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COOPERATIVE RESEARCH CENTRE FOR COAL IN SUSTAINABLE DEVELOPMENT Established and supported under the Australian Government’s Cooperative Research Centres Program

SYSTEMS ASSESSMENT OF FUTURE ELECTRICITY GENERATION

OPTIONS FOR AUSTRALIA

TECHNOLOGY ASSESSMENT REPORT 32

Authors:

A. Cottrell J. Nunn

D. Palfreyman A. Urfer P. Scaife

L. Wibberley

BHP Billiton

November 2003 QCAT Technology Transfer Centre, Technology Court

Pullenvale Qld 4069 AUSTRALIA Telephone (07) 3871 4400 Facsimile (07) 3871 4444

Email: [email protected]

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DISTRIBUTION LIST CCSD Chairman; Chief Executive Officer; Research Manager, Manager Technology; Files Industry Participants Australian Coal Research Limited ............................................................. Mr Ross McKinnon BHP Billiton Minerals - Coal .................................................................... Mr Ross Willims CNA Resources.......................................................................................... Mr Rod Hall CS Energy .................................................................................................. Dr Chris Spero Delta Electricity ......................................................................................... Mr Steve Saladine Queensland Natural Resources and Mines ................................................ Ms Mary Worthy Rio Tinto (TRPL)....................................................................................... Mr David Cain .................................................................................................................... Dr Jon Davis Tarong Energy ........................................................................................... Mr Burt Beasley The Griffin Coal Mining Co Pty Ltd ......................................................... Mr Jim Coleman Wesfarmers Premier Coal Ltd ................................................................... Mr Peter Ashton Western Power ........................................................................................... Mr Keith Kirby Xstrata Coal Australia Pty Ltd................................................................... Mr Barry Isherwood Research Participants CSIRO ……............................................................................................... Dr Adrian Williams Curtin University of Technology ............................................................... Dr Barney Glover Macquarie University ................................................................................ Prof Jim Piper The University of Newcastle ..................................................................... Prof Adrian Page The University of New South Wales ......................................................... Prof David Young The University of Queensland ................................................................... Prof Don McKee Black Coal CRC Participants ARCO Resources Ltd ................................................................................ Mr William Ash BHP Coal Pty Ltd ...................................................................................... Mr Alan Davies Pacific Power ............................................................................................. Dr Allen Lowe Rio Tinto Pacific Coal ............................................................................... Mr Duncan Waters Stanwell Power .......................................................................................... Mr Wayne Collins

Cooperative Research Centre for Coal in Sustainable Development

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Fax: (07) 3871 4444

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Disclaimer Use of the information contained in this report is at the user’s risk. While every effort has been made to ensure the accuracy of that information, neither Australian Black Coal Utilisation Research Limited (ABCUR) nor the participants in the CRC for Coal in Sustainable Development make any warranty, express or implied, regarding it. Neither ABCUR nor the participants are liable for any direct or indirect damages, losses, costs or expenses resulting from any use or misuse of that information. Copyright © Australian Black Coal Utilisation Research Limited 2003 All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, whether electronic, mechanical, photocopying, recording or otherwise, without the prior written permission of Australian Black Coal Utilisation Research Limited.

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PREFACE

As the work for Program 1 of the CCSD has progressed, it has become increasingly apparent that systems assessment approaches are required to support both the CCSD, as well as COAL21. Over the past 12-18 months, a number of research based activities have been undertaken related to tools for the assessment of energy systems: externalities (complements the long standing work on life cycle analysis), experience or learning curves (to estimate changes to capital costs for the various technologies into the future), and technology modelling, in addition to LCA (which has been further refined).

This study was carried out to assess future energy options (focus on electricity generation) in an Australian context, with the premise that step reductions in greenhouse gas emissions could and should occur.

It integrates the above tools for the assessment of a number of technologies for coal based power generation, both now and into the future (to 2030), focussing on the unique Australian context. Emerging technologies, as well as the most economic non- hydro renewable technology, wind, are included. It includes a range of technical, economic and environmental issues and solutions, as currently understood. The goal has been to give a clear concept of the principles used in our approach to systems assessment.

Streamlined models have been used to assess the complex systems involved, as it is not possible to present all possible options and the associated ramifications. The results should therefore be regarded as useful first estimates, rather than as firm values – this is work in progress. In addition the issue of risk is not included.

The study has involved many assumptions and estimates. The authors have attempted to use representative values that have a comparative basis, and to indicate the basis for these assumptions, estimates and relationships. Based on the reviewer’s comments, it is proposed that supplementary reports should be produced that provide a more detailed analysis of specific technology combinations of interest. It is recommended that more highly detailed assessments be on a project, rather than generic basis, and with key input from technology providers.

The authors would like to thank the many individuals from other companies and organizations who have supplied information, comments and guidance in preparation of both this report and a number of preceding studies.

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TABLE OF CONTENTS

PEER Reviewers comments .....................................................................................12 EXECUTIVE SUMMARY...........................................................................................15

Key findings ...........................................................................................................16 Economics of CO2 abatement ............................................................................19 Future grid scenarios .........................................................................................21

Conclusions ...........................................................................................................23 Recommendations.................................................................................................24

1 Introduction.............................................................................................................27 2 Background – TRENDS IN ELECTRICITY GENERATION ....................................29 3 Technology Descriptions ........................................................................................37

3.1 Supercritical and Ultra-supercritical pf fired boilers ..........................................39 3.2 Oxygen USC with CO2 capture and compression............................................43 3.3 Natural gas combined cycle.............................................................................45 3.4 Integrated gasification combined cycle ............................................................47 3.5 IGCC with CO2 capture and compression........................................................49 3.6 Underground coal gasification and combined cycle gas turbine ......................53 3.7 Direct fired coal combined cycle gas turbine....................................................56 3.8 Acid gas removal processes ............................................................................58

3.8.1 Solvent based capture...............................................................................58 3.8.2 Solid absorbents .......................................................................................62 3.8.3 Membranes ...............................................................................................62 3.8.4 Flue gas recycle with liquefaction..............................................................63

3.9 Other considerations........................................................................................64 3.9.1 The sulfur issue.........................................................................................64 3.9.2 Hot flue gas cleanup..................................................................................65

3.10 CO2 storage options.......................................................................................65 3.10.1 Ocean sequestration and storage ...........................................................66 3.10.2 Geological storage ..................................................................................67

4 Systems Assessment Methodology........................................................................69 4.1 Technology modelling ......................................................................................70 4.2 Projecting installation costs..............................................................................75 4.3 Life cycle analysis ............................................................................................81 4.4 Economics .......................................................................................................82 4.5 Electricity scenarios to 2030 ............................................................................85

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5 Results and Discussion ..........................................................................................87 5.1 Technology comparison...................................................................................87

5.1.1 Technology modelling ...............................................................................87 5.2 Economic analysis of technologies ..................................................................92

5.2.1 Installation cost .........................................................................................93 5.2.2 Generation cost.........................................................................................93 5.2.3 Economics of CO2 abatement ...................................................................99

5.3 Life cycle greenhouse gas emissions ............................................................101 5.4 Future grid projections ...................................................................................103

5.4.1 Effect on overall grid emissions...............................................................110 5.4.2 Effect on required rate of investment in new/replacement capacity ........111

6 Conclusions..........................................................................................................112 7 Recommendations ...............................................................................................113 8 Glossary – power generation context ...................................................................115 9 References ...........................................................................................................130

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LIST OF FIGURES

Figure 2.1 Historical and future world energy mix. .............................................................29

Figure 2.2 Share of fuel sources to generate electricity in 2000 and 2030...........................30

Figure 2.3 CO2 emissions by fuel source to generate electricity in 2000 and 2030. ............31

Figure 2.4 Electricity generation (grid only) by fuel type in 2000/01 (ESAA)....................32

Figure 2.5 Projected Australian power supply and demand. ................................................34

Figure 2.6 Greenhouse gas intensity of coal-fired power generation since 1890.................35

Figure 3.1 Changes in efficiency of pf plants since 1952, normalised to Australian conditions (from European data and projections). ..............................................41

Figure 3.2 Simplified process flow diagram for supercritical/ultrasupercritical pf generation. ...........................................................................................................42

Figure 3.3 Simplified process flow for ultra-supercritical power generation with CO2 capture/compression. ...................................................................................44

Figure 3.4 Simplified process flow for natural gas combined cycle plant with single-shaft turbine set. .......................................................................................46

Figure 3.5 Existing and planned IGCC plants and sizes (MW). ..........................................47

Figure 3.6 Simplified process flow for an IGCC plant with single-shaft turbine set (coupled gas and steam turbines). .......................................................................51

Figure 3.7 Simplified process flow for IGCC power generation with CO2 capture and compression. .................................................................................................52

Figure 3.8 Simplified process flow for underground coal gasification combined cycle plant with single-shaft turbine set. .............................................................55

Figure 3.9 Generic process for a direct fired coal combined cycle plant with single-shaft turbine set. ..................................................................................................57

Figure 3.10 Generic amine absorption of CO2 from flue gases..............................................59

Figure 3.11 Options for acid gas removal from synthesis gas................................................61

Figure 3.12 CO2 liquefaction by multistage compression and cooling. ................................63

Figure 3.13 CO2 liquefaction by multistage compression and refrigeration, incorporating gas industry standard methanol polishing reflux condenser.............................................................................................................64

Figure 3.14 Potential capacity for sequestration/storage of carbon........................................66

Figure 4.1 Systems assessment approach. ............................................................................69

Figure 4.2 Approach to projecting future installation costs from overseas data to account for both currency and location factors. ..................................................75

Figure 4.3 Relationship between E, PR and LR. .................................................................77

Figure 4.4 Relationship between E, PR and LR using double-logarithmic representation. .....................................................................................................77

Figure 4.5 Experience curves for power generation technologies up to 2030......................79

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Figure 4.6 Replotting estimates in Figure 4.4 based on projected increases in capacity................................................................................................................80

Figure 5.1 Calculated parasitic load for CO2 compression/pumping for various Schedule 100 mild steel pipe sizes for a 500 MW power station (125 kg CO2/s). .................................................................................................................92

Figure 5.2 Cost comparison of power generation technologies. Error bar show sensitivity to a variation in capital cost of ±20%. ...............................................94

Figure 5.3 Effect of fuel price 2002......................................................................................95

Figure 5.4 Effect of fuel price in 2030. ................................................................................96

Figure 5.5 Current and projected costs for power generation technologies to 2030. Note, NGCC points lie directly under those for DFC. ........................................97

Figure 5.6 Current and projected costs for power generation technologies in 2002, 2010, 2030. ..........................................................................................................98

Figure 5.7 Effect of value of carbon, 2002. ........................................................................100

Figure 5.8 Effect of value of carbon, 2030. ........................................................................101

Figure 5.9 Life cycle greenhouse gas emissions (kg/MWh). .............................................102

Figure 5.10 Greenhouse intensity of the grid scenarios (kg/MWh). ....................................109

Figure 5.11 Projected total annual greenhouse gas emissions (Mtpa)..................................109

Figure 5.12 Cumulative projected capital costs for the hypothetical grid scenarios. ...........111

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LIST OF TABLES

Table 2.1 World electricity generation (TWh). ....................................................................30

Table 2.2 World CO2 emissions from power generation......................................................31

Table 2.3 Electricity generation capacity of Australian States (ESAA, June 2002). ...........32

Table 2.4 Electricity generation projections by fuel type.....................................................33

Table 3.1 Advanced PF Power Plants in Construction or Projects in Europe and Japan....................................................................................................................40

Table 3.2 Existing and planned IGCC plant details (Korens et al). .....................................48

Table 3.3 Typical CO2 compositions of flue and synthesis gases ........................................58

Table 3.4 Comparison of acid gas removal technologies. ....................................................62

Table 4.1 Basis for power generation technologies..............................................................71

Table 4.2 Input properties for power generation technologies modelling............................72

Table 4.3 Weighted average composition of coals in process modelling (as received basis). ....................................................................................................74

Table 4.4 Average composition of Australian pipeline natural gas[]....................................75

Table 4.5 Estimated energy-related learning rates. ..............................................................78

Table 4.6 Assumptions for various energy technologies for 2010 and 2030. ......................81

Table 4.7 Parameters for economic analysis. .......................................................................84

Table 5.1 Summary of process modelling results for technology combinations..................89

Table 5.2 Comparison of IGCC modelling results with other studies..................................90

Table 5.3 Current and projected capital cost and sent-out efficiency for the generation technologies.......................................................................................93

Table 5.4 Effective cost of CO2 abatement relative to supercritical pf. ...............................99

Table 5.5 Life cycle greenhouse gas emissions for the generation technologies modelled, (CCSD LCA values, except for UCC production14) ........................102

Table 5.6 Scenario A - replacing future power demand with high efficiency coal fired power stations. ..........................................................................................104

Table 5.7 Scenario B - replacing demand with wind (5,000 MW by 2010 then 12% of generation 2020-2030) and cleaner coal technologies..................................105

Table 5.8 Scenario C - replacing demand with wind (5,000 MW by 2010 then 12% of generation 2020-2030) and CCNG technology. ...........................................106

Table 5.9 Scenario D - replacing demand with renewable technologies............................107

Table 5.10 Scenario E - replacing demand with 100% coal based CO2 capture and storage technologies. .........................................................................................108

Table 5.11 ABARE power generation projections by fuel type..........................................110

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PEER REVIEWERS COMMENTS

A. Draft version 1.0; by Chris Spero (Manager Engineering Technology, CS Energy)

1. It is difficult to audit the costs presented because the split between CAPEX, fuels cost, O&M cost, CO2 capture cost and CO2 transport and storage costs is not clear. And whilst I think you have included the CO2 capture costs as part of the plant CAPEX and O&M it is not clear that his is in fact the case.

Capture costs have been included as part of the CCS cases, however the capital cost of this equipment has not been specified because it involves both additional plant and other changes to the process. For example, O2-SC-CCS requires additional plant for oxygen production and flue gas liquefaction/compression; however, other plant items are either reduced in size or eliminated. To clarify the capital cost differences due to capture, additional values have been included in Table 5.3 to show the overall capital cost increase of capture; however, they do not include the effect of reduced availability. The availability effects are included in the generation costs for sent-out electricity in Figure 5.2.

2. Need to revise cost differential for raw coal (21% ash) versus washed/lower ash coal for IGCC – suggest A$0.40/GJ difference now, reducing to half that by 2030. Also need to clarify the specification of 8% ash for the IGCC cases. Note, in the case of Surat Basin coals, there is a natural cut-point of 13% ash. To get down to 8% ash would be expensive because of the energy wasted.

Use of 8% coal for the IGCC case was not meant to imply that this ash level would be required. This value was chosen as the IGCC case study was modelled around the design performance of Tampa, which specified Pittsburgh No. 8 with this ash level. The cost premium for IGCC was meant to represent a combination of penalties for lower ash coal and/or the use of fluxes. Additional clarification to this effect has therefore been included in several sections of the report.

3. Comparison of energy costs is always difficult. Wellhead natural gas costs are typically $2.00/GJ with another $1.00 - $2.00/GJ added on for transport (400-1,000 km). When we do comparisons with different fuels we need to specify the transport distance assumptions.

The cost estimates for gas do include the delivered cost, which for the purposes of this report is assumed as south-east coast of Queensland with nominal transmission distances of 800 km. Additional explanation of this assumption has been included, but the difficulty and uncertainties in this value are acknowledged as a key issue in the coal-gas comparison.

4. The availability values used for the different technologies should be reviewed.

This comment refers to the low availability factors for USC pf in 2010 and 2030 in Table 4.7 in the first draft. These values have been corrected to reflect generators expectations and learning rates (initial values had been incorrectly applied for this technology).

B. Draft version 1.10; by Terry Wall (Professor of Chemical Engineering, University of Newcastle, Australia)

1. A number of comments were made relating to the clarification of statements, definitions and values.

All recommended changes were incorporated.

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C. Draft version 1.10; by Jon Davis (Head Energy Technology Group, Rio Tinto)

1. I agree with Chris Spero's comments about auditing costs; this could be usefully discussed at the Program 1 review. I also agree with Chris' comments about IGCC coal costs - a 50% price relativity? And gas costs - $3.50 going forward seems low.

See comments to Chris Spero. Regarding gas prices, this is identified as key area of uncertainty for generation cost comparisons into the future. The present report has used a nominal value which has been judged as both too high and too low. There are presently Australian studies being undertaken to predict future gas prices based on supply (includes potential coal seam methane) and demand which will clearly benefit future studies.

2. 400km is a long way to transport CO2 - refer CO2CRC comments.

400km was chosen to allow a coastal power station to access inland storage sites, and in the absence of specific injection site information. For the purposes of this study this value has only a small effect via pumping losses, as a flat $10/t has been used for the combined transmission and injection costs.

3. UCC prices of A$3.00/GJ seem low - just a little more than double the IGCC coal price seems unrealistic.

In the present study a value of A$3.00/GJ was used for an “ultra low ash coal” suitable for direct firing (ie DFC), and produced and used in Australia. This value was based on comments from UCC on what might be achieved with full commercialisation of this type of technology. A sensitivity analysis has also been included for $2-5/GJ. Since completing this report, the group has completed a detailed analysis for White Industries UCC (presently a draft CCSD report). In that study, UCC have provided a 2003 cost of US$3.40 delivered to Japan (this is equivalent to around US$2.70 ex-UCC) from a first-of-a-kind production plant. At these costs in Australia, DCF would clearly be uneconomic against most other technologies, except when used for peaking, or in the case of substantially increased gas prices. Given the newness of the technology (and therefore scope for improvement) and the range of potential overall process configurations (production and use), the authors prefer to retain the initial DFC cost estimate, but have highlighted the uncertainty in this value - along with that for gas.

4. O2-USC emerges from the analysis as a preferred option (I do not oppose this conclusion, which if correct is very important). However I wish to understand it, as it differs from other opinions – eg EPRI have advised it is a high cost alternative, and the Canadians (CCPC) have published direct cost of electricity and avoided carbon costs for different technologies (admittedly for low rank coals) which show oxy-firing to be more expensive than solvent PF capture and gasification.

Agree with the significance of this result. We have strengthened the recommendation for the need for a both a supplementary CCSD report, and a more detailed engineering study lead by technology suppliers. This level of detail was beyond the scope and capabilities of the present study.

5. New technologies - bit of a stretch, surely, to promote a technology that is 'unproven at any scale' as a 'low risk step development'?

This statement was based mostly on communications with IHI, together with opinions from several generators. We acknowledge that any new combination of technologies

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has inherent risk – this is clearly very subjective and will be influenced by what the industry is most comfortable with.

6. Discussion of coal-derived hydrogen needs to mention significant sensitivities of fuel cells to sulphur.

Noted, and comments to this effect have been added, including a general specification for <0.1 ppm sulfur from fuel cell developers.

7. Maybe I missed it, but I would have expected to see a comment on oxyfuels oxygen consumption and this impact on costs.

This information is buried in Table 5.1, and not referred to in the text as such, but is reported as a percentage loss of power output (18-20% of electricity generated for oxygen production and fluegas compression). Oxygen production accounts for approximately 65% of this energy consumption. We admit that the present report does not give a high level of process detail, which is beyond the original broad intent of the report. It is therefore recommended that a supplementary CCSD report (on the key technologies only) be produced to provide this level of detail from the underlying modelling and analysis.

8. UCG last sentence - 'a range of environmental benefits' – I think ignores groundwater contamination, which overshadows all other issues.

Given the wide range of opinions on this subject, which is complicated by many site specific effects, this option has been included for completeness but with reservations noted. These reservations have been further highlighted.

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EXECUTIVE SUMMARY

This report gives a comparative assessment of electricity production options for Australia, including projections to 2030. It is based on literature data, LCA, techno-economic modelling, technology experience curves and national energy demand predictions. The report is a melding of outputs for ACA support and the CCSD.

The assessment has been undertaken on the basis that:

The best options for Australia will not necessarily be the same as for other regions, given differences in coal properties, coal intensity, coal exports, availability of natural gas and renewables, and demographics.

There is a need to compare technology options on a common basis – in this case, in an Australian context.

There are differing views on the most appropriate technology combinations for Australia, which is compounded by the time scale under consideration and the strategies being pursued (eg staged reduction or zero emissions).

There remains considerable uncertainty as to exact configuration of the preferred technologies, which is compounded by the trade-offs in capital costs, risk, operating costs, timing and flexibility.

The assessment has compared technologies, and possible technology pathways to meet the projected growth in electricity generation.

The technology combinations evaluated include:

Incremental developments in pf and gas. Alternative technologies – integrated gasification combined cycle gas turbine (IGCC);

underground coal gasification (UCG). New technologies – direct fired coal combined cycle (DFC-CC), oxygen-pf with CO2

capture, IGCC with CO2 capture. Wind.

While covering a wide range of technologies, most of the options evaluated have been limited to representative and relatively conservative technology combinations. These include technologies which are either proven on the required scale, proven as component technologies, or for which there are deemed no significant limiting steps. It is therefore assumed that the technologies could be applied at the demonstration or commercial scale within the next five years if required, and with incremental improvements possible out to 2030. Sufficiently detailed information was lacking to allow comparisons of more step-out technology combinations, for example for fuel cells, membrane capture/separation technologies, alternative technologies for oxygen production and large scale renewables with storage.

The systems assessment methodology used a number of tools including technology modelling, life cycle analysis (LCA), experience curves and economic models. Capital cost projections used a combination of experience curves and literature data corrected for Australian conditions, using currency and location conversion factors.

Technology modelling was carried out using the process simulator METSIM to perform mass and energy balances around the overall process flow sheets. The key location specific conditions used to represent Australian (Queensland) locale were:

Ambient temperature of 25°C, and at sea level (working condenser pressure of 7 kPa).

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Fuel compositions were based on generic Qld/NSW bituminous energy coals, and Australian average natural gas. The same generic coal was used for all coal-fired processes, apart from the ash content, which was lower for the IGCC and ultra clean coal case studies. The base delivered fuel costs were:

- Coal for pf (SC or USC) @ A$1.00/GJ. - Coal for IGCC @ A$1.40/GJ (now) reducing to A$1.20 by 2030, which gives a

nominal cost impost for lower ash in the coal and fluxing requirements. - Natural gas for NGCC @ A$3.50/GJ. The cost estimate of natural gas is the

delivered cost which includes a nominal transmission distance of around 800 km. - Direct fired coal (turbine coal) DFC-CC @ A$3.00/GJ (assumes considerable

refinement for the production process over that currently for UCC). Captured CO2 is compressed and piped a distance of 400 km for injection at 10 MPa.

A pipeline and disposal cost of A$10 per tonne of CO2 has been used, with capture and compression costs being allocated to generation.

Different annual capacity factors have been used to allow for differences in availabilities for each technology, and these factors were increased with time.

The DFC-CC was assumed to give a 5% saving in transmission losses by enabling distributed generation.

CCSD life cycle values have been used to compare the overall greenhouse gas emissions (with CSIRO values were used for UCC production).

Key findings

Effect of CO2 capture on plant efficiency

For the IGCC technologies, the base plant (based on Texaco) has a sent out efficiency of 43.4% (HHV) with greenhouse gas emissions of 713 kg/MWh – this predicted efficiency is significantly higher than for current IGCC plants due to the assumption of a more advanced gas turbine. Capture of 75% of CO2 using a single sour shift and MEA stripping reduced the overall plant efficiency by 10% to 33%. MEA has been used as the base case due to its widespread use in industry for CO2 capture. Use of Selexol reduced this loss to 7%, giving an overall efficiency of 37%. It is likely that improved integration of the CO2 capture with the power plant together with alternative capture processes are likely to further improve the sent out efficiency.

CO2 capture for oxygen USC reduces the sent out efficiency by approximately 9%, due to the parasitic load for oxygen production and flue gas compression.

CO2 capture and compression reduces sent out electricity by 16-23% for the IGCC cases and 18-20% for O2-USC-95% cases.

The parasitic losses for CO2 pipelining are relatively small: a 500 MW plant would need a 12-14” nominal bore pipe to maintain pumping losses over 400 km to around 0.5% of the sent out electricity.

Installation costs

Projected costs use the capital costs for 2002 decreased by the learning rate factors, which includes changes to both efficiency and availability. Projected capital costs (on a A$2002 basis) and efficiencies are shown in the table below for a number of power plants (this excludes CO2 pipelines and injection wells). The efficiency data are based on a combination

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of EU projections and other estimates, and include allowances for Australian conditions. The most significant changes between current and projected 2030 are:

The marked decrease in capital cost for IGCC (either with out without capture) and wind. For IGCC this reflects both a reduction in installed cost/MW, and improved availability.

A marked increase in the efficiency for all of the technologies.

2002 2010 2030 Technology Capital cost(A$M/MW)

Eff.(%)

Capital cost(A$M/MW)

Eff. (%)


Eff.(%)

Supercritical pf (SC) 1,151 41 1,062 43 960 45

Natural gas combined cycle (NGCC) 825 53 679 56 614 65

Ultrasupercritical pf (USC) 1,210 43 1,117 45 1,010 52

Ultrasupercritical pf (O2-USC-95% CCS)2

1,868 34 1,589 37 1,438 44

Direct fired coal combined cycle (DFC-CC)

926 49 762 52 689 60

Integrated gasification combined cycle (IGCC)

1,584 43 1,172 48 884 50

Integrated gasification combined cycle (O2-IGCC-25% CCS)2

1,839 39 1,360 45 1,026 60


2,453 33 1,814 40 1,369 44

Wind (based on peak capacity factor)3 1,700 - 1,458 - 1,014 -

1. Based on A$2002. 2. Excludes CO2 transmission and storage. 3. Excludes effects of low capacity factor (25-30% for wind) and any energy storage. These factors

increase the capital cost/MW by 800-1,000%.

Current generation costs

The lowest cost options are supercritical and ultrasupercritical pf at A$25/MWh. This is a significantly lower cost than for IGCC, NGCC and DFC, which have similar costs of A$33-35/MWh.

All of the technologies with carbon capture and storage (CCS) have generating costs, which are around A$20/MWh higher – when all of the costs are assigned to the sent out electricity. This is due to higher capital costs, lower availability and lower sent-out efficiency.

On the same basis, O2-USC-95% CCS would be the lowest cost technology for carbon capture and storage. However, this difference decreases into the future due to the anticipated more rapid developments in IGCC (as discussed latter).

The production cost of hydrogen is A$7.90/GJ (which equates to A$55-60/MWh of electricity if used in a hydrogen combined cycle gas turbine).

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Cost comparison of power generation technologies.

Equivalent of fuel costs

Currently, supercritical pf with coal at the base cost of A$1.00/GJ gives similar generation costs (sent out basis) to DFC-CC at A$1.60/GJ, NGCC using gas at A$2.00/GJ, and IGCC using coal at approximately A$0.20/GJ.

This equivalent value of fuel changes is predicted to change greatly by 2030, with ultrasupercritical pf with coal at the base cost of A$1.00/GJ giving similar generation costs to IGCC using coal at A$1.10/GJ, DFC-CC at A$1.65/GJ and NGCC using gas at A$2.00/GJ.

Projected generation costs

By 2030, the lowest generation cost is for supercritical/ultrasupercritical and IGCC, all similar at A$20-22/MWh.

IGCC-75% CCS generation costs decrease more quickly than for the other coal-based technologies, and give similar generation cost to O2-USC-95% CCS in 2030.

NGCC and DFC-CC have similar costs.

IGCC-25% CCS (ie partial capture) becomes lower cost than NGCC and DFC-CC at around 2015-2020.

Costs for CO2 pipelining and storage are 15-20% of the overall generation costs.

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(A$/

MW

h)

SC NGCCUSC O2-USC-95% CCSDFC-CC IGCCO2-IGCC-25% CCS O2-IGCC-75% CCSWind

Current and projected costs for power generation technologies to 2030.

Economics of CO2 abatement

The generation costs above assign no value to the reduction in CO2 emissions from either improvement in efficiency and/or CO2 capture and storage. Two approaches have been used to take account of reduced emissions:

Comparing the overall cost of CO2 abated, relative to a base case cost of generation. In the present study, the technology base used here is supercritical pf to 2015, and ultrasupercritical from 2015 to 2030. Note that comparisons of the cost of CO2 abated are highly sensitive to the base case chosen; for example, using a grid average base case (which includes older stations would give a marked decrease in the cost of abatement.

Assigning an externality or societal value to the CO2; ie a dollar value of carbon. The present study has used A$0-50/t CO2 emitted.

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Cost of CO2 abated method

Technology Cost of CO2 abatement 2002

($/t CO2)

Cost of CO2 abatement 2010

($/t CO2)


($/t CO2)

IGCC 201 44 -3

DFC-CCGT 76 61 34

IGCC-25% CCS 95 45 22

IGCC-75% MEA-CCS 67 42 27

O2-USC-95% CCS 31 26 21

NGCC 25 22 16

USC 28 18 -7

Currently (relative to the base case supercritical plant):

NGCC gives the lowest abatement cost of A$25/t CO2.

USC and O2-USC-95% CCS have abatement costs of A$28-31/t CO2.

For 2030:

There is a large projected decrease in the abatement costs for IGCC relative to estimates for 2002.

USC and IGCC give the lowest abatement costs of negative A$3-7/t CO2 (ie can give reduced CO2 emissions and overall generation costs, relative to SC).

NGCC has an abatement cost of around A$16/t CO2.

IGCC-CCS and O2-USC-95% CCS have similar costs of A$22-27/t CO2.

Direct-fired coal (DFC-CCGT) gives the highest cost of abatement of A$34/t CO2.

Note, that other factors not included in the analysis could also influence this comparison, for example credits from liquids and chemicals polygeneration options possible with IGCC and technology development rates - small changes to the experience curves now (eg due to a major RD&D effort), will have a major influence on economics in 2030.

Externality method

Projected generation costs are shown for a range of hypothetical values of carbon in the figure below; most technologies have similar costs of A$20-35/t CO2.

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20

30

40

50

60

70

0 5 10 15 20 25 30 35 40 45 50

Value of carbon (A$/t CO2)

Pow

er c

ost (

A$/

MW

h)

SC NGCC

USC O2-USC-95% CCS

DFC-CC IGCC

O2-IGCC-25% CCS O2-IGCC-75% CCS

Effect of value of carbon, 2030.

Other implications

The present analysis has not included credits from co-products from any of the technologies, for example, from the sale of fly ash, slags or by-product sulphur. Note, if all sulphur was captured from power generation for acid production, this would still only produce approximately 33% of Australia’s current demand for sulphuric acid.

Future grid scenarios

Five scenarios were chosen to represent extreme technology pathways. A key assumption was that new technologies apply equally to black and brown coals (ie new technologies for brown coal will result in similar CO2/MWh sent out basis).

Scenario A (all new by coal)

Replacement of future power demand with higher efficiency coal fired plants (SC).

Scenario B (high wind, additional by coal)

Replacement of future demand with 5,000 MW of wind by 2010, then maintaining 12% wind generation with additional demand met by high efficiency coal-fired plants (no CO2 capture)

Scenario C (high wind, additional by gas)

Replacement of future demand with 5,000 MW of wind by 2010, then maintaining 12% wind generation with additional demand met by high efficiency combined cycle natural gas (no CO2 capture).

Scenario D (all new by renewables)

Replacement of all future demand with renewables.

Scenario E (all new by zero emissions coal)

Replacement of all future power demand with 100% coal-fired CO2 capture and storage technologies.

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The projected annual average greenhouse intensity and total emissions are shown below:

0

100

200

300

400

500

600

700

800

900

1000

2000 2005 2010 2015 2020 2025 2030

Year

Gre

enho

use

gas

inte

nsity

(kg/

MW

h)

High eff. coal

Wind + High eff coalWind + NGCC

Renewables100% Coal CCS

Greenhouse intensity of the grid scenarios (kg/MWh).

0

50

100

150

200

250

300

2000 2005 2010 2015 2020 2025 2030

Year

Tota

l gre

enho

use

gas

emis

sion

s (M

t)

0

50

100

150

200

250

300

350

400

450

Tota

l ele

ctrii

cty

dem

and

(TW

h)

High eff. coalWind + High eff coalWind + NGCCRenewables100% Coal CCSDemand (TWh)

Projected total annual greenhouse gas emissions (Mtpa).

Scenario A - by 2030 the greenhouse intensity of the grid would decrease by approximately 20%, but total greenhouse gas emissions would increase by approximately 67% due to the projected growth in power demand.

Kyoto target? 1990 emissions 131 Mt 2008-12 emissions 141 Mt

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Scenario B – gave a decrease in greenhouse intensity of 30% by 2030, but total emissions would increase by 46% due to growth in demand. This requires 24,000 MW of new wind capacity (or 2.4 MW of added wind capacity every day from 2003 to 2030).

Scenario C - the greenhouse intensity is decreased by 54% out to 2030, which results in an overall reduction of 5%.

Scenario D - the greenhouse intensity would decrease by 85% to 2030, and the total emissions from power generation would decrease by 68%. This would require an extreme installation rate of renewables (17.4 MW of renewable capacity per day, or 10 large wind turbines per day for the next 27 years). In addition, this would need to be backed by a similar capacity of energy storage (unless backup was provided by additional fossil fuelled capacity).

Scenario E – gives similar greenhouse intensity and the total emissions as all renewables.

It is noted that by 2008-12, no scenarios would meet a 108% rise of 1990 greenhouse gas emissions. Only scenarios D and E would meet the target around 2020.

The cumulative capital costs for new and replacement capacity are highly dependent on the proportion of renewables:

The lowest cost option to meet expected emissions abatement targets is high efficiency coal with carbon capture and storage.

If all future generation were via renewables (in this case the lowest cost renewable option, wind) the cumulative capital costs to 2030 would be 800% higher – around A$370 billion.

Conclusions

Technology - effect of CO2 capture on efficiency CO2 capture for IGCC reduces the overall thermal efficiency by approximately 7-10%,

due to the energy for capture and the parasitic load for CO2 compression.

CO2 capture for oxygen USC reduces the overall thermal efficiency by approximately 9%, due to the parasitics for oxygen production and flue gas compression/liquefaction.

CO2 capture and compression reduces sent out electricity by 16-23% for IGCC and 18-20% for O2-USC.

Economics - generation and hydrogen costs (based on A$2002) In the near future, lowest cost generation options are supercritical and

ultrasupercritical pf at A$25/MWh. This is a significantly lower cost than for IGCC, NGCC and DFC-CCGT, which have similar costs of A$33-35/MWh.

All of the technologies with CCS have generating costs, which are A$20/MWh higher – when costs are assigned to the sent out electricity. This is due to increased capital, lower availability and lower sent-out efficiency.

By 2030, the lowest generation cost is for supercritical/ultrasupercritical and IGCC at A$20-22/MWh.

IGCC-CCS generation costs are projected to decrease more quickly than for the other coal-based technologies.

NGCC and DFC have almost identical costs.

For CCS, the cost of CO2 pipelining and storage is 15-20% of overall generation costs.

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The current production cost of hydrogen from gasification is A$7.90/GJ (equates to A$50-60/MWh of electricity if used in a hydrogen combined cycle gas turbine).

CO2 abatement costs (based on A$2002)

In the near future, NGCC will give the lowest abatement cost of A$25/t CO2, followed by USC and O2-USC-95% CCS at A$28-31/t CO2 (costs for IGCC CCS are higher).

There is a large projected decrease in the abatement costs for IGCC over the next 30 years. By 2030 NGCC, IGCC-CCS and O2-USC-95% CCS have similar costs of A$20-27/t CO2, and direct-fired coal has the highest cost of abatement.

Meeting emissions targets

Of the five scenarios considered, zero emission coal technologies and renewables are the only options, which give a marked decrease in GGE with the projected electricity demand. ZETs are the lowest cost option, with renewables costing over 800% more.

RD&D

The study has highlighted the need for more detailed assessment of the wide range of technology options available.

Given the wide range of options available, the level of improvements achieved by 2030 will be most highly dependent on RD&D commitments made now.

Recommendations

As literature values for capital costs vary greatly and are compounded by the differences in scope, timing, different bases and degree of CO2 captured, costs should be established for a number of selected technology combinations for specific sites on a semi-engineered basis (ie to a prefeasibility level of detail). This requires working with suppliers of technology on a case-by-case basis.

IGCC options did not give favourable generation costs until ~2030. However, as IGCC offers many more options than considered in the present study, and projected costs and efficiencies are highly dependent on experience/learning rates, a more detailed analysis is required to consider the effect of RD&D on the development path for IGCC. This should include analysis for the production of liquid fuels and chemicals (polygeneration), and consider the life cycle and economic implications of a hydrogen economy. This assessment should use real options analysis to assess alternatives (in collaboration with CCSD Project P4.2).

Only three CO2 capture technologies have been studied in this project – this can impact significantly on the economics, so assessment of additional configurations are required.

Oxygen ultrasupercritical shows good economics and, while not yet demonstrated, is considered to be achievable by a major technology provider, and several overseas groups. A more detailed analysis is required, with emphasis on when this technology is likely to be demonstrated, and the scope for retrofitting.

The study has only considered black coal generation options in detail – developments in brown coal technologies (drying, IGCC and O2 USC) should result in similar overall greenhouse gas intensities and overall generation economics. Given the large reserves of soft and hard brown coals, a detailed analysis of these options should be included in future analyses.

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Additional natural gas options should be considered, including oxygen firing and synergies with coal; eg gas co-firing and the utilisation of coal seam methane from coal mining - options that may economically lower the greenhouse intensity of the coal chain.

Future costs for natural gas and direct fired coal require re-assessment.

Retrofitting options were not considered in the present study due to adverse opinions of this technology. As the cost benefits of pf may outweigh efficiency losses, especially with small improvements in capture technology/re-engineering, retrofitting should be considered in future analyses.

The present study only considered wind energy due to the current adverse economics of alternative renewables. As all types of renewable energy are available in Australia, a range of grid-connected options should be included in future studies. This study should include the ability of the grid to balance a significant input from discontinuous generators without the need for storage.

There is a need to consider other benefits derived from location specific integration/synergies of options based on coal, including polygeneration, co-firing and the utilisation of biomass and other wastes.

Future analyses therefore need to consider;

- the effects of accelerated developments from increased rates of RD&D, and the role of current Australian research programs, and

- the overall implications of these developments on coal markets.

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1 INTRODUCTION

This report gives a comparative assessment of electricity and energy production options for Australia, with projections to 2030. It is based on literature data, LCA and techno-economic modelling, and the use of technology experience curves and national energy demand predictions. The report is a melding of outputs for ACA support and the CCSD.

This report is mostly restricted to black coal options. A similar analysis is in progress for a wider range of alternative energy sources (both renewable and fossil) using similar basis.

Whilst the authors acknowledge the present broad appeal of IGCC with capture and storage, the present study has considered a wider set of technology combinations to provide both a baseline for comparison and increased completeness. The broader assessment has been undertaken on the basis that:

There remain several views on the most appropriate technology combinations – this is compounded by the time scale under consideration and the strategy being pursued (staged reduction or zero emissions).

There remains considerable uncertainty as to the exact configuration of the preferred generic technologies, which is compounded by the trade-offs involved (capital cost, risk, operating costs, timing and flexibility).

The best combinations for Australia will not necessarily be the same as for other regions, given differences in coal properties, coal intensity, and coal exports.

There is a need to compare technology options on a common basis – in this case, in an Australian context.

The specific objectives of this study were to provide a:

Comparative assessment of electricity generation options using a range of technology/fuel combinations in an Australian context, with projections out to 2030. A further objective was to undertake the assessments on a common basis, to provide consistent and in-context information for COAL21.

Framework for collating and reconciling data from a wide range of sources, and especially to help provide tools for future collaborative work for both COAL21 and the CRCs.

Development and demonstration of CCSD systems assessment tools specifically to assist decision-making at both industry and policy levels. Also, that these tools provide a vehicle to facilitate collaboration between key Australian CRCs – namely the CCSD, CRC for Clean Power from Lignite, and the CO2 CRC. It is envisaged that this facilitation will also extend to other Australian groups (eg the Renewables CRC), and provide a basis for information exchange with overseas groups (eg CREIPI/IHI-Japan, NICERT-UK) – there has already been some exchange with these groups.

The study marks a significant extension of activities from the earlier LCA work (ACARP/CISS), and has been supported by the Australian Coal Association and the CCSD. CCSD inputs have been via Program 1 (namely P1.1 and P1.3), and tools and methods established to complete a similar study for Western Australia. The latter was commenced, but revised with a COAL21 emphasis as the priority.

Given the breadth and depth of knowledge required to complete this type of analysis, together with the rapid rate of change in technology (and views), the findings detailed in this report should be regarded as work-in-progress, and hopefully will assist in providing a model

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framework for on-going work and benefit from more direct inputs from experts from other organisations.

The report is comprised of 4 main sections:

Section 2 Background focused around trends in electricity generation demand growth on a global and Australian basis.

Section 3 Technology overview, giving typical process configurations, features and development trends.

Section 4 The systems assessment methodology used in the current analysis, including details on base fuel compositions and key performance parameters for each of the technologies assessed.

Section 5 Results and discussion for technology comparisons on a $/MW installed, $/MW sent out and GGE basis, and the greenhouse intensity and capital requirements for 5 project grid scenarios.

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2 BACKGROUND – TRENDS IN ELECTRICITY GENERATION

The driver for this work is recognition of the need to provide more sustainable energy for more of the World’s population. Whilst the definitions for sustainability are many, all involve (or imply) increased energy supply, increased energy security, and reduced environmental and social impacts - though all do not necessarily need to be achieved by a particular option. Trade-offs will be a necessity.

This study has focused on meeting the required growth in electricity generation, and has included overall economics, greenhouse gas emissions (GGE) and potential Australian capacity from a range of technologies – on a current and projected basis.

World energy consumption

The evolution of world energy consumption has changed markedly since the beginning of the industrial revolution in the late 1700s, which up until then was sourced primarily from biomass. The marked decline in forest reserves coupled with the discovery of fossil fuels changed the energy mix significantly. These changes, together with projected trends, are depicted graphically in Figure 2.1 (modified from Baretto et al[1]) and show:

A marked increase in the use of coal as an energy source from 1850 to 1900.

An increase in the percentage share of oil and gas from 1920 to 2000.

In common with most other predictions, Baretto shows a significant swing to hydrogen based, zero emission energy sources will occur between 2000 and 2100, with natural gas playing an important role as a transition fuel. The use of coal is predicted to drop to below 10% of the energy mix by 2050.

The future predictions are based on the premise of a hydrogen economy, with hydrogen derived from zero emission processes using a combination of fossil, nuclear and renewable energy sources. It is unclear what trade offs are required for these projections, the effect of growth in less developed countries, and the role of coal in zero emissions technologies

Renewables / Zero Carbon

Oil/Gas

18501900

1920

1950

1970

1990

20002050

B1-H2 2100

100%

80%

80%

60%

60%

40%

40%

20%

20%

100%20% 40% 60% 80% 100%

Coal

Figure 2.1 Historical and future world energy mix.

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Growth in world electricity demand

On a worldwide basis, electricity generation was 15,391 TWh in 2000. Since 1971, power generation has increased by 3.8% annually, outpacing economic growth of 3.3% per annum (pa). The International Energy Agency (IEA) expects economic growth to slow down to 3% pa for the period 2000-2030, with power generation growth rate decreasing to 2.4% pa. Forecasts for electricity generation are 20,037 TWh in 2010, 25,578 TWh in 2020 and 31,524 TWh in 2030. These data and projections are summarised in Table 2.1. Note that the projections of this reference scenario are based on a set of assumptions on macroeconomic conditions, population growth, energy prices, government policies and technology. Only those government policies and measures that have been enacted, though not necessarily implemented, as of mid-2002 are taken into account.

Table 2.1 World electricity generation (TWh).

Electricity generation (TWh) Share (%) Growth rate (% pa) 1971 2000 2010 2020 2030 1971 2000 2010 2020 2030 1971-

2000 2000-2010

2000-2020

2000-2030

Coal 2,101 5,989 7,143 9,075 11,591 40 39 36 35 37 3.7 1.8 2.1 2.2

Oil 1,095 1,241 1,348 1,371 1,326 21 8 7 5 4 0.4 0.8 0.5 0.2

Gas 696 2,676 4,947 7,696 9,923 13 17 25 30 31 4.8 6.3 5.4 4.5

H2 fuel cell 0 0 0 15 349 0 0 0 0 1 - - - -

Nuclear 111 2,586 2,889 2,758 2,697 2 17 14 11 9 11.5 1.1 0.3 0.1

Hydro 1,208 2,650 3,188 3,800 4,259 23 17 16 15 14 2.7 1.9 1.8 1.6

Renewables 36 249 521 863 1,381 1 2 3 3 4 6.9 7.7 6.4 5.9

Total 5,248 15,391 20,037 25,578 31,524 100 100 100 100 100 3.8 2.7 2.6 2.4

Renewables

Biomass 167 276 399 568 67 53 46 41 5.1 4.5 4.2

Wind 31 147 307 539 12 28 36 39 16.8 12.1 10.0

Geothermal 49 85 126 174 20 16 15 13 5.6 4.8 4.3

Solar 1 11 27 92 0 2 3 7 25.1 17.1 15.7

Tide/Wave 1 1 4 8 0 0 0 1 9.3 9.5 8.9

40%

8%17%

0%

17%

17%1%2000

36%

4%31%

1%

9%

14%

1%2%

2% Coal

Oil

Gas

Hydrogen-fuel cell

NuclearHydro

Biomass

Wind

Geothermal

Solar

Tide/Wave

2030

Figure 2.2 Share of fuel sources to generate electricity in 2000 and 2030.

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Figure 2.2 shows that the share of fossil fuels in the projected energy mix increases from 65% in 2000 to 72% in 2030, with a big increase for natural gas and slight reductions for coal (from 40% to 36%) and oil (from 8% to 4%). In the same time period, nuclear’s share diminishes by 47%, hydropower goes from 17% to 14% and other renewables double from 2% to 4%. Biomass and wind make up 80% of these renewables. Hydrogen-fuel cells will generate one percent of electricity demand in 2030.

Carbon dioxide emissions associated with the generation of power increased from 3,925 Mt in 1971 to 8,958 Mt in 2000, a 2.9% pa increase. The growth in CO2 emissions is anticipated to be 2.0% pa for the period 2000-2030, reaching 11,285 Mt in 2010, 13,848 Mt in 2020 and 16,457 Mt in 2030. CO2 emissions are summarised in Table 2.2.

Table 2.2 World CO2 emissions from power generation.

CO2 emissions (Mt) Shares (%) Growth rates (% pa) 1971 2000 2010 2020 2030 1971 2000 2010 2020 2030 1971-

2000 2000-2010

2000-2020

2000-2030

Coal 2,524 6,276 7,482 8,977 10,706 64 70 66 65 65 3.2 1.8 1.8 1.8

Oil 862 992 1,070 1,060 1,000 22 11 9 8 6 0.5 0.8 0.3 0.0

Gas 539 1,689 2,733 3,811 4,752 14 19 24 28 29 4.0 4.9 4.2 3.5

Total 3,925 8,958 11,285 13,848 16,457 100 100 100 100 100 2.9 2.3 2.2 2.0

70%

11%

19%

2000

65%6%

29% Coal

Oil

Gas

2030

Figure 2.3 CO2 emissions by fuel source to generate electricity in 2000 and 2030.

While the share of greenhouse gas emissions from coal used for electricity production will decrease from 70% in 2000 to 65% 2030, coal will remain the dominant greenhouse gas contributor. Doubling of electricity production from gas-based technologies will increase their greenhouse gas contribution from 19% in 2000 to 29% in 2030. (Figure 2.3)

All global numbers are extracted from The International Energy Agency’s World Energy Outlook 2002 [2].

Australian situation

The capacity of the Australian power generation system in 2001 was 46.5 GW and generated approximately 198 GWh (from grid connected plants only). The bulk of the installed capacity is in Queensland, NSW and Victoria (see Table 2.3).

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The share of fuel sources for electricity generation in 2001 was black coal 57.6%, brown coal 26.8%, natural gas 7.4%, hydro 7.9% and oil 0.03% (see Figure 2.4). Note that these figures exclude non-grid private generators[3].

Table 2.3 Electricity generation capacity of Australian States (ESAA, June 2002).

State Principal plant (MW)

Non-grid generators and non-renewable cogeneration

(MW)

Renewable1

(MW) Total (MW)

% of total

Grid Capacity

factor (%)

NSW & ACT 12,147 209 272 12,628 27.0 58.1

Qld 10,691 213 386 11,290 20.5 55.5

VIC 8,337 220 242 8,799 18.1 68.7

SA 3,479 195 20 3,694 7.0 39.1

WA 3,316 1,849 71 5,236 12.7 42.9

NT 504 226 - 730 1.6 50.9

Tas 2,542 16 11 2,569 5.3 39.5

SMHEA 3,756 - - 3,756 7.8 -

Total 44,772 2,928 11 48,702 100 56.4

1. Does not include principal generation hydroelectricity

57.4%26.6%

8.1%

7.6% 0.3%Black coal

Brown coal

Hydro

Natual gas

Oil products

2001

Figure 2.4 Electricity generation (grid only) by fuel type in 2000/01 (ESAA).

The Australian Bureau of Agriculture and Resource Economics (ABARE)[4] and the International Energy Agency (IEA)[5] have made projections on the amount and mix of power generation in 2020 (see Table 2.4). The annual growth rates for all fuel types are positive to 2020, with ABARE projecting black coal to be 1.6%, brown coal 1.0%, natural gas 5.4%, hydro 0.8% and renewables by 10-15%. Market shares in 2020, based on ABARE’s projections, results in the black coal market share dropping from 54% in 2000 to 49% in 2020, and brown coal from 24% in 2000 to 19% in 2020. The market share for natural gas increases significantly from 13% in 2000 to 23% in 2020. While the growth in renewable technology is high, market shares in 2020 are only around 1% each for wind, biogas and biomass.

Pa

ge 3

3 of

131

Tabl

e 2.

4 El

ectr

icity

gen

erat

ion

proj

ectio

ns b

y fu

el ty

pe

El

ectri

city

gen

erat

ion

(TW

h)

Shar

es (%

) G

row

th ra

tes (

% p

a)

20

01

2010

20

20

2001

20

10

2020

20

01-2

010

2001

-202

0

IEA

A

BA

RE

IEA

AB

AR

EIE

AA

BA

RE

IEA

AB

AR

E IE

AA

BA

RE

IEA

AB

AR

EIE

A

AB

AR

EIE

A

AB

AR

E B

lack

coa

l 11

7.8

129.

6 16

0.5

54%

49

%

49%

1.

1%

1.6%

B

row

n co

al

162.

2 51

.8

199.

653

.1

231.

062

.8

77%

24%

77

%20

%

71%

19%

2.

3%

0.3%

1.

9%

1.0%

O

il 2.

6 2.

9 3.

0 2.

9 3.

9 2.

9 1%

1%

1%

1%

1%

1%

1.

4%

0.2%

2.

1%

0.0%

G

as

26.7

27

.5

31.7

54

.6

59.4

74

.4

13%

13%

12

%20

%

18%

23%

1.

9%

7.9%

4.

3%

5.4%

H

ydro

16

.6

16.8

18

.1

18.4

19

.1

19.6

8%

8%

7%

7%

6%

6%

0.

9%

1.0%

0.

7%

0.8%

C

ombu

stib

le re

new

able

s & w

aste

1.

7

5.7

6.

9

1%

2%

2%

14

.2%

7.

5%

O

ther

rene

wab

les

0.1

2.

5

3.1

0%

1%

1%

37.9

%

17.7

%

Bio

mas

s

0.6

4.

0

4.8

0%

1%

1%

23.4

%

11

.6%

B

ioga

s

0.3

1.

9

2.1

0%

1%

1%

22.7

%

10

.8%

W

ind

0.

2

2.4

2.

9

0%

1%

1%

32

.1%

15.1

%

Tot

al 2

10.0

21

8.0

260.

626

7.0

323.

433

0.1

2.4%

2.3%

2.

3%2.

2%

CO

2 em

issi

ons (

Mt)

18

1.5

19

3.2

23

0.1

0.

7%

1.

3%

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A model developed by Roam Consulting[6] for Rio Tinto Technical Services estimates the gap between projected demand and the generation available from existing plant over time as old plant retires and demand grows. One set of results from that model is shown in Figure 2.5 and use the following assumptions:

The supply and demand balance for electrical energy to 2030 was developed using forecasts from reliable sources such as NEMMCO and extrapolation as needed.

High, medium and low economic growth scenarios were based on those developed for NEMMCO and transmission grid owners. A medium load growth forecast was selected as the central case (which is shown here), based on NIEIR's latest set of forecasts supplied to NEMMCO.

The requirement that retailers and other large wholesale buyers of electricity purchase at least 2% of their power requirements from new renewable sources has been taken into account in the forecasts as a net reduction in the energy to be supplied.

Hydro generators in the Snowy Mountains, Tasmania, Victoria, New South Wales and Queensland are kept in service throughout the scenario period.

Existing and future transmission capabilities have been taken into account when modelling the utilisation of plant through the NEM.

Existing coal-fired electricity generation plant was assumed to have a 40-year life.

The results show the total power consumed in Australia increasing from approximately 205 TWh in 2002 to 450 TWh by 2030 with the existing capacity not able to meet demand in 2005-06. By 2030, existing capacity would only meet 100 TWh of the predicted 450 TWh.

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

1999/2000

2004/05

2009/10

2014/15

2019/20

2024/25

2029/30Year

GW

h G

ener

ated

NT Generation

WA Generation

Tas Generation

SA Generation

VIC Generation

Snowy Generation

NSW Generation

QLD Generation

EnergyRequirement

Figure 2.5 Projected Australian power supply and demand.

In line with the projected increase in power demand will come an increase in greenhouse gas emissions, which will exceed our Kyoto commitments at current CO2 emissions rates.

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Emissions from the Australian electricity grid in 1990 were 131 Mt[7]. When applying Australia’s 108% factor for the electricity grid the target emissions in the Kyoto period from 2008-12 are 141.5 Mt. In 2000, the greenhouse gas emissions from the Australian grid were approximately 180 Mt (NGGIC), well in excess of the Kyoto target. It is evident that significant progress is required to reduce greenhouse gas emissions. An increase in renewable energy technologies and fossil fuelled power generation efficiency is required, along with significant developments in, and application of, CO2 capture and storage technologies.

While it is technically possible that all of Australia’s power generation could be generated from renewable resources, it is highly unlikely that this will be possible in the next 50 years or so, due primarily to the dispersed and intermittent nature of renewable energy supply, not to mention the massive infrastructure requirement. Therefore, in the transition period, fossil fuels will be required to play a significant role. In order to meet the Kyoto emission targets, a more concerted effort is required in the area of CO2 capture and storage from fossil fuel power generation.

Indeed, over the last century, significant progress has been achieved in reducing the greenhouse gas intensity of fossil fuelled electricity generation (see Figure 2.6[8]). Increasing scale, plant design and superior materials, which allow higher steam temperatures and pressures, have combined to improve plant efficiencies and reduce emissions per unit of power. There is potential to further increase power plant efficiencies and decrease greenhouse gas emissions, though to achieve a net stabilisation or decrease in emissions, CO2 capture and storage will be required.

0

12

34

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1850 1900 1950 2000 2050

GG

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1884 Steam turbine

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1920-35 Increased scale, superheat,

water wall fu

rnaces, suspension firing

1970s Larger capacity, unifie

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designs

Universal use of steam turbine

Increasing scale 10 - 50,000kW

Increasing scalesuperheat & pressure

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water wall fu

rnaces, suspension firing

1970s Larger capacity, unifie

d

designs

Universal use of steam turbine

Increasing scale 10 - 50,000kW

Increasing scalesuperheat & pressure

1800

Faraday

generates

electricity

Figure 2.6 Greenhouse gas intensity of coal-fired power generation since 1890.

There are Commonwealth and State Government policies in place to assist in the abatement of greenhouse gas emissions. The two schemes of particular note are the Australian Greenhouse Office Mandatory Renewable Energy Targets (MRET) and the NSW Governments Greenhouse Gas Abatement Scheme.

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The Mandatory Renewable Energy Target commenced on 1 April 2001 and The Renewable Energy (Electricity) Act 2000 requires the generation of 9,500 GWh of extra renewable electricity per year by 2010, enough power to meet the residential electricity needs of four million people. The Office of the Renewable Energy Regulator has been established to oversee the implementation of the measure. A high level Panel has been formed during 2003 to review the Mandatory Renewable Energy Target (MRET) legislation and will be reporting back later in 2003[9].

From 1 January 2003, NSW electricity retailers and certain other parties will be required to meet mandatory targets for abating the emission of greenhouse gases from electricity production and use. These benchmark participants will have to reduce their emissions of greenhouse gases to the pre-set benchmark levels, or pay a penalty per tonne of emissions above their targets. Benchmark participants can offset their excess emissions by surrendering abatement certificates bought from low-emission electricity generators and other persons accredited as certificate providers. The Independent Pricing and Regulatory Tribunal (IPART) administer the scheme[10].

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3 TECHNOLOGY DESCRIPTIONS

This section gives a brief overview of a range of potential generation technologies that are of particular relevance to Australia, and the process technology flow sheets are similar to those modelled in Section 4. The technologies include:

Benchmark technologies – supercritical pf (SC) and natural gas combined cycle gas turbine (NGCC).

Incremental developments in pf - supercritical (SC) and ultra-supercritical (USC) plants.

Alternative technologies – integrated combined cycle gas turbine (IGCC), underground coal gasification (UCG).

New technologies – direct fired coal combined cycle (DFC-CC), oxygen-pf with CO2 capture, IGCC with CO2 capture (hydrogen turbine).

Hydrogen production - to provide a feed for hydrogen-economy options; eg coal-to-liquids production and electricity generation using solid oxide fuel cells.

CO2 /other acid gas capture, and CO2 compression and liquefaction (sequestration ready supercritical CO2).

Implications of sulphur capture.

Benchmark technologies

Supercritical pf (SC) is used as the benchmark technology for coal-fired generation. Although the technology was first demonstrated in 1957, metallurgical and control problems have delayed widespread application until the last 15 years. SC is now regarded as mature technology in many overseas countries, especially in Japan, the USA and Europe, with many installations over 15 years old. The uptake of supercritical technology has been much slower in Australia where to date only three plants have been installed, all in the last few years (eg Tarong North, Callide and Millmerran). 42% OTE is practical under Australian conditions.

Combined cycle natural gas (NGCC) used as the benchmark for gas-fired generation. Large NGCC plants have been installed in Australia over the past 5 years (eg Swanbank E and Pelican Point). 52% OTE is practical under most conditions.

Incremental technologies

Ultrasupercritical pf (USC) is an incremental pf technology, which is undergoing extensive development and re-engineering in Japan, USA and Europe. The EU AD700 Program considers that ~50% overall thermal efficiency (HHV) is possible, with an estimated ~48% OTE being achievable for Australian conditions.

NGCC is also being subject to extensive on-going development to improve efficiency, with estimates of 65% OTE being achieved by 2030.

Alternative technologies

Integrated gasification combined cycle (IGCC) – this is a relatively new technology for power generation, with most of the earlier applications of coal gasification being used for chemical production. IGCC is undergoing extensive RD&D for the production of both electricity and hydrogen. Inherent advantages of the technology

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are the relative ease of producing hydrogen, and CO2 capture. IGCC is capable of achieving 42-43% OTE.

Underground coal gasification combined cycle (UCG-CC) has been chosen as alternative technology because it gives similar option as IGCC, and has been demonstrated at large pilot scale (with varying levels of success), and because it uses a combination of mostly proven technologies. The technology has special advantages by avoiding mining, by allowing use of deep/uneconomic seams, and the avoidance of disposal of solid wastes (both coal washery refuse and fly ashes). In practice the technology should attain an OTE similar to IGCC. Though the technology will only be applicable under specific site conditions, Australia has large coal reserves that could utilise this technology.

New technologies

Oxygen SC pf, while unproven at any scale, is considered by a wide group of technologists to offer a low risk step development of existing pf technology to enable CO2 capture and storage. Oxygen combustion combined with flue gas recycle increases the CO2 concentration of the off-gases from around 15% for pf up to a theoretical 95%. Oxy-combustion is likely to give increased fuel flexibility (same as current pf), but it lacks the polygeneration options of the gasification.

Direct fired coal combined cycle (DFC-CC) – removing almost all ash and alkalis, together with approximately 50% of the sulphur produces a fuel which (when finely milled) enables direct firing of coal into high efficiency combined cycle plants (cf NGCC plants). Although there have been several coal treatment processes over the last 20 years, the present study is mostly applicable to White Industries UCC product.

IGCC is generally regarded as a sequestration ready technology (ie IGCC-CCS), as chemical plants to convert coal to hydrogen (involves CO2 removal from the syngas intermediate) are well proven. The new aspect of this technology is the need to produce hydrogen at significantly lower costs. This will need new technology and new technology combinations, and to optimise the level of CO2 capture. Though high purity hydrogen is required for chemical production, and for potential electricity production using solid oxide fuel cells, the purity of hydrogen for use in combined cycle gas turbines is far less stringent.

Hydrogen production from coal gasification has been widely proposed to provide a fuel for combined cycle electricity generation and/or chemicals and liquid hydrocarbon production. Electricity generation would use either hydrogen-fired gas turbines or hydrogen-fuel solid oxide fuel cells (SOFC). Note, the latter has very stringent specification, especially for sulphur and heavy metals (eg maximum sulphur content 0.1ppm). In this report hydrogen production is considered up to fuel production only.

For some of the technologies, integrated CO2 capture and compression has been included. Whilst CO2 capture (from combustion or gasifier syngas) with liquefaction and storage is proven for enhanced oil recovery operations, it has not been proven for electricity generation installations. It is therefore regarded as a new technology for the purpose of this report.

Renewables have not been evaluated on a technology basis in the present study, although wind (the most economic renewables option) has been included for the purpose of comparison in the power generation projections.

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3.1 Supercritical and Ultra-supercritical pf fired boilers

Conventional pulverised fuel (pf) power generation is the dominant electricity generation technology in Australia. The technology involves burning finely milled coal in boilers to generate steam that drives turbo-alternators.

Units up to 1200 MW have been constructed, though in Australia most have unit capacities of 400-600 MW. A pf power station typically contains 2-6 turbo-alternators, each with its own boiler and coal milling equipment. In general, the large capacity and the long start-up cycles mean these stations are most suited to base load, rather than peak-load or load following duties. This avoids maintaining hot spinning reserve, or maintaining low fire on oil or natural gas. Recent developments in SC and USC plants have greatly improving load following ability; ie have increased flexibility.

All pf power stations have flue gas particulate control by electrostatic precipitators or fabric filters, the latter being the choice for new power stations. Further pollution control technologies can be added to reduce NOx and SOx emissions to comply with local regulations, and whilst not employed in Australia, these controls are the norm in most overseas countries:

SOx emissions are determined by the sulfur in the coal (low for Australian coals), and to a lesser extent by the basicity and morphology of the fly ash - basic ashes (ie those comprising predominantly CaO and MgO) tend to dry scrub some SOx from the furnace gases. To meet SOx regulations, many pf stations in other countries are equipped with flue gas desulfurisation equipment (FGD). FGD is used extensively in Austria, Denmark, Germany, Japan, Netherlands, Sweden, UK and USA. Australian coals used for power generation are generally low in sulfur, and coal based power plants in Australia are not equipped with FGD.

NOx emission regulations in heavily populated first world countries had been introduced over time with power stations utilising expensive post combustion NOx reduction methods. The modern trend is to use special burner technology for NOx control (ie low NOx burners). There are no Australian power plants fitted with post combustion NOx removal systems. All facilities rely on combustion control to limit NOx emissions.

Being the dominant generation technology, pf technology has been the subject of on-going incremental improvements (for the last 60 years), and it now has a number of categories, which relate to differences in steam conditions (and therefore the overall efficiency):

Sub-critical – boiler steam pressure below 23.1 MPa (most operate with 16-18 MPa, and a superheat of 520-540°C).

Supercritical – boiler steam pressure is greater than 23.1 MPa.

Ultra-supercritical – supercritical steam pressures, and with a higher steam temperature of >566°C[11] (most project plants will use 35-40 MPa and 700°C).

Most power stations currently operating in Australia are based on sub-critical steam conditions with drum boilers (steam pressure in the range 16-18 MPa and steam temperatures of 520-540°C). The current trend is towards increasing both pressure and temperature, and re-engineering of the technology to decrease capital costs and to reduce the impact of including increased emissions controls. Re-engineering is being applied to the entire plant, together with changes necessary to enable operation at higher temperatures and pressures. Supercritical (SC) is now the benchmark for the technology, with ultrasupercritical (USC) being the subject of on-going development.

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The major barrier to supercritical in the past, and to current incremental development of ultrasupercritical steam cycles, has been metallurgical and control issues. The development of new steels for the water and steam boiler tubes now have sufficient longevity, and on-going developments in high alloy steels (both ferritic and austenitic) to minimise corrosion and high temperature creep, are expected to result in an dramatic increase in the number of supercritical plants installed over the last few years. In addition, new control equipment and strategies allow these plants to be far more flexible than when first introduced in the late 1950s.

Current supercritical power plants usually operate with steam pressures of 24-26 MPa and at temperatures of 540-560°C, while ultrasupercritical plants are being designed to operate with steam pressures of 26 – 35 MPa and temperatures of 566 - 630°C. Examples of advanced pf SC and USC plants are shown in Table 3.1.[12]

Table 3.1 Advanced PF Power Plants in Construction or Projects in Europe and Japan.

Project / Plant Output (MW)

Steam conditions Efficiency (%, HHV)

Commissioned

Denmark

Skaerbek 3/Nordjylland 1 (ELSAM) 400 29 MPa /582/580/580°C 47 – 49 1997/1998

Avedore 2 (ELKRAFT) 400 30 MPa /580/600°C 48 2000

USC 2005 (ELSAM) N/A 33 MPa /610/630/630°C 51 2005

Germany

Bexbach II 750 25 MPa /575/595°C 46 planned

Schwarze Pumpe A/B 800,900 25 MPa /580/600°C N/A planned

Frimmesdorf 950 25 MPa /580/600°C 45 planned

Lübeck 400 27.5 MPa /580/600°C 46 planned

Hässler 700 27 MPa /580/600°C 45 planned

Franken II 600 27 MPa /570/590°C 46 planned

Schkopau A/B 450 28.5 MPa /545/560C 40 1995-96

Boxberg Q/R 818 26.8 MPa /545/583°C 41.7 1999-00

Lippendorf R/S 900 26.8 MPa /554/583°C 42.3% 1999-00

AD700 EU project 37.5 MPa /700/720°C 55 aim by 2010

Japan

Kawagoe 1&2 700 31.9 MPa /571/569/569°C N/A 1989-90

Hekinan 3 700 25.5 MPa /543/593°C N/A 1993

Nanao-ohta 500 24.6 MPa /566/593°C N/A 1994

Noshiro 3 600 24.6 MPa /566/593°C N/A 1994

Haranomachi 1000 24.6 MPa /566/593°C N/A 1997

Matsuura 2 1000 25.5 MPa /598/593°C 41% 1997

To place developments in pf technology in context, Figure 3.1 above shows overall thermal efficiency for pf plants with time. This data has been adapted from European sea cooling to allow for warmer Australian conditions (which significantly decreases the efficiency of the steam cycle). It shows that Australian plants are generally more conservative in performance

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than those from overseas – ie have lagged overseas developments to improve efficiency, when compared on a common basis of HHV, with warmer condenser temperatures, and no auxiliary SOx or NOx equipment (assumes NOx levels are met by combustion controls).

30

35

40

45

50

55

1950 1960 1970 1980 1990 2000 2010 2020

Bayswater

Tarong North

Elsam plants HHV basis, cooling towers

Line of steel

Line of superalloysO

vera

ll th

erm

al e

ffici

ency

(%)

Year of startup

30

35

40

45

50

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1950 1960 1970 1980 1990 2000 2010 2020

Bayswater

Tarong North

Elsam plants HHV basis, cooling towers

Line of steel

Line of superalloysO

vera

ll th

erm

al e

ffici

ency

(%)

Year of startup Figure 3.1 Changes in efficiency of pf plants since 1952, normalised to

Australian conditions (from European data and projections).

A simplified process flow diagram for ultrasupercritical pf generation is shown in Figure 3.2.

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3.2 Oxygen USC with CO2 capture and compression

Oxygen USC power generation is a hypothetical technology reconfiguration of USC.

It involves replacing combustion air with a mixture of (cold or only slightly preheated) oxygen and recycled flue gas. The amount of recycled flue gas is set to maintain a slightly higher concentration of O2 to the burners (25-35% O2) than for air. The remaining flue gas is passed to a CO2 liquefaction plant. Note, the higher O2 concentration is required to maintain similar flame temperatures to those for conventional pf, as the presence of high concentrations of CO2 significantly reduces flame temperatures (due to the higher specific heat of CO2 compared to N2).

As the flue gas is predominantly (around 95%) CO2, capture is not required. CO2 is prepared for storage by a combination of compression and liquefaction, which includes separation of water and other non-condensable gases using a gas-liquid separator. A possible processing sequence is as follows:

Particulates removal by an electrostatic precipitator prior to compression.

Cooling to about 20°C, combined with most flue gas water being removed by condensation, and residual particulates.

The pressure of gas is then raised to 3 MPa, with intercooling to 20°C. At this stage all the remaining moisture is removed from the gas using a tri-ethylene glycol absorber. It is important to remove the moisture from the gas to inhibit corrosion and the formation of hydrate precipitates. These precipitates can cause blockages in the pipeline, valves and other equipment. Note, that this applies to all capture and storage options, regardless of the coal utilisation technology used.

The dried gas is then compressed to 5.8 MPa and cooled to around -15°C, at which point the CO2 (and SO2) condense. This allows separation from the residual (5-7%) non-condensable gases N2, O2 and Ar using as gas-liquid separator.

The pressure of the liquid CO2 (and small amounts of SO2) is then raised to 10 MPa at 20°C by a pump. At this pressure, the CO2 can be transported by pipeline for injection into the storage areas. Note, the SO2 has similar transport properties to CO2, and is likely to have lower associated risks than for the H2S-CO2 mixtures commonly involved in acid gas storage.

A simplified process flow diagram for ultrasupercritical pf generation with integrated SO2/CO2 capture is shown in Figure 3.3.

From a practical view, O2-USC process (whilst it has not been demonstrated) uses mostly proven technology units and is not generally regarded as a new technology (IHI, 2003)[13].

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3.3 Natural gas combined cycle

Combined cycle plants integrate a gas turbine generator with a steam cycle to utilise most of the waste heat from the gas turbine exhaust. The technology can achieve an overall thermal efficiency of ~53% (HHV).

Hot exhaust gases (typically ~650°C) from a gas turbine are then used to raise steam in a heat recovery steam generator (HRSG), which drives a steam turbogenerator. Note, the steam cycle is subcritical - supercritical cycles are unlikely due to the low turbine gas off gas temperatures and relatively small capacity of the steam plant (400 MW is regarded as the smallest efficient size for supercritical units, by this could be attained by linking dual gas turbines to a single steam unit). Generally 55% of total power is generated from the gas turbine, and 45% from the steam cycle.

Although mostly used for supplying peaking demand, they are now also an economic option for base load electricity generation in regions with relatively low gas prices. Over the last 20 years there have been major improvements to gas turbines, in a number of areas of the technology which have resulted increased size and efficiency, reduced capital costs, and significantly reduced NOx emissions.

Current developments to increase thermal efficiency include the use of ceramic blades for the inlet stator to allow higher turbine inlet temperatures. Turbine blades are normally manufactured made from exotic high temperature alloys; however, impurities in the fuel (even at extremely low levels) can still cause corrosion of the blades. Various coatings for turbine blades have been developed to avoid this high temperature corrosion. Contaminants are therefore a significant concern for gas turbines used in IGCC applications, necessitating stringent syngas cleaning/scrubbing.

As natural gas contains only trace levels of sulfur, SOx emissions are very low. However, NO and NO2 emissions from gas turbines are a greater problem, which requires control technologies - pre-mix/ hybrid burners, water/steam injection, selective catalytic reduction.

The GE H-Class gas turbine gives a step improvement in efficiency, and includes a 23:1 pressure ratio, firing temperature of 1430°C (110°C higher than current F-class machines), and steam cooling of the high-pressure Stage 1 nozzles rather than air-cooling. These changes give a 480 MW machines with an overall sent out efficiency of 54.4%, around 3% higher than the current F-class.

A generic process flow diagram for NGCC generation is shown in Figure 3.4.

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3.4 Integrated gasification combined cycle

Integrated gasification combined cycle (IGCC) is a combined cycle gas turbine which uses fuel gas (called syngas) produced from a separate, but integrated process for the gasification of coal. The degree of integration can vary significantly, particularly with respect to the coupling between the turbine generators and the oxygen plant or in the provision of compressed air in the case of air blown IGCC.

IGCC was developed to enable low cost coal and other solid fuels to be used in low cost and higher efficiency gas turbines.

The process comprises 3 main stages – gasification, gas treatment, and a combined cycle gas turbine.

The gasification process transforms the organic matter in coal or biomass into a gaseous fuel by reaction with steam, air and/or oxygen at temperatures of between 800°C and 1600°C depending on the type of gasifier. The product of gasification is a syngas containing H2, CO, CO2, CH4 and small amounts of impurities. The mineral matter of coal undergoes decomposition and transformation to form ash or slag, again depending on the type of gasifier - the two dominant types of gasifier are the fluidised bed and entrained flow slagging gasifiers.

Gas treatment can use many technology combinations, however the overall objectives are to remove sulfur compounds, ash, and usually to maximise hydrogen content by reacting CO with steam, and selective removal of CO2.

There are a number of existing and proposed IGCC plants around the world as shown in Figure 3.5 and Table 3.2.

0

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1970 1975 1980 1985 1990 1995 2000 2005

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Lünen/D

Cool Water/USA

Plaquemine/USA

Tiruchirapalli-II(BHEL)/IN

Freetown/USAWisconsin/USA

Dadri-III/N

TVA Bellefonte (Electricity + Methanol)/USA

Hürth (KoBra)/D

Taranto (AGIP)/I

Sannazzaro

Sicily

Porvoo (NESTE ÒY)/SF

Wise City (Toms Creek)/USA

Springfield (CE Project)/USA

Camden/USA

IGCC Demo/JAP

Delaware/USA

Ancona (API)/I

Puertollano/E

Rotterdam (Pemis)/NL

El Dorado/USA

Daggett (Air Products LPMEOH)/USA

Buggenum/NL

Tiruchirapalli-II(BHEL)/IN

Terre haute (Wabash River)/USA

Morwell (IDGCC Demo)/AUS

Polk County (Tampa Electric)/USA

Reno (Piñon Pine)/USA

Sardinia

TVA Bellefonte (Electricity + Methanol)/USA

Iowa/USA

Figure 3.5 Existing and planned IGCC plants and sizes (MW).

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Table 3.2 Existing and planned IGCC plant details (Korens et al).

Plant Owner Country Commiss. Year

Feedstock Gasifier type Acid gas removal process

SCE Cool Water United States 1984 bituminous coal

Texaco Selexol

LTGI United States 1987 sub-bituminous

coal

E-GAS MDEA

NUON Netherlands 1994 coal Shell Sulfinol-M

Global Energy Inc. United States 1995 coal, pet coke

E-GAS MDEAa

Frontier Oil and Refining Co. (Texaco Inc.)

United States 1996 pet coke Texaco MDEA

Tampa Electric Co. United States 1996 bituminous coal

Texaco MDEAa

Schwarze Pump Germany 1996 municipal waste

GSP/Noell Rectisol

Sokolovska Uhelna, A.S. Czech Republic

1996 coal Lurgi dry ash Rectisol

Elcogas SA Spain 1997 coal & pet coke

PRENFLO MDEAa

Shell Nederland Raffinaderij BV

Netherlands 1997 visbreaker residue

Shell Rectisol

Sierra Pacific Power Co. United States 1998 coal KRW Limestone /ZnOb

ISAB Energy Italy 2000 heavy oil Texaco MDEAa

Motiva Delaware Refinery United States 2000 pet coke Texaco MDEA

api Energia S.p.A Italy 2001 visbreaker residue

Texaco Selexola

SARLUX srl Italy 2001 visbreaker residue

Texaco Selexola

ExxonMobil Singapore 2001 residual oil Texaco FLEXSORBc

Shin Nihon Sekiya (Nippon Pet. Ref. Co.)

Japan 2004 vacuum residue

Texaco ADIPa

AgipPetroli/EniPower Italy 2004d visbreaker residue

Shell Aminea

PIEMSA Spain 2006d visbreaker tar

Texaco MDEAa

a COS hydrolysis precedes the acid gas removal process at this plant. b Commissioning of this demonstration project was unsuccessful and the project was terminated. Consequently, both the KRW gasification process and the limestone/ZnO hot gas cleanup process remain unproven. c Version not disclosed – indicated only as “generic FLEXSORB”. d In planning/engineering/development.

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In a fluidised bed gasification system, crushed coal (1-5 mm) is fed into a fluidised bed consisting of inert material such as sand. Oxygen (or air) and steam are passed through the bed as fluidising gases, and a small amount of these gases is injected above the bed to increase the temperatures and to help gasify any elutriated material. The gas exit temperature is around 1,000°C at a pressure of 1-2.5 MPa. Ash is removed by extracting bed material from the bottom of the gasifier, then separating the coarser sand fraction using hot gas cyclones that is then recycled back to the bed.

In an entrained flow gasifier, the pulverised coal (0.1 mm) is introduced into the gasifier via burner nozzles, and gasification occurs as the fuel flows through the gasifier (1-5 seconds), mostly in suspension. This type of gasifier operates at a temperature higher than the ash melting point, which enables molten ash (slag) to flow out of the gasifier. The resulting gas has negligible tar, oil and phenol content, and has a relatively high H2:CO ratio. The gas exit temperature is around 1,500°C at a pressure of 2.5-4 MPa.

Before combustion in the gas turbine, the gas is cooled and scrubbed to remove H2S and particulates. Alternatives include hot gas scrubbing and filtration. In special cases, filtration is eliminated completely and a ruggedised gas turbine has been used. These turbines can tolerate dirty fuel gas, but operates at a significantly lower efficiency.

Although the technology has many variants, in this study the Texaco Process has been used as the benchmark gasification technology - in this case, an oxygen blown, slurry feed system with a down fired gasifier. This process is in commercial operation at a Tampa Electric power plant, Florida. The Tampa plant has a Claus process for removing sulphur from the syngas (as a saleable sulfur), and uses the cleaned syngas in conventional combined cycle gas turbines.

An example of a process flow diagram for IGCC generation is shown in Figure 3.6.

3.5 IGCC with CO2 capture and compression

IGCC is the most ‘sequestration ready’ of the current and new future technologies (the latter includes IGSOFC), because of 2 factors:

The need to remove impurities from the syngas before the gas turbine means that similar technologies as those required to remove CO2 are already being used – albeit at a much smaller scale than for CO2 removal for power generation.

The syngas is at pressure, around 20-30 MPa, which improves the practicality of CO2 removal by allowing pressure-swing techniques to be used, and by reducing by up to ~20% the energy required for CO2 compression/liquefaction.

There are a large number of technology combinations available to achieve CO2 capture, although MEA is presently the most common, which has been used as the base case in the present study. Other combinations are described in Section 3.8.1 on page 53.

MEA absorption is most effective at a gas temperature of around 40°C, and after sulphur removal – this involves COS hydrolysis followed by H2S removal. The main inefficiencies in this system are the need to cool the gas to allow H2S removal, followed by reheating for the shift reaction, then cooling to allow CO2 absorption. Another energy loss occurs through the need to repeatedly reheat large flows of MEA solution to ~170°C to boil off the CO2, and then cool the same solution to 40°C to allow adsorption. Some of these cyclic heating and cooling

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stages can be achieved by optimising heat exchanger networks, but at increased equipment cost. A generic process flow diagram for IGCC with MEA capture is shown in Figure 3.7.

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3.6 Underground coal gasification and combined cycle gas turbine

In this approach, coal is gasified underground (ie in situ) and the gases are piped to the surface and treated for use in gas turbines or for other purposes. The technology is receiving increased attention worldwide as it avoids the need for mining and the disposal of solid wastes (both coal washery refuse and fly ash), is applicable to deep/uneconomic seams, and allows the use of lower cost/more efficient gas turbine power plants.

Underground coal gasification (UCG) with CCGT has some similarities with IGCC (integrated gasification combined cycle) with the major difference being in the gasification process. Where IGCC produces coal fuel gas by gasification of mined and treated coal in a gasification equipment above ground, underground gasification requires performing the heating and oxidation process in situ, using boreholes drilled into and along the coal seams to allow injection of heating and oxidising gases (oxygen, air, steam, or a mixture of these gases). The gas system is pressurised to control water ingress (and also to enhance production rates). The raw product gas is piped to the surface and after treatment to remove contaminants/diluents (ash, most water vapour, H2S) can be used as fuel gas for heating or power production (cleanup is essential for use in gas turbines, but could be eliminated for conventional boilers). With further treatment (removal of CO2, or shifting CO to H2) the gas can be used as a synthesis gas for the chemicals industry as is for conventional coal gasification. The composition and energy value of the gas produced can be controlled (but not to the same extent as for conventional gasification) by adjusting process parameters such as pressure or the quantity and composition of oxidation gas used and the combination of bores in production.

The power plant of an UCG-CCGT and IGCC system are mostly the same – although there may be small differences, especially due to integration of the power island with oxygen production. With UGCC, the power plant and injection well may be separated by several kilometres, and together much slower response of the underground production wells will require a non-integrated oxygen plant (ie powered from other sources). Note, this dis-integration is also widely favoured for ‘IGCC’ plants, as the gasification process can be separated from the operation of the power block, which increases operational flexibility and improves availability; albeit with the trade-of – lower overall efficiency (~1%).

Despite the obvious advantages of UCG, commercialisation of the technology in USA, Europe and other Western countries has proved difficult. Problems are:

− The natural permeability of the coal seam to transmit the gases to and from the oxidation zone can be unreliable.

− Gasification over long coal seams will probably require the construction of an in-seam channel prior to gasification (ie before a cavity can be developed)

− In the past, there have been problems with directional underground drilling, but these have been overcome due to developments in the oil and gas industry, and similar technology is now being used regularly for the de-gassing of coal seams in Australia, South Africa and the United States.

− Environmental constraints, eg extensive cleanup operations still underway in the USA following closure of demonstration UCG fields.

However, technologies have been used to commercially produce reliable syngas for over 60 years in Russia and former Soviet countries such as Uzbekistan. Trials of the UCG process have recently conducted in Australia (using derivatives of the technology used in Russia) by

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Linc Energy and lasted over two and a half years at Chinchilla (Queensland, Australia). These technology developments include establishing wells in deeper coal seams, which have advantages in control, power output, and a range of environmental benefits (eg better quality gas leads to increased generating efficiency, lower GGE, NOx, SOx and water consumption).

An example of a process flow diagram for UCGCC generation is shown in Figure 3.8.

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3.7 Direct fired coal combined cycle gas turbine

Direct firing of coal in turbines and previously other types of internal combustion engines (both conventional and with external combustion chambers) has been an on going challenge for over a century, and has proven impractical without using ultra clean coal.

DFC must be chemically and mechanically treated to remove mineral matter, and some of the organically bound alkalis and sulfur. This enables the coal to be combusted in higher efficiency turbines without significant issues with turbine blade erosion and damage from high temperature corrosion.

These ultra clean coals are a high value product, and are at present not considered a substitute for conventional coal in SC or USC power generating systems; the major application is where conventional coal cannot be used - an alternative for heavy fuel oil and gas in turbines. Producing such fuels is of particular importance to developing countries with indigenous coal supplies, but limited in other energy resources, countries dependent on energy imports (UCC) as it is readily stored (and therefore highly suitable for distributed power generation).

The two most prominent technologies are CENFUEL and White Industries UCC. Both technologies (which differ widely their approach) have been developed over the last 20 years, and have been proven technically feasible at the pilot scale. As claims by CENFUEL have received unfavourable comment by a wide range of technologists, the present study is based mostly on data obtained from White Industries UCC:

The UCC project a joint venture between the CSIRO Energy Technology division and White Mining’s subsidiary UCC Energy. A pilot plant presently operates at Cessnock in the Hunter Valley. Trial product has been sent to Mitsubishi Heavy Industries and Idemitsu Kosan for combustion tests.

The UCC process has a series of chemical leaching processes to achieve high levels of purity. Minerals are converted to soluble forms in a high temperature alkali leaching process, and then the converted clays are then dissolved in an acid washing process. Finally, a hydrothermal process reduces the ash level to between 0.1% and 0.2%, and also results in low alkalis. Dissolved minerals are precipitated as gypsum/aluminium silicates, which may have commercial value in the building and ceramics industries, while the alkalis are regenerated for re-use. The UCC process is suited to most black coals. Fine milling is not required prior to treatment. CSIRO estimates indicate that the production of UCC increases the overall GGE by approximately 10%(14).

This clean coal can be fired directly into gas turbines, which will give higher efficiency power generation than from SC or USC pf. To allow direct firing, the coal must contain extremely low levels of alkalis sodium and potassium, as these elements lead to blade fouling and corrosion, and seriously reduce efficiency and longevity. As blade erosion from unburnt char or fly ash is also an issue, the coal must be ground (micronised) to below 10µm in size – in practice, this is done immediately prior to combustion to allow the easier transportation of the granular UCC (250-1000 µm).

UCC is aimed at being cost competitive with LNG, most natural gases, and is a potentially a substitute for heavy fuel-oil when slurried with oil/water (a possible fuel for large diesel engines), and an alternative to petroleum coke for anode production in the aluminium industry. In combustion applications particulate control will probably not be required.

A generic process flow diagram for UCGCC generation is shown in Figure 3.9.

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3.8 Acid gas removal processes

There are several combinations of technology for removing CO2 and other acid gases[15,16]:

Solvent-type capture of CO2 from flue gases or synthesis gases by selective absorption.

Solid absorbents.

Membranes, most of which aim to selectively separate the hydrogen rather than CO2.

Oxygen combustion with flue gas recycle with liquefaction of the flue gas. Separation is confined to removing moisture and gas-liquid separation to remove the non-condensed gases (mostly argon). The liquefied flue gas CO2-SO2 is pumped to higher pressures for pipelining and storage.

All approaches involve complex trade-offs with equipment costs, power or energy losses, or technical risk, and most are restricted to treating flue gases or syngases with high concentrations of CO2. It is generally accepted that treating conventional flue gases is uneconomic, though research continues, mostly with the objective of providing retrofit technologies. Table 3.3 shows typical CO2 compositions.

Table 3.3 Typical CO2 compositions of flue and synthesis gases

Vol. % (wet basis)

Pf combustion (conventional, SC, USC) 15-17

IGCC – syngas (before shift) 15-20

IGCC – syngas (after shift) 35-50

NGCC – gas turbine off gases 4-7

Oxygen fired pf (O2-SC or O2-USC) 85-95

Direct fired coal CC (DFC-CC) 8-12

In IGCC, the CO2 concentration is increased by passing the syngas through a shift reactor to convert CO to CO2 and H2:

CO + H2O CO2 + H2

The shift reaction may take place before removal of sulfur compounds (sour shift) or after removal of sulfur compounds (sweet shift).

3.8.1 Solvent based capture

Solvent-based CO2 capture processes have been used for many years, mostly for processing natural gas to remove H2S and CO2. The processes can be divided into three generic types:

Chemical - the principal chemical solvents for synthesis gas treatment are amines. These include primary amines, usually monoethanolamine (MEA), secondary amines, usually diethanol amine (DEA) and tertiary amines, usually methyl diethanol amine (MDEA).

Physical - popular physical solvents are methanol and dimethyl ether of polyethylene glycol as used in the Rectisol and Selexol processes, respectively.

Mixed chemical/physical - mixed chemical/physical processes usually consist of mixtures of amines and a physical solvent, such as in the Sulfinol process which uses a mixture

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of sulfolane (tetrahydrothiophene dioxide) and an aqueous solution of amine, either diisopropanol amine or MDEA.

Chemical processes

In the amine based processes, flue or synthesis gas must be cooled to ~40°C and then scrubbed (contacted) with an aqueous solution of the amine in an absorber (see Figure 3.10). The CO2 is preferentially absorbed. The amine mixture, rich in CO2 is then passed to a stripper where the temperature of the solution is raised to release the CO2. The lean amine solution is then returned to the absorber (minus small losses due to entrainment and the formation of insoluble salts). Heat energy is generally provided as low-pressure steam, which in power generating plants would be drawn from the low-pressure turbines – but still results in a substantial reduction in net power output.

Primary amines form the most stable bond with CO2, followed by secondary, then tertiary amines. MDEA has become the most popular of the amines in the natural gas industry, due to its high selectivity of H2S over CO2, its stability against degradation and it being the least corrosive of the amines. MEA and DEA are both susceptible to degradation by COS and problems with corrosion – MEA being more affected in both respects.

Figure 3.10 Generic amine absorption of CO2 from flue gases.

Physical processes

Physical solvents currently used for CO2 removal are Selexol and Rectisol. These physical solvents have benefits over chemical solvents, which include:

High gas loadings - at high gas partial pressures (the higher the pressure the higher the acid gas loading in the solvent).

Solvent stability – solvents are not destroyed as easily as chemical solvents.

Low heat requirements –most of the solvent can be regenerated simply by decreasing pressure.

Non-corrosive to metals.

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In the Selexol process a mixture of dimethyl ethers and polyethylene glycol is used to physically absorb CO2 in a pressurised absorber, then regenerated via a simple pressure letdown, though deep stripping of the solution required the use of steam. The chemical mixture used in the Selexol process is chemically and thermally stable and has a low vapour pressure that limits it losses to the treated gas. It has a high solubility for CO2, H2S and COS, with a preference for H2S over CO2.

The Selexol process can be configured in a number of ways, depending on the specific requirements of the plant. These include H2S/CO2 selectivity, need for CO2 removal, and whether the gas needs to be dehydrated.

The Rectisol process is the most widely used physical solvent gas treatment process in the World, with more than a hundred units in operation or under construction.

The Rectisol process uses chilled methanol at a temperature of –40 to –62°C. The chilled methanol is contacted with flue/synthesis gas where H2S and CO2 are selectively absorbed (selectivity of H2S to CO2 approximately 6:1). The absorbed gases are stripped from the methanol via pressure reduction, though deep stripping requires the use of steam. The methanol must then be cooled and refrigerated before being returned to the absorber. The process can be configured in a number of stages to remove H2S and CO2 separately, depending on the process requirements.

Mixed chemical/physical solvents

There are a number of processes that use a mixture of chemical and physical solvents, with the aim of extracting the most desirable characteristics of both types. The most common of the mixed solvent processes are Sulfinol and FLEXSORB and are primarily used where there is a compromise between H2S selectivity and the degree of the physical solubilities of other sulfur compounds.

Process options for solvent based capture

There are a number of options for solvent based capture processes from a gasification plant, depending on whether H2S and CO2 can be sequestered together, whether a CO-shift is used, whether the CO-shift is before or after H2S removal or whether separate sulfur recovery is required. Four options for CO2 removal are shown in Figure 3.11.

Option 1 gives only partial removal of CO2 (say less than 30%), but avoids CO-shift, thus reducing capital investment. H2S removal in a separate absorber, usually MDEA based, may be required before the CO2 stripping step. In the present study, Option 1 has been modelled with H2S removed in a MDEA absorber followed by CO2 removed via a MEA absorber at a recovery rate of approximately 25% of the CO2 present.

Option 2 assumes that storage of both CO2 and H2S is acceptable practice. A sour CO-shift reaction is used before the CO2 absorber. The absorber employed may be either a physical or chemical based process to separate the CO2 from the synthesis gas.

Option 3 shows sour shift with separate H2S and CO2 removal. The processes for CO2 removal may be a combination of chemical or physical. In the present study, a sour shift similar to Option 3 is modelled with H2S removal via MDEA and separate CO2 removal via an MEA absorber with a CO2 recovery rate of approximately 75% of the CO2 present.

In Option 4, involves H2S removal before a sweet shift and CO2 removal.

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Figure 3.11 Options for acid gas removal from synthesis gas.

The following table gives a summary comparison of chemical based acid gas removal processes.

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Table 3.4 Comparison of acid gas removal technologies.

Absorbent Acid gas pickup mol/mol amine (normal range)a

Reboiler duty kJ/L lean solutionb

Heats of reaction kJ/kg CO2

Heats of reactionkJ/kg H2S

MEA 0.33-0.4 280-335 1445-1630 1280-1560

DEA 0.35-0.65 245-280 1350-1515 1160-1400

MDEA 0.2-0.55 220-335 1325-1390 1040-1210

Selexol NA NA 372c 442c

Sulfinol NA 100-210 Varies with loading

Rectisol NA NA NA

FLEXSORB NA NA NA

3.8.2 Solid absorbents

There are a number solid absorbent processes that are being investigated including:

EniTecnologie Process that uses non-volatile amines on alumina to absorb CO2. Regeneration of the sorbent requires heating to 100°C under a vacuum.

RTI Process that uses sodium carbonate as a sorbent for CO2 capture. The reaction is reversible at around 200°C.

Toshiba Process, which uses lithium orthosilicate to absorb CO2 in a reaction that can be reversed at between 450-650°C.

The advantages of solid absorbents is that they offer the possibility of avoiding the sensible and latent heat losses that are associated with liquid solvent based processes.

3.8.3 Membranes

Research is being carried out in the area of membrane separation of hydrogen from synthesis gases – rather than trying to remove sulphur compounds and CO2 from syngas. Of particular interest to the USDOEs National Energy Technology Laboratories (NETL) are robust hydrogen separation membranes that are suitable for the rapid, selective removal of hydrogen from high-temperature, high-pressure gas streams, while remaining resistant to chemical impurities such as sulfur[17]. The NETL program is conducting research into fabrication and characterisation of novel membranes, testing of membranes, membrane reactors, membrane modelling and sorbent-based membrane methods.

A key driver to the development of membrane technology is the possibility of obtaining substantial energy savings in industrial separation processes and also the combination of reaction and separation in a single system.

a Dependant upon acid gas partial pressures and corrosiveness of solution. Might be only 60% or less of value shown for corrosive systems. b Varies with stripper overhead flux ratios, rich solution feed temperature to stripper and reboiler temperature. c At 25°C

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3.8.4 Flue gas recycle with liquefaction

This approach must be integrated with oxygen combustion, with flue gas recirculation being required to control combustion temperatures. In this approach, the CO2 content of the flue gas can exceed 85%, and is suitable for direct liquefaction for storage. This is achieved by a combination of compression to 5.8 MPa with several stages of intercooling. Residual gases (mostly nitrogen and argon) are removed from the liquid (CO2 with a small proportion of liquid SO2) before pumping to the required pipeline pressure of ~10 MPa.

Figure 3.12 shows a schematic of the process. The clean flue gas is cooled to around 20°C, which allows most of the moisture to be removed. The gas is then compressed to around 3 MPa with inter-cooling. After this residual moisture is stripped by gas scrubbing with triethylene glycol. This reduces moisture down to ppm levels (to reduce the formation of corrosive compounds and clogging of equipment from hydrates) – a process step required for all capture methods. The gas is further compressed to 5.8 MPa and cooled to around -15°C. At this point remaining gases are removed from the liquid CO2 by separator.

Many of the unit operations for flue gas liquefaction are common to both capture from flue gases and capture from synthesis gas; ie once the CO2 is captured from these approaches, it must also be liquefied. Note, there may be some differences in the first stages of compression, as some approaches (eg those with pressure swing absorption) to capture from syngas can produce the CO2 stream at elevated pressure.

Figure 3.12 CO2 liquefaction by multistage compression and cooling.

An alternative CO2 liquefaction process is shown in Figure 3.13, which is based on refrigeration rather than compression, with the inclusion of a methanol reflux condensing heat exchanger for moisture polishing.

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Figure 3.13 CO2 liquefaction by multistage compression and refrigeration, incorporating gas

industry standard methanol polishing reflux condenser.

3.9 Other considerations

3.9.1 The sulfur issue

In the case of the sour shift the gas can be shifted before it is cooled for CO2 capture, which reduces energy consumption, however the presence of H2S can poison any catalysts used in the reaction and results in a CO2-H2S mixture for storage, which results in other risks. With sweet shift, the H2S and other sulfur compounds are removed and converted into saleable sulfur/sulfuric acid – provided markets exist. Sulfur and sulfuric acid are important to the fertiliser industry, mineral processing and many other industries.

Unlike some mineral commodities, there is no concern that supplies of sulfur will decrease. The concern will be what to do with the increasing quantities of sulfur produced as a result of regulations and new technologies limiting and eliminating sulfur emissions from all types of industries. In Australia the production of sulfur increased from 496,000 t in 1997 to 750,000 t in 2002[18] mainly due to increases SO2 capture from metallurgical operations and production is expected to rise into the near future. With reductions in demand for locally manufactured superphosphate fertiliser, production of sulfuric acid has fallen to about half the level of 1980[19], but Australia still imports considerable amounts of sulfur with 462,400 t in 2001 and 634,100 t in 2002 imported from Canada[20].

For fertilizers, sulfur as the main raw material which is converted to sulfuric acid and reacted with phosphate rock to produce phosphate fertilisers. Sulfur is an important plant nutrient. Historically, sulfur has been applied with fertilisers containing other nutrients, such as ammonium sulfate, single superphosphate (SSP), or sulfate of potash.

Sulfur has other uses, especially for minerals extraction, with demand from these uses predicted to expand in the future – mostly due to changes in the type of minerals being processed.

Acid pressure leaching of nickel laterite ores is becoming one of the fastest-growing markets for sulfur. Nickel is produced from either sulfides or laterites. Approximately 65% of the world's known nickel resources are in the form of nickel-bearing laterites, while the balance

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occurs in the better-known sulfides such as those being mined in Canada. The cost of mining nickel laterite ores, normally in open pit situations, is relatively inexpensive compared to underground mining typical for sulfide nickel ores, which is highly labor-intensive. Laterite nickel ore enjoys a major advantage in the combination of low mining costs with relatively high value content. These two factors provide a strong incentive to find economic means of extracting nickel from laterites. Since the process also consumes a considerable amount of energy, installation of sulfur burners is providing by-product energy and reducing costs.

New nickel ore mining projects are coming on stream in Australia and are projected to significantly boost sulfur consumption over the next five years. This sector of the sulfur industry is forecast to become the second largest in the world after phosphate fertilisers, expanding at an expected annual growth rate of 10% over the next decade. Sulfur consumption for ore leaching could more than double during the next decade to exceed 4 million tonnes sulfur per year worldwide, with Australia consuming a substantial portion[21].

New phosphate projects will have an impact on phosphate production, consumption, and trade patterns. In Australia processed phosphates at Phosphate Hill, Queensland will be based on domestic raw materials. Phosphate rock will come from the large Duchess deposits, close to the phosphate complex and sulfuric acid will be recovered from smelter gas from the adjacent Mount Isa Mines copper smelter and from the Korea Zinc project at Townsville.

Although the new phosphate fertiliser plant projects in Australia are in addition to the nickel acid pressure leaching process, unless phosphate consumption increases substantially, these projects may not result in a significant net increase in sulfur consumption. However, they will impact trade patterns for suppliers to Australia, though Australia are still likely to be dependant on sulfur imports into the near future.

Sulfur production from IGCC

As IGCC could produce large quantities of sulfur, an estimate has been made to place this in context of the current Australian markets of sulphur and sulphuric acid: All sulfur produced via future IGCC power plants in Australia could be consumed by the local market:

Current demand for sulfur 1.5 Mtpa

Sulfur production assuming that all power is produced by IGCC

0.3 Mtpa

3.9.2 Hot flue gas cleanup

There has been considerable effort in the past to develop commercial hot gas cleanup technologies for IGCC, and especially for pressurised fluidised bed combustion - which depends entirely on effective hot gas cleanup.

For IGCC, hot gas cleanup has been a preferable feature as it increases overall efficiency by around 2%, though some of these gains are offset by higher capital costs, repairs and availability issues.

Despite much previous research and development, most current designs do not rely on hot gas cleanup, as subsequent gas processing requires that the syngas be cooled, which enables conventional particulates removal equipment to be used.

3.10 CO2 storage options

There are a number of possible options for permanent storage, and in some cases reuse of CO2:

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Storage in the ocean

ocean fertilisation

deep ocean injection

Storage in geological formations

oil and gas reservoirs

unmineable coal seams

deep saline aquifers

Sequestration through afforestation, rehabilitation and accumulation in soils

Reuse through current and advanced methods, eg for urea or methanol production, or for feeding methanogens[22].

Estimated potential capacity of each option is shown in Figure 3.14 (redrawn from DOE Fossil Energy website). The present report includes only a brief description of this subject - for further information see, for example, www.ieagreen.org.uk or www.co2crc.com.au

The present summary is also restricted to geological and ocean sequestration, as these are regarded by others to be the only practical solutions for large scale CO2 storage.

Note, in keeping with current terminology, the term sequestration is restricted to biological processes that utilise and store CO2 – ie for plant growth (forests and algae).

21.6

3601,080

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Human activity(GtCO2/yr)

Forests and soils Geological Oceans

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Figure 3.14 Potential capacity for sequestration/storage of carbon.

3.10.1 Ocean sequestration and storage

CO2 is soluble in seawater making oceans a large natural sink for CO2. Each year large amounts of CO2 are both emitted and absorbed by the oceans (around 90 GtC/y) with a net

Shaded area shows possible

range

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removal of CO2 from the ocean surface to deep water of around 2 GtC/y. It is widely believed that the oceans will eventually absorb most of the CO2 in the atmosphere. However, the kinetics of ocean uptake are very slow.

A number of options have been suggested to increase the rate at which the oceans sequester CO2; enhancing the natural sequestration process in the surface layers by ocean fertilisation, or bypassing the CO2 saturated surface layer by direct injection into deeper layers.

Sequestration by ocean fertilisation

Fertilisation of the surface layers has been suggested, in which nutrients are added to stimulate the growth of phytoplankton (net consumers of CO2), which reduces the CO2 concentration and enables more CO2 to be absorbed. The increased rate of CO2 absorption via ocean fertilisation is not known as this stage, and research is continuing. Three open ocean experiments have been undertaken, SOIREE (Southern Ocean Iron Enrichment Experiment), SOFeX and EisenEx-1 (note, the SOIREE used 8,700 kg of ferrous sulphate supplied by BHP Steel, Port Kembla).

Storage by direct Injection

Ocean storage has the potential to absorb at least 5,000 Gt of CO2 (which is equivalent around 250 years of present global production). It is essential that the CO2 is disposed of at great depth as the saturation levels and retention time of the CO2 is increased significantly with depth, and it is general estimated that an injection depth greater than 3000 m is required to achieve minimum retention times of greater than 1000 years.

This approach has many technical issues, with a number of options being considered, including injection from suspended vertical pipes from a ship or platform. Current pipe laying technology would allow injection depths to around 850 m, but this would restrict injection to selected sites that would enable the dense CO2 plume gravitate to deeper regions.

The direct injection process still requires much R&D for the optimisation of the process and to determine whether there are detrimental effects to ocean biogeomechanical cycles.

3.10.2 Geological storage

This includes storage in geologic formations such as oil and gas reservoirs, unmineable coal seams, and deep saline reservoirs.

Oil and gas reservoirs

CO2 can be stored in both depleted on non-depleted oil and gas reservoirs. In depleted reservoirs, the underground volume of recovered hydrocarbons is replaced with CO2. For maximum storage potential the CO2 must be above the supercritical pressure of 7.4 MPa, and this condition is met at depths below 800m where the majority of oil and gas reservoirs exist.

In some cases, production from an oil or natural gas reservoir can be enhanced by pumping gaseous or supercritical CO2 into the reservoir to displace and dissolve out some of the remaining hydrocarbons. This is called enhanced oil recovery (EOR). EOR has the potential to sequester carbon at low net cost, due to the revenues from recovered oil/gas. In an EOR application, the leakage of the CO2 that remains in the reservoir is well understood and acceptably low. The scope of this EOR application is currently economically limited to point sources of CO2 emissions that are near an oil or natural gas reservoir.

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An estimate of the potential storage capacity for CO2, based on proven reserves, suggest a capacity approaching 200 Gt carbon would eventually become available (70% from natural gas reservoirs). Unproven reservoirs could double the future capacity.

Unmineable coal seams

Coal beds typically contain large amounts of methane-rich gas that is adsorbed onto the surface of the coal. The current practice for recovering coal bed methane from unmineable coal seams is to depressurise the bed, usually by pumping water out of the reservoir. An alternative approach is to inject carbon dioxide gas into the bed from surface bores. Tests have shown that CO2 is preferentially adsorbed on coal (compared to methane), giving it the potential to efficiently displace methane, with the CO2 remaining stored in the coal bed (but this precludes future mining). CO2 recovery of coal bed methane has been demonstrated in limited field tests, but more work is necessary to understand and optimise the process.

One benefit is that CO2 storage by this method results in displaced methane provides a value-added revenue stream to the carbon sequestration process to offset storage costs. An additional advantage is that large amounts of unmineable coal are near many current/future coal-fired electricity-generating facilities, allowing potential to integrate displaced methane into nearby stations.

Deep saline aquifers

Aquifers represent the most widely available and probably the second largest, naturally occurring potential store for CO2 with global potential storage range of 100-3000 Gt carbon.

Aquifers are permeable rock formations. The porosity of the host rock determines permeability and the capacity of the aquifer for CO2 storage. The pores in the aquifer are usually filled with saline water (oil and gas reservoirs are essentially the same but the pores are filled with oil and gas). The permeability and porosity, together with the presence of overlying stratigraphic traps to confine the area and the presence of sealing cap-rock, determine the suitability of an aquifer for CO2 storage.

Many of Australia’s power stations are located near potential saline aquifer injection points, and are regarded as the most feasible storage option in Australia. However, most research conducted in this area has been in relation to EOR projects, however the Sleipner-North Sea and Weyburn-Saskatchewan projects have been constructed specifically to demonstrate CO2 storage.

Further research and development is needed to assure the environmental acceptability and the long-term security of this type of storage.

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4 SYSTEMS ASSESSMENT METHODOLOGY

The main objective of the present study was to make a detailed comparative assessment of different power generation options using a systems or holistic approach. While there have been other systems assessment studies, particularly using life cycle analysis, the present study has attempted to broaden the life cycle approach to include technology constraints, economics, the cost of externalities, and learning rates. These aspects have been included on a common Australian basis, and use fully reconciled data sets – ie all key assumptions have been subject to modelling or scaling to ensure consistency.

The approach has incorporated a technology process modelling, life cycle analysis (LCA), experience curves, and economic models. Figure 4.1 outlines the methodology and approach.

Figure 4.1 Systems assessment approach.

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Values sourced from literature has been used to set the process operating parameters for mass and energy balance models (technology models) for each of the technologies outlined in Table 4.1, except for UCG-CC which used information from a previous LCA study sourced from Linc Energy and HRL. Technology modelling results, such as overall thermal efficiency and greenhouse gas emissions, are used as inputs to the life cycle and economic models.

The life cycle analysis model was limited to the reporting of greenhouse gas emissions. The life cycle analysis model draws on previous work carried out by BHP Billiton including open cut coal mining, coal transportation, processing/distribution of natural gas.

Economic modelling has been carried out for each of the technologies studied. The models use a range of literature sources for base capital, operating and repairs and maintenance costs with sizing and mass and energy flows from the technology models. The main sensitivity was to fuel cost and carbon taxes.

Generation costs were projected to 2030 for each of the technologies using the economic models with factors for experience curves sourced from the literature.

These models were used to determine the effects of 5 hypothetical scenarios for future power generation in Australia based on electricity demand predictions by ABARE. These where based on a number of assumptions for phase out of existing stations, and the introduction of new capacity.

4.1 Technology modelling

Table 4.1 lists the technology and CO2 capture combinations, and base plants evaluated in this study. The key parameters for each of the combinations are shown in Table 4.2.

Overall modelling was carried out using the process simulator METSIM to perform mass and energy balances around the unit operations within the overall process flow sheets, with additional cross calculations using turbine and petrochemical process models (Taftan Data and ASPEN Plus). Though originally designed for metallurgical and chemical engineering applications, for this study METSIM developed new unit operations to allow the simulation of advanced power generation systems.

The process modelling was used improve the understanding technology constraints, to provide increased transparency for key performance attributes, and a common basis for the comparisons.

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Tabl

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Cap

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pf

SC

450

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45

0 -

Bas

ed o

n El

sam

proj

ekt p

ower

pla

nt w

ith 3

0 M

Pa

600°

C/6

00°C

stea

m c

ycle

Oxy

gen

ultra

supe

rcrit

ical

pf w

ith C

O2 c

aptu

re

and

stor

age

O2-

USC

-100

CC

S 45

0 Fl

ue g

as re

cycl

e

Bas

ed o

n El

sam

proj

ekt p

ower

pla

nt w

ith 3

0 M

Pa

600°

C/6

00°C

stea

m c

ycle

, Den

mar

k, w

ith

inte

grat

ed fl

ue g

as re

cycl

e/C

O2 c

aptu

re

Com

bine

d cy

cle

natu

ral g

as

NG

CC

39

0 -

Bas

ed o

n C

S En

ergy

’s S

wan

bank

E p

ower

st

atio

n, Q

ueen

slan

d

Inte

grat

ed g

asifi

catio

n co

mbi

ned

cycl

e IG

CC

40

0 -

Bas

ed o

n th

e Ta

mpa

Ele

ctric

Com

pany

’s T

ampa

co

mbi

ned

cycl

e po

wer

pla

nt, F

lorid

a

Oxy

gen

blow

n in

tegr

ated

gas

ifica

tion

com

bine

d cy

cle

with

25%

CO

2 cap

ture

via

MEA

strip

ping

O

2-IG

CC

-25%

CO

2 40

0 Su

lfur r

emov

al,

MEA

abs

orpt

ion

B

ased

on

Tam

pa p

ower

pla

nt w

ith in

tegr

ated

CO

2 ca

ptur

e (2

5% c

aptu

re)

Inte

grat

ed g

asifi

catio

n co

mbi

ned

cycl

e w

ith so

ur

shift

and

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2 cap

ture

via

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strip

ping

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CC

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2 40

0 Su

lfur r

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al,

sour

shift

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tor,

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abs

orpt

ion

Bas

ed o

n Ta

mpa

pow

er p

lant

with

inte

grat

ed C

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capt

ure

(75%

cap

ture

)

Inte

grat

ed g

asifi

catio

n co

mbi

ned

cycl

e w

ith

doub

le sh

ift a

nd 9

5% C

O2 c

aptu

re v

ia M

EA

strip

ping

O2-

IGC

C-9

5% C

O2

400

Sulfu

r rem

oval

, sw

eet s

hift

reac

tor,

MEA

abs

orpt

ion

Bas

ed o

n Ta

mpa

pow

er p

lant

with

inte

grat

ed C

O2

capt

ure

(95%

cap

ture

) – u

nder

dev

elop

men

t

Inte

grat

ed g

asifi

catio

n w

ith d

oubl

e sh

ift a

nd 9

5%

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2 cap

ture

via

MEA

strip

ping

for h

ydro

gen

prod

uctio

n

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IG-H

2

Sulfu

r rem

oval

, sw

eet s

hift

reac

tor,

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abs

orpt

ion

Bas

ed o

n Te

xaco

gas

ifier

with

inte

grat

ed C

O2

capt

ure

–und

er d

evel

opm

ent

Und

ergr

ound

gas

ifica

tion

com

bine

d cy

cle

UC

G-C

C

- -

Bas

ed o

n co

mbi

ned

cycl

e po

wer

gas

turb

ine

pow

er p

lant

– u

nder

dev

elop

men

t

Dire

ct fi

red

coal

gas

turb

ine

com

bine

d cy

cle

DFC

-CC

39

0 -

Bas

ed o

n ru

gged

ised

com

bine

d cy

cle

gas t

urbi

ne

pow

er p

lant

firin

g D

FC (W

hite

Indu

strie

s)

Pa

ge 7

2 of

131

Tabl

e 4.

2 In

put p

rope

rtie

s for

pow

er g

ener

atio

n te

chno

logi

es m

odel

ling.

Proc

ess

SC

NG

CC

U

SC

O2-

USC

-95%

C

CS

DFC

-CC

IG

CC

O

2-IG

CC

-25%

M

EA-C

CS

O2-

IGC

C-7

5%

MEA

-CC

S

Ove

rall

syst

em

Fuel

pf

N

atur

al g

as

pf

pf

DFC

pf

slur

ry

pf sl

urry

pf

slur

ry

Stea

m c

ycle

Su

perc

ritic

al

U

ltras

uper

criti

cal

Ultr

asup

ercr

itica

l C

onve

ntio

nal

Con

vent

iona

l C

onve

ntio

nal

Con

vent

iona

l

Oxi

dant

A

ir A

ir A

ir O

xyge

n A

ir O

xyge

n/A

ir O

xyge

n O

xyge

n C

O2 c

aptu

re te

chno

logy

N

one

Non

e N

one

Flue

gas

recy

cle

Non

e N

one

MEA

/CO

2 liq

uefa

ctio

n So

ur sh

ift/M

EA/

CO

2 liq

uefa

ctio

n O

utpu

t (M

W)

450

390

450

450

390

400

400

400

Gas

ifica

tion

Gas

fier t

ype

- -

- -

- Te

xaco

Te

xaco

Te

xaco

Gas

ifier

tem

pera

ture

(°C

) -

- -

- -

1500

15

00

1500

G

asifi

er p

ress

ure

(bar

) -

- -

- -

28.6

28

.6

28.6

O

xyge

n ric

h ga

s flo

w (k

g/s)

-

- -

- -

32.5

32

.5

32.5

O

xyge

n pu

rity

(%)

- -

- -

- 95

95

95

St

eam

cyc

le

HP

turb

ine

tem

pera

ture

(°C

) 56

5 56

5 59

7.5

597.

5 56

5 56

5 56

5 56

5 H

P tu

rbin

e pr

essu

re (b

ar)

250

113.

3 29

1.79

29

1.79

11

3.3

113.

3 11

3.3

113.

3 R

ehea

t tem

pera

ture

(°C

) 56

5 56

5 60

0 60

0 56

5 56

5 56

5 56

5 Tu

rbin

e po

lytro

pic

effic

ienc

y (%

) 0.

87

0.

87

0.87

C

onde

nser

pre

ssur

e (b

ar)

0.07

0.

07

0.07

0.

07

0.07

0.

07

0.07

0.

07

Dea

erat

or p

ress

ure

(bar

) -

0.2

12.6

12

.6

0.2

0.2

0.2

0.2

Was

te h

eat b

oile

r tem

pera

ture

(°

C)

- 96

-

- 96

99

96

96

Pa

ge 7

3 of

131

Proc

ess

SC

NG

CC

U

SC

O2-

USC

-100

%

CC

S D

FC-C

C

IGC

C

O2-

IGC

C-2

5%

MEA

-CC

S O

2-IG

CC

-75%

M

EA-C

CS

Gas

turb

ine

Gas

turb

ine

type

-

KA

26-1

SS

PT

- -

- K

A26

-1

SSPT

K

A26

-1 S

SPT

KA

26-1

SSP

T

LP c

ompr

esso

r out

let p

ress

ure

(bar

) -

15

- -

15

15

15

15

Inte

rsta

ge c

oolin

g te

mpe

ratu

re

(°C

) -

279

- -

279

279

279

279

HP

com

pres

sor o

utle

t pre

ssur

e (b

ar)

- 30

-

- 30

30

30

30

Turb

ine

inle

t tem

pera

ture

(°C

) -

1200

-

- 12

00

1200

12

00

1200

Tu

rbin

e in

let p

ress

ure

(bar

) -

30

- -

30

30

30

30

Turb

ine

outle

t tem

pera

ture

(°C

) -

650

- -

650

650

650

650

Turb

ine

outle

t pre

ssur

e (b

ar)

- 1

- -

1 1

1 1

Com

pres

sor p

olyt

ropi

c ef

ficie

ncy

(%)

- 0.

86

- -

0.86

0.

86

0.86

0.

86

Turb

ine

poly

tropi

c ef

ficie

ncy

(%)

- 0.

86

- -

0.86

0.

86

0.86

0.

86

CO

2 ca

ptur

e

M

EA so

lutio

n co

ncen

tratio

n (%

) -

- -

- -

- 20

%

20%

C

O2 a

bsor

ptio

n ef

ficie

ncy

(%)

- -

- -

- -

90%

90

%

Reb

oile

r pre

ssur

e (b

ar)

- -

- -

- -

4 4

CO

2 com

pres

sion

stag

es (b

ar)

- -

- 4.

9:12

.2:3

0:58

-

- 4.

9:12

.2:3

0:58

4.

9:12

.2:3

0:58

C

O2 c

ompr

esso

r eff

icie

ncy

(%)

- -

- 90

%

- -

90%

90

%

CO

2 pip

e pr

essu

re (b

ar)

- -

- 10

0 -

- 10

0 10

0 C

O2

pipe

linin

g

D

ista

nce

(km

); di

a ch

osen

to g

ive

~0.5

% u

se o

f pow

er fo

r pum

ping

-

- -

400

- -

400

400

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Location specific conditions

The key location specific conditions used to represent Australian (Queensland) locale were:

Ambient conditions are assumed to be 25°C and at sea level.

Steam cycle condenser pressure of 7 kPa (≈ a condensate temperature of 39°C).

The fuel compositions were based on generic Qld/NSW bituminous energy coals, and Australian average natural gas.

Although there are a number of options for CO2 storage, including storage in the deep ocean, saline aquifers, un-minable coal seams and exhausted oil and gas reservoirs, the present study has assumed that captured CO2 (at 8 MPa) is compressed and piped a distance of 400 km and stored at a final pressure of 10 MPa (ie transported and sequestered under supercritical conditions).

Different annual capacity factors have been used to allow for differences in availabilities for each technology, and these factors were increased with time.

The DFC-CC was assumed to give a 5% saving in transmission losses by enabling distributed generation.

The weighted average composition of the coals and ultra clean coal is given Table 4.3. The same generic coal was used all coal fired processes, apart from ash content (lower for the IGCC cases) and that for DFC-CC (the UCC ultra clean coal case). The latter used a typical UCC composition provided by White Industries UCC. The composition of pipeline natural gas was based on a weighted Australian average.

The low ash content for the IGCC cases is consistent with current usage in IGCC power plants around the world - though it is a present unclear what ash contents would be used in practice.

Table 4.3 Weighted average composition of coals in process modelling (as received basis).

Component pf SC/USC (as received)

IGCC (as received)

UCC (as received)

Ash (%) 21.4 8.0 <0.2

Moisture (%) 8.0 5.0 4.8

Carbon (%) 59.0 73.7 79.8

Hydrogen (%) 3.7 4.7 5.1

Nitrogen (%) 1.4 1.4 1.8

Sulfur (%) 0.5 0.5 0.4

Oxygen (5%) 6.0 7.0 7.9

SE (GJ/t) 24.6 30.7 32.5

The pipeline composition of natural gas (as used in the process modelling) is given in Table 4.4. Natural gas pipeline specifications are sourced from the National Greenhouse Gas Inventory (NGGIC) and Australian Gas Association.

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Table 4.4 Average composition of Australian pipeline natural gas[23].

Component Vol. %

Methane (CH4) 89.9

Ethane (C2H6) 7.2

Propane (C3H8) 0.1

CO2 1.6

SE (MJ/Nm³) 38.9

4.2 Projecting installation costs

In all of the cases considered, capital costs represented a significant uncertainty in the overall cost of generation. This was especially the case for the projected installation costs out to 2030. In the absence of more detailed information and understanding of installation costs for the different technologies, a combination of experience curves and literature data was used to estimate the cost of future installations. Figure 4.2 below shows schematically how overseas data and projected learning rates have been corrected for an Australian context, based on current Australian installation costs; ie installation costs effectively include both a currency and location conversion factor. (Urfer, 2003)[24]

1990 2000 2010 2020 2030

Year

$/M

W in

stal

led

Learning curve from overseas data (converted to Australian dollars)

Corrected Australian installation costs

Current Australian installed cost ($/MW)

Figure 4.2 Approach to projecting future installation costs from overseas data

to account for both currency and location factors.

Experience curves

Experience curves based on historical cost/production data are a method of forecasting future costs of technologies. Because experience curves have been used for many decades, there is now considerable empirical support for such a quantitative relationship between price and cumulative production (synonymous with use of a technology) from all fields of industrial activities, including energy technologies. While experience curves cannot be used reliably for operating controls or short-term decision-making, experience curves can be a powerful long-range strategic tool in the formulation of competitive strategies.[25]

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The background of experience curves are learning curves which were first developed in the 1930s to illustrate how labour costs for producing a particular manufactured good are reduced with cumulative production. These learning curves reflect a learning-by-doing process or learning-by-producing process within a factory setting[26, 27].

The learning curve concept was expanded in the 1960s to include all costs involved in researching, developing, producing and marketing a given product. Not surprisingly, experience curves have also been employed in analysing cost reductions of energy technologies, with historical data forming the basis for extrapolations into the future. As alluded to earlier, these forecasts are important for making strategic decisions.

Generally, experience curves can be expressed mathematically as shown in Equation 4.1:

Pt = P0 · Xt-E, Equation 4.1

where Pt = Price at year t

P0 = Price at one unit of cumulative production/sales/installation

Xt = Cumulative production/sales/installation in year t

E = Experience parameter (a positive value)

Comparison between different experience curves can be made with the help of the progress ratio PR. PR is a specific feature of any experience curve and expresses the reduction in price on doubling cumulative volume. It can be derived from the experience parameter E as shown in Equation 4.2:

PR = 2-E Equation 4.2

Another term frequently used is learning rate LR and can be derived from PR as shown in Equation 4.3:

LR = 1 - PR = 1 - 2-E Equation 4.3

As can be seen from Equation 4.1, larger values of E indicate a steeper learning curve with a higher learning rate, as illustrated in Figure 4.3 using two different experience parameters. For instance, for an experience parameter E of 0.20, the progress ratio PR is 0.87, highlighting the fact that the price is reduced to 87% of its previous level after a doubling of cumulative units. The corresponding learning rate LR is 13%. By convention, experience curves are displayed using double-logarithmic scales. One advantage of using this representation is that experience curves appear as straight lines as shown in Figure 4.4 using the previous examples, with the slope being equal to -E.

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0

10

20

30

40

50

60

70

80

90

100

0 100 200 300 400 500 600 700 800 900 1000

Cumulative units in year t

Pric

e at

yea

r tE=0.20; PR=0.87; LR=0.13

E=0.60; PR=0.66; LR=0.34

Figure 4.3 Relationship between E, PR and LR.

1

10

100

1 10 100 1000

Cumulative units in year t

Pric

e at

yea

r t

E=0.20; PR=0.87; LR=0.13

E=0.60; PR=0.66; LR=0.34

Figure 4.4 Relationship between E, PR and LR using double-logarithmic representation.

Table 4.5 summarises published examples of learning rates for several energy and electricity generation technologies.[28] Several types of experience curves have been used for energy technologies:

Costs per kW vs the cumulative installed capacity

Costs per kWh vs the cumulative generation

Costs per kWh vs the cumulative number of units installed

Experience curves of the first type are the most common found.

As part of the European Commission’s energy, technology and climate policy outlook for the world (WETO), historic development of total investment costsa, as a function of total cumulative installed capacity, have been compiled for 18 energy technologies in the form of learning curves[29] which are reproduced in Figure 4.5. The technologies include the 4 main energy types:

Gas conventional gas, gas combined cycle.

Coal conventional lignite, conventional coal, supercritical coal, coal gasification combined cycle, direct coal-fired combined cycle.

Nuclear conventional and new designs.

Renewables hydro, small hydro, wind, photovoltaics, biogas turbine, biomass combined heat and power (CHP), solar thermal power, solid oxide fuel cells (SFC) and proton exchange membrane fuel cells (PEM).

Underlying these learning curves are “business and technical change as usual” assumptions (from an installed capacity perspective), which provide a reference scenario (or benchmark) when assessing alternative energy scenarios. The markers in Figure 4.5 represent five-year intervals up to the year 2030. Policies and demand-side technologies are not included in the assessments.

a Total investment costs include costs for equipment, construction and decommissioning. They have been

adjusted from €1999 to US$2002 by converting €1999 into US$1999 using the average US$/€ exchange rate in 1999 (1.066), followed by applying an US$2002/US$1999 inflation factor (1.080).

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Table 4.5 Estimated energy-related learning rates.

Technology Country/region Time period Learning rate (%)

Oil extraction North Sea - ~ 25

Gas pipelines, onshore US 1984-1997 3.7

Gas pipelines, offshore US 1984-1997 24

DC converters World 1976-1994 37

Gas turbines World a 1958-1963 22

Gas turbines World a 1963-1980 9.9

Gas turbines World a 1958-1980 13

Nuclear power plants OECD 1975-1993 5.8

Hydropower plants OECD 1975-1993 1.4

Coal power plants OECD 1975-1993 7.6

Lignite power plants OECD 1975-1992 8.6

GTCC power plants OECD 1984-1994 34

GTCC power plants World 1981-1991 -11 bd

GTCC power plants World 1991-1997 26 b

Wind power plants OECD 1981-1995 17

Wind power (electricity) California 1980-1994 18

Wind Germany 1990-1998 8

Wind turbines Denmark 1982-1997 8

Solar PV modules c World 1968-1998 20

Solar PV panels US 1959-1974 22

Ethanol Brazil 1979-1995 20

a The geographical scope of the data is not reported explicitly. The context suggests it is the whole world. b Note that these learning rates are based on prices, and one explanation of the negative 1981-1991 “learning”

rate could be oligopolistic pricing behaviour. c Based on preliminary data.

Pa

ge 7

9 of

131

100

1,00

0

10,0

00

100

1,00

010

,000

100,

000

1,00

0,00

010

,000

,000

Cum

ulat

ive

inst

alle

d ca

paci

ty [M

W]

Total investment cost [€99/kW]C

onve

ntio

nal g

asG

as c

ombi

ned

cycl

eC

onve

ntio

nal l

igni

teC

onve

ntio

nal c

oal

Sup

ercr

itica

l coa

lC

oal g

asifi

catio

n cc

Dire

ct c

oal

Nuc

lear

New

nuc

lear

des

ign

Hyd

roS

mal

l hyd

roW

ind

Pho

tovo

ltaic

sB

ioga

s tu

rbin

eB

iom

ass

CH

PS

olar

ther

mal

pow

erFu

el c

ells

(SFC

)Fu

el c

ells

(PE

M)

Fi

gure

4.5

Exp

erie

nce

curv

es fo

r pow

er g

ener

atio

n te

chno

logi

es u

p to

203

0.

Pa

ge 8

0 of

131

0

1,00

0

2,00

0

3,00

0

4,00

0

5,00

0

6,00

0 2000

2005

2010

2015

2020

2025

2030

Year

Total investment cost [€99/kW]C

onve

ntio

nal g

asG

as c

ombi

ned

cycl

eC

onve

ntio

nal l

igni

teC

onve

ntio

nal c

oal

Sup

ercr

itica

l coa

lC

oal g

asifi

catio

n cc

Dire

ct c

oal

Nuc

lear

New

nuc

lear

des

ign

Hyd

roS

mal

l hyd

roW

ind

Pho

tovo

ltaic

sB

ioga

s tu

rbin

eB

iom

ass

CH

PS

olar

ther

mal

pow

erFu

el c

ells

(SFC

)Fu

el c

ells

(PE

M)

Fi

gure

4.6

Rep

lotti

ng e

stim

ates

in F

igur

e 4.

4 ba

sed

on p

roje

cted

incr

ease

s in

capa

city

.

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The present study has used the following learning rates for the different technologies for the future periods 2000-2010 and 2010-2030.

Table 4.6 Assumptions for various energy technologies for 2010 and 2030.

Reference Annual change 2002-2010

(%)

Annual change 2010-2030

(%)

Gas turbine combined cycle

Total investment cost (€1999/kW) -2.4% -0.5%

Electricity generation (TWh) 14.9% 2.3%

Supercritical coal


Electricity generation (TWh) 230% 8.4%

Integrated Coal Gasification (IGCC)


Electricity generation (TWh) 124% 11.4%

Light Water Reactor (LWR)

Total investment cost (€1999/kW) -0.2% 0.1%

Electricity generation (TWh) 1.8% -0.5%

Advanced Nuclear Design

Total investment cost (€1999/kW) -4.7%

Electricity generation (TWh)

Wind turbines



Photovoltaics



Biomass gasification


Electricity generation (TWh) 117.0% -2.0%

It is noted, that learning rates can be greatly affected by factors external to those for the development of the individual technologies – any bias for a particular technology (for example for new installations to meet the forecasted increase in energy demand) will result in large deviations from the base case. In some cases, this will result in the technology being developed along a new learning curve.

4.3 Life cycle analysis

Life cycle analysis (LCA) and life cycle assessment are internationally accepted techniques for estimating environmental impacts over the life cycle of a defined system. Life cycle assessment has been standardised through a set of guidelines by the International Standards

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Organisation as part of the ISO 14000 series[30,31,32,33], and represents a specific application of the older, and more generic, type of systems modelling called life cycle analysis.

The methodology used in conducting this LCA is based on the 4-stage approach recommended in the ISO guidelines (an extension of the 3 stage approach recommended by SETAC in 1993[34]). The approach comprises:

1. Establishing the goal and scope of each study. In the current study care was taken to ensure that system boundaries were chosen which enable a fair comparison between the different combinations of technology.

2. Completing an inventory analysis, which involves accounting for all significant inputs and outputs of the system (includes those of 3rd party suppliers).

3. Performing an assessment of the impacts. In the present study, this was by direct comparison of the inventory values and impact categories.

4. Using the analysis to identify improvement opportunities.

Basis for comparison

In the present study, the “life cycle” is defined as the system to produce 1 MWh of electricity. These are called the functional units.

System boundaries

System boundaries were set as wide as possible and up to the production of the first common product which is 1 MWh (or in the hydrogen case, 1 GJ of hydrogen) delivered at the plant gate. This included the provision of 3rd party goods and services and waste management, but did not include credits for the production of by-products.

An exception was made for the DFC-CC LCA to make an allowance for the likely savings in transmission losses. In this case, the system boundary was artificially extended to give the technology an efficiency credit of +5%.

Impacts from plant construction, decommissioning, repairs and maintenance have been estimated from previous LCA studies.

Impact assessment

While the main focus of the study was the global issue of greenhouse gas emissions, it is acknowledged that future work should attempt to include a wider range of impacts (as is usual in LCA). Greenhouse gas emissions (GGE) have been expressed as the equivalent mass emission of CO2 (CO2-e) using the Greenhouse Warming Potentials from the Intergovernmental Panel for Climate Change (IPCC) for non-CO2 contributors.

4.4 Economics

The economic analysis included capital, fuel, operating costs and sensitivity analyses for costs for CO2 emissions or the cost of capture and storage. Capital costs are based on a range of data sources, the principal references being Gray and Tomlinson[35], USDOE[3637], European Commission[38,39], IEA[40,41], CIAB[42] and the World Energy Assessment[43].

In the present study, all costs are reported in Australian dollars, whereas most cited literature data is reported in $US or other currencies. For plant capital costs, it is erroneous to convert installed costs quoted in other currencies directly to Australian dollars using exchange rates, due to the differences in the relative costs for material/equipment, labour rates etc. These

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location dependent factors require that capital costs be based on a detailed cost breakdown for individual plant. As this has not been possible in the present study, a simplified approach has been used.

Where possible, currency conversions have been made for individual plant items, for example, gas and steam turbines that are always purchased from overseas. For other plant, estimates have been made using advice from a range of sources, including CS Energy[44] and the CRC for Clean Power from Lignite[45] (the CRC has recently completed detailed cost conversions for Victorian brown coal plant). Overall capital cost estimates therefore have a significant uncertainty, especially those for new technologies. In reporting of economic results, a ±20% uncertainty factor has been applied to the capital service charge (based on capital cost). The effects of risk and other contingencies have been included as an additional factor (5-15% depending on the technology), again following advice from CS Energy.

Fuel compositions were based on generic Qld/NSW bituminous energy coals (see Table 4.3), and Australian average natural gas (see Table 4.4). The same generic coal was used for all coal-fired processes, apart from the ash content, which was lower for the IGCC and ultra clean coal case studies. The composition of pipeline natural gas was based on a weighted Australian average. The following fuel costs were used for the base cases:

- Coal for pf (SC or USC) @ A$1.00/GJ.

- Coal for IGCC @ A$1.40/GJ (current), reducing to A$1.20/GJ by 2030. The higher cost is an allowance for lower ash coal and flux use. It is noted that this differential will be highly dependent on situation and coal-technology combination used; however, there is insufficient information available to make a more accurate estimate of any cost premium.

- Natural gas for NGCC @ A$3.50/GJ. The cost estimate of natural gas is the delivered cost which includes a nominal transmission distance of around 800 km.

- Direct fired coal (turbine pf) DFC-CC @ A$3.00/GJ.

For captured CO2, a disposal cost of A$10 per tonne of CO2 has been applied to any carbon dioxide stored. This cost is assumed to cover the compression and piping of liquid CO2 a distance of 400 km and stored at a final pressure of 10 MPa (ie transported and sequestered under supercritical conditions).

Different annual capacity factors have been used to allow for different plant availability for each of the technologies. This capacity factor is based on the assumed plant availability and the plant load factor (%) while operational.

Other key base assumptions are a capital service charge of 7% and labour, research and maintenance costs at 4% of capital.

Table 4.7 summarises the key assumptions for each of the technologies, including the sensitivity to fuel costs and carbon taxes.

Pa

ge 8

4 of

131

Tabl

e 4.

7 Pa

ram

eter

s for

eco

nom

ic a

naly

sis.

Tech

nolo

gy c

ombi

natio

n Fu

el c

ost

($

/GJ)

Ava

ilabi

lity

2003→

2030

(%

)

Load

Fa

ctor

(%

)

Cap

acity

fa

ctor

(%

)

CO

2 pip

elin

e an

d di

spos

al

($/t

CO

2)

Bas

elin

e

Supe

rcrit

ical

pf (

SC)

Bas

e: 1

.00

Ran

ge: 0

.50-

2.50

97

95

92

10

Nat

ural

Gas

Com

bine

d C

ycle

(NG

CC

) B

ase:

3.5

0 R

ange

: 2.0

0-5.

00

95→

97

95

90→

92

10

Incr

emen

tal

Ultr

asup

ercr

itica

l pf (

USC

) B

ase:

1.0

0 R

ange

: 0.5

0-2.

50

80→

87

95

87→

92

10

Oxy

gen

inte

grat

ed g

asifi

catio

n co

mbi

ned

cycl

e (I

GC

C)

Bas

e: 1

.20

Ran

ge: 0

.50-

2.50

85→

92

95

81→

87

10

Oxy

gen

inte

grat

ed g

asifi

catio

n co

mbi

ned

cycl

e, 2

5% C

O2 c

aptu

re

(MEA

) and

CO

2 com

pres

sion

(O

2-IG

CC

-25%

MEA

-CC

S)

Bas

e: 1

.20

Ran

ge: 0

.50-

2.50

80→

87

95

76→

83

10

Oxy

gen

inte

grat

ed g

asifi

catio

n co

mbi

ned

cycl

e, 7

5% C

O2 c

aptu

re

(MEA

) and

CO

2 com

pres

sion

(O

2-IG

CC

-75%

MEA

-CC

S)

Bas

e: 1

.20

Ran

ge: 0

.50-

2.50

80→

87

95

76→

83

10

Oxy

gen

inte

grat

ed g

asifi

catio

n co

mbi

ned

cycl

e, 7

5% C

O2 c

aptu

re

(Sel

exol

) and

CO

2 com

pres

sion

(O

2-IG

CC

-75%

SX

-CC

S)

Bas

e: 1

.20

Ran

ge: 0

.50-

2.50

80→

87

95

76→

83

10

New

Dire

ct fi

red

coal

com

bine

d cy

cle

gas t

urbi

ne

(DFC

-CC

) B

ase:

3.0

0 R

ange

: 2.0

0-5.

00

90→

92

95

86→

88

10

Ultr

asup

ercr

itica

l pf

(O2-

USC

-100

% C

CS)

B

ase:

1.0

0 R

ange

: 0.5

0-2.

50

87→

92

95

82→

87

10

Oxy

gen

inte

grat

ed g

asifi

catio

n hy

drog

en, 9

5% C

O2 c

aptu

re

(MEA

) and

com

pres

sion

(O

2-IG

CC

-95%

MEA

-CC

S)

Bas

e: 1

.20

Ran

ge: 0

.50-

2.50

80→

87

95

76→

83

10

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4.5 Electricity scenarios to 2030

Five simplified scenarios for future power generation in Australia have been developed using the previous results and electricity demand predictions from the Electricity Supply Association of Australia[3] and ABARE[4]. The scenarios estimate future average greenhouse gas intensity and the total greenhouse gas emissions out to 2030.

The scenarios analysed are:

Scenario A (business as usual, new by coal)


Scenario B (high wind, new by coal)

Replacement of future power demand with 5,000 MW of wind by 2010, then maintaining 12% wind generation with the additional demand met by high efficiency coal fired plants (no CO2 capture)

Scenario C (high wind, new by gas)

Replacement of future power demand with 5,000 MW of wind by 2010, then maintaining 12% wind generation with the additional demand met by high efficiency combined cycle natural gas (no CO2 capture).


Replacement of all future power demand with renewable technologies.



The main assumptions/basis were as follows:

Only stations that are grid connected are included in the analysis, which includes all stations on Western Australia’s south-west interconnected grid.

New technologies are assumed to apply equally to black and brown coals (ie new technologies for brown coal will result in similar CO2/MWh sent out basis) to black and brown coals.

All new fossil generation has an 80% capacity factor and all new wind/renewable generation has a 25% capacity factor.

Fossil power stations older than 40 years are decommissioned.

Coal technologies are assumed to have the

No significant growth in the installed hydroelectric capacity.

No nuclear power generation capacity installed.

All renewables are based on wind.

No storage is required for renewables up to 15% of total generation, and when storage is required this is assumed to increase the installation cost by 100%.

Life cycle greenhouse gas emissions (CO2 equivalents) were used and include fuel mining, processing and transportation/distribution for fossil fuels and the construction of the facilities for renewable technologies such as wind and hydroelectricity.

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A Kyoto target for power generation greenhouse gas emissions in Australia has been set as 108% of the total emissions from power generation in 1990. Total emissions in 1990 from power generation in 1990 were 131 Mt, so the 2008-12 target has been assumed to be 141 Mt CO2.

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5 RESULTS AND DISCUSSION

The results are presented to show the 3 types of analyses:

Technology comparison for current and emerging technologies – a technical analysis of the technology combinations for Australian coals and under Australian conditions.

Current and future economics – for the technology combinations now and out to 2030, with sensitivity analyses for fuel cost and the value of carbon emissions. This analysis considers technology creep and its effect on capital costs, efficiencies and availabilities.

Future Australian scenarios – comparing 5 hypothetical future scenarios for technology implementation to meet the projected growth in the Australian electricity demand using the economic and life cycle emissions data.

5.1 Technology comparison

This section compares a range of current and emerging technologies to determine thermal efficiency on a sent-out basis (after allowances for CO2 controls), plant sizing, and greenhouse gas emissions. This comparison includes a number of non-commercial technologies, which are considered to be technically feasible; ie which have been demonstrated at a pilot scale (eg DFC using White Industries UCC), or are based on new combinations of old technology (eg CO2 capture from syngas, O2-USC-95% CCS).

5.1.1 Technology modelling

The results of the METSIM process modelling are given in Table 5.1 and are based on the process parameters specified in Table 4.2 in the previous section. The results show mass and energy flows, capacities, and efficiencies for the main process blocks for each technology combination. Key modelling results are:

Gross and net power generated (after consideration of auxiliaries and parasitic loads).

Losses and plant sizing for CO2 capture.

CO2 liquefaction energy to produce sequestration ready pipeline CO2.

Estimated overall or sent out efficiency (on a HHV basis).

Energy required for CO2 pipelining.

The results from the present models is compared with previous studies in Table 5.2

The main findings are as follows:

For the IGCC technologies, the base plant (based on Texaco) has a sent out efficiency of 43.4% (HHV) with greenhouse gas emissions of 713 kg/MWh – this predicted efficiency is significantly higher than the 39-42% obtained by current IGCC plants due to using data for advanced gas turbines. With MEA stripping of the flue gas (no CO-shift), approximately 25% of the CO2 can be captured. After compression this reduces the plant efficiency to 40.4%. When a sour CO-shift reactor is incorporated to increase CO2 removal to approximately 75%, the overall plant efficiency decreases by 10% to 33.4%. The efficiency decreases are due primarily to the regeneration of the CO2 rich MEA solution. MEA has been used as the base case due its widespread use

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in industry. The Selexol case reduced this loss to 7%, giving an overall efficiency of 36%. In addition, as the present models are based on plant literature data for proposed plants, it is likely that improved integration of the CO2 capture with the power plant together with alternative capture solutions are likely to further improve the sent out efficiency.

The results for the present calculations compare reasonably well with the results of other studies. The effects of Australian conditions are less pronounced for IGCC, as only 1/3 of the power output is from a steam cycle. Other results for technologies using other forms of CO2 capture (chemical and physical solvents) show decreases in efficiency of 2.0% to 16%.

CO2 capture for oxygen USC reduces the sent out efficiency by approximately 9%, due to the parasitic load for oxygen production and flue gas compression and liquefaction.

CO2 capture and compression reduces sent out electricity by 16-23% for IGCC and 18-20% for O2 USC (ie on a relative basis).

Pa

ge 8

9 of

131

Tabl

e 5.

1 Su

mm

ary

of p

roce

ss m

odel

ling

resu

lts fo

r tec

hnol

ogy

com

bina

tions

.

Proc

ess

SC

N

GC

C

USC

O

2-U

SC-

100%

CC

S D

FC-C

C

IGC

C

O2-

IGC

C-2

5%

MEA

-CC

S O

2-IG

CC

-75%

M

EA-C

CS

Hea

t inp

ut (M

Wt,,

HH

V)

73

2.8

993.

2 12

44.9

75

0.0

940.

4 94

0.4

940.

4

Gas

Tur

bine

Pow

er O

utpu

t (M

We)

- 25

0.2

- -

250.

2 27

8.1

271.

4 25

5.3

Stea

m T

urbi

ne P

ower

O

utpu

t (M

We)

485

145.

7 48

3.4

598.

6 14

5.7

199.

7 18

6.5

151.

9

Tota

l Pow

er O

utpu

t (M

We)

485

395.

9 48

3.4

598.

6 39

5.9

477.

8 45

7.9

405.

4

Boi

ler A

uxili

arie

s (M

We)

34.7

5.

9 33

.4

21.5

6.

0 7.

2 6.

6 5.

5

O2 S

epar

atio

n Po

wer

(M

We)

- -

- 85

.5

- 62

.1

62.1

62

.1

MEA

Sys

tem

Pow

er

(MW

e) -

- -

- -

- 29

.3

91.7

CO

2 Liq

uefa

ctio

n Po

wer

(M

We)

- -

- 41

.6

- -

8.7

24.5

Net

Ele

ctric

ity P

rodu

ctio

n (M

We)

450

389.

9 45

0 45

0 38

9.9

408.

5 36

4.9

271.

9

Ove

rall

Effic

ienc

y (%

) (H

HV

) 41

.0%

53

.2%

45

.3%

36

.1%

49

.0%

43

.4%

40

.4%

33

.4%

Gre

enho

use

gas e

mis

sion

s (k

g/M

Wh)

76

3 34

7 69

2 0

661

713

561

230

Pa

ge 9

0 of

131

Tabl

e 5.

2 C

ompa

riso

n of

IGC

C m

odel

ling

resu

lts w

ith o

ther

stud

ies.

Sh

ift/ty

pe

CO

2 re

mov

al

CO

2 ca

ptur

e

(%)

Effic

ienc

y w

ithou

t CO

2 ca

ptur

e (%

)

Effic

ienc

y w

ith

CO

2 cap

ture

(%

)

Effic

ienc

y de

crea

se

(%)

Sour

ce

O2-

IGC

C-T

exac

o lo

w

pres

sure

N

o sh

ift

ME

A

25

43.4

(HH

V)

40.4

(HH

V)

3.0

Pres

ent s

tudy

O2-

IGC

C-T

exac

o lo

w

pres

sure

So

ur sh

ift, o

ne st

age

ME

A

75

43.4

(HH

V)

33.4

(HH

V)

10.0

Pr

esen

t stu

dy

O2-

IGC

C-T

exac

o lo

w

pres

sure

So

ur sh

ift, o

ne st

age

Sele

xol

75

43.4

(HH

V)

36.4

(HH

V)

7.0

Pres

ent s

tudy

O2-

IGC

C-S

hell

low

pre

ssur

e So

ur sh

ift, t

wo

stag

e Se

lexo

l 85

43

.1 (L

HV

) 34

.5 (L

HV

) 8.

6 IE

A, 2

003[4

6]

O2-

IGC

C-S

hell

low

pre

ssur

e C

lean

shift

, thr

ee

stag

e Se

lexo

l 85

43

.1 (L

HV

) 33

.0 (L

HV

) 10

.1

IEA

, 200

3

O2-

IGC

C-S

hell

high

pre

ssur

e So

ur sh

ift, t

wo

stag

e Se

lexo

l 85

41

.3 (L

HV

) 32

.7 (L

HV

) 8.

6 IE

A, 2

003

O2-

IGC

C-T

exac

o hi

gh p

ress

ure

Sour

shift

, one

stag

e Se

lexo

l 85

37

.0 (L

HV

) 30

.6 (L

HV

) 6.

4 IE

A, 2

003

O2-

IGC

C-S

hell

low

pre

ssur

e So

ur sh

ift, t

wo

stag

e M

DEA

85

43

.1 (L

HV

) 35

.0 (L

HV

) 8.

1 IE

A, 2

003

O2-

IGC

C

Shift

R

ectis

ol

~90

46.7

(LH

V)

40.5

(LH

V)

6.1

Hau

pt e

t al,

2002

[47]

O2-

IGC

C

Unk

now

n C

old

CO

2 re

cove

ry fr

om

syng

as

~85

45.9

(HH

V)

36.1

(HH

V)

9.8

WEA

, 200

1[43]

O2-

IGC

C-T

exac

o-hi

gh p

ress

ure

Sour

shift

Se

lexo

l 75

41

.0 (L

HV

) 39

(LH

V)

2.0a

O’K

eefe

et a

l, 20

03[4

8]

O2-

IGC

C-S

hell

Unk

now

n Se

lexo

l 96

42

.0 (H

HV

) 34

.7 (H

HV

) 7.

3 D

ave,

et a

l, 20

00[4

9]

O2-

IGC

C-S

hell

Unk

now

n U

nide

ntifi

ed

solv

ent

>90

42.0

(HH

V)

29.2

(HH

V)

12.8

D

ave,

et a

l, 20

00

O2-

IGC

C

Unk

now

n sh

ift

Phys

ical

solv

ent

~80

46.0

(LH

V)

38 (L

HV

) 8.

0 A

udus

, 200

0[50]

a D

oes n

ot in

clud

e C

O2 c

ompr

essi

on

Pa

ge 9

1 of

131

Sh

ift/ty

pe

CO

2 re

mov

al

CO

2 ca

ptur

e

(%)

Effic

ienc

y w

ithou

t CO

2 ca

ptur

e (%

)

Effic

ienc

y w

ith

CO

2 cap

ture

(%

)

Effic

ienc

y de

crea

se

(%)

Sour

ce

O2-

IGC

C-T

exac

o-hi

gh p

ress

ure

No

shift

D

EA, p

ost

com

bust

ion

91.5

45

.9 (L

HV

) 37

.8 (L

HV

) 8.

1 C

hies

a et

al,

1999

[51]

O2-

IGC

C-T

exac

o-hi

gh p

ress

ure

No

shift

, par

tial f

lue

gas r

ecyc

le

DEA

, pos

t co

mbu

stio

n 91

.5

45.9

(LH

V)

38.4

(LH

V)

7.5

Chi

esa

et a

l, 19

99

O2-

IGC

C-T

exac

o-hi

gh p

ress

ure

No

shift

, par

tial f

lue

gas r

ecyc

le

Sele

xol,

post

co

mbu

stio

n 91

.5

45.9

(LH

V)

38.2

(LH

V)

7.5

Chi

esa

et a

l, 19

99

O2-

IGC

C-T

exac

o-hi

gh p

ress

ure

Shift

Se

lexo

l 91

.5

45.9

(LH

V)

39.3

(LH

V)

6.6

Chi

esa

et a

l, 19

99

O2-

IGC

C-T

exac

o-hi

gh p

ress

ure

No

shift

Fl

ue g

as

com

pres

sion

91

.5

45.9

(LH

V)

38.5

(LH

V)

7.4

Chi

esa

et a

l, 19

99

O2-

IGC

C

- M

EA

83

38.4

(HH

V)

27.0

(HH

V)

11.4

Jo

ule

II, 1

995[3

8]

O2-

IGC

C

- Pr

essu

re sw

ing

adso

rptio

n 95

42

.0 (L

HV

) 26

.0 (L

HV

) 16

.0

IEA

, 199

5[52]

O2-

IGC

C

- Te

mpe

ratu

re

swin

g ad

sorp

tion

95

42.0

(LH

V)

29.0

(LH

V)

13.0

IE

A, 1

995

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Energy for CO2 pipelining

The parasitic load for pumping and storing compressed CO2 is a function of the injection well pressure at the disposal site, pipe diameter and pipe length. To put CO2 pipelining in context, the parasitic load has been calculated for a range of pipe diameters, based on 10 MPa pressure at the injection well and 400 km of pipeline; see Figure 5.1. A 500 MW plant would need a 12-14” nominal bore pipe to maintain pumping losses to around 0.5% of sent out electricity. In practice the selection of the pipe diameter will be based on trade-offs between the cost of the pipe and laying, the value of the power consumed in pumping, other installation costs such as provision of easements, and management charges.

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

8 10 12 14 16

Nominal pipe diameter (inch)

Par

asiti

c lo

ad (%

)

Figure 5.1 Calculated parasitic load for CO2 compression/pumping for various Schedule 100

mild steel pipe sizes for a 500 MW power station (125 kg CO2/s).

5.2 Economic analysis of technologies

The economic analysis covers:

Current and projected installation costs (on a MW installed basis), with projected costs based on experience curves to give costs to 2030.

Current and projected generation costs (sent out basis), with a sensitivity for a range of current fuel costs.

Effect of technology options on the cost of CO2 abated.

Effect of a range of carbon values for the overall generation costs.

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5.2.1 Installation cost

Current and projected capital costs are given in Table 5.3 on a A$2002/MW basis. Projected costs use the capital costs for 2002 decreased by the learning rate factors in Section 4, Table 4.6, but normalised back to A$2002. Note, that the efficiency and availability of the each technology also increases, which affects both the installed and operating costs. Wind generation has been included to represent renewable energy, and whilst it is noted that other renewables are possible, wind is likely to remain the lowest cost renewables option.

The most significant changes between current and projected 2030 values in Table 5.3 are:

The marked decrease in capital cost for IGCC and wind.

A marked increase in base efficiency (without capture) for all of the technologies.

Table 5.3 Current and projected capital cost and sent-out efficiency for the generation technologies.

2002 2010 2030 Technology Capital cost(A$M/MW)

Eff.(%)


Eff. (%)


Eff.(%)

Supercritical pf (SC) 1,151 41 1,062 43 960 45

Natural gas combined cycle (NGCC) 825 53 679 56 614 65

Ultrasupercritical pf (USC) 1,210 43 1,117 45 1,010 52

Ultrasupercritical pf (O2-USC-95% CCS)2

1,868 34 1,589 37 1,438 44


926 49 762 52 689 60


1,584 43 1,172 48 884 50


1,839 39 1,360 45 1,026 60


2,453 33 1,814 40 1,369 44

Wind (peak capacity factor)3 1,700 - 1,458 - 1,014 -

CO2 capture via O2-USC (95% capture) 658 - 472 - 428 -

CO2 capture for IGCC (75% capture) 869 - 642 - 485 - 1. Based on A$2002 2. Excludes CO2 transmission and storage 3. Excludes effect of low capacity factor and costs of any energy storage, which can increase

capital on an average sent out basis by 800-1000%.

5.2.2 Generation cost

Generation costs for new plant are shown on a sent-out basis in Figure 5.2. The results also include an estimate for hydrogen produced via IGCC technology with CO2 capture and storage.

The key points are summarised as follows:

For current technologies (say commissioned in 2005-08), the lowest cost options would be supercritical and ultrasupercritical pf at A$25/MWh. This is a significantly

of 131

lower cost than for IGCC, NGCC and DFC, which have similar costs of A$33-35/MWh.

All of the technologies with CCS have generating costs, which are A$20/MWh higher – when all of the costs are assigned to the sent out electricity. This is due to the combined effects of higher capital costs for plants with CO2 capture and compression (which includes a compounding effect for estimated lower availability of new and more complex technology combinations), plus the lower thermal efficiencies on a sent-out basis (due to increased parasitic loads and some thermal effects).

On the same basis, O2-USC-95% CCS would be the lowest cost technology for higher rate (for greater than 75% capture) carbon capture and storage. However, this difference decreases into the future due to the anticipated more rapid developments in IGCC (as discussed later).

The production cost of hydrogen is A$7.90/GJ (which equates to A$55-65/MWh of electricity if used in a hydrogen combined cycle gas turbine).

A 20% uncertainty in capital cost estimates will result in generation cost error of 10-15% for all of the coal-based technologies except for direct-fired coal. DFC-CC is estimated to have similar capital costs (only about 10% higher) to NGCC, which is approximately two-thirds that for conventional pf and IGCC technologies.

0

10

20

30

40

50

60

70

SCNGCC

USC

O2 USC-95

% CCS

DFC-C

CIG

CC

O2-IGCC-25

% MEA-C

CS

O2-IGCC-75

% MEA-C

CS

O2-IGCC-75

% SX-CCS

Elec

trici

ty c

ost (

A$/

MW

h)

Capital serviceCO2 disposalOtherFuel

0

2

4

6

8

10

12

14

16

18

O2-IG-H

2 CCS

Hyd

roge

n co

st (A

$/G

J)

Figure 5.2 Cost comparison of power generation technologies. Error bar show sensitivity to

a variation in capital cost of ±20%.

of 131

Effect of fuel cost

As fuel represents 25-35% of the overall generation cost (when CO2 pipeline and storage charges are included for the options with CO2 capture and storage), a range of fuel costs have been considered – with coal at A$0.50-2.50/GJ and gas and DFC at A$2.00-5.00/GJ. The corresponding generation costs for 2002 and 2030 are given in Figure 5.3 and Figure 5.4, respectively.

For 2002:

Supercritical pf with coal at the base cost of A$1.00/GJ gives similar generation costs (sent out basis) to;

- DFC-CC using DFC at A$1.60/GJ,

- NGCC using gas at A$2.00/GJ,

- IGCC using coal at approximately ~A$0.25/GJ.

10

20

30

40

50

60

70

80

0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00

Fuel cost (A$/GJ)

Pow

er c

ost (

A$/

MW

h)

SC NGCCUSC O2-USC-95% CCSDFC-CC IGCCO2-IGCC-25% MEA-CCS O2-IGCC-75% MEA-CCSO2-IGCC-75% SX-CCS

Figure 5.3 Effect of fuel price 2002.

of 131

For 2030:

Ultrasupercritical pf with coal at the base cost of A$1.00/GJ gives similar generation costs (sent out basis) to;

- IGCC using coal at approximately ~A$1.05/GJ (this is a marked change from the 2002 case).

- DFC-CC using DFC at A$1.65/GJ,

- NGCC using gas at A$2.00/GJ,

IGCC-CCS with coal at the base cost of A$1.20/GJ gives similar generation costs to O2-USC-95% CCS at A$1.15.

10

20

30

40

50

60

0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00

Fuel cost (A$/GJ)

Pow

er c

ost (

A$/

MW

h)

SC NGCC

USC O2-USC-95% CCS

DFC-CC IGCC


Figure 5.4 Effect of fuel price in 2030.

Projected generation costs

A summary of the overall projected sent-out generation costs for the different technologies out to 2030 is shown in Figure 5.5. Note that these results use the base values for fuel costs, CO2 pipelining and storage charges, R&M and the capital service charge.

The main findings are:


IGCC-CCS generation costs decrease more quickly than for the other coal-based technologies. The O2-IGCC-75% CCS gives a similar generation cost to O2-USC-95% CCS in 2030.

of 131

NGCC and DFC have almost identical costs (note, NGCC curve lies under that for DFC in the figure below).

IGCC-25% CCS (ie partial capture) becomes lower cost than NGCC and DFC-CC at around 2015-2020.

20

30

40

50

60

70

80

2000 2005 2010 2015 2020 2025 2030

Year

Gen

erat

ion

cost

(A$/

MW

h)

SC NGCCUSC O2-USC-95% CCSDFC-CC IGCCO2-IGCC-25% CCS O2-IGCC-75% CCSWind

Figure 5.5 Current and projected costs for power generation technologies to 2030. Note,

NGCC points lie directly under those for DFC.

An additional breakdown of costs for years 2002, 2010 and 2030 is given in Figure 5.6 below. These results use the same base data. The most significant point is that the costs for CO2 pipelining and storage are 15-20% of the overall generation cost for the technologies with capture.

Pa

ge 9

8 of

131

01020304050607080

SC (41%

) - 20

02(43

%) - 20

10(45

%) - 20

30

NGCC (53%

) - 20

02(56

%) - 20

10(65

%) - 20

30

USC (43%

) - 20

02(45

%) - 20

10(52

%) - 20

30

O2-USC-95

% CCS (3

4%) -

2002

(37%) -

2010

(43%) -

2030

DFC-C

C (49%

) - 20

02(52

%) - 20

10(60

%) - 20

30

IGCC (4

3%) -

2002

(48%) -

2010

(50%) -

2030

O2-IGCC-25

% CCS (3

9%) -

2002

(45%) -

2010

(46%) -

2030

O2-IGCC-75

% CCS (3

0%) -

2002

(36%) -

2010

(37%) -

2030

WIND (2

5% C

F) - 20

02

(25% C

F) - 20

10

(25% C

F) - 20

30

Generation cost (A$/MWh)C

O2

disp

osal

Fuel

Oth

erC

apita

l ser

vice

Fi

gure

5.6

Cur

rent

and

pro

ject

ed c

osts

for p

ower

gen

erat

ion

tech

nolo

gies

in 2

002,

201

0, 2

030.

of 131

5.2.3 Economics of CO2 abatement

The results above assign no value to the reduction in CO2 emissions from improvements in efficiency and/or CO2 capture and storage. Two approaches have been used be to take into account reduced emissions:

Comparing the overall cost of CO2 abated, which requires comparisons to a base case cost of generation (sent out basis). In the present study best the cost of electricity from best available pf technology has been used as the base electricity cost (ie from supercritical to 2010, and from ultrasupercritical from 2010 to 2030). Note that comparisons of the cost of CO2 abated are highly sensitive to the base case chosen. For example, if the base case were an older pf station, or the grid average, the cost of abatement would be markedly lower.

Assigning an externality or societal value to the CO2; ie a dollar value of carbon. The present study has used A$0-50/t CO2 emitted.

Cost of CO2 abated

The cost of CO2 abatement for each technology combination in 2002, 2010 and 2030 are given in Table 5.4.

Table 5.4 Effective cost of CO2 abatement relative to supercritical pf.

Technology Cost of CO2 abatement 2002

(A$/t CO2)


(A$/t CO2)


(A$/t CO2)

IGCC 201 44 -3

DFC-CCGT 76 61 34

IGCC-25% CCS 95 45 22

IGCC-75% MEA-CCS 67 42 27

O2-USC-100% CCS 31 26 21

NGCC 25 22 16

USC 28 18 -7

For 2002:

NGCC gives the lowest abatement cost of A$25/t CO2.

USC and O2-USC-95% CCS have abatement costs of A$28-31/t CO2.

IGCC (ie without capture) has the highest abatement cost of A$201/t CO2 - due to marked increases in both capital and fuel costs, and only a slight decrease in CO2.

IGCC-CCS options give abatement costs of A$67-94/t CO2.

Direct-fired coal (DFC-CCGT) gives a cost of abatement of around A$76/t CO2, between IGCC and IGCC-CCS.

For 2030:

There is a large projected decrease in the abatement costs for IGCC relative to estimates for 2002.

of 131

USC and IGCC give the lowest abatement costs of negative A$3-7/t CO2 (ie can give reduced CO2 emissions and overall generation costs, relative to SC).

NGCC has an abatement cost of around A$16/t CO2.

IGCC-CCS and O2-USC-95% CCS have similar costs of A$21-27/t CO2.

Direct-fired coal (DFC-CCGT) gives the highest cost of abatement of A$34/t CO2.

As noted previously, abatement costs are highly dependent on the base case chosen for comparison, fuel costs, efficiency loss due to capture and the efficiency of the base technology - the latter being especially significant for the non-capture technologies.

Other factors will also influence this comparison, for example credits from liquids and chemicals polygeneration options that are possible with IGCC – this will be the subject of future analysis. Another factor is technology development rates, as small changes to the experience curves now (eg due to a major RD&D effort), will have a major influence on economics in 2030.

Effect of the value of carbon

Generation costs are shown for a range of hypothetical values of carbon in Figure 5.7 and Figure 5.8. Note, that intercepts for each pair of cost curve gives the cost of abatement for a particular generation cost (eg in 2002, at A$43/MWh, the effective cost of abatement for NGCC and SC is approximately A$26/t CO2).

20

30

40

50

60

70

80

0 5 10 15 20 25 30 35 40 45 50


Pow

er c

ost (

A$/

MW

h)

SC NGCCUSC O2-USC-95% CCSDFC-CC IGCCO2-IGCC-25% MEA-CCS O2-IGCC-75% MEA-CCSO2-IGCC-75% SX-CCS

Figure 5.7 Effect of value of carbon, 2002.

of 131

20

30

40

50

60

70

0 5 10 15 20 25 30 35 40 45 50


Pow

er c

ost (

A$/

MW

h)SC NGCC

USC O2-USC-95% CCS

DFC-CC IGCC


Figure 5.8 Effect of value of carbon, 2030.

5.3 Life cycle greenhouse gas emissions

The results for greenhouse gas emissions over the entire fuel cycle are given in Table 5.5, which includes a breakdown of the CO2 emissions from the power plant, and greenhouse gas emissions from fuel production, processing and transportation (includes methane emissions for coal mining and wellhead stripping and leaks in transmission and distribution for natural gas). The overall results are compared graphically in Figure 5.9.

of 131

Table 5.5 Life cycle greenhouse gas emissions for the generation technologies modelled, (CCSD LCA values, except for UCC production14)

Technology Power station(kg/MWh)

Transportation(kg/MWh)

Processing (kg/MWh)

Total (kg/MWh)

Supercritical pf (SC) 763 4.5 20.2 787.7

Natural gas combined cycle (NGCC) 347 0 91.1 438.1

Ultrasupercritical pf (USC) 692 4.3 20.1 716.4

Ultrasupercritical pf (O2-USC-95% CCS)

46 5.4 25.4 76.8


636 3.3 14.9 654.2


713 2.7 12.4 728.1

Integrated gasification combined cycle (O2-IGCC-25% MEA-CCS)

562 9.6 13.4 585

Integrated gasification combined cycle (O2-IGCC-75% MEA-CCS)

230 3.8 17.4 251.2

Integrated gasification combined cycle (O2-IGCC-75% SX-CCS)

211 3.2 14.9 229.1

0

100

200

300

400

500

600

700

800

900

SCNGCC

USC

O2 USC-95

% CCS

DFC-C

CIG

CC

O2-IGCC-25

% MEA-C

CS

O2-IGCC-75

% MEA-C

CS

O2-IGCC-75

% SX-CCS

GG

E (t

CO

2-e/

MW

h)

Figure 5.9 Life cycle greenhouse gas emissions (kg/MWh).

of 131

5.4 Future grid projections

The overall results the five grid scenarios are summarised in Table 5.6 to Table 5.10, which show projected power demand, total grid capacity, new capacity, greenhouse gas intensity, retired power plants and projected total greenhouse gas emissions for the grid scenarios out to 2030.

The scenarios for future power generation in Australia were:

Scenario A (business as usual, new by coal)


Scenario B (high wind, new by coal)

Replacement of future power demand with 5,000 MW of wind by 2010, then maintaining 12% wind generation with the additional demand met by high efficiency coal fired plants (no CO2 capture)

Scenario C (high wind, new by gas)

Replacement of future power demand with 5,000 MW of wind by 2010, then maintaining 12% wind generation with the additional demand met by high efficiency combined cycle natural gas (no CO2 capture).


Replacement of all future power demand with renewable technologies.



Pa

ge 1

04 o

f 131

Tabl

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6 Sc

enar

io A

- re

plac

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futu

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dem

and

with

hig

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coal

fire

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stat

ions

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ess

2000

20

05

2005

-201

0 20

10-2

020

2020

-203

0

Tota

l pow

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eman

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Wh)

19

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5,00

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0,00

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0

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l cap

acity

(MW

) 44

,700

45

,800

50

,700

57

,300

65

,200

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cap

acity

(MW

) -

2,11

0 6,

500

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00

22,9

00

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cap

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ion

A$)

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21.0

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use

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mis

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Pa

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05 o

f 131

Tabl

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7 Sc

enar

io B

- re

plac

ing

dem

and

with

win

d (5

,000

MW

by

2010

then

12%

of g

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20

05

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06 o

f 131

Tabl

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8 Sc

enar

io C

- re

plac

ing

dem

and

with

win

d (5

,000

MW

by

2010

then

12%

of g

ener

atio

n 20

20-2

030)

and

CC

NG

tech

nolo

gy.

Proc

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2000

20

05

2005

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0 20

10-2

020

2020

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0

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(HH

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Add

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Pa

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07 o

f 131

Tabl

e 5.

9 Sc

enar

io D

- re

plac

ing

dem

and

with

rene

wab

le te

chno

logi

es.

Proc

ess

2000

20

05

2005

-201

0 20

10-2

020

2020

-203

0

Tota

l pow

er d

eman

d (G

Wh)

19

2,00

0 22

5,00

0 26

5,00

0 33

0,00

0 40

0,00

0

Tota

l cap

acity

(MW

) 44

,700

45

,800

52

,200

92

,200

15

0,20

0

New

cap

acity

(MW

)

2,11

0 21

,000

53

,000

73

,000

Estim

ated

cap

ital c

ost (

Bill

ion

A$)

-

- 35

.7

77.8

74

.0

Gre

enho

use

gas e

mis

sion

s (k

g/M

Wh)

90

7 88

0 72

7 42

7 13

8

Gre

enho

use

gas e

mis

sion

s (M

t/yea

r)

180

198

193

141

55

Prin

cipa

l sta

tions

ass

umed

to

be c

lose

d in

per

iod

(ie >

40

year

s old

)

- M

orw

ell,

Play

ford

B,

Bun

bury

, Muj

a A

&B

, Sw

anba

nk A

, Sw

anba

nk C

, M

iddl

e R

idge

Kw

inan

a C

, Ang

lese

a,

Torr

ens I

slan

d B

Li

ddel

l, M

unm

orah

, Val

es

Poin

t, M

acka

y G

T,

Swan

bank

B, T

aron

g,

Snug

gery

, Tor

rens

Isla

nd A

, Y

allo

urn,

Ger

aldt

on,

Kw

inan

a A

&B

, Haz

elw

ood,

Je

eral

ang

A

Bay

swat

er, E

rarin

g,

Wal

lera

wan

g, C

allid

e B

, C

ollin

svill

e, G

lads

tone

, M

uja

C&

D, J

eera

lang

B,

Nor

ther

n

New

prin

cipa

l pow

er st

atio

ns

- Sw

anba

nk E

, C

allid

e C

, Tar

ong

Nor

th, M

illm

erra

n

21,0

00 M

W o

f w

ind/

rene

wab

le a

nd/o

r 100

%

CC

S

Add

ition

al 5

3,00

0 M

W o

f w

ind/

rene

wab

le e

nerg

y fo

r to

tal o

f 74,

000

MW

of n

ew

capa

city

sinc

e 20

02

Add

ition

al 7

3,00

0 M

W o

f w

ind/

rene

wab

le e

nerg

y fo

r to

tal o

f 147

,000

MW

of

new

cap

acity

sinc

e 20

02

Add

ition

al n

otes

M

unm

orah

con

verte

d to

NG

Pa

ge 1

08 o

f 131

Tabl

e 5.

10 S

cena

rio

E - r

epla

cing

dem

and

with

100

% c

oal b

ased

CO

2 cap

ture

and

stor

age

tech

nolo

gies

.

Proc

ess

2000

20

05

2005

-201

0 20

10-2

020

2020

-203

0

Tota

l pow

er d

eman

d (G

Wh)

19

2,00

0 22

5,00

0 26

5,00

0 33

0,00

0 40

0,00

0

Tota

l cap

acity

(MW

) 44

,700

45

,800

50

,700

57

,300

65

,200

New

cap

acity

(MW

)

2,11

0 6,

500

16,6

00

22,9

00

Estim

ated

cap

ital c

ost

(Bill

ion

A$)

-

- 10

.6

22.9

28

.6

Gre

enho

use

gas e

mis

sion

s (k

g/M

Wh)

90

7 88

0 73

5 44

1 15

6

Gre

enho

use

gas e

mis

sion

s (M

t/yea

r)

180

198

195

146

62

Prin

cipa

l sta

tions

ass

umed

to

be c

lose

d in

per

iod

(ie >

40

year

s old

)

- M

orw

ell,

Play

ford

B,

Bun

bury

, Muj

a A

&B

, Sw

anba

nk A

, Sw

anba

nk C

, M

iddl

e R

idge

Kw

inan

a C

, Ang

lese

a,

Torr

ens I

slan

d B

Li

ddel

l, M

unm

orah

, Val

es

Poin

t, M

acka

y G

T,

Swan

bank

B, T

aron

g,

Snug

gery

, Tor

rens

Isla

nd A

, Y

allo

urn,

Ger

aldt

on,

Kw

inan

a A

&B

, Haz

elw

ood,

Je

eral

ang

A

Bay

swat

er, E

rarin

g,

Wal

lera

wan

g, C

allid

e B

, C

ollin

svill

e, G

lads

tone

, Muj

a C

&D

, Jee

rala

ng B

, Nor

ther

n

New

prin

cipa

l pow

er

stat

ions

-

Swan

bank

E,

Cal

lide

C, T

aron

g N

orth

, Mill

mer

ran

Coa

l fire

d po

wer

stat

ion

with

C

CS

at 3

2% th

erm

al

effic

ienc

y w

ith 9

5% C

O2

capt

ure

(HH

V)

Coa

l fire

d po

wer

stat

ion

with

C

CS

at 3

9% th

erm

al

effic

ienc

y w

ith 9

5% C

O2

capt

ure

(HH

V)

Coa

l fire

d po

wer

stat

ion

with

C

CS

at 4

2% th

erm

al

effic

ienc

y w

ith 9

5% C

O2

capt

ure

(HH

V)

Add

ition

al n

otes

M

unm

orah

con

verte

d to

NG

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The resulting annual average greenhouse intensity and annual emissions are shown in Figure 5.10 and Figure 5.11, which also show a projection of power demand to 2030. The latter are based on the projected power generation by fuel type for 2000 to 2030 in Table 5.11.

0

100

200

300

400

500

600

700

800

900

1000

2000 2005 2010 2015 2020 2025 2030

Year

Gre

enho

use

gas

inte

nsity

(kg/

MW

h)

High eff. coalWind + High eff coalWind + NGCCRenewables100% Coal CCS

Figure 5.10 Greenhouse intensity of the grid scenarios (kg/MWh).

0

50

100

150

200

250

300

2000 2005 2010 2015 2020 2025 2030

Year

Tota

l gre

enho

use

gas

emis

sion

s (M

t)

0

50

100

150

200

250

300

350

400

450

Tota

l ele

ctrii

cty

dem

and

(TW

h)

High eff. coalWind + High eff coalWind + NGCCRenewables100% Coal CCSDemand (TWh)

Figure 5.11 Projected total annual greenhouse gas emissions (Mtpa).

Kyoto target? 1990 emissions 131 Mt 2008-12 emissions 141 Mt

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Table 5.11 ABARE power generation projections by fuel type.

2000-01

(TWh)

2009-10a

(TWh)

2019-20

(TWh)

Annual growth 2000-2020

(%)

Black coal 117.8 135.8 160.5 1.6

Brown coal 51.8 56.6 62.8 1.0

Oil 2.9 2.9 2.9 0.0

Natural gas 27.5 44.1 74.4 5.4

Renewables 17.9 22.7 29.4 2.7

Hydro 16.8 - 19.6 0.8

Biomass 0.6 - 4.8 11.2

Biogas 0.3 - 2.1 11.5

Wind 0.2 - 2.9 14.8

Total 218.0 262.5 330.1 2.2

5.4.1 Effect on overall grid emissions

Scenario A - based on all new coal, reduced the greenhouse gas intensity (kg CO2/MWh) of the grid through higher efficiency SC and USC technologies for both new capacity and the replacement of decommissioned less efficient stations. By 2030 the greenhouse intensity of the grid would decrease by approximately 20%. However, the total greenhouse gas emissions would increase by approximately 67% due to the projected growth in power demand – to levels much higher than a hypothetical Kyoto target.

Scenario B – was based on 5,000 MW of wind power being installed by 2010, and providing 12% of total generation thereafter, with the remaining generation filled by higher efficiency SC/USC coal. These options give a decrease in greenhouse intensity of approximately 30% by 2030. However, the total greenhouse gas emissions would increase by 46% due to growth in demand.

This scenario requires that by 2030, approximately 22,100 MW of new wind capacity be installed, which would require installing 2.2 MW of wind capacity every day from 2003 to 2030 (assuming a capacity factor of 25%). Note, this option would require new energy storage capacity, as intermittent supplies over to 15% of the overall grid capacity is generally regarded as the maximum to manageable grid stability.

Scenario C - assumed the same increments in wind generation as Scenario B, and assumes that natural gas combined cycle is used instead of new coal capacity. In this scenario, the greenhouse intensity of the grid is decreased by 54% out to 2030, which results in a net overall reduction in emissions by approximately 5%. However, this still fails to meet the hypothetical Kyoto target.

a Interpolated using annual growth data.

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Scenario D - assumed that all new capacity is filled by wind/renewable technologies. The greenhouse intensity of the grid would decrease by 85% to 2030, and the total emissions from power generation would decrease by 68% and exceed hypothetical Kyoto targets.

This would require an extreme installation rate of renewables. At 25% capacity factor, 174,000 MW of renewable technology would need to be installed by 2030. Approximately 17.4 MW of renewable capacity would need to be installed every day, which for wind equates to around 10 large turbines per day for the next 27 years. In addition, this would need to be backed by an equivalent 17.4 MW of generation from energy storage systems, some of which could be met by fossil fuelled capacity.

Scenario E assumed that all new capacity is filled by advanced coal technology with 100% CO2 capture and storage; ie zero emissions coal-based technology. The greenhouse intensity of the grid decreases by approximately 83% (similar to the renewable scenario), and the total emissions from the grid would decrease by 64%.

note that by 2008-12, no scenarios would meet the hypothetical Kyoto target. Only scenarios D and E would meet the target by 2020, and give substantial reductions out to 2030.

5.4.2 Effect on required rate of investment in new/replacement capacity

The cumulative capital costs for new and replacement capacity are shown in Figure 5.12.

The projection shows that the lowest cost option is high efficiency coal.

The high efficiency coal with carbon capture and storage case is approximately A$20 billion more costly than the base coal case (SC/USC).

If all future generation was via renewables (wind) the cumulative capital costs to 2030 are 8-10 times that of the base coal case (includes an allowance for storage).

0

50

100

150

200

250

300

350

400

2005 2010 2015 2020 2025 2030 2035

Year

Cum

ulat

ive

capi

tal i

nves

tmen

t (B

illio

n A

$) High eff. coalWind + High eff coalWind + NGCCRenewables100% Coal CCS

Figure 5.12 Cumulative projected capital costs for the hypothetical grid scenarios.

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6 CONCLUSIONS

Technology - effect of CO2 capture on efficiency

CO2 capture for IGCC reduces the overall thermal efficiency by approximately 7-10%, due to the energy for capture and the parasitic load for CO2 compression.

CO2 capture for oxygen USC reduces the overall thermal efficiency by approximately 9%, due to the parasitic load for O2 production and flue gas compression/liquefaction.

CO2 capture and compression reduces sent out electricity by 16-23% for IGCC CCS and 18-20% for O2 USC CCS.

Economics - generation and hydrogen costs (based on A$2002)

In the near future, lowest cost generation options are supercritical and ultrasupercritical pf at A$25/MWh. This is a significantly lower cost than for IGCC, NGCC and DFC-CCGT, which have similar costs of A$33-35/MWh.

All of the technologies with CCS have generating costs, which are A$20/MWh higher – when costs are assigned to the sent out electricity. This is due to increased capital, lower availability and lower sent-out efficiency.


IGCC-CCS generation costs are projected to decrease more quickly than for the other coal-based technologies.

NGCC and DFC have almost identical costs.

Costs for CO2 pipelining and storage are 15-20% of the overall generation costs.

The current production cost of hydrogen from gasification is A$7.90/GJ (equates to A$50-60/MWh of electricity if used in a hydrogen combined cycle gas turbine).

CO2 abatement costs (based on A$2002)

In the near future, NGCC will give the lowest abatement cost of A$25/t CO2, followed by USC and O2-USC-95% CCS at A$28-31/t CO2 (costs for IGCC CCS are higher).

There is a large projected decrease in the abatement costs for IGCC over the next 30 years. By 2030 NGCC, IGCC-CCS and O2-USC-95% CCS have similar costs of A$20-27/t CO2, and direct-fired coal has the highest cost of abatement.

Meeting emissions targets

Of the 5 scenarios considered, only zero emission coal technologies and renewables are the only options, which give a marked decrease in GGE with the projected electricity demand. ZETs are the lowest cost option, with renewables costing over 800% more.

RD&D

The study has highlighted the need for more detailed assessment of the wide range of technology options available.

Given the wide range of options available, the level of improvements achieved by 2030 will be most highly dependent on RD&D commitments made now.

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7 RECOMMENDATIONS

There was considerable variance in literature values for capital costs for most of the technology combinations; a factor further compounded by the differences in scope and timing of projects, and the use of different bases for costs, efficiency and proportion of CO2 captured. Costs should be established for a number of selected technology combinations for specific sites on a semi-engineered basis (ie to a prefeasibility level of detail). The necessary details can only be obtained by working with suppliers of technology on a case-by-case basis.

IGCC options did not give favourable generation costs until ~2030. However, as IGCC offers many more options than considered in the present study, and projected costs and efficiencies are highly dependent on experience/learning rates, a more detailed analysis is required to consider the effect of RD&D on the development path for IGCC. This should include analysis for the production of liquid fuels and chemicals (polygeneration), and consider the life cycle and economic implications of a hydrogen economy. This assessment should use real options analysis to assess alternatives (in collaboration with CCSD Project P4.2).

Only three CO2 capture technologies have been studied in this project. As this technology impacts significantly on the economics, assessment of additional configurations are required to assess the implications of the full range of capture options.

Oxygen ultrasupercritical shows good economics and, while not yet demonstrated, is considered to be achievable by a major technology provider, and several overseas groups. A more detailed analysis is required, with emphasis on when this technology is likely to be demonstrated, and the scope for retrofitting (particularly for newer supercritical stations).

For simplicity, the present study has only considered black coal generation options in detail –developments in brown coal technologies (drying, IGCC and O2-USC) should result in similar overall greenhouse gas intensities and overall generation economics. Given the large reserves of soft and hard brown coals in Australia, and the different options that this coal provides, a detailed analysis of these options should be included in future analyses.

Additional natural gas options should be considered, including oxygen firing and synergies with coal; eg gas co-firing and the utilisation of coal seam methane from coal mining - options that may economically lower the greenhouse intensity of the coal chain.

Cost assumptions for natural gas and direct fired coal have received considerable comment - namely were too low. As higher costs will significantly alter the comparative cost of generation relative to the other coal options, improved estimates are required.

Retrofitting options were not considered in the present study due to adverse opinions of this technology. As the cost benefits of pf may outweigh efficiency losses, especially with small improvements in capture technology/re-engineering, retrofitting should be considered in future analyses.

The present study only considered wind energy due to the current adverse economics of alternative renewables. As all types of renewable energy are available in Australia,

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a range of grid-connected options should be included in future studies. This study should include the ability of the grid to balance a significant input from discontinuous generators without the need for storage.

There is a need to consider other benefits derived from location specific integration/synergies of options based on coal, including polygeneration, co-firing and the utilisation of biomass and other wastes.

The above recommendations should greatly contribute the understanding of the development pathways for a wide range of technology options. This will have implications both for domestic generation and export energy coals. Future analyses therefore need to consider two additional factors:

- the effects of accelerated developments from increased rates of RD&D, and the role of current Australian research programs, and

- the overall implications of these developments on coal markets.

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8 GLOSSARY – POWER GENERATION CONTEXT

Absorption Transfer of a substance into another through chemical or physical action (eg absorption of SO2 into an alkaline solution in a scrubber).

Acid gas Gases which form acids with water, eg containing amounts of CO2, SO2, H2S, or COS.

Acid rain Precipitation containing harmful levels of nitric and sulfuric acids formed mostly from nitrogen oxides and sulfur oxide emissions from combustion. Acid rain can take the form of wet precipitation (rain, snow, or fog) or dry precipitation (absorbed gaseous and particulate matter, aerosol particles or dust).

Adsorption The process of physical adhesion of the molecules of a gas, liquid or dissolved substance (in a condensed form) to a surface (eg adsorption of mercury vapour onto activated carbons). If weak chemical bonding occurs, then this is referred to as chemisorption.

Amine A family of hydrocarbon solvents used for the capture of acid gases mostly though chemical adsorption (chemisorption).

Amortization period The time over which a capital cost is recovered through a depreciation process.

Anthracite A very low volatile black or bituminous coal, often referred to as hard coal. Anthracites contain a high percentage of fixed carbon.

Aquifer A subsurface water bearing porous rock structure (stratum).

Ash Post-combustion impurities consisting of silica, iron, alumina, and other noncombustible matter that are contained in coal.

Availability The percentage of time a plant is available for operation, ie when not on down time for maintenance and repairs.

Baseload The minimum amount of electric power delivered to, or required by the transmission grid over a given period of time at a steady rate on an around-the-clock basis.

BAU Business as usual – the scenario were current trends are extrapolated into the future assuming no significant drivers for change.

Bituminous coal The most common category of black coals, and that which dominates global power generation. When mined it has a wide range of compositions, especially in ash and moisture contents.

Boiler Externally fired equipment for generating steam for power and heating purposes. Boilers have many different forms – for power generation these have large rectangular furnaces lined with water tubes (steam raising section), from which hot furnaces gases pass into tube banks for superheating

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(convective section). Boilers can use a wide range of fuels.

Capacity factor The electricity produced from a power station compared to the theoretical maximum – usually on a % per annum basis.

Carbon capture and storage

Process for removing carbon dioxide from combustion or other gases, and long-term storage (usually +1000 years). Note, CCS includes capture, transmission (pipelining) and storage.

Capital cost Overall installed capital cost – usually includes engineering construction and procurement, and contingencies for risk.

Carbon dioxide A non-toxic gas present is trace amounts (around 350 ppm by volume, or 0.035%) in the Earth’s atmosphere. Carbon dioxide is the major product of fossil-fuel combustion, and the major contributor to global warming.

Carbon dioxide equivalent The amount of carbon dioxide by weight emitted into the atmosphere that would produce the same estimated radiative forcing as a given weight of another radiatively active gas. Carbon dioxide equivalents are computed by multiplying the weight of the gas being measured (for example, methane) by its estimated global warming potential (which is 23 for methane).

Carbon sink A reservoir that absorbs or takes up released carbon from another part of the carbon cycle. There are four sinks; the atmosphere, terrestrial biosphere (usually including freshwater systems), oceans, and sediments (including fossil fuels).

Carbon tax A tax applied to the emission of gaseous carbon bearing compounds to provide incentive for industries to reduce GGE.

CCGT See combined cycle gas turbine.

CCS See carbon capture and storage.

CH4 See methane.

Claus Process A process for sulfur production which is most applicable to gas streams containing gas streams containing 20-100% H2S. The first step in the reaction is the free oxidation of one third of the H2S to SO2. The SO2 and the remaining H2S then undergo the Claus reaction both in the reaction furnace and a series of catalytic reactors.

H2S + 3/2 O2 SO2 + H2O

H2S + SO2 3 S + 2 H2O

Climate change Regional or global-scale changes in historical climate patterns arising from natural and/or manmade causes that produce an increasing mean global surface temperature, which are linked to adverse weather effects.

CO2 See carbon dioxide.

Coal A general name for a carbonaceous mineral formed from ancient vegetable matter. Coal is composed largely of carbon with smaller amounts of hydrogen, nitrogen, oxygen and sulfur.

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It is formed in various geological ages and under varying conditions and occurs in several distinct forms (eg peat, lignite, bituminous, anthracite)

Cogeneration The integrated production of electricity and heat or steam, which increases the overall system efficiency and reduced the overall cost of production.

Combined cycle gas turbine

A combined gas/steam turbine plant. Exhaust gases from the gas turbine raise steam in a heat recovery boiler that drives a steam turbine. Efficiencies can be in excess of 50% (HHV).

Combustion Burning of fuels in air or oxygen mixtures to produces heat (the chemical energy content of a fuel is converted to heat energy).

Conversion Losses A portion of the energy content of a fuel that is lost or is not useable to provide energy services due to operation of the energy conversion process.

COS Carbonyl sulfide or carbonoxysulfide. Formed in the gasifier, it can be hydrolysed to H2S, which is suitable for sulfur recovery via the Claus Process.

Crude oil A mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. Depending upon the characteristics of the crude stream, it may also include:

- Small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric pressure after being recovered from oil well (casinghead) gas in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included;

- Small amounts of non-hydrocarbons produced with the oil, such as sulfur and various metals;

- Drip gases, and liquid hydrocarbons produced from tar sands, Gilsonite, and oil shale.

Liquids produced at natural gas processing plants are excluded. Crude oil is refined to produce a wide array of petroleum products, including heating oils; gasoline, diesel, and jet fuels; lubricants; asphalt; ethane, propane, and butane; and many other products used for their energy or chemical content.

DEA Diethanol amine; see amine

Demand-side management The planning, implementation, and monitoring of utility activities designed to encourage consumers to modify patterns of electricity usage including the timing and level of electricity demand. It refers only to energy and load-shape modifying

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activities that are undertaken in response to utility-administered programs.

Electrostatic precipitator A particulate control device used to clean ash and dust from flue gases. The device operates by charging the particles inductively with a strong electric field, and particles then migrate to oppositely charged plates for removal as an agglomerated mass.

Emission(s) The release or discharge of a substance into the environment; generally refers to the release of waste products (solids, liquids, or gases) into the air, water, or soil.

Emissions trading A system of managing emissions whereby a regulatory agency specifies an overall level of pollution that will be tolerated (a cap) and then uses allowances to develop a market to allocate the pollution among sources of pollution under the cap. Emissions permits or allowances become the currency of the market, as pollution sources are free to buy, sell, or otherwise trade permits based on their own marginal costs of control and the price of the permits.

Energy efficiency The ratio of the energy produced over the energy consumed during production – usually expressed as a %. Different bases are used – on a process by process, overall process, or total s

Energy reserves Estimated quantities of energy sources that are demonstrated to exist with reasonable certainty on the basis of geologic and engineering data (proved reserves) or that can reasonably be expected to exist on the basis of geologic evidence that supports projections from proved reserves (probable/indicated reserves). Knowledge of the location, quantity, and grade of probable/indicated reserves is generally incomplete or much less certain than it it is for proved energy reserves.

ESP See electrostatic precipitator.

Experience curves Trends based on historical cost/production data used for forecasting future costs and performance of technologies.

Externalities Benefits or costs from activities that do not accrue directly to the parties involved in the activity. Environmental externalities are costs incurred through changes in the physical or biological environment due to the impacts from emissions, noise, and visual effects.

FGD Flue gas desulfurisation.

Fossil fuel A fuel extracted from a hydrocarbon deposit such as petroleum, coal or natural gas, which was derived from living matter from a previous geological time.

Flue gas A generic term for the exhaust gases from combustion; can be at various temperatures and before or after cleaning.

Fly ash Fine ash residue from the combustion of pulverised coal, typically 2-20µm.

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Fuel Any material substance that can be consumed to supply heat or power. Included are petroleum, coal, and natural gas (the fossil fuels) and other consumable materials, such as uranium, biomass, and hydrogen.

Fuel Cells One or more cells capable of generating an electrical current by converting the chemical energy of a fuel (eg hydrogen) directly into electrical energy. Fuel cells differ from conventional electrical cells in that the active materials such as fuel and oxygen are not contained within the cell but are supplied from outside. The fuel gas must be extremely high purity, eg have a sulphur content below 0.1ppm.

Functional unit The main product of a system (eg material, energy, a service). Quantified performance of a product system for use as a reference unit in an LCA (ISO)

Gasifier A reaction vessel where solid or liquid fuel are processed into gaseous fuel via the gasification process. The reactor can be a circulating fluidized bed, a bubbling fluidized bed, or an entrained flow reactor. The reactor can be pressurised or non-pressurised.

Gasification In this process, a solid fuel is first partially oxidised with air at elevated pressure, converting the fuel to a raw fuel gas called synthesis gas.

GDP See gross domestic product

GGE See greenhouse gas emissions

Gigajoule A measurement of energy – 109 joules, 3.6 GJ = 1 MWh

Global Warming An increase in the near surface temperature of the Earth. Global warming has occurred in the distant past as the result of natural influences, but the term is today most often used to refer to the warming some scientists predict will occur as a result of increased anthropogenic emissions of greenhouse gases.

Global Warming Potential An index used to compare the relative radiative forcing of different gases without directly calculating the changes in atmospheric concentrations. GWPs are calculated as the ration of the radiative forcing that would result from the emission of one kilogram of a greenhouse gas to that from the emission of one kilogram of carbon dioxide over a fixed period of time, such as 100 years.

Greenhouse effect The result of water vapor, carbon dioxide, and other atmospheric gases trapping radiant (infrared) energy, thereby keeping the Earth’s atmosphere warmer than it would otherwise be. Greenhouse gases within the lower levels of the atmosphere trap this radiation, which would otherwise escape into space, and subsequent re-radiation of some of this energy back to the Earth maintains higher surface temperatures than

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would occur if the gases were absent.

Greenhouse gases Those gases, such as water vapor, carbon dioxide, nitrous oxide, methane, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride, that are transparent to solar (short-wave) radiation but opaque to long-wave (infrared) radiation, thus preventing long-wave radiant energy from leaving Earth’s atmosphere. The net effect is a trapping of absorbed radiation and a tendency to warm the planet's surface

Grid The layout of an electrical distribution system.

Gross Domestic Product The total value of goods and services produced by labour and property located in a country. As long as the labour and property are located in the country, the supplier (that is, the workers and for property, the owners) may be either residents of that country or residents of foreign countries.

GJ See gigajoule ;

GW See gigawatt

GWh See gigawatt hour

GWP See global warming potential

Gross specific energy The maximum energy attainable from the combustion of a fuel, assuming the products of combustion are cooled to 298 K and all water is condensed.

Heat exchanger A device for transfer of heat from an area of higher temperature to one of lower temperature.

Heat recovery The process of capturing heat that normally would be wasted and delivering it to a device or process where it can be used.

Hydrocarbon An organic chemical compound of hydrogen and carbon in either gaseous, liquid, or solid phase. The molecular structure of hydrocarbon compounds varies from the simplest (e.g., methane, a constituent of natural gas) to the very heavy and very complex.

Hydrolysis Decomposition of a chemical compound by reaction with water, for example the hydrolysis of COS to H2S via the reaction COS + H2O H2S + CO2

Hydroelectric power Electricity generated by an electric power plant whose turbines are driven by falling water. It includes electric utility and industrial generation of hydroelectricity, unless otherwise specified. Generation is reported on a net basis, i. e., on the amount of electric energy generated after the electric energy consumed by station auxiliaries and the losses in the transformers that are considered integral parts of the station are deducted.

Hydrogen A colourless, odourless, highly flammable gaseous element. It is the lightest of all gases and the most abundant element in the universe, occurring chiefly in combination with oxygen in

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water and also in acids, bases, alcohols, petroleum, and other hydrocarbons.

Hydrogen economy An economy where main energy carrier is hydrogen, which can be used for central power generation, distributed generation, combined heat and power, transportation and chemicals. Hydrogen is not naturally occurring and therefore would need to be produced from other energy sources, including nuclear and renewables.

HHV See higher heating value

Higher heating value An approach for the measurement of the gross specific energy of a fuel.

Hypothetical Kyoto target Assumes that greenhouse gas emission from power generation emissions are proportional to Australia’s overall Kyoto target.

Installed capacity Total electricity generating capacity of a power station or grid; cf MCR capacity.

IGCC See integrated gasification combined cycle

IGSOFC Integrated gasification solid oxide fuel cell

In situ leach mining The recovery, by chemical leaching, of the valuable components of an ore body without physical extraction of the ore from the ground. Also referred to as “solution mining.”

Insolation The amount of radiation from the sun received at the surface of the earth in a particular geographic location or region.

Integrated gasification combined cycle

IGCC is a coal-fired, combined cycle electric power generation technology with post-combustion emission controls. The four major processes in an IGCC facility are: 1) converting coal into a fuel gas, 2) cleaning the fuel gas, 3) using the clean fuel gas to fire a gas turbine generator and using the hot turbine exhaust to make steam that drives a steam turbine generator, and 4) treating waste streams generated. Gasification of coal allows pollutant carriers?? to be removed from the fuel before its combustion in the power plant. Emissions of sulfur and nitrogen oxides and particulates from IGCC facilities are projected to be significantly lower than for existing technologies.

ISO International Standards Organisation.

Joule The metre-kilogram-second unit of work or energy, equal to the work done by a force of one Newton when its point of application moves through a distance of one meter in the direction of the force; equivalent to 107 ergs and one watt-second. Represented by the unit “J”.

Kilojoule A measurement of energy – 1,000 J

Kilowatt A measurement of power – 1,000 watts where 1 kW = 1 kJ/s

Kilowatt hour A measurement of energy production or consumption – equivalent to production power or consumption load of 1 kW

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for a period of 1 hour. 1 kWh = 3600 kJ

kJ See kilojoule

kW See kilowatt

kWh See kilowatt hour

Kyoto Protocol The result of negotiations at the third Conference of the Parties (COP-3) in Kyoto, Japan, in December 1997. The Kyoto Protocol sets binding greenhouse gas emissions targets for countries that sign and ratify the agreement. The gases covered under the Protocol include carbon dioxide, methane, nitrous oxide, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride.

LCA Life cycle analysis or life cycle assessment

Life cycle analysis/assessment

Analysis of the impacts (eg energy, environmental or economic impacts) of a system over its complete lifetime from creation to destruction, sometimes including the lifetimes of key constituents and components.

Life time Time plant is in service from construction to decommissioning, for the specified availability.

Lignite The lowest rank of coal, often referred to as brown coal, used almost exclusively as fuel for steam-electric power generation. It is brownish-black and has a high inherent moisture content.

Liquefaction The act, process, or method, of reducing a gas or vapour to a liquid by means of cold or pressure; as, the liquefaction of oxygen or hydrogen.

Liquefied natural gas Natural gas product cooled to below it boiling point (-161°C), usually for sea transportation.

LNG See liquefied natural gas.

Load The amount of energy (eg electric) needed to meet a requirement for an energy service by energy consuming equipment at any specific point in a system.

Load management Use of power management techniques such as off-peak generation capacity to better match power supply with load demand so that generating resources are used to maximum efficiency.

Maximum continuous rating

The rating (MW) of a power plant unit running at 100% load.

MCR See maximum continuous rating

MDEA Methyl diethanolamine. See amine.

MEA Monoethanolamine. See amine.

Megajoule A measurement of energy – 1,000,000 joules

Megawatt A measurement of power – 1,000,000 watts where 1 MW = 1 MJ/s

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Megawatt hour A measurement of energy production or consumption – equivalent to production power or consumption load of 1 MW for a period of 1 hour. 1 MWh = 3600 MJ

Membrane A thin film or structure that selectively retards mixing or permits separation of one or more fluids.

Methane A hydrocarbon gas that is the principal constituent of natural gas. Methane has a 100-year GWP of 21.

Methanol A light alcohol that can be used for as a transportation fuel or as a raw material for other chemicals.

Methanogen Archaebacteria found in anaerobic environments, capable of producing methane (as also exists in digestive tracts and in sewage).

METSIM A process modelling software package originally designed for the simulation of metallurgical processes but has evolved into a high powered general process modelling tool.

MJ See megajoule.

MW See megawatt.

MWh See megawatt hour.

N2O See nitrous oxide.

Natural gas A gaseous mixture of hydrocarbon compounds, the primary one being methane.

NEM National Electricity Market

NEMMCO National Electricity Market Management Company

Net specific energy As for gross specific energy, except that assumes no condensation of water vapour from the products of combustion.

NG See natural gas.

NGCC Natural gas combined cycle.

NIEIR National Institute of Economics and Industry Research, Australia

Nitrous oxide A colourless gas, naturally occurring in the atmosphere. Nitrous oxide has a 100-year GWP of 310.

NOx Any oxide of nitrogen of the form NOx eg NO2, NO not N2O.

Oil reservoir An underground region of liquid hydrocarbons (together with smaller amounts of sulfur, oxygen, and nitrogen) trapped within a geological formation and protected from evaporation by the overlying mineral strata.

Oil Well A well completed for the production of crude oil from one or more oil zones or reservoirs. Wells producing both crude oil and natural gas are classified as oil wells.

Operating cost Overall cost of power generation which includes allowances for capital, R&M, labour and operating costs. The capital cost

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includes allowances for contingencies

Oxidize To chemically transform a substance by combining it with oxygen.

OTE See overall thermal efficiency

Overall thermal efficiency Efficiency after accounting for all electricity consumption and other power for auxiliary or parasitic loads at the power station. Other terminology – sent out or export thermal efficiency.

Parabolic Dish A high-temperature solar thermal concentrator, generally bowl shaped, with two-axis tracking.

Parabolic Trough A high-temperature solar thermal concentrator with the capacity for tracking the sun using one axis of rotation.

Parasitic load Electricity consumed by machinery required for the production of electricity reducing a power stations overall thermal efficiency.

Peak load The maximum load during a specified period of time.

Perfluorocarbons A group of man-made chemicals composed of one or two carbon atoms and four to six fluorine atoms, containing no chlorine. PFCs have no commercial uses and are emitted as a by-product of aluminium smelting and semiconductor manufacturing. PFCs have very high 100-year Global Warming Potentials and are very long-lived in the atmosphere.

Petroleum A broadly defined class of liquid hydrocarbon mixtures. Included are crude oil, lease condensate, unfinished oils, refined petroleum products obtained from the processing of crude oil, and natural gas plant liquids. Note: Volumes of finished petroleum products include non-hydrocarbon compounds, such as additives and detergents, after they have been blended into the products.

Pet coke Petroleum coke. A solid carbon rich and low-ash residue from the oil refining process. Often used in steelworks coke blends and in gasification processes.

Petroleum products Products obtained from the processing of crude oil (including lease condensate), natural gas, and other hydrocarbon com-pounds. Petroleum products include unfinished oils, liquefied petroleum gases, pentanes plus, aviation gasoline, motor gasoline, naphtha-type jet fuel, kerosene-type jet fuel, kero-sene, distillate fuel oil, residual fuel oil, petrochemical feedstock’s, special naphtha’s, lubricants, waxes, petroleum coke, asphalt, road oil, still gas, and other miscellaneous products.

Pf See pulverised fuel

PFCs See perfluorocarbons

Photovoltaic energy Direct-current electricity generated from sunlight through solid-state semiconductor devices. This energy is usually converted to alternating current for use by conventional

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equipment by electrical devices called inverters. This is also required for grid transmission and distribution.

Photovoltaic module An integrated assembly of interconnected photovoltaic cells designed to deliver a selected level of working voltage and current at its output terminals, packaged for protection against environmental degradation, and suited for incorporation in photovoltaic power systems. Currently mostly used for remote power, such as radio communication, cathodic protection, and navigational aids.

Plant A term commonly used either as a synonym for an industrial establishment or a generation facility or to refer to a particular process within an establishment

Pollution Any substances in water, soil, or air that degrade the natural quality of the environment or cause health issues. Other impacts can include offensive smells or visual effects, noises.

Power loss The difference between electricity input and output as a result of an energy transfer between two points – due to a number of factors including resistance, inductive losses and power factor.

Pressurized fluidized bed combustion

Burning of coal in a reactor comprised of a bed through which gas is fed to keep the fuel in a turbulent state which improves combustion, heat transfer and recovery of waste products.

Pulverised fuel Finely divided fuel, mostly with a mass mean size of 60-70 µm.

PV Photovoltaic(s)

Pyrolysis The thermal decomposition of a suitable solid material (e.g. hydrocarbon or biomass) at high temperature in the absence of oxygen.

R&D Research and development

R&M Repairs and maintenance

RAM Repairs, availability and maintenance

RD&D Research, development and demonstration

Refinery An installation that manufactures finished petroleum products from crude oil, unfinished oils, natural gas liquids, other hydrocarbons, and alcohol.

Reforestation Replanting of forests on lands that have recently been harvested or otherwise cleared of trees.

Reinjected of natural gas The forcing of gas under pressure into an oil reservoir in an attempt to increase recovery.

Renewable energy Renewable energy sources are those which are not sourced from fossil fuels or nuclear energy, ie hydroelectricity, wind, biomass, solar thermal, photovoltaics, etc.

Repressuring Injection of a pressurized fluid (air, gas, or water) into oil or

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gas reservoir formations to effect greater ultimate recovery

Reservoir A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system

Residual oil One of the low-grade oil products that remain after the distillation of petroleum, used in adhesives, roofing compounds, and asphalt manufacture.

Resource Any material sourced in its natural state of occurrence (ie before mining).

Resource depletion Depletion of natural reserves – can be regional or global.

Resource energy The energy from primary non-renewable sources, eg coal, NG, oil, does not include electricity, diesel etc (secondary sources).

SC See supercritical steam

Selexol Allied Chemical Corp process from 1960’s used to selectively capture acid gases from natural gas using a mixture physical solvents - dimethyl ethers of polyethylene glycol.

Sent out efficiency See overall thermal efficiency

Sequestration Originally referred to the conversion of atmospheric CO2 into plant matter (ref Kyoto Dec 1997) – ie a biological process. Although this terminology has been used to refer to CO2 capture and storage from combustion via chemical processes, this is being replaced by the term carbon capture and storage.

Sequestration ready Suitable for retrofitting to enable CO2 capture and compression for storage.

SF6 See sulfur hexaflouride

Shift reaction Refers to the water-gas shift reaction where effectively carbon monoxide is converted to hydrogen (CO + H2O CO2 + H2) usually in the presence of a catalyst. The extent of the reaction is determined mainly by the temperature and pressure. Usually to shift all carbon monoxide to hydrogen, up to three separate shift reaction s are required, with CO2 removal between shifts.

SO2 See sulfur dioxide

Solar thermal Utilisation of solar energy by conversion to heat. This usually involves concentrating the suns rays by mirrors. The most common form is the solar hot water heater.

SOx See sulfur oxides

SPM See suspended particulate matter.

Steaming coal Coals used for combustion, mostly to generate steam of power generation. Usually is a lower quality (higher ash and moisture) than is used for metallurgical applications such as

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coke making.

Sub-bituminous coal A lower rank (ie lower degree of coalification) black coal (eg Leigh Creek coal), sometimes categorized as lignites. The lower rank makes this coal unsuitable for coke making, and together with a higher moisture and oxygen content, results in a lower heating value - mostly used for electricity generation.

Subcritical steam Temperature and pressure is generally in the range of 16-18 MPa and a temperature of 520-550°C; ie below the critical point of water.

Sulfur A minor component of coal. As concentrations vary widely, (0.2-8%) this affects coal utilisation and the emissions of SOx. Sulfur is most deleterious in gas turbines and fuel cells.

Large amounts of sulfur compounds, especially sulphuric acid, are used in many industrial processes.

Sulfur dioxide A toxic, irritating, gas, an emission from most combustion processes, which is controlled by a range of technologies.

Supercritical steam Steam temperature and pressure above the critical point of water; generally refers to pressures of 23-30 MPa and steam temperatures of 550-566°C. More extreme conditions are called ultrasupercritical.

Suspended particulate matter

Fine suspended solids, most of which have a range of environmental and health impacts. For power generation this usually refers to dust generated from mining and power station stacks. Levels are generally categorised by size; eg PM10 is the concentration of particulars smaller than 10 micron .

Syngas See synthesis gas.

Synthesis gas A gas manufactured from petroleum or coal gasification. It is usually substituted for higher cost natural gas, though may have significantly different properties.

Systems assessment Assessment based on tools and methods that consider the broader or total systems context. This usually requires an integration of a number of these techniques, eg overall process modelling, LCA, and economic models.

System boundaries The interface between a product system and the environment or other product systems.

Terawatt 1012 watts - a measurement of power (or the rate of doing work).

Terawatt hour 1012 watt-hours - a measurement of energy production or consumption, expressed as an equivalent to number of TW for a period of 1 hour. 1 TWh = 3600 TJ. A single 660 MW unit at a NSW power station could generation 5.8 TWh of power

Transmission The transfer of mass or energy over an interconnected group of wires or conduits. In the present report it relates mostly applied to electricity, but is also used to refer to the movement

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of natural gas, liquid hydrocarbons and CO2.

Transmission becomes distribution, when energy (or mass) is transformed for distribution to the consumer – usually by decreasing the voltage or pressure.

Transmission and distribution loss

For electric energy lost due to the transmission and distribution of electricity, mostly due to line resistance and inductive losses, and transformer losses. For gases this refers to gas used to provide pumping energy and in leaks.

Turbine A machine for converting energy of a stream of fluid (such as water, steam, or hot gas) into rotating mechanical energy. The thermodynamic efficiencies are usually 40-55%.

TW See terawatt

TWh See terawatt hour

Ultra-supercritical steam Any super critical steam conditions where the steam temperatures excess of 566°C (usually as reheat or at the main steam valve).

UCC Ultra Clean Coal; a White Industries trade name for very clean coal, which removes ash and sulphur to enable coal to be used in place of natural gas and some liquid fuels in gas turbines. This is termed direct fired coal, as distinct from coal which is gasified to produce a syngas to fire a gas turbine.

UCG Underground coal gasification; a technology where coal is converted to syngas underground and in-situ by gasification via bore holes drilled from the surface.

USC An ultra-supercritical steam power plant; see ultra-supercritical steam.

Vacuum residue A heavy oil residue from vacuum distillation (oil refinery) containing asphaltenes and trace metals found in crude oil.

Value of carbon Generic terminology to represent either imposed cost, credit, societal value, or externalised value for greenhouse gases.

Visbreaker tar/residue A heavy oil residue from the visbreaker unit (oil refinery). It is a slightly lighter material than vacuum residue.

Volatile matter Those products, exclusive of moisture, given off by a material as gas or vapour. Volatile matter is determined by heating the coal to 950°C under carefully controlled conditions and measuring the weight loss, excluding weight of moisture driven off at 105°C

Waste Heat Heat energy produced in an energy conversion or transfer process that is lost during conversion or transfer and is not available for useful purposes.

Wind power Electricity production from wind turbines or wind mills, and usually refers to the electricity as delivered to the grid, and without storage.

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