The ZeroGen Integrated Gasification Combined Cycle (IGCC) with CCS project, was a first-of-a-kind, commercial-scale CCS project proposal in Australia. Lessons learnt from this project include real-life project management experience integrating the key elements of a large-scale CCS project, from the technical to the commercial to stakeholder management. This webinar was presented by Professor Andrew Garnett, Director, Centre for Coal Seam Gas, The University of Queensland. The Q&A session also included Martin Oettinger, Deputy Director, Low Emissions Technology for ACALET. Martin's career includes 6 years in a senior technical leadership role with ZeroGen.

1. CCS major project development lessons from the
ZeroGen experience
Webinar – 21 August 2014, 1700 AEST

2. Professor Andrew Garnett
Director, Centre for Coal Seam Gas, The University of Queensland
Professor Andrew Garnett is a newly appointed Professor
and Director of the University of Queensland CCS Program
in the UQ Energy Initiatives (he is also Director at the UQ
Centre for Coal Seam Gas).
A former Shell and Schlumberger executive, Andrew has
over 25 years’ worldwide experience with oil majors in
conventional and unconventional hydrocarbon exploration,
appraisal and development projects.
Prior to joining the University of Queensland, Andrew
consulted widely on unconventional and acid gas
developments, most notably those with high GHG
emissions footprints, and worked on the 500MW, 60 MT
ZeroGen IGCC & CCS Project, as manager for Carbon
Transport and Storage and ultimately as CEO and Project
Director.

3. Martin Oettinger
Deputy Director, Low Emissions Technology, ACALET
Martin Oettinger is Deputy Director, Low Emissions
Technology for ACALET (Coal21 Fund), aimed at
facilitating the early demonstration of low emissions black
coal technologies.
Prior to this he was Principal Manager – Carbon Capture,
for the Global CCS Institute. Martin has over 30 years’
experience in senior technical, leadership and
management roles for a range of blue-chip Australian and
international corporations in the power, mineral and
hydrocarbon processing industries.
The last 15 years of his career have involved large-scale
first-of-kind developments, including 6 years in a senior
technical leadership role with ZeroGen.

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5. CCS Major Project Development
Lessons from the ZeroGen Experience
Confidential
Prof. Andrew Garnett
UQ Energy Initiative
Director, CCS
(former CEO & Project Director ZeroGen)
Disclaimer:
The views presented in this presentation do not necessarily represent
the views of ZeroGen, its former directors, former funders or the
University of Queensland.

6. Background & Context
► ZeroGen Pty Ltd was fully owned by the Queensland State
Government and sponsored by Federal Government & the Australian
Coal Association (ACALET). It was established to …
► “Facilitate the development and accelerated commercial
deployment of low emissions coal technology to preserve
Queensland’s competitive position in power generation and to
ensure the continued mining use and exploration of
Australian black coal”.
► Configuration
► IGCC with CCS
► 530 MW (gross) 391 MW (net)
► Capture
► 65% ~ 2 mln tpa
► 90% ~ 3 mln tpa 250MW plant at Nakoso constructed by MHI MHI
Confidential

7. Location of Project
Confidential
Nth Bowen
Basin
Surat
Basin
Gladstone
Brisbane
ZeroGen Tenements
Emerald
Miles
Roma

8. Evolving Scope
80MW IGCC
75% Capture +
Pipeline
80MW Demo
+ Trucking
3.3 mln t
84 mln t
ZG1 ZG2 ZG3,ZG4,ZG5,ZG6 ZG7,ZG8,ZG9,ZG10,ZG11,ZG12
2000
1500
1000
500
Confidential
Design/Build Injection Skid Injection Test
0
‘000 T CO2 PA
2006 2007 2008 2009 2010 2011
DP-1
9 mln t
DP2b
120MW
DP2a
3000
2500
Scope /
MW
Gasif. Power Solvent etc % capture
100/200 Noell GE/Siemens Selexol 90%
200 Shell GE 9E Selexol 75%
47 Shell GE 6B E Sulferox,
Sulfinol
75%
87 Shell GE 6FA Genosorb-sulferox
75%
120 Shell GE
400 MHI MHI 701G2 Selexol 65-90%
60 mln t
Clean Coal
Council Approval
of 530MW Plant
Potential Rate
to be
Sequestered
Tenements in
Surat released
Flagship
2015
Flagships Jun 10
PFS Report Jul 10
Alt basins
studies

9. IGCC with CCS – PFS Configuration
Coal
handling,
grinding and
drying
Confidential
ASU
Gasifier &
Syngas
Cooler
Slag, Waste
Water and
Solids
Handling
CO Sour Shift
CO+H2O
-> CO2 + H2
Water
Treatment
Location - B Location - D
Raw Water
CO2
Compression
&
Dehydration
Solexol AGR
& CO2
Removal
Wet Sulphuric
Acid Plant
Sulphuric
Acid Handling
& Export
Syngas
CCGT Power
Block
Substation
Transmission
Lines
CO2 Pipeline
(? Boosters)
CO2 Storage
Field
Location - A
Location - C
Location - E
composition, pressure(t)

10. And so … lessons ?
Confidential

11. AGAIN ! Cost Estimate Growth vs. Engineering Effort
• RAND corp study – (an alternative look-ahead view)
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
Duke Edwardsport 2006-2012
0 1 2 3 4 5
Ration of Estimate to Initial (class 0) estimate.
Approx. Estimate Class
• RAND corp study – 1981 (a look back view)
Ratio of estimate to Final Cost
Estimating Maturity
completion
ZeroGen Scoping to end PFS
$4.3B
$6.9B
1. % of capital cost in new technology compared with the capital cost of the
entire plant,
2. complexity of the plant, - the number of continuously linked process units,
3. the degree of project definition, and
4. the degree of process definition.

12. Costs to end PFS
Cost Group Estimated Cost
(M AUD)
% of Total
COStorage Prior to PFS period (6 wells) $48.0
2 all configs. PFS period (6 wells) $53.6 73.5%
Power Plant with
Engineering $14.71
Capture
13.9%
final config. only Coal Studies & Testing $2.43
Site Selection $1.87
Operations & Maintenance Studies $0.26
Environmental Studies $2.68 1.9%
Stakeholder Engagement $0.81 0.6%
Commercial
Capital & Operating Cost Estimates $0.31
Studies
Power Revenue & Trading $0.20 0.9%
Financial Modelling
$0.35
Financing Studies
$0.40
Project Management & Controls $4.08 3.0%
Corporate Administration, Financing Studies, etc $8.6 6.2%
Total Study Expenditure $138.3

13. From end PFS – CtG … Capital Cost Estimates
• Prefeasibility Study Estimated TIC of $6.93 billion, including escalation to
2016 start-up [cf $4.3 billion in scoping study- Oct 2008 Basis]
Main Project Cost Area AUD billions % Total
ZG Owner’s Costs $ 0.30 5%
Enabling Works $ 0.62 11%
Power Plant incl. Balance of Plant $ 3.90 68%
Carbon Transport & Storage (scoping) $0.80 14%
Operations Readiness & Start-up $0.14 2%
Total Base Cost Estimate $5.76 100%
Direct project contingency $ 0.52 9%
Escalation $0.65 11%
Total Fully Load Capital Cost $6.93

14. Reconciling the Cost Increases
It’s about design maturity, Australian productivity and site specific issues
[ $4.3 B AUD to $6.29 B AUD incl. contingency]
May 2010
Basis
Escalation
2016

15. Decision to discontinue
In November 2010, ZeroGen management advised closure of the ZeroGen
commercial scale IGCC with CCS demonstration project due to:
• very high capital and operating costs which could not be supported by
anticipated revenue streams;
• technical risks around the CO2 capture technology and project
integration; and
• lack of credible project funding opportunities to achieve financial close.
• inability of the Northern Denison Trough storage resource to
accommodate the sustained injection rates or volumes of CO2 required
by the project;
• uncertainty as to the timely award of sufficient tenure and funding
necessary to successfully appraise an alternative CO2 storage resource;
• AND also advised that lessons be documented (an activity which was concurrent with
project close-out, surrender of licenses and final members’ voluntary liquidation)

16. Key Lessons Learned - SUMMARY
1. Markets & Economics: Industrial–scale in Aust. is simply not economic or
supportable
2. Scale: Industrial–scale is not a simple scale–up from demo. scale
3. Risk Mgmnt: Careful pace of ‘first’ projects is critical to wider deployment.
4. Risks Mgmnt : Pre–FEED and feasibility risks and costs are heavily
weighted to the search for storage.
5. Risks Mgmnt : Storage is a natural resource, a portfolio exploration and
appraisal approach is needed.
6. Clear Storage Goals: When defining storage resources requirements it is
essential to discuss the consequences and trade–offs between injection rate
and/or cumulative volume objectives.
7. FEL costs: Very high front–end engineering loading is needed for first–of–a–
kind.

17. Key Lesson Learned ... #1
• Industrial–scale, low emissions coal–fired power projects
incorporating CCS are not currently economic (in the Queensland,
Australia context) – costs are well above published costs
• While limited funds are potentially available from strategic investors such as the coal
industry and technology providers, the project team for this FOAK project identified a
large funding gap which could not be closed.
• Deployment and operating costs for ZeroGen were at (beyond) the upper limit of
published ranges.
• FOAK low emissions coal–fired power projects that incorporate CCS have very high
capital and operating costs and with forecast electricity and carbon prices, will
generally not be financially viable.
• Would require significantly heavier & more ongoing gov. financial support than
previously thought.
• Low emissions coal–fired power projects must rely on large capital and operating
subsidies, the majority of which governments will be required to fund.
• This is exacerbated in Australia, where strong levels of major resource project activity
in the creates skills shortage adversely impacting labour cost and productivity.

18. Key Lesson Learned … #2
• Industrial–scale is not a simple scale–up from demonstration–scale
• ZeroGen experience: for full comprehension CCS projects should be at commercial
scale.
• Only at this scale that significant reality checks can be made regarding schedule, cost
and performance predictions
• Only at this scale that the main locally–relevant deployment challenges emerge and can
be understood.
• Desk–top analyses proved inadequate.
• For storage, a significant acquisition and evaluation (drilling, testing and seismic)
program proved to be necessary and this should have been conducted well before
significant power plant engineering commenced.
• Such exploration and appraisal programs are, by their nature, subject to significant
uncertainty as is the level of funds at risk.
• The scale of funds available for such programs should be flexible and large enough to
provide a portfolio chance of success in line with the risk tolerance of the funders.

19. Key Lesson Learned … #3
• Measured management of pace of ‘first’ projects is critical to wider
deployment
• First CCS projects carry the burden of ‘proof’ for follow–up wider deployment.
• Risk management, approaches to Environmental Impact Assessments and public
consultation will need to be conservative and with measured (slow) pace.
• This requirement runs counter to any urgent push or mandate for an early operational
start date (or to spend budget in any calendar year !).
• ZeroGen experience suggests that, at least in the case of IGCC, CCS project
schedules need to be risk optimised, such that larger investment decisions in plant and
capture are not taken before achieving sufficient confidence that
– storage is present ?
– will perform as required ?
– is licensable and acceptable ?

20. Risk Optimised Project Scheduling
“pre-project”
Confidential
DG7
Appraisal of
Selected Sites
IR IR
IR
Screening DG1 DG5 Field Development
Planning
EIS &
Approvals
Develop
Field
Project
Completion
IR
IR IR
Feasibility
& BED
Construct
Inject
Operate
Closure
FEED
IR
CO2
TRANSPORT &
CAPTURE
CO2
STORAGE
Exploration
Scoping
DG2 DG3
Prefeasibility
IR
DG4
Detailed
Engineering
DG6
IR
DG8 FULLY INTEGRATED
CCS DEVELOPMENT
IR IR
IR
Note: the CO2 Transport and Capture Prefeasibility stage
may also be delayed until after the Storage Appraisal of
Selected Sites, depending on the residual post-Exploration
risk and the estimated cost of the Prefeasibility Study.

21. Key Lesson Learned … #4
• Pre–FEED and feasibility costs, risks and uncertainties are heavily
weighted to the search for storage
• Prior to Front End Engineering Design (FEED) and probably prefeasibility stages for an
integrated CCS project, the majority of at-risk expenditure lies in finding and appraising
storage resources to a sufficient level of confidence (in storage security and sustained
injectivity) to justify a larger investment in plant engineering.
• In ZeroGen’s case:
– over 70% of expenditure to end PFS was related to storage (and this was to ultimately establish
the site was not appropriate)
– 20% to plant and capture.
• Forecasts to evaluate an entirely new storage area to a mature stage of
characterization would have resulted in over 90% of costs, to the end of prefeasibility,
being storage related.
• Note especially that commonly available storage “Atlas” type estimates, based on
pore-space corrected, volumetric estimates should give NO confidence that
appropriate, rate matched storage is available.

22. Lessons: Storage pre-project works ?
• Prior to site-specific characterisation storage uncertainties and risks are high.
– Are there any storage resources that can perform as required ?
– If so, then how much and are they developable ?.
• Exploration plans must include a risk-diverse portfolio of prospects.
– Risks should be diversified in geology, environmental, technical,
overlapping-resources, community and public acceptance ...
• BUT, without more drilling and dynamic testing we simply do not have a handle on how much practical storage
there is.
ZeroGen Northern Denison
Trough
QLD storage Atlas1 BWW
“High Prospectivity” Basin
(Bradshaw et al, 2009)
1 Bradshaw et al (2009)
Confidential
Desktop Studies
static capacity in
ZeroGen acreage.
Results from ZeroGen Drilling, Testing & FDP
Effective resource
(technical FDP
constraints only)
Contingent
capacity (limited
only by FDP
and project
lifetime)
Practical
Capacity
(unit cost,
project and rate
constrained)
Aldebaran,
Freitag & Cath.
QLD Atlas
50 – 90 mln t
Catherine ~ 10 mln t
Aldebaran,
Freitag & Cath.
Zerogen
80 – 100 mln t Catherine was found to be main practical formation
Catherine 20 – 30 mln t
54 mln t
(takes 120 yrs to fill)
25 mln t
(at >$140/t, CTS)
ZERO tonnes

23. Key Lesson Learned … #5
• Storage is a natural resource, a portfolio exploration and appraisal
approach is needed
• Exploration and appraisal of potential storage sites requires a portfolio approach to
create multiple options to allow for some sites which might be found to be ‘unsuitable’.
• A large amount of expensive data gathering should be expected and while success
rates might be higher than in the oil and gas exploration sector, delays and escalating
costs are still likely to be significant with storage exploration. Costs are at-risk.
• Storage exploration and appraisal data acquisition and study programs should be
focused on reducing large geotechnical uncertainties (containment & sustained rate).
• Acquiring data and conducting analyses which can quickly polarise the suitability or
otherwise of a site are of highest appraisal value and may allow for a rapid reduction in
the need for further exploration spending. It’s cheaper to seek data which “kills” an area!
• It is essential to develop clear storage decision criteria, with both confidence levels and
performance targets, which will define whether subsequent stages of (often larger)
investment in plant should go ahead. You have to know when to stop!

24. Key Lessons Learned … #6
• When defining storage resources requirements it is essential to discuss the
consequences and trade–offs between injection rate and/or cumulative
volume objectives
• Storage resources and field developments which match specific injection rate requirements
are likely to be significantly different from (unrelated to) those which must only fulfill a
cumulative volume target.
• Appraisal of storage site and predictions of ‘reserves’ and performance must be based on
long term, dynamic well testing (production or injection) and not on static–based derivations
of capacity as is currently the case for most published estimates. Testing with CO2 is not
technically necessary (at least not initially).
• In addition to extended well tests, conceptual, engineered field development plans are
essential and need to be constrained by real surface and environmental factors and
potential sub–surface risk features.
• Development drilling sequences need to be simulated to account for static and
dynamic uncertainties and show how injection rate might be installed over time
and might need to be maintained by in–fill drilling or venting or development of and
transport to other sites.

25. Key Lessons Learned … #7
• High front–end (engineering) loading is needed for first–of–a–kind
• Integrating CO2 separation technologies with power generation is not mature and there
remain significant technical risks. Integration itself is not mature especially at location.
• Proponents must recognise that these projects are technically complex and it is not just
a matter of ‘integrating well understood, proven technologies’. Such statements
understate the challenges (incl. local context) and set unreasonable stakeholder
expectations for project development schedule and cost and, potentially, for plant start–
up performance and availability.
• Significant further technical development and engineering is required to provide
confidence in plant design and performance (especially in an electricity market context).
• Furthermore, if FOAK projects are to be economically viable then, notwithstanding
currently immature ‘breakthrough developments’, significant developments in
commercial terms and project financing as well as significant technical improvements
will be required.
• Funding arrangements must sustain an organisation through the project reviews and
decision making processes and hiatuses that are inevitable between phases of a
project.

26. Thanks and Acknowledgements
► This presentation is made possible
through the willingness of the ZeroGen
funding bodies to share lessons from the
project.
► The ZeroGen funders were:
► the Queensland Government (DEEDI)
► Australian Coal Association (ACALET)
► the Australian Government (DRET).
► Continued funding of the role of CCS Director at
UQ has been provided by ACALET
Confidential

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View the report: http://www.uq.edu.au/energy/docs/ZeroGen.pdf