologies, and provides the relative rankings of the technologies over the outlook period to 2050.

The ALFTA model is obtainable from BREE which also provides some additional information including the breakdown of the LCOF estimate by capital, O&M and feedstock costs. The additional detail available in the model includes the following:

LCOF input parameters and the ability to incorporate user input values; LCOF graphs for the period out to 2050; Breakdown of LCOF across major cost categories; Capital unit cost comparison; Cost uncertainty definition; and Full feedstock, by-product and energy cost tables.

Key points

The LCOF estimates for 9 technologies are provided for the year 2013, while the LCOF estimates for all 18 technologies are provided for the years 2020, 2025, 2030, 2040, and 2050;

The LCOF estimates vary substantially across the technologies from $14/GJ (for LNG) to $52/GJ in 2013 (for HEFA/HVO), $15/GJ (again for LNG) to $103/GJ (for solar fuel to MTG) in 2020, and $15/GJ (for CTL) to $73/GJ (for solar fuel to MTG) in 2050;

By 2050 coal to liquid fuel technology is expected to have the lowest LCOF of all the evaluated technologies;

LNG production technology in 2013 appears to provide the most cost competitive forms of liquid fuel followed by Coal to Liquids (CTL) technology in Australia. CTL technology is projected to remain cost competitive out to 2050;

Estimated costs of solar fuel to methanol to DME and MTG technologies appear to have wider ranges throughout the outlook period mainly due to the uncertainties around capital costs. Where oxygen is a by-product of solar fuel to methanol technology, the demand for oxygen is usually met by localised production;

The LCOF estimates suggest that the costs of producing biomass to methanol to DME and MTG, solar fuel to methanol to DME and MTG, bioethanol, and synthesis gas fermentation, are all expected to decline over the outlook period to 2050;

The LCOF is projected to increase over time for the CNG, LNG, GTL, Biodiesel, HEFA/HVO, and Algal Biomass technologies. Increasing feedstock prices is one of the reasons for the future increase of the LCOF for these technologies; and

Cost ranges are provided for each technology that accounts for several reasons including differences in feedstock prices and capital costs.

5.1 Technology tablesThis study considers that the conventional petroleum fuels and LPG markets are mature and internationally competitive, and that prices of these products are well understood. As such, the conventional petroleum fuels and LPG have not been modelled in this study in the context of Australian plants. The LCOF data for the other 18 liquid fuel technologies are extracted from the ALFTA model output.

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Cost of conventional petroleum fuels and liquid petroleum gasThe projected costs of conventional petroleum fuels and LPG are presented in Table 24 and Table 25 respectively. The weighted average cost of conventional petroleum fuel is calculated on the basis of the types petroleum fuel use in Australia (i.e. unleaded petrol 39.3 per cent, diesel 45 per cent, jet fuel 15.5 per cent and aviation gasoline 0.2 per cent).

Table 24 Cost of petroleum fuels (base case) in East Coast Region (Real 2012-2013 A$/GJ) Units 2012-13 2019-20 2024-25 2029-30 2039-40 2049-50

USD/AUD exchange rate Nominal 0.90 0.75 0.75 0.75 0.75 0.75

Australian Liquid Fuels

Wholesale TGP ULP (exc GST)

A$/GJ 30 36 37 38 40 43

Wholesale TGP Diesel (exc GST)

A$/GJ 26 30 31 31 33 35

Jet fuel (Jet A-1) A$/GJ 56 61 61 61 62 63

Aviation Gasoline (AvGas)

A$/GJ 62 66 65 65 65 65

Conventional Petroleum (Weighted)

$A/GJ 32 38 38 39 41 42

Source: ACIL Allen analysis

Table 25 Cost of LPG (base case) in East Coast Region (Real 2012-2013 A$/GJ)

Units 2012-13 2019-20 2024-25 2029-30 2039-40 2049-50

USD/AUD exchange rate Nominal 0.90 0.75 0.75 0.75 0.75 0.75

Australian LPG wholesale MDP (excl GST) A$/GJ 25 31 31 32 33 34

Source: ACIL Allen analysis

LCOF results of the ALFTA model technologiesTables and charts are provided in this section to summarise the LCOF results of 18 technologies out to 2050 as modelled in this study. The LCOF reported in the tables is the overall cost from raw feed to finished product. The results include the costs of all the processing steps involved for all technologies.

The LCOF estimates for all 18 technologies under this study for four regions (East Coast Metropolitan, East Coast Regional, West Coast Metropolitan, and West Coast Regional) are available in the ALFTA model. However, the LCOF estimates for the East Coast Metropolitan area have been presented below for the outlook period out to 2050.

Table 26 Compressed natural gas plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050

East Coast Metropolitan 34 35 36 36 38 40

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Figure 1 Compressed natural gas plant, LCOF, East Coast Metropolitan

Table 27 Liquefied natural gas plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan 14 15 16 16 18 19

Figure 2 Liquefied natural gas plant, LCOF, East Coast Metropolitan

Table 28 Gas to liquids plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan 26 28 29 30 31 33

Figure 3 Gas to liquids plant, LCOF, East Coast Metropolitan

Table 29 Coal to liquids plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Regional 16 16 15 15 15 15

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Figure 4 Coal to liquids plant, LCOF, East Coast Regional2

Table 30 Biomass to methanol to DME plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 20 20 19 19 19

Figure 5 Biomass to Methanol to DME plant, LCOF, East Coast Metropolitan

Table 31 Biomass to methanol to MTG plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 24 24 24 23 23

Figure 6 Biomass to Methanol to MTG plant, LCOF, East Coast Metropolitan

Table 32 Solar dissociation to methanol to DME plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 83 78 72 66 59

2 The LCOF for coal to liquids has not been estimated for the east coast metropolitan region. East coast regional estimates have been presented instead.

79

Figure 7 Solar Dissociation to Methanol to DME plant, LCOF, East Coast Metropolitan

Table 33 Solar dissociation to methanol to MTG plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 103 97 90 82 73

Figure 8 Solar dissociation to methanol to MTG plant, LCOF, East Coast Metropolitan

Table 34 Conventional bioethanol plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan 36 36 35 35 35 34

Figure 9 Conventional bioethanol plant, LCOF, East Coast Metropolitan

Table 35 Advanced lignocellulosic bioethanol plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 32 31 30 30 30

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Figure 10 Advanced lignocellulosic bioethanol plant, LCOF, East Coast Metropolitan

Table 36 Synthesis gas fermentation plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 53 51 50 49 48

Figure 11 Synthesis gas fermentation plant, LCOF, East Coast Metropolitan

Table 37 Biodiesel by transesterification plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan 49 52 53 54 57 58

Figure 12 Biodiesel by transesterification plant, LCOF, East Coast Metropolitan

Table 38 Hydrothermal upgrade to bio-oil to refinery products plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 31 30 30 29 29

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Figure 13 Hydrothermal upgrade to bio-oil to refinery products plant, LCOF, East Coast Metropolitan

Table 39 HEFA/HVO plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan 52 55 56 57 58 59

Figure 14 HEFA/HVO plant, LCOF, East Coast Metropolitan

Table 40 Algal biomass via HEFA/HVO, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 61 61 63 67 71

Figure 15 Algal biomass via HEFA/HVO plant, LCOF, East Coast Metropolitan

Table 41 Methanol to DME plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan 30 31 30 30 31 31

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Figure 16 Methanol to DME plant, LCOF, East Coast Metropolitan

Table 42 Methanol to MTG plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan 38 38 37 37 38 38

Figure 17 Methanol to MTG plant, LCOF, East Coast Metropolitan

Table 43 Fast pyrolysis to bio oil to refinery products plant, LCOF (Real 2012-13 A$/GJ)Year 2013 2020 2025 2030 2040 2050East Coast Metropolitan n/a 20 20 20 20 20

Figure 18 Fast pyrolysis to bio oil to refinery products plant, LCOF, East Coast Metropolitan

5.2 Relative ranking of the ALFTA technologiesInter-technology LCOF comparisons as provided in Figure 19 to 24 show a relative ranking of the analysed technology’s LCOF estimates in 2013, 2020, 2025, 2030, 2040 and 2050 for Australia. The figures illustrate how the LCOF of various technologies change over time.

Differences are explained by several factors including technical developments, learning rates or cost reductions, region-based variations and feedstock prices.

83

Figure 19 LCOF for technologies, 2013 (Real 2012-13 A$/GJ)

Figure 20 LCOF for technologies, 2020

(Real 2012-13 A$/GJ)

Figure 21 LCOF for technologies, 202584

(Real 2012-13 A$/GJ)

Figure 22 LCOF for technologies, 2030

(Real 2012-13 A$/GJ)

Figure 23 LCOF for technologies, 2040

(Real 2012-13 A$/GJ)

Figure 24 LCOF for technologies, 2050

85

(Real 2012-13 A$/GJ)

86

6ConclusionsThe Australian Liquid Fuels Technology Assessment (ALFTA) 2014 provides the most up-to-date estimates of current and possible future costs of a wide range of both established and emerging liquid fuel production technologies under Australian conditions, to be used in the transport sector. BREE engaged the engineering consultant WorleyParsons to develop cost estimates for 18 liquid fuel production technologies for this study. Knowledge of the cost of emerging liquid fuel production technologies is likely to play an important role in determining the mix of primary energy supply for meeting the growing fuel oil demand in the future. Understanding technology costs also helps to determine how new technologies would compete against the existing fuel production technologies. The Levelised Cost of Fuel (LCOF) estimates are used. The LCOF is the cost of fuel production in real dollar terms incorporating all costs, amortised over the economic life of the plant. The relevant unit for the LCOF is $ per Gigajoule (GJ) of fuel produced.

The key findings of the ALFTA include:

By 2020, several emerging technologies are expected to be available at lower LCOF than currently available petroleum fuels. None of these low LCOF alternatives fuel technologies have been implemented yet in Australia with the exception of LPG and CNG.

Some renewable technologies such as sugar/starch or natural oil-derived fuels or solar conversion fuels, are expected to have LCOF values that are marginally competitive with petroleum fuels by 2050.

Natural gas and coal-derived fuels technologies offer the lowest LCOF over most of the projection period and they remain cost competitive with the lower cost renewable technologies out to 2050, if carbon pricing or cost of carbon capture is not included in the LCOF estimates.

The ALFTA study provides the basis for considering Australia’s liquid fuel mix into the future.

87

ReferencesARENA (Australian Renewable Energy Agency) 2013, Technology and commercial readiness tools. Retrieved October 2013, from Australian Renewable Energy Agency: http://arena.gov.au/resources/readiness-tools/

Atlas Copco 2014, CNG Enquiry, 31 January

Bao, B., El-Halwagi, M. M., & Elbashir, N. O. 2010, Simulation, integration, and economic analysis of gas-to-liquid processes, Fuel Processing Technology. Fuel Processing Technology

Department of Industry, Innovation, Climate Change, Science, Research and Tertiary Education 2013, Australian National Greenhouse Accounts Factors - July 2013. Australian Government, Retrieved from Climatechange.gov.au: http://www.climatechange.gov.au/sites/climatechange/files/documents/07_2013/national-greenhouse-accounts-factors-july-2013.pdf

Duncan J. 2003, Costs of Biodiesel Production. Study prepared for the Energy Efficiency and Conservation Authority, New Zealand

Gardener Denver Industrial Products Group Asia Pacific 2014, CNG Enquiry, January

Gary, J., Handwerk, G., & Kaiser, M. 2007, Petroleum Refining Technology and Economics (Fifth Edition ed.). CRC Press

Hammerschmidt A, B. N. 2011, Catalytic conversion of waste biomass by hydrothermal treatment. Fuel 90, 555-562

Humbird, D., Davis, R., Tao, L., Kinchin, C., Hsu, D., Aden, A. et al. 2011, Process Design and Economics for Biochemical Conversion of Lignocellulosic Biomass to Ethanol. National Renewable Energy Laboratory

Johnson, C. 2010, Business Case for Compressed Natural Gas in Municipal Fleets. Technical Report NREL/TP-7A2-47919. NREL

Jones SB, C. V. 2009, Production of Gasoline and Diesel from Biomass via Fast Pyrolysis, Hydrotreating and Hydrocracking: A Design Case. Pacific Northwest National Laboratory

Jones, D., & Pujado, P. 2006, Handbook of Petroleum Processing. Springer

Kim, Y. H., Jun, K. W., Joo, H., Han, C., & Song, I. K. 2009, A simulation study on gas-to-liquid (natural gas to Fischer–Tropsch synthetic fuel) process optimization. Chemical Engineering Journal

Koskinen, M., Sourander, M., & Nurminen, M. 2006, Apply a comprehensive approach to biofuels. Hydrocarbon Processing. February

Kreutz, T. G., Larson, E. D., Liu, G., & Williams, R. H. 2008, Fischer-Tropsch Fuels from Coal and Biomass. 25th Annual International Pittsburgh Coal Conference. Pittsburgh, Pennsylvania

Kundiyana, D. K., Huhnke, R. L., & Wilkins, M. R. 2010, Syngas fermentation in a 100-L pilot scale fermentor: Design and process considerations. Bioscience and Bioengineering, 492-498

Lane, J. 2012, The Solyndra Effect, or why alcohol-to-jet fuel is a tough sell. Biofuels Digest. November 16

Larivé, J.-F. 2007, Life cycle (“Well-to-Wheels”) assessment of alternative fuels and powertrains in the European context. 5th JCAP. Tokyo

Licella 2013, Techno-economic Model Summary

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Mahammadi, M., Najafpour, G. D., Younesi, H., Lahijani, P., Uzir, M. H., & Mohamed, A. R. 2011, Bioconversion of synthesis gas to second generation biofuels: A review. Reviewable and Sustainable Energy Reviews, 4255-4273

Meyers, R. A. 2004, Handbook of Petroleum Refining Processes (Third Edition ed.). McGraw-Hill

Mika, S. 2013, Exploring the Total Cost of CNG. March. Retrieved from Government Fleet: http://www.government-fleet.com/channel/green-fleet/article/story/2013/04/exploring-the-total-cost-of-cng/page/3.aspx

Mikkonen, S. 2007, Presentation NExBTL - Premium Quality 2nd Generation Hydrogenated Renewable Diesel Fuel. JSAE/SAE International Fuels and Lubricants Meeting. Kyoto

Munasinghe, P. C., & Khanal, S. K. 2010, Biomass-derived syngas fermentation into biofuels: Opportunities and challenges. Bioresource Technology, 5013-5022

Neste Oil 2013, NExBTL Review Diesel Singapore Plant, Tallow Pathway Description

New CO2 Fuels 2014a, Market Analysis and Applications

New CO2 Fuels 2014b, Product Financial Analysis

NREL, 2011 “Process Design and Economics for Biochemical Conversion of Lignocellulosic Biomass to Ethanol” – “Dilute-Acid Pretreatment and Enzymatic Hydrolysis of Corn Stover”, NREL Technical Report NREL/TP-5100-47764

Paulson, N.D. and Ginder, R.G. 2007, The Growth and Direction of the Biodiesel Industry in the United States. Center for Agricultural and Rural Development Iowa State University. Working Paper 07-WP 448

Qantas & Shell 2013, Australian feedstock and production capacity to produce sustainable aviation fuel - public report. ARENA

Rawlinsons 2013, Rawlinsons Australian Construction Handbook 2013. Rawlinsons Publishing

Ringer, M., Putsche, V., & Scahill, J. 2006, Large-Scale Pyrolysis Oil Production: A Technology Assessment and Economic Analysis. National Renewable Energy Laboratory

Rismiller, C.W., and Tyner, W.E 2009, Cellulosic Biofuels Analysis: Economic Analysis of Alternative Technologies. Department of Agricultural Economics, Purdue University. Working Paper #09-06

Sasol Limited 2013, Sasol Senior Group Executive Provides Testimony to the U.S. House of Representatives. 20 June. Retrieved from Sasol.com: http://www.sasol.com/media-centre/media-releases/sasol-senior-group-executive-provides-testimony-us-house-representatives

TIAX 2012, U.S. and Canadian Natural Gas Vehicle Market Analysis: Liquified Natural Gas Infrastructure Final Report. America's Natural Gas Alliance

89

AppendicesAppendix A: Discount Rates and Correlations for EscalatorsA1. Discount ratesThe discount rate used in the ALFTA report and modelling is a modified weighted average cost of capital (WACC), which is pre-tax (whereas the usual WACC is post tax). In general, companies are financed through debt and equity. The WACC is the weighted mean cost of the returns on debt and equity. A weighted mean allows a clear understanding of the returns the company has to pay for its sources of finance (debt and equity). The WACC is the return required of the company in its entirety and is often used as a hurdle rate in order to ascertain which opportunities are worth pursuing.

The usual formula for calculation of the (post-tax) WACC is as follows:

WACC=W eRe+W d Rd (1−t )

where:

W e=¿ The weight of equity in the firm’s balance sheet (equity divided by the sum of equity and debt).

Re=¿ The required rate of return on equity. This reflects the riskiness of the firm and its covariance with market returns.

W d=¿ The weight of debt in the firm’s balance sheet (debt divided by the sum of equity and debt).

Rd=¿ The return payable on debt. This reflects the riskiness of the firm.

t=¿ The corporate tax rate (30 per cent in Australia).

Setting the corporate tax to zero yields the pre-tax WACC, which will be the used for the ALFTA study. The reasoning behind this is that the ALFTA study aims to calculate the Levelised Cost of Fuel (LCOF) and as such is focussed exclusively on costs, and not on taxes, excises or revenues. Accordingly, the correct discount rate to use should be a pre-tax WACC. In this case, the modified WACC formula simplifies to:

WACC=W eRe+W d Rd

The technologies have been divided into established and emerging technologies. The established technologies carry lower risks than the emerging technologies. In consequence, the discount rate to be applied to the established technologies needs to be lower than that applied to the emerging technologies. This is due to the maturity of the technologies themselves, as well as the risk profiles of the project proponents (the firms).

ACIL Allen conducted a review of WACC’s in use for projects that are similar to the technologies in the ALFTA study. Typical discount rates applied to projects involved in the production of liquid fuels

90

vary from 10 to 20 per cent (nominal $).3 ACIL Allen’s industry knowledge supports the use of discount rates within this range. Two WACC’s are used in the ALFTA study:

Established technologies are discounted using a WACC of 9.3 per cent for real $, or 12 per cent for nominal $.

Emerging technologies are discounted using a WACC of 12.1 per cent for real $, or 15 per cent for nominal $.

The conversion from nominal to real assumes a 2.5 per cent projected inflation rate, as follows:

The real discount rate equivalent to a 12 per cent nominal discount rate is 9.3 per cent, calculated as (1.12/1.025)-1=0.093 (9.3 per cent).

The real discount rate equivalent to a 15 per cent nominal discount rate is 12.1 per cent, calculated as (1.15/1.025)-1=0.121 (12.1 per cent).

A2. Analysis of correlations for escalation and projectionsIn building projections for costs, the ALFTA study uses proprietary escalators to generate future costs. When generating projections, it is important to make them internally consistent. For example, a high oil price will usually be a consequence of strong economic activity, which will in turn result in high prices for capital equipment and high labour costs. Thus, the prices that drive the LCOF tend to be correlated. To be internally consistent, the escalators need to capture the correlation between costs and fuel prices (for both feedstocks and output).

Likewise, the Australian dollar foreign exchange rate tends to be correlated with commodity prices, and this correlation has been incorporated into the low-mid-high scenarios for the feedstock and co-product projections.

The correlations present in the data have been incorporated into the ALFTA model as well as in the feedstock and co-product projections. In particular, capital costs are closely correlated with oil price, with a correlation coefficient of 0.94 over the 2000-2012 periods.

Regression analysis was conducted as follows. The natural logarithm of the IHS-CERA upstream capital cost index was regressed against a time trend and the natural logarithm of Brent oil price, using a time series approach with Ordinary Least Squares (OLS) regression.

The resulting regression is given by:

ln (UpstreamCapitalCost Indext )=−673.4+0.29 ln (BrentOil Price t )+89.06 ln (T ime )

The above regression has an adjusted coefficient of determination (R2) of 0.91, which means that 91 per cent of the variation in the data is explained by the above specification. Furthermore, all of the coefficients are statistically significantly different from zero with a probability higher than 0.9.

Overall, this implies that the above specification is robust. On this basis, the capital cost escalation uses oil price as a driver, along with a constant escalation growth rate related to the time trend and a sensitivity for carbon pricing, if the latter has been enabled in the LCOF model.

3 See, for example:

Paulson and Ginder (2007). The Growth and Direction of the Biodiesel Industry in the United States. Center for Agricultural and Rural Development Iowa State University. Working Paper 07-WP 448.

Duncan (2003). Costs of Biodiesel Production. Study prepared for the Energy Efficiency and Conservation Authority, New Zealand.

Rismiller and Tyner (2009). Cellulosic Biofuels Analysis: Economic Analysis of Alternative Technologies. Department of Agricultural Economics, Purdue University. Working Paper #09-06.

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Appendix B: Production process diagram of liquid fuel technologies

Figure B1 Conventional petroleum refinery

Figure B2 LPG from LNG process

LP C3

Reflux Separator

HP C3 MP C3

Scrub Column

LP C3

Surge Tank

Depropaniser Debutaniser

De-ethaniser

LP C3 LP C3 MP C3

Ethane Storage Propane Storage Butane Storage

Blending

Treated Gas

Gas to Liquefaction

Condensate

LPG

92

Figure B3 Compressed natural gas (CNG)

Figure B4 Liquefied natural gas (LNG)

Figure B5 Gas to liquids (GTL)

SMR

Air Separation

Unit

H2 PSA

F-T Synthesis

Product Upgrade

Power Island

Air

Recycle Compressor

Syngas

HC

Recovery

Unconverted syngas+ C, -C4 FT gases Purge Gas

Flue Gas

LPG, Diesel &Naptha

Syncruderaw FTproduct

Natural Gas

Oxygen

Steam

ATR

HPS

Natural Gas

93

Figure B6 Coal to liquids (CTL)

raw FT product

RefrigerationPlant

Lignite pre-drying

Coal drying &mill ing

Gasification & Quench

Syngas Scrubber

Water Gas Shift

Air Separation

Unit

Acid Gas Removal

Refinery H2

F-T Synthesis

F-T Refining

Power Island

Lignite

Air

MP Steam

Slag

Gas Cooling Expander

Oxygen Steam

Recycle Compressor

Flash

Flash

Regenerator

Methanol

H2S + CO2To Claus/SCOT

CO2

CO2

Syngas

HC

Recovery

Unconverted syngas+ C, -C4 FT gases Purge Gas

Flue Gas

Net exportelectricity

Finished gasoline & diesel

blendstocks

Syncrude

ATR

raw FTproduct

After Kreutz, Larson et al, 2008

Figure B7 Biomass to methanol

Gas Combustion &

Catalyst Regeneration

Feed Preparation Dryer Gasification

& CyclonesFluidized Bed Tar Reformer

Quench Scrubber

Syngas Compression

Water-Gas Shift

CO2/H2S RemovalDegassing Syngas/Methanol

SeparationMethanol SynthesisStorage

CharCombustion

and Cyclones

Biomass

Ash

Flue

Gas

Flue

Gas

Hot

San

d

Cha

r&

San

d

Raw Syngas

Div

erte

d S

ynga

s

Dry SyngasWet "Tar Free"

Syngas

Sol

id

Sul

fur

Car

bon

Dio

xide

Clean Syngas

Unreacted/Recycled Syngas

Methanol, Unreacted

Syngas

Methanol

Steam Cycle

Electricity

Use

d C

atal

yst

Reg

ener

ated

Cat

alys

t

Figure B8 Solar dissociation of CO2 and H2O

Electricity Gas flowT~900C

From Solar EnergyGas flow T≥1000°C

Syngas to Methanol

production

Electricity production for

process

NCFReactor

Gas flowT~100C

Syngas

High Temp Heat Source Methanol

CO2

H2OO2

94

Figure B9 Conventional bioethanol

Water

Evaporation

Drying Dehydration

Milling Hydrolysis Saccharification

Centrifuge Distillation Fermentation

Grain (Starch)

Water

EthanolSy rup DDG CO2

Figure B10 Advanced lignocellulosic bioethanol

Water

Steam/P ower

Biogas

Waste Water Treatmant

CFB Boiler Dehydration

Feed P reparation P retreatment Conditioning

Centrifuge Distillation Saccharification & Fermentation

Biomass

Water

EthanolAsh CO2

Acid

Figure B11 Advanced bioethanol - synthesis gas fermentation

Co-products

Catalysts

Industrial Waste Gases

Biomass

Biogas

Solid Waste

Fermentation Recovery

Digestion

Gasification

CompressionCO, CO/H2, CO2/H2 Ethanol

Biomass

Acetic acid 2, 3 Butanol

FeedHopper

Feed Preparation and

Dry ing

95

Figure B12 Biodiesel by transesterification

WashColumn

Glycerin Water

Evaporation

Reactor 1 Reactor 2

Methanol Recovery

Oil

Crude Glycerin

Biodiesel

Methanol

Catalyst

Figure B13 Hydrothermal upgrade

WaterCatalyst

Crush Slurry

Thermal Heater

Reactor

P rocessSeparator

Biomass

Bio Oil to Hydrogeneration

Waste Water & Treatment

NCG to Flare

Figure B14 Hydro-processed esters and fatty acids (HEFA) and Hydro-treated vegetable oil (HVO)

Shift & PSAReforming(SMR)

Synthesis GasNatural Gas

Fats/Oils Naphtha

Diesel

Pretreatment, Hy drotreating Hy dro Isomerisation

Hy drogen

Water

Distillation

LPG

LPG

96

Figure B15 Algal biomass converted via HEFA/HVO

Algal biomassBiophotoReactor

Separate/Extract

Nutrient Recovery

Sunlight/Electric Light

Algal Protein (stock feed)

Triglyceride Oil to HEFA/HVO

Nutrients

CO2

Water

Waste Water

Figure B16 Methanol to dimethyl ether (DME)

DME Reactor

MeOH Column

MeOH Recycle

DME Column

Methanol Feedstock

Off Gas

Eff luent

Fuel Dimethyl Ether

Figure B17 Methanol to gasoline

Methanol

C2-

LPG

Water

Gasoline

LPG

Treated GasolineHeavy Gasoline

Stabilised Gasoline

Light GasolineBlending

DeEthanizer Stabilizer

Splitter HGT Reactor Stabilizer

MTG Reactor (multiple)

97

Figure B18 Fast pyrolysis

Figure B19 Alcohol to jet fuel

Oligomerization Hydrogenation

ChemicalSynthesis

Water

DehydrationEthanol

Gasoline

Jet Fuel

Diesel

Figure B20 Hydrogenation of bio-oil

H2

Vapor H2Off-Gas

Clarified Bio OilOil Feed

P ressurization

To WastewaterTo Wastewater Residue Treatment

Treatment (If any)

P reheater Hydrotreater(2 stages)

PSA SteamReforming

StrippingDesalter Vacuum

DistillationBio Oil from Hydrothermal Unit Stable Syncrude

Natural Gas

98

Figure B21 Bio-oil upgrade

H2

Vapor H2Off-Gas

Oil

P ressurization

To Wastewater Heavy StableTreatment Oil to

Hydrocracker

P SA SteamReforming

P reheater Hydrotreater(2 stages) Distillation

Bio Oil from Pyrolysis Unit Light Stable Oil

Natural Gas

Figure B22 Processing of bio-crude to refined products

H2

Off-Gas Off-Gas

HeavyStable Oil

LightStable Oil

Distillation

Hydrocracker

SteamReforming

DistillationUpgraded Stable Oil

Off-Gas from Hydrotreaters

Gasoline

Diesel

Natural Gas

To Hydrotreaters

99