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Issue No. 121
December 2012 / January 2013
www.pnronline.com.au
unconventionals:
Black Swans Spread
Their Wings At AAPG
industry news:
NOPSEMA ‘Offside’ As Companies Cry
Foul Over ‘Heavy-Handed’ Regulations
seismic technology:
The Value Of PRM In
Enabling High Payback IOR
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#121
In this issue...
editor’s comment........................................................................................................................................ 6
The Answer is 42
president’s report ...................................................................................................................................... 8
Year End Report
diary of events ............................................................................................................................................. 10
uncle duster’s opinion repository ............................................................................................... 12
Uncle Duster’s Year In Review
On the cover:
A ‘Black Swan Event’ is a term used
to describe an unlikely event – quite
understandable unless you happen
to live in Western Australia.
See story on page 14.
© iStockphoto.com/Craig Dingle
unconventionals ......................................................................................................................................... 14
Black Swans Spread Their Wings At AAPG
Moving Australian Coalbed Methane Reserves Into Production Through Reservoir
Simulation
SA Unconventional Gas Update
branch activities .........................................................................................................................................22
Students’ Thesis Abstracts
Curtin Geology Student Society (GEOS) Quiz Night
industry news ...............................................................................................................................................24
NOPSEMA ‘Offside’ As Companies Cry Foul Over ‘Heavy-Handed’ Regulations
Beach Energy’s Cooper Basin Resurgence Continues
Bauer Field May Hold More Oil
Central Petroleum And Total Announce Strategic Alliance For Exploration In Southern
Georgina Basin
Energy White Paper Welcomed By Santos But Mixed Feelings From APIA And DomGas
Hackers Posing A Threat To Industry
DownUnder GeoSolutions Appoints New COO
Buru Pens State Agreement For WA Domgas
Australian LNG Producer Santos Sees LNG-Price Remaining Linked To Oil
Gas Discovery At Crown In The Browse Basin
Poland Woos Shale Gas Investment

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pesa resources
news
Published for:
Petroleum Exploration Society of Australia Ltd
(A.B.N. 12 009 061 278: Inc. in WA)
Publisher:
Brian Wickins
RESolutions Resource & Energy Services Pty Ltd
PO Box 24 Innaloo City WA 6918
Ph: +61 8 9347 9400 Fax: +61 8 9244 3714
Email: brian@resolutions-group.com.au
Web: www.resolutions-group.com.au
Editor:
Adrian Williams
Ph/Fax: +61 8 9474 6640
Email: carm@iinet.net.au
Advertising:
Louise Street (Sales & Marketing Manager)
Email: louise@resolutions-group.com.au
Darren Hagen (Marketing & Development Manager)
Email: darren@resolutions-group.com.au
Alison McLeod (Sales & Marketing)
Email: alison@resolutions-group.com.au
Editorial:
Dale Granger (Senior Journalist)
Email: dale@resolutions-group.com.au
Troy Douglas (Journalist)
Email: troy@resolutions-group.com.au
Graphic Design:
Katharina Ott
Email: katharina@resolutions-group.com.au
PESA News Resources (Issue No. 121) is published under the
authority of the Federal Executive of the Petroleum Exploration
Society of Australia Ltd (PESA). Reproduction of material in
whole or part requires the customary acknowledgements.
All expressions of opinion in PESA News Resources are
published on the basis that they are not to be regarded as
expressing the official views of the Petroleum Exploration
Society of Australia Ltd unless expressly stated. The Society
accepts no responsibility for the accuracy of any of the
opinions or information contained in this newsletter and
readers should rely upon their own enquiries in making any
decisions touching upon their own interests.
Deadlines
PESA News Resources is published bi-monthly. The deadline
for submission of all material to the National Editor is the
first week of the month preceding issue. The deadline for
submissions to Branch Editors is one week prior to that.
Editorial copy deadline for the next issue,
February / March 2013
is Friday, 11 January 2012.
aussies overseas .........................................................................................................................................40
Feisty Perth Junior Flexes Muscles In Texas
MEO Expands Thai Exploration Portfolio
Woodside Enters Major Gas Discovery Offshore Israel
seismic technology ..................................................................................................................................44
The Value Of PRM In Enabling High Payback IOR
onlaps ..................................................................................................................................................................46
In Praise Of Older Cycles – Part 3 of 3
view from the top .....................................................................................................................................50
Blind Date Provides Long And Satisfying Relationship
geothermal .....................................................................................................................................................54
AGEC 2012: The Heat Is On For Australian Geothermal
words ...................................................................................................................................................................56
Duh Vinci
Advertisers
Archimedes Financial Planning 38
Ikon Science 17
RPS Energy 39
CGG Veritas Services
IFC
Ion Geophysical Corporation 53
Scope Resources 31
Chemostrat 10
DMITRE 7, 39
Melbourne Business School 21
Petrosys 33
Searcher Seismic 11, 35
Spectrum Australian Seismic Brokers 3, 27
DownUnder GeoSolutions 1
PGS Australia 42
Task Geoscience
6, OBC
Fugro-Jason 37
Polarcus 5
TGS-Nopec 13, 39
Fugro Multi Client Services
IBC
Rob Kirk Consultants 38
Velseis Processing 39
Geospace 49
Roxar Software Solutions 29
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editor’s comment
The Answer is 42
Well, as anticipated, I have been
totally unindated by applications
for my job, so it looks like you will
be subjected to my sharp wit and intense
sense of humour for another 21 years! But
don’t worry, I’ve solved the problem of what
to write about in my columns: I will just go
back to issue No.1 and start recycling the
original columns from there on.
Those of you that were around then will be
too old and doddery to remember back that
far anyway, and the rest of you probably hadn’t
even learnt to read by then, so we are in good
shape. So, what was the first column about? To
be honest, I can’t actually remember!
What I do remember is that ‘cutting and pasting’
those early issues actually did involve just that –
with scissors and glue! And laying the magazine
out required a qualification in origami to ensure that
all the pages turned out the right way around after
they were printed front and back, folded and then
cut up and reassembled. The editorial content was
supplied in ‘galleys’ – long scrolls of chemical
induced, shiny, photographic-like paper, very hard to
mark up any corrections on. Those were the days!
Nowadays, with Adobe InDesign the text flows
through the columns in the allotted space
and you can automatically adjust the kerning
and leading as you go – not that I’d actually
know if my kern needed adjusting. Katharina,
Resolutions’ very talented graphic designer
sees to all that, and makes it look so simple.
On to things that aren’t so simple: reading
some of the articles in this edition you’ll quickly
find that there are many influences
on our industry – and not all of
them are there to make our lives
any easier.
AAPG President, Ted Beaumont,
who gave a keynote address at the
AAPG ICE in Singapore recently (see
page 14), on the success of unconventionals in
the USA, described how they were instrumental
in removing the country’s reliance on imported
oil and gas, and aiding its manufacturing sector
to return to a semblance of its former glory.
Competitive energy being the key.
Adrian Williams.
The first of our two technology contributions
in this edition (Page 18) looks at how reservoir
simulation can help to bring Australia’s coal
bed methane into production. Our thanks to
Taha Taha from Roxar Software Solutions for
providing this. Our other technology article on
Page 44, provided by Martin Bett of TGS, looks
at the value of permanent reservoir monitoring,
using seabed seismic technology to help
improve oil recovery.
RPS Energy’s MD, John Stanton provides us his
View From The Top – from his early days, when
although he had a lot of fun, he wasn ’t sure of
which direction to take, through to representing
his company throughout Asia. He admits that,
like many of us, our partners support and ‘guide’
us through the stressful times – and allow us the
occasional relaxing game of golf.
One of our team attended the recent
Geothermal Conference in Sydney and provides
a frank report on an optimistic but
realistic industry sector. See Page 54.
The first report in our Industry News
section covers industry concerns
on what they describe as federal
regulator, NOPSEMA’s heavy-handed
regulations on companies trying
to full-fill their exploration licence work programs
in the allotted times. See Page 24 for this report.
The Federal Government’s much awaited Energy
White Paper has been met with mixed emotions,
depending on what side of the energy fence you
sit on. The Feds talk up energy reform and energy
security, but don’t side with the domestic gas
users for a federal gas reservation policy. They also
sound a caution on rising costs and its affect on
households and businesses, but pull up short of
providing their view of the way forward. Industry
groups, APIA and WA Domgas are much more
forward in offering their opinions on solutions.
Turn to Page 30 to read the various opinions.
Aussies are still active overseas, with reports on
Antares in Texas, MEO in Thailand and Woodside
spreading its wings to Israel.
In the magazine’s 21 st year, stalwart Peter Purcell
continues to provide us with entertainment while
lightly rapping us over the knuckles for errors in
grammar – or duhvincis as he calls them.
We hope you enjoy reading the final edition for
2012. The only thing left for us to do is to wish
you all the compliments of the S eason and
have a safe a pleasant holiday. We’ll see you in
the New Year. Rest in peace JR.
Concerned about your image?
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6 | PESA News Resources | December 2012 / January 2013

")
Marla
CO2012-A
Moomba ")
")
Marree
") Ceduna
Port Augusta
")
Whyalla ")
")
Port Pirie
") Burra
Port Lincoln
")
")
Berri
")
ADELAIDE
Petroleum exploration licence
Current (offshore EPP; onshore PEL)
Under application (PELA)
Petroleum production licence
Current (PPL) —
individual licences not shown
Under application (PPLA)
Petroleum retention licence
Current (PRL)
Under application (PRLA)
2012 onshore acreage release blocks
Bids close 4 April 2013
Offshore acreage release blocks
Bids close 8 November 2012
Bids close 9 May 2013
0 100 200 km
Lambert Conformal Conic
Petroleum pipeline licence
Gas
Gas and liquids
Liquids
Mount Gambier ")
Coongie Lakes control zone – no access
OT2012-A
DMITRE 204226-037
Department for Manufacturing,
Innovation, Trade, Resources and Energy

president’s report
Year End Report
Dear members,
As you are filling out your 2013
membership renewal it may interest
you to know our final membership
figure for the year (yes, it takes some
people until October to renew, and we are
probably still chasing some people) was
1995 members. Our membership is growing
slowly but steadily. It would be nice to top
2000 members in 2013 so please mention
to your colleagues the benefits of PESA
membership and sign them up for the new
year. The membership renewal forms will be
out by the time you read this column.
Keen-eyed members will not have missed the
rise in membership fees for 2013. Such rises are
never popular but it was necessar y to ensure
that our capacity to carry out objectives of the
society are not consumed by rising costs. The
society has a substantial cash reserve however
members whose memory matches their visual
acuity may remember the rare occasion when a
commercial mishap with a symposium cost the
society dearly. Our large flagship conference
budgets are now close to one million dollars: a
cash reserve is no luxury. That time was longer
ago than the last membership rise, so we have
done OK for a while. Student memberships
have remained free and retirees have not
copped the increase.
Last issue I predicted a perverse outcome for
Victoria’s fracc moratorium. It might be perverse
but it was surely predictable. Victoria’s 2012
onshore petroleum acreage release passed
deadline without troubling the assessors with
bids of any kind. Anything for the quiet life I
guess. Never mind that the rest of the world
is creating a revolution in unconventional
production. Never mind we can see the
US working towards energy self-sufficiency
with the pure “black swan” opportunity this
represents. Never mind that we don’t even have
aquifers within the prospective sequences. We’ll
just mothball the whole thing behind an openended
review process that when I last checked
had (read carefully now) no timeline, and no
timeline for even announcing the timeline, let
alone for the conclusion.
I won’t bang on about lost investment – that’s
obvious. I do feel acute disappointment for the
fine professionals who, in the faint hope that
someone gives a damn, work extremely hard
keeping Victorian prospectivity fresh and in the
eye of the industry. If anybody had put in an
application it would have been based on the
excellent precompetitive work built up over many
years by these folk. It must be hard to maintain
the enthusiasm to compete for investment dollars
with legislative regimes that, y’know, accept
petroleum as a legitimate endeavour.
Victoria is the second largest producer of oil
and gas in Australia, supplying largely into
the domestic market. One would struggle to
see this recognised in government talk and
certainly not in the walk.
Also, as flagged last issue, the ASX, in its review
of reporting rules has determined that reserve
and resource reports to the public must be
prepared by a qualified petroleum reserves and
resources estimator being:
A member in good standing of a pr ofessional
organisation of engineers geologists or other
geoscientists whose professional practice
includes petroleum reserves, contingent resources
and prospective resources evaluations and/
or audits. The professional organisation must
have disciplinary powers, including the power to
suspend or expel a member.
I have been in touch with the review group
in the ASX and the upshot is that PESA has
most of the requirements. Our Articles are
under review anyway, and a tweak to the
existing disciplinary process will allow PESA
membership to be accepted for this purpose: a
step forward.
I was pleased to receive a note from the
organisers of the Central Australian Basins
Symposium (CABS), that they would like PESA
to adopt the organisation and management
of future CABS symposia. CABS has provided
a specific forum for the sharing of information
on the older basins of central Australia like
the Amadeus, McArthur Georgina and Officer
basins, among others. With the focus on
unconventional resources, and the aptly named
Surprise-1 oil discovery in the Amadeus Basin,
these basins, are undergoing one of their semiregular
resurgences of interest and activity.
PESA has been happy to help in a small way
with previous CABS and is very proud to be
asked carry on the tradition. The scheduling of
CABS within the existing framework of EABS
and WABS is yet to be worked out but the
existing periodicity of 7–8 years can be more
than honoured I feel.
Gordon Wakelin-King.
By the time you are reading this a new crop of
graduates will be banging on doors, or if they
are lucky, swimming luxuriously in the warm
all-enclosing Turkish bath of your company’s
generous graduate development programme.
Hopefully you hired some good ones.
Our chance of getting good graduates depends
on good students choosing Earth Science in the
first place. Through our sponsorship of the teacher
earth science education programme TESEP we
have introduced nearly half a million high school
students to earth science via teacher workshops
throughout the country. Many general science
teachers have no background and no confidence
in earth science curriculum material. Our
industry will inevitably fall to the bottom of the
pile in bright students’ career selection unless
they are exposed to it at school via teachers
with some knowledge and a positive view.
Through TESEP workshops teachers see earth
science in action and gain some familiarity
in practice. The workshops are tailor-made to
teachers’ requirements and are in the right
place and the right time as the new National
Curriculum with earth science is rolled out.
Feedback to TESEP organisers from teachers is
overwhelmingly positive. The second phase of
TESEP will extend the workshops and develop
case studies and field guides and a lot of online
material. TESEP has been an excellent way to
get teachers thinking about earth science and I
urge companies to get on board as Phase two
sponsoring partners. More information is to be
found at www.tesep.org.au.
Just enough time to say thanks and good luck
to those writing their paper for WABS or the
PESA ASEG symposium.
PS Andy Whittle won the footy tipping … with
luck and persistence he’ll get his money in time
for the next season.
8 | PESA News Resources | December 2012 / January 2013

West Australian Basins Symposium
18 - 21 August 2013
Perth Convention and Exhibition Centre
Perth, Western Australia
Early bird
registrations open
January 2013
www.wabs2013.com.au
The regional oil and gas conference explorers have been waiting for, including:
New Oil and Gas Discoveries
Triassic of the Northwest Shelf
Unconventional Petroleum Resources
Canning Basin Revival
Latest Regional Geology
New Hydrocarbon Plays
International Speakers
Field Trips
Short Courses
Conference website with program, sponsorship and exhibition
opportunities and registration: www.wabs2013.com.au
Trade Exhibition

diary of events
2013 Conferences And Courses
FEBRUARY 2013
6–7 Subsea 2013
Venue: Aberdeen Exhibition & Conference Centre,
New South Wales
Web: www.subsea2013.com
20–22 Australasian Oil & Gas Exhibition and Conference 2013
Venue: Perth Convention Exhibition Centre, Western Australia
Web: www.aogexpo.com.au
MARCH 2013
4–6 8 th annual Excellence in Oil & Gas Conference and
Exhibition
Venue: Sofitel Sydney Wentworth, New South Wales
Web: www.excellenceoilgas.com
6–8 Offshore Asia
Venue: Kuala Lumpur Convention Centre, Malaysia
Web: www.offshoreasiaevent.com
12–14 Future Gas 2013 Conference and Exhibition
Venue: Brisbane Convention and Exhibition Centre, Queensland
Web: www.futuregas.com.au
Chemostrat Australia, servicing the
APAC region
APRIL 2013
8–11 SEAPEX Exploration Conference 2013
Venue: Fairmont, Singapore
Web: www.seapexconf.com
MAY 2013
6–9 Offshore Technology Conference – OTC Texas 2013
Venue: Houston, Texas
Web: www.otcnet.org/2013
26–29 2013 APPEA Conference and Exhibition
Venue: Brisbane Convention and Exhibition Centre,
Queensland
Web: www.appeaconference.com.au
26 PESA Deal Day
Venue: Brisbane Convention and Exhibition Centre,
Queensland
Email: jokicp@awtinternational.com
JULY 2013
1–3 Australian Gas Technology Conference and
Exhibition
Venue: Perth Convention Exhibition Centre, Western Australia
Web: www.australiangastechnology.com.au
AUGUST 2013
11–14 ASEG-PESA Conference
Venue: Melbourne Conference and Exhibition Centre, Victoria
Web: www.aseg-pesa2013.com.au
®
18–21 West Australian Basins Symposium 2013
Venue: Perth Convention Exhibition Centre, Western Australia
Web: www.wabs2013.com.au
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SEPTEMBER 2013
18–20 South East Asia Australia Offshore Conference
Venue: Darwin Convention Centre, Northern Territory
Web: www.seaaoc.com
22–27 SEG International Exposition and 83 rd Annual Meeting
Venue: Houston, Texas
Web: www.seg.org
OCTOBER 2013
18–20 Offshore Technology Conference – OTC Brazil 2013
Venue: Rio de Janeiro, Brazil
Web: www.otcbrasil.org/2013
10 | PESA News Resources | December 2012 / January 2013

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• The Duvalia 2D Seismic Survey provides 3,302 km of new
acquisition, long offset 2D non-exclusive seismic data
over the Outer Exmouth West blocks included in the 2012
Federal Acreage Release.
• The presence of a working petroleum system in the area
is clearly demonstrated by several recent discoveries in
adjacent permits, including Alaric-1 (2010), Cadwallon-1
(2010) and Vos-1 (2011), with an overall success rate of 82%
for exploration drilling over the last 5 years in the area.
• All of these wells encountered gas in the Triassic Mungaroo
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uncle duster’s opinion repository
Uncle Duster’s
Year In Review
Well, it's been another bumper
year for the Australian petroleum
industry, and PESA News Resources,
along with your old mate Uncle Duster, has
been there every step of the way, bringing
readers in-the-know coverage of industry,
from company and people profiles, regional
and project reviews, to technology reviews,
conference coverage and in-depth analysis
of the 2012 offshore petroleum acreage
release. Now, it's fair to say old Duster
has been a little sceptical of this new
technology that seems to be all the talk
these days, especially among the younger
generation, a technology consisting of a
vast and ever expanding global web of
computer networks, delivering information
to your home computer screen via
electronic, wireless and optical networking
conveyance, however, gauging the usability
and ease of access of the online version
of PESA News Resources, PNRonline, old
Duster has undergone something of a fibre
optic metamorphosis and is now a devout
convert, well and truly jumping on the
online bandwagon. Indeed, Duster reckons
PNRonline makes a great accompaniment
to the print edition, having grown steadily
since its 2010 inception.
As it has done so since it first came online ,
throughout 2012 PNRonline has comprehensively
documented goings on in Australian petroleum,
offering users additional, online only, features
such as webcasts of the PESA WA branch
monthly technical luncheon presentations and a
easily accessed database of ready information. In
fact, Duster often uses PNRonline as a reference
point when putting together his most keenly
anticipated, widely lauded column on goings on
in Australian petroleum.
So it is, delving into the digital annals, Duster
reckons possibly the biggest news story for
the petroleum industry in 2012, that with the
most far-reaching consequences, was the
introduction of the highly contentious and,
right-to-the-end, heavily debated carbon
tax. In Duster's eyes this was little more
than a politically motivated and precipitous
manoeuvre, not to mention a burdensome
impost on industry; ever since 2007's 'climate
change' election, carbon mitigation has, one
way or the other, been on the Australian
political agenda, and the government's
introduction of the carbon tax this year was
the parliamentary denouement of what had
become an interminable, highly partisan and
ideologically fuelled political soap opera. I ts
introduction was particularly galling in light
of Prime Minister Julia Gillard's pre-election
comments that, “there will be no carbon tax
under the government I lead”.
Yet here we are. Indeed, in previous years
Duster has made note of the competitive
disadvantage the carbon tax places on
the Australian industry in an international
marketplace in which project investment
is now more keenly fought for than ever,
particularly in the Asia Pacific. Lets hope
industry can get on with what it does best in
2013, with proper government support,
relatively unhindered.
The debate over the
environmental safety
of CSG mining
continued at pace
throughout 2012,
with APPEA highly
critical of the ABC's
coverage of the issue.
In one of a number of widely r eported incidents,
the ABC was forced to remove coverage of a US
study linking gas drilling to health problems and
the potential implications for the Australian CSG
industry from its website. APPEA Chief Operating
Officer – Eastern Region Rick Wilkinson was
not shy in broadcasting his views of Aunty's
journalistic standards with regard to the debate:
“Given the number of formal complaints still
to be resolved regarding the ABC’s error-prone
coverage of CSG, it is remarkable to see the ABC
continues to incorrectly report on CSG issues”,
Wilkinson stated at the time. “APPEA is again
seeking clarification regarding why the ABC has
failed to properly check facts or claims made by
the Greens or other activists.”
This is a debate that will no doubt continue
well on into 2013, and probably beyond. Duster
has made his thoughts on the matter known,
and reckons, separate from the often hysterical
media shouting match, industry would best be
allowed to get on with its business, with the
appropriate controls in place, in what is a boom
industry in the eastern states.
In what was another big year for conferences,
Duster particularly enjoyed PNRonline's analysis
of the 2012 offshore petroleum acreage release
announced at the annual APPEA Conference, this
year held in Adelaide. Duster also enjoyed the
many profiles that featured throughout 2012, along
with the edition-by-edition special features, from
safety to recruitment to Aussies overseas. Duster
would also make note that he particularly looks
forward to the regular View From The Top profiles
in which his peers talk about themselves and their
time in the petroleum industry, although it is an
ongoing source of personal bemusement as to
why he hasn't yet been approached to expound
on his colourful life and views on industry.
Doubtless this is in the metaphorical pipeline
for 2013. As for what else 2013 holds in store,
well, having seen just about everything there is
to see over the course of what has been a long
and celebrated career, nothing would surprise
old Duster in the least, although he does r est
easy in the knowledge that PESA News Resources
and PNRonline will be there to document all
relevant news and events as they have been
doing so for over 20 years now.
12 | PESA News Resources | December 2012 / January 2013

Quality
Multi-client Data

unconventionals
Black Swans Spread
Their Wings At AAPG
The Unconventional Black Swan
and AAPG
Singapore
September 2012
The American Association of Petroleum
Geologists (AAPG) 2012–13 President
Ted Beaumont has had a long and
active involvement with AAPG over the
course of a prolific career in which, among
other accolades, he was honoured with an
AAPG Special Award in 1991 for his work on
the Treatise of Petroleum Geology, a series
of over 30 publications on which he was a
co-editor, the same year he took to Australian
shores as the PESA distinguished lecturer.
Drawing on over 30 years’ experience in a
variety of roles across the oil and gas sector,
Beaumont has a number of interesting opinions
on the state of industry, the challenges it faces,
its potential for success, and its capacity for
veering in seemingly unexpected directions
that, with the benefit of hindsight, at once
appear perfectly predictable.
At September’s AAPG International Conference
and Exhibition (ICE) Singapore, PESA News
Resources (PNR) took the opportunity to sit
down with Beaumont to talk in detail about
his keynote presentation, ‘The Unconventional
Black Swan Event’, in which he addressed the
ability of seemingly unexpected events to wield
a significant, long-term impact on industry.*
By way of background, Beaumont told PNR that
‘black swan theory’ was developed by Nassim
Taleb, a Lebanese-American essayist; Taleb’s
2007 book, The Black Swan: The Impact of the
Highly Improbable defines the theory as an
event characterised by: “rarity, extreme impact,
and retrospective (though not prospective)
predictability.”
While the theory was originally conceptualised
around events occurring in financial markets,
Taleb’s 2007 book broadened the metaphor,
labelling almost all major scientific discoveries
and historical events black swans—for instance,
labelling the rise of the personal computer and
the subsequent ascent of the internet as black
swan events.
Beaumont has applied this rationale to the
petroleum industry, specifically to the rise of
unconventional resources in the US; the shale
revolution that in a relatively short period
of time has dramatically transformed the
country’s domestic and export market.
“I started thinking about it, I thought how many
people saw this coming, and the impact it
has had: it has had just an incr edible impact”,
he told PNR. “So I thought of the black swan
term—maybe that’s what this is, this is a black
swan in our industry.”
Citing a quote from influential and seminal
petroleum geologist Wallas E. Pratt, that “Where
oil is first found is, in the final analysis, in the
minds of men”, Beaumont observed inspiration
and innovative thinking have the powerful
capacity to transform widely accepted rationale.
“It is interesting to think about it, your
imagination is really the limiting factor, you
know it’s your ability to take the information
and create some new idea from it, and that is
his point,” he told PNR, noting there was once
a school of opinion firm in its conviction that
Saudi Arabia bore no petroleum.
Saudi Arabian production commenced in the
1950s—and, as Beaumont commented, it is
“hard to imagine now there were people who
used to say that there is no oil in Arabia—this
was an example to me of black swan.”
Yet, and hindsight may well be a wonderful
thing, how is it that we can collectively miss the
apparently blatantly obvious?
“Well, one reason is that we have this natural
conservatism from our training and this makes us
ignore the significance of what we don’t know.
We tend to think, ‘I know this, and that’s how it
is, I don’t have to worry, I understand this now,”
Beaumont observed. “We have psychological
biases, where we miss these things.”
Beaumont cites theories of peak oil as an
example of the influence widely accepted
convention can have on thinking in the industry.
The Hubbert peak theory (developed by Shell
geoscientist and co-founder of the Technocracy
movement, Marion
King Hubbert)
dictates the rate
of resources
production, which
initially increases
rapidly, will
reach a
Ted Beaumont, President AAPG.
* Arriving in Singapore just in time to attend Ted Beaumont’s Key Note, Welcome address, and not having heard the Black Swan Theory before, I was surprised
to learn it is a term used to describe an unlikely event. Anyone living in Western Australia will know that the Black Swan is common-placed, and forms part
of the Coat of Arms of Western Australia. So the next time you hear the term used, explain why the term is a misnomer to West Aussies.
Brian Wickins
14 | PESA News Resources | December 2012 / January 2013

unconventionals
maximum and decline, following a bell-shaped
curve. Using this methodology, Hubbert
predicted the world would reach peak oil
around the year 2000 (Figure 1).
Fig. 1. 1956 Prediction and Hubbert (1903–1989).
Source: en.wikipedia.org
The discovery and development of
unconventional resources in the US has,
however, led to a redefinition of peak petroleum
forecasts, with potentially far-reaching global
ramifications.
Over the past decade, the development of
new technologies in recovering shale gas have
transformed the American energy marketplace
from a position of shortage to one of glut.
Indeed, shale gas currently accounts for roughly
30% of total US gas production and there are
estimates it could reach as high as 50% by
2040. To put this into context, back in 2000 US
shale gas production was around 1% of total
gas production.
Beaumont stated, rather than declining, US
gas production is now actually increasing,
essentially reversing the natural production
decline predicted by Hubbert (Figure 2).
“No one thought that would happen. I did
not think it would; so I think there is reason to
believe, we are going to go higher, for sure—
right now we know we are.”
Fig. 2. Savings to the US Economy. Ahlbrandt, Search and Discovery, 2012 | Source: Demming, 2000
“I heard Robin West from the AAPG say the USA went from importing 65% of its gas requirements five
years ago, and recently down to 45%. He said in 2020 w e will be importing only 25% of our needs. I never
thought that would happen! As I got thinking about this I came up with some conservative savings to the
US – US$125 billion a year that stays in the US. By the time we are down to 25%, I think the saving will be be
around US$275 billion … every year. Every three and a half years that is like a trillion dollars that stays in the
economy. So it is real dollars.” Ted Beaumont, September 2012
Lower 48 states shale plays.
In turn, further technological development may
well also result in deviations from Hubbert’s
peak oil production curve. Explorers in the
North American onshore market are now
almost exclusively focused on unconventional
plays, and Beaumont noted current trends have
seen explorers becoming increasingly focused
on tight oil sands, with new technologies,
including drilling and completion procedures
and methods of petroleum system modelling,
capable of bringing about further potential
changes in oil recovery techniques (Figure 3).
Tight oil, trapped in low permeability
reservoirs, has been identified in plays
throughout oil producing regions in Canada
and the US; as Beaumont explained, while
conventional petroleum is found in structural
traps, unconventional petroleum is found in
stratigraphic traps (Table 1).
Shale plays
Basins
Current plays
*** Mixed shale &
chalk play
Prospective plays
*** Mixed shale &
limestone play
Stacked plays
*** Mixed shale &
Shallowest / youngest
tight dolostone-
Intermediate depth / age sillstone-sandstone
Deepest / oldest
Fig. 3. Source: Energy Information Administration based on data from various published studies. Updated: 9 May 2011
December 2012 / January 2013 | PESA News Resources | 15

unconventionals
Conventional
Unconventional
Preferred Trap Type Structural Stratigraphic
Aerial Trap Size Small Huge
Geological Risk High Low
Drilling Risk High Low
Completion Expense Low High
Critical Geologic Element Reservoir Source
Table 1. Conventional Versus Unconventional Petroleum Resources.
We usually find oil in a ne w place with old
ideas. Sometimes, we find oil in an old place
with a new idea, but we seldom find much oil
in an old place with an old idea.
Several times in the past we have thought
that we were running out of oil, whereas
actually we were only running out of ideas.
New Technologies Bring Change
••
Drilling and Completion Procedures
••
Petroleum System Modeling – The vocabulary and concepts
have shifted to the source rocks. Seems simple – it is not.
••
Reservoir Scales (nanodarcies vs. millidarcies)
••
TOCs, Brittleness (Poisson’s ratio, Young’s Modulus)
much more laboratory focused, pressure regimes and
identification
••
New training is required to exploit modern resource plays
Fig. 4. Ahlbrandt, Search and Discovery, 2012
This statement will ring true with many c ompanies and
individuals involved with unconventional exploration in 2012.
So, who said it and when?
— Parke A. Dickey, University of Tulsa Petroleum
geology professor, September 1958
54 years later, Professor Dickey’s statement still seems timeless.
“A stratigraphic trap is one that is there because of the change in the r ock
character, in other words it goes from big holes to small holes, and the
smaller holes, it’s harder for the oil and gas to escape from, then it seals the
oil into the rock that has the larger pore space”, he noted.
The development of new technologies used to recover tight gas, such as
horizontal drilling and multi-stage fraccing, are also used in the recovery of
tight oil, along with an ever expanding suite of new computer technology.
“We have these computer programs that we can measure with—so we
started looking at how did the source rock get buried, and when did it
release its hydrocarbons, how much did it release?” Beaumont observed.
(See Figure 4.)
“We look in terms of total organic carbon, TOCs: how much organic
carbon, and that is in a per cent. We are more laboratory focused than
we used to be; we take rocks and we send them to the labs for all kinds
of measurements, we never did that really, now we have 20 or 30 more
measurements than before.”
Fig. 5. What Is Happening Now? The Inversion of the Hydrocarbon Resource
Pyramid. Ahlbrandt, Search and Discovery, 2012 | After Thomasson, 2000
Industry vocabulary and concepts have made a definite shift
to source rocks Beaumont noted, leading to an inversion of the
hydrocarbon resource pyramid, shifting the focus from conventionals to
unconventionals (Figure 5).
The US is currently producing more gas than ever, with shale now looked
upon as potential reservoirs rather than seals or source rocks. As Beaumont
observed, recent developments in the petroleum industry have all the
characteristics of a black swan event; indeed, horizontal drilling and
completion technology had been around for 20 years before they were
utilised in tight gas recovery.
For so long the shadow of peak oil has loomed large over the petroleum
industry—could it be that continuing technology innovation will stimulate
a new age in fossil fuel production, defying long-held wisdom?
“I just wanted to show this to make the point,” Beaumont told PNR, pointing
out a photo from his presentation (Figure 6). “This is a slide that somebody
gave at a presentation, and it shows a tanker coming into the US in 2001,
carrying LNG, and it was coming in— they were going to bring it in.”
Fig. 6. Natural Gas Imports & Exports, 2001 (BCF).
Ahlbrandt, Search and Discovery, 2012 | Source: DOE, 2002
Over a decade later, the tankers are now taking it out; the times have
changed and black swans may well abound.
16 | PESA News Resources | December 2012 / January 2013

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unconventionals
Moving Australian Coalbed Methane Reser ves
Into Production Through Reser voir Simulation
Taha Taha, Roxar Software Solutions, Emerson Process Management
The Growth of CBM
Australia is a centre for Coalbed Methane (CBM)
or Coal Seam Gas (CSG) with almost 40% of all
global CBM reserves located in China, Australia,
India and Indonesia.
Today, Australia has an estimated 198 billion
cubic meters (Bcm) of CBM resources, according
to a 2012 article by Hart’s E&P, and Queensland
has as much as A$50 B worth of CBM projects
in progress. These include the Surat Basin,
which has been producing since 2006, and
developments in the Bowen Basin that covers
160,000 km 2 of central Queensland and has
produced the majority of CBM to date.
As the focus on CBM has increased, however, so
has the quest for more effective technologies to
help bring the reserves in such tight reservoirs
into production. One such technology is
reservoir simulation.
Reservoir Simulation and CBM
Challenges
Reservoir simulation has undergone huge
changes over the last few years.
The rise in computer power, such as 64-bit
multi core chip clusters, parallel processing and
computer-led automation, has ensured that
reservoir simulation is contributing to faster
decisions and a greater ability to determine
the important ‘what-if’ scenarios relating to
operators’ reservoirs. Today, multi-million cell
reservoir simulation models are the norm.
In addition, history matching technologies have
also seen dramatic changes. Manual history
matching has been replaced by robust and
automated algorithms that allow the reservoir
engineer to focus on developing a clearer
understanding of reservoir mechanisms and their
relative impact on production behaviour and
creating simulation models that are fully consistent
with their underlying geological interpretation.
It is against this backdrop that reservoir
simulation has the potential to play a key role
today in tight reservoirs and moving CBM
reserves into production. CBM reservoirs today,
however, come with a number of simulation
and production challenges.
Firstly, there is the geological complexity of
many CBM reserves represented by the often
tighter and thinner coal seams that require
more sophisticated drilling and completion
techniques and irregular well trajectories.
CBM is further characterised by a higher
number of wells, shallower drilling and lowpressure
extraction, requiring highly flexible,
fast and accurate simulation programmes. A
clear description of CBM well trajectories, for
example, is often a vital input to simulation.
It is also important that any CBM reservoir
simulation package is flexible and can
incorporate individual variables into the
simulation process. CBM simulation, for
example, requires gas content data values at
initial pressure, historical pressures, adsorption
isotherms, and parameters to estimate the
changes in absolute permeability. It is only
through incorporating these variables that more
accurate reservoir predictions can be generated.
Furthermore, horizontal and multilateral
wells with different well trajectories must be
incorporated into the model with the shrinking
and swelling of the coal matrix (often through
EOR techniques) also needing to be simulated.
As a result, modern full field, full physics
simulator programmes that can be optimised
for very large models have been developed,
that offer black oil, compositional and thermal
options.
Such programmes can simulate a wide
range of physical processes such as black oil,
compositional, dual porosity, steam, coal bed
methane and polymer injection within the one
programme and incorporate a wide variety of
different variables into the simulation runs. The
result when simulating CBM reservoirs is the
ability to generate information on multi-well
developments, identify the value of hydraulic
fracture treatments, and optimise drilling and
production programmes to name just a few
benefits.
Case Study of Norwest in the
Williston Basin
Norwest, a North American consulting firm
to the energy, mining, and natural resources
sectors, has extensive experience in CBM.
The company has experience in international
CBM projects in Australia, Western Siberia,
Kazakhstan, Italy, Southeast Asia, China, Chile
and Colombia.
In this particular case, Norwest needed to
optimise recovery on behalf of its client from
the Williston Basin, a large sedimentary basin
with significant CBM reserves that spans eastern
Montana, western North and South Dakota and
southern Saskatchewan.
In this case, Norwest’s client did not have
the expertise and manpower to embark on
a full scale CBM modelling simulation. “Some
of our clients don’t have the expertise to do
CBM modelling or large-scale simulation,” said
John Campanella, Senior Reservoir Engineer at
Norwest at the time. “Others have the ability,
but their people are spread too thin. They come
to us to help get things moving.”
The field in question was discovered in the early
1990s and was developed through open-hole
completions in mile-long horizontal wells on
640-acre spacing. Production peaked in 1998
and has since declined.
Addressing Key Field Challenges
In the spring of 2002, Norwest began working
on a full-field simulation project for the basin.
Norwest’s client needed a reliable full-field
simulation model to optimise a high-pressure
air injection and horizontal infill drilling
programme for a tight reservoir within the
basin.
One of the key challenges in the field, however,
was that decline curve techniques could not
accurately predict the oil rate response during
transient periods in which new wells were
drilled and producers converted to injectors.
The relatively complex development and
investment strategy also called for numerical
modelling.
It was also felt that air would sweep the
reservoir more efficiently than water and at a
lower cost than CO 2. Norwest therefore needed
to develop a cost effective, reliable full-field
simulation model from which a high-pressure
air injection and horizontal infill drilling
programme could be optimised.
18 | PESA News Resources | December 2012 / January 2013

unconventionals
The Simulation Results
Nine years of production history and air
injection information from a nearby field were
used to calibrate the simulation model and
achieve the history match. Working iteratively
with the client to clarify the reservoir geology
and tweaking the model to account for water
lost into the formation during drilling (not
otherwise factored into historical water and oil
production), Norwest was able to achieve an
excellent history match.
The model was tuned and validated to reflect
drilling and conversion activity through the
autumn of 2004, including 21 months of highpressure
air injection. Then, 12 months later,
measured water and oil production rates were
compared with the forecast. The model was
then used to optimise the timing and sequence
of infill drilling and the conversion of wells to
air injection.
“The predictions and actuals matched almost
exactly,” said Campanella. “We’re pretty proud
of that, especially because it was dur ing a huge
transient phase when things were changing
rapidly. I think it shows what an engineer can
accomplish by properly using an effective
simulation tool.”
The predicted production and injection
forecasts (see figures 1 and 2) matched the
actuals and, based on the new production
programme, field recovery is expected to more
than double.
Since 2005, three drilling rigs have been active
in the field, and new infill wells drilled on
160-acre spacing. Whereas estimated primary
recovery was originally only between eight and
10% of original oil in place, now the client’s
company is predicting recovery of 24%. All
field development plans that included more
than 125 horizontal wells and extensions by
2009, were driven by the results of reservoir
simulation.
Furthermore, in addition to high-pressure air
injection, the client is also investigating the
possibility of a hybrid air and water injection
programme to further improve recovery and
reduce operating expenses. The company
is also using what it learned in this project
to set up simulation models for two older
fields nearby, in order to evaluate proper well
spacing and plan infill drilling in the next year
or so.
Lessons for Australian producers
So what lessons can we take from this North
American case study and apply to Australian
producers?
Firstly, there is the importance of reservoir
simulation when it comes to CBM reservoirs.
Campanella commented: “A lot of companies
involved in CBM don’t use reservoir simulation
which often is a big mistake. We see
tremendous losses in productivity, especially
when companies drill horizontal CBM wells
without simulation. Some just poke a lot of
holes in the ground and hope and either
they drill more wells than they need to,
wasting money unnecessarily, or they sit on
unproductive areas pumping water for way
too long because they don’t understand what’s
going on.”
CBM today is a very complex play where
operators need to lower the water pressure
so gas will desorb from the coal. By
plugging the gas content and absorption
isotherm into a reservoir simulator along
with historical information on pressures,
operators can find out exactly how to get
gas out of the ground, how fast they can
produce it and what their peaks will look
like. Only reservoir simulation provides this
information to the operator.
Secondly, there is the importance of
accessibility.
“Personally,” said Campanella, “I think reservoir
simulation should be brought down to
every engineer’s desktop. We need to push
simulation out of the back room and into the
mainstream where people can use it on a daily
basis. In addition to the big 3D projects, there
are a lot of existing fields where simulation
could be applied, but too often it gets
skipped.”
Finally, although not directly relating to the
Norwest case study, there is the need for multicomponent
simulation in CBM reservoirs.
Enhanced CBM simulation today, for example,
involves the tracking of a number of gases,
such as carbon dioxide and nitrogen, with a
compositional model required to track the
individual components as well as accounting
for the adsorption/desorption of these
components. Simulation programmes that have
the ability to track multiple components in the
gas stream are required.
A Major Future Impact
There’s no doubt that CBM reservoirs are likely
to have a major future impact on oil and gas
production in Australia for many years to come
– ushering in perhaps as big a revolution as
with shale gas in North America.
As operators look to introduce ever greater
efficiencies and move reserves into production,
it’s clear that reservoir simulation will have a
vital role to play.
Fig. 1. Fig. 2.
December 2012 / January 2013 | PESA News Resources | 19

unconventionals
SA Unconventional Gas Update
More than 20 companies/Joint
Ventures are now focusing on
exploring unconventional gas
plays with giant discovery (find-size)
potential in South Australia.
This exploration is in addition to exploration for
conventional oil plays in the onshore frontier
Officer and Arckaringa basins, the offshore
frontier Bight Basin, and in existing proven,
commercial, conventional oil and gas plays in
the Cooper-Eromanga and Otway basins. The
unconventional gas resources targeted in South
Australia include shale gas, tight gas, deep coal
seam gas (CSG), underground coal gasification
(UCG), and the gasification of mined coal. With
such diversification, the chance at least one
of these unconventional gas plays will lead to
resources sufficient to underpin exports is high.
Once regarded as something that would
happen in the future, recent exploration
results achieved in the SA Cooper Basin by
companies like Santos, Beach Energy, Origin
Energy, and Senex Energy are leading towards
unconventional gas being used in households
across southeast Australia.
Australia’s first unconventional gas
production was achieved by Santos and
its Cooper Basin Joint Venture partners
Beach Energy (Dehli) and Origin Energy
on 19 October, when commercial
natural gas production commenced from
Moomba 191 shale gas well.
Explorers have accelerated appraisal of
Cooper Basin unconventional gas plays.
Seven vertical wells to test unconventional
plays have been drilled this year:
Nappamerri Trough wells Moonta-1 and
Streaky-1 (PEL 218, Beach Energy) encountered
gas saturation in the target Permian section.
Beach reported that Moonta-1 encountered
gas saturation over more than 1,000 m. Fracture
stimulations of the gas zones are expected to
proceed in Q4 2012.
••
A multi-zone fracture stimulation of
Patchawarra tight sands and the Roseneath
and Murteree shales in Sasanof-1 (PEL 516,
Senex Energy) was completed in May.
The well is producing fracture stimulation
fluid and liquids rich gas at a peak rate of
170,000 scf/day.
••
High gas readings
with evidence of
condensate and
heavy gases
were recorded
in the Permian
section in
Talaq-1 (PEL 516, Senex Energy). The well will
be fracture stimulated to test deliverability
and gas composition.
••
More than 75 m of net gas pa y in the
Patchawarra Formation and 164 m of gas
charged Roseneath and Murteree shales
were interpreted from wireline logs and
mud gas recorded in the Skipton-1 well
(PEL 516, Senex Energy). The well will be
fracture stimulated to test deliverability and
gas composition.
••
In the southern Cooper Basin Marsden-1
encountered elevated gas readings through
the Permian section, and Davenport 1
encountered over 110 m of net coal,
including a 45 m thick Patchawarra coal,
with elevated gas readings.
Recent fracture stimulations of vertical
wells drilled in 2010 (Encounter-1) and 2011
(Moomba-191) delivered very encouraging
results:
••
A 3 stage fracture stimulation of the
Moomba-191 Roseneath-Epsilon-
Murteree (REM) section (Cooper Basin JV
operated by Santos) resulted in stabilised
flow rate of 2.7 MMscf/d dry gas. The
close proximity of the well to existing
infrastructure enabled it to be brought on
line quickly and the Premier and Minister
attended the ceremony to connect the
well to markets on 19 October 2012.
••
A six stage fracture stimulation of the gas
saturated Permian section in Encounter-1
resulted in a combined gas flow rate
exceeding 2 MMscf/d.
Jay Weatherill SA Premier, turned the
valve to connect Moomba-191 to supply
Australia’s first unconventional gas to
markets on 19 October, Minister Tom
Koutsantonis, Minister for Mineral
Resources and Energy was
present, along with Santos
VP James Baulderstone.

unconventionals
Horizontal wells to test Cooper Basin shale gas
deliverability are planned. The first horizontal
well in South Australia is expected to be
Holdfast-2 in the Nappamerri Trough (Beach
Energy, PEL 218), currently planned for Q4 2012.
Santos is also planning a horizontal well trial
expected to proceed in Q1 2013.
Senex Energy has completed a $155 MM equity
raising to fund the planned FY2012–2013+ work
program. The work includes 12 vertical wells
targeting unconventional gas in Senex Energy’s
southern Cooper Basin permits (primarily
PEL 516), following early success at Sasanof-1,
Talaq-‌1 and Skipton-1.
The South Australian Department of
Manufacturing, Innovation, Trade, Resources
and Energy (DMITRE) formed a South Australian
Roundtable for Unconventional Gas in May
2010.
A total of 149 organisations are participating
in the Roundtable including individuals, peak
representative bodies, companies, universities,
media outlets, and key agencies from all States,
the Northern Territory and the Commonwealth
governments.
The Roundtable is tasked with producing a
Roadmap for Unconventional Gas Projects in
South Australia to identify opportunities and
risks to: inform markets; inform people and
enterprises that may someday compatibly
co-exist with unconventional gas projects; and
reduce critical uncertainties that may impede
efficient, profitable and welcomed investment.
The Roadmap is being developed with input
from stakeholders and is scheduled to be
published in late 2012. You can check the latest
on the Roadmap here:
http://www.petroleum.pir.sa.gov.au/
prospectivity/basin_and_province_information/
unconventional_gas/unconventional_gas_
interest_group/roadmap_for_unconventional_
gas_projects_in_sa
Top Patchawarra depth structure image with wells
targeting unconventional gas plays.
December 2012 / January 2013 | PESA News Resources | 21

anch activities
Students’ Thesis Abstracts
Three student members of the NSW
PESA branch recently completed
petroleum focused honours theses
and have written short descriptions of their
work for PNR. Amanda and Arvic have also
been student reps on the NSW committee.
Amanda and Emma were recipients of PESA
scholarships in 2012 which assisted with the
completion of their work.
The Geology and Structural Style of
the Juha gas field, PNG
Amanda Hanani, The University of NSW
The Papuan Fold Belt, located in the highlands
of Papua New Guinea (PNG), has had a long
history of petroleum exploration. A high level of
ambiguity exists in the structural analysis of the
fold belt because of PNG’s highly mountainous
terrain, dense equatorial jungle and limited
access. This often results in the acquisition of
poor quality seismic data and limits the abilit y to
collect geological data from surface exposures.
The Juha structure and associated Cecilia
Anticline, are located in the frontal area of the
Papuan Fold Belt. The Juha Anticline can be
clearly identified on aerial photographs and is
8 km in width by 25.2 km in length. The drilling
of three wells on the Juha Anticline in the
1980s resulted in the discovery of significant
gas reserves.
The study aims to better constrain the timing and
style of extensional and compressional deformation
at Juha. This will provide one component of the
petroleum system analysis for this field.
Twenty-five 2D seismic lines totalling 303.03 km
in length were interpreted, and seven wells
were used to tie the seismic horizons to depth.
Eight horizons were mapped, and the creation
of three two-way-time (TWT) structure maps
enabled analysis of the structural framework.
The results of this analysis revealed the
presence of two unconformities in the Ieru
Formation, whereas, only one unconformity had
been previously identified. From this study it
appears that orogenesis that had commenced
in the northeast of the fold belt at 25 Ma
reached the Juha area in the Plio-Pleistocene.
The forward modelling technique was used to
assess a detachment style of deformation to
explain the observed structures. The resulting
features indicate that the Juha structures were
driven by thick-skinned compressional tectonics.
Deformation started with an inverted basement
fault beneath the Juha area. The deformation was
transferred by a décollement and reached the
surface in the Cecilia Anticline. The development
of the Wai Asi and Cecilia Anticlines have been
identified as fault propagation folds, on the
leading edge of this thrust system.
Other fields in the frontal range show similarities
and differences with the thrust system proposed
for the Juha structure. At Hides and P’nyang,
thick-skinned tectonics like that proposed
at Juha are responsible for the structural
architecture of the anticlines. Further south, the
Kutubu structure has components of both thick
and thin-skinned models of thrusting.
The structure and timing of the Juha Anticline
has allowed for the entrapment of considerable
quantities of hydrocarbons. This structural
study has improved our understanding of
the petroleum system at Juha. This will help
develop the resource and assist in exploration
efforts in the Papuan Fold Belt.
Amanda thanks Oil Search for providing the data
needed for this project and for support through
training and mentoring. She also acknowledges
her supervisors Dr. Paul Lennox (UNSW) and
Dr. Kevin Hill (Oil Search) for their guidance and
invaluable teaching throughout this year.
Numerical simulation of
earthquake-induced submarine
landslides
Arvic Osorio, The University of Sydney
Recent exploration and expansion of
human infrastructure into offshore areas
have exposed the existence and ubiquitous
nature of submarine mass movements. These
geographically prevalent phenomena have
been observed in deep-marine offshore
environments within various geological settings.
There are numerous contributing factors
thought to affect the formation of submarine
landslides and because of this complex
and multi-faceted nature, a comprehensive
physical model to explain the generation
of submarine landslides has not been fully
developed. Furthermore, they have significant
potential physical, social, and economic impacts
to human society, and offshore or coastal
infrastructure which makes understanding their
formation of great relevance, especially to the
petroleum exploration industry.
Hanani, Fig. 1. Image of the western Papuan Fold Belt including the main oil
fields (green) and gas fields (red) fields have been labelled. The yellow box
highlights the location of the Juha study area (image courtesy of Oil Search
Limited).
Hanani, Fig. 2. Forward Model illustrating the evolution of structures in the
Juha area. Rifting in the Triassic was followed by deposition of sediments
(A) with compression reactivating a basement fault and developing fault
propagation folds (B). To accommodate further shortening a break-thrust
develops creating further uplift of the Cecilia Anticline (C).
22 | PESA News Resources | December 2012 / January 2013

anch activities
Curtin Geology Student Society (GEOS) Quiz Night
The WA Branch of PESA sponsored
a Quiz Night in mid-August
for Curtin University geology
students to attend.
PESA provided support to encourage
students to be socially active networking
with each other and to participate in
building stronger relationships with
professional organisations, such as PESA,
throughout their geological careers.
GEOS reports that the Quiz Night was a fantastic
affair, commencing with a BBQ at the beg inning
of the night to provide the 50 attendees with
sustenance for the night ahead. The quiz
consisted of 10 rounds with varying topics
from biology to pop culture. Between
the rounds, attendees were challenged
to create the tallest tower out of items
on the table and to find out who
could do the best impersonations.
It was a great night where people
from different year groups got
to socialise and there were even
a few lecturers who joined in
the fun.
Continued from page 22
Osorio, Fig. 1.
From the relevant scientific literature, it is
believed that earthquakes are among the
most critical factors in submarine landslide
generation. A case study employing a numerical
model of a submarine slope stimulated by
earthquake action was then developed to
test this hypothesis. Through this case study,
it was revealed that submarine slope stability
was highly sensitive to changes in excess
pore pressure generation as a result of varying
earthquake magnitude, demonstrating that
earthquakes can indeed be considered a highly
probable cause for the formation of submarine
landslides. Despite these positive results, the
exact physical mechanism responsible for this
process is still open to debate and other material
parameters utilised in the modelled submarine
slope have yet to be calibrated and verified with
other types of submarine soils. It is concluded
that deep-seated submarine landslides are very
likely to be induced by earthquake excitation.
Chemical analysis of source rocks
Emma Flannery, Macquarie University
The chemical analysis of source rocks and oils
provides invaluable information on thermal
maturity, source characteristics, oil-oil or oilsource
correlations and palaeobiology. The use
of chemical analysis in the understanding of
the palaeobiology is particularly important in
Precambrian rocks, due to the relative scarcity
of body fossils. Many applications involving the
analysis of hydrocarbons in petroleum systems
rely upon the assumption that there has been no
contamination of the sample. Due to both age and
typically low total organic carbon content however,
Precambrian basins are susceptible to hydrocarbon
overprinting due to contamination. In my honours
study three cores from the 1.4 billion year old
Velkerri Formation, McArthur Basin, were subjected
to slice experiments and molecular geochemical
analyses using gas chromatography-mass
spectrometry (GC-MS). Internal slices were found
to have consistent hydrocarbon signals, providing
strong evidence that the organic matter in the
inner slices is indigenous (Figure 1). In all three
cores, both the aliphatic and aromatic hydrocarbon
signatures indicate that the outside of the
core had been exposed to contamination
from both the drilling and sawing processes
(Figure 2). This contamination has the potential
to overprint the indigenous hydrocarbon signal
and highlights the importance of the removal
of the outside portion of the drill core prior to
analysis, even in organic rich rocks.
Biomarkers are molecular fossils that allow us
to infer the past presence of life. In my study,
biomarker analysis of Velkerri Formation rock
extracts allowed for the reconstruction of the
palaeobiology at time of deposition. High
bacterial input into the organic matter was
evidenced by hopanes, bicyclic sesquiterpanes
and monomethylalkanes. This is not unusual
as Precambrian source rocks are thought
to result almost entirely from microbial mat
growth. Steranes, or eukaryotic biomarkers,
have previously reported in Velkerri Formation
oils and rock extracts. However, in this study
steranes were found to be absent or below the
limit of detection, indicating a low input from
eukaryotes in the deep marine environment
of the Velkerri Formation. This suggests that
previous studies on the chemical composition
of Velkerri Formation rock extracts, particularly
that use whole rock extraction, may have
analysed non-indigenous steranes.
Flannery, Fig. 1. An example of one of the many
compound groups studied in McManus-1 1216 m:
n-Alkanes normalised to the n-alkane with the
highest concentration in each slice, showing
inconsistent hydrocarbon distributions in both the
outside flat slice and outside curve slice A. Slices B
to F show a consistent hydrocarbon distribution,
attributable to the indigenous hydrocarbon signal.
Flannery, Fig. 2. An example of one of the many
compound groups studied in McManus-1 1216 m:
Concentration of n-alkanes with % error estimate
in McManus-1 slices. The outside flat slice shows
an increase in concentration in n-alkanes
compared to slices A–F.
December 2012 / January 2013 | PESA News Resources | 23

industry news
NOPSEMA ‘Offside’ As Companies Cr y
Foul Over ‘Heavy-Handed’ Regulations
NOPSEMA has been accused of
overstepping the boundaries of its
jurisdiction by enforcing heavyhanded
regulations of seismic vessels
synonymous with oil producing rigs and
platforms that has cost energy companies
millions of dollars in downtime and caused
some exploration contracts to be canned
altogether.
In this report, a number of industry insiders
reveal how NOPSEMA has been causing a
stir, subjecting seismic vessels to levels of
operational compliance that are more stringent
that even standards applicable to fully laden oil
tankers.
This resulted in the $165 MM Polarcus vessel
Alima, one of the most environmentally
sophisticated vessels of its kind, being anchored
off Broome for five weeks – at a significant cost
to Woodside, who had contracted the vessel
for a $100 MM survey on the North West Shelf
and, as Operator, was required to submit an
environment plan that incorporated an oil spill
contingency plan.
In another instance a seismic sur vey program
was cancelled altogether. The company is
currently considering claiming force majere as
a consequence of the bureaucracy and red
tape surrounding NOPSEMA, which companies
allege is entangling the exploration industr y in
Australia.
The Australian Maritime Safety Authority (AMSA)
said all vessels in Australian waters were regulated
for safety and environmental purposes. Some
regulations may be based on the International
Maritime Organisation MARPOL convention which
categorised all vessels under one or more of the
following annexes governing regulations for the
prevention by: oil, noxious liquid substances
in bulk, harmful substances carried by sea in
packaged form, sewage from ships, garbage by
ships and air pollution by ships.
These regulations were implemented by various
federal and state laws depending on the size
and activity of the vessels.
However, vessels are often subject to additional
regulations, depending on their activity, which
are enforced by the relevant government
agency (for example, some fishing vessels
require fishing licences administered by the
Australian Fisheries Management Authority).
NOPSEMA has allegedly overstepped the mark
in its stringent interpretation of the Offshore
Petroleum and Greenhouse Gas Storage Act by
forcing seismic operators to submit an oil spill
contingency plan synonymous with offshore
rigs and production platforms, among a
number of other heavy handed requirements.
During the process of evaluation three
NOPSEMA officials spent a week on the Alima
performing an audit of Woodside’s project
that involved a thorough examination of the
vessel including an investigation into how
the company disposed of barnacles that had
attached to streamers. Apparently NOPSEMA
classifies barnacles as waste which should not
be returned to the ocean.
NOPSEMA was described as being “obsessed”
with collisions at sea, despite The Australian
Transport Safety Bureau’s (ATSB) marine safety
database indicating that there have been no
recorded instances of collisions, groundings or
sinking of a seismic vessel or its support vessels
in Australian waters in at least the last 30 y ears.*
“In some instances, when a large vessel comes
within 200 km we take notice. At 100 km we
take a lot of notice and at 50 k m we start to
shit ourselves. At 20 km we would bring in all
the gear and the chase boat and suppor t vessel
would try and put themselves between the
approaching vessel and the seismic ship,” said
one industry professional.
Another seasoned seismic operator said with
fishing activity within a 3D ‘racetrack’, based
on a racetrack width of about 10 k m, a fishing
vessel could be 5 km from a survey vessel
with close on-water cooperation achieving a
harmonious synergy.
Polarcus’ vessels are double-hulled, a
virtually unique safety feature exclusive to oil
carriers, and subscribes to the highest global
environmental standards attainable, classified
as Ice Class 1A+. This year the vessel worked
for Shell operating in the ice fields of the Ar ctic
where it had to be robust enough to function
safely in 1 m thick ice.
Nevertheless, NOPSEMA still demanded that
Woodside submit details of how they would
avoid collisions at sea off the nor th west coast
of Australia.
This was despite the Alima operating in Arctic
fields so saturated with icebergs and growlers
moving in different directions that daily
satellite images were downloaded to plan for
operations. An investigation revealed that,
by contrast, only 12 vessels in two years had
passed through the area to be surveyed by the
Alima for Woodside.
Some companies are said to be incensed at
being granted Federal Government approval
to explore for hydrocarbons off the coast
of Australia, only for another government
department to subsequently scuttle operations
and send costs soaring.
Australia is already in the spotlight for
significant cost blow-outs to major projects
and high operating expenses in comparison
to other parts of the world, causing energy
companies to review planned operations in
Australia.
It is understood that the cost of commissioning a
state-of-the-art seismic vessel for an exploration
program can be about $350,000 a day.
In the pre-NOPSEMA era, when oil companies
were able to get approval from the Western
Australian government for seismic operations,
the process is believed to have taken days, as
opposed to weeks running into months.
Besides conforming to the most stringent Arctic
standards of any seismic vessel to operate in
harsh environmental regions where “not many
can go”, the Alima had safely completed a
110,000 km 2 program in ice fairways as part of a
three boat, three month operation.
The vessel exceeds even Australian
environmental standards by having the capacity
to measure its own emissions. It is equipped with
a high specification catalytic converter used to
* http://www.atsb.gov.au/publications/
safety-investigation-reports.aspx
24 | PESA News Resources | December 2012 / January 2013

industry news
reduce nitrous oxide by 60 to 80% by converting
it into nitrogen, an inert gas, and water, using a
liquid form of urea imported from Rotterdam.
This process also reduces soot output.
In addition, the vessel has minimised emissions
being powered by heavy diesel marine oil
similar to the low-sulphur diesel fuel used in
motor vehicles. The revolutionary X-bow design
delivers 15–20% more efficient hydrodynamic
properties in a head sea, fur ther reducing
emissions.
The vessel recently acquired a EEE worldwide
environmental rating from DNV, the highest
standard available conforming to green standards
exceeding the criteria for cruise-liners.
John Hughes, an independent geophysical
operations advisor who assists a number of
oil and gas companies submitting sur vey
applications, is concerned that NOPSEMA’s
pedantic and interpretive application of the act
and regulations is not having the desired effect
of improving the safety and environmental
sensitivity of what he considers are already very
safe and environmentally sensitive operations.
He said forcing state-of-the-art vessels to
comply with oil rig safety standards and
standards that are significantly higher than
other shipping in Australian waters is causing
concern in the industry.
“These actions are causing very significant and
expensive suspensions and even cancellations,
to work programs” added Hughes. “I’m sure
NOPTA (National Offshore Petroleum Titles
Authority) must have seen a significant increase
in suspension and extension requests from
petroleum licence holders in the last few
months.
“It appears that NOPSEMA’s emphasis on the
wording of the OPGGS Act and Regulations
which, in a number of instances needs
significant re-drafting, is resulting in the
regulator, operators and seismic contractors
placing more effort on bureaucratic
documentation than focusing on the practical
aspects of the safety and environmental
sensitivity of the activity.
“For example, here are two requirements of
the OPGGS Act/Regulations that give rise
to significant misinterpretation by all and
angst plus significant additional workload for
no benefit for the industry. First, a ‘relevant
person’ with whom the operator must consult
in preparing the EP is, among other things,
defined as ‘a person or organisation whose
functions, interests or activities may be affected
by the activities to be carried out under the
environment plan’.
December 2012 / January 2013 | PESA News Resources | 25

industry news
“This definition enables environmental NGOs
to claim that they are ‘relevant persons’. In fact,
even though I’m sure the Act and Regulations
were written to ensure the operator consulted
with all other stakeholders who actually used
or had responsibility for the area in which the
activity would be carried out, the definition
is so wide-ranging that any person whose
‘interests may be affected’ (even if they are not
tangible interests – simply ideological interests!)
can now claim they are a ‘relevant person’ and
must be consulted by the operator.
“This then leads to the second requirement
that we are concerned about. That is, we must
include in the EP ‘a copy of the full text of any
response by a relevant person’ and ‘a statement
of the operator’s response, or proposed
response, if any, to each objection or claim’.
“The outcome is obvious, the operator
spends extensive efforts addressing issues
that are often irrelevant and the EP becomes
a major document that is not of prac tical
use to those that carry out the activity but,
put simply, just ticks the box for NOPSEMA.
Furthermore, the requirement to include
‘a copy of the full text of any response by
a relevant person’ in the EP makes it even
more difficult to consult with the fishing
industry and individual fishermen who simply
do not wish the commercial in confidence
information that they sometimes provide us
to be placed in the EP,” said Hughes.
“Furthermore, such information is simply not
relevant to the environmental sensitivity or
safety of the seismic survey.
“It is now becoming very difficult to get a seismic
survey acquired in the first permit year of a
three year guaranteed work program. Up until
recently (prior to NOPSEMA’s arrival), although
it was a challenge, it was not a significant
problem. Under Australian petroleum licencing
procedures, seismic surveys are generally
conducted in the first year and drilling in year
three of a guaranteed three-year program. I
would suggest this is now almost impossible in
the current regulatory regime and will inevitably
lead to exploration wells being delayed and
drilling/development activity in decline.
“Another concern is that NOPSEMA appears
to have an unrealistic assessment of the risk
of collision involved in seismic surveys. They
appear to consider the risk of collision during
a seismic survey to be higher than general
commercial shipping due to the fact that the
vessel moves slowly and is in the same general
area for a period of time. Given the track record
and statistics plus the use of such mitigation
factors as scout/support vessels, notices to
mariners, amongst other processes, I fail to
understand how NOPSEMA can maintain this
position,” said Hughes.
Under current regulations, the ‘instrument
holder’, who holds authority to carry
out a ‘petroleum activity’ must submit
an environment plan and comply with
environment plans as accepted by NOPSEMA.
Department of Transport Oil Spill Response
co-ordinator Matt Verney said prior to the
Montara oil spill from the PTTEP, Thai-operated
West Atlas oil rig in 2009, the Western Australian
Department of Mines and Petroleum, in
conjunction with the Department of Transport,
had regulated offshore petroleum activity on
behalf of the Commonwealth Government.
He said companies involved in oil extraction
had to submit an oil contingency plan to the
DMP, which was then forwarded to DOT for
review and comment.
NOPSEMA was created to regulate petroleumrelated
activity in Commonwealth waters after
a Federal Government investigation into the
Montara incident had concluded that there
were shortcomings in the Northern Territory’s
regulation regime that had approved the West
Atlas for operations.
The Western Australian government still has
jurisdiction over activities in State waters, which
Verney said extended three nautical miles off
the coast encompassing strategic islands such
as Barrow Island, home to the gargantuan
Gorgon project, and Browse Island.
“Seismic vessels do not have to submit an oil
spill contingency plan for operating in state
waters,” Verney said.
In response to the industry concerns over
heavy-handed regulation of the seismic industry,
NOPSEMA responded by stating it is “simply
applying the law via its legislated assessment,
inspection and compliance functions”.
“The authority’s policies and processes,
including assessment of environment plans,
focus on ensuring duty holders, and the
regulator, comply with their obligations
specified in law. This reflects the objectives of
the regulatory regime, which allows industry
to tailor environment plans and oil spill
contingency plans (and the risk management
measures within them) appropriate to the
nature and scale of a proposed activity,”
NOPSEMA said in a written response to our
questions regarding grievances brought against
it by the industry.
“In practice this means there are no stipulations
in the offshore petroleum legislation about,
for example, disposing of barnacles as trash.
But with that flexibility comes a responsibility
for the operator to demonstrate appropriate
management of the risks and impacts that
are generated by their activity. This means
that proposed activities involving higher risks,
such as re-fuelling at sea in a sensitive coral
reef environment, requires commensurate risk
management measures by industry.
“Further, NOPSEMA inspections will involve
monitoring how industry has complied with
industry’s own commitments listed in the
environment or oil spill contingency plans.
Throughout all of its functions, NOPSEMA
encourages and facilitates extensive
consultation with industry to discuss concerns
and misconceptions regarding the offshore
regulatory regime and NOPSEMA’s functions
and processes.”
From the tone of NOPSEMA’s response it
doesn’t appear the industry can expect a better
understanding of its predicament.
26 | PESA News Resources | December 2012 / January 2013

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industry news
Beach Energy’s Cooper Basin Resurgence Continues
Beach Energy will spend up to a record
$410 MM on South Australian Cooper
Basin exploration and development
and add up to 50 new jobs at its Glenside
headquarters in the current financial
year as new technologies and shale gas
opportunities transform Australia’s onshore
energy hub.
In total the Adelaide-based oil and gas group,
will spend up to $450 MM on development and
exploration activities in the current financial
year with the vast majority devoted to SA’s
Cooper Basin region.
This reflects expected record spending of
well over $1 B in the current financial year
for all companies operating in the S outh
Australian Cooper Basin on exploration and
development.
Beach, which has zero corporate debt and close
to $500 MM in cash and undrawn loan facilities,
as well as annual operating cash flow of around
$300 MM expected for this financial year, is
investing heavily in South Australia’s Cooper
Basin renaissance.
Over 100 wells will be drilled by Beach (either
alone or in partnership) with the vast majority
devoted to the SA portion of the Cooper Basin
to define more gas reserves for the East coast
market.
Reg Nelson, Beach Energy Managing Director.
Image courtesy of Beach Energy
Beach is also harnessing the latest oil industry
technology to drill the Holdfast-2 horizontal
well in the Cooper Basin, due to start in mid-
December. This well is expected to be drilled
vertically for 3 km with the potential to then be
drilled laterally for up to another 2 km into the
key gas bearing shale formations.
On 23 November, at Beach’s AGM, Managing
Director Reg Nelson said said the Cooper Basin
is not receiving international recognition.
“It is clear that several billion dollars will be
spent by petroleum companies in the Cooper
Basin on exploration and development
activities in the next five years. Beach alone
will be involved in over 100 wells in the next
12 months.
“The shale revolution has had a major impact
on the USA’s energy security and transformation
from coal to gas. There is no reason to believe
this will not happen in Australia. The Cooper
Basin, with its existing infrastructure linked to
the vast East coast gas network and the new
LNG developments in Queensland, has become
the engine room of Australia’s East coast energy
industry.
“Gas demand for both the Australian domestic
market and export LNG projects is expected to
triple to around 3,000 PJ a year by 2020. From
2015 onwards, we expect that a number of
domestic and export linked gas production
opportunities will open up for gas from the
Cooper Basin.
“To keep pace with this dramatic increase in
exploration, Beach Energy expects to lift its
total employee base from 130 to 180 by the
end of this financial year, a 40% increase, at a
time when South Australia really needs new
jobs.
“On top of this, many more new jobs will be
generated through the numerous contractors
involved in Beach’s very active operations.”
Bauer Field May Hold More Oil
On 6 November Beach Energy and
Drillsearch Energy announced that
they have made a new Cooper
Basin oil discovery that may increase
reserves at the Bauer oil field, announced on
6 November.
The Bauer North-1 well intersected about 3 m
of net oil pay in high quality McKinlay/Namur
sandstones and will be cased and suspended
as a future oil production well.
Following completion, it will tied into the
Bauer central production facility.
Mud and wireline logs indicate that Bauer
North-1, which is 2.2 km north northwest from
the Bauer-8 development well, appears to
have similar but differing oil/water contacts to
the Bauer oil field. This suggests that it may be
part of the Bauer oil field and fur ther appraisal
drilling is required to confirm this.
Following completion of operations at Bauer
North-1, the Ensign 930 rig will move to drill
the Bauer-9 appraisal well.
Drilling results from both wells will be
included in a reserves update for the Bauer oil
field.
Beach has a 40% operating interest in PEL 91
while Drillsearch holds 60%.
PEL 91 Western Flank Oil Fairway – Bauer oil field
development.
4
28 | PESA News Resources | December 2012 / January 2013

industry news
Central Petroleum And Total Announce Strategic
Alliance For Exploration In Southern Georgina Basin
Central Petroleum has announced a
multistage farm-out agreement with
French energy company Total for the
exploration of approximately 6 MM acres in
the southern Georgina Basin.
The 6 November agreement covers four highly
prospective areas in the vicinity of recent
discoveries in the southern Georgina Basin in
central Australia, in EP(A)132 in the Northern
Territory and ATP(A)909, ATP(A)911 and
ATP(A)912 in Queensland.
The exploration will start with an investment
by the JV of US$60 MM for stage one, and, at
Total’s election, US$130 MM for stages two
and three. Should Total continue and fulfil its
funding obligations for stages two and three,
Total will earn in increments to a total of 68%
in the permits.
Total is required to fund 80% of exploration
and appraisal costs over four years to which
Total has committed the first US$48 MM of
expenditure for stage one after which Central
will fund the next US$12 MM.
Central will operate the farm-out areas for the
first four years and after completion of stage 3
Total will assume operator-ship for 90% of the
area. Central will retain operatorship of the
upstream activities on the remaining 10% of
the area.
Central, CEO Richard Cottee has attracted
significant investment into the company’s
tenements and said that with this
agreement Central could achieve long term
objectives he had outlined to the market
and the access to the capital required for
success.
“Central Petroleum retains 100% interest
in and 100% access to the cash flow from
its Surprise discovery. This also gives the
company the necessary time to build the
human resources and expertise to develop its
capacity as an operator.
“The company’s focus is clearly on the
exploration and development of our assets
in the Amadeus and Southern Georgina
Basins.
“Central is locating its head office to
Brisbane from where it is better placed
to concentrate on the development of its
operator-ship of the southern Georgina
Basin holding. We expect that the ATPs will
be granted in the New Year allowing us
to have a planned build-up of resources”,
Cottee said.
In October, he announced that Santos would
fund exploration in the company’s 13 permit/
application areas in the Amadeus and Pedirka
basins in central Australia by spending an
initial $30 MM.
It will provide capital for a fully funded
exploration programme while enabling Central
to retain a significant interest in the southern
Georgina Basin.
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December 2012 / January 2013 | PESA News Resources | 29

industry news
Energy White Paper Welcomed By Santos
But Mixed Feelings From APIA And DomGas
The eagerly awaited / Energy
White Paper – Australia’s Energy
Transformation / document drew a
mixed response from industry and lobby
groups after being released by the Federal
Government on 8 November.
Setting out the Government’s strategic
policy framework to guide Australia’s energy
transformation to a cleaner and more productive
energy economy, the central objective of the
paper is to provide the settings to deliver secure,
reliable, clean, competitively priced energy
to consumers; while building national wealth
through the safe and sustainable development
of our energy resources.
In Melbourne Minister for Resources and
Energy, Martin Ferguson, outlined the massive
transformation underway in Australia’s energy
and resource sectors, saying the need to
ensure the right policy settings are in place
to effectively respond to this change is
paramount.
“The Energy White Paper is about laying
the foundation for sound energy policy
development in this country for years to come,”
Ferguson said.
Ferguson noted challenges such as rising
energy prices and the importance of
maintaining liquid fuel security and bringing
new clean energy technologies to market.
“It is also important that all governments maintain
an attractive investment environment through
efficient, timely and consistent national planning,
approval and regulatory processes,” he said.
Ferguson said the Australian Government
recognises that rising energy prices are hurting
households and businesses and carrying out the
energy market reforms outlined in the Energy
White Paper will help to ease price pressures
over the longer-term, while acknowledging that
there are no quick fix solutions.
“However, the Australian Government cannot
do this alone. Governments at all levels must
embrace key reforms, including improving the
efficiency of electricity networks, establishing
effective competition and removing retail
price caps, providing for greater demandside
participation and moving towards cost
reflective pricing,” he said.
Martin Ferguson, Minister for
Resources and Energy.
“The key to delivering on this reform agenda –
and locking in the benefits to consumers – will
depend largely on the agreement that can be
reached by the Standing Council on Energy and
Resources followed by the Council of Australian
Governments later this year,” Ferguson said.
Also commenting was the Australian Pipeline
Industry Association (APIA), who welcomed the
increased focus on the challenges facing Australia’s
natural gas industry. However it claimed that
according to the nation’s gas transmission industry
there remains a need to address a looming gas
price “bubble” which could threaten Australian
industries that rely on gas as a major input.
APIA also said that according to work being
undertaken by the Australian Pipeline Industry
Association, and economic consultancy, ACIL
Tasman, LNG exports from Australia and the
slowdown in CSG development may lead to
a supply shortfall of natural gas and an up t o
seven-year east coast gas price “bubble”.
Cheryl Cartwright, Chief Executive of APIA
warned that such a short-to-medium term price
hike has the potential to close down Australian
businesses unable to deal with an explosion in
the price they pay for their gas.
“Federal Government claims that market
development initiatives such as the Gas Bulletin
Board, the Short Term Trading Market and a
proposed gas supply hub at Wallumbilla in
Queensland can assist in providing access
to affordable gas are, at best, misguided”,
Cartwright said.
“While such mechanisms increase information
availability and demand flexibility, they do not
provide more gas to Australian industry, nor will
they reduce prices. The Gas Bulletin Board and
Cheryl Cartwright, Chief Executive
of APIA.
Tony Petersen, DomGas Alliance.
Short Term Trading Markets are already in place
and are doing nothing to prevent the supply
and prices issues facing Australian industry.
“While the Energy White Paper is welcome,
and its call for regular review of the energy
economy demonstrates foresight, there remains
the fundamental challenge facing Australia’s
energy industries, and that is, the cost to the
domestic economy of linking national gas
prices to LNG-export prices.
“However, APIA agrees with the suggested partsolution
to addressing the price bubble, and
that is improved access to the nation’s vast gas
reserves in order to increase gas supply.
“The current delays in CSG developments in
Queensland and New South Wales will coincide
with LNG-export demand coming on line, and
exporting companies will need to draw on gas
that had been anticipated to be available to
Australian gas users,” she said.
A graph developed by ACIL Tasman predicts the
expected seven year east coast price “bubble”
commencing from 2013 and tailing off by 2020 as
gas production eventually meets market demand.
“After this ‘bubble’, or without the ‘bubble’, it is
expected the price of gas would increase, but
remain affordable,” Cartwright said.
“Right now, the answer to affordable gas
prices is to not tinker with end markets, nor
gas transportation – the solution is to address
gas supply – and ensure that businesses
threatened by a short-to-medium term price
hike can survive until the price levels out.
“With the vast resources of natural gas in
Australia, improved access will address
30 | PESA News Resources | December 2012 / January 2013

industry news
supply issues – which will in tur n assist in bringing prices down. In the
meantime, Government should seriously consider whether it wants a
short-term gas supply crisis to permanently damage some sectors of the
economy.
“If businesses are not viable in the long-term, then market forces should
allow them to close or move offshore, but if the dramatically high pr ice of
this input to their business is temporary, the Government should step in.
“As we have seen already, a failure by Governments to step in has led to
the closure of many manufacturing businesses – including steel pipeline
manufacture, which has closed forever because of the high Australian
dollar and the tardiness of any useful action by the Government’s
Manufacturing Taskforce, led by former Queensland Premier Peter Beattie.
“It would be a tragedy if this mistak e is repeated. Future transmission
infrastructure construction will be hampered by the lack of local production.”
On the other hand Santos welcomed the Energy White Paperand its
recognition of the important role natural gas will play in Australia’s energy
future.
Santos Chief Executive David Knox said, “Australia’s abundant gas resources,
together with the economies of scale provided by the export LNG market,
put us in an enviable position to both adequately supply our domestic
market and deliver the significant economic benefits possible from Asian
demand growth.
“Interventions in gas markets that disrupt the natural economic forces
of supply and demand will result in Australia’s gas resources being
uneconomic and ultimately unavailable to Australian industry and
consumers. This will undermine the more than $180 B being invested in
Australia’s LNG sector and the significant follow-on investments which are
currently in the planning phase.”
chemicals industry alone, as well as other value-adding manufacturing like
plastics, aluminium, steel and automotives,” Petersen said.
“The US has taken a strategic approach on energy security and requires
LNG exporters to prioritise the local economy. Canada also applies a
national interest test on exports to ensure the domestic market is not
disadvantaged in any way. It makes no economic sense for Australia to link
our domestic gas prices to the world’s highest prices in Japan.”
Petersen said the market has failed to deliver and governments must act in
the national interest to ensure supply.
“Most of Australia’s gas resources are now controlled by a handful of very
large producers who think in terms of multi-billion dollar LNG contracts.
Selling to smaller Australia customers will not happen voluntarily,” he said.
“These resources belong to all Australians. Simply saying ‘Let the market
work’, as the White Paper does, is not in the national interest.”
It should be noted that Australia is the only country in the world where
international oil companies can openly access and expor t gas without
prioritising the local economy.
It is also the only major gas pr oducing country facing serious shortages
and sharply rising prices.
The DomGas Alliance welcomed proposed changes to improve
transparency and participation in the management of offshore retention
leases. These changes were recommended six years ago in 2007.
Santos acknowledged the Energy White Paper’s challenge to ensure the gas
industry’s competitiveness amid rising construction costs and increasing
competition from emerging global suppliers.
Knox said “it is vital that the industr y address these cost challenges
through the application of new technology, innovation and the ongoing
development of a skilled and mobile labour force.
“Santos is making inroads into reducing its own costs and will continue
to work with the broader industry to ensure that the future pipeline of
projects is competitive and attracts the investment needed.”
In opposition to this – the DomGas Alliance claimed the Energy White
Paper effectively surrenders Australia’s competitive advantage in energy.
In a statement released in response to The Energy White Paper DomGas
said that despite a massive increase in gas production, Australian industry
cannot secure long term supply at affordable prices.
Australia now has some of the highest domestic gas pr ices in the world at
around $8 – $12 per gigajoule. This compares to just $3.50 in the US and
$3.20 in Canada.
DomGas Alliance Chairman, Tony Petersen, said Australia’s approach
contrasts to the United States where a manufacturing renaissance was
underway on the back of affordable gas.
“Affordable gas has driven some $US 40 B in ne w investment in the US
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December 2012 / January 2013 | PESA News Resources | 31

industry news
Hackers Posing A Threat To Industry
Anonymous is a loosely associated
hacktivist group. Hacktivism being
the use of computers and computer
networks as a means of protest to promote
political ends. Anonymous originated in 2003
on the imageboard 4chan, representing
the concept of many online and offline
community users simultaneously existing as
an anarchic, digitised global brain. It is also
generally considered to be a blanket term for
members of certain internet subcultures, a
way to refer to the actions of people in an
environment where their actual identities
are not known. It strongly opposes internet
censorship and surveillance, and has hacked
various government websites. It has also
targeted major security corporations. In
public, its members are distinguished at
various protests by wearing Guy Fawkes masks.
In July this year, Anonymous supported a
protest against the tar sands oil industr y, which
ended in protesters dancing on the meeting
table of the Governor of Montana.
Anonymous networked like ants in the internet
to get word out about this civil disobedience,
and about the issue at hand. Anonymous spent
weeks researching the corporations involved,
uncovering mountains of email addresses and
contact info of employees who Anonymous
considers to “work to destroy our planet for
profit.”
The group was in protest of the Keystone XL
pipeline and made a week-long information
campaign against the project and spread
word of Washington D.C. protests where over
850 people were arrested at the White House
for peaceful sit-ins.
Anonymous said, “our journey has manifested
into a full-on conquest to expose the corruption
in the companies who plan to mine this oil and
build the Keystone XL pipeline from Canada to
the Gulf of Mexico.”
Anonymous proceeded to release hundreds
of corporate emails that were obtained from
servers of oil industry websites. The mailservers
of Transcanada were shut down for two days.
At the time, Wikileaks, a group that Anonymous
supports, published a series of cables and
according to Anonymous: “directly prove that
Statoil corporation, a major player in the tar
sands industry, has fired workers in Venezuela
for their political leanings, in collusion with
state-owned petroleum company PDVSA.”
The Embassy Caracas Venezuela cable reference
number 08CARACAS264 stated, “Norway’s
StatoilHydro received a far more lucrative
compensation package for its lost equity in
the former Sincor strategic association than
reported in the press.”
Another quotes Canadian Environmental
Minister Prentice as saying he is deeply
concerned with the effect of the tar sands on
the image of Canada,” claimed Anonymous.
Group Anonymous is not the only hackers out
there posing a threat to the Industry. On the
14 October the United States admitted they
believe a series of cyber attacks on domestic
banks and some foreign oil company’s carried out
over the last year are the handy work of a group
of hackers linked to the Iranian government.
Leon Panetta, Defence Secretary said the
cyber-threat from Iran has grown, and declared
that the Pentagon is prepared to take action
if America is threatened by a computer-based
assault. The hackers are apparently part of
a group of less than 100 computer security
specialists from Iranian universities and network
security firms, according to theHackernews.com.
American officials have said they are able to
discover the source of the recent cyber-attacks.
The Iranian official said Tehran has already offered
help to boost the companies cyber-security, as
Iran has itself recently been the victim of cyberattacks
on its offshore oil platforms.
The cyber-attacks hit the Saudi Arabian state
oil company Aramco and Qatari natural
gas producer RasGas using a virus, known
as Shamoon, which can spread through
networked computers and ultimately wipes out
files by overwriting them. Iran blames Israel and
the United States for the attacks.
In Australia there has been numerous cases
of Group Anonymous cyber attacks on the
Australian Government. With no reports thus far
on any attacks on Australian based oil and gas
companies. This is not to say it would or could
not happen in the future.
The Australian Federal Police gave PESA
News Resources some organisational-specific
preventative hacking tips to readers including;
Members of the group Anonymous wearing Guy Fawkes masks in Los Angeles, 2008.
••
Educating staff on maintaining the
confidentiality of systems and information
so as not to leave them open to corporate
espionage.
••
Implementing policies which do not permit
employees to access social media sites at
work, as these sites can allow malware to
access company systems.
••
Maintaining firewalls and other protective
measures across the workplace network.
••
Information Communication Technology
(ICT) organisations spend a lot of time,
money and effort on identifying potential
vulnerabilities in their products and providing
‘patches’ to the public to overcome this.
••
However, it is still up to the individual user
or company to ensure that they make the
most of all the protection options available
to them.
32 | PESA News Resources | December 2012 / January 2013

industry news
DownUnder GeoSolutions Appoints New COO
DownUnder GeoSolutions appointed Paul Crute as its new Chief
Operations Officer in September.
Crute joins the company with a 25 year career in the resources sector,
including senior executive and management roles in the resources and oil and
gas industry, most recently as Executive General Manager of Human Resources at
Oil Search Ltd. Prior to that he was with BHP Billiton as Vice President of Human
Resources for many of their divisions around the world.
This international management experience will serve him well in his new role at
DownUnder GeoSolutions as they expand into new global markets. Although based
in Perth, DownUnder GeoSolutions has a large hub in Malaysia and recently opened
offices in Brisbane, Singapore, London and Houston.
Crute’s role at DownUnder GeoSolutions will focus on managing the resources,
infrastructure, systems and processes the company needs to meet its global
growth objectives.
DownUnder GeoSolutions Managing Director, Dr Matthew Lamont said, “Paul
Crute brings a new level of strategic business thinking to our company. His
thorough understanding of our industry, coupled with his proven ability to build
and manage organisational capability will be an incredible asset to our company
as we continue our growth path.”
Paul Crute, COO, DownUnder GeoSolutions.
December 2012 / January 2013 | PESA News Resources | 33

industry news
Buru Pens State Agreement For WA Domgas
Buru Energy’s has struck a deal with
the West Australian government to
build a $500 MM Kimberley pipeline
connecting to the domestic gas network
in the Pilbara, an agreement representing
a major boost to the company’s shale gas
aspirations from its Canning Basin assets.
In terms of the arrangement, WA’s domestic
gas reservation policy that secures 15% of gas
from new projects for domestic use, has now
been extended to an onshore project for the
first time.
Buru Executive Director Eric Streitberg said the
company still needed to prove up sufficient
reserves in the Canning Basin before building
the 600 km pipeline, for which purpose the
company was in talks with a major pipeline
player.
For Western Australia, the 25 year state
agreement – which carries an extension clause
for another 25 years – provides security of
energy tenure over the 1.7 MM hectares of
exploration permits held by Buru and its joint
venture partner, Japanese conglomerate,
Mitsubishi.
In a separate announcement, Buru Energy said
it would execute a state agreement covering
its core permits whereby Buru and Mitsubishi
will not be required to relinquish core acreage
until 2024.
The company said the agreement will give it
time to fully appraise its Canning Superbasin
acreage and also revealed that if it satisfied
its domestic gas obligations, it may, in future,
consider an LNG development.
Streitberg said that in terms of the agreement,
provided the joint venture met its exploration,
appraisal and development obligations, it would
not be required to relinquish acreage in key
permits EP371, EP391, EP428, EP431 and EP436 at
the end of an initial six year period. The normal
procedure requires a permit holder to relinquish
50% of the area in its permit after six years.
“The state agreement allows us to use gas
appraisal work done in one permit to offset
the work obligations in any adjacent permit
covered by the state agreement,” Streitberg
said. “This is a change to the way the legislation
currently works and will assist us to ensure that
our on ground dollars are spent in a way that
most quickly builds up gas reserves.”
The Canning Superbasin, Buru Energy’s jewel in
the crown.
Effectively, the agreement secures acreage in
the stipulated areas for the joint-venture until
31 January 2024.
Streitberg said the agreement only covered
some of their permits as the WA Government
was encouraging the company to develop this
acreage as a fillip to domgas supply. Significantly,
the agreement covers the jewel in the crown of
Buru’s assets, including the highly prospective
Valhalla and Yulleroo accumulations.
“In terms of relief for relinquishment, Buru and
Mitsubishi are required to keep exploring for
gas and to make a proposal to the state by
mid-2016 for the development of a gas pipeline
and project to deliver gas into the existing
domestic gas pipeline network in the Pilbara,
assuming we have the gas reserves to do so,”
said Streitberg.
The Buru boss also revealed that the WA
government was targeting the delivery of
1,500 PJ of gas into the domestic market in the
next 25 years.
“Very important for the state, we need to have
our project to deliver domestic gas approved
by the state before we can seek approval for
any gas export,” he said.
In terms of the agreement, if the joint venture
fails to prove up sufficient reserves for a
domestic gas project or is unable to make it
work technically, or economically, it has the
option of seeking an extension or terminating
the agreement.
Streitberg described the 1500 PJ of gas to be
delivered under the deal as “only a target”.
“There is no obligation on us to actually deliver
this much gas and the state agreement cannot
compel us to deliver gas uneconomically.
Our only obligation around gas delivery is to
develop a domestic gas pipeline and project
before we seek approval to export gas via LNG.
We may never prove up enough reserves to
justify an LNG project, in which case all of our
reserves, however big they are, will be available
for the domestic market.”
Streitberg pointed out, however, that
independent assessment of only a few wells at
the Valhalla accumulation had flagged 6.5 Tcf of
mean recoverable gas: “Which is about 6,900 PJ,
so we think the 1,500 PJ target is something we
can legitimately aim for.”
Looking ahead to future potential expansion,
Streitberg said LNG loomed large on the horizon.
“Provided we could meet our domestic gas
obligations and the economics stacked up,
we would definitely look at an LNG scale
development.
“We are working on integrating the results of
the recent Asgard well into our assessment
of the Valhalla accumulation, which we
are hopeful will result in an increase in the
recoverable gas from that accumulation.
“We are also revisiting our assessment of
the Yulleroo field after the very successful
Yulleroo-3 well.
“Taken together, these areas may eventually be
proven to hold sufficient gas to form the basis
of an LNG scale development. However, we are
still a fair few years away from that point. If we
did go down that route, our plan is to transport
the gas to the Pilbara through an expansion or
twinning of our domestic gas pipeline. If we do
develop an LNG project, the WA Government’s
15% domestic gas reservation policy will apply
to that project, further projecting the WA
domestic gas supply.”
The joint venture has spent over $100 MM in
the last two years with spectacular success in
the Superbasin that saw Buru Energy’s share
price soaring almost 800% from $0.50 to over
$3.50 during this period.
Western Australia’s peak energy user group,
DomGas Alliance, has welcomed the agreement
as a deal that could unlock a major ne w source
of energy.
4
34 | PESA News Resources | December 2012 / January 2013

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industry news
Australian LNG Producer Santos
Sees LNG-Price Remaining Linked To Oil
Santos believes LNG contracts will
mostly remain linked to crude oil
prices due to the importance of
security of supply to Japanese utilities, who
are the world’s biggest buyers of the fuel.
Santos CEO and Managing Director David
Knox told the Australian Institute of Energy
Conference in Sydney on 19 November, “It is
an important factor that you can buy Henry
Hub gas and transport it to Tokyo Bay for about
$7 MM Btu, but it’s a factor that probably in the
long term is going to be on the margin.”
Knox said that at current Henry Hub prices it
would be theoretically possible to deliver LNG
from North America to Tokyo Bay at around
$11 MM Btu, compared with the Japanese spot
price of around $12.50 MM Btu and Australian
LNG price of $14–14.50 MM Btu. Henry Hub
cash averaged $3.455 MM Btu on 16 November.
Knox said that the key if you are in Japan and
you are running a major utility is security of
supply. He further added that to maintain
security, “Japanese buyers need multiple
sources of supply and they like very much to
look right the way through to the reservoirs.”
“They like to know that the molecules are there
in the ground and they will, through prudent
operators, be delivered into Tokyo Bay,” Knox said.
“I suspect there will be a mixture of the way
contracts are linked but I think fundamentally
(oil price-linking) will remain and the reason
it will remain is because of security of supply
being so important.”
David Knox, CEO and Managing Director Santos.
Knox said he believed regulators would allow
North America to export 5–10% of domestic gas
consumption. “That’s 30–40 MM tpa in a global
LNG market by 2025 of 450 MM tpa, so less than
10% of the global LNG market,” he added.
According to FACTS Global Energy figures,
presented at the AIE conference on
20 November – Japan imported 78.5 MM t of
LNG in 2011 and is expected to take 82.2 MM t
in 2012. FACTS sees Japan’s demand rising to
84.3 MM t in 2015 and 88.5 MM t in 2020.
Santos, which claims the top spot among
Australian domestic gas producers, holds stakes
in four producing and developing LNG projects
in the region. Santos owns 11.5% of the
ConocoPhillips-operated Darwin LNG project,
which produces 3.5 MM tpa.
The company also has 13.5% of the 6.6 MM tpa
Papua New Guinea LNG project, currently
under construction by operator ExxonMobil
and scheduled for startup in 2014. In Australia,
Santos holds a 30% operating stake in the
7.8 MM mt/year CSG based Gladstone LNG
project in Queensland, approved in January and
slated to start up in 2015.
In addition, Santos is targeting a FID in 2014
and first production in 2018 at its Bonapar te
floating LNG project off northern Australia. The
company holds 40% of the planned 2 MM tpa
facility in a JV with GDF Suez.
Continued from page 34
DomGas Alliance Chairman, Tony Petersen, said
there was sufficient demand for gas in the state
to underpin development of the Canning Basin
reserves.
“Western Australia is by far the largest gas
market in Australia and the state depends on
secure, affordable gas supply,” Mr Petersen said.
“Canning Basin gas could be used to fuel new
industries in the Pilbara or piped south to supply
industry and households in the South West.”
While most of any gas produced is likely to
be supplied to the local market, the State
Agreement also includes a domestic gas
reservation commitment in the event of LNG
exports.
DomGas also endorsed the requirement for the
joint-venture to make available for sale related
products such as ethane, propane, butane
and condensate, for possible manufacture of
chemicals or use as transport fuel.
“This gives long-term confidence that gas
will be supplied to the state whatever the
development options pursued by the project
partners,” Mr Petersen said.
“I commend Buru and Mitsubishi for committing to
domestic supply and thereby opening up a world
of opportunities for increasing the economic value
of this gas to the people of this state.
“The State’s 15% reservation policy has again
been useful in delivering positive outcomes for
project proponents and WA residents.”
At the time of going to press Buru Energy was
trading around $2.76.
36 | PESA News Resources | December 2012 / January 2013

industry news
Gas Discovery At Crown In The Browse Basin
Santos recently announced a
significant gas discovery at the
Crown-1 exploration well in
WA-274-P, located in the Browse Basin,
offshore Western Australia.
Crown-1 is located approximately 500 km
north of Broome, approximately 60 km west
of the Ichthys field and 20 km east of the
Poseidon field. The water depth at location is
440 m.
By early November wireline logging had
confirmed 61 m of net gas pay in the
Jurassic-aged Montara, Plover and Malita
reservoirs between 4,873 and 4,998 m, and
the well has not intersected a gas-water
contact.
“The strong partnerships and
the material prospectivity
in this key offshore gas
province positions Santos
very well for the future. We
look forward to the WA-408-P
drilling programme,”
Anderson said.
Crown gas discovery,
Browse Basin.
4
Pressure data has been acquired from multiple
points indicating that gas would be expected
to flow at a high rate. Multiple condensatebearing
gas samples have been recovered to
surface.
Drilling is progressing to a proposed total
depth of 5,200 m.
Santos’ Head of Exploration Bill Ovenden
described Crown-1 as an important gas
discovery for the company.
“The Crown discovery is well positioned, in
close proximity to existing and proposed
LNG projects in the Browse Basin and other
material exploration prospects,” Ovenden
said.
Santos holds 30% of WA-274-P and is
operator. JV partners are Chevron (50%)
and INPEX (20%). In addition, Santos
has executed agreements to take a 30%
interest in the adjoining exploration permit,
WA-408-P, operated by Total (50%), subject
to customary conditions.
Murphy Oil Corporation has a 20% interest
in the permit. The JV has committed to an
initial drilling programme in the permit,
including Dufresne-1 and Bassett West-1.
These wells are expected to immediately
follow the Crown-1 program.
Santos VP Western Australia and Northern
Territory John Anderson said the agreement
with Total and Murphy substantially increased
the company’s exposure to exploration upside
in the Browse Basin.
December 2012 / January 2013 | PESA News Resources | 37
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industry news
Poland Woos Shale Gas Investment
Poland has stepped on the
shale gas accelerator by
proposing tax capping
incentives in a bid to woo
investment towards developing
its unconventional resources.
In terms of the new regulatory and
tax regime plan, taxes would be
capped at 40% of profits entailing
a 5% tax on gas extraction, 10%
on crude and a new hydrocarbons
tax of 25% levied according to the
difference between revenue and
costs.
The total tax includes 19% company tax and
competes favourably against the United
Kingdom, which imposes a petroleum revenue
tax of 50%, and Norway, with a total oil and gas
profit tax of 78%.
Australia, by comparison, has one of the highest
tax rates in the world in ballpark terms where
companies are subject to a complex and
convoluted fiscal burden.
Carlo Franchina, Partner-in-Charge Tax at
the Perth office of KPMG, said oil and gas
companies in Australia were subject to a 30%
corporate tax rate and a Petroleum Resource
Rent Tax (PRRT) of 40% “that is deductible for
tax purposes”.
“If you have a producing field, I would say the
broad effective tax rate on profits in Australia is
58%, but you probably would describe that as
a worst case scenario. If a company undertakes
exploration there are allowances and the PRRT
effective rate is reduced,” said Franchina.
He added that Australia’s corporate tax rate was
significantly higher than the UK, reduced to 22%.
Carlo Franchina, Partnerin-Charge
Tax at the Perth
office of KPMG.
“One of the main criticisms of the
Australian revenue system is that
the corporate tax rate is still high
in comparison to other OECD
countries,” said Franchina.
While Australia boasts oil and gas
activity that is the envy of many of
its peers, operators are continually
fingering high costs compounded
by heavy tax burdens as a stumbling
block to continued growth.
Poland recognises the urgency it
faces securing future energy supplies
and is prepared to offer attractive incentives to
lure major corporations to the country to free it
from the shackles of reliance on Russia.
Poland’s proposal makes provision for the
establishment of a new state-owned company,
the National Energy Mines Operator, to
participate in consortia. It is envisaged that
future exploration and extraction licences will
only be auctioned off to qualified buyers.
Poland is estimated to have possible reserves
of 67 Tcf, the third largest in Europe according
to the National Geological Institute, to Norway
and the Netherlands.
The tax incentive scheme was announced after
Poland announced plans to invest Euro 15.5 B
in shale gas exploration within the nex t eight
years, with spending over the next two years
totalling Euro 1.2 B.
Poland Finance Minister Mikolaj Budzanowski
articulated the urgency behind the government’s
tax and investment initiatives, saying: “With the
Russian gas accord terminating at the end of 2022,
we must be well prepared to noticeably boost the
exploitation of our own gas fields three years earlier.”
Poland has a population of 38 million and
consumes 14 B m 3 of gas per annum with t wo
thirds of the fuel imported from Russia.
The country’s shale gas resources are seen
as an opportunity to make Poland energyindependent
of Russia with first extraction of
shale gas targeted for 2014.
Poland’s shale hopes were dented in June when
US supermajor ExxonMobil flow tested two
unconventional wells in the eastern part of the
country that proved non commercial, before
announcing it had completed its exploration
program in the country.
A disappointed Polish Economy Minister,
Waldemar Pawlak, claimed ExxonMobil had lost
interest in Poland after being sweetened by a
deal to develop tight oil reserves in Siberia by
Russian state oil company Rosneft.
“With such prospects, shale gas in Poland did
not have as much meaning,” Pawlak said.
Poland has awarded 109 shale gas exploration
licences around the country in which Chevron
and ConoccoPhillips, among a number of
smaller explorers, are active.
PGNiG’s Lubocino, Poland’s first shale gas
production well near Wejherowo.
38 | PESA News Resources | December 2012 / January 2013

We wish all members and clients
Merry Christmas & a Happy New Year!
Resources and Energy Group
Barry Goldstein
Executive Director
Energy Resources Division
Dr Paul Heithersay PSM
Deputy Chief Executive, Resources and Energy
Chief Executive, Olympic Dam Task Force
Tel +61 8 8463 3200
Fax +61 8 8463 3229
Mobile +61 413 007 365
barry.goldstein@sa.gov.au
Level 6, 101 Grenfell Street
Adelaide SA 5000
GPO Box 1671, Adelaide SA 5001
www.dmitre.sa.gov.au
Resources and Energy
Tel +61 8 8303 2299
Fax +61 8 8303 2965
Mobile +61 428 895 639
paul.heithersay@sa.gov.au
Level 9, Terrace Towers
178 North Terrace
Adelaide SA 5000
www.dmitre.sa.gov.au

aussies overseas
Feisty Perth Junior Flexes Muscles In Texas
Australian junior exploration and
production company Antares Energy
has expanded it’s Big Star acreage in
Texas, USA, through the acquisition of Big
Star Oil and Gas company’s interests in the
project.
The company now holds 15,215 net acres in the
Lower Mississippian Lime Horizontal Fairway,
where wells drilled by SM Energy have reported
initial, seven day flow rates of 571-665 boepd.
Big Star is located in the expanding northern
fairway of the main Wolfberry producing trend
within Southern Dawson County.
Antares Energy said vertical Lower Missippian
wells achieve initial production rates of between
10–200 bopd. The company said that on average
it costs US$6.5 MM to drill a horizontal well and
that SM Energy intended running two drill rigs in
the play up until the end of the y ear.
The company has spruiked the Big Star project
as well suited for horizontal drilling development
in the Lower Mississippian, saying existing
3D seismic run over 80% of the leases has
demonstrated reservoir potential from wireline
logs and isolated fracture stimulations in vertical
Big Star Mississippi/Wolfberry completions.
In addition, the nearby Deroen field has
produced in excess of 2.4 MM bbl from Lower
Mississippian porous and fractured cherty
limestone. This facies is the expected reservoir
character of the Big Star project area, according
to Antares Energy.
The reservoir was enhanced by uplift and erosion
in Upper Mississippian time as evidenced by
paleothins occurring as a result of this uplift.
The company said the best fracture stimulation
breakdowns and flowback results are coincident
with features in the vertical Missberry
stimulations to date.
Wireline resistivity and porosity character in
the Big Star wells have been tied back to the
heart of the SM Energy horizontal activity and
the two areas appear identical in regards to
neutron/density porosity crossover indicative
of gas and porosity development in the Lower
Mississippian.
Antares’ three core projects in the US are
Southern Star, Big Star and Northern Star with
interests in Oyster Creek and Hawkville.
Southern Star is located in the core of the main
Wolfberry producing trend within Northwest
Howard County and Northern Star is located
in the expanding northern fairway of the main
Wolfberry producing trend within Southern
Dawson County.
Oyster Creek is located in the Frio oil and gas
producing trend within central Brazoria County.
Hawkville is located in the central Eagleford
gas and condensate producing trend within
northwestern McMullen County.
Antares Energy’s share price has trended
upwards over the past six months and was
trading at $0.56 on the ASX, spik ing 55% from a
year low of $0.36 in June.
MEO Expands Thai Exploration Portfolio
Australian company MEO has
acquired a 50% stake in Pearl
Oil’s G2/48 concession in the
Rayong Basin in the Gulf of Thailand.
The exploration permit granted by the
Thailand government covers 9449 km 2
in shallow waters in the Thai Gulf and
is close to the producing assets of the
Jasmine oil and Manora oil development.
The Rayong Basin displays similar
characteristics to oil producing basins
nearby. The Jasmine field, which is
operated by Pearl Energy, the Southeast
Asian operating arm of Mubadala Oil and
Gas, has so far produced over 40 MM bbl
of oil at a peak rate of over 20,000 bopd
via an FPSO.
The developing Manora field to the west,
discovered in 2009, is scheduled to produce
first oil in 2014. It is estimated to hold
31 MM bbl and is expected to produce at
a peak rate of 15,000 bopd via a wellhead
production platform linked to an FSO.
The joint venture plans to drill two
exploration wells in late November in the
G2/48 block and will target Oligo-Miocene
clastics analogous to the adjacent proven
Kra Basin. MEO has touted Thailand as
an attractive exploration and operating
option, citing relatively inexpensive drilling
costs using shallow water jack-up rigs
testing targets located in relatively shallow
depths as factors enhancing the risk/return
profile. The Melbourne-based company
said it costs $US5–$US10 MM per well
to run an exploration program in
Thailand.
In Indonesia MEO is also upbeat following
drilling results from the Gurame field at
its Seruway production sharing contract
showing elevated gas levels from 2776 m
to 2794 m. The company is preparing to
cut a 30 m conventional core from 2794 m.
The drilling program at Gurame is
designed to test the deep gas potential
at the Baong and Belumai reservoirs.
MEO has estimated the P50 recoverable
resource of Gurame field to be 0.5 Tcf of
low CO 2 gas and 57 MM bbl of liquids .
MEO shares closed at $2.60 on the ASX
following news of the award.
40 | PESA News Resources | December 2012 / January 2013

aussies overseas
Woodside Enters Major
Gas Discovery Offshore Israel
Woodside has reached an
agreement in principle to
acquire a participating interest
in one of the largest recent gas discoveries
worldwide, which could see the company
play a key role in the potential development
of an LNG industry in Israel.
The Leviathan JV participants, Noble Energy
Mediterranean Ltd., Delek Drilling LP, Avner Oil
Exploration LP and Ratio Oil Exploration (1992)
LP, have reached agreement with Woodside
on the key commercial terms under which
Woodside will acquire a participating interest
in each of the 349/Rachel and 350/‌Amit
petroleum licences which contain the Leviathan
field.
Under the agreement Woodside will acquire
a 30% interest in the Leviathan field, which
is estimated to contain about 17 Tcf of
recoverable natural gas. The agreement will
also allow Woodside to participate in further
exploration opportunities in the Leviathan
licences.
••
Potential annual LNG revenue
sharing payments equal to 11.5%
of Woodside’s incremental revenue
above an agreed escalating price
threshold, over the life of the project
(capped at US$1 B).
••
Carry of expenditure up to US$50 MM in
relation to costs associated with the drilling
of a deep oil exploration well targeted for
late 2013.
The agreement is subject to a number
of conditions including execution of
fully termed agreements, completion of
confirmatory due diligence and obtaining
the necessary government and regulatory
approvals.
Location of Leviathan gas field in the Rachel and
Amit permits.
Woodside will be the operator of any LNG
development of the field, while Noble Energy
will remain upstream operator. Noble Energy
targets initial production to the domestic
gas market in 2016. A pre-FEED (front-end
engineering and design) assessment for an LNG
project is underway.
Woodside CEO Peter Coleman said the
agreement was a significant step towards
realising Woodside’s ambition to secure worldclass
growth opportunities.
“Acquiring an interest in these permits is an
exciting opportunity to grow our portfolio in
the emerging Eastern Mediterranean basin and
we look forward to finalising the agreement,”
Coleman said.
The agreement involves an initial upfront
payment of US$696 MM. Woodside has offered
the following contingent payments:
••
A payment of US$200 MM once laws
permitting LNG export from Israel are in
force.
••
A payment of US$350 MM on a final
investment decision in relation to an LNG
development.
# Gross unrisked resource potential.
December 2012 / January 2013 | PESA News Resources | 41

2.0
3.0
4.0
Supporting your exploration success
Nick David
Tel: +61 8932 09007
nick.david@pgs.com
Robert McArdle
Tel: +61 8932 09121
robert.mcardle@pgs.com

1.0
1.0
2.0
2.0
3.0
3.0
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Aurora Aurora 3D 3D
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3D 3D GeoStreamer ® ® Aurora MC3D MC3D Seismic Survey
The The Browse Browse Basin Basin is one is one of of Australia’s exploration hot-spots in the in the quest quest for new for new oil and oil and gas gas
reserves. The The basin basin remains remains underexplored and and is is geologically challenging, where where imaging imaging
and and mapping, especially of the of the deep deep Lower Lower Cretaceous and and Jurassic Jurassic intervals, remains remains
difficult difficult using using conventional seismic seismic data. data.
The The AURORA survey survey is the is the first first GeoStreamer MultiClient 3D project 3D project in the in the Browse Browse Basin Basin
giving giving greatly greatly improved resolution and and penetration over over existing existing data data sets. sets.
• Broad • Broad bandwidth 7,719 7,719 km 2 km of 2 of GeoStreamer 3D 3D coverage
• Gas • Gas discovery at at Burnside within within the the survey survey area area
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• • High-resolution GeoStreamer data data to image to image targets targets at all at levels all levels
• Clearest • Clearest imaging imaging ever ever of of PermoTriassic fault fault blocks blocks and and stratigraphic pinchouts
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seismic technology: permanent reservoir monitoring
The Value Of PRM In
Enabling High Payback IOR
Martin Bett, TGS
Innovative uses of seabed seismic
technology can help operators achieve
considerably higher returns from new
and mature fields. High potential returns
with low risk and lower lifetime cost of
ownership are increasingly attractive.
An increase in hydrocarbon recovery factors
from a producing reservoir can make a
significant economic contribution. In Norway,
for example, it is estimated that “a 1% increase
in the recovery rate for fields that are currently
operating will increase oil production by
approximately 570 million barrels of oil”.
Assuming an oil price of NOK 570 per barrel
(A$95.00), “the gross sales income from such an
oil volume is approximately NOK 325 billion”*
(A$53.5 B).
It is acknowledged that many of the enabling
technologies deployed on fields on the
Norwegian Continental Shelf that have
contributed to the high recovery rates have
been developed through close cooperation
between international seismic companies
and regional operators. Indeed, the use of 4D
seismic on the Gullfaks field alone has been
estimated by Statoil to provide value creation
equalling about NOK 6 billion (A$1 B), with the
value creation from 4D seismic over the last
10 years estimated at more than NOK 22 billion*
(A$3.7 B).
As a result, it is likely that the number of
seabed multi-component time-lapse (4C/4D)
seismic permanent reservoir monitoring
(PRM) systems (See Figure 1) will increase in
the years ahead as successive surveys on four
existing field installations (See Table 1) fulfil
their promise to deliver 4% to 6% additional
recovery. Asset managers who have studied
the results know that the benefits of ‘on
demand’ 4D seismic over the life of the field
far outweigh the cost. To help overcome
the inertia that can block operators in other
regions from accessing these benefits,
innovative feasibility, seabed risk mapping
and illumination studies are being conducted
to ensure effective project delivery and
mitigate the potential risk that a PRM system
installation costing tens of millions will not
prove profitable.
Year km Operator Region Field Comments
1995 30 BP, Shell N Sea Foinaven Experimental
2002 8 ConocoPhillips N Sea Ekofisk Test line
2003 120 BP N Sea Valhall Operational
2004 10 Shell GoM Mars Test line destroyed in
Hurricane Katrina in
2005
2006 40 BP N Sea Clair Operational
2007 120 BP Caspian CARSP Operational
2007 1 Multiple N Sea Tjeldbergodden Test line
2008 4 ConocoPhillips N Sea Ekofisk Test line
2008 1 Multiple N Sea Tjeldbergodden Test line
2009 25 Statoil N Sea Snorre Test line
2010 200 ConocoPhillips N Sea Ekofisk Operational
2012 30 Petrobras Brazil Jubarte Installation Q4 2012
2013 90 Shell Brazil BC-10 Planned
2013 260 Statoil N Sea Snorre Phase I Planned
2014 165 Statoil N Sea Grane Planned
2015 230 Statoil N Sea Snorre Phase II Planned
Table 1. Chronology of PRM trials and implementations.
These risk mitigation studies have been
developed because the upfront cost of a
PRM installation is expensive compared
to alternative approaches to seismic data
acquisition. Although a US$50 MM to
US$100 MM PRM system requires about
the same level of investment as one deepwater
well, PRM investments are often seen
as major projects with too much technical
and commercial risk. This perception is
slowly changing given the industry’s track
record over the last 10 years and the slowly
emerging published results from operators
who made the leap of faith to install the early
PRM systems.
The early adopters now understand that a
PRM system is considerably less risky than
a deep-water well and they have learned
that a well-designed PRM system is capable
of delivering a substantial reward. The PRM
prize can reach an ROI of five to 25 times
the cost of the investment because the
superior images are delivered frequently
enough so that they can impact all aspects
of improved oil recovery (IOR) programmes.
This is well understood by oil companies
such as Statoil which has recently approved
large PRM system implementations on
the Snorre and Grane fields to support its
strategy of achieving a production rate of
more than 2.5 MM boe per day by 2020.
PRM systems impact IOR programmes so
significantly because stationary arrays of
sensors offer geoscientists a new “super high
definition resolution” dimension to time-lapse
seismic. Simply by ensuring that no sensor
movement takes place between subsequent
surveys, and that the data is full azimuth, data
resolution and accuracy are greatly improved.
This substantive improvement reduces
processing time, and costs, while enabling
informed reservoir management decision
making that impacts five significant drivers of
improved recovery:
••
Better in-field exploration
••
Improved well placement
••
Optimised completions
••
Fracture monitoring from active and passive
micro-seismic
••
Flood front monitoring.
44 | PESA News Resources | December 2012 / January 2013

seismic technology: permanent reservoir monitoring
Geoscientists and engineers who manage fields with PRM systems
are experiencing these benefits because they are not limited to the
compressional data of a towed survey. By leveraging 4C/4D data they
can map minute pressure changes, monitor saturation and phase
changes, and manage reservoir drainage. With these inputs, production
can be optimised with better planning of in-fill drilling locations,
improved sweep efficiency, and most importantly, accurate knowledge
of what is going on between the wells (See Figure 2). Drillers are even
taking advantage of permanent seismic array data to understand
geomechanical rock properties and to monitor cuttings disposal beds
to avoid overcharging them.
In common with experience in the telecommunications industry which
has relied on optical fibres for over 30 years, the latest PRM systems use
fibre-optic technology that has been qualified to deliver a 25+ year life
in deep water. By way of an example, proven optical hydrophones and
orthogonally-mounted accelerometers in Stingray seismic sensing arrays
have a low noise floor and a 180 dB dynamic range . Cables on these
systems are lightweight with simple and reliable connectivity that have
been rigorously tested and qualified to military standards. With no subsea
electrical power requirements, the seabed array is connected through a
riser cable to a compact acquisition and recording unit situated on surface
facilities, an FPSO or tied back to a remote host facility up to 500 km away.
Fig. 1. A typical seabed array of bi-directional optical cables linked to a
production facility allows operators to affordably monitor production and
injection performance on demand and to improve recovery with lower drilling
and EOR expense.
Image courtesy of TGS
Unlike towed streamer surveys, ocean bottom cable surveys or node
surveys, permanent sensors installed on the seafloor minimise the
impact on existing oilfield infrastructure and enable highly repeatable,
cost-effective time-lapse seismic imaging in and around obstructed
zones. PRM systems are much less costly over the life of the field and
present a significantly lower health, safety and environmental risk (See
Table 2).
As many mature offshore fields have low recovery factors, the question
being asked is no longer “Why 4C/4D PRM?” – the question now is “Why
not 4C/4D PRM?”
Man-hours /
200 km 2 survey
Towed OBC Node Permanent
36,000 235,000 72,000 10,000
Major risk Towing Cable lay Node lay Gun work
CO 2 emissions
per survey
High High Medium Low
Table 2. Qualitative HSE risk comparison of four types of 4D surveys adapted
from Seismic Surveillance for Reservoir Delivery, Education Tour Series, EAGE
2012.
* Meld. St. 28 (2010–2011). An Industry for the Future – Norway’s
Petroleum Activities.Whitepaper Report to the Storting, published by
the Norwegian Ministry of Petroleum and Energy, Norway, 2011.
Fig. 2. An array deployed between producers and injectors gives dynamic
detail needed to optimise sweep efficiency, identify bypassed oil and detect
compartmentalisation by seeing what is going on bet ween the wells.
Image courtesy of TGS
December 2012 / January 2013 | PESA News Resources | 45

onlaps
In Praise Of Older Cycles – P art 3 of 3
Rob Kirk, Rob Kirk Consultants
This article on geological cycles is the
3 rd and last part of the cycle seriesnote
that figure numbering continues
on from the last article which appeared in
PESA News Resources #120.
Figure 27 (from Vyssotsky and Keith, 1992) shows
a sketch of a 2 nd order Cretaceous cycle from
Siberia (taken from a Russian seistrat book). The
individual sketch sequences can be seen as the
Fig. 27.
Fig. 28.
oil filled yellow delta pulses. Note the classic 2 nd
order interfingering between the deltas (yellow)
and fluvial (orange). This figure is interesting as
the purple facies represents the Bazhenov Shale,
one of the world’s great marine source rocks.
Here we see the Russian’s view of how this source
rock works. It is composed of the condensed
section of several 3 rd order “sequences” stacked
together and not 'diluted' by any intervening
clastics. This thin source rock (only 10’s of metres
thick) must be considered as unconformity
bounded and we cannot interpret it using the
standard LST, TST or HST terminology.
Many of the world’s 'big' marine source rocks
act like this-such as the Gothlandian in North
Africa, the Kimmeridge in the North Sea, the
Pebble Shale in Alaska and the La Luna in
Trinidad, Colombia etc.
We have most of these rocks in Australian
basins but they have not reached the richness
of those above-either due to climatic/
oceanographic differences or “out of phase
sequence stacking” that dilutes the organic
facies with clastics.
Figure 28 from the same publication ( Vyssotsky
and Keith, 1992) shows how the Russians
have cycles within cycles-as we have been
discussing.
Figure 29 is (low fold) seismic through the
Russian 2 nd order cycle (Vyssotsky and Keith,
1992). The seismic facies are as we see them in
many basins, namely LAC basal TST/HST shales,
HAC HST deltas and LAC HST fluvial facies.
Figure 30 (Vyssotsky and Keith, 1992) is a well
section in Siberia showing the 2 nd order cyclenote
that the yellow sands are both fans and
deltas-there are many 3 rd order cycles on this
section. This is a relatively short period of time
(Neocomian) and many of the fans appear
to be high stand related-suggesting active
tectonics.
These patterns are remarkably similar to the
coeval Barrow Group sediments in Western
Australia-see Figure 31.
Figure 31 is a NE-SW well section between
Barrow Island and the coast of Western Australia
with orange topset facies being HST deltas and
fluvial, basinal yellow facies being basin floor
fans and the green sands being apparently high
stand fans-as seen in Siberia. (Scales of the two
figures are approximately the same – see
120 Collins Street, Melbourne, 80 story
building for scale on Figure 31, lower left) The
Exxon model does not work so well when
active tectonics are occurring as we can get
significant amounts of high stand fans.
Fig. 30.
Fig. 29.
Fig. 31.
46 | PESA News Resources | December 2012 / January 2013

onlaps
Figure 32 shows a Cretaceous-Tertiary,
dominantly carbonate, 2 nd order cycle that
occurs over much of the Western Australian
offshore. Even at this highly condensed scale
we can see candidates for the component 3 rd
order SBs.
Fig. 32.
Figure 33 shows another 2 nd order cycle-Tertiary
clastics (with some volcanics) in the Taranaki
Basin, offshore the North Island, New Zealand.
Here the best fans are the early ones-as seen in
Brazil, North Africa, West Africa, Gulf of Mexico
inter alia.
Figures 34 (uninterpreted) and 35 (interpreted)
show an excellent 2 nd order Tertiary clastic cycle
in SE Asia. As seen in most examples the 2 nd
order fan is better developed that the 3 rd order
fans in the 2 nd order HST.
Fig. 33.
Figure 36 shows the Exxon log (gamma) model
(described in earlier Onlap articles in PNR) with
a 2 nd order log cycle from the entire Neocomian
Barrow Group of the Exmouth Sub-basin,
Western Australia. The massive 2 nd order fan
complex (in orangey-brown) is composed of
many 3 rd order fans stacking together. (These
fans are spectacular with one of the youngest
being deposited 60+ km from its coeval shelf
edge).
Fig. 34.
Figure 37 shows the Barrow 2 nd order cycle
on seismic. The yellow basal unit is a gigantic
undrilled (?) 2 nd order fan complex overlain by
the 2 nd order HST slope facies (grey) and 2 nd
order fluvial-deltaics (orange).
Figure 38 is a more unusual 2 nd order fan cycle,
from the Barrow Group in the Barrow Sub-basin
Fig. 35.
Fig. 37.
Fig. 36.
December 2012 / January 2013 | PESA News Resources | 47

onlaps
Fig. 38. Fig. 40.
(from Boote and Kirk, 1984) of Western Australia.
This figure shows an apparently increasing up fan
cycle from Late Jurassic to Neocomian. Note the
better fan development in yellow as we go up in
the Bambra well. The late Jurassic fans are small
and not very sandy, the Barrow fans are bigger
and sandier but the best fan system is the Flag
Fan, being the LST of the Zeepaard sequence. The
Harriet group of fields are in the Flag Fan.
Another 2 nd order cycle is seen in Figure 39
in the Great Australia Bight Basin of southern
Australia. The red horizon is a 2 nd order SB with
massive channels cut into it that suggests
undrilled basin floor fans may be present
outboard. This unconformity represents the
change from a more sag dominated, shallow
marine basin to a deep water 'drift' basin as
Antarctica tears away from Australia.
Figure 40 shows the base of the Tertiary
2 nd order cycle in the Taranaki Basin in New
Zealand. We see on log and in outcrop a
coarsening/thickening up fan which then fines/
thins up. The seismic shows the fan which has
the common HAC seismic character.
Figure 41 shows the same 2 nd order cycle
elsewhere in the Taranaki Basin with the basal
2 nd order fan in yellow but not such high
amplitudes and continuity. Each basin is a bit
different so you need to “get your eye in” on
how fans etc look in your area.
These lower order cycles seem to be relatively
common and it may be worth looking at them in
your acreage or in the next farm out data room
as they could be useful in predicting the type of
reservoirs that may be present up and down dip.
I have operationally used them to help predict
a source rock location and where to focus
down dip exploration for fans.
Happy hunting.
Any image resolution issues are solely due to the
author and not the publisher.
References
Armentrout, J. (1993) Integrated Stratigraphic
Analysis – SEPM Short Course, New Orleans,
23–25 April.
Boote, D.R.D., Kirk, RB. (1989) Depositional
wedge cycles on evolving plate margin, West
and Northwest Australia. AAPG Bulletin, Vol. 73,
pp. 216–243.
Bruhn, C., (1998), Deepwater Reservoirs from the
Eastern Brazilian Rift and Passive Margin Basin, AAPG
International Conference, Rio de Janeiro, Brazil.
Cramez, 2009, University of Fernando Pessoa,
homepage.ufp.pt/biblioteca/Seismic/Images/
Plate290-Breakup2.jpg
Den Hartog Jager, D., Giles, M., Griffiths, G.,
(1993), Evolution of Paleogene fans in the North
Sea, In: Parker, J., (Ed.), Petroleum Geology of
NW Europe: Proceedings of the 4 th Conference.
The Geological Society, London, pp 59–71.
Haq, B.V., Hardenbol, J. (1987) Chronology of
fluctuating sea level since & Vail, P.R. the Triassic
(250 million years ago to present): Science, Vol.
235, pp. 1156–1167.
Jennette, D., Wawrzyniec, T., Fouad, K., et al, (2003),
Traps and turbidite reservoir characteristics from
a complex and evolving tectonic setting, Veracruz
Basin, southeastern Mexico, AAPG Bulletin, Vol. 87,
No. 10, pp. 1599–1622.
Vail, P.R. & Womardt, W.W (1990), Well logseismic
sequence stratigraphy. A new tool for
exploration in the 90’s. pp. 379–388. GCSSEPM
Foundation. 11 th Annual Research Conference.
Program and abstracts, December 2, 1990.
Vail, P. & Wornardt, W. (1991) Well, Seismic & Log
Sequence Stratigraphy. AAPG Course, Dallas,
April.
Vyssotsky, V & Keith, J. (1992) West Siberian
Study. ESRI Technical Report 92-02-372.
White, D. (1990) Assessing oil and gas plays in
facies-cycle wedges. AAPG Bulletin, Vol. 64, pp.
1158–1178.
Fig. 39.
Fig. 41.
48 | PESA News Resources | December 2012 / January 2013

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view from the top
Blind Date Provides Long
And Satisfying Relationship
PESA News Resources recently met
up with John Stanton: Managing
Director, Energy, RPS Australia Asia
Pacific, who has a 30+ year history in the
petroleum exploration industry, to talk
about his career.
His experience and knowledge is extensive
and there aren’t many people in the industry
better known and liked. He’s loved being part
of the industry and it appears his only regret
is his golf handicap. What is it? True to the
explorer in him: “it’s a work in progress.”
Going back to the beginning John, what’s your
background, and what helped you map out
your career?
I spent most of my teenage life in Hong Kong.
This was the 60s and Hong K ong was a much
quieter place than it is today. At the age of 18 I
returned to the UK to further my education and
get a degree. Initially attending an electrical
engineering course, I quickly realised that my
heart wasn’t in it. I knew I wanted to have a
degree qualification so I applied to Lanchester,
which was offering a BSc in Applied Physics.
When I graduated I realised that I had spent a
very pleasant three years playing rugby, golf,
drinking beer and studying but I still had no
idea what I was going to do. I remember to
this day ordering a pint of bitter with my last
20 pounds and feeling daunted by the prospect
of getting a job.
I needed money to live, so I worked in a
lemonade factory in London, while I applied for
more ‘career-orientated’ positions. One such job
advertised by GSI, a leading seismic company
at the time, wanted young graduates to train
as “seismic data processors”. My interview went
well; I outlined my education, my experience
and there was a point at which the int erviewer
linked my overseas experience with my
education and offered me a job. I was a trainee
electronic instrument engineer on board a
seismic vessel in Australia and had to be ready
to fly in five days. That was the beginning.
What attracted you into the industry?
Like a lot of people I k now, especially in the oil
and gas service industry, I fell into the industry
rather than seeking it out. It was more of a
“blind date” which resulted in a very long and
satisfying relationship.
What do you think it takes to succeed in the
petroleum sector?
I truly believe that we are all blessed working
in the industry that we do. It is an industry
that has demanded the highest technical
specification from “silicon valley” year on year.
It has some of the highest technical achievers
in the world. It has operational diversities
from frozen tundra, ice, swamp, desert, jungle,
shallow water, ultra deep water; all having their
own specific challenges.
To succeed in this industry you have to
dedicate a lot of time, be proactive, inventive
and safety conscious. The petroleum sector is
24/7 so you have to be prepared to respond to
changes.
What do you believe separates high-performing
companies from their less successful
counterparts?
I think that the high per forming oil and gas
companies can be viewed, simply, in two ways.
Ones that have capital and ones that haven’t.
In the ones without capital, it is all about
people. Companies strapped for cash need
good leadership to build an experienced team
with all the attributes mentioned previously.
Companies with capital can use this to farm-in
to proven assets and grow their businesses.
When looking at service companies, technology
and the acceptance of technologies play a very
important part in their success.
In Hong Kong with my mother and sister.
Playing soccer for St Alleyne School, Stone, Staffordshire.
50 | PESA News Resources | December 2012 / January 2013

view from the top
As client representative.
Winning team at PESA/ASEG golf tournament with Paul Gilleran, Bill Ashby and
Terry Walker. Love the grin of the triumphant golfer!!!
What are the current technology trends you see
emerging over the short term?
The main technology trends are about
enhancing the seismic image and developing
direct hydrocabon indicators.
The seismic image has been continuously
improved over the years. This has come from
improved acquisition techniques such as:
the increased number of streamers for 3D
data; Q technology; broadband techniques
(Geostreamer, Broadseis, Uniq); and enhanced
processing techniques.
I believe the current broadband technology
will be the focus over the short term. The
technology has demonstrated a step change
in enhancement of the seismic image, by
eliminating streamer ghosting and delivering a
much clearer image.
What is the most significant technological
advancement you have experienced in your
career?
Having a marine seismic background and
been at sea for 15 years, I believe the “multiple
streamer” vessel is the most significant
development: in every respect, from the vessel
design to the streamer control. The resulting
volume of data has enabled the industr y to
produce the final seismic image that is r equired
to explore in all regions of the world.
Without these vessels and their related towing
capacity and control systems, we would not
be as far ahead in exploration as w e are today.
There was a time when “Peak Oil” was a news
item most weeks. Now with our improved
exploration techniques we are discovering oil
and gas at a rate to keep the “Peak Oil” debate
off the front page.
What technology will provide the next step
change—in your opinion?
I think the “Node” technology will be the next
step change.
This has a number of advantages over the
current acquisition techniques. These include
its broadband capability and quiet operating
environment – the sea floor. It doesn’t have
any ghosting, it is HSE friendly through the
reduction of streamer handling, and it is
multi azimuth. However, it needs a significant
reduction in cost before this “technology step
change” can happen.
How have the range of services provided by the
resources consultancy sector changed and what
has driven those changes?
Historically, the main industry requirement was
a technical consultancy with HSE operation
services. While these are still important and
required, more emphasis has been placed
on the Health, Safety and Environmental
aspects of the consultancy services, including
auditing, hazard workshops and Safety Case
requirements.
There is a requirement for HSE training and
qualifications for all consultants and trained
and experienced environmental consultants,
including cetacean monitoring.
There’s been an increasing call for consultant
to manage projects: consultants with local
experience that understand the local regulatory
requirements. There is also an increasing call for
G&G consults to provide “Competent Persons
Reports”.
What has driven these changes? Operators are
looking to reduce risk.
How has RPS managed the change in the r ange
of services required?
RPS has managed the change very well in my
opinion. I doubt we could have imagined the
extent our depth of services would grow to.
Today, services in the industry have to be
offered within a robust HSE management
system which RPS has developed. We set out to
ensure all the risk associated with our activities
under our control are understood and are as
low as practicable.
We have ensured we have“in house experts” for
remote operations such as seismic sur veys, site
surveys, MMO services etc. We identify potential
risks and give professional advice on upcoming
projects. We have established a strong team of
HSE and Risk Management consultants in Perth,
Brisbane and Kuala Lumpur. The same applies
to managing the technical risk of the ‘asset’,
with a strong team of geologists, geophysists
and petroleum engineers in Perth, Singapore
and Brisbane.
RPS has also built an environmental group
in Perth and the Eastern States which can
address, EIAs, cultural heritage, native title; and
a ‘Water’ team provides water management
advice and services across mining, CSG and
unconventionals.
How do you think Australia compares on the
global stage in exploration and production?
In general I think we compare well.
I think the terms and condition of our exploration
and production permits, coupled with the stability
of our government system makes Australia very
competitive globally. We do not have a strong
local market, which may deter some investors.
December 2012 / January 2013 | PESA News Resources | 51

view form the top
This reminds me how long I have been trying to master the game of golf with a
young Bob Beatie, John Law and I think, Hank Mitedera.
In China meeting clients – where has the hair gone?!
Our regulatory process is proving to be a
hurdle and needs to be better understood in
the near future to avoid it becoming a barrier
to investment into Australia. I believe a better
understanding of the process is ongoing and
Australia will be the better for it in the long term.
Our wages bill and cost of living has become
an issue as a result of the resources boom and
the high Australian dollar. This is a factor most
global companies consider.
What do you think are the major challenges the
oil and gas sector has yet to face a) in the shortterm
and b) long-term?
Public awareness of the industry practices and
projects is becoming a major challenge in the
short and the long term. Projects are at risk of
stalling or being stopped by a misinformed
public sector. This is a challenge that requires a
different thought process at the board level.
The take-over of Fugro’s geoscience division
by CGG Veritas was recently announced. Were
you surprised and do you feel there is reason
for further consolidation in the sector? What
impact do you feel the merger will have on the
Australian sector?
Yes, I was surprised when the take-over was
announced. It took a while to sink in but then
when you think about the reasons it starts to
make sense. With the continual requirement for
research and development in the contracting
seismic business, the recent flurry of contractors
positioning themselves with a “broadband”
product was probably the straw that broke the
camel’s back. Fugro is not a company that enjoys
having a product or service that is not ‘state of the
art’ or close to it. It would not be in their business
model to be 3 rd or 4 th as a service provider.
I do not think it will have much impact on the
Australian sector.
What do you hope to achieve for RPS in your
role running the Energy division?
To grow the RPS services thoughout the
Australia, Asia Pacific region.
Establishing the robust HSE management
system as a frame work for all our activities
will greatly assist us to achieve this. We have
offices in Jakarta, Singapore, Kuala Lumpur,
Perth and Brisbane and have been recruiting
local, experienced consultants in each to ensure
we can meet the local requirements for most
tenders being issued.
What have been your greatest rewards and
achievements from pursuing a career in the
resources sector?
It’s definitely the people I have met and
worked with all these years. I have the utmost
admiration for the people that work in our
industry, and it has been a pleasure to go to
work every day.
What has been your biggest challenge during
your career and how did you overcome it?
The biggest challenge is being in my current
position, managing director of RPS Energy AAP.
There are many components to the job,
including management of employees, associate
consultants, client relations and expectations,
growth and P& L.
It’s very demanding, requiring a game of golf at
least once a week to balance the stress!
What do you think the industry can do to make
itself more attractive to today’s youth?
Showing we offer a stable industry is the key to
attracting youth. Historically the industry has
been boom and bust, which has had a negativ e
effect on recruitment. Maybe with $100 oil
for an extended period of time will have a
stabilising effect.
What advice do you have for young professionals
embarking on a career in resources?
Once you make the choice to join the industry
listen to your peers: there is a wealth of
knowledge in the industry which only comes
from experience. Ask many questions, and
when you feel you have a good idea, express it.
There are fewer people in the industry than you
think and your ideas are important and may not
have been thought of before.
When a chance comes along grab it with both
hands.
How do you manage a work/home balance?
That’s easy, I don’t manage that part of my life,
my wife does. I could ask her but I am sur e she
will say that is a mutual management process
that all in the family has to be on-board with.
Work hours, time away from home etc, all has
to be accepted by the family.
What changes would you make (if any) if you
could do it all again?
I can honestly say that I would not change a
thing. It has been a very rewarding career thus
far and I hope to be going for a few more years
yet.
52 | PESA News Resources | December 2012 / January 2013

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geothermal
AGEC 2012:
The Heat Is On For Australian Geothermal
The 2012 Australian Geothermal Energy
Conference was dubbed ‘unleashing
the heat’, and while overcast and
cool conditions reigned at Sydney’s scenic
Coogee Beach, inside the beachside Crowne
Plaza conference venue the hot topics in
geothermal were addressed by industry,
academia and government over the course
of three days and a variety of presentations.
The mood from the outset was frank, reflecting
an industry optimistic about its prospects yet
realistic in its appraisal of how far it has come
and the challenges it faces.
Federal Resources and Energy Minister Martin
Ferguson perhaps set the tone with his admission
that over the past five years the geothermal
industry had not experienced anywhere near the
growth or development anticipated.
“We have not made as much progress as we
would have thought five or six years ago;
it’s proved far more challenging than we
would have thought in terms of the capacity
of industry and I might say where our own
thinking was, the government, in terms of these
issues,” he commented.
Following the recent release of the 2012 Energy
White Paper, Ferguson’s address was topical,
as the government lays out its blueprint for
Australia’s energy future. He told the conference
the make up of Australia’s energy mix is highly
complex, stating the government’s carbon price
is a key driver of the long-term transition to a
low carbon economy, with the market itself
fundamentally driving change.
“The White Paper emphasises that Australia’s
future energy technology fuel mix will be
determined by the market, and so it should be,”
he commented. “The key role of the Australian
Government is to provide proper regulatory
frameworks to meet its policy objectives, and
that is a complex, difficult debate.”
Spruiking the government’s clean energy
credentials, Ferguson noted the Clean Energy
Finance Corporation will come into being
next year, and stated ARENA (the Australian
Renewable Energy Agency) will also be a key
driver of the development of renewable energy
industries.
Ferguson told the conference long-term Treasury
modelling has suggested geothermal sources
could comprise around 20% of Australia’s energy
mix by 2050, however this was tempered by the
observation that Bureau of Resources and Energy
Economics modelling has also found the cost of
geothermal development is likely to be higher
than previously anticipated over the next
15–20 years.
“This underscores the extent of the challenges
geothermal faces in reaching commercialisation
here in Australia. I think we all acknowledge
and appreciate that the development of the
technologies that supply geothermal energy
has not occurred as quickly as we all would
have liked,” Ferguson stated.
Observing the NSW Government believes the
geothermal industry “does hold a great amount
of promise both here and across the country,”
Chris Hartcher, the NSW Minister for Resources
and Energy, like Ferguson, talked about the role
geothermal may well potentially play in the
future energy mix.
“The NSW Government views direct use
geothermal technologies as having significant
potential to provide Sydney, and indeed all
of NSW, with a significant means of offsetting
growing electricity demand and abating
greenhouse gas emissions,” he stated
“With an estimated 55 GW of potential
electricity generation, if 20% of the total
estimated peak energy was extracted, NSW may
have the potential to generate up to 46 times
more energy from geothermal resources than
currently generated using fossil fuels.”
To this end, Hartcher stated the state government
supports geothermal resource mapping, along
with the funding of further research, and
extending the mineral exploration licensing
regime to include geothermal resources.
Hartcher, however, like Ferguson, noted
investment barriers need to be overcome,
commenting that the NSW Government is
committed to building confidence for investors
and developing a framework that encourages
private sector investment.
“The industry does continue to face investment
barriers in the form of higher price costs in
drilling and identifying geothermal resource.
At this stage, there are still significant steps to
be taken to develop the industry,” he told the
conference.
Federal Resources and Energy Minister, Martin
Ferguson.
NSW Minister for Resources and Energy, Chris
Hartcher.
“We acknowledge the government has a role
to play in encouraging research and investment
and ensuring that there are not unnecessary
barriers to investment.”
54 | PESA News Resources | December 2012 / January 2013

geothermal
If the impression given by the federal and state
energy ministers was one of cautious optimism
and long-term, rather than short or mid-term,
thinking, Kobad Bhavnagri, Bloomberg New
Energy Finance Lead Clean Energy Analyst, was
by comparison brutally candid in his assessment
of the current state of the industry in Australia.
Bhavnagri noted the outlook for the global
geothermal sector is relatively strong, with
countries in the Asia Pacific, among them
Indonesia leading the charge, offering up
promising signs. In all, Bhavnagri noted, there
are currently 273 projects being undertaken in
50 countries around the world, but with only
16%, 1.9 GW, currently under construction.
“The sector is poised for steady growth. This will
mostly be in the emerging markets around the
world which have an abundance of very high
quality resources,” he told the conference.
“What has driven investment so far, and
what will continue to drive investment, is the
activity of development banks. Development
banks have really picked up their game,” he
commented, noting that money continues to
flow into developing countries.
Additionally, a number of countries have
implemented feed-in tariffs which, he stated, is
helping drive deployment. However, he cautioned
that there are “several uncertainties” that he told
the conference seem “to be systematic around
geothermal developments around the world.”
“When you start to look at the historic
performance of geothermal installations around
the world … we see that the capacity factor
that geothermal actually contains is only 73%
on global average, and that’s in stark contrast to
the accepted wisdom in the industry that you
always get a capacity factor of 95%,” he stated.
“Availability factors are very high, the capacity
factors tend to be low because sites often
under-perform,” he commented. “We’re really
telling the industry to be very thorough in your
resource characterisation and conservative in
your modelling.”
He also cautioned that motivation for Australian
investment is comparatively low in a market
abundant with fossil fuels. “You have a lot of
low hanging fruit,” he observed. “So why would
you do the very difficult thing?”
Indeed, this is a clarion call to the federal and
state governments to continue to provide further
incentive to get projects off the ground, and,
throughout the conference, various aspects of
project management were examined by presenters,
Kobad Bhavnagri, Bloomberg New Energy Finance
Lead Clean Energy Analyst.
from the identification of resources, through to
methods of harnessing resources, to means of
transferring of energy to the electricity grid.
The global financial crisis may well have
presented new challenges for the worldwide
geothermal sector, yet, doubtless, the appetite
for clean and renewable energy technologies
remains, with geothermal at the forefront
of many governments’ thinking. If AGEC
highlighted one thing, it is that the potential for
geothermal energy in Australia is huge and that
there is a significant Australian expertise intent
on driving the industry forward.
As the government continues its push towards
a less carbon intensive economy, future
planning may well see the heat unleashed, but
for the geothermal sector it currently seems to
be a case of “watch this space”.
The 2012 Australian Geothermal
Energy Conference was held near
Sydney’s scenic Coogee Beach.
December 2012 / January 2013 | PESA News Resources | 55

words
Duh Vinci
A
paper I edited recently for AAPG
regularly used the wrong words. For
example, High density sources have
been interpreted as Miocene reefs, amplified
by underlying Oligocene intrusives.
(In the interests of not too blatantly fingering
the author, I have modified this and other
examples slightly from the original, retaining
the errors but changing the setting.)
Are the high-density bodies properly described
as ‘sources’? The context is that they are
the ‘source’ of the positive Bouguer Gravity
anomalies. Underlying dense intrusive material
was interpreted as also contributing to the
gravity highs. So, it was the gravity highs that
were amplified, not the Miocene reefs.
I do sense an increase in this type of error in
the geological papers I’ve edited over the past
few years. Is this the geoscientific community’s
drift into Amglish, the ‘language’ I discussed last
month, with its dumbing-down loss of precision
and a lack of any care at the loss; indeed, a
cheering at the freedom of close-enough will
do, and applauding this as far more politically
correct for our times than the elitist notion of
speaking properly. I hope not.
By co-incidence, I was browsing through past items
in a favourite blog, Language Log, when I came
across posts by Geoffrey K. Pullum criticising the
writing in Dan Brown’s novel The Da Vinci Code.
One of his posts offered an excellent example of
imprecision. (May 1, 2004, The Dan Brown Code)
Pullum quoted from the first page of the novel,
as terrified Louvre curator Jacques Saunière
flees from his attacker.
A voice spoke, chillingly close. "Do not move."
On his hands and knees, the curator froze, turning
his head slowly. Only fifteen feet away, outside
the sealed gate, the mountainous silhouette of
his attacker stared through the iron bars. He was
broad and tall, with ghost-pale skin and thinning
white hair. His irises were pink with dark red pupils.
Pullum then listed the errors and imprecisions
– what he, being precise, called infelicities and I
quote him almost directly below.
1. A voice doesn't speak — a person speaks; a
voice is what a person speaks with.
2. ‘Chillingly close’ would be right in your
ear, whereas this voice is fifteen feet away
behind the thundering gate.
3. It was the fall of the gate that made a thunderlike
noise; the gate itself wasn’t thundering.
4. The curator cannot slowly turn his head
if he has frozen; freezing (as a voluntary
human action) means temporarily ceasing
all muscular movements.
5. A silhouette does not stare! A silhouette is a
shadow.
6. If the curator can see the man's pale sk in,
thinning hair, iris colour, and red pupils (all
at fifteen feet), the man cannot possibly be
in silhouette.
Perhaps we can call such errors duhvincis.
It is important for authors to read closely what
they have written. This is especially true for
younger authors, many of whose schooling
had a less rigorous approach, shall we say, to
grammar and writing than was the case for
older Pesapersons.
I have touched before on this need for very
careful reading of what has been written before
it is passed onto editors or managers and the
like. It is a point that needs regular restating. It is
too easy to simply glance across the words and
sit back with a Nobel-winners smile, confident
that the words say exactly what was meant.
Consider these sentences from recent papers:
••
‘When lake level rose and spilled into an
adjacent basin …’
••
‘The overfilled lake model occurs when
the rate of supply of sediment and water
exceeds the potential accommodation.’
••
‘The top surface of the lower unit reflects
the thickness changes of this sequence.’
••
‘The main objective was to interpret
basement structure within the data.’
••
‘The contract deadline was not achieved
because of the timely negotiations
necessitated by the contractor.’
The meaning is clear enough in most cases but
the words do not say what the writer meant to
be saying.
••
Lake levels can’t spill. ‘When lake levels rise
and the water spills into …’
••
Models don’t occur, in the real-world sense
used here. (Plus I have always had a struggle
accommodating ‘accommodation space’ as
a necessary term – though several geologist
friends I admire greatly, and whose skills
exceed mine, are enthusiastic supporters and
users of the term; so it might be me. But, in
this case, is it the potential accommodation
that is being exceeded? Or is it the actual
accommodation? And, while I’m being picky,
shouldn’t it be ‘accommodation space’.)
••
The isopach reflects (shows?) the changing
thickness of the sequence; the top (upper?)
surface does not. (I can hear the ho wls
that, given a smooth lower surface for the
sequence, the top surface would reflect the
thickness changes. Fair enough. If that was
the case, the sentence is acceptable. But it
has to be read in context and that decision
made by the writer.)
••
There is no ‘basement structure within the
data’; …from the data? …using the data.
Maybe … use the data to interpret …
••
The negotiations weren’t timely; they
were time-consuming. ‘Required’ by the
contractor would be better.
As several of these examples show, a common
problem is the imprecise use of a term in relation
to the action being discussed; the lake level
‘spilling’ or the model ‘occurring’. Sometimes it is
just poor expression and needs more work.
Confronted by these confused sentences, an
experienced editor or manager will begin to
look very closely at the technical details. If
a writer can’t put down what he means in a
simple and clear way, it might be revealing
that he doesn’t have a clear and simple
understanding of what he (or she) is saying.
I have cited Hemingway many times in this
column, most commonly his declaration that
when you know something well (as opposed
to knowing about it – a distinction one of my
mentors was very fond of ), you know what you
can leave out and still get the message thr ough
clearly. When you don’t know well enough
what you’re writing about, it shows.
On which note, let me remind younger
Pesapersons that the Papa in my August column,
A Reminder from Papa, was not me being all
fatherly. That was Hemingway's popular nickname,
given him, not surprisingly, by his children, and
adopted quite widely by his friends and admirers
later in his life and after his death.
All the best for the New Year. Enjoy the
Christmas season. If it all gets too much, read
the first few pages of The Da Vinci Code and
have a bloody good laugh. Try not to think too
much about the money he made writing that
badly about something so ridiculous. And let’s
have less duhvincis in our writing in 2013.
Peter Purcell
56 | PESA News Resources | December 2012 / January 2013

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