IN WESTERN AUSTRALIA - Department of Mines and Petroleum

APRIL 2004
PETROLEUM
IN WESTERN AUSTRALIA
more developments on the horizon
than ever before...
Western Australia’s Digest of Petroleum Exploration, Development and Production. Department of Industry and Resources

april 2004
Petroleum and Royalties Division - Mineral House
100 Plain Street, East Perth, Western Australia 6004
Tel +61 8 9222 3273 Fax +61 8 9222 3799
www.doir.wa.gov.au
Publisher - RIU Resource Information Unit
Tel +61 8 9382 3955 Fax +61 8 9388 1025
www.riu.com.au
Design & Artwork - Triton Corporate
Tel +61 8 9325 1644 Fax +61 8 9325 1644
www.tritoncorporate.com.au
Editor - Darren Ferdinando
Email darren.ferdinando@doir.wa.gov.au
Cover Photo:
Goldwyn ‘A’ Platform
(Photo Courtesy of Woodside Energy).
All expressions of opinion are published here on the basis that they are not
to be regarded as expressing the official views of the Department of
Industry and Resources. The Department accepts no responsibility for the
accuracy of any of the opinions or information contained herein and readers
should rely on their own enquiries in making any decisions touching
upon their own interests.
Contents
PWA April Edition - Contents
International Contacts 2
Minister’s Message 3
Director’s Comment 5
Review of 2003 - Exploration, Production and Development Activities in Western Australia 7
Resource Branch’s Recent Activities 22
Magnetotelluric Surveys for Petroleum Exploration in Western Australia 24
State Acreage Release March 2004 28
Diving Regulations 32
Coal Seam Methane - what’s the gas? 34
International Risk Consultancy - Company Focus 37
Table 1. Reserves as at 31 December 2003 - Developed Fields 39
Table 2. Reserves as at 31 December 2003 - Undeveloped Fields 39
Table 3. Unbooked Resources as at 31 December 2003 40
Table 4. Cumulative Production to 2003 40
Table 5. Production by Field to 2003 41
Table 6. Seismic Surveys in Western Australia 2003 Calendar Year 42
Table 7. Petroleum Wells in Western Australia 2003 Calendar Year 42
Table 8. Seismic Surveys in Western Australia Operating 2003 Calendar Year 43
Table 9. Petroleum Wells in Western Australia Operating 2003 Calendar Year 44
Table 10. Western Australia list of Petroleum Titles and Holders as at 15 April 2004 45
Department of Industry and Resources - Key Contacts 57
Department of
Industry and Resources
Western Australia’s Digest of Petroleum Exploration, Development and Production.
Department of Industry and Resources.
1

2
PWA April Edition - International Contacts
International
Contacts
CHINA - Shanghai
Mr BJ Zhuang, Regional Director
Western Australian Trade & Investment Promotion
Shanghai Representative Office
Room 2208 CITIC Square
1168 Nanjing Road West
SHANGHAI 200041
PEOPLES REPUBLIC OF CHINA
Tel: +86 21 5292 5899
Mobile: +86 1390 175 8192 (for BJ Zhuang)
Fax: +86 21 5292 5889
E-mail: bj.zhuang@doir.wa.gov.au
CHINA - Hangzhou
Ms Stella Bu, Manager
Western Australian Trade & Investment Promotion
Hangzhou Representative Office
Room 910, World Trade Office Plaza
Zhejiang World Trade Centre
15 Shuguang Road
HANGZHOU 310007
PEOPLES REPUBLIC OF CHINA
Tel: +86 571 8795 0296
Fax: +86 571 8795 0295
E-mail: stella.bu@doir.wa.gov.au
EUROPE - London
Mr Robert Fisher, Agent General
Government of West. Aust. - European Office
5th Floor, Australia Centre
Corner of Strand & Melbourne Place
LONDON WC2B 4LG
UNITED KINGDOM
Tel: +44 20 7240 2881
Fax: +44 20 7240 6637
E-mail: agent_general@wago.co.uk
Website: www.wago.co.uk
INDIA - Mumbai
Ms Sonia Grinceri, Regional Director
Western Australian Trade Office
93, Jolly Maker Chambers No2
9th Floor, Nariman Point
MUMBAI 400 021
INDIA
Tel: +91 22 5630 3973/74 & 78
Fax +91 22 5630 3977
E-mail: sonia.grinceri@doir.wa.gov.au
INDIA - Chennai (Madras)
Mr K.V. Rajan Senior Trade Advisor
1 Doshi Regency
876 Poonamallee High Road Kilpauk
CHENNAI 600 084 INDIA
Tel: +91 44 2640 0407
Tel/Fax: +91 44 2643 0064
Mobile: +91 098 410 4364
E-mail: KVV.RAJAN@doir.wa.gov.au
INDONESIA - Jakarta
Mr Trevor Boughton, Regional Director
Western Australia Trade Office
Australian Trade Commission
Australian Embassy
Jl H R Rasuna Said Kav C15-16
Kuningan JAKARTA 12940 INDONESIA
Tel: +6221 2550 5331
Fax: +6221 522 7103
Mobile: +62 81 2301 4891
Email: trevor.boughton@austrade.gov.au
INDONESIA - Surabaya
Ms Lydia Agam, Manager
Western Australia Trade Office
Graha Pena, 17th Floor
Jl. Ahmad Yani 88
SURABAYA 60234 INDONESIA
Tel: +6231 829 9979
Fax: +6231 829 9975
Mobile: 62 81 2301 4892
Email: lydia.agam@doir.wa.gov.au
JAPAN - Tokyo
Mr Craig Peacock, Official Representative
North Asia
Government of Western Australia Office
Australian Business Centre
28th Floor, New Otani Garden Court
4-1 Kioicho, Chiyoda-Ku
TOKYO 102-0094 JAPAN
Tel: +81 3 5214 0791
Fax: +81 3 5214 0796
Email: tokyo@wajapan.net
Web: www.wajapan.net
JAPAN - Kobe
Ms Noriko Hirata, Manager
Government of Western Australia Office
6th Floor Golden Sun Building
3-6 Nakayamate-dori
4-Chome Chuo-Ku
KOBE 650-0004 JAPAN
Tel: +81 78 242 7705
Fax: +81 78 242 7707
Email: kobe@wajapan.net
MALAYSIA
Ms Elaine Yong, Regional Director
Western Australian Trade Office
4th Floor, UBN Tower
10 Jalan P Ramlee
KUALA LUMPUR 50250 MALAYSIA
Tel: +603 2031 8175/6
Fax: +603 2031 8177
Mobile: 012 2388 174
E-mail: elaine.yong@doir.wa.gov.au
MIDDLE EAST - Dubai
Mr Chris Heysen, Regional Director
Western Australian Trade Office
Suite 106, Emarat Atrium Blg.
PO Box 58007 DUBAI
UNITED ARAB EMIRATES
Tel: +971 4 343 3226
Fax: +971 4 343 3238
Mobile: +971 50 4567 448
E-mail: chris.heysen@wato.ae
TAIWAN- Taipei
Mr Nicholas McKay,
WA Business Development Manager
Australian Commerce & Industry Office
Australian Business Centre
Suite 2606, International Trade Building
#333 Keelung Road Section 1
TAIPEI 110 TAIWAN R.O.C.
Tel: +886 2 8725 4280
Fax: +886 2 2757 6707
Mobile: +886 937 455 431
E-Mail: nicholas.mckay@austrade.gov.au
THAILAND - Bangkok
Mr Siraphop Apilertvorakorn, WA Business
Development Manager
Australian Trade Commission
Australian Embassy
37 South Sathorn Road
BANGKOK 10120 THAILAND
Tel: +662 287 2680 Ext 3307
Fax: +662 287 2589 or
+662 679 2090
E-mail: siraphop@austrade.gov.au
Department of
Industry and Resources
PETROLEUM AND ROYALTIES DIVISION
Mineral House
100 Plain Street, East Perth
Western Australia 6004
Telephone +61 8 9222 3333
Facsimile +61 9222 3430
www.doir.wa.gov.au

The oil and gas industry is a significant contributor
to the economic development of Western Australia
and is the State’s largest resource sector, with total
petroleum sales in 2002–03 of more than $10
billion, or 37 per cent of the total value of the
State’s mineral and petroleum sales, and annual
exports of $7.8 billion in 2002–03 (Figure 1).
The industry directly employs over 13,000 people in
Australia. Around 900 Western Australian service
and contracting companies are involved in the
industry.
The oil and gas industry has enormous potential,
with increasing demand for LNG in the USA, China,
Korea and Japan, as well as opportunities for
further downstream processing in WA. Gas is also a
major source of energy for the State in electricity
generation, minerals processing and service
provision.
Gold
12%
Iron ore
20%
Alumina
11%
Nickel
9%
Others
11%
Petroleum
37%
Minister’s Message
Western Australia is increasingly becoming a major
player in the global oil and gas industry. This
position is predicated on a number of strategic
advantages.
First, WA has significant petroleum reserves, with
our already world-class natural gas reserves
expected to increase substantially with further
exploration and advances in technology.
Second, WA has a strong record of meeting supply
commitments, led by Woodside’s faultless record in
the export of LNG to Japan over the last two
decades. This record contributes to Western
Australia’s reputation as a low sovereign risk
environment.
Third, WA is proximate to many of the world’s
fastest growing economies, making us ideally
placed to both meet their energy needs and assist
them in developing their own oil and gas industries.
Crude Oil
41%
Natural Gas
6%
Condensate
19%
LPG - Butane
2%
LNG
30%
LPG - Propane
2%
Figure 1. Western Australia Resources Sales 2002-03 - $A27.9 billion (Graphic source: DoIR)
PWA April Edition - Minister’s Message
Hon. Clive Brown,
Minister for State Development Western Australia
Fourth, WA has a high quality and diverse skills
base, with our traditional trades skills
complemented by growing expertise in engineering
design, engineering construction and fabrication.
Fifth, WA is a wonderful place in which to live and
do business. We have a high and affordable
standard of living and a warm and welcoming
society.
The challenge for WA is to take advantage of these
strategic advantages and continue to become a
major player in all levels of the oil and gas industry.
We have to utilise WA’s strategic advantages and
the current boom in projects to develop local service
and supply capabilities. It is for this reason that I
organised the Summit on Maximising Western
Australian Business and Employment Opportunities,
which was held on Friday 27 February 2004 in the
Legislative Assembly of the Western Australian
Parliament.
My vision is for a local support industry that will be
able to provide competitively priced services and
supplies not only to our local Western Australia
projects but also to the Asia Pacific region.
Over 60 representatives of Industry, Government
and the Unions attended the Summit to discuss
ways to maximise the benefits to Western
Australians from the State’s major oil and gas
projects. It was a common view of those who
attended that all parties should work together to
maximise the business and employment
opportunities. It was also a common view that
ongoing communication and the building of trust
between the key stakeholders were essential if
progress was to continue.
The major outcome of the Summit was the
establishment of a new Coordinating Council which I
3

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PWA April Edition - Minister’s Message
will chair. The Tripartite Council will consist of
Industry, Government and Union movement leaders
and will, for the first time, facilitate ongoing
communication between the oil and gas industry’s
major stakeholders.
Early focus is to be on strategies to:
• address barriers and impediments to accessing
resources;
• address and overcome barriers and
impediments to the successful participation of
local companies in the oil and gas industry;
• urgently address current and future skill
requirements in the industry and develop and
coordinate an oil and gas industry and
associated service industries training plan.
I look forward to working with the new
Coordinating Council to maximise business and
employment opportunities throughout the State. DoIR
Linda oilfield’s jacket and deck, which were fabricated at the Australian Marine Complex.

2004 - It’s going to be a busy year
Petroleum exploration in Western Australia has
recovered to 2001 levels and there are more
upstream developments on the horizon than we
have ever had. About $11 billion in upstream oil
and gas developments are either committed to or
being evaluated prior to final commitment. The
Petroleum and Royalties Division has a higher
than ever base workload. In addition to this
increased base load activity, the Division is
implementing change on a number of fronts:
NOPSA Transition
The National Offshore Petroleum Safety Authority
(NOPSA) is to start operation on the 1st of January
2005. Western Australia has to prepare for the
transfer of responsibility through amending State
legislation and providing a seamless handover. The
State is unique in being the only State/Territory with
Safety Offshore
State
7%
PETROLEUM DIVISION WORK FUNCTIONS
Onshore Pipelines
Safety Onshore
State
Safety Offshore
Cwlth
15%
5%
5%
Environment
10%
* 22% to NOPSA 1-1-05
* Prior to Royalties joining the Division
*
*
significant oil and gas operations offshore in State
waters and this has complicated arrangements.
Detailed transition plans are being developed to
identify interfaces between the continuing role of
the Department of Industry and Resources (DoIR) as
the Designated Authority (DA) and NOPSA. DoIR will
continue to provide regulatory services both offshore
and onshore for petroleum titles, resource
management, and environment. Additionally, DoIR
will provide regulatory services for onshore safety
including drilling and production and pipelines as
well as for some offshore activities. An estimated
split of resources necessary for these functions is
shown in Figure 1. DoIR will effectively hand over
22% of its responsibilities to NOPSA. A seminar is
planned for later in the year (sponsored by NOPSA,
DoIR, APPEA and the ACTU) to broadcast
arrangements for the transition.
Titles
22%
Admin/Exec
10%
Figure 1. Split of resources between DoIR and NOPSA
Resources
26%
PWA April Edition - Director’s Comment
Bill Tinapple,
Director, Petroleum and Royalties Division
Legislation Amendments
There are currently two petroleum legislation
amendment bills of major significance being
drafted:
• NOPSA Amendments:
These amendments to the WA petroleum
legislation (Petroleum (Submerged Lands) Act
1982, Petroleum Act 1967, and Petroleum
Pipelines Act 1969) will enable NOPSA to
regulate safety in all the State’s coastal waters
and under certain circumstances onshore, for
example, where a pipeline development extends
from offshore to onshore. On those occasions,
NOPSA will be contracted by way of a service
level agreement. This package will also include
the consequential amendments to the State’s
submerged lands legislation to allow for the
Commonwealth’s plain English rewrite of the
Petroleum (Submerged Lands) Act 1967.
• Common Mining Code/Gorgon CO 2
sequestration/Environmental
Regulations/National Competition Policy
Amendments:
These amendments provide for the common
mining code changes since 1994, changes to
the Petroleum Act 1967 and the Petroleum
Pipelines Act 1969 to provide coverage of CO 2
sequestration in the State’s onshore petroleum
legislation to cater for the Gorgon gas
development on Barrow Island, provision for the
drafting of environmental regulations in all State
petroleum legislation and minor National
Competition Policy amendments.
Workshop Outcomes
Following the successful feedback received from the
three breakfast workshops held by DoIR late in
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6
PWA April Edition - Director’s Comment
2003, the Department is following up to implement
the recommendations made at the workshops.
Topics presented and recommended actions were
as follows.
• Simplifying the Petroleum Act
The Department is continuing to refine
amendments. A discussion paper is being
developed. Further consultation will be
organised.
• Greenfield/Frontier Exploration
The APPEA Exploration Subcommittee proposals
for a cascade title gazettal system to determine
which acreage should be classified as frontier
acreage has now been endorsed by the APPEA
Council and is being evaluated by Government.
An Exploration Working Group has been
established by the Upstream Petroleum
Subcommittee.
• Early Access to Data
Industry placed a high priority on gaining early
access to basic data and requested that
Government endeavour to get more information
out sooner. Data transcription and reprocessing of
seismic data is being given a high priority by DoIR.
• Aquifer Depletion Studies
DoIR has carried out aquifer depletion studies
for the Barrow and Dampier Sub-basins, which
indicated significant resources are potentially
being lost. The Department is proposing that a
national government and industry working group
be established under the auspices of the
Ministerial Council on Mineral and Petroleum
Resources to assess the implications of the
issue and develop policies to address prevention
and corrective measures.
WA Acreage Releases
In a continuing effort to maintain exploration,
acreage releases are planned as follows:
• WA State release opens on 30 March 2004 and
bids close 23 September 2004 with 3 blocks in
State Waters in the Northern Carnarvon Basin, 2
blocks onshore in the Perth Basin, and 1 block
in the Officer Basin; and
• Commonwealth acreage release 2004 to be
announced 29 March 2004, with the 1st round
closing 30 September 2004. This round has 3
blocks in the outer northern Rankin Platform, 3
blocks in the Barrow Sub-basin and Rankin
Platform, 3 blocks in the Exmouth and Barrow
Sub-basins and 1 block in the Vlaming Subbasin,
Perth Basin. The 2nd round, closing 31
March 2005, has 1 block in the Bonaparte
Basin, 4 blocks in the Exmouth Plateau and 2
blocks in the Houtman Sub-basin, Perth Basin.
A re-release of the 2003 areas not taken up is
planned for both the Commonwealth and State
areas.
Electronic Petroleum Register
The Electronic Petroleum Register (EPR) upgrade
from an old database system to a modern webbased
system is reaching completion. In conjunction
with this will be the proof of concept testing of Eforms,
which is the electronic update of information
on the register from forms forwarded from
companies electronically to the Petroleum and
Royalties Division.
2004 Direction
Whale investigating the Legendre Production Facility (image courtesy of Woodside)
The Department is committed to completing these
activities in an effective manner, which will maintain
the emphasis on stakeholder satisfaction that we
have set as a benchmark. DoIR

Review of 2003
Exploration, Production and Development Activities in Western Australia
During the 2003 calendar year, 77 petroleum
wells were drilled in Western Australia;
comprising 14 development wells, 21 extension
wells, and 42 new field wildcat wells. This level of
activity marks a significant increase on the
previous year, where 51 wells were drilled. This
has brought the State back to the high level of
drilling activity seen in 2000 and 2001 where 75
wells were drilled in each of those years. The
current level of activity is partly attributable to the
continuing high oil price and improvements in the
gas sales market. On a national level, Western
Australia has attracted over 70% of Australia’s
petroleum exploration expenditure during the
year, indicating the State remains the most
prospective area of Australia for new petroleum
finds (Figure 1).
Activity in the Perth Basin, particularly the northern
portion of the basin, remains high, buoyed by the
Cliff Head, Hovea and Jingemia discoveries in 2002
(Figure 2). During 2003, three onshore and three
offshore exploration wells were drilled, along with
10 development and extension wells drilled onshore
and two extension wells drilled offshore as part of
the Cliff Head project. Of the onshore exploration
wells, Eremia 1 proved to be a success for ARC
Energy just to the northwest of their Hovea
discovery, while Eclipse 1 and Leafcutter 1 had
some interesting gas shows, but were abandoned
as non-economic. The Northern Carnarvon Basin
continues to be the centre of exploration and
development activity, with 31 of the 42 wildcat wells
drilled in 2003 located in that basin, and 22
development and extension wells spudded in the
basin. A number of significant discoveries were
made, including oil pools discovered by the BHP
Billiton Petroleum (BHPBP) wells Stybarrow 1,
Ravensworth 1 and Crosby 1 (Figure 3). Four
exploration wells were spudded in the Browse
Basin, two of these discovering gas in Inpex’s
WA-285-P permit, with the Ichthys 2 extension well
drilled in November to assess the gas discovery
made by Ichthys 1 in June. The sole exploration well
in the offshore Bonaparte Basin, Woodside’s Weasel
1, was plugged and abandoned as a dry hole.
The wave of drilling predicted last year in response
to higher oil prices and an increase in gas contract
availability appears to be occurring, with a mix of
exploration in both brownfields and greenfields
areas. While some of the greenfields exploration
results have been disappointing, for example the
Maginnis and Strumbo wells in the Browse Basin,
there is still a large amount of prospective acreage
that is largely unexplored by modern techniques and
play concepts. Perhaps the most exciting of the
upcoming greenfields exploration is the drilling of
the Sally May prospect (formerly known as the
WA Exploration Expenditure ($ million)
250
200
150
100
50
0
136.3
141.7
119.7
82
85.3
PWA April Edition - 2003 Review
Darren Ferdinando
Research Geologist, Resources Branch
Cetus prospect) in the central Canning Basin by
Kingsway Resources 2001 later this year. If
successful, this prospect has the potential to
completely rewrite current thinking on the Canning
Basin and introduce a number of new play targets
to the region. In the coming year a number of
critical wells are also planned for the onshore
northern Perth Basin, and success with these will
help push the boundary of the region deemed
prospective for liquid hydrocarbons further south.
This, in turn will help spur on further exploration in
the central Perth Basin region.
The Whicher Range 5 well, drilled in the southern
Perth Basin during the second half of the year,
proved to be a mixed result for Amity Oil. While
there is no question that there is a large gas
resource in the Whicher Range field, the extraction
of the gas from tight sandstone units affected by
170.2
191.5
151.3
177.9
Sep-01 Dec-01 Mar-02 Jun-02 Sep-02 Dec-02 Mar-03 Jun-03 Sep-03
Figure 1. Petroleum exploration expenditure in WA and % of total exploration expenditure in Australia.
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
7
Percentage of Australian Exploration Expenditure

8
PWA April Edition - 2003 Review
swelling clays is proving to be a technological
challenge. Work is currently being undertaken by
Amity Oil to look at stimulating the reservoir so that
commercial quantities of gas may be obtained from
the field. As the Whicher Range field is situated at the
southern end of the Dampier to Bunbury gas pipeline,
it is strategically located to provide gas to a large
number of electricity-intensive industries in the South
West, such as the Alcoa aluminium operations.
Looking at other greenfields locations likely to be
explored in the coming year, the offshore northern
Perth Basin will again see significant activity.
Despite the disappointment associated with the
drilling of Twin Lions, Vindara and Mentelle in
February 2003 and Morangie in 2002, some
interesting results were obtained. Residual oil
columns were recorded in a number of these wells
in Late and Early Permian sandstones, with followup
drilling expected to occur soon in the Apache
Energy and ROC Oil operated permits between
Dongara and the Abrolhos Islands.
Continued exploration in the Exmouth Sub-basin on
targets found using the 2D and 3D seismic
coverage acquired over the last few years paid
dividends this year for BHPBP. The play fairway they
modelled in the centre of the sub-basin came up
trumps for Stybarrow with 18.6 m of net oil pay and
this was followed-up by successful drilling of the
Ravensworth prospect, with the well encountering a
37 m oil column overlain by a 7 m gas cap. Even
the Eskdale prospect, which appears to be
subcommercial, was a technical success for BHPBP
with oil shows in tight sandstone confirming the
presence of a valid trap and oil migration. BHPBP
were not as successful in the Browse Basin
however, with their first well in the region, Maginnis
1, penetrating a thick pile of volcanic sediment and
basalt in what was interpreted to be Plover
Sandstone. While this is a set-back for BHPBP and
its Joint Venture partners in these permits, the size
of some of the possible traps and the presence of
source and migration to the east and possibly the
west, mean that work here will continue. BHPBP are
currently re-evaluating their data on the region so
the extent and impact of Jurassic volcanic activity
on the petroleum prospectivity is fully understood.
Exploration activity in the Barrow Sub-basin was
once again dominated by Apache Energy operated
Joint Ventures, assisted by Tap Oil and Woodside
Energy operated Joint Ventures. While no significant
new discoveries were made in the sub-basin, a
number of small discoveries were made in permits
under Apache operatorship, which are likely to be
put into production in the near future. The Apache
philosophy of drilling many, low-cost wells over
relatively small prospects in an area where it has a
strong understanding of the petroleum system,
instead of focussing on finding high-risk, highreward
targets, appears to be paying off. The
Blackdragon prospect, which will be drilled early in
2004, is perhaps the exception to this, but all
indications from Apache are that this prospect looks
extremely good.
The level of exploration activity seen in Western
Australia at present appears to be sustainable over
the medium term based on the number of wells that
are to be drilled as part of permit commitments for
the next 5 years. The acreage in both
Commonwealth and State areas that was released
over the last two years have now in almost all cases
either successfully negotiated Native Title
Agreements or are in the final stages of reaching
Native Agreement and exploration will soon
commence. Future release areas, with
accompanying pre-competitive prospectivity
packages and data, are underway with acreage in
the Northern Carnarvon, Perth and Officer Basins
and a future release of further Canning Basin areas
in the planning stage. While the farmin market at
present is sluggish, it is hoped that as interest in
the exploration ‘hot spots’ of the Perth and Northern
Carnarvon Basins increases, a number of
multinational and larger Australian ‘junior’ explorers
will take the opportunity to invest in the prospective
Western Australian acreage that will be on offer in
the coming year.
On the production and development side, further
development at the Hovea and Eremia oilfields,
including drilling of water injector wells to assist in
maintaining pressure support for the field continued
with 4 development wells drilled there during 2003.
Testing of the Jingemia oilfield in preparation for
submission of a field development plan in 2004
continued during the second half of 2003. In the
offshore Perth Basin, the Cliff Head oilfield was
declared commercial by the Joint Venture and they
have commenced front-end engineering and design
studies and submitted a field development plan to
DoIR. It is expected that first oil will come from the
field in late 2005. Apache Energy drilled a number
of development and appraisal wells, with two fields
brought online as one or two well producers: Hoover
and North Pedirka. The Enfield development, due to
commence production in 2006, gained
environmental approvals for the development and
were in the final stages of obtaining approval for
their field development plan from the State and
Commonwealth upstream petroleum regulators.
DoIR granted a retention lease over the Blacktip
gasfield in late 2003 as one of the initial steps in
bringing the field on-stream to supply gas to the
Alcan aluminium refinery in Gove. During the year
approval was also granted in principle by the State
Government for the Gorgon gasfield development to
commence, including the use of land on Barrow
Island (an ‘A’ class nature reserve) to house gas
processing facilities.
ACTIVITY BY BASIN
Perth Basin
Within the Perth Basin, three onshore and three
offshore exploration wells were drilled. The offshore
wells were follow-up wells to the Cliff Head
discovery and all were plugged and abandoned,
with Twin Lions 1 and Vindara 1 classified as dry
and Mentelle 1 having indications of a 50 m
residual oil column. Of the onshore wells, Leafcutter
1 intersected some interesting residual oil
indications and Eclipse 1, drilled in the central Perth
Basin, penetrated some minor oil shows in the
Cattamarra Coal Measures. In October the OD&E
Rig 28, brought in from SE Asia, spudded the
Whicher Range 5 well. The well has been
suspended after air-drilling operations failed to go
as planned after water break-through. While
elevated gas shows were recorded, further study is
being undertaken by Amity Oil to assess whether a
commercial flow can be obtained through a ‘dry’
fracc process.
The major success for 2003 in the Perth Basin was
Eremia 1, drilled to the northwest of the Hovea
oilfield. Development drilling for the Cliff Head
oilfield saw Cliff Head 3 and 4 drilled early in 2003,
and development of the Hovea oilfield saw Hovea
wells 4 through to 10 drilled in 2003, with Hovea
10 drilled as a water injector well to maintain
pressure support for the Hovea field.
Eremia 1
ARC Energy drilled Eremia 1 in their L1 production
permit, roughly 2 km to the north-northwest of the
Hovea oilfield in a similar style of fault-bounded trap
to that found in Hovea. The well intersected a 15 m
oil column in the Upper Permian Dongara
Sandstone. The field has been production tested
and is currently online and producing into the Hovea
facility at a rate of 238 kL/d (1500 bbl/d). A followup
horizontal well, Eremia 2 was drilled in November
and completed as a producer.
Northern Carnarvon Basin
During the 2003 calendar year, 33 exploration and
22 development/extension wells were drilled in the
Northern Carnarvon Basin. A number of oil and gas
discoveries were made, the most significant of
which are Stybarrow, Ravensworth and Crosby.
North Perdirka 1
The North Perdirka oilfield is located approximately
15 km east of Barrow Island in Apache operated
licence TL/6. The well intersected an 8 m oil column
in the Flag Sandstone and was brought into
production immediately through the Victoria Platform.
Stybarrow 1
The Stybarrow oilfield, operated by BHP Billiton
Petroleum is located in WA-255-P. Stybarrow 1
intersected a 23 m gross (18.6 m net) oil column in
the top Macedon Member.
Cyrano 1
Cyrano 1 targeted a rollover anticline in the Tap Oil
operated permit EP 364 (R1), 4 km to the southwest
of the Nasutus oilfield. The well intersected a 29 m
gross hydrocarbon column comprising a 19 m gas
column in the Lower Cretaceous Mardie Greensand

GASCOYNE
SIGNIFICANT
HYDROCARBON DISCOVERIES
CUVIER
ABYSSAL
PLAIN
INDIAN
ABYSSAL
OCEAN
Refer to Figure 3
EXMOUTH
PLATEAU
CARNARVON
PERTH
NATURALISTE
PLATEAU
in WESTERN AUSTRALIA
ABYSSAL
PLAIN
PLAIN
Oil
GERALDTON
ONSLOW
EXMOUTH
FREMANTLE
ARGO ABYSSAL PLAIN
0 100 400
Department of
Industry and Resources
112^
as at February 2004
114^
Gas
Oil and Gas
Kilometres
DAMPIER - BUNBURY NATURAL GAS PIPELINE
PARMELIA PIPELINE
DAMPIER
PORT HEDLAND
KARRATHA ROEBOURNE
PERTH
BUNBURY
BUSSELTON
NORTH
MEEKATHARRA
Whicher Range
116^
MIDWEST PIPELINE
See Enlargement
Gingin
ALBANY
118^
WEST
Sumba
NEWMAN
INDIAN
OCEAN
SCOTT
PLATEAU
SHELF
Sawu
Scott Reef
Brecknock
Brecknock South
GOLDFIELDS
NATURAL GAS
SOUTHERN
120^
PIPELINE
BROOME
Roti
Dinichthys
Point Torment
KALGOORLIE
DERBY
ESPERANCE
Timor
Territory of Ashmore
and
Cartier Islands (N.T.)
Titanichthys
Ichthys
Gorgonichthys
Yulleroo
Cudalgarra
OCEAN
Figure 2. Significant Hydrocarbon discoveries in Western Australia.
122^
Pictor
124^
PWA April Edition - 2003 Review 9
Laminaria
Saratoga
Prometheus
Cornea
Lennard Shelf
Oilfields
Looma
Joint Petroleum
Development Area
Buffalo
Proposed Bayu-Undan
Pipeline
Petrel
Tern
Blacktip
Waggon Creek
WYNDHAM
St George Range
GERALDTON
Dongara
Jingemia
Cliff Head
Beharra
Springs
Woodada
126^
MIDWEST PIPELINE
Mt Horner
Eremia
Hovea
Beharra
Springs
PARMELIA PIPELINE
North
GEOCENTRIC DATUM of AUSTRALIA
NTv2 GRID FILE TRANSFORMATION
128^
-12^
-14^
-16^
-18^
-20^
-22^
-24^
-26^
-28^
-30^
-32^
-34^
pwawellsGDA_Jan03.lat

10
PWA April Edition - 2003 Review
114^ 116^
Department of
Industry and Resources
Norfolk
Pitcairn
Mutineer
Exeter
Egret
Talisman
Lambert/Hermes
Angel
Cossack
Eaglehawk
Athena
Capella
Perseus
Significant North West Shelf
Hydrocarbon Discoveries
Legendre
Legendre South
Wanaea
North
Rankin
Goodwyn
Gaea
Echo/Yodel
Keast
Tidepole
Rankin Dockrell
West Dixon Dixon
HYDROCARBON DISCOVERIES
Urania
Io
FEBRUARY 2004
Gas
Oil
Oil & Gas
Jansz
Scarborough
Sage
Iago
Geryon
PRODUCTION FACILITIES
20^
Reindeer/Caribou
Wilcox
Dionysus
Orthrus
A
Wandoo
Corvus
Maenad
B
Chrysaor
West Tryal Rocks
Stag
Commonwealth Jurisdiction
State Jurisdiction
Burrup Peninsula
KARRATHA
North Gorgon
Central Gorgon
Gorgon
C
Spar
Barrow Island
B
Montebello Islands
Thomas Bright John Brookes
Campbell
Wonnich Linda Sinbad
Montgomery
Bambra Rose/Lee
Maitland
Harriet A Gipsy/North Gipsy
Agincourt
Monty
Rosette
Josephine/Baker
East Spar Little Sandy/Pedirka Alkimos/Tanami/Simpson
Double Island Varanus Island
Gibson/South Plato
Barrow Island
Victoria
Woollybutt
Pasco
INDIAN
DAMPIER
OCEAN
Conventional platform
Mini platform
Jack-up rig
Monopod/Minipod
Subsea completion, well
Navigation, Command,
and Control Buoy
Floating Production Storage
and Offloading vessel
LNG carrier
Oil carrier
Pipeline, possible pipeline route
ROEBOURNE
LNG storage tanks
Oil storage tanks
Onshore production facility
Under construction
Proposed development
South Pepper
North Herald
Chinook/Scindian
Griffin
Chervil
Coniston Airlie Island
Novara
Skiddaw Vincent
Crest
Thevenard Island
A
Stybarrow
Ravensworth
B Saladin
Enfield Crosby
Corowa Yammaderry
C
Macedon/
Cowle
Laverda
Scafell Pyrenees
Roller Skate
A
C
B ONSLOW
Figure 3. North West Shelf production facilities and significant hydrocarbon discoveries.
Abandoned field
Onslow
Tubridgi
EXMOUTH
Rivoli
22^
22^
Yardie East
Cape Range
LOCALITY
MAP
Rough Range
Parrot Hill
WESTERN
50 km
AUSTRALIA
Map produced by Petroleum Division, Department of Industry and Resources WA.
Maritime boundary data supplied by Geoscience Australia and is AMBIS 2001 data.
116^
114^

underlain by a 10 m gross oil column at the top of
the Birdrong Sandstone.
Crosby 1
The Crosby field, located in WA-12-R and operated
by BHP Billiton Petroleum, is situated 106 km westnorthwest
of Onslow. Crosby 1 penetrated 7 m of
gas overlying 36 m of oil in the Pyrenees Member
of the Lower Barrow Group in a complex structural
trap between the Scafell Trend and the Novara Arch
in the Exmouth Sub-basin.
Ravensworth 1
Ravensworth 1 was drilled in WA-155-P,
approximately 108 km west-northwest of Onslow.
The well encountered a 44 m gross hydrocarbon
column consisting of 7 m of gas and 37 m of oil in
the Pyrenees Member sands.
Browse Basin
Within the Browse Basin, four exploration wells were
drilled: Ichthys 1, Ichthys Deep 1, Maginnis 1 and
Strumbo 1, with Ichthys and Ichthys Deep both
intersecting thick zones of gas pay. Neither
Maginnis nor Strumbo intersected any
hydrocarbons. An appraisal well, Ichthys 2, was
drilled to assist in determining the extent of the
Ichthys gasfield.
Ichthys 1 and Ichthys Deep 1
These wells were drilled by Inpex in their 100%
owned permit WA-285-P. The wells encountered
excellent gas shows in their target horizons and
follow-up gas discoveries at Gorgonichthys,
Dinichthys and Titanichthys made in 2002.
Bonaparte Basin
The only well drilled in the Bonaparte Basin was
Weasel 1 by Woodside Energy in WA-279-P. The
well did not intersect any hydrocarbons and was
plugged and abandoned.
PETROLEUM RESERVES AND RESOURCES
Petroleum reserves in Western Australia have been
compiled under two main headings – ‘developed
fields’ and ‘undeveloped fields’. Developed fields are
those currently producing fields that are located
either offshore in Commonwealth or State Waters or
onshore within Western Australia. The reserves
quoted are remaining reserves as at 31 December
2003. Undeveloped fields have reserves associated
with the static petroleum resources that may be
developed in the future.
In all of the above categories, reserves or resources
have been quoted at the 90% and 50% probability
of recovery levels (P90 and P50).
The reserves for undeveloped fields are the
reserves associated with the static petroleum
resources that may be developed in the future.
Undeveloped fields have been subdivided into three
categories as follows:
• Category 1, Potential for early development
• Category 2, Expected medium to long term
development
• Category 3, Not currently viable; subject to
Retention Lease
The overall reserves and production figures for
Western Australia up to 31 December are listed
in Table 1.
EXPLORATION ACTIVITY
(Compiled from data provided by companies; where
there is no report for a company, it is due to them
not submitting a report)
Apache Energy
In the calendar year 2003, Apache operated 18
exploration wells, 11 appraisal wells and 4
development wells. Three field discoveries were
confirmed and all appraisal wells but two and all
development wells were successful.
Taunton 3 and 3ST (TL/2) were to confirm the
easterly extent of the field. Both wells encountered
oil-bearing reservoir section of similar thickness and
quality to the discovery well, Taunton 1 drilled in
1991.
Thomas Bright 1 and 2 (WA-214-P) were drilled to
establish the presence of gas-bearing sands over
the southern portion of the John Brookes-Tryal
Rocks Anticline. Both wells encountered the main
pay section seen at John Brookes 1 and both were
gas bearing. Deeper gas-bearing sands were also
encountered at Thomas Bright 1. The outcome of
these wells in combination with John Brookes 1 has
led the WA-214-P participants to proceed with the
development of the field.
North Pedirka 1 (TL/1) was drilled from the Victoria
Platform and encountered an 8 m gross oil column
in the massive Flag Sandstone. The well was
immediately completed and brought on production.
Ginger 1 well was drilled to evaluate a Biggada
prospect identified by bright seismic amplitudes.
Table 1. 2003 Production and reserves for Western Australia
PWA April Edition - 2003 Review 11
The well encountered a 21 m gross gas column
within a tight sandstone reservoir. No gas/water
contact was encountered. The commercial viability
of Ginger remains uncertain pending the analysis of
reprocessed seismic data.
Apache expects to drill more than 35 wells during
2004. Exploration activities will comprise more than
20 wells and be mainly concentrated in the Varanus
Island and Dampier areas. A highlight of the year will
be Blackdragon 1 in the Exmouth Sub-basin (WA-
335-P). This well is situated in over 1400 m of water
and is Apache’s first deep water well in Australia.
Arc Energy
ARC Energy participated in the drilling of 14 of the
77 wells drilled in Western Australia in 2003 and
operated seven of these.
2003 Exploration Highlights
Exploration drilling at Eremia 1, in the onshore
resulted in a commercial oil discovery at Eremia.
Offshore, the Twin Lions 1, Mentelle 1 and Vindara
1 wells were unsuccessful.
The Hibbertia 3D seismic survey identified a number
of gas prospects east of the Hovea oilfield and north
of the Beharra Springs gasfield that will be drilled in
2004. Preparations are underway for the acquisition
of the Denison 3D seismic survey over the eastern
oil fairway in L1/L2, and land gravity data has
already been acquired over this oil fairway.
BHP Billiton Petroleum
Outer Browse Area
BHP Billiton regards the deep water Outer Browse
Basin as a frontier basin with high potential and
little prior exploration.
In 2000, the company was awarded five blocks:
WA-301-P, WA-302-P, WA-303-P, WA-304-P and
WA-305-P. These blocks comprise around
25 000 km 2 and lie in water depths ranging from
1000 to 3000 metres.
Category Oil (GL) Condensate (GL) Gas (Gm 3 )
Developed Fields
2003 Production 14.054 6.606 27.435
Remaining Reserves P90 33.449 51.968 462.253
P50 60.015 75.757 592.933
Undeveloped Reserves
Category 1 P90 36.681 38.295 214.656
P50 54.057 55.871 304.145
Category 2 P90 8.900 3.400 31.750
P50 13.300 7.500 62.190
Category 3 P90 4.980 87.509 1530.892
P50 8.660 141.275 2385.666

12
In 2002, a major remote sensing programme
including a geotechnical piston core survey was
undertaken in the five blocks to help understand the
likelihood of a working petroleum system.
Early in 2003, BHP Billiton drilled the Maginnis 1
well in WA-302-P. Maginnis 1 was located in
approximately 1300 m of water and was drilled by
the Jack Ryan dynamically positioned drill ship. BHP
Billiton, on behalf of the respective Joint Venture
partners, also acquired a combined 510 km 2 of 3D
seismic data over permits WA-303-P and WA-304-P.
The focus has been to incorporate the Maginnis 1
results and data and interpret the seismic data.
BHP Billiton is the operator in all five blocks. The
ownership interests are:
• WA-301-P, Kerr McGee, 50%; BHP Billiton, 50%
• WA-302-P, Texaco, 33%; Kerr McGee, 33%;
BHP Billiton, 33%
• WA-303-P, Texaco, 33%; Kerr McGee, 33%;
BHP Billiton, 33%
• WA-304-P, Kerr McGee, 50%; BHP Billiton, 50%
• WA-305-P, Texaco, 33%; Kerr McGee, 33%;
BHP Billiton, 33%.
Carnarvon Basin
PWA April Edition - 2003 Review
BHP Billiton Petroleum is the operator of exploration
permits WA-255-P, WA-155-P(1) as well as
retention lease WA-12-R (Macedon-Pyrenees fields)
and production licences WA-10-L and WA-12-L
(Griffin-Chinook-Scindian complex), all located
within the offshore Carnarvon Basin, Western
Australia.
During the second half of 2003, our Western
Australian exploration focus was on the Exmouth
Sub-basin of the Carnarvon Basin, with drilling
activity in permits WA-155-P(1) and WA-12-R, and
exploration studies following an active drilling
programme in WA-255-P.
In WA-255-P (BHP Billiton 50%, operator), data
gathered from a 4-well programme undertaken from
February to June 2003 were analysed and results
interpreted in preparation for a renewed drilling
campaign proposed for the first half of 2004.
Our exploration activity in WA-155-P(1) (BHP Billiton
39.999%, operator) focused on extension of the
Pyrenees-Vincent heavy oil play. An exploration well,
Ravensworth 1, was drilled in July 2003 using the
Sedco 703, approximately 10 km southeast of the
Vincent oil and gas field. The well encountered a 37
m oil column with a 7 m gas cap in high quality
sandstones and after sidetracking to acquire core
across the reservoir, Ravensworth 1 was plugged
and abandoned, as planned.
The Ravensworth discovery was followed up in
ChevronTexaco’s Greater Gorgon Area (Image courtesy of ChevronTexeco)
October 2003 by an exploration well on the
adjacent Crosby feature in WA-12-R. Ravensworth
and Crosby are currently being evaluated, along
with several undrilled prospects in WA-12-R inbetween
Crosby 1 and West Muiron 5.
The Van Gogh 1ST well was drilled in WA-155-P(1)
to test the northern part of the Vincent field,
discovered by Vincent 1 (Woodside, 1999). The
results of BHP Billiton Petroleum’s Van Gogh 1ST
and Woodside’s Vincent 1 and 2 wells are currently
being evaluated.
ChevronTexaco
Barrow Island / Thevenard Island Licences
ChevronTexaco continued to develop its exploration
portfolio within the exploration and production
licences of the Barrow and Thevenard areas.
Exploration focus was on oil plays close to existing
production facilities. No exploration drilling was
undertaken in the Barrow and Thevenard Island
regions during 2003.
The renewal of Barrow Island onshore exploration
permits EP61 and EP62 was granted in 2003.
Exploration permit TP/2 is currently subsisting
awaiting formal renewal approval.
In the Thevenard area, the only activity was the
assignment of ChevronTexaco Australia’s interest in
exploration permit TP/3 to Santos.
There are no planned exploration activities for 2004
in the Barrow Island or Thevenard Island regions.
Greater Gorgon Area Gas Assets
There were no exploration drilling activities in 2003
within the Greater Gorgon Area exploration permits in
the area including and to the west of the Gorgon field.
Activities during the last twelve months in the
Greater Gorgon Area were focused on retaining the
recently discovered gas in WA-267-P and WA-25-P
and extensions of these resources into WA-253-P.
Ten retention leases have been awarded to
ChevronTexaco Australia and their partners during
the last two years covering the Iago, Geryon,
Orthrus-Maenad, Urania, Io-South, and Io-Eurytion
gasfields (from WA-25-P, WA-267-P, and WA-253-
P). The remaining WA-267-P and WA-25-P
graticular blocks were surrendered during 2003.
In addition, and concurrent to this, marketing efforts
for the sale of the Gorgon Area gas (which includes
Spar, West Tryal Rocks and the Gorgon gasfields) was
the main focus for ChevronTexaco Australia Pty Ltd
during 2003. These three Gorgon Area gasfields were
renewed for a further five years in August 2003.
Seismic acquisition was undertaken in WA-253-P
(Wheatstone 2D MSS), WA-268-P (Champagne 2D
MSS) and WA-205-P (Acme 3D MSS) to fulfil their
respective work commitments. Wheatstone 2D MSS
comprised 625 line km while Champagne 2D MSS
2430 line km and Acme 3D MSS 220 km 2 . The

acquisition had incident free operations.
Texaco Australia Pty Ltd participated in the drilling of
the Mobil operated Jansz 3 well. The well was
successfully production tested, with a peak rate of 2
Mm 3 /d (72.6 MMcf/d).
A major event during 2003 was the announcement
of the ratification of the State legislation that will
allow Gorgon limited access to Barrow Island for the
construction of a gas processing plant. Many other
approvals are required before Gorgon can start
construction of the plant notwithstanding the
stringent environmental approvals.
Two large seismic programs have been planned for
2004 in the Greater Gorgon Area. The Chandon 3D
MSS will focus on the Chandon Prospect in WA-
268-P and the Io-Jansz 3D MSS will further
delineate the large gas resource discovered by the
Io and Jansz wells over the last several years.
Acquisition is scheduled to start in February 2004.
The major focus in 2004 for the Gorgon Area Gas
Team will be the continued commercialisation effort
for the Gorgon gas. To this, numerous positions
have been advertised in the national newspapers
looking for engineers and other project experienced
personnel.
Eni Australia
In 2003, Eni Australia was actively involved in 11
exploration permits in offshore Australian waters
and eight of these were in Western Australian
waters. As operator, Eni acquired 5300 km of 2D
seismic in the Houtman Sub-basin and reprocessed
a further 5000 km of 2D seismic. As non-operator,
Eni participated in two exploration wells, Wigmore 1
and Weasel 1.
Activity planned for 2004 as operator includes the
acquisition of 600 km 2 of 3D seismic and the
drilling of one exploration well on the Woollybutt
production licence. The company also intends to
participate in at least two other exploration wells
during the year.
Kimberley Oil
Due to the forthcoming granting of Application Area
2/96-7, which contains the oil and gas-bearing
Pictor anticline, the company commissioned an
engineering appraisal of the economic viability of
horizontal drilling into the oil and gas-bearing zone.
The study concluded that horizontal drilling into the
Pictor Anticline is likely to achieve economic oil
production rates and that estimated recoverable oil
reserves total 6.4 GL (40 MMbbl).
Kimberley Oil will be seeking a farm-in into the
exploration permit, subsequent to the granting of
Application Area 2/96-7, so that a horizontal well is
drilled into the Pictor Anticline.
A commitment exploration well is due in EP129, and
the company is seeking a farm-in partner for the
drilling of Boundary Southeast 1. A commitment
exploration well is due in EP391, and the company
is seeking a farm-in partner for the drilling of a test
well on the crest of the Yulleroo Anticline.
Nexen Energy
On the exploration front, Nexen had been seeking
partners to participate in the exploration of WA-239-
P, in the Browse Basin, offshore Western Australia.
The block is situated on the Yampi Shelf on the
eastern margin of the basin, approximately 730 km
southwest of Darwin. It has an area of
approximately 4700 km 2 and only two wells have
been drilled in the permit. However, the farm-out
efforts were unsuccessful and Nexen surrendered
the permit.
Roc Oil
Permit Interests
As at 31 December 2003, Roc Oil (WA) Pty Ltd
(ROC) is the operator of four permits in the Perth
Basin and participates in another permit, as detailed
in Table 2. Effective 1 April 2003, ROC acquired Arc
Nexen’s Buffalo oilfield (Image courtesy of Nexen Energy)
Table 2: ROC’s W.A. Permit Interests as at 31 December 2003
PWA April Edition - 2003 Review 13
Energy’s 7.5% interest in WA-286-P (which
includes the Cliff Head oilfield). ROC farmed into
EP413 effective 1 April 2003, by acquiring Victoria
Petroleum’s 0.25% equity in the permit, which
contains the Jingemia oilfield. In mid-2003, ROC
acquired an option to acquire Norwest Energy’s
7.5% equity in WA-226-P. This option may be
exercised pending the review of Macallan 3D
seismic data.
In addition, ROC announced on 18 December 2003
that it will exercise an option with Voyager Energy
Limited to acquire a 50% interest in, and
operatorship of, the gazettal block WO3-14, which
is contiguous with three licences in which ROC
already hold interests, and is on the same
geological trend as the Cliff Head oilfield.
Drilling Activity
In 2003, ROC participated in three exploration and
four appraisal wells in the Perth Basin. The
exploration wells did not encounter significant
hydrocarbons, while all appraisal wells were
successful.
Permit Basin ROC Interest Operator
WA-286-P Perth (Offshore) 37.5% Roc Oil (WA) Pty Ltd
TP/15 Perth (Offshore) 20.0% Roc Oil (WA) Pty Ltd
WA-325-P Perth (Offshore) 37.5% Roc Oil (WA) Pty Ltd
WA-327-P Perth (Offshore) 37.5% Roc Oil (WA) Pty Ltd
EP413 Perth (Onshore) 0.25% Origin Energy
Developments Pty Ltd
WA-226-P (Option to acquire) Perth (Offshore) 7.5% Origin Energy
Developments Pty Ltd

14
Two wildcat wells in WA-286-P (Mentelle 1 and
Vindara 1) encountered minor oil shows in sidewall
cores, but were assessed to be non-commercial
and were plugged and abandoned. The Twin Lions 1
wildcat in TP/15 encountered good quality
reservoirs, which were water-wet, and the well was
plugged and abandoned.
Seismic Activity
PWA April Edition - 2003 Review
During 2003, ROC as operator recorded four marine
seismic surveys; 687 km 2 of 3D data and 1554 km
of 2D data.
The Veritas Pacific Sword completed the Cliff Head
3D seismic survey of 30.4 km 2 over the Cliff Head
oil discovery in WA-286-P on 1 November 2003.
The survey was designed to support development
planning, in particular optimisation of development
well design.
This was followed by acquisition of the Lilian 2D
seismic survey of 729 km (644 km in WA-286-P
and 85 km in TP/15), completed on 11 November.
The Pacific Sword then acquired the MaryAnn 2D
seismic survey (825 km) in WA-325-P. In the WA-
327-P and WA-325-P permits, the Nordic Explorer
acquired the 657 km 2 Vicki/Angela 3D seismic
survey in late November–December 2003.
The WA-226-P JV (operated by Origin Energy)
acquired the 522 km 2 Macallan 3D seismic survey
over the major leads in the block. ROC acquired an
option over Norwest Energy’s (NWE) 5% equity in
WA-226-P, by funding NWE’s share of the survey.
The option may be exercised pending review of the
seismic data, which was ongoing at the end of
2003.
Other Geophysical Activity
During 2003, ROC as operator recorded two
aeromagnetic surveys. The East Abrolhos
Aeromagnetic Survey was acquired in WA-325-P in
September to October 2003. A total of 31 338 line
km were recorded (including 3204 km in the
adjacent W03-14 gazettal block), covering an area
of 3521 km 2 (including 353 km 2 in W03-14).
The Offshore Dongara Aeromagnetic Survey was
acquired in WA-286-P and TP/15 in September
2003, to provide structural detail in areas of sparser
seismic coverage and where shallow water makes
seismic data difficult to acquire. A total of 11 876
line km were recorded (7508 km in WA-286-P and
4368 km in TP/15), covering an area of 1375 km 2 .
In 2004, ROC plans to participate in the drilling of
one firm and one contingent wildcat well; a
commitment well in WA-325-P, operated by ROC
and possibly one well in WA-226-P, operated by
Origin Energy. No appraisal wells are planned.
No seismic acquisition is planned, however,
processing and interpretation of seismic acquired in
late 2003 continues into 2004.
Victoria Petroleum
Victoria Petroleum’s North West Shelf permits and prospects. (Image courtesy of Victoria Petroleum)
During 2003, Victoria Petroleum N.L. participated in
exploration and production activities in its Western
Australian permits in the North Perth Basin and the
Carnarvon Basin.
The North Perth Basin permit EP413 was of
particular significance to Victoria Petroleum as this
onshore permit provided the company’s first
commercial onshore oil production in Australia.
During 2003, continued production testing of the
Jingemia 1 discovery well at rates of up to 318 kL
of oil per day (2000 bbl/d) with no water, confirmed
the commercial nature of the Jingemia oilfield, with
all production being trucked to the BP Oil refinery at
Kwinana.
The Jingemia 2 and Jingemia 3 development wells

were drilled in 2003 and defined the southern limits
of the field. The Jingemia 3 well was converted to a
water injection well for pressure maintenance with
water injecting starting in late 2003.
Exploration in Victoria Petroleum’s offshore and
onshore Carnarvon Basin permits in 2003 focused
on the evaluation of the drilling results from the
2002 drilling programme, to generate drilling
targets for 2004. Victoria Petroleum has an interest
in seven permits in the Carnarvon Basin, with four
permits operated by Victoria. The remaining permits
are operated by Apache Energy and Strike Oil.
2004
North Perth Basin Permit EP413
A 3D seismic survey and follow up development
well, Jingemia 4, to increase production from the
Jingemia oilfield is planned for 2004.
Carnarvon Basin Permits
Exploration drilling is planned for WA-261-P with
drilling of the 3.6 GL (23 MMbbl) of recoverable oil
potential Vesta Prospect in late February 2004.
Exploration drilling is also planned for the Exmouth
Gulf permit EP325 with the drilling of the 4.3 GL
(27 MMbbl) of recoverable oil Champion Prospect in
the second half of 2004.
Victoria Petroleum is currently seeking farm-in
partners to participate in the drilling of Champion 1
on favourable farm-in terms.
Woodside Energy
Woodside continues to focus its Australian
exploration on hydrocarbons adjacent to existing or
planned production facilities and testing prospective
new frontier provinces.
During the period, Woodside farmed in to WA-255-P
in Western Australia with 50% equity. In northern
Australia, Woodside strengthened its position around
the Blacktip gasfield by acquiring Shell’s interests in
WA-279-P, WA-313-P and NT/P57. These interests
were partially on-sold to Agip (Eni) leaving Woodside
with 53.85% of WA-279-P, 50% of WA-313-P and
66.67% of NT/P57.
During the first half of 2003, the company
participated in 14 exploration and appraisal wells in
Australian acreage. Seven of these wells
encountered hydrocarbons. In WA-255-P, Stybarrow
1 discovered a 23 m gross oil column. This was
appraised by Stybarrow 2, which encountered a 22
Victoria Petroleum’s northern Perth Basin permits and prospects. (Image courtesy of Victoria Petroleum)
PWA April Edition - 2003 Review 15
m oil column. The Skiddaw 1 sidetrack encountered
a 22 m column of oil and gas and successfully
appraised the northern extent of the Laverda field.
Eskdale 1, also in WA-255-P, penetrated noncommercial
hydrocarbon shows. The Egret 3 well
successfully appraised the Egret field in WA-10-R,
encountering a 50 m gross hydrocarbon column (5
m of net gas pay plus 24 m of net oil). The well also
encountered hydrocarbons in the deeper exploration
objective, making a sub-commercial gas discovery.
Sub-commercial hydrocarbons were also
encountered in the Guilford 1 well drilled in WA-
269-P.
The Weasel 1 exploration well was drilled to test a
four-way dip closure in the hanging wall of a
northeast-southwest trending basin margin fault
approximately 35 km south of Blacktip 1. The
primary objective of Weasel 1 was to evaluate the
hydrocarbon potential of the Early Permian Keyling
Formation sandstones with the Carboniferous
Kuriyippi Formation sandstones providing a
secondary objective.
Weasel 1 was spudded on 9 March 2003 and
drilled to a total depth of 1776 mRT in sandstones
of the secondary objective Kuriyippi Formation. Both
objective intervals were interpreted to be water-

16
bearing. No significant hydrocarbons were
encountered. Weasel 1 was plugged and abandoned
as a dry hole on 19 March 2003. The drilling of
Weasel 1 fulfilled the Year 5 work commitment for
permit WA-279-P.
Seven other wells drilled in WA-1-P, WA-248-P, WA-
279-P, WA-296-P, WA-299-P, NT/P57 and EPP29
failed to encounter hydrocarbons.
During the period, the company farmed out 35% of
its equity in WA-248-P to MIMI, leaving a residual
interest of 45%.
DEVELOPMENT AND PRODUCTION OVERVIEW
(Compiled from data provided by companies; where
there is no report for a company, it is due to them
not submitting a report)
Apache Energy
Simpson (TL/1 & TL/6)
At Simpson, four development wells, Simpson 7,
West Simpson 1, South Simpson 2 and Simpson 6
were drilled and completed during 2003.
Hoover
Hoover 2 (TL/6) was successfully drilled and
completed from the Victoria Platform. The Hoover
field is located over 3 km from the Victoria Platform.
Gipsy
PWA April Edition - 2003 Review
Gipsy 3 was located 1.2 km south of Gipsy 1 and
successfully proved a southern extension of the
Gipsy field confirming 13 m of net oil pay and an
extension of the Gipsy oilfield to the south within the
North Rankin Formation. The well also discovered a
new pool of oil within the deeper Mungaroo ‘B’
sandstones not penetrated by previous drilling
within the Gipsy oilfield. Gipsy 4 was drilled and
completed to produce the oil encountered in both
intervals.
Linda
Linda Development fabrication took place during
2003 with installation and development drilling
expected in February/March 2004.
During 2004, Apache will finish the development of
the Linda field and the upgrade of the gas
processing facilities on Varanus Island (VGEP). VGEP
will expand the capacity of the Harriet Joint Venture
gas plant and compression to around 220 TJ/d
(currently 100 TJ/d). Development activities will
commence for John Brookes gasfield (WA-214-P)
and Bambra gas- and oilfield (TL/1) with first
production expected in mid 2005 and late 2004
respectively. Further appraisal drilling will take place
at the Taunton field in TL/2 and TP/7.
Arc Energy
Checking the welhead at Eremia 1
(image courtesy of Arc Energy)
During the year ARC enjoyed exploration success at
Eremia, appraisal and development success at
Hovea, Jingemia and Cliff Head and commissioned
its permanent oil production facility at Hovea only
nine months after field appraisal was completed.
The company is now firmly established as the
dominant acreage holder and operator in the
onshore Perth Basin, a position under-pinned by its
net production of approximately 413 kL (2600 bbl)
of oil per day and 8 TJ/day of gas. The Perth Basin
now supplies up to 10% of WA’s crude oil
requirements.
In 2004, ARC is undertaking an aggressive oil and
gas exploration programme in addition to
consolidating and improving its production from the
Hovea, Eremia and Jingemia fields. It will also be
aggressively increasing its gas business in the area,
which has very high strategic value for gas supply
to Perth.
2003 Development Highlights
• Successful appraisal/development drilling at
Hovea 5, 6, 7, 8, 9 and 10 enabled field
production to increase to in excess of 794 kL/d
(5000 bbl/d)
• First use of auto-trak rotary steerable drilling
system onshore WA
• First commercially successful horizontal oil
development well (Hovea 8) in onshore WA
• Appraisal/development drilling at Jingemia 2 and
3 confirming a commercial field and extended
production testing commenced
• Appraisal drilling at Cliff Head 3 and 4
progressing the field towards a declaration of
commerciality
2003 Production Highlights
• Test production commenced from Eremia 1, six
weeks after the well was completed
• Production from Hovea and Eremia increased to
in excess of 874 KL/d (5500 bbl/d)
• One millionth barrel of oil produced from Hovea
• Continued gas production from the Dongara
gasfield
• Highly successful road transport system for
crude export commissioned
2003 Corporate Highlights
ARC consolidated its position as the principal
acreage holder and operator in the northern Perth
Basin
• ARC awarded EP2/02-3 to the north of L1/L2 as
operator subject to native title determination
• ARC sold its 7.5% interest in offshore permit
WA-286-P to ROC Oil
• ARC purchased AWE’s interests in EP413,
EP368, EP320 and L11
• On 10 February 2004, purchased a 100%
interest in L7 (Mt Horner)
• Posted a 2002/03 financial year after tax profit
of $8.97 million and a 31 December 2003 halfyear
profit of $8.5 million
BHP Billiton Petroleum
BHP Billiton Petroleum holds a 45% interest and is
the operator of the Griffin field, WA-10-L. Joint
venture partners in WA-10-L are Mobil Exploration
& Producing Australia (35%) and Inpex Alpha (20%).
The Griffin oil and gas project is located
approximately 60 km offshore Western Australia. Oil
and gas from the Griffin, Chinook and Scindian
fields are produced via the Griffin Venture, a floating
production, storage and offloading facility (FPSO).
The Griffin Venture is a disconnectable vessel
(which allows it to relocate in the event of a cyclone)
with gas processing facilities on board.
Griffin gas is exported directly into the Dampier to

Bunbury Natural Gas Pipeline and blended with
North West Shelf gas. The produced oil is stored on
board and off-loaded to tankers periodically.
Griffin crude and condensate production for the
period from July – December 2003 was 465.8 ML
(2.93 MMbbl) gross (206.7 ML (1.3 MMbbl) net to
BHP Billiton), or an average of 2.5 ML/d (16 016
bbl/d). Also during the 3rd quarter of 2003 the
Griffin Venture reached the milestone of achieving a
total oil production of 23.85 ML (150 MMbbl). The
cumulative oil production from the Griffin Venture to
31 December 2003 is 24.25 ML (152.5 MMbbl).
Griffin total sales gas production for the period from
July – December 2003 was 118.6 m 3 (4.19 Bcf)
gross (53.24 Mm 3 (1.88 Bcf) net to BHP Billiton), or
an average of 648 km 3 /d (22.89 MMcf/d).
ChevronTexaco
Barrow Island
Total oil production for Barrow Island during 2003
was 525 710 kL (Table 3). The total production had
decreased compared to previous annual production
volumes of 569 043 kL in 2002 and 610 427 kL in
2001. The volume of water produced during 2003
was 3 598 924 kL and the volume of gas was
59 569 m 3 (Table 3).
Drilling
No new wells were drilled in 2003.
Other Well Work
All activities on Barrow Island during 2003 were
related to normal oilfield operations and ensuring
operations have minimal impact on the fauna and
flora of the island.
Thevenard Island
Total oil production from the Thevenard production
licences during 2003 was 315 006 kL (Table 4).
Total production had decreased compared to
previous annual production volumes of 406 364 kL
in 2002 and 459 746 kL in 2001 due to natural
depletion. The volume of water produced during
2003 was 2 956 629 kL and the volume of gas
was 50 237 km 3 (Table 4). The majority of all water
produced is reinjected back into the source
reservoir.
Saladin Field Activities
No new wells were drilled.
Cowle Field Activities
No new wells were drilled and no well interventions
were undertaken during the year.
Skate and Roller Fields Activities
No new wells were drilled during the year. Skate 2
was re-entered and then plugged and suspended.
Skate 4 underwent additional perforations in the
Barrow Group gas cap and then suspended. This
operation was to ensure future gas supplies would
be available for the Thevenard Island gas processing
plant.
Crest Oilfield
Mardie Greensand oil production recommenced
from the Crest oilfield, in early December 2002,
after the native title negotiations were finalised. The
exploration permit EP65, which covered the
Thevenard Island and the Crest oilfield, has been
converted to two production licences L12 and L13.
Table 3: Chevron Texaco’s Barrow Island production in 2003
In December 2002, initial oil production started at
45 kL/d but has as of December 2003 declined to 9
kL/d.
Eni Australia
Table 4: Chevron Texaco’s Thevenard Island leases production in 2003
PWA April Edition - 2003 Review 17
Eni Australia started production from the Woollybutt
field (WA-25-L, Eni 65% operator, ExxonMobil 20%,
Tap West 15%) at the end of April 2003.
The field is located in 100 m water depth about
100 km west of Dampier, in the Carnarvon Basin.
Month Oil Production Water Production Gas Production
(kL) (kL) (km 3 )
Jan - 03 44 530 313 437 4 312
Feb - 03 43 587 307 889 4 201
Mar - 03 43 469 306 123 4 119
Apr - 03 38 456 280 402 3 629
May - 03 48 383 336 539 4 590
Jun - 03 45 938 316 631 5 033
Jul - 03 44 087 306 878 5 145
Aug - 03 48 385 307 814 5 817
Sep - 03 44 695 290 527 5 677
Oct - 03 43 551 289 284 5 924
Nov - 03 36 837 248 597 5 277
Dec - 03 42 792 294 803 5 845
Total 525 710 3 598 924 59 569
Nb: km 3 is one kilometre cubed which equals one thousand metres cubed
Month Oil Production Water Production Gas Production
(kL) (kL) (km 3 )
Jan - 03 30 828 266 819 4 146
Feb - 03 26 581 219 612 3 511
Mar - 03 25 318 211 107 4 051
Apr - 03 22 086 180 647 3 708
May - 03 27 579 254 699 4 722
Jun - 03 25 591 241 569 4 086
Jul - 03 25 493 240 252 4 609
Aug - 03 26 989 268 000 4 511
Sep - 03 26 813 269 466 4 355
Oct - 03 27 083 278 632 4 175
Nov - 03 24 529 253 390 4 219
Dec - 03 26 116 272 436 4 144
Total 315 006 2 956 629 50 237
Nb: km 3 is one kilometre cubed which equals one thousand metres cubed

18
The oil is a good quality 49.2° API and is produced
from two wells. A total of 1.2 GL (8 MMbbl) have
been produced since the start up in 2003.
The oil is processed and stored onboard the FPSO
Four Vanguard. This ship exhibits a double hull and
an internal turret, quickly disconnectable, mooring
system. A number of offtakes have been
successfully performed in the year.
ExxonMobil
PWA April Edition - 2003 Review
ExxonMobil, through its subsidiaries, operated the
Jansz 3 appraisal well and participated in two
development wells at Woollybutt.
The Jansz 3 well spudded on the 3rd of June and
was drilled in 1340 m of water to a depth of
approximately 2900 m below sea level. Jansz 3
confirmed the high reservoir quality continuity with a
successful well test flowing a maximum 2 Mm 3 /d
(72.6 MMcf/d) for a period of 30 minutes. The
successful production test demonstrates that it can
be produced at rates that will allow a range of
commercial developments. The WA-18-R joint
venturers are currently conducting a study to assess
these development options.
Plans are currently being finalised for a 2600 km 2
3D survey over the Jansz gasfield with acquisition
due to commence mid February 2004. The field
covers an area in excess of 2000 km 2 and has an
interpreted 400 m gross gas column. Including an
extension into the adjacent WA-25-R and WA-26-R
blocks, it is estimated that the field contains
approximately 566 Gm 3 (20 Tcf) of recoverable
sales gas, believed to be the largest gas discovery
ever to have been made in Australian waters.
The WA-1-R joint venturers reviewed concepts for
development of the Scarborough gasfield with
additional appraisal activity consisting of a 3D
seismic survey commencing Q1, 2004.
Wandoo production averaged 1621 kL/d (10 200
bbl/d) in 2003 with reservoir decline being partially
offset by well cycling and optimisation programs.
Two scheduled shutdowns occurred for general
maintenance including replacement of the WNB
production riser and the submarine hose. Other
activities included work carried out on the fitness for
service assessment of the test riser and an upgrade
to the blanket gas system.
During 2003, ExxonMobil subsidiaries withdrew
from WA-255-P, WA-155-P, WA-12-R, TL/2, TP/7,
WA-25-P, WA-214-P and WA-298-P. Retention
leases were granted over WA-267-P discovered
gasfields, including the extension to Jansz, Orthrus,
Geryon, Maenad and Urania and the remaining
portion of WA-267-P was relinquished by the joint
venture.
ExxonMobil’s current focus in WA is on working with
our co-venturers to develop the large gas resources
of the deep water Carnarvon Basin.
Kimberley Oil
During the 2002-2003 fiscal year, the company
produced 4.8 ML (30 362 bbl) of oil from its five
oilfields in the Canning Basin: Blina, Boundary,
Lloyd, Sundown and West Terrace.
Nexen Energy
In July 2001, Nexen Petroleum Australia Pty Limited
(Nexen), (formerly Canadian Petroleum Australia
(Operations) Pty Limited), became 100% owner and
operator of the Buffalo field in WA-19-L and WA-
Location of Nexen’s WA-239-P permit. (Image courtesy of Nexen Energy)
21-L in the Timor Sea. Prior to assuming the
operatorship, Nexen had been a 50/50 joint venture
partner, as non-operator, with BHP Petroleum.
Facilities in the Buffalo field currently consist of an
unmanned wellhead platform (WHP) with four wells,
which stands in 27 m of water on the
environmentally sensitive Big Bank; and the ‘Buffalo
Venture’ floating production, storage, and offloading
(FPSO) facility, which is permanently moored 2.5 km
from the WHP, in 300 m of water.
During 2002, Nexen undertook and completed a
two well development drilling programme in the
Buffalo field, to double the production well count to
four. The jackup drilling rig Ocean Heritage arrived
in the field on March 9, 2002 and moved away from
the WHP on June 13, 2002. The first of the new
wells, Buffalo 7, was placed on production in the
middle of April 2002 and had a demonstrated
production capability of 4000 kL of oil per day
(25 000 bbl/d). The well produced approximately
140 ML (880 Mbbl) prior to producing any water
and is currently producing 365 kL of oil per day (2
300 bbl/d) at an 83% water cut.
The second well in the programme, Buffalo 8, came
in structurally low to prognosis and was
subsequently sidetracked up structure into another
fault block. Buffalo 9, as the sidetrack is designated,
encountered the top Elang reservoir (RAB 6 zone in
Nexen informal terminology) at 3242 m (TVDSS),
the highest location encountered in wells in the
field, thereby confirming the presence of the
western attic. Despite being 74 m above the field
oil/water contact, however, the RAB 3, 4, 5 and 6
units of the reservoir proved to be water-wet.
Subsequent petrophysical analyses indicated oil
saturations up to 35%. Adding to the enigma, the
well encountered oil in the lower Elang sands,
informally designated RAB 1 and 2. Oil was also
encountered in the underlying W. digitata
palynozone (WD) zone of the Elang Formation. This
was the first time that oil had been encountered in
the WD zone in the field; all other production is from
the RAB zone. The well was completed in the RAB 2
and WD zones.
Buffalo 9 was placed on production in June 2002
on a co-mingled basis from the WD and RAB 2
sands and was subsequently suspended in March
2003 because of a very high water cut (greater than
95%). In May 2003, a bridge plug was set in the
well above the WD perforations and the upper RAB
section was perforated to test the possibility of
moveable oil in these sands. This was unsuccessful
and the well remains suspended.
The current (December 2003) oil production
capability of the field is approximately 795 kL/d
(5000 bbl/d) and averaged 96.4 kL/d (6064 bbl/d)
in 2003. Production for 2004 is expected to
average approximately 55.6 kL/d (3500 bbl/d) and
it is expected that the economic limit for the field

will be reached in the fourth quarter of 2004. At
that time, the Buffalo Venture FPSO will be released,
the existing wellbores will be abandoned, and the
wellhead platform will be recovered and towed away
for onshore salvage.
The safety and environmental performance of the
entire Buffalo operation has been outstanding. There
were no lost time incidents or reportable
environmental incidents during the 97-day drilling
programme in 2002, some of which involved
simultaneous activities (drilling, production,
offloading and construction). The operations were a
complex sequence of activities executed under the
simultaneous operations (SIMOPS) constraints
developed specifically for Buffalo and included in
the Safety Case documentation. The Ocean Heritage
drilling rig was also new to Australia and therefore
required the development of a stand-alone Safety
Case by the drilling contractor (Diamond Offshore
Drilling, Inc.), and Bridging and SIMOPS documents,
which were developed by Nexen. The operations
also demonstrated Nexen’s commitment to protect
the environment through the successful use of drill
cuttings re-injection sub-sea, when possible, and
the use of a water based sodium silicate drilling
fluid that reduced the impact of the remaining
drilling cuttings on the sensitive Big Bank
environment.
Further to this, the Buffalo Venture FPSO achieved
four years without an LTI (Lost Time Incident) on 29
December 2003. This outstanding safety record,
which commenced at the start of production from the
field in December 1999, has continued into 2004.
Roc Oil
The Cliff Head field, discovered in 2001 by ROC,
was successfully appraised with the drilling of two
wells in January and March 2003. Cliff Head 3 was
sidetracked to core and was production tested at a
stabilised rate, constrained by surface facilities, of
477 kL (3000 bbl) of oil per day via an 11 mm
(28/64”) choke and a down hole electrical
submersible pump. The second appraisal well, Cliff
Head 4, was drilled and also cored for reservoir
information.
The EP413 JV conducted an extended production
test on Jingemia 1 (drilled in October 2002) over
the period May to August 2003, to determine the
commerciality of the oil discovery and development
strategy. During the test, rates in excess of 286
kL/d (1800 bbl/d) were recorded.
Jingemia 2 and its sidetrack Jingemia 3 were
successfully drilled in August to September 2003,
primarily to provide water injection for the field. A
second extended production test was underway on
Jingemia 1 at year-end.
Detailed engineering and design work for the Cliff
Head oil development was undertaken in 2003, and
ROC established an office in Perth to manage the
project. On 14 October 2003, the Joint Venture took
a major step towards commercial production with a
unanimous declaration of commerciality and
agreement to move forward to the Front End
Engineering and Design review stage (FEED). The
FEED contract was awarded to Worley Pty Ltd. The
decision to proceed towards FEED was based on a
proved and probable reserve estimate of 3.3 GL (21
MMbbl) of recoverable oil.
The cost of the development is yet to be
determined, but it is expected to be in the order of
$140 million, with a final decision on the investment
expected in 2004. An application for the declaration
of a location of one block was made over the Cliff
Head field on 19 December 2003.
A location of one graticular block over the Jingemia
oilfield in EP413 was gazetted in January 2003, and
in July 2003, the JV made an application for a
production licence.
Work continues on progressing the Cliff Head oilfield
towards commercial production. Subject to
satisfactory completion of FEED and receipt of
regulatory and JV approvals, it is anticipated that a
final investment decision for the project will be
made during the second quarter of 2004 and that
first oil will be produced from Cliff Head during the
second half of 2005.
Woodside Energy
Development Activities 2003
WA-271-P
Development of the Enfield oilfield has progressed
according to plan in 2003 with the project
commencing the Front End Engineering Phase in
May 2003. Contractors for the FPSO Hull, EPCm
and Turret & Mooring facilities have been awarded.
Environmental approval for the development was
given by the Commonwealth Minister for
Environment and Heritage in July. The development
is planned to come on stream in late 2006 and will
accommodate future area tie-backs such as
Laverda as ullage becomes available.
Following the disappointing appraisal result of
Laverda 2 (drilled in December 2002), Woodside
participated in the drilling of Skiddaw 1 in May
2003 in WA-255-P to appraise the northern extent
of the Laverda field. Gas and oil columns were
penetrated in Skiddaw 2 (a sidetrack to Skiddaw 1).
Feasibility studies with respect to future
development of the technically challenging Vincent
field are continuing.
WA-279-P
Development of the Blacktip gasfield progressed
into the concept selection phase in March 2003. In
June 2003, the Blacktip JV signed a Heads of
Agreement with Alcan for the supply of gas to
underpin Alcan’s planned expansion of its Gove
alumina production and bauxite mining facilities.
PWA April Edition - 2003 Review 19
First gas is currently scheduled for January 2007.
Following a further review in December, the Blacktip
development will commence Basis of Design (BOD)
studies in January 2004.
Production Activities 2003
Laminaria and Corallina
In November 1999, the Northern Endeavour FPSO
commenced production from the Laminaria and
Corallina fields in production licence AC/L5 located
in the Timor Sea.
The Laminaria and Corallina reservoirs have
performed above expectation. The onset and rate of
increase in water production and the associated
decline in productivity has been broadly in-line with
reservoir model predictions. Total produced oil to the
North end Rankin of June A platform 2003 was (image 24.13 courtesy GL. of Woodside)
Legendre
Development studies carried out in Q4, 2002
resulted in an infill drilling opportunity to develop the
poorly swept southwestern flank of the Legendre
North field. The infill well, Legendre North 4H was
drilled in April 2003 using the Ensco 56 and
commenced production on 10 June 2003.
The performance of the Ocean Legend has been
good with an annual average production rate of
4370 kL/d, with almost all gas re-injected and
minimal flaring. The maximum rate achieved during
2003 followed the drilling of Legendre North 4H and
optimisation of gas handling facilities. Cumulative
total produced oil to end 2003 was 4.429 GL.
North Rankin
The North Rankin gasfield lies 23 km northeast of
the Goodwyn field and approximately 140 km
offshore from Karratha in approximately 125 m of
water. The field was discovered in 1971 when the
NRX-01 well penetrated 565 m of gross
hydrocarbon column in Triassic, fluvio-estuarine
reservoir quality sands. The trap is structural,
comprising a large horst block complex in the main
body of the field with a zone of westerly dipping
fault blocks in the northwest part of the field.
Reservoir units gently dip northwards and sub-crop
sealing Cretaceous shales over the crest of the
field. At the northern end of the field, the top of the
North Rankin reservoir is defined by depositionally
conformable Triassic to Early Jurassic shales.
During 2003, the field produced 3.79 Gm 3 of raw
gas and 429 ML of condensate. During 2003/04,
the NRA life extension and North Rankin ‘B’ platform
will be studied to determine an optimum
development infrastructure and functionality of the
assets.
Perseus
The Perseus gasfield is located approximately 135
km northwest of Karratha in 131 m water depth.
The field lies in a graben bounded by the North
Rankin field to the east and the Goodwyn field to
the west.

20
PWA April Edition - 2003 Review
The Cossack Pioneer FPSO at the Wanaea - Cossack oilfield (image courtesy of Woodside)
The phased development of the Perseus field
progressed with production commencing in 2001
from the PEN02 and PEN03 ‘Big Bore’ wells drilled
from the NRA platform in 2000. Medium term plans
include the drilling of a further three ‘Big Bore’ wells
from the NRA platform during 2005. Future phases
are envisaged to include satellite development and
the introduction of gas compression. In 2003/04 the
potential development of some Perseus reserves via
the Goodwyn Alpha (Goodwyn A) platform will be
studied.
During 2003, the Perseus field produced a total of
7.367 Gm 3 of raw gas and 1.507 GL of condensate.
Goodwyn
The Goodwyn gasfield was discovered in 1972 and
is centred 23 km southwest of North Rankin field.
The multiple Goodwyn reservoirs are contained in
highly permeable dipping sandstones in the Upper
Triassic Mungaroo Formation. They are truncated
and sealed by the Lower Cretaceous Muderong
Shale within a large northward-tilted Jurassic horst
structure.
Recycle volumes during 2003 were at similar levels
to 2002 rates with a total of 5.25 Gm 3 dry gas
injected to maintain optimum condensate
production. The start up of the Echo Yodel field in
early 2002 has preserved production from the
Goodwyn field. During 2003, the field produced
9.659 Gm 3 of raw gas and 2.467 GL of condensate.
Four well interventions, mostly perforations, are
planned for 2004 (GWA12, 08, 04 or 05 and
GWA13). A blow down strategy based on field CGR
will be devised during 2004 to optimise condensate
recovery. Work is continuing on future tiebacks of
satellite fields to the Goodwyn A platform.
Echo/Yodel (gas & condensate)
The Echo/Yodel field lies 25 km southwest of the
Goodwyn A platform in 140 m water depth. The
Echo field was discovered in 1988 by Echo 1, which
penetrated a 19 m gross hydrocarbon column in
fluvio-deltaic sandstones of the Triassic Mungaroo
Formation. The northwesterly dipping reservoir units
subcrop the regional unconformity (MU), which also
dips to the northwest. Overlying Cretaceous shales
provide the seal to the accumulation.
The Yodel field was discovered in 1990 and
production is continuing from the Yodel 3 and Yodel
4 wells at expectation levels. During 2003, the field
produced approximately 2.436 Gm 3 of raw gas and
1.758 GL of condensate.
Wanaea and Cossack
The Wanaea field was discovered in June 1989 with
the Wanaea 1 exploration well. It is located 30 km
east of the North Rankin field in 80 m water depth.
In 2000, the Cossack 1 well discovered the Cossack
field situated northeast of the Wanaea field.
Currently, there are five deviated wells producing
from the Wanaea field and one horizontal well
producing from the Cossack field. Reservoir quality
in both the Wanaea and Cossack fields is good and
typical production rates of about 3.18 ML/d (20 000
bbl/d) have been achieved from the deviated wells
in Wanaea with rates up to 6.36 ML/d (40 000
bbl/d) from the Cossack horizontal well.
Oil production from the Wanaea field in 2003 was
4.187 GL while production from the Cossack field
was 821 ML. The Cossack Pioneer also exported
927 Mm 3 of raw gas via the inter-field line to North
Rankin A platform. Future developments for the
Wanaea-Cossack area are being evaluated, with
new 3D seismic acquisition planned to be followed
by further development in 2004/05 currently
expected to include gas lift and new infill wells.
Lambert and Hermes
The Lambert and Hermes structures form two
separate oil accumulations that are located in 125
m of water, 15 km to the north of the Wanaea and
Cossack fields and 145 km north of Karratha. The
Lambert accumulation was discovered in 1973 by
the Lambert 1 exploration well, which intersected
11 m net of oil-bearing sandstone at the top of the
Tithonian Angel Formation. The Hermes field was
discovered in 1996.
Oil production from the Lambert and Hermes fields
in 2003 was 429 ML and 808 ML, respectively.
Future developments for the Lambert-Hermes area
are being evaluated, with new 3D seismic
acquisition planned to be followed by further
development in 2004/05 including gas lift and new
infill wells.
Future Developments
LNG Expansion
Commitment to the NWSV $2.4 billion 4th LNG
expansion and second trunkline projects were
approved by the boards of the North West Shelf
Joint Venture Partners in March 2001 after
successful negotiations with LNG customers.
Train 4
Australian companies are on target to win 66% of
contracts on the Train 4 Project. When items that
are not available in Australia are deducted from the
total project value, the project’s “achievable”
Australian Content, is 95% (* “Achievable” excludes
specialist equipment not built in Australia eg:
cryogenic heat exchangers, compressors, turbines
etc and not tendered for by Australian companies).
So far Australian companies have won A$1030
million out of A$1482 million in contracts let.
Second Trunkline
Australian companies are on target to win 54%, or
A$292 million of total contracts, against an original
forecast of 51%. So far Australian companies have
won A$252.8 million of manufacturing and
construction contracts out of a total project value of
A$489 million.
The second trunkline is forecasting an “achievable”
rate for Australian industry of 94%. Assessment and
concept selection work for a fifth LNG Processing
Train on the Burrup Peninsula is also progressing in
support of prospective customers in Asia.

Angel
The Angel field is a gas/condensate discovery
located approximately 50 km east of North Rankin
platform. The discovery is currently being assessed
for future development potential, with the possibility
of development being undertaken for a 2007/08
startup.
Searipple
The Searipple field was discovered in 1996 by the
deepened Perseus 3A appraisal well. Development
plans are in progress in conjunction with the further
development of the Perseus field.
Egret
Egret is a small oilfield approximately 12 km
northwest of the Wanaea field and is currently under
appraisal. The most recent (Egret 3) appraisal well
was drilled in June 2003 finding a gas and oil
column. The decision on future development will be
taken in 2004/05, post acquisition of new seismic.
Dockrell
The Dockrell field is located 6 km southeast of the
Echo/Yodel field and 20 km southwest of the
Goodwyn A platform, in 110 m water depth. The
field was discovered in 1973 by Dockrell 1, which
encountered gross gas and oil columns of 88 m and
14 m respectively, in the Jurassic Brigadier (D Unit)
and Triassic Mungaroo (E Unit) Formations. The
Brigadier Formation is a dominantly shaly interval
with thinly interbedded sands, deposited in a
shallow marine delta front setting. The E Unit is a
high energy, sand dominated, fluvio-deltaic,
sequence. Reservoir units dip towards the northeast
and are truncated by MU. Regionally extensive
Cretaceous shales provide the seal to the
accumulation. Two additional thin hydrocarbon
zones were encountered within Unit F of the
Mungaroo Formation some 300 and 550 m below
the base of the Unit E. Dockrell 2 was drilled in
1998 to test the reservoir units to the north of the
Dockrell field. Two oil-bearing reservoir units, the E
sand (Dockrell 1) and D sand (Dockrell 2), have
been penetrated.
The field is covered by the Keast 3D seismic survey
acquired in 1997, which provided improved
structural and fault definition. Reprocessing of the
Keast 3D data was conducted during 2003.
Timing of the development of the Dockrell field,
which is located within the Goodwyn field
production licence, is dictated by gas supply
demand and is anticipated for a later date.
Development is likely to consist of a sub-sea
development tied-back to GWA.
Keast
The Keast field is located 4 km southeast of the
Echo/Yodel field and 20 km southwest of the
Goodwyn A platform, in 125 m water depth. Keast 1
was drilled in January 1997 and encountered a
gross gas column of 32 m in the Jurassic Unit D
(Brigadier Formation). Gas was also encountered in
Unit E, Intra E, and Lower E sands of the Triassic
Mungaroo Formation. Both the D and E Unit sands
dip northwards and sub-crop below the regional
unconformity (MU). Cretaceous shales above MU
seal the accumulation. The Intra E and Lower E
sands are structurally trapped beneath intraformational
shales.
Unit D is a claystone-dominated interval with
occasional interbedded sands, deposited in a
shallow marine, delta front setting. The E Unit is a
high energy, sand-dominated, fluvio-deltaic
sequence. Unit E sands are thick and are
interpreted to be really extensive. Keast 2 was
drilled in March 1997, to test the hydrocarbonbearing
potential of the Lower Jurassic C Unit and D
Unit to the north. The well intersected a shaly, nonreservoir
D Unit beneath MU. Sands deeper withithe
D Unit, structurally lower than the gas column
encountered in the sub-cropping D Unit at Keast 1,
were water bearing. The current seismic (Keast 3D
survey) provides reliable structural definition and
further improvements may be realised through
interpretation of the Keast 3D reprocessed data.
Development timing for the Keast field, which is
located within the Goodwyn field production licence,
is anticipated at a later date and will be dictated by
gas supply demand. Development will most likely
rely upon a depletion-drive recovery and is likely to
consist of a sub-sea development tied-back to GWA.
Wilcox
The Wilcox field is located approximately 55 km
southwest of the Goodwyn A platform in 70 m water
depth. Wilcox 1 was drilled in March 1983 and
discovered a 500 m gross column within thick
fluvio-deltaic beds of the Triassic Mungaroo
PWA April Edition - 2003 Review 21
Formation. The field lies within a large Triassic fault
block bound to the northwest by a steeply dipping
fault. There are four gas-bearing sands in the E, F,
and G Units. Wilcox 2 was drilled down-flank in
June 1985 to prove additional reserves, but all
sands were found to be water bearing.
First production from Wilcox is not expected until a
later date. Development will most likely rely upon a
depletion-drive recovery and is likely to consist of a
sub-sea development tied-back to GWA.
In 2000, the retention lease WA-7-R was renewed
over the block where the field is located.
Sculptor
The Sculptor field comprises of several fault blocks
and encompasses both the Lower-E and F Units of
the Triassic Mungaroo Formation.
The field is covered by the Keast 3D seismic data,
which was acquired in 1997. A volumetric update to
reflect 3D seismic data was completed during 2002.
Development timing for Sculptor is anticipated at a
later date and will be dictated by gas supply
demand. Development will most likely rely upon a
depletion-drive recovery and is likely to consist of a
sub-sea development tied-back to GWA.
In 2001, the production licence WA-24-L was
granted over the field area thus changing the blocks
status from retention lease (WA-11-R) to production
licence. DoIR
Laying the second trunkline for Burrup gas processing facilities (Image courtesy of Woodside)

22
PWA April Edition - Resources Branch Activities
Reza Malek, Manager Resources Branch,
Petroleum and Royalties Division
The Resources Branch provides a broad spectrum
of services to the industry and undertakes an
important regulatory role to facilitate the upstream
petroleum industry development. This review hopes
to provide a better understanding of the Resources
Branch roles and activities.
There is a significant decision making process
involved in approving field development plans,
production licences, declarations of location, wells,
seismic surveys and retention leases. The
Resources Branch is effectively the custodian of the
natural resources involved in a petroleum field’s
development and must ensure that the proposed
development strategy is optimal to maximise
hydrocarbon recovery and expedite the project in
the best interests of the citizens of WA. Thus an
experience-based assessment of such proposals is
a prerequisite to a good outcome.
During the past few years the Branch has taken
ambitious and creative steps forward and has
accomplished a number innovative projects such as
the Atlas of Petroleum Fields and prospectivity
enhancement packages, as well as being the driving
force behind the Division’s Petroleum in WA journal.
New projects such as the Barrow and Dampier
aquifer depletion studies and Gorgon CO 2
sequestration studies have been so important that
they have made milestones in Australia’s regulatory
scene and demonstrated the tangible role the
Branch has for the responsible production of WA
petroleum resources for the long term benefit of all
Western Australians.
Approval Processes
The need for technical assessment for numerous
seismic surveys, well approvals and development
plans continued throughout 2003, reflecting the
continued interest in the development of the
Resources Branch’s Recent Activities
Commonwealth and State’s petroleum resources.
They included the assessment of: three production
licence renewal applications, and three field
development plans, 15 location applications, 12
retention lease applications or renewals and 69 well
approvals including 15 development well
applications, 16 appraisal well applications and 38
exploration well applications. In addition, WA hosted
a meeting between the Commonwealth and
State/Territory Designated Authorities to agree on
uniform protocols for the granting of Production
Licences and approval of Field Development Plans
within Commonwealth Waters.
Acreage Releases
During 2003, the Resources Branch coordinated the
release of a number of blocks for petroleum
exploration both onshore and offshore. Perhaps the
most significant was the release of four Canning
Basin blocks that included a prospectivity package
identifying leads and prospects in the released blocks
as well as the petroleum systems within the area.
Bids for these areas closed on the 11 March 2004.
As part of the overall promotion of Western
Australian acreage, the Resources Branch was
involved in a number of conferences and
presentations throughout 2003. These included the
APPEA conference held in Melbourne, the North
American Prospect Expo (NAPE), The Good Oil
Conference and DoIR’s Petroleum Open Day. The
Branch also produced the Western Australian
Petroleum Opportunities farm-out booklet and
heavily contributed to two editions of the Petroleum
in Western Australia journal in 2003.
Production monitoring and metering
Petroleum is Western Australia’s golden egg, as the
most important revenue source for the State from
resources is generated from royalties associated
with petroleum production. These royalties, for 2001
and 2002, amounted to $494.5 and $438.5 million
respectively. Although there is a decline in the WA
petroleum royalties associated with decline in
hydrocarbon production, petroleum is still the most
valuable commodity produced in WA, surpassing
iron ore in 1994 and gold in 1996. A critical first
step in royalty collection for petroleum is
determining the production from each active field
within the State.
According to the requirement of the Schedule of the
Specific Requirements for Offshore Exploration and
Production 1997, the Division must audit petroleum
producers in Commonwealth Offshore and State
Water areas. This process involves a review of their
data sheets, procedures and equipment
specifications to determine whether their
measurement systems in place conform to the
above schedule. During 2003 the Resources Branch
continued to update its hydrocarbon accounting
systems manual and it is hoped that the final
product will be use by the middle of 2004. Officers
from Resources Branch conducted a number of site
visits during the year to audit the measurement
systems in place at production facilities.
Research
The Resources Branch was also actively involved in
research aimed at enhancing the petroleum
prospectivity of the State. This research included an
overview of the petroleum systems in the central
Canning Basin, potential areas for coal bed methane
exploration and production, and geological and
engineering analyses of the Wonnich, Barrow Island
and Egret fields.

Barrow and Dampier Sub-basin Aquifer
Depletion Studies
Australia is potentially incurring loss of oil as
petroleum production continues. Aquifer pressure
decline is occurring not only in Western Australia
but also in the Gippsland Basin of Victoria and the
portion of the Bonaparte Basin in the Territory of
Ashmore and Cartier (administered by the Northern
Territory Government).
The Barrow and Dampier Sub-basins lie in the
Carnarvon Basin off the northwest coast of WA. First
oil from the Barrow Sub-basin came on-stream in
1986 and production from the fields in this area has
been continuous since 1986. The value of
petroleum royalties from the Barrow Sub-basin was
$56 million in 2002/03.
First oil from the Dampier Sub-basin came onstream
from the Talisman oilfield in July 1989. The
value of petroleum royalties from the Dampier Subbasin
was $262 million in 2002/03. These subbasins
lie both in WA State waters and the
Commonwealth Adjacent Area.
Originally, it was believed that the reservoirs in the
Barrow and Dampier Sub-basins had infinite aquifer
pressure support with no regional draw-down effect.
Recent observations from newly discovered fields in
the Barrow and Dampier Sub-basins, however,
indicated that there has been a significant pressure
draw down in some parts of these sub-basins. Also,
petrophysical logs from some of these discoveries
indicated a few metres of residual oil below the oil
water contact.
As a result of pressure draw down and subsequent
gas cap expansion, oil accumulations in these
reservoirs may have been forced down into the
aquifer and, where this migration extended below
spill point, it is possible that some oil may have
been lost. This, in turn, means that millions of
dollars worth of royalties could have been lost. The
conclusions that can be drawn from the above
observations would have serious implications for the
conservation of as yet undiscovered and/or
undeveloped hydrocarbon resources in the region as
well as known and developed fields.
It is crucial for the regulatory bodies to fully
understand the implications of draw down and
subsequent possible loss of oil and its impact on
State and Commonwealth revenues. To assist in this
investigation, the Petroleum Division of DoIR
engaged the services of OPES International and
CSIRO between 2000 and 2003. The main objective
was to determine the extent at which hydrocarbons
are potentially being lost in the region and possible
future losses and the affect on royalty income to the
State and Commonwealth.
Based on the results of the Barrow Sub-basin study
by the year 2030, the total oil loss can be as high
as 83 GL. At current oil prices (approximately A$50
per barrel), a loss in royalty due to oil loss amounts
to $5 per barrel and therefore the WA community
could lose as much as $2.6 billion by 2030 if
corrective measures are not taken against aquifer
depletion in the Barrow Sub-basin. Similarly, based
on the results of the Dampier Sub-basin study by
the year 2030, the total oil loss can be as high as
42 GL. Once again, this could mean a potential loss
of up to $1.33 billion to the WA community.
These studies revived the interest in industry to
implement their investigations. Major WA operators
such as Woodside Energy Limited, Santos and
Apache Energy have already recognized aquifer
depletion and its possible impact. There is increased
interest within the WA petroleum industry to take
part in a joint Government/Industry task force to deal
with the issue in a constructive manner. WA
Department of Industry and Resources has already
taken a number of initiatives to share the results of
these studies in the Barrow and Dampier Sub-basins
with the petroleum industry and Commonwealth.
Feasibility Study of Gorgon CO 2 Sequestration
at Barrow Island
The Gorgon gasfield is situated 130 km off the
northwest coast of Western Australia in 200 metres
of water and was discovered in 1981. The Gorgon
field has certified proven hydrocarbon gas reserves
of 272.69 Gm 3 (9.63 Tcf). Carbon dioxide comprises
about 14 mole % of the raw gas resource. The
Gorgon Venture asked the WA Government to
consider whether it could be acceptable, in
principle, for a gas processing plant to be located
on Barrow Island.
According to Chevron Texaco, landing and
processing gas from Gorgon on Barrow Island is the
most economically viable option for the project. The
field development concept consists of sub-sea wells
arranged in several production centres over the
field, tied back to gas processing facilities on
Barrow Island via a 70 km pipeline. Later on, a gas
connection will be installed from Barrow Island to
the mainland connecting Gorgon gas to the existing
domestic pipeline.
DoIR and ChevronTexaco Australia agreed to
regularly review the technical work being
performed. To assist in the assessment, DoIR
engaged the services of Curtin University. The Phase
1 review was completed in June 2003 and provided
technical assurance on the feasibility of CO 2 storage
beneath Barrow Island. This provided one of the
criteria for the WA State Government’s decision to
grant in-principle access to Barrow Island for the
project. The in-principle approval for access to
Barrow Island was granted on September 8, 2003
after rigorous reviews and careful consideration.
The Phase 1 review provided a comparative risk
analysis, which compared most of the injection and
storage parameters of the Utsira Formation -
Sleipner West (a site where the injection and
PWA April Edition - Resources Branch Activities 23
storage process is considered a success by the
Norwegian Government) with the proposed injection
and storage parameters of the Dupuy Formation -
Barrow Island. The key findings of the DoIR review
concluded that injection of Gorgon reservoir CO 2
into the Dupuy Formation at Barrow Island was
technically feasible, and the acknowledged risks
were to be expected and manageable. However it
was also concluded that long term monitoring of
CO 2 migration needs to be addressed.
The Phase 1 general recommendations were related
to improving the subsurface definition of the earth
model, further assessment of seal and fault
integrity, injectivity, near-well bore reactions and
CO 2 surveillance and monitoring technologies. Key
DoIR recommendations included the need for
additional geological data and a long-term
monitoring strategy for reservoir management and
contingency planning.
More specifically the study recommended that at
least one pilot well must be drilled at injection site to
acquire the necessary core and geological
information, acquire further seismic surveys in
northern Barrow Island, perform further mapping of
the seal, application of CO 2 , simulators for future
Dupuy aquifer studies, identify the optimum long term
monitoring methodology and drill an inclined injection
well with 3 km reach into the offshore areas.
Development of this world-class resource is of
national importance and will benefit Australia with
employment opportunities and infrastructure
development. It is important to note, that Gorgon may
also provide the foundation development on which
the Greater Gorgon area fields can be advanced. DoIR

24
PWA April Edition - Magnetotelluric Surveys
Peter Kirk, Petroleum Geophysicist
Peter Kirk Geophysical Consultancy Pty Ltd
Of all the geophysical techniques used in
petroleum exploration in Australia over the last 50
years or more, the magnetotelluric or MT method
has been used the least frequently and is probably
the least familiar method to explorationists. There
have, in fact, been five MT surveys conducted in
WA, one conventional MT survey and four audio
frequency MT (AMT) surveys, all of which have
been conducted onshore.
Although to date the technique has not resulted in
any major discoveries, it has produced some
interesting results and in the case of one survey it
accurately predicted the results of two
unsuccessful wells. It deserves to be used more
frequently, particularly in areas where the seismic
technique has significant problems (mainly due to
shallow limestone) or where seismic acquisition is
restricted due to environmental problems.
The Magnetotelluric Method
Magnetotellurics (MT) is a division of geophysics
which studies the earth’s naturally occurring
electromagnetic field and the telluric (from the
Greek Tellus meaning earth) currents caused by
fluctuations therein. Many researchers say that this
source is “many orders of magnitude greater than
the strengths of fields that can be generated with
man-made sources on the surface of the earth”.
The primary energy source is naturally occurring
electromagnetic waves that are confined to the
space between the ionosphere and the earth’s
surface, these circumnavigate the globe and are
consequently known as ‘spherics’. The frequencies
of these waves cover a spectrum from 10 -3 Hz to
10 4 Hz (about 22 octaves). The low to mid
frequencies are caused by the interaction of the
natural solar wind with the earth’s magnetic field,
whilst the higher frequencies are generally
Magnetotelluric Surveys for Petroleum
Exploration in Western Australia
attributed to distant lightning strikes. Nearby
lightning strikes, powerful man-made transmitters
and highly irregular solar activity due to solar flares
all produce levels of unwanted noise that prevent the
recording of useful signal and also introduce
spurious ‘static’ delays or depth shifts. Constant
monitoring of sunspot activity or ‘space weather’ is
necessary but this is greatly facilitated by the
availability of reliable online data compiled by solar
observatories, including the one at Learmonth in WA.
Since the bulk of the useful energy is generated by
the interaction with the solar wind, it is normally only
possible to record during daylight hours.
The primary energy source induces telluric currents
just below the earth’s surface in large sheets,
preferentially through conducting layers such as
brine filled sedimentary rocks and certain mineral
deposits. These currents flow more slowly through
resistive layers such as dense limestone, volcanics
such as basalt, tight non-porous rocks and
evaporites including salt (although salt in solution is
highly conductive, solid salt is highly resistive). The
currents can be readily measured as a result of the
horizontal potential gradients and the horizontal and
vertical magnetic gradients that they produce at the
surface. A modern recording instrument normally
incorporates two electrical antennae horizontally at
right angles and three magnetic coiled antennae
horizontally and vertically at right angles. These
signals may be recorded separately or the magnetic
and electrical signal may be combined and recorded
in stereo on digital magnetic tape. A high sampling
rate is required for the higher frequency
components and this is provided by modern DAT
recorders, principally used by the music industry.
The depth of penetration of the induced currents
within the earth depends upon the frequency of the
primary source with lower frequencies necessary to
induce currents at greater depths. In order to
measure currents kilometres below the surface, we
need frequencies with periods of several minutes.
Typically the length of each individual recording is
20 minutes for petroleum exploration. The digitally
recorded signals, which contain information for all
depths, are demodulated by analogue or digital
computer to final form for analysis. The recorded
signal contains frequency-phase vs. amplitude
information relating to the incoming field at the
surface, the decaying earth carrier field, and the
modulation resulting from the earth’s resistivity
reflection coefficients. The former two fields are
extracted using least square methods. Only the
earth’s resistivity profile remains as a function of
frequencies. The depth of investigation is a result of
the frequency of the data and the resistivity, and this
is approximately described by the well known ‘skin
depth equation’ - skin depth (m) = 500 p/f.
Simplification of the “skin depth” equation is used to
convert the profiles to depth. The result of this
process is a series of electric and magnetic
reflection coefficients. These are then combined to
form the apparent resistivity series defined by
Z = E/H as a function of depth. In addition phase
values with depth are also obtained. The depths
derived from the skin depth equation can then be
corrected at a calibration well within the survey
area. However, changes in the overburden
composition, irregular variations in the earth’s
magnetic field and accelerated solar activity can
affect the depth accuracy. This can occur from dayto-day
or from one survey area to another. These
inaccuracies can be reduced by recording at a
known calibration point at least every day and
sometimes continuously throughout the day.
Sophisticated inversion algorithms can also be used
to produce 2D and even 3D plots of apparent
resistivity using all 5 recorded signals at each

station. However, for conventional MT recording
these models generally lack the resolution needed
for accurate prospect delineation.
In addition to the primary frequencies induced in the
telluric currents, higher order harmonic energy is
also generated. The audio frequency magnetotelluric
(AMT) technique varies from conventional MT by
attempting to analyse the higher frequency
harmonics of the recognised lower frequency carrier
waves that propagate within the earth. As with
conventional MT, the final output is a pseudoresistivity
curve but with greater vertical resolution.
These plots, when compared to wireline data from
wellbores, often show a good correlation with a self
potential (SP) log. In addition, the phase component
within low resistivity (i.e. porous) zones may be
further analysed for phase distortions considered
typical of hydrocarbon pore saturation. Because the
frequencies of the data are in the audio frequency
range, the analogue signal can be listened to by an
experienced operator in the same manner as used
by a trained sonar operator and then categorised as
being strongly or weakly typical of water, gas or oil.
Computer software to try to perform this task
digitally has been written but it is currently not as
good. The scientific validity of this technique is not
theoretically proven but even where these ‘shows’
are not definitive they are often useful in correlating
responses from one station to another.
The Canning Basin
The first MT survey for petroleum exploration in WA
was conducted in the central Canning Basin for Elf
Aquitaine in 1968. It was a fairly extensive
conventional MT survey, which provided useful
information about the basin structure and sediment
thickness in the area of the survey.
The second survey in the Canning Basin was an
AMT survey conducted by Digital Magneto-telluric
Technologies (DMT) for Kingsway Resources 2001
to help evaluate the Sally May prospect (formerly
known as Cetus) in 2003. This prospect is a large
Ordovician sub-salt play with 4-way dip closure
previously identified from both a seismic grid and
from an aeromagnetic survey. The MT survey
comprised approximately 20 recordings over the
prospect plus calibration recordings at two offset
wells; Looma 1, which discovered oil at the main
prospective reservoir levels and Fruitcake 1, which
is the closest well to the prospect. The survey
produced results that closely matched data from the
wells and provided information on the depth
structure of the prospect, likely reservoir quality,
thickness and fluid fill. Looma 1 encountered oil in
six zones, 3 zones in the Nita Formation carbonate
section and 3 in the deeper Acacia Formation
sandstone. All zones correctly were predicted from
analysis of the MT data without detailed prior
knowledge. Looma 1 did not flow oil to surface due
to very poor permeability in the reservoir sections.
Fruitcake 1 was an unsuccessful test of a shallow
(post-salt) play type.
The crest of the structure identified from two
perpendicular lines of MT recordings more closely
matched the result predicted from the aeromagnetic
survey than that previously interpreted from the
seismic survey. The seismic data interpretation was
severely affected by velocity variations due to
varying salt thickness and also infilled eroded
channels at the top of the salt. The MT data predicts
a 45 m oil column at the structurally highest point
recorded. The Sally May prospect is likely to be
drilled in 2004.
The Carnarvon Basin
Three separate MT surveys were carried out in this
basin, mainly focussed on the Rough Range and
Giralia anticlines.
In 1999-2000, Empire Oil & Gas carried out
technical work to appraise the Rough Range oilfield,
culminating in the drilling of Rough Range 1B and
Central Rough Range 1. The Rough Range anticline
was formed by Miocene aged compressional
reactivation of the Rough Range fault (a major
Jurassic fault). A small oil accumulation exists within
the Early Cretaceous Birdrong Sandstone at the
crest of the anticline. Since the accumulation is far
from being filled to spill, it is likely to have remigrated
from a nearby accumulation following the
Miocene compression. The anticline is easily
observable at the surface that comprises weathered
Miocene aged Trealla Limestone. The recent
weathering of the Trealla carbonates has resulted in
rapid near-surface velocity variations, which badly
affect the seismic data recorded over the anticline.
PWA April Edition - Magnetotelluric Surveys 25
A Brief History of the Magnetotelluric Method
1939 First documented experiments with MT reported by Schlumberger in France.
1953 Cagniard discovered that the ratio of E/H as a function of frequency could yield a plot of
resistivity with depth. This was also discovered independently by Russian researchers.
1960’s MT becomes main technique for evaluating new basins in Europe and North Africa. Extensive
use of MT in Siberia results in the discovery of many giant oilfields.
1968 First MT survey in Australia carried out by Elf in the Canning Basin.
1980’s Development of AMT technique. Improvements in instrumentation. Used for prospect
evaluation as well as regional studies. Used in many in-house research groups for
companies like Shell, Chevron, Amoco, Arco, Sohio, etc.
1990’s First use of MT on seafloor to evaluate sub-salt and sub-basalt plays. Further improvements
in instrumentation result in very lightweight portable systems and better sampling accuracy.
Constant monitoring of solar activity possible. GPS surveying.
Empire commissioned additional work to try to
address this problem including the use of pre-stack
depth migration (PSDM). Unfortunately, Central
Rough Range 1 came in low to prognosis and
proved to be on the edge of the field. A post mortem
of the well results concluded that the PSDM method
could not determine seismic velocities with sufficient
accuracy to define the small accumulation present.
Following the drilling of Central Rough Range 1, the
Rough Range field was now surrounded by
unsuccessful wells – Rough Range 4, 5, 6, 10, 11
and Central Rough Range 1. It was now possible to
determine a very accurate velocity field using well
data alone. This was done and a revised map of the
field produced. Immediately following this, the
results of a magnetotelluric survey carried out in
1987 were discovered. This survey was carried out
for Nomeco who were one of the participants in the
Ampolex led joint venture. The MT survey was
recorded and analysed following the acquisition of
the 1986 seismic survey but prior to the drilling of
Rough Range 11. The map of the top Birdrong
Sandstone then obtained from the survey matched
exactly with that derived from the seismic data
corrected with the velocity field derived post Central
Rough Range 1 (totally independently). In addition,
the MT survey would have accurately predicted the
results of Rough Range 11 and Central Rough
Range 1 to within 2 m. A close examination of the
results of the survey also showed that the top of the
Birdrong Sandstone could be picked unambiguously
with a high degree of accuracy. In addition, the
method allowed prediction of the fluid content of the
reservoir and column heights predicted over the
field area also proved to be accurate.

26
PWA April Edition - Magnetotelluric Surveys
Empire decided to contact the company responsible
for carrying out the survey and contracted DMT, to
carry out a new MT survey starting in November
2000 to evaluate a number of other prospects that
had been identified from the re-interpretation of the
seismic data. The prospects identified included
small four-way dip closures on the Rough Range
anticline, (the largest named Brooke); a large fault
dependent closure at the northern end of the
anticline updip of Lefroy Hill 1 (Tess); a fault
dependent closure to the east of the Rough Range
fault (Jennifer); and updip of Parrot Hill 1 (Elysia).
The survey was carried out between 10 November
and 4 December 2000 by DMT technologies under
the supervision of Empire Oil & Gas. Field
operations went very smoothly with very few hitches
and overall productivity was on average 30% higher
than expected, which enabled additional programme
to be recorded. After the first two days recording,
Empire undertook the acquisition programme
leaving the DMT operator, Bob Mecionis, to
concentrate on the analysis of the data. The main
advantage of this method of operation to Empire
was the flexibility to be able to change the
programme as preliminary results were obtained.
The ability to be able to record data on any
particular day was subject to the vagaries of solar
weather. A total of 165 points were recorded –
approximately 60 more than was originally planned.
The Rough Range area is well suited to the MT
method due to the sharp contrast between the
saline Birdrong reservoir and the overlying shales
and also due to the ideal ground conditions.
DMT were provided with log data from the Rough
Range 1A well. Analysis of all other points was done
without prior knowledge of any existing
interpretation or of the results of the other wells
recorded. The initial test programme consisted of a
line across the Rough Range field including the
Rough Range 1A well plus points recorded at the
following wells – Rough Range 6, Rough Range 10,
Rough Range 11, Central Rough Range 1, Rough
Range 2 and Rough Range 7. Interpretation of the
line over the field confirmed the existing
interpretation within expected margins of error for
both structure and fluid content. For the additional
well points the Z-scan plots accurately identified the
top of the Birdrong to an accuracy of +/- 3 m and
identified fluid content and column heights with
complete accuracy. The author can personally
confirm that these results were obtained in strict
‘blind test’ conditions. In addition, the top reservoir
was an unambiguous pick on all the analysed plots,
thin zones within the Windalia Radiolarite typically
gave a weak oil responses followed by a bland
medium to high electromagnetic (EM) impedance
response through the Muderong Shale followed by a
sharp kick to a low EM impedance zone
corresponding to the Birdrong Sandstone, which
gave either a strong water response sometimes
preceded by a few metres of an oil response. It was
concluded that the method appeared to be working
to better than expectations and that the remainder
of the survey should proceed as planned and
possibly expanded.
The main results of the remainder of the survey,
were that the Brooke, Tess, Elysia and Jennifer
prospects all yielded encouraging results in terms of
picked depths and predicted oil columns.
Recordings over a number of other minor leads and
prospects (e.g. a lead updip of Roberts Hill 1) all
gave negative results. A number of other wells were
analysed and these mostly gave consistently good
correlations although the oil column of 3-6 m (from
logs) in Parrot Hill was not identified and there was
a depth error of 12 m at Lefroy Hill 1. The updip
Parrot Hill prospect, Elysia, was affected by steep
dip and it was found to be necessary to hand
migrate the results using shallow dips derived from
the seismic data to obtain a more meaningful map.
It was subsequently decided to test the most
promising prospect, Brooke, identified from the MT
survey. This prospect was relatively small in size but
predicted to be about twice as large as the Rough
Range field. It was about 400 m from Rough Range
7 which had good oil shows but was poorly
controlled by seismic and what seismic there was,
was affected by a strong velocity field. Unfortunately,
Brooke 1 came in low to prognosis and was dry. It is
interpreted that the well was just on the wrong side
of a normal fault running perpendicular to the Rough
Range fault and sub-parallel to the nearby 2D
Drilling operations at Rough Range (image courtesy of Empire Oil and Gas)

seismic line and that both the nearby MT points and
the 2D seismic line were imaging the upthrown side
of the fault. A fault was interpreted from the MT
results but was placed about 100 m to the north of
the well location. Steep shallow dips are believed to
be responsible for the data not being imaged in the
correct place. There was no seismic line running in
this direction and the shallow data from the MT
survey was not initially analysed.
At the same time as the well Brooke 1 was being
drilled, the third MT survey to be acquired in the
Carnarvon Basin, the Sandalwood MT survey, was
being acquired in the adjacent permits EP359 and
EP412. This survey was conducted in June 2001
and comprised 88 recordings, many of which were
in very remote and difficult locations. A large
number of leads and prospects were tested. The
most encouraging results came from a sizeable
prospect in EP359 on the east side of the
Learmonth fault adjacent to Learmonth 2 and
opposite Trealla 1. An additional 5 wells were
analysed in this survey and all had depth accuracies
of less than 5 m with the exception of Trealla 1,
which was out by 18 m and this was attributed to
unusual ground conditions.
It was next decided to test the potentially largest
prospect, Tess. This prospect had previously been
identified from the seismic data and was located on
a seismic line, so it was not purely a test of the MT
method. As this well was being drilled, depths were
on prognosis until near the base of the Muderong
Shale, a thrust fault was intersected and a repeat
Muderong Shale section was encountered. The
location on the seismic line appeared to be well
back from the main fault and the fault intersected
was essentially subhorizontal and almost impossible
to see on the seismic line. Empire did try to
reprocess this line but the tapes were unreadable.
However, it would probably have required 3D
seismic in order to image the fault in question.
Again, the MT data that supported the seismic
interpretation were probably imaging data from the
other side of a fault.
The Perth Basin
Empire acquired a small MT survey comprising 13
points in April 2001. This consisted of a number of
points in the Gingin area, the Bullsbrook 1 well and
a number of points over the Eclipse prospect. The
results of this survey gave an excellent correlation
between the log data at Bullsbrook 1 and the MT
plot, the correlation at the Gingin wells was not as
good although some of the gas zones at Gingin 1
were correctly identified. The survey also predicted
depths at Eclipse close to that predicted from the
seismic data and also predicted gas saturation in
the main target reservoir. Eclipse was defined by a
2D seismic grid and exhibited a well-defined AVO
anomaly, which appeared to closely match the
mapped structure. Eclipse 1 was drilled in 2003
with disappointing results, although there was a 3
m oil column in the upper sand. The AVO anomaly
was probably due to very clean, high porosity sand.
Depth predictions from both the seismic and MT
data were quite accurate.
Summary and Conclusions
Although to date, the MT method has not resulted in
a commercial discovery in WA, the vast majority of
exploration wells based on seismic data have also
failed this test. However, the AMT technique has
given prediction.
The major advantages of the MT method are:
1. The ability to record data in areas with poor or
uninterpretable seismic signal, e.g. areas with
surface basalt or weathered near surface
PWA April Edition - Magnetotelluric Surveys 27
carbonates.
2. The ability to more precisely predict depths
where the seismic data is affected by changes
in velocity caused by thick layers of carbonates
or salt.
3. The ability to record data in environmentally
sensitive areas with restricted or no vehicular
access.
4. It provides information about electrical rock
properties in addition to acoustic rock properties.
Disadvantages of the MT method are:
1. In areas of complex stratigraphy it may be
difficult to accurately correlate events. However,
recording more closely spaced points may solve
this problem.
2. It can only be used in dry surface conditions –
although it can be used over shallow salt water
or on the seabed.
3. Recording is not possible during unfavourable
periods of solar activity or in culturally noisy
areas (i.e. close to radio transmitters, power
lines, etc.).
4. Some depth shifting occurs due to diurnal and
seasonal changes in the earth’s magnetic field –
recording frequent calibration points can
substantially reduce these inaccuracies.
Worldwide, both conventional MT and AMT continue
to be used in oil and gas exploration. The most
recent developments include the recording of
seabed surveys for sub-salt and sub-basalt
imaging. Conventional MT has been used
successfully in Papua New Guinea to image beneath
overthrust carbonates. DoIR
image courtesy of Paul Cartwright

28
PWA April Edition - State Acreage Release
Richard Bruce
Exploration Geologist, Resources Branch
State Acreage Release March 2004
Figure 1. Location of Northern Carnarvon Basin release areas (in blue).
In March 2004 the Western Australian Department
of Industry and Resources released six petroleum
exploration areas at the APPEA Conference and
Exhibition, in Canberra.
The Acreage
Applications are invited for the grant of Exploration
Permits for areas as in the table below.
The location of the application areas is shown in
figures 1, 2 and 3.
Key Dates
Release date: Tuesday 30 March 2004
Closing date: 4pm Thursday 30 September 2004
Release package
The CD package includes non-geotechnical
information such as investment background,
applying for acreage and land access.
Northern Carnarvon Basin Acreage
The Northern Carnarvon Basin, and particularly the
Barrow and Dampier Sub-basins, is one of the more
intensively explored areas of Australia. Islands (such
as Barrow, Airlie, Varanus and Thevenard) provide
excellent locations for production facilities and
bases (Fig. 1).
Area L04-1 is situated some 10 km to the east of
the Varanus Production Area and less than 25 km
southwest from the Stag (oil) Production Licence.
Combined Areas L04-2 and T04-1 lie to the west of

and immediately adjacent to the Airlie Island
Production Facility, as well as immediately north of
the Thevenard Production Facility. Area L04-3 is
situated immediately adjacent to this facility. Water
depths are less than 50 m in the release areas
making jackup drilling rigs practical to use in these
areas. There is a good coverage of 2D seismic and
partial coverage of 3D seismic in the release areas.
The offshore Northern Carnarvon Basin is Australia’s
leading producer of both liquid hydrocarbons and
gas. To date, most oil production has come from the
Barrow Sub-basin. Key factors leading to this
success include good Mesozoic source rocks, which
have generated over a long period of time; Lower
Cretaceous reservoir rocks with excellent porosity
and permeability; and a thick and effective regional
seal (Muderong Shale; Baillie and Jacobson, 1997).
Most of the oilfields discovered in the Barrow Subbasin
rely on fault closure where the Winning Group
shales (Muderong Shale and Gearle Siltstone)
provide a seal for accumulations in the Barrow
Group, Windalia Sandstone Member and Birdrong
Sandstone (West Australian Petroleum Ltd, 1995).
Perth Basin Acreage
The two Perth Basin release areas (L04-4 and L04-
5) are situated east and southeast of the Woodada
gasfield respectively, in the northern part of the basin
(Fig. 2). The area is readily accessible, consisting of
undulating farm and shrub lands. Access from main
roads is relatively simple, and petroleum-industry
infrastructure includes two major gas pipelines and
good roads to an oil refinery 30 km south of Perth.
The logistics and economics of potential oil and gas
discoveries are very positive given the proximity of
existing infrastructure and an expanding market,
particularly since the deregulation of Western
Australian gas markets in 1988.
Twelve commercial hydrocarbon fields and numerous
additional significant discoveries have been made in
the onshore northern Perth Basin. The largest of
these by far is the Dongara field, with 14.3 Gm 3
(508 Bcf) of original in-place gas and 16.6 GL (104
million barrels) of original in-place oil. Other notable
discoveries are the Woodada gasfield, the Mount
Horner oilfield and the Beharra Springs gasfield. In
recent years, exploration in the Perth Basin has been
revitalised by the discovery of the Hovea oilfield by
ARC Energy, the Beharra Springs North gasfield and
the Jingemia oilfield by Origin Energy, and the
offshore Cliff Head oilfield by Roc Oil.
Petroleum-system analysis indicates that mature
source rocks are widespread, reservoirs are
abundant, and structures are well timed for
hydrocarbon entrapment. A critical factor is
considered to be the seal, due to the intense
faulting and high sand-to-shale ratio of the post-
Lower Triassic succession.
The main source for oil is a basal marine facies in
the Lower Triassic Kockatea Shale, with reservoirs in
Lower Triassic and Permian sandstones. The main
source for gas is the Permian Irwin River Coal
Measures, with reservoirs in the Upper Permian and
Jurassic strata. Carbonaceous horizons within the
Cattamarra Coal Measures may also contribute gas
from the central part of the Dandaragan Trough
where the unit is up to 6000 m deep.
Major play types include Permian–Triassic and
Jurassic anticlines as well as Permian–Triassic tilted
fault blocks and stratigraphic traps. There are many
untested hydrocarbon prospects in the Perth Basin.
Structures on the upthrown side of the Eneabba
Fault are considered the most prospective untested
plays in the release areas, especially where a
reservoir is juxtaposed against sealing units such as
the Cadda Formation and shale in the Cattamarra
Coal Measures and Eneabba Formation. Strong
PWA April Edition - State Acreage Release 29
Tectonic element Application area 5’ x 5’ Approximate
graticular blocks square kilometres
Northern Carnarvon L04-1 9 720
Basin (offshore) L04-2* & T04-1* 3 & 4 240
L04-3 1 80
Perth Basin (onshore) L04-4 13 1040
L04-5 15 1200
Officer Basin (onshore) L04-6 297 23760
* Combined areas
flows of wet gas were encountered within fractured
zones of the Kockatea Shale in Eneabba 1 in a
similar structural position (Crostella, 1995),
suggesting that the top Permian level could be an
attractive target where sufficiently shallow. Other
plays include fault plays on the eastern margin of
L04-4 with a deeply buried Kockatea Shale source,
and stratigraphic pinchouts within the Cattamarra
Coal Measures on the western flank of the
Dandaragan Trough with an intra-formational
source.
Officer Basin Acreage
The frontier Officer Area L04-6 is being released at
the request of industry who consider it has some
potential for oil. The basin is under-explored
probably because of its age and its remoteness.
Figure 2. Location of Perth Basin release areas (in blue).

30
PWA April Edition - State Acreage Release
However, the Goldfields Gas Transmission Pipeline
runs south from the North West Shelf to Kambalda,
about 200 km west of the Officer Basin. Potential
markets or delivery points for discoveries include
mining centres along this pipeline, Alice Springs in
central Australia, and coastal ports.
Thin but good source rocks have been identified
through the succession, and sandstone intervals
with excellent reservoir characteristics are present.
Seals include salt, evaporite, shale, and siltstone.
Potential traps formed from the mid-Neoproterozoic
to the Palaeozoic, and were in place before the
main phase of hydrocarbon generation (Ghori,
1998, 2002).
Mineral exploration drillhole NJD 1 lies on the
Western Platform. NJD 1 intersected a section of
probable Kanpa and Hussar Formation
(Neoproterozoic) beneath 108 m of Cainozoic lake
fill, and steeply dipping, slightly cleaved
?Mesoproterozoic sandstone and siltstone at 377 m
(Hocking, 2002). Migrated hydrocarbons are present
in NJD 1 as staining (originally reported as oozing)
in the Neoproterozoic interval, and bitumen in the
?Mesoproterozoic interval. Shaly siltstone near the
base of the Neoproterozoic succession has good
source-rock potential (Ghori, 1998). However, none
of the hydrocarbons from NJD 1 have been charged
from the source rocks intersected by the drill hole,
underlying ?Mesoproterozoic succession.
Acreage release Area L04-6 lies at the western
margin of the basin, and includes parts of the
Western Platform and a thin Phanerozoic
succession (Gunbarrel Basin) that rests directly on
Archaean crystalline basement. Linked deep seismic
lines 01AGSNY-01 and 01AGSNY-03 (Cassidy,
2002) extend from the Yilgarn Craton
northeastwards through the area. 01AGSNY-03 was
located to pass through NJD 1, and appears to
show shallowly dipping, westward-thinning Officer
Basin rocks overlying variably dipping older
sedimentary and unbedded rocks.
Exploration drilling in the Amadeus Basin in the
Northern Territory and in the Officer Basin in South
Australia has demonstrated the prospectivity of
Australia’s Neoproterozoic section. Several oil and
gas shows were encountered and the Dingo gasfield
discovery in the Northern Territory was made.
Results to date have identified reservoirs with
porosities greater than 20% and permeabilities
ranging from hundreds of millidarcies to more than
a darcy, particularly in the Hussar Formation. Halite
beds greater than 10 m thick in the Browne
Formation and shales greater than 10 m thick in the
Browne, Hussar, Kanpa, and Lupton Formations
provide potentially effective seals. Thin, but goodquality
source rocks have been found in the
indicating an effective migration pathway from
Figure 3. Location of Officer Basin Browne, release Kanpa, area and (in blue).
Hussar Formations. The close
elsewhere in the Officer Basin and possibly in the
association of laminae-scale source rocks with
good-quality reservoir and seal horizons indicates
the presence of at least the basic physical elements
of a petroleum system, and the widespread, though
minor shows indicate that hydrocarbons have
moved through the system. Maturity modelling
indicates that substantial hydrocarbon traps had
formed before most of the potential source rocks in
the Officer Basin first entered the oil window, and
much of the section remains in the oil-maturation
window today (Ghori, 1998, 2002).
Further Geological Information
For further information on the Perth Basin contact
Arthur Mory (+61 8 9222 3327), or on the Officer
and Northern Carnarvon Basins contact Roger
Hocking (+61 8 9222 3590).
To Apply
Western Australia has a work programme bidding
system, details of which are available in the release
CD package available on request. Contact:
Petroleum and Royalties Division
Telephone +61 8 9222 3273
Fax +61 8 9222 3799
References
BAILLIE, P.W. and JACOBSON, E.P., 1997,
Prospectivity and Exploration History of the Barrow
Sub-basin, Western Australia, APPEA Journal 1997,
117–135.
CASSIDY, K. F. (editor), 2002, Geology,
geochronology and geophysics of the north eastern
Yilgarn Craton, with an emphasis on the Leonora-
Laverton transect area: Geoscience Australia Record
2002/18, 118p.
CROSTELLA, A., 1995, An evaluation of the
hydrocarbon potential of the onshore northern Perth
Basin, Western Australia: Western Australia
Geological Survey, Report 43, 67p.
GHORI, K. A. R., 1998, Petroleum source rock
potential and thermal history of the Officer Basin,
Western Australia: Western Australia Geological
Survey, Record 1998/3, 52p.
GHORI, K. A. R., 2002, Modelling the hydrocarbon
generative history of the Officer Basin, Western
Australia: PESA Journal, no. 29, p. 29–43.
HOCKING, R. M. (compiler), 2002, Drillhole WMC
NJD 1, western Officer Basin, Western Australia:
Stratigraphy and petroleum geology: Western
Australia Geological Survey, Record 2002/18, 26p.
WEST AUSTRALIAN PETROLEUM, 1995, Annual
Petroleum Exploration Appraisal of the Offshore
Carnarvon Basin Permits WA-24-P and TP/3 from
22 June 1994 to 21 June 1995, Western Australian
Geological Survey, S-series, S7003 R1 A2
(unpublished). DoIR

32
PWA April Edition - Diving Regulations
Andrew Pearce
Senior Safety Assessor, Safety and Environment Branch
Diving is regarded as a relatively high-risk activity
and is one of the industries associated with oil
and gas exploration and production that has been
regulated by Direction for many years. The move
away from reliance on prescriptive Directions to
objective based regulations is ongoing.
Prior to the introduction of the Commonwealth
Petroleum (Submerged Lands) (Diving Safety)
Regulations 2002 (Diving Safety Regulations) in
May last year, diving operations in both
Commonwealth and State areas were regulated
by Direction under Part 8 – Diving of the Schedule
of Specific Requirements as to Offshore
Petroleum Exploration and Production 1995 (the
Offshore Schedule).
Part 8 Diving of the Offshore Schedule was
revoked for Commonwealth areas following the
introduction of the Diving Safety Regulations;
however, diving in WA State waters is still under
the requirements of the Offshore Schedule. It is
anticipated that WA will mirror the Diving Safety
Regulations before the introduction of NOPSA
(National Offshore Petroleum Safety Authority) in
January 2005; these will apply in State waters
and the diving section of the Offshore Schedule
will be revoked.
Diving Safety Regulations
The Petroleum (Submerged Lands) (Diving Safety)
Regulations 2002 - Diving Safety Regulations) were
developed by a tripartite working group (diving
contractors, oil industry and State and
Commonwealth regulators).
Diving Regulations
These are objective based regulations with a
minimum of prescription. The main regulations
require:
• diving contractors to develop and implement
their own Diving Safety Management System
(DSMS);
• diving contractors and operators to develop a
Diving Project Plan (DPP) to identify hazards and
control risks for the specific project; and
• involvement of employees in both the DSMS
and DPP.
There are other regulations covering reporting,
recording, notification, responsibilities and
qualifications for diving personnel.
The diving contractor’s DSMS must be submitted to
the Designated Authority (DA) for review and
assessment and have the acceptance of the
regulator before the diving contractor can operate in
the upstream petroleum industry.
In addition to the DSMS, the diving contractor in
conjunction with the Operator (client) prepare a Diving
Project Plan (DPP). The Operator accepts the DSMS
and must approve the DPP for use in the execution of
works by/for the Operator before diving operations
can begin. The DPP does have to be submitted to the
DA for acceptance or approval; however, the DA can
request a copy for review and auditing.
The DSMS and the DPP are the rules by which the
diving project must be executed. Works conducted
in breach of the diving contractor’s DSMS and the
diving project plans are in breach of the diving
safety regulations.
Diving Safety Management Systems
Submissions
Many contractors were daunted by the prospect of
documenting their management systems and
revising their current documentation to ensure
compatibility with their revamped systems and
submitting them to the authorities. However, after
going through the process the overwhelming
response from the contractors was positive, with the
general acknowledgement that they wished they
had done this sooner.
Operators and the DA may audit the diving
contractor to ensure the DSMS is implemented and
they are complying with it. The DA audits operators
diving projects against the requirements of their DPP.
By the end of last year DoIR (as the Western
Australian DA) had assessed and accepted DSMS
from 5 diving contractors and provided advice to the
Victorian DA on a submission there.
There are 7 contractors with their DSMS accepted
by the DA in Australia. This represents the majority
of offshore diving contractors operating in the oil
and gas industry.
What diving approvals are required?
In WA there are 2 areas of jurisdiction: WA State
waters, where the diving requirements in the Offshore
Schedule apply and the Commonwealth Adjacent
Area where the Diving Safety Regulations apply.
Commonwealth Adjacent Area
From a DoIR perspective, operators are required to
review and accept or approve the management
systems of their subcontractors. With diving
contractors, operators are obliged to review and
approve their DSMS before developing and
approving the DPP. Operators need to ensure that

the contractors they select have their DSMS
accepted by the regulator. Operators are required to
notify the DA of diving operations at least 14 days
before they start.
WA State waters
Diving operations in State areas are still regulated
under Part 8 - Diving of the Schedule of Specific
Requirements as to Offshore Petroleum Exploration
and Production 1995 (the Offshore Schedule).
The requirements under the Offshore Schedule are
prescriptive. Where there are deviations from the
requirements of the Schedule exemptions must be
sought and justified before being submitted to the
DA for consideration. The operator is obliged to
obtain approvals from the DA for diving operations
and any exemptions required.
The approval for operation in State waters can be
managed in 2 ways, by requesting approval:
• under the requirements of the Offshore
Schedule or
• by complying with the requirements of the Diving
Safety Regulations.
Option 1 - Under the Offshore Schedule
Under the existing requirements of the Offshore
Schedule, the operator must request approval for
the diving operation and provide details of the
operation to the DA.
Option 2 - In conjunction with Commonwealth
Diving Safety Regulations
With the intention of having consistency across
Commonwealth and State jurisdictions, DoIR believe
that where the operator uses a diving contractor
who has their DSMS accepted by both the operator
and the DA, then the request for approval can be
granted on the basis that the diving contractor and
the operator comply with the intent of the Diving
Safety Regulations. The operator requests approval
for the operation and agrees to conduct the
operation under the DSMS and DPP.
The subsequent approval from the DA will contain a
general dispensation from the prescriptive hardware
requirements of the Offshore Schedule and the
differences in diving contractor’s DSMS.
The advantages of option 2 are that the operator
and diving contractor can maintain a systematic
approach to their operations in both State and
Commonwealth waters. It allows the diving
contractor and the operator to focus on areas of risk
associated with the project rather than complying
with specific prescriptive diving requirements of the
Offshore Schedule.
The more prescriptive aspects of the Offshore
Schedule are managed by having the diving operation
controlled under the diving contractor’s DSMS and
the DPP, which is approved by the operator.
We would encourage operators and diving
contractors to discuss these options so that a
consultative process can occur and agreement
reached on the appropriate application of the diving
safety regulations.
PWA April Edition - Diving Regulations 33
For additional information and links to diving
legislation and guidelines please see our web site:
www.doir.wa.gov.au/safetyhealthandenvironment/
petroleumdiving.asp DoIR
Divers on the Woodside Trunkline System Expansion Project. This project was the first major diving project
completed under the Diving Safety Regulations in WA. Photo courtesy of Technip Oceania Pty Ltd, operators
of the CSO Venturer, the diving support vessel from which the diving operations were carried out.

34
PWA April Edition - Coal Seam Methane
Darren Ferdinando
Research Geologist, Resources Branch
Coal seam methane (CSM; also known as coal
bed methane - CBM, and coal seam gas - CSG),
is a naturally occurring hydrocarbon that is
generated and reservoired within coal seams. The
methane gas is generated either through biogenic
activity in near-surface coals or through
thermogenic activity for deeper coal bodies. The
generated methane is held within the coal by
burial and hydrostatic pressure in a process
known as adsorption.
Coal seam methane over the last ten years has
become a significant source of sales gas across
eastern Australia. In Queensland for example, nearly
80% of the petroleum wells drilled last year were
for CSM operations. Total Queensland CSM
production in 2002/03 is estimated at 25 PJ, which
equates to almost 25% of Queensland’s current gas
demand - this is an increase from 2 PJ in 1998 and
11 PJ in 2001. In New South Wales, CSM
operations accounted for all the petroleum wells
drilled in the State. In 1999/00 the gross value of
CSM operations in NSW was reported by the NSW
Department of Mineral Resources at $18.56 million
and the value of production is expected to increase
to increase by at least 5% annually for the next ten
years, with a new CSM operation well at Camden
due to be commissioned soon. By 2020 it is
estimated that CSM will account for 100 PJ/annum
of energy production in eastern Australia, with
Queensland accounting for 60% of this and New
South Wales the remaining 40%. ABARE has
estimated a 3% annual growth in natural gas
consumption until 2020, increasing from 521 PJ
(17% of Australia’s total energy consumption) to
974 PJ in 2020 equating to nearly 20% of
Australia’s energy consumption. CSM operations
have the potential to contribute to an increasing
proportion of this natural gas consumption.
Coal Seam Methane - what’s the gas?
At present there are no commercial CSM operations
in Western Australia; however, the level of CSM
exploration in the State has increased over the last
two years. In response to this, the Petroleum and
Royalties Division of DoIR is commencing a study
into the CSM potential of Western Australia to assist
explorers in this field find appropriate acreage in the
State. This article intends to provide a broad
overview of CSM operations and the regions of the
State that may be prospective for CSM.
Differences between conventional gas and CSM
All the gas currently produced in Western Australia
comes from ‘conventional’ gas plays where gas has
been generated at depth in organic-rich claystones
or shales and migrated along permeable rock beds
into an area that has effectively trapped the gas; for
example, through sealing the permeable rock
against impermeable rock by faulting; or in creation
of domal structures through folding of the
permeable rocks that the gas is then trapped in.
Coal seam methane operations involve extracting
methane gas from subsurface coal accumulations.
While it is possible to extract methane from shallow
coals, such as those mined from the Collie coalfields
in the southwest of Western Australia, the production
rates from these deposits tend to be noncommercial.
For optimal methane production rates,
coal seams generally need to be at a depth of
between 500 to 1200 m. The maximum depth of
burial for coal seam methane production (at
commercial rates) appears to be about 1200 to 1500
m, although some wells produce methane at greater
depths. The minimum depth of burial is about 200 to
300 m, depending on the sealing efficiency of the
overburden. These are depths at which coal mining is
uneconomic – thus these two uses of coal for energy
are not competing for the same resource.
Coal has an extremely large internal surface area
due to its enormous micropore surface area, and as
such it can store surprisingly large volumes of
methane-rich gas; six or seven times as much gas
as a conventional natural gas reservoir of equal rock
volume can hold.
One of the greatest advantages associated with the
coal seam methane resource relative to
conventional gas is that the size and extent of the
coal deposits, along with the gas content of the
coal, can be estimated with a reasonable degree of
accuracy before major investments are made.
Technical issues for CSM exploration and
production
The technical considerations in determining whether
a CSM prospect will be commercially viable are
quite different than those used in making such
determination for conventional gas prospects. Key
factors that affect gas flow rates in coal seam
methane projects include the absorption properties
of the gas, presence of fracturing and permeability.
Biogenic vs thermogenic methane
Coal seam methane can be generated through two
distinct mechanisms. The first is generation of
methane through thermogenic breakdown of the
carbon-rich material in the coal due to burial of the
coal seam. Thermogenic methane generation
usually occurs at depths of greater than 300 m. The
second mechanism for methane generation from
coal seams relies on methane being generated from
bacteria found within the coal at generally shallow
depths (up to 500 m). Research has indicated that
biological methane generation can be very rapid in
low-rank coals such as those found in Western
Australia. This biological gas generation is so rapid
that it is technically feasible to generate usable gas

y introducing appropriate organisms into suitable
coals. This process of in-situ biogasification is at the
conceptual stage at present, but has important longterm
implications. Further refinement of this process
may be provided by the use of genetic engineering
to optimise the organisms for gas generation.
There is some difference of opinion regarding the
nature of biogenically generated gas in coal seams
- some authorities consider that there is little, if any,
adsorbed gas, and that the gas is present in a ‘free’
form in the cleats (small fractures in the coal) and
other openings, as well as in formation waters. It is
probable that both biogenic and thermogenic
scenarios embrace adsorbed, ‘free’ and dissolved
gas, but in different proportions. In both scenarios,
the retention of gas is almost totally dependant
upon hydrostatic pressure and commercial
production, thus involving the production of
significant water to lower the hydrostatic pressure to
permit the gas to flow.
Coal quality
Increasing ash content causes coal strength to
increase, thereby decreasing the potential for
fracturing/cleating. Coals with lesser amounts of ash
are, therefore, the most likely to have the greatest
cleat development - and thus the highest
permeabilities. Also, as the ash component of coal
cannot absorb methane, it reduces the volume of
gas that can be contained in a unit volume of coal.
The maximum ash content before a coal becomes
non-commercial has not been determined, but
probably varies according to other parameters such
as maturation level. Additionally, the cleat density is
greater in the brighter coal types - such as vitrain
and bright clarain and substantially less in the dull
coals - like durain.
The process of gas flow from the solid coal to the
cleats is one of diffusion. Usually the cleats are filled
with water and the desorption of gas within the cleats
leads to the two phases existing within the cleats. If a
secondary major fracture system exists, flow may
then take place from the cleats to the major fractures
(Figure 1). Both the cleats and major fractures exhibit
their own phase dependant permeabilities.
Diagenesis may cause deposition of mineral matter
in the coal cleats, significantly reducing coal
permeability. Carbonate infilling is the most
common form of diagenesis in coals, but silica,
pyrite, illite, smectite, kaolinite and other clays have
also been observed as cleat infillings. Prospective
gas coals should thus be relatively free of such
cleat-filling substances.
The gas content of any prospective coal should be
greater than 8.5 cc/g (300 scf/t). The coals also
need to reach a certain level of thermal maturity in
order to generate gas and to produce the structure
and chemistry necessary for storing commercial
quantities of methane within the coal. The vitrinite
reflectance should be in the range of R O of 0.7% to
R O of 2.0%. In general, the higher the maturity, the
greater the adsorption capability of any coal. From
looking at coal seam methane operations in the US,
where the industry is approaching a mature stage, it
appears that the minimum thickness of coal
required to produce commercial quantities of gas is
5 to 6 metres in no more than 3 or 4 seams.
The gas content of coal is usually determined by
gas desorption procedures, which means gas is
desorbed from coal by placing a sample of the coal
(usually from drillcore) in a sealed container, and
measuring the amount of released gas over periods
which may range from days to months. This
procedure requires the gas to be desorbed from the
coal’s micropore structure (ie the thermogenic
scenario); however, the predominantly ‘free’ gas of
the biogenic scenario (or a significant component of
it) may not be detected by this desorption method
and, hence, the resulting low to non-existent gas
contents may give a quite false portrayal of gas
producibility from a formation.
Pressure and permeability
In thermogenic situations, gas is adsorbed onto the
coal’s micropore surfaces and held in place by the
reservoir (water) pressure. The methane within a
coal seam is released when the hydrostatic
pressure is reduced, allowing the cleats in the coal
to expand, increasing permeability and commencing
the process of desorption of the methane gas from
the coal. Most coals show a significant relationship
between effective stress (total stress minus
hydrostatic pressure) and permeability. The cleats
being closed by increasing effective stress cause a
reduction in permeability. If fluid pressure is high, it
tends to open the cleats and as pressure decreases
with fluid withdrawal the cleats close. The reduction
in permeability may be of an order of magnitude for
anything between 2 and 10 MPa of increasing
effective stress. The softer the coal the more
pronounced this effect is.
As water and gas are produced from the seam, the
effective stress increases leading generally to a
reduction in permeability. Many coals, however,
exhibit an increase in permeability with production.
Figure 1. Flow through cleats in coal
PWA April Edition - Coal Seam Methane 35
This is caused by an effect that tends to de-stress
the seam. This de-stressing is a result of the fact
that most coals shrink as gas is desorbed. The
shrinkage reduces the lateral stress on the seam
and shifts that stress into the surrounding rocks.
These two opposing effects on the effective stress
mean that the permeability of the seam may either
decrease or increase with the removal of gas and
water from the seam, depending on the
characteristics of the coal and associated gas.
Frequently both these effects are present, with an
initial permeability decrease in the reservoir
pressure around the producing well, followed by an
increase as significant desorption-induced
shrinkage occurs within the coal.
Depending on the nature of the coal and depth of
burial, this release of methane varies from negligible
gas flow to commercial rates of gas flow, although
in all cases a significant amount of time is required
to dewater the coal bed before any gas is
recovered. Timing of water handling is one of the
major differences between CSM and convention
gas. With conventional gas, gas is trapped under
pressure and overlies water. This pressure is then
used to allow the gas to flow to surface through the
well casing until the rising water level in the trap
increases to the point where the amount of gas
produced relative to water becomes uneconomic
because the rate of gas production is so low. In
CSM operations, the water, which is holding the gas
to the coal through hydrostatic pressure, is drained
first and as the water pressure (measured in terms
of hydrostatic pressure on the gasfield) decreases,
adsorbed gas is released from the coal seam and
then produced through the well bore over a long
period (Figure 2). Over time, the rate of gas
desorption decreases until the flow rates become
uneconomic to continue to produce from the bore.
The water, which is commonly saline but in some
areas can be potable, must be disposed of in an
environmentally acceptable manner. Surface
disposal of large volumes of potable water can
affect streams and other habitats, and subsurface
reinjection makes production more costly.

36
PWA April Edition - Coal Seam Methane
Other considerations
Figure 2. Rate of methane production against produced water over time,
water production shown in blue, methane in orange.
The processing of CSM is in many cases simpler
than that required of conventional gas. Conventional
gas can have a highly variable composition, from
‘dry’ (where the dominant hydrocarbon in the gas is
methane) to ‘wet’ (where the heavier hydrocarbons
such as butane, ethane and pentane are present in
the gas in addition to methane). The ‘wet’ gases
need to be stripped of the heavier hydrocarbons
(which are sold separately as condensate). In
addition, extraneous gases such as nitrogen, carbon
dioxide and hydrogen sulphide may be present in
the gas and these must be removed during
processing, as well as water vapour, which must be
stripped from the gas. Once the extraneous
components of the conventional gas have been
removed, the gas is then compressed and piped to
users. In CSM, the gas is predominantly methane,
and impurities such as carbon dioxide are generally
localised and comprise a small portion of the gas.
The major steps for processing of coal seam gas
include removal of water vapour from the gas and
compression of the gas to pipeline pressure
conditions. Gas plants for CSM operations therefore
tend to be less complex than those used to process
conventional gas.
To assist the flow of gas from the coal to the
producing well, the coal is hydraulically fractured.
This is accomplished by pumping large volumes of
water and sand at high rates down the well and into
the coal seam. This operation either produces new
fractures or forces the pre-existing cracks and
fractures in the coal seam to enlarge and extend.
The fractures begin at the well bore and then
extend for distances of up to several hundred
metres away from the well. Fractures deep in the
coal seam are less than one centimetre wide, and
have no effect on the ground surface.
Producing coal seams must be isolated from flowing
aquifers in order that they may be successfully
dewatered. This is necessary because coal seam
methane is produced from a seam after the water is
allowed to flow in the well, producing a lowered
pressure regime suitable for desorption of the methane
from the coal. Paradoxically, too high a permeability in
the coal can allow too much water flow, thus inhibiting
the methane desorption and recovery.
In recent years there has been a growing increase
in interest by both the coal industry and the
petroleum industry in CSM resources. There are
considerable commercial advantages offered by
methane, that has been drained from coal seams,
as an energy resource. These advantages include a
relatively low “finding cost”, and, often a convenient
location close to major markets.
Potential sources of CSM in WA
Perth Basin
Cattamarra Coal Measures
Jurassic coals found in the northern Perth Basin in
1961 on the western flank of the Dandaragan
Trough show potential for CSM production. The
extent of high quality coal is estimated at 800 km 2
from Eneabba down to Wongonderrah Spring. A
number of CRAE exploration programmes have
covered the near-surface area of the coals and will
form the basis of future studies by DoIR on the
potential for CSM generation from these coals.
Irwin River Coal Measures
Low-grade Lower Permian coals are found in the
northern Perth Basin, and were the first coal beds to
be recorded in Western Australia in 1846. The coal
measures extend of over 600 km 2 and CRAE
undertook a systematic study of the region during
the late 1980s and early 1990s. Coal resources for
the Irwin River Coal Measures are estimated at
1180 Mt of inferred in situ coal. The coals have an
ash content of 11 to 31%, are sub-bituminous and
generally dull. At a depth of 145 m, the vitrinite
reflectance ranges from 0.5 to 0.6 and the coals
have a medium to low sulphur content.
Sue Coal Measures
Low-moderate grade Lower Permian coals of the
Sue Coal Measures are found in the southern Perth
Basin in the graben between the Darling and
Dunsborough Faults. Up to 17 coal seams with a
maximum recorded seam thickness of 5.5 m are
present, varying in rank from lignitic to bituminous,
with the most economically attractive seams near
the base of the Permian strata.
Collie Basin
The Collie Basin is a sedimentary outlier on the
southwest Yilgarn Craton and hosts Western
Australia’s most significant coalfield. The coal
sequence has a maximum thickness of 700 m and
individual seams vary in thickness, with a maximum
of 13 m recorded. The vitrinite reflectance of coals
mined from the Collie coalfields is approximately
0.65 at 130 m.
Canning Basin
Coal-bearing areas of the Canning Basin are mainly
confined to the Fitzroy Trough and occur in Upper
Permian sediments. The coal is thin and sparse, and
the resource appears to be limited and highly
faulted. Upper Jurassic coals have also been
recorded in the Canning Basin in petroleum wells,
but no specific details on these coals are known at
present.
Carnarvon Basin
Thin Permian coals have been recorded from the
southern Carnarvon Basin, notably within the Byro
and Merlinleigh Sub-basins and along the
Wandagee Ridge. Limited data is available on these
coals, and comes from both petroleum well data
and mineral exploration programmes.
Bremer and Eucla Basins
Cainozoic brown coals are found within the Bremer
and Eucla Basins and the deposits cover a
significant area of the basins including
contemporaneous drainage channels. The coal
generally occurs as a single seam up to 12 m thick
within the Werillup Formation. Exploration drilling of
these coals has occurred on a limited basis, and the
coal has higher ash, salt and sulphur content than
brown coals from Victoria.
Conclusion
The capacity of coal to hold gas is dependent on
porosity, which in turn is related to coal quality, gas
composition and gas pressure. A general
relationship has been established that adsorptive
capacity (and therefore potential total gas content)
increases with rank of the coal and with depth.
Permeability of coal decreases with depth.
Within Western Australia, there does appear to be
some potential for coal seam methane production,
generally confined to the southwestern portion of
the State in the northern and southern Perth Basin.
The subsurface extents of the Lower Permian Irwin
River and Sue Coal Measures and the Lower
Jurassic Cattamarra Coal Measures, where the coal
seams lie between 300 and 1200 m are the areas
that at this stage of the Department’s CSM
prospectivity study appear to show the most
potential. DoIR

International Risk Consultancy
It was the hot summer of 1997. Air-conditioning
systems crashed and burned without warning and
the sweat dripped off the goannas that basked in
the midday sun. Inside a Perth suburban house,
three dedicated engineers were faced with a
difficult decision. To cave in to temptation and head
to the beach, or to start a risk management
consultancy?
As Morris Burch, Managing Director and founder of
IRC explains, they chose the latter, and the decision
was nothing more than a calculated risk.
“We went forward with blind faith, optimism and
naivety,” he said.
It was almost exactly opposite to the philosophy of
risk management for which IRC is now
internationally renowned, but an optimism that
appears to have worked. The consultancy now
employs 70 full time staff, runs five business units,
has an established office in Houston, Texas and is
currently launching an Aberdeen office.
Morris attributes IRC’s success to three competitive
“obsessions” – people, innovation and quality. He
believes that it takes exceptional individuals to drive
an exceptional business. So the focus is on
acquiring, retaining, and developing talent.
Recruitment has attracted candidates from UK,
Europe, North America and the Asia-Pacific regions,
as well as Australia. He describes the organisation
as young, energetic and enthusiastic consultants
supported by principals with substantial experience.
“It’s the best bunch of people I have ever worked
with,” he said.
While he sees being part of a world-leading
organisation as an objective for some members of
his team, he understands that personal career
development and training may be more of a priority
for them. What is clear, he says, is that highly skilled
people want to work together with others of similar
talent, in an environment where their skills interlink.
Each of IRC’s five business units: Safety and Risk,
Environment, Asset Optimisation, People and
Information offers services directed at assisting
energy organisations to set new benchmarks in their
health, safety and environmental performance, while
maximising the value of their assets. IRC has
tailored its services so that it is single point of
contact for a HSE department within any
organisation.
“We assist all of our clients in developing, and
retaining ownership of, their risk management
process,” said Morris.
The Safety and Risk group carries out studies from
the provision of ad-hoc safety advice to the
complete management of safety and risk on major
projects. The Environment group specialises in
environmental management and monitoring
services. The Asset Optimisation group undertakes
studies in system availability, reliability and
maintainability, and performance optimisation. IRC
also provides programmes focussed on optimising
the performance of an organisation’s workforce
through its People group, whose services are
designed to promote corporate health and
organisational culture.
As part of ongoing change management, IRC
encourages all groups to participate in improving
services. ‘Innovation meetings’ are regularly held
within business units to harvest ideas and concepts,
to arrive at a better risk management service. Such
an initiative is rare in consulting, particularly where
there is often emphasis on time and budget
constraints.
PWA April Edition - Company Focus
Grant O’Connell,
IRC
The Information Technology group provide the tools
and thinking required to automate aspects of IRC’s
services and provide innovative risk management
solutions. Recently IRC has developed two new and
exciting ‘off-the-shelf’ software packages for risk
management – RiskNet and Optimize.
RiskNet is an online risk management system. Its
strength as an action tracking and close-out tool
makes it ideal for monitoring hazards, risks, and
incidents arising from an organisation’s day-to-day
operations, as well as larger projects. It represents a
streamlined, easy to use and inexpensive way of
managing HSE processes.
RiskNet is designed for deployment across multiple
sites, promoting the sharing of knowledge and
information across the enterprise. It is also targeted
at those organisations that require a practical,
keenly priced solution.
RiskNet is a new product, but already customer
feedback has been excellent. IRC has endeavoured
to keep the system interface easy to use as we
consider this vital for effective user-take up. The
system’s flexibility means that we can align
processes and naming conventions to our clients
requirements, which also facilitates user adoption
and eases implementation.
The software is modular. Functionality includes:
37
• action tracking;
• incident reporting and investigations;
• hazard/risk registers, with safeguards and risk
ranking;
• process mapping;
• key performance indicators (KPI) and legislative
reporting and analysis;
• audit and inspections (particularly Behavioural
Based Safety);
• emergency response;

38
PWA April Edition - Company Focus
• safety and environmental information
management; and
• workers’ compensation.
Optimize was developed to carry out reliability,
availability and maintainability (RAM) analysis. The
software was developed by IRC engineers who
required a more powerful modelling tool for their
calculations than was available on the market. The
solution – develop their own.
While lowest cost is seen as being an important
dimension in remaining competitive in the
consulting market, Morris also cites quality of
product as an equally important aspect.
“The emphasis continues to be on producing
outputs of the highest technical quality.”
Establishing an office in Houston was a recent
challenge to IRC, and an interesting learning
experience. Citing new opportunities and growth as
their reasons for choice of location, the initial stages
of the set up were difficult but rewarding. They
intend to apply the model to establishing other
overseas locations to serve the energy industry’s
risk management requirements.
Their commitment to the Australian market,
however, continues to remain a priority. While giving
IRC staff opportunities to gain overseas work
experience, Morris recognises that returning to
Australia is just a fact of life for Australians.
“There is no beach in Houston,” he said. DoIR
(Image courtesy of Woodside)

Table 1. Reserves as at 31 December 2003 - Developed Fields
FIELD TENEMENT Oil 90% Oil 50% Cond. 90% Cond. 50% Gas 90% Gas 50%
GL GL GL GL Gm 3 Gm 3
Agincourt TL/1 0.131 0.154 0.001 0.001 0.006 0.007
Barrow Island L1H 3.580 5.800 0.000 0.000 0.000 0.000
Beharra Springs L11 0.000 0.000

Category 2: Expected Medium to Long Term Development
FIELD Oil 90% Oil 50% Cond. 90% Cond. 50% Gas 90% Gas 50%
GL GL GL GL Gm 3 Gm 3
Dockrell WA-5-L 0.000 0.000 1.200 2.500 8.880 17.160
Gaea WA-1-L 0.000 0.000 0.300 0.500 1.950 3.680
Goodwyn S/Pueblo WA-5-L 0.100 0.400 0.000 0.000 2.640 8.200
Keast WA-6-L 0.000 0.000 0.700 1.600 5.420 9.940
Lambert Deep WA-16-L 0.000 0.000 0.200 0.400 5.660 7.360
Saffron WA-1-P 0.000 0.000 0.000 0.000 0.460 0.570
Tidepole WA-5-L 0.400 1.500 1.000 2.500 6.230 14.720
Vincent WA-271-P 8.400 11.400 0.000 0.000 0.510 0.560
Total 8.900 13.300 3.400 7.500 31.750 62.190
Category 3: Not currently viable; Held under Retention Lease
FIELD Oil 90% Oil 50% Cond. 90% Cond. 50% Gas 90% Gas 50%
GL GL GL GL Gm3 Gm3 Brecknock WA-33-P 0.000 0.000 8.270 16.380 104.770 150.080
Brecknock South WA-33-P 0.000 0.000 9.500 13.800 79.010 112.410
Blencathra TP/6 0.390 0.640 0.000 0.000 0.020 0.030
Capella WA-28-P 0.000 0.000 0.800 2.100 5.920 15.830
Chrysaor/Dionysus WA-15-R 0.000 0.000 5.405 6.287 94.860 112.940
Dixon/W.Dixon WA-9-R 2.900 4.100 0.900 1.300 3.140 4.350
Egret WA-10-R 0.700 1.800 0.000 0.000 0.140 0.390
Flinders Shoal TR/1 0.060 0.290 0.000 0.000 0.430 0.740
Geryon WA-267-P 0.000 0.000 10.720 13.800 73.000 94.000
Gorgon WA-2-R 0.000 0.000 17.011 20.986 436.500 520.430
Iago WA-25-P 0.000 0.000 1.208 2.512 17.518 27.667
Io/Eurythion WA-267-P 0.000 0.000 3.150 4.920 105.160 164.860
Io South WA-267-P 0.000 0.000 0.660 0.990 21.890 33.900
Jansz WA-18-R 0.000 0.000 4.680 13.170 156.309 439.479
Macedon WA-12-R 0.000 0.000 0.000 0.000 10.000 18.000
Orthrus/Meanad WA-267-P 0.000 0.000 2.210 4.960 15.000 33.950
Petrel WA-6-R 0.000 0.000 0.000 0.000 0.000 0.000
Prometheus/Rubicon WA-278-P 0.000 0.000 0.000 0.000 6.909 10.449
Pyrenees WA-12-R 0.100 0.600 0.000 0.000 0.200 1.100
Rankin/Sculptor WA-11-R 0.000 0.000 0.200 2.200 0.850 11.040
Scarborough WA-1-R 0.000 0.000 0.000 0.000 133.000 170.000
Scott Reef WA-33-P 0.000 0.000 10.020 19.240 172.730 325.640
Spar WA-4-R 0.000 0.000 0.588 1.844 1.690 9.910
Tern WA-18-P 0.000 0.000 0.355 0.899 9.910 11.761
Turtle WA-13-R 0.830 1.230 0.000 0.000 0.000 0.000
Urania WA-267-P 0.000 0.000 1.006 1.240 6.136 7.544
West Tryal Rocks WA-5-R 0.000 0.000 8.426 11.447 68.800 99.476
Wilcox WA-7-R 0.000 0.000 2.400 3.200 7.000 9.690
Total 4.980 8.660 87.509 141.275 1530.892 2385.666
Grand Total 84.010 136.032 181.172 280.403 2239.551 3344.934
PWA April Edition - Reserves Tables 40
Table 3. Unbooked Resources as at 31 December 2003
Field Oil in place Cond in place Gas in place
GL GL Gm 3
Baker TL/1 1.860 0.000 0.000
Cadell TP/7 0.000 0.030 1.440
Chamois WA-265-P 0.650 0.000 0.000
Crosby WA-12-R 19.200 0.000 0.100
Eaglehawk WA-28-P 0.160 0.000 0.000
Gwydion WA-239-P 0.950 0.000 0.000
Ishmael WA-1-L 0.000 0.620 2.260
Jingamia EP413 1.110 0.000 0.000
Josephine TL/1 0.000 0.000 0.060
Leatherback EP342 0.330 0.000 0.000
Maitland WA-149-P 0.000 0.000 5.000
Mardie EP137 0.000 0.000 17.710
Montague WA-10-R 0.000 0.400 2.790
Nimrod WA-155-P 0.000 0.000 0.765
Oryx WA-209-P 5.040 0.000 0.000
Outtrim WA-155-P 1.900 0.000 0.300
Point Torment EP104 0.000 0.000 0.250
Ravensworth WA-155-P 17.500 0.000 0.300
Scafell WA-155-P 0.000 0.000 7.079
Skiddaw WA-155-P 1.600 0.000 0.000
South Chervil TL/2 0.770 0.000 0.510
Stybarrow WA-255-P 17.800 0.000 0.000
Tusk WA-249-P 3.700 0.000 0.000
Ulidia TL/1 0.000 0.000 0.406
Whicher Range EP 408 0.000 0.000 45.000
Total 72.570 1.050 83.970
Table 4. Cumulative Production to 2003
Field Oil kL Gas km3 Condensate kL
Agincourt 505,504 25,273 3,816
Alkimos 4,923 157,757 24,770
Barrow Island 47,670,583 4,943,353 0
Beharra Springs 0 2,057,738 22,128
Beharra Springs N 0 106,414 1,106
Blina 288,459 0 0
Boundary 19,466 0 0
Buffalo 3,097,380 70,851 0
Campbell 3,887 2,366,777 293,718
Chervil 764,676 191,903 0
Chinook/Scindian 4,019,514 1,201,572 0
Cossack 9,591,640 300,192 0
Cowle 501,609 74,701 1,748
Crest 267,158 41,891 108
Dongara 185,799 12,503,366 47,997
Double Island 350,203 17,626 1,966
East Spar 0 5,789,385 1,984,785
Echo/Yodel 0 5,074,920 3,750,276
Endymion 0 231,426 34,965
Gibson 27,291 2,063 61

Gingin 0 48,545 3,169
Gipsy 315,750 66,375 2,307
Goodwyn 0 77,920,819 32,894,563
Griffin 20,144,294 1,682,015 0
Harriet 8,015,894 1,440,409 59,500
Hermes 4,547,960 311,502 0
Hoover 31,786 2,040 205
Hovea 272,603 16,636 0
Jingemia 29,189 1,039 0
Lambert 2,028,159 107,214 0
Laminaria East 1,333,902 17,214 69,697
Legendre North 3,766,933 733,005 0
Legendre South 662,456 153,218 0
Little Sandy 54,559 3,024 362
Lloyd 29,351 0 0
Mondarra 0 667,563 9,184
Mount Horner 284,130 0 0
North Gipsy 104,452 78,733 5,658
North Herald 653,189 77,521 0
North Pedirka 10,590 595 58
North Rankin 0 167,644,334 21,912,878
North Yardanogo 295 0 0
Pedirka 187,443 7,385 841
Perseus 0 35,476,687 7,008,881
Roller 6,592,628 632,748 0
Rosette 1,100 309,723 44,735
Rough Range 9,390 0 0
Saladin 14,835,099 1,565,741 0
Simpson 701,946 43,955 5,133
Sinbad 0 1,992,519 230,964
Skate 266,884 81,246 11,106
South Pepper 2,634,632 692,860 0
South Plato 410,218 20,810 552
Stag 5,134,986 270,557 0
Sundown 63,657 0 0
Talisman 1,229,512 12,897 0
Tanami 460,124 82,662 12,885
Tubridgi 0 1,938,808 951
Victoria 35,825 2,807 329
Walyering 0 7,377 237
Wanaea 24,335,720 5,172,696 0
Wandoo 9,630,694 658,807 0
West Kora 3,659 0 0
West Terrace 33,060 0 0
Wonnich 0 1,809,400 199,431
Woodada 0 1,374,281 10,001
Woollybutt 1,170,138 34,400 0
Yammaderry 849,601 94,525 0
Yardarino 1,567 143,390 771
Total 178,171,467 338,555,290 68,651,846
Table 5. Production by Field to 2003
Field Oil kL Gas km 3 Condensate kL
Agincourt 18,846 2,753 228
Barrow Island 525,710 59,569 0
Beharra Springs 0 40,965 379
PWA April Edition - Production Table 41
Beharra Springs N 0 67,323 623
Blina 1,953 0 0
Boundary 426 0 0
Buffalo 363,950 11,335 0
Campbell 3,887 138,012 18,937
Chinook/Scindian 452,889 246,870 0
Cossack 821,100 25,227 0
Cowle 8,556 649 0
Crest 4,373 6,265 0
Dongara 471 31,790 235
Double Island 350,203 17,626 1,966
East Spar 0 984,967 303,544
Echo/Yodel 0 2,436,480 1,758,320
Endymion 0 210,341 31,641
Gibson 464 553 22
Gipsy 25,138 3,246 3
Goodwyn 0 9,659,360 2,467,570
Griffin 579,575 44,151 0
Harriet 62,448 10,714 7
Hermes 807,950 51,387 0
Hoover 31,786 2,040 205
Hovea 244,710 15,060 0
Jingemia 29,189 1,039 0
Lambert 429,020 21,422 0
Laminaria East 107,686 2,289 19,164
Legendre North 1,566,265 288,088 0
Legendre South 31,716 34,358 0
Little Sandy 42,859 2,414 286
Lloyd 319 0 0
Mount Horner 4,506 0 0
North Pedirka 10,590 595 58
North Rankin 0 3,793,810 429,200
Pedirka 155,461 6,305 713
Perseus 0 7,367,670 1,507,790
Roller 168,157 25,032 0
Saladin 129,222 22,066 0
Simpson 109,324 16,201 1,846
Skate 0 1,521 2,233
South Plato 258,479 13,923 370
Stag 699,572 28,850 0
Sundown 347 0 0
Tanami 36,602 5,377 563
Tubridgi 0 80,590 0
Victoria 24,220 1,774 203
Wanaea 4,187,670 902,020 0
Wandoo 582,640 96,952 0
West Terrace 1,823 0 0
Wonnich 0 576,391 60,192
Woodada 0 43,884 193
Woollybutt 1,170,138 34,400 0
Yammaderry 4,698 1,169 0
Yardarino 0 833 0
Total 14,054,939 27,435,652 6,606,492

Table 6. Seismic Surveys in Western Australia 2003 Calendar Year
2D (line km) 3D (km2 )
Bonaparte Basin Onshore 0 0
Offshore 668 0
Browse Basin Onshore 0 0
Offshore 1044 510
Carnarvon Basin Onshore 0 0
Offshore 6191 3761
Perth Basin Onshore 6 0
Offshore 8991 551
Sub Total Onshore 6 0
Offshore 16914 4822
Total 116920 4822
Table 7. Petroleum Wells in Western Australia 2002/03 Fiscal Year
The below table lists the number of wells spudded and metres drilled (subsurface) during the 2003 calendar year. For wells spudded before 1.1.2003 only metres drilled during calendar year are included.
➢
The above table lists the quantity of
2D seismic (line km) and 3D seismic (sq km) acquired during the
calendar year. For survey that commenced before 1.1.2003 only
acquisition after this date is included.
Non-seismic surveys for the year include:
43214 km Aeromagnetic
2991 Gravity stations and
17 Magnetotelluric stations
The attached listing of surveys operating in the calendar year
includes all data gathered prior to 31.12.2003
PWA April Edition - Surveys and Wells 42
NFW EXT DEV Sub Total Total
Wells Metres Wells Metres Wells Metres Wells Metres Wells Metres
Bonaparte Basin Onshore 0 0 0 0 0 0 0 0 1 1709
Offshore 1 1709 0 0 0 0 1 1709
Browse Basin Onshore 0 0 0 0 0 0 0 0 5 20614
Offshore 4 15455 1 5159 0 0 5 20614
Canning Basin Onshore 0 0 0 0 0 0 0 0 0 0
Offshore 0 0 0 0 0 0 0 0
Carnarvon Basin Onshore 0 0 0 0 0 0 0 0 53 118644
Offshore 31 66139 (a) 14 31609 8 20896 53 118644
Perth Basin Onshore 3 7541 4 11741 (b) 6 (c) 12809 13 32091 18 39930
Offshore 3 4694 2 3145 0 0 5 7839
Sub Total Onshore 3 7541 4 11741 6 12809 13 32091 77 180897
Offshore 39 87997 17 39913 8 20896 64 148806
Total 42 95538 21 51654 14 33705 77 180897
(a) Includes Dawn 1 and Wigmore 1 spudded 2002. (b) Includes Hovea 4/ 4ST 1 Spudded 2002. (c) Includes Hovea 10 Water Injection Well.

KEY: Classification 2D: 2D Reflection, 3D: 3D Reflection, MT: Magnetotelluric
Table 8. Seismic Surveys in Western Australia Operating 2003 Calendar Year
PWA April Edition - Seismic Surveys 43
Survey Name Class On Off Title Operator Commenced Completed 2D Line km @ 3D Sq km @ Aeromag Line km MT/ Gravity
31/12/2003 31/12/2003 @ 31/12/2003 Stations
Bonaparte Basin
Seahorse 2D M.S.S. 2D Off WA-18-L, WA-21-L Woodside 6-May-03 18-May-03 668
Browse Basin
Floreana 2D M.S.S. 2D Off WA-306-P Magellan 24-Apr-03 6-May-03 532
Plazas 2D M.S.S. 2D Off WA-307-P Magellan 24-Apr-03 6-May-03 512
HBR03A M.S.S. 3D Off WA-303-P BHP Billiton 31-May-03 13-Jun-03 510
Canning Basin
SPA 2/02-3 MT On SPA 2/02-3 AO Kingsway 23-Aug-03 26-Aug-03 17
Carnarvon Basin
Champagne 2D M.S.S. 2D Off WA-268-P Chevron Texaco 27-Mar-03 22-Apr-03 2546
Chimaera 2D M.S.S. 2D Off WA-335-P Apache 19-May-03 1-Jun-03 1259
Klammer 2D M.S.S. 2D Off WA-320-P OMV 11-Mar-03 17-Mar-03 765
Munmorah 2D M.S.S. 2D Off WA-308-P, WA-309-P OMV 13-Apr-03 24-Apr-03 838
Posiedon 2D M.S.S. 2D Off WA-2-R R2 Chevron Texaco 18-Feb-03 20-Mar-03 58
Wheatstone 2D M.S.S. 2D Off WA-253-P R1 Chevron Texaco 20-Mar-03 27-Mar-03 725
Demeter 3D M.S.S. 3D Off WA-1-P R6, WA-17-L, Woodside 10-Apr-03 3114
WA-191-P R3, WA-208-P R2,
WA-248-P R1,
WA-28-P R6, WA-330-P
Viper 3D M.S.S. 3D Off WA-335-P Apache 15-Apr-03 27-Apr-03 647
Perth Basin
Fulfillment 2D M.S.S. 2D Off WA-336-P Petroz 17-Jan-03 8-Mar-03 2005
Jovian 2D M.S.S. 2D Off WA-337-P Kerr-McGee 21-Nov-03 1-Dec-03 1368
Lilian TP/15 2D M.S.S. 2D Off TP/15 Strike Oil 2-Nov-03 11-Nov-03 85
Lilian WA-286-P 2D M.S.S. 2D Off WA-286-P ROC Oil 2-Nov-03 11-Nov-03 644
Mary Ann 2D M.S.S. 2D Off WA-325-P ROC Oil 11-Nov-03 17-Nov-03 825
Moon Part 1 and 2 2D M.S.S. 2D Off WA-326-P AGIP 29-Nov-02 16-Feb-03 4794
Ramsgate 2D M.S.S. 2D Off WA-339-P Santos 2-Dec-03 18-Dec-03 1570
Wildwood S.S. 2D On SPA 1/01-2 Red Mt Energy 29-Sep-02 10-Mar-03 6
Cliff Head WA-286-P 3D M.S.S. 3D Off WA-286-P ROC Oil 23-Oct-03 1-Nov-03 30
Macallan 3D M.S.S. 3D Off WA-226-P R2 Apache 2-May-03 24-May-03 521
Perth Basin
East Abrolhos Aeromagnetic Survey AEROMAG Off WA-325-P ROC Oil 31-Aug-03 5-Oct-03 31338
Offshore Dongara Aeromagnetic Survey TP/15 AEROMAG Off TP/15 ROC Oil 31-Aug-03 18-Sep-03 4368
Offshore Dongara Aeromagnetic Survey WA-286-P AEROMAG Off WA-286-P ROC Oil 1-Sep-03 18-Sep-03 7508
Denison Gravity Survey GRAVITY On L 1 R1 Arc 26-Jul-03 1-Sep-03 2441
Denison Gravity Survey 413 GRAVITY On EP 413 R1 Origin 24-Aug-03 7-Sep-03 550

Table 9. Petroleum Wells in Western Australia Operating 2003 Calendar Year
PWA April Edition - Petroleum Wells 44
Well Name Class On / Off Tenament Operator Lattitude Longitude Gnd Elev RT KB Spud Date TD Date Rig Rel Depth @ Metres Status @
Date 30 June Drilled 30 June
2003 Subsurf 2003
Bonaparte Basin
Weasel 1 NFW OFF WA-279-P Woodside 14 13 21.48 128 28 44.54 38 29 9-Mar-03 16-Mar-03 20-Mar-03 1776 1709 P&A
Browse Basin
Ichthys 2/ 2A/ 2A ST1 EXT OFF WA-285-P INPEX Browse 13 54 0.60 123 9 28.18 268 25 29-Nov-03 4006 5159 DRILLING
Ichthys 1/ 1A NFW OFF WA-285-P INPEX Browse 13 56 45.30 123 11 29.11 274 25 19-Jun-03 5-Sep-03 7-Oct-03 4826 6664 P&A GS
Ichthys Deep 1 NFW OFF WA-285-P INPEX Browse 13 52 3.23 123 13 27.15 285 25 8-Oct-03 21-Nov-03 27-Nov-03 4956 4646 P&A GS
Maginnis 1/ 1A/ 1A
ST1/ 1A ST2 NFW OFF WA-302-P BHP Billiton 13 42 20.31 121 43 56.28 1304 26 24-Jan-03 31-Mar-03 4-Apr-03 4643 3497 P&A
Strumbo 1 NFW OFF WA-288-P Magellan 13 13 40.94 125 29 52.13 59 22 24-Jan-03 30-Jan-03 1-Feb-03 728 648 P&A
Carnarvon Basin
Gibson 2H/ 2H BHC1 DEV OFF TL/6 Apache 20 41 57.45 115 33 51.82 8 30 16-Feb-03 18-Feb-03 25-Feb-03 2543 1583 O
Gipsy 4 DEV OFF TL/1 Apache 20 38 6.97 115 43 43.49 30 33 20-Oct-03 24-Oct-03 9-Nov-03 3911 3848 O
Hoover 2 DEV OFF TL/6 Apache 20 44 22.43 115 34 18.23 7 32 11-Aug-03 23-Aug-03 29-Aug-03 3604 3565 O
Legendre North 4H/
4H ST1/ 4H ST2 DEV OFF WA-20-L Woodside 19 42 14.20 116 42 31.45 52 44 5-May-03 2-Jun-03 5-Jun-03 3112 3802 O
Simpson 7 DEV OFF TL/1 Apache 20 40 20.03 115 35 7.94 8 28 28-Feb-03 8-Mar-03 17-Mar-03 2064 2029 O
South Plato 3/ 3H DEV OFF TL/6 Apache 20 41 57.62 115 33 51.96 8 30 31-Jan-03 4-Feb-03 25-Feb-03 2356 2962 O
Stag 25H DEV OFF WA-15-L Apache 20 17 23.91 116 16 31.06 49 53 26-Jun-03 28-Jun-03 1-Jul-03 1285 905 O
West Simpson 1 DEV OFF TL/1 Apache 20 40 24.69 115 35 7.90 8 28 27-Feb-03 11-Mar-03 17-Mar-03 2237 2202 O
Campbell 6 EXT OFF TL/5 Apache 20 24 50.85 115 43 49.08 40 41 3-Sep-03 10-Sep-03 15-Sep-03 3232 3152 P&A GS
Campbell 7 EXT OFF TL/5 Apache 20 24 50.85 115 43 49.08 40 41 11-Sep-03 13-Sep-03 15-Sep-03 2385 1080 P&A GS
East Spar 6/ 6 ST1 EXT OFF WA-13-L Apache 20 43 49.35 114 59 23.94 95 26 29-Jul-03 6-Sep-03 19-Sep-03 3150 3762 G
Egret 3 EXT OFF WA-10-R R1 Woodside 19 29 54.00 116 21 27.65 119 26 27-Mar-03 20-May-03 29-May-03 4881 4736 P&A OGS
Gipsy 3 EXT OFF TL/1 Apache 20 39 4.04 115 43 19.05 28 32 3-Aug-03 9-Aug-03 14-Aug-03 2483 2423 P&A OGS
Jansz 3 EXT OFF WA-18-R Mobil Australia 19 49 12.66 114 34 39.03 1340 25 4-Jun-03 16-Jun-03 10-Jul-03 2966 1601 P&A G
Simpson 6 EXT OFF TL/1 Apache 20 40 24.14 115 35 5.61 8 29 4-Dec-03 5-Dec-03 10-Dec-03 2681 1328 O
Simpson 8/ 8 BHC1 EXT OFF TL/1 Apache 20 40 24.14 115 35 5.61 8 28 29-Nov-03 1-Dec-03 10-Dec-03 2080 964 P&A OS
Skiddaw 2 EXT OFF WA-255-P R1 BHP Billiton 21 28 49.62 113 52 18.85 769 22 21-May-03 26-May-03 4-Jun-03 2248 1457 P&A OGS
South Simpson 2 EXT OFF TL/1 Apache 20 40 24.44 115 35 5.79 9 29 16-Nov-03 18-Nov-03 10-Dec-03 3231 1710 O
Stybarrow 2 EXT OFF WA-255-P R1 BHP Billiton 21 29 33.03 113 51 19.99 873 22 6-Jun-03 16-Jun-03 23-Jun-03 2380 1485 P&A OS
Tanami 7 EXT OFF TL/1 Apache 20 40 24.14 115 35 5.61 8 29 3-Dec-03 4-Dec-03 10-Dec-03 2739 2702 P&A
Taunton 3/ 3 L1 EXT OFF TL/2 Apache 21 19 8.17 115 6 51.02 15 32 16-Aug-03 20-Aug-03 24-Aug-03 1433 2320 P&A OS
Thomas Bright 2 EXT OFF WA-214-P R2 Apache 20 27 14.66 115 4 11.62 82 32 12-Dec-03 19-Dec-03 26-Dec-03 3003 2889 P&A GS
Ajax 1/ 1 ST1 NFW OFF WA-1-P R6 Woodside 19 37 -0.19 116 41 58.85 55 32 28-Dec-03 684 561 DRILLING
Bandera 1 NFW OFF WA-256-P R1 Apache 20 21 59.33 115 50 4.05 47 32 8-Jan-03 11-Jan-03 13-Jan-03 2187 2108 P&A
Banjo 1 NFW OFF EP 397 Tap Oil 21 3 35.71 115 33 55.71 12 35 30-Mar-03 2-Apr-03 9-Apr-03 971 923 P&A
Bob 1 NFW OFF EP 363 R2 Apache 20 43 3.65 115 40 35.12 24 32 14-Jan-03 25-Jan-03 29-Jan-03 3140 3085 P&A GS
Carteret 1 NFW OFF WA-4-L R1 Woodside 19 20 1.04 116 32 56.07 145 26 26-Jun-03 6-Jul-03 13-Jul-03 3515 3344 P&A
Cerberus 1 NFW OFF WA-202-P R2 Apache 19 47 54.42 116 45 50.59 73 33 25-Sep-03 30-Sep-03 3-Oct-03 2182 2076 P&A
Chiru 1 NFW OFF WA-209-P R2 Apache 20 10 6.11 116 17 32.50 56 32 23-Jul-03 31-Jul-03 2-Aug-03 1779 1691 P&A
Crackling South 1 NFW OFF EP 341 R2 Tap Oil 21 12 25.92 115 33 7.76 14 32 27-Mar-03 28-Mar-03 30-Mar-03 503 457 P&A OGS
Crosby 1 NFW OFF WA-12-R BHP Billiton 21 31 46.95 114 6 8.23 197 26 3-Oct-03 6-Oct-03 10-Oct-03 1226 1003 P&A OS
Cyrano 1 NFW OFF EP 364 R1 Tap Oil 21 12 34.15 115 17 9.43 16 31 21-Mar-03 23-Mar-03 25-Mar-03 769 722 P&A OGS
Dawn 1 NFW OFF TL/1 Apache 20 31 15.61 115 43 22.77 39 31 20-Dec-02 1-Jan-03 7-Jan-03 2711 2641 P&A GS
Eskdale 1 NFW OFF WA-255-P R1 BHP Billiton 21 21 49.01 113 49 36.57 798 22 14-Mar-03 30-Mar-03 13-Apr-03 3127 2307 P&A OS

PWA April Edition - Petroleum Wells 45
Felicia 1 NFW OFF TL/1 Apache 20 43 1.36 115 35 26.00 8 26 4-Aug-03 7-Aug-03 10-Aug-03 1877 1843 P&A
Ginger 1/ 1 CH1 NFW OFF TL/1 Apache 20 40 17.73 115 39 7.80 26 32 20-Jul-03 26-Jul-03 3-Aug-03 2497 2564 P&A GS
Carnarvon Basin
Guilford 1 NFW OFF WA-269-P Woodside 19 39 11.07 115 15 21.47 1032 22 17-Apr-03 27-Apr-03 5-May-03 4272 3218 P&A
Herdsman 1 NFW OFF WA-299-P Shell 22 52 15.67 113 17 30.49 553 22 29-Jan-03 3-Feb-03 8-Feb-03 2010 1435 P&A
Hyssop 1 NFW OFF TP/7 R2 Santos 21 13 58.98 115 26 30.41 12 32 25-Aug-03 27-Aug-03 28-Aug-03 756 712 P&A
Karangi 1 NFW OFF TP/8 R2 Apache 20 39 17.35 115 25 38.61 11 32 16-Sep-03 21-Sep-03 24-Sep-03 2463 2420 P&A
Kilauea 1 NFW OFF WA-257-P Apache 20 14 5.74 115 57 22.50 53 32 3-Jul-03 14-Jul-03 18-Jul-03 3426 3341 P&A GS
Montgomery 1 NFW OFF WA-149-P R3 Apache 20 31 17.62 115 15 7.19 58 32 1-Apr-03 16-Apr-03 24-Apr-03 2965 2875 P&A GS
Mosman 1 NFW OFF TL/2 Apache 21 7 29.37 115 14 37.88 19 32 29-Aug-03 9-Mar-03 13-Sep-03 2705 2654 P&A OS
Nickol 1 NFW OFF WA-1-P R6 Woodside 19 53 47.98 116 27 19.87 67 30 7-Jun-03 12-Jun-03 17-Jun-03 2690 2592 P&A OS
North Pedirka 1 NFW OFF TL/6 Apache 20 44 22.16 115 34 18.26 7 32 13-Aug-03 17-Aug-03 1-Sep-03 2927 2888 O
Ravensworth 1/ 1CH NFW OFF WA-155-P R3 BHP Billiton 21 31 39.10 114 5 1.79 205 26 15-Jul-03 20-Jul-03 27-Jul-03 1432 1345 P&A OGS
Skiddaw 1 NFW OFF WA-255-P R1 BHP Billiton 21 28 49.62 113 52 18.85 769 22 8-May-03 14-May-03 4-Jun-03 2192 1401 P&A OS
Stybarrow 1/ 1 CH1 NFW OFF WA-255-P R1 BHP Billiton 21 28 40.15 113 50 3.55 825 22 12-Feb-03 20-Feb-03 11-Mar-03 2477 1861 P&A OS
Thomas Bright 1 NFW OFF WA-214-P R2 Apache 20 27 2.96 115 5 57.81 75 32 21-Mar-03 27-Mar-03 31-Mar-03 3044 2937 P&A GS
Tigger 1 NFW OFF WA-248-P R1 Woodside 19 20 55.15 116 23 54.24 142 26 30-May-03 21-Jun-03 29-Jun-03 3650 3482 P&A
Toobada 1 NFW OFF WA-192-P R3 Tap Oil 20 21 14.07 115 24 58.49 35 32 19-Sep-03 26-Sep-03 1-Oct-03 3120 3053 P&A OS
Twickenham 1 NFW OFF TL/9 Apache 20 45 21.33 115 30 17.77 8 26 3-Oct-03 10-Oct-03 12-Oct-03 3410 3376 P&A
Van Gogh 1/ 1 ST1 NFW OFF WA-155-P R3 BHP Billiton 21 23 22.68 114 4 57.12 357 26 20-Sep-03 28-Sep-03 2-Oct-03 1526 1384 P&A OS
Whitetail 1 NFW OFF WA-296-P Woodside 17 39 7.85 118 15 5.98 953 22 1-Jan-03 8-Jan-03 13-Jan-03 2504 1529 P&A
Wigmore 1 NFW OFF WA-295-P Kerr-McGee 18 17 9.71 117 7 45.78 1247 27 28-Nov-02 11-Jan-03 23-Jan-03 5395 4121 P&A
Perth Basin
Cliff Head 3/ 3 CH1 EXT OFF WA-286-P ROC Oil 29 26 11.56 114 51 50.46 25 18 6-Jan-03 12-Jan-03 1-Feb-03 1408 1599 P&A O
Cliff Head 4 EXT OFF WA-286-P ROC Oil 29 26 45.81 114 52 2.48 21 31 3-Mar-03 10-Mar-03 15-Mar-03 1598 1546 P&A OS
Mentelle 1 NFW OFF WA-286-P ROC Oil 29 26 9.31 114 53 21.02 19 32 11-Feb-03 14-Feb-03 18-Feb-03 1509 1459 P&A
Twin Lions 1 NFW OFF TP/15 AWE 29 22 10.45 114 53 11.38 14 31 1-Feb-03 7-Feb-03 10-Feb-03 1570 1525 P&A
Vindara 1 NFW OFF WA-286-P ROC Oil 29 29 57.40 114 56 3.50 12 32 19-Feb-03 24-Feb-03 28-Feb-03 1755 1710 P&A
Eremia 2/ 2H/ 2H ST1 DEV ON L 1 R1 Arc 29 18 36.39 115 1 38.14 31 39 20-Nov-03 2-Dec-03 2497 5607 DRILLING
Hovea 5 DEV ON L 1 R1 Arc 29 19 8.77 115 2 30.00 59 67 30-Jan-03 6-Feb-03 24-Feb-03 2105 2097 P&A OS
Hovea 6 DEV ON L 1 R1 Arc 29 19 8.77 115 2 30.00 59 67 9-Feb-03 14-Feb-03 24-Feb-03 2126 970 P&A OS
Hovea 7 DEV ON L 1 R1 Arc 29 19 8.77 115 2 30.00 59 67 16-Feb-03 21-Feb-03 24-Feb-03 2245 562 O
Hovea 8 DEV ON L 1 R1 Arc 29 19 5.78 115 2 41.23 60 68 20-Jul-03 10-Aug-03 14-Aug-03 2352 2344 O
Hovea 4/ 4 ST1 EXT ON L 1 R1 Arc 29 19 8.33 115 2 28.20 59 67 20-Nov-02 8-Dec-02 13-Jan-03 2530 3307 O
Hovea 9/ 9 ST1 EXT ON L 1 R1 Arc 29 19 41.56 115 2 39.00 55 63 9-Oct-03 26-Oct-03 12-Nov-03 2102 2750 P&A OS
Jingemia 2 EXT ON EP 413 R1 Origin 29 20 21.48 114 59 23.71 6 14 24-Aug-03 9-Sep-03 29-Sep-03 2781 2773 P&A OS
Jingemia 3 EXT ON EP 413 R1 Origin 29 20 21.48 114 59 23.71 6 14 19-Sep-03 21-Sep-03 29-Sep-03 2625 1885 SUSP OS
Whicher Range 5/ 5 ST1EXT ON EP 408 R1 Amity 33 50 54.35 115 21 36.83 125 134 11-Oct-03 4060 4221 DRILLING
Eclipse 1 NFW ON EP 389 R1 Empire 31 25 53.53 115 52 41.73 70 78 18-Apr-03 10-May-03 13-May-03 3660 3652 P&A OGS
Eremia 1 NFW ON L 1 R1 Arc 29 18 32.35 115 1 5.10 27 35 6-Mar-03 27-Mar-03 31-Mar-03 2550 2542 O
Leafcutter 1 NFW ON L 4 Hardman 29 51 8.43 115 3 15.25 20 5 1-Sep-03 17-Sep-03 20-Sep-03 1332 1347 P&A
Hovea 10 WIW ON L 1 R1 Arc 29 19 41.56 115 2 39.00 55 63 28-Oct-03 2-Nov-03 12-Nov-03 2233 1229 SERVICE
STATUS
Drilling Drilling
G&C Producing Gas & Condensate Well
O Producing Oil Well
O&G Producing Oil & Gas Well
P&A Plugged & Abandoned Dry Nonproducing, No Shows
P&A G Plugged & Abandoned Gas Producer
P&A GC Plugged & Abandoned Gas & Condensate Producer
P&A GS Plugged & Abandoned Dry/Non Producing Gas Shows
P&A O Plugged & Abandoned Oil Producer
P&A OGS Plugged & Abandoned Dry/Non Producing Oil & Gas Shows
P&A OS Plugged & Abandoned Dry/Non Producing Oil Shows
P&S Plugged & Suspended
Service Service Well
SUSP Shut In/Suspended nonproducing Well, No Shows
SUSP G Shut In/Suspended Gas Well
SUSP O Shut In/Suspended Oil Well

Table 10. Western Australia list of Petroleum Titles and Holders as at 15 April 2004.
(Issued for Guidance and information purposes only, The legal status of the Petroleum tenements listed may be verified by conducting a search of the register at the Petroleum Division)
STATUS KEY
ACT Active
SPEN Surrender Pending
EREN Renewed extension
SUBS Subsisting
Title Status Map ReferExpiry Registered Holders (* denotes Nominee)
PETROLEUM (SUBMERGED LANDS) ACT, 1967 - Exploration Permit
WA-1-P R6 Active K 11 16 Nov 2007 Apache Northwest Pty Ltd
K 12 Santos Limited
* Woodside Energy Ltd
WA-18-P R5 Pending Renewal W 5 01 Jun 2004 Bonaparte Gas & Oil Pty Limited
Santos Offshore Pty Ltd
* Santos Limited
WA-28-P R6 Active J 11 13 Feb 2007 BHP Billiton Petroleum (North West Shelf) Pty Ltd
K 11 BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-149-P R3 Active J 12 09 May 2005 Pan Pacific Petroleum (South Aust) Pty Ltd
Santos (Bol) Pty Ltd
Tap (Shelfal) Pty Ltd
* Apache Oil Australia Pty Ltd
WA-155-P R4 Active H 13 23 Feb 2009 Apache Northwest Pty Ltd
Inpex Alpha Ltd
* BHP Billiton Petroleum (Australia) Pty Ltd
WA-191-P R3 Pending Renewal K 11 01 Jun 2004 Kufpec Australia Pty Ltd
L 11 Nippon Oil Exploration (Dampier) Pty Ltd
Woodside Energy Ltd
* Santos Limited
WA-192-P R3 Pending Renewal J 12 08 Jul 2004 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Apache Northwest Pty Ltd
Kufpec Australia Pty Ltd
* Tap (Harriet) Pty Ltd
WA-202-P R2 Active K 11 03 Aug 2004 AWE Petroleum Pty Ltd
K 12 Wandoo Petroleum Pty Ltd
* Apache Northwest Pty Ltd
WA-205-P R2 Active H 12 03 Dec 2005 Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-208-P R2 Active K 11 03 Jun 2007 Eni Australia Limited
Mosaic Oil NL
STATUS KEY
EXTN Extended
SUS Suspended Conditions
RPEN Renewal Pending
* Operator
PWA April Edition - Titles and Holders 46
Santos Offshore Pty Ltd
* Woodside Energy Ltd
WA-209-P R2 Active J 12 09 Nov 2005 Globex Far East Pty Ltd
K 11 Santos Offshore Pty Ltd
K 12 * Apache Northwest Pty Ltd
WA-214-P R2 Active H 12 06 Mar 2008 Santos (Bol) Pty Ltd
J 12 * Apache Northwest Pty Ltd
WA-226-P R2 Active F 19 05 Mar 2008 Apache Northwest Pty Ltd
G 19 Dana Petroleum (E&P) Limited
Dana Petroleum (WA) LLC
Norwest Energy NL
Planet Resources Limited
Voyager (PB) Limited
* Origin Energy Developments Pty Limited
WA-242-P R1 Pending Surrender Q 7 14 Nov 2004 Santos (Bol) Pty Ltd
R 7 * Woodside Energy Ltd
S 7
WA-246-P R1 Active K 12 23 Oct 2005 Globex Far East Pty Ltd
Kufpec Australia Pty Ltd
Pan Pacific Petroleum (South Aust) Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
WA-248-P R1 Suspension with extn K 10 11 Dec 2005 Japan Australia LNG (MIMI) Pty Ltd
K 11 Kufpec Australia Pty Ltd
* Woodside Energy Ltd
WA-253-P R1 Active H 11 21 Feb 2007 Texaco Australia Pty Ltd
H 12 * ChevronTexaco Australia Pty Ltd
J 11
WA-254-P R1 Active K 11 02 May 2006 First Australian Resources Limited
K 12 Pan Pacific Petroleum NL
Sun Resources NL
Victoria Petroleum NL
Woodside Energy Ltd
* Apache Northwest Pty Ltd
WA-255-P R1 Active G 12 01 Aug 2005 Woodside Energy Ltd
G 13 * BHP Billiton Petroleum (Australia) Pty Ltd
H 13
WA-256-P R1 Active J 12 15 Oct 2007 Wandoo Petroleum Pty Ltd
* Apache Northwest Pty Ltd
WA-257-P R1 Active J 12 18 Jan 2009 Kufpec Australia Pty Ltd
Sun Resources NL

Wandoo Petroleum Pty Ltd
* Apache Northwest Pty Ltd
WA-261-P R1 Active K 12 11 Jul 2007 Arrow Energy NL
Strike Oil NL
Sun Resources NL
Victoria Petroleum NL
* Apache Northwest Pty Ltd
WA-264-P R1 Suspension with extn H 13 03 Feb 2009 Kufpec Australia Pty Ltd
* Santos Offshore Pty Ltd
WA-268-P Extended G 10 04 Dec 2004 Texaco Australia Pty Ltd
G 11
G 12
H 10
H 11
H 12
WA-269-P Pending Renewal H 10 04 Sep 2003 Japan Australia LNG (MIMI) Pty Ltd
H 11 * Woodside Energy Ltd
J 10
J 11
K 10
K 11
WA-271-P R1 Active G 13 24 Nov 2008 Mitsui E&P Australia Pty Limited
H 13 * Woodside Energy Ltd
WA-274-P Active R 5 18 Feb 2005 * Coveyork Pty Limited
S 5
WA-275-P Pending Renewal Q 6 18 Aug 2004 BHP Billiton Petroleum (North West Shelf) Pty Ltd
Q 7 BP Petroleum Developments (NWS) Pty Ltd
ChevronTexaco Australia Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-278-P Pending Surrender V 4 18 May 2007 Encana Corporation
Kerr-McGee NW Shelf Australia Energy Pty Ltd
SK Corporation
Tap Oil Limited
WA-279-P Pending Renewal X 5 18 Aug 2004 Eni Australia B.V.
X 6 * Woodside Energy Ltd
WA-280-P Active 6 18 Aug 2004 Eni Australia B.V.
W 6
X 6
WA-281-P Active R 5 18 Feb 2005 Beach Petroleum Limited
R 6 Oil Search (Australia) Pty Ltd
* Santos Offshore Pty Ltd
WA-285-P Pending Renewal S 5 18 Aug 2004 Inpex Browse Ltd
S 6
WA-286-P Active G 21 21 Apr 2005 AWE Oil (Western Australia) Pty Ltd
H 20 Cieco Exploration and Production (Australia) Pty Ltd
H 21 Voyager (PB) Limited
H 22 Wandoo Petroleum Pty Ltd
* Roc Oil (WA) Pty Limited
WA-287-P Pending Surrender T 4 21 Feb 2005 Magellan Petroleum (WA) Pty Ltd
T 5
U 4
U 5
WA-288-P Pending Surrender U 4 21 Feb 2005 Inpex Alpha Ltd
PWA April Edition - Titles and Holders 47
U 5 * Magellan Petroleum (WA) Pty Ltd
WA-290-P Suspension with extn H 12 25 Jul 2005 OMV Barrow Pty Ltd
WA-291-P Active L 11 03 Feb 2006 Tap (Shelfal) Pty Ltd
M 11 * Magellan Petroleum (WA) Pty Ltd
WA-293-P Active M 9 03 Aug 2005 Japan Australia LNG (MIMI) Pty Ltd
M 10 * Woodside Energy Ltd
M 11
N 9
N 10
N 11
WA-294-P Active K 9 16 Aug 2005 BHP Billiton Petroleum (North West Shelf) Pty Ltd
K 10 BP Exploration (Alpha) Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-296-P Active L 9 16 Feb 2006 BHP Billiton Petroleum (North West Shelf) Pty Ltd
L 10 BP Exploration (Alpha) Ltd
M 8 ChevronTexaco Australia Pty Ltd
M 9 Japan Australia LNG (MIMI) Pty Ltd
M 10 Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-297-P Active M 8 16 Aug 2005 BHP Billiton Petroleum (North West Shelf) Pty Ltd
M 9 BP Exploration (Alpha) Ltd
N 8 ChevronTexaco Australia Pty Ltd
N 9 Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-301-P Active P 5 24 Jul 2006 BHP Billiton Petroleum (North West Shelf) Pty Ltd
P 6 Kerr-McGee NW Shelf Australia Energy Pty Ltd
Q 5
Q 6
WA-302-P Active Q 5 24 Jul 2006 BHP Billiton Petroleum (North West Shelf) Pty Ltd
Q 6 Kerr-McGee Australia Exploration and Production Pty
Ltd
Kerr-McGee NW Shelf Australia Energy Pty Ltd
Texaco Copernicus Pty Ltd
WA-303-P Active P 6 24 Jul 2006 BHP Billiton Petroleum (North West Shelf) Pty Ltd
Kerr-McGee NW Shelf Australia Energy Pty Ltd
Texaco Barcoo Pty Ltd
WA-304-P Active P 6 24 Jul 2006 BHP Billiton Petroleum (North West Shelf) Pty Ltd
Q 6 Kerr-McGee NW Shelf Australia Energy Pty Ltd
WA-305-P Active P 6 24 Jul 2006 BHP Billiton Petroleum (North West Shelf) Pty Ltd
P 7 Kerr-McGee NW Shelf Australia Energy Pty Ltd
Texaco Barcoo Pty Ltd
WA-306-P Active P 7 24 Jul 2006 Magellan Petroleum (WA) Pty Ltd
* Antrim Energy Australia Pty Limited
WA-307-P Active P 8 22 Aug 2006 Magellan Petroleum (WA) Pty Ltd
* Antrim Energy Australia Pty Limited
WA-308-P Pending Surrender H 12 11 Jun 2007 OMV Petroleum Pty Ltd
J 12 * OMV Timor Sea Pty Ltd
WA-309-P Pending Surrender J 12 11 Jun 2007 OMV Petroleum Pty Ltd
J 13 * OMV Timor Sea Pty Ltd
WA-310-P Active K 11 20 Aug 2007 * West Oil (Carnarvon) Pty Ltd

L 11
WA-311-P Active U 5 02 Sep 2007 Inpex Alpha Ltd
* Magellan Petroleum (WA) Pty Ltd
WA-312-P Active K 12 17 Sep 2007 Pancontinental Oil & Gas NL
L 12 Strike Oil NL
Sun Resources NL
* Victoria Petroleum (WA-209P) Pty Ltd
WA-313-P Active X 5 24 Sep 2007 Eni Australia B.V.
* Woodside Energy Ltd
WA-314-P Suspension with extn Q 5 11 Nov 2008 Liberty Petroleum Corporation
R 5
WA-315-P Suspension with extn Q 5 11 Nov 2008 Liberty Petroleum Corporation
R 5
WA-316-P Active U 2 05 Dec 2007 Ashmore Oil Pty Ltd
U 3
WA-317-P Suspension with extn W 5 12 Dec 2008 Drillsearch Energy Limited
WA-318-P Suspension with extn W 5 12 Dec 2008 Drillsearch Energy Limited
X 5
WA-319-P Suspension with extn X 5 12 Dec 2008 Drillsearch Energy Limited
X 6
WA-320-P Active H 13 13 Mar 2008 OMV Petroleum Pty Ltd
OMV Timor Sea Pty Ltd
WA-321-P Active J 11 21 Mar 2008 Strata Resources N.L.
J 12 * Octanex N.L.
K 11
WA-322-P Suspension with extn H 12 21 Sep 2008 BHP Billiton Petroleum (North West Shelf) Pty Ltd
H 13
WA-323-P Active J 11 21 Mar 2008 Octanex N.L.
J 12 Strata Resources N.L.
WA-324-P Active W 4 04 Jul 2008 Bounty Oil & Gas NL
W 5
WA-325-P Active G 20 23 Jul 2008 Apache Northwest Pty Ltd
G 21 Bounty Oil & Gas NL
H 20 Voyager (PB) Limited
H 21 * Roc Oil (WA) Pty Limited
WA-326-P Active F 20 23 Jul 2008 Eni Australia B.V.
G 20
WA-327-P Active G 19 23 Jul 2008 Apache Northwest Pty Ltd
Bounty Oil & Gas NL
Voyager (PB) Limited
* Roc Oil (WA) Pty Limited
WA-328-P Active F 19 24 Jul 2008 Santos Offshore Pty Ltd
F 20 * Eni Australia B.V.
G 19
G 20
WA-329-P Active H 13 04 Sep 2008 "Rocky Mountain Minerals, Inc "
Strata Resources N.L.
* Octanex N.L.
WA-330-P Active J 11 04 Sep 2008 Strata Resources N.L.
J 12 * Octanex N.L.
WA-331-P Active T 5 04 Sep 2008 Eagle Bay Resources NL
T 6 Icon Energy Ltd
U 5 Rough Range Oil Pty Ltd
U 6 * Rawson Resources NL
PWA April Edition - Titles and Holders 48
WA-332-P Active S 5 30 Sep 2008 Alpha Oil & Natural Gas Pty Ltd
S 6 Goldsborough Energy Pty Ltd
T 5 Hawkestone Oil Pty Ltd
T 6 * Batavia Oil & Gas Pty Ltd
WA-333-P Active T 5 30 Sep 2008 Alpha Oil & Natural Gas Pty Ltd
T 6 Goldsborough Energy Pty Ltd
Hawkestone Oil Pty Ltd
* Batavia Oil & Gas Pty Ltd
WA-334-P Active J 12 16 Dec 2008 Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
WA-335-P Active G 12 16 Dec 2008 Apache Northwest Pty Ltd
G 13
H 12
WA-336-P Active E 18 17 Dec 2008 Petroz N.L.
E 19
F 18
F 19
WA-337-P Active F 20 14 Jan 2009 Kerr-McGee NW Shelf Australia Energy Pty Ltd
G 20
G 21
WA-338-P Active T 5 14 Jan 2009 SK Corporation
U 5 * Santos Offshore Pty Ltd
WA-339-P Active E 19 14 Jan 2009 Kerr-McGee NW Shelf Australia Energy Pty Ltd
F 19 * Santos Offshore Pty Ltd
G 19
WA-340-P Active K 12 05 Mar 2009 Pancontinental Oil & Gas NL
Sun Resources NL
Victoria Petroleum (WA-209P) Pty Ltd
* Strike Oil NL
WA-341-P Active S 5 28 May 2009 Alpha Oil & Natural Gas Pty Ltd
T 5 Batavia Oil & Gas Pty Ltd
Goldsborough Energy Pty Ltd
Hawkestone Oil Pty Ltd
WA-342-P Active T 5 28 May 2009 Alpha Oil & Natural Gas Pty Ltd
Batavia Oil & Gas Pty Ltd
Goldsborough Energy Pty Ltd
Hawkestone Oil Pty Ltd
WA-343-P Active S 5 10 Jun 2009 National Gas Australia Pty Ltd
WA-344-P Active S 5 10 Jun 2009 National Gas Australia Pty Ltd
WA-345-P Active H 13 10 Jul 2009 OMV Petroleum Pty Ltd
OMV Timor Sea Pty Ltd
WA-346-P Active G 11 15 Jul 2009 BHP Billiton Petroleum (North West Shelf) Pty Ltd
WA-347-P Active G 10 25 Sep 2009 Woodside Energy Ltd
H 10
WA-348-P Active G 10 25 Sep 2009 Woodside Energy Ltd
G 11
WA-349-P Active H 20 05 Jan 2010 Voyager (PB) Limited
* Roc Oil (WA) Pty Limited
WA-350-P Active J 11 22 Dec 2009 Woodside Energy Ltd
J 12
WA-351-P Active G 12 05 Jan 2010 BHP Billiton Petroleum (North West Shelf) Pty Ltd
G 13
WA-352-P Active K 11 08 Jun 2010 Drillsearch Energy Limited
L 11

PETROLEUM (SUBMERGED LANDS) ACT, 1967 - Pipeline Licence
WA-1-PL Extended 05 Jan 3002 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-2-PL Active 01 Feb 2093 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-3-PL Active 17 Nov 2093 Inpex Alpha Ltd
Mobil Exploration & Producing Australia Pty Ltd
* BHP Billiton Petroleum (Australia) Pty Ltd
WA-4-PL Active 16 Mar 2095 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-5-PL Active 18 Mar 2096 Apache East Spar Pty Limited
Apache Kersail Pty Limited
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
WA-6-PL Active 25 Aug 2097 Globex Far East Pty Ltd
Santos Offshore Pty Ltd
* Apache Northwest Pty Ltd
WA-7-PL Active 07 Jan 3001 Apache Northwest Pty Ltd
Santos Limited
Woodside Energy Ltd
WA-8-PL Active 26 Apr 3001 ConocoPhillips Pipeline Australia Pty Ltd
Eni Gas & Power LNG Australia B.V.
Inpex DLNGPL Pty Ltd
Petroz LNG Pty Ltd
Santos Timor Sea Pipeline Pty Ltd
TEPCO Darwin LNG Pty Ltd
Tokyo Gas Darwin LNG Pty Ltd
WA-9-PL Active 28 Oct 3001 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-10-PL Active 12 Dec 2102 BHP Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
PETROLEUM (SUBMERGED LANDS) ACT, 1967 - Production Licence
WA-1-L R1 Active K 11 29 Sep 2022 BHP Billiton Petroleum (North West Shelf) Pty Ltd
PWA April Edition - Titles and Holders 49
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-2-L R1 Active K 11 29 Sep 2022 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-3-L R1 Active K 11 29 Sep 2022 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-4-L R1 Active K 11 29 Sep 2022 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-5-L R1 Active J 11 29 Sep 2022 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-6-L R1 Active J 11 29 Sep 2022 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-7-L Active J 12 03 Feb 2009 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-8-L Active K 11 16 Aug 2009 Kufpec Australia Pty Ltd
Tap (Shelfal) Pty Ltd
* Santos Limited
WA-9-L Active K 11 11 Apr 2012 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
Woodside Energy Ltd
WA-10-L Active H 13 18 Feb 2014 Inpex Alpha Ltd
Mobil Exploration & Producing Australia Pty Ltd
* BHP Billiton Petroleum (Australia) Pty Ltd
WA-11-L Active K 11 30 Sep 2014 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd

Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
Woodside Energy Ltd
WA-12-L Active H 13 13 Feb 2015 Mobil Australia Resources Company Pty Limited
* BHP Billiton Petroleum (Australia) Pty Ltd
WA-13-L Active H 12 18 Feb 2017 Apache East Spar Pty Limited
J 12 Apache Kersail Pty Limited
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
WA-14-L Active K 12 19 Mar 2017 Wandoo Petroleum Pty Ltd
* MOBIL (LEGENDRE) PTY LTD
WA-15-L Active K 12 25 Aug 2018 Globex Far East Pty Ltd
Santos Offshore Pty Ltd
* Apache Northwest Pty Ltd
WA-16-L Active K 11 11 Sep 2018 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-17-L Active K 11 14 Jan 2099 ConocoPhillips Australia Gas Holdings Pty Ltd
* Mobil Australia Resources Company Pty Limited
WA-18-L Active V 2 12 May 2099 BHP Billiton Petroleum (North West Shelf) Pty Ltd
WA-19-L Active V 2 05 Sep 2099 Nexen Petroleum Australia Pty Limited
WA-20-L Active K 11 15 Nov 2099 Apache Northwest Pty Ltd
Santos Limited
* Woodside Energy Ltd
WA-21-L Active V 2 25 Nov 2099 Nexen Petroleum Australia Pty Limited
WA-22-L Active H 12 28 Feb 3000 Mobil Australia Resources Company Pty Limited
Tap West Pty Ltd
* Eni Australia Limited
WA-23-L Active J 11 12 Sep 3001 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-24-L Active J 11 12 Sep 3001 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-25-L Active H 12 20 Jun 3002 Mobil Australia Resources Company Pty Limited
H 13 Tap West Pty Ltd
* Eni Australia Limited
WA-26-L Active K 11 23 Mar 2104 Kufpec Australia Pty Ltd
Nippon Oil Exploration (Dampier) Pty Ltd
Santos Limited
Woodside Energy Ltd
WA-27-L Active K 11 23 Mar 2104 Kufpec Australia Pty Ltd
Nippon Oil Exploration (Dampier) Pty Ltd
Santos Limited
Woodside Energy Ltd
PWA April Edition - Titles and Holders 50
WA-28-L Active G 13 28 Mar 2104 Mitsui E&P Australia Pty Limited
H 13 * Woodside Energy Ltd
PETROLEUM (SUBMERGED LANDS) ACT, 1967 - Retention Lease
WA-1-R R2 Pending Renewal G 11 03 Aug 2004 BHP Billiton Petroleum (North West Shelf) Pty Ltd
* Esso Australia Resources Pty Ltd
WA-2-R R2 Active H 12 28 May 2008 Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-3-R R2 Active H 12 28 May 2008 Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-4-R R2 Active H 12 28 May 2008 Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-5-R R2 Active J 12 28 May 2008 Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-6-R R1 Active X 4 31 Jan 2005 Bonaparte Gas & Oil Pty Limited
Origin Energy Bonaparte Pty Limited
Santos Offshore Pty Ltd
* Santos Limited
WA-7-R R1 Active J 11 05 Dec 2005 BHP Billiton Petroleum (North West Shelf) Pty Ltd
J 12 BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-9-R R1 Active J 11 05 Aug 2007 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-10-R R1 Active K 11 11 Jul 2007 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-12-R R1 Active H 13 05 Oct 2008 Apache Northwest Pty Ltd
* BHP Billiton Petroleum (Australia) Pty Ltd
WA-13-R Active X 6 18 Oct 2005 Basin Oil Pty Ltd
Frontier Bonaparte Pty Ltd
OMV Timor Sea Pty Ltd
* OMV Petroleum Pty Ltd
WA-14-R Active H 12 08 Nov 2005 Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd

WA-15-R Active H 11 19 Apr 2006 Texaco Australia Pty Ltd
H 12 * ChevronTexaco Australia Pty Ltd
WA-16-R Active J 11 22 Aug 2007 Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-17-R Active J 11 01 Oct 2007 Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-18-R Active H 11 29 Oct 2007 Texaco Australia Pty Ltd
* Mobil Exploration & Producing Australia Pty Ltd
WA-19-R Active H 12 17 Aug 2008 Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-20-R Active H 12 17 Aug 2008 Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-21-R Active J 11 17 Aug 2008 Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-22-R Active H 11 17 Aug 2008 BP Exploration (Alpha) Ltd
Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-23-R Active J 11 17 Aug 2008 BP Exploration (Alpha) Ltd
Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-24-R Active H 12 17 Aug 2008 BP Exploration (Alpha) Ltd
Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-25-R Active H 11 17 Aug 2008 BP Exploration (Alpha) Ltd
Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-26-R Active H 11 17 Aug 2008 BP Exploration (Alpha) Ltd
H 12 Mobil Australia Resources Company Pty Limited
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
WA-27-R Active X 5 28 Oct 2008 Bonaparte Gas & Oil Pty Limited
Santos Offshore Pty Ltd
* Santos Limited
WA-28-R Active Q 6 29 Dec 2008 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Petroleum Developments (NWS) Pty Ltd
ChevronTexaco Australia Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-29-R Active Q 6 29 Dec 2008 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Petroleum Developments (NWS) Pty Ltd
ChevronTexaco Australia Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
PWA April Edition - Titles and Holders 51
WA-30-R Active Q 5 29 Dec 2008 BHP Billiton Petroleum (North West Shelf) Pty Ltd
Q 6 BP Developments Australia Pty Ltd
R 5 ChevronTexaco Australia Pty Ltd
R 6 Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-31-R Active Q 6 29 Dec 2008 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-32-R Active Q 6 29 Dec 2008 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
WA-33-R Active J 12 04 Apr 2009 Pan Pacific Petroleum (South Aust) Pty Ltd
Santos (Bol) Pty Ltd
Tap (Shelfal) Pty Ltd
* Apache Oil Australia Pty Ltd
PETROLEUM (SUBMERGED LANDS) ACT, 1982 - Exploration Permit
TP/2 R2 Pending Renewal J 12 09 May 2003 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
TP/6 R2 Pending Renewal H 13 12 Oct 2003 * Apache Northwest Pty Ltd
TP/7 R2 Active ? 16 Apr 2005 Ampolex (PPL) Pty Ltd
J 12 Pan Pacific Petroleum (South Aust) Pty Ltd
J 13 Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
TP/8 R2 Active J 12 14 Nov 2004 Apache Harriet Pty Limited
J 13 Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TP/9 R2 Active H 13 09 Jul 2006 * Apache Northwest Pty Ltd
TP/15 Suspended Condition H 20 21 Apr 2005 AWE (Perth Basin) Pty Ltd
H 21 Arc Energy Limited
Hardman Oil And Gas Pty Ltd
Voyager (PB) Limited
Westranch Holdings Pty Ltd
* Roc Oil (WA) Pty Limited
TP/17 Extension Renewal J 12 25 Dec 2004 Strike Oil NL
K 12
TP/18 Active H 13 11 Oct 2007 Strike Oil NL
J 13 * Tap Oil Limited
TP/19 Active K 12 20 Mar 2008 Strike Oil NL
TP/20 Active J 12 02 Apr 2008 Tap (Shelfal) Pty Ltd
TP/21 Active K 12 02 Jan 2009 Eagle Bay Resources NL
Icon Energy Ltd
Rough Range Oil Pty Ltd
Victoria Petroleum (Middle East) Pty Ltd
* Rawson Resources NL

TP/22 Active 6 11 Jan 2010 Eni Australia B.V.
W 6
X 6
PETROLEUM (SUBMERGED LANDS) ACT, 1982 - Pipeline Licence
TPL/1 Active 29 Aug 2006 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TPL/2 Active 29 Aug 2006 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TPL/3 Active 09 Nov 2008 Ampolex (PPL) Pty Ltd
Pan Pacific Petroleum (South Aust) Pty Ltd
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
TPL/4 Active 09 Nov 2008 Ampolex (PPL) Pty Ltd
Pan Pacific Petroleum (South Aust) Pty Ltd
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
TPL/5 Active 09 May 2010 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TPL/6 Active 19 Jan 2010 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
TPL/7 R1 Active 09 Dec 2022 Ampolex (PPL) Pty Ltd
Pan Pacific Petroleum (South Aust) Pty Ltd
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
TPL/8 Active 25 Jul 2012 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TPL/9 Active 09 Feb 2009 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
TPL/10 Active 01 Nov 2014 Inpex Alpha Ltd
Mobil Exploration & Producing Australia Pty Ltd
PWA April Edition - Titles and Holders 52
* BHP Billiton Petroleum (Australia) Pty Ltd
TPL/11 Active 30 Dec 2014 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
TPL/12 Active 14 Mar 2017 Apache East Spar Pty Limited
Apache Kersail Pty Limited
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
TPL/13 Active 20 Sep 2019 Apache East Spar Pty Limited
Apache Harriet Pty Limited
Apache Kersail Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Apache Oil Australia Pty Ltd
Kufpec Australia Pty Ltd
Santos (Bol) Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TPL/14 Active 26 Nov 2019 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TPL/15 Active 05 Jan 2023 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
TPL/16 Active 17 Oct 2023 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
PETROLEUM (SUBMERGED LANDS) ACT, 1982 - Production Licence
TL/1 Active J 12 06 Nov 2006 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TL/2 Active J 13 25 Nov 2008 Ampolex (PPL) Pty Ltd
Pan Pacific Petroleum (South Aust) Pty Ltd
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
TL/3 Active J 12 03 Feb 2009 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd

* ChevronTexaco Australia Pty Ltd
TL/4 Active H 13 14 Nov 2010 Mobil Australia Resources Company Pty Limited
J 13 Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
TL/5 Active J 12 03 Nov 2012 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TL/6 Active J 12 03 Nov 2012 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TL/7 Active H 13 15 Dec 2014 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
TL/8 Active J 12 20 Sep 2019 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TL/9 Active J 12 28 Nov 2023 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
PETROLEUM (SUBMERGED LANDS) ACT, 1982 - Retention Lease
TR/1 Pending Renewal J 13 31 Jan 2004 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TR/2 Pending Renewal J 12 31 Jan 2004 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
TR/3 Active H 13 19 Nov 2006 Apache Northwest Pty Ltd
TR/4 Active J 13 28 Jul 2007 Mobil Australia Resources Company Pty Limited
PWA April Edition - Titles and Holders 53
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
TR/5 Active Q 5 29 Dec 2008 BHP Billiton Petroleum (North West Shelf) Pty Ltd
Q 6 BP Developments Australia Pty Ltd
R 6 ChevronTexaco Australia Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
PETROLEUM ACT, 1967 - Access Authority to Deviated Well
ADW 8/90-1 Active 23 Jun 2009 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
ADW 10/92-3 Active 08 May 2006 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
ADW 12/91-2 Active 19 Dec 2004 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
PETROLEUM ACT, 1967 - Exploration Permit
EP 23 R6 Active J 21 09 Jun 2007 Ausam Resources Limited
EP 41 R6 Active G 14 13 May 2008 Pace Petroleum Pty Ltd
H 14 Rough Range Oil Pty Ltd
* Lansvale Oil & Gas Pty Ltd
EP 61 R6 Active J 12 11 Dec 2007 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
EP 62 R6 Active J 12 28 Oct 2008 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
EP 104 R4 Active S 8 09 Nov 2004 First Australian Resources Limited
S 9 Indigo Oil Pty Ltd
Kimberley Oil NL
Pancontinental Oil & Gas NL
Pelsoil Limited
Voyager (PB) Limited
* Gulliver Productions Pty Ltd
EP 110 R4 Active H 13 23 Jan 2006 Carnarvon Petroleum NL
J 13 Euro Pacific Energy Pty Ltd
Hardman Oil And Gas Pty Ltd
Pan Pacific Petroleum (South Aust) Pty Ltd
"Radford, Roy Antony "
EP 129 R4 Active S 9 08 Jul 2006 * Terratek Drilling Tools Pty Limited
T 9

EP 137 R4 Active J 13 22 May 2005 JED North West Shelf Pty Ltd
* Tap (Shelfal) Pty Ltd
EP 307 R3 Active J 12 17 Sep 2005 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
EP 320 R3 Active J 21 23 Jul 2007 AWE (Perth Basin) Pty Ltd
J 22 * Origin Energy Developments Pty Limited
EP 321 R3 Active J 22 05 Apr 2009 Capital Consultant Services Pty Ltd
* Ausam Resources Limited
EP 325 R2 Extension Renewal H 13 03 Feb 2005 Sun Resources NL
H 14 * Victoria Petroleum NL
EP 341 R2 Active J 12 22 May 2005 Strike Oil NL
J 13 West Oil (Carnarvon) Pty Ltd
* Tap (Shelfal) Pty Ltd
EP 342 R2 Active H 13 19 Apr 2005 * Apache Northwest Pty Ltd
EP 357 R2 Active H 13 29 Apr 2007 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
EP 358 R1 Active J 12 14 Nov 2004 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
EP 359 R1 Pending Renewal G 14 06 Apr 2004 Pace Petroleum Pty Ltd
H 13 Rough Range Oil Pty Ltd
H 14 Sun Resources NL
* Lansvale Oil & Gas Pty Ltd
EP 363 R2 Active J 12 11 Aug 2007 Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
EP 364 R1 Active J 13 14 Nov 2004 Westranch Holdings Pty Ltd
* Tap (Shelfal) Pty Ltd
EP 368 R2 Active J 21 10 Feb 2008 Arc Energy Limited
Hardman Oil And Gas Pty Ltd
Origin Energy Developments Pty Limited
Voyager (PB) Limited
Westranch Holdings Pty Ltd
EP 369 R2 Active H 15 25 Mar 2009 Longreach Oil Limited
EP 371 R1 Active T 9 04 May 2005 Kimberley Oil NL
T 10
U 10
EP 374 R1 Suspension with extn S 13 16 Jul 2004 Nerdlihc Company Inc
T 13
T 14
EP 375 R1 Suspension with extn S 13 16 Jul 2004 Nerdlihc Company Inc
S 14
T 13
PWA April Edition - Titles and Holders 54
T 14
EP 376 R1 Suspension with extn T 14 16 Jul 2004 Nerdlihc Company Inc
T 15
U 14
U 15
EP 380 R1 Pending Renewal Q 15 13 Jan 2004 Jagen Nominees Pty Ltd
R 15 * Amadeus Petroleum NL
R 16
S 16
EP 381 R1 Pending Renewal J 25 10 Dec 2003 Geopetro Resources Company
J 26 * Southern Amity Inc.
EP 386 R1 Pending Renewal X 6 11 Jul 2004 Kimberley Energy Group Pty Ltd
X 7
EP 389 R1 Active J 23 24 Sep 2005 * Empire Oil Company (WA) Limited
K 23
EP 390 R1 Active R 10 28 Jun 2006 Kimberley Oil NL
R 11
S 10
S 11
EP 391 R1 Active R 9 28 Jun 2006 Kimberley Oil NL
R 10
S 9
S 10
EP 395 R1 Active J 12 11 Feb 2007 First Australian Resources Limited
Goodrich Petroleum Company
Sun Resources NL
Tap (Shelfal) Pty Ltd
* Apache Northwest Pty Ltd
EP 397 R1 Active J 12 27 Aug 2008 First Australian Resources Limited
J 13 Goodrich Petroleum Company
* Tap (Shelfal) Pty Ltd
EP 403 R1 Active J 12 10 Dec 2007 Tap (Shelfal) Pty Ltd
K 12
EP 405 R1 Active H 16 25 Mar 2009 Longreach Oil Limited
J 16
EP 406 Pending Renewal G 16 28 Nov 2002 Euro Pacific Energy Pty Ltd
G 17 * Victoria Diamond Exploration Pty Ltd
EP 407 R1 Active J 22 13 Apr 2009 Capital Consultant Services Pty Ltd
* Ausam Resources Limited
EP 408 R1 Active J 25 28 Jul 2008 Geopetro Resources Company
Korea National Oil Corp.
SCGAU Pty Limited
* Southern Amity Inc.
EP 409 R1 Active J 13 13 May 2009 OMV Barrow Pty Ltd
* Apache Oil Australia Pty Ltd
EP 410 R1 Active H 15 25 Mar 2009 Longreach Oil Limited
EP 411 Pending Surrender J 24 26 Aug 2004 * Empire Oil Company (WA) Limited
EP 412 Extension Renewal G 14 18 Jun 2004 Bounty Oil & Gas NL
G 15 * Rough Range Oil Pty Ltd
H 14
H 15
EP 413 R1 Active H 21 25 Aug 2004 Arc Energy Limited
J 21 "Geary, John Kevin "
Hardman Oil And Gas Pty Ltd

Norwest Energy NL
Roc Oil (WA) Pty Limited
Victoria Petroleum Offshore Pty Ltd
Voyager (PB) Limited
* Origin Energy Developments Pty Limited
EP 414 R1 Active J 22 25 Aug 2004 "Burns, Alan Robert "
Empire Oil Company (WA) Limited
Euro Pacific Energy Pty Ltd
"Geary, John Kevin "
"Hughes, Dan Allen "
"Hughes, Dudley Joe "
Springfield Oil and Gas Limited
* Ausam Resources Limited
EP 415 Active J 20 25 Aug 2005 * Empire Oil Company (WA) Limited
J 23
EP 416 Active J 24 25 Aug 2005 Empire Oil Company (WA) Limited
J 25
J 26
EP 417 Active V 11 21 Feb 2006 New Standard Exploration NL
V 12
W 11
W 12
EP 419 Active J 21 18 Oct 2006 Black Rock Resources Australia NL
Norwest Energy NL
EP 420 Active J 13 11 Oct 2007 Strike Oil NL
* Tap Oil Limited
EP 421 Active K 12 20 Mar 2008 Strike Oil NL
EP 422 Active P 11 21 Mar 2008 Ausoil Exploration Pty Ltd
P 12
Q 11
R 11
R 12
EP 423 Active K 12 02 Jan 2009 Eagle Bay Resources NL
Icon Energy Ltd
Rough Range Oil Pty Ltd
Victoria Petroleum (Middle East) Pty Ltd
* Rawson Resources NL
EP 424 Active J 13 13 Apr 2010 West Oil NL
EP 425 Active H 22 16 Jun 2010 Amity Oil NL
J 22
J 23
PETROLEUM ACT, 1967 - Production Licence
L 1 R1 Active J 21 17 May 2014 Origin Energy Developments Pty Limited
* Arc Energy Limited
L 2 R1 Active H 21 17 May 2014 Origin Energy Developments Pty Limited
J 21 * Arc Energy Limited
L 4 Pending Renewal J 21 24 Mar 2004 Bounty Oil & Gas NL
* Hardman Oil And Gas Pty Ltd
L 5 Active J 21 28 Dec 2004 Bounty Oil & Gas NL
* Hardman Oil And Gas Pty Ltd
L 6 Active T 9 22 Sep 2004 * Terratek Drilling Tools Pty Limited
L 7 Active J 21 13 May 2005 Arc Energy Limited
L 8 Active T 9 21 Oct 2005 * Terratek Drilling Tools Pty Limited
L 9 Active H 13 03 Jun 2008 Origin Energy Amadeus NL
PWA April Edition - Titles and Holders 55
Origin Energy Petroleum Pty Limited
Pan Pacific Petroleum NL
Tubridgi Petroleum Pty Ltd
* Sagasco South East Inc.
L 10 Active J 12 03 Feb 2009 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
L 11 Active J 21 14 May 2013 AWE (Perth Basin) Pty Ltd
* Origin Energy Developments Pty Limited
L 12 Active J 13 28 Jul 2023 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
L 13 Active H 13 28 Jul 2023 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
L 1H R1 Active J 12 09 Feb 2009 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
PETROLEUM ACT, 1967 - Retention Lease
R 1 Active S 9 28 Aug 2008 First Australian Resources Limited
Indigo Oil Pty Ltd
Kimberley Oil NL
Pancontinental Oil & Gas NL
Pelsoil Limited
Voyager (PB) Limited
* Gulliver Productions Pty Ltd
R 2 Active Q 6 29 Dec 2008 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
PETROLEUM PIPELINE ACT, 1969 - Pipeline Licence
PL 1 R1 Active 01 Dec 2012 CMS Gas Transmission of Australia
PL 2 R1 Active 01 Dec 2012 CMS Gas Transmission of Australia
PL 3 R1 Active 01 Dec 2012 CMS Gas Transmission of Australia
PL 5 R1 Active 01 Dec 2012 CMS Gas Transmission of Australia
PL 6 R2 Active 28 Dec 2004 Bounty Oil & Gas NL
* Hardman Oil And Gas Pty Ltd
PL 7 Pending Renewal 08 May 2004 Terratek Drilling Tools Pty Limited
PL 8 Pending Renewal 13 Oct 2004 Mitsui Iron Ore Development Pty Ltd
Nippon Steel Australia Pty Limited
Peko-Wallsend Operations Ltd
Sumitomo Metal Australia Pty Ltd
* Robe River Mining Co Pty Ltd
PL 12 Active 08 May 2006 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd

* Apache Northwest Pty Ltd
PL 14 Active 26 Nov 2008 Ampolex (PPL) Pty Ltd
Pan Pacific Petroleum (South Aust) Pty Ltd
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
PL 15 Active 23 Jun 2009 Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
PL 16 Active 17 Nov 2011 Origin Energy Amadeus NL
Origin Energy Petroleum Pty Limited
Pan Pacific Petroleum NL
Tubridgi Petroleum Pty Ltd
* Sagasco South East Inc.
PL 17 Active 25 Jul 2012 Apache Harriet Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Kufpec Australia Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
PL 18 Active 22 Apr 2013 AWE (Perth Basin) Ltd
* Origin Energy Developments Pty Limited
PL 19 Active 08 Jun 2014 Origin Energy Amadeus NL
Origin Energy Petroleum Pty Limited
Pan Pacific Petroleum NL
Tubridgi Petroleum Pty Ltd
* Sagasco South East Inc.
PL 20 Active 28 Sep 2014 Inpex Alpha Ltd
Mobil Exploration & Producing Australia Pty Ltd
* BHP Billiton Petroleum (Australia) Pty Ltd
PL 21 Active 23 Dec 2014 Chevron Asiatic Limited
Mobil Australia Resources Company Pty Limited
Santos Offshore Pty Ltd
Shell Development (Australia) Proprietary Limited
Texaco Australia Pty Ltd
* ChevronTexaco Australia Pty Ltd
PL 22 Active 06 Apr 2009 Epic Energy (Pilbara Pipeline) Pty Ltd
PL 23 Active 01 Dec 2012 CMS Gas Transmission of Australia
PL 24 Active 26 Jan 2016 Duke Energy WA Power Pty Ltd
Southern Cross Pipelines (NPL) Australia Pty Ltd
* Southern Cross Pipelines Australia Pty Limited
PL 25 Active 01 Apr 2017 Southern Cross Pipelines Australia Pty Limited
PL 26 Active 01 Apr 2017 Southern Cross Pipelines Australia Pty Limited
PL 27 Active 01 Apr 2017 Southern Cross Pipelines Australia Pty Limited
PL 28 Active 09 Apr 2017 Southern Cross Pipelines (NPL) Australia Pty Ltd
PL 29 Active 12 Sep 2016 Apache East Spar Pty Limited
Apache Kersail Pty Limited
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
PL 30 Active 14 Mar 2017 Apache East Spar Pty Limited
Apache Kersail Pty Limited
Santos (Bol) Pty Ltd
* Apache Oil Australia Pty Ltd
PWA April Edition - Titles and Holders 56
PL 31 Active 11 Sep 2017 Epic Energy (Pilbara Pipeline) Pty Ltd
PL 32 Active 26 Nov 2017 APT Pipelines (WA) Pty Limited
PL 33 Active 16 Mar 2018 APT Pipelines (WA) Pty Limited
PL 34 Active 06 Apr 2018 Newmont Yandal Operations Pty Ltd
PL 35 Active 13 May 2018 Plutonic Operations Limited
PL 36 Active 06 Jul 2018 Origin Energy Pipelines Pty Limited
PL 37 Active 23 Dec 2018 Centaur Nickel Pty Limited
PL 38 Active 05 Feb 2019 Epic Energy (Pilbara Pipeline) Pty Ltd
PL 39 Active 10 Mar 2019 Origin Energy Pipelines Pty Limited
PL 40 Active 24 Mar 2019 Epic Energy (WA) Nominees Pty Ltd
PL 41 Active 12 Aug 2019 Epic Energy (WA) Transmission Pty Ltd
PL 42 Active 13 Oct 2019 Apache East Spar Pty Limited
Apache Harriet Pty Limited
Apache Kersail Pty Limited
Apache Lowendal Pty Limited
Apache Miladin Pty Ltd
Apache Nasmah Pty Ltd
Apache Oil Australia Pty Ltd
Kufpec Australia Pty Ltd
Santos (Bol) Pty Ltd
Tap (Harriet) Pty Ltd
* Apache Northwest Pty Ltd
PL 43 Active 31 Jan 2020 Western Power Corporation
* APT Pipelines (WA) Pty Limited
PL 44 Active 02 Feb 2020 CMS Gas Transmission of Australia
PL 45 Active 16 Feb 2020 CMS Gas Transmission of Australia
PL 46 Active 21 Jun 2020 CMS Gas Transmission of Australia
PL 47 Active 24 Mar 2019 Epic Energy (WA) Transmission Pty Ltd
PL 48 Active 26 Oct 2020 Statewest Power Pty Ltd
PL 52 Active 21 May 2021 CMS Gas Transmission of Australia
PL 53 Active 22 May 2021 CMS Gas Transmission of Australia
PL 54 Active 08 Mar 2022 Western Power Corporation
* APT Pipelines (WA) Pty Limited
PL 55 Active 29 Jul 2022 Gwalia Tantalum Pty Ltd
PL 56 Active 29 Jul 2022 Epic Energy (WA) One Pty Ltd
PL 57 Active 14 Oct 2022 Australian Gold Reagents Pty Ltd
PL 58 Active 17 Oct 2023 BHP Billiton Petroleum (North West Shelf) Pty Ltd
BP Developments Australia Pty Ltd
ChevronTexaco Australia Pty Ltd
Japan Australia LNG (MIMI) Pty Ltd
Shell Development (Australia) Proprietary Limited
* Woodside Energy Ltd
PL 59 Active 23 Feb 2024 Esperance Pipeline Co. Pty Limited
PL 60 Active 16 Oct 2024 Gas Transmission Services WA (Operations) Pty Ltd
PL 61 Active 25 Nov 2024 CMS Gas Transmission of Australia

EXECUTIVE
Director General
Jim Limerick (08) 9327 5488
PETROLEUM AND ROYALTIES DIVISION
Telephone (08) 9222 3273
Facsimile (08) 9222 3515 / 3799
EXECUTIVE
Director
Bill Tinapple (08) 9222 3291
RESOURCES BRANCH
Manager Resources
Reza Malek (08) 9222 3759
Senior Production Geologist
Rod Dedman (08) 9222 3311
Senior Petroleum Technologist
Steve Walsh (08) 9222 3267
Reservoir Geologist
Lisa Gibbons (08) 9222 3284
Research Geologist
Darren Ferdinando (08) 9222 3445
Exploration Geologist
Richard Bruce (08) 9222 3314
POLICY, LEGISLATION & TITLES BRANCH
Manager Policy, Legislation and Titles
Bill Mason (08) 9222 3133
Petroleum Registrar
Stephen Hill (08) 9222 3140
Work Commitments Monitoring Officer
Stephen Collyer (08) 9222 3318
Legislation and Special Projects Officer
Colin Harvey (08) 9222 3315
SAFETY & ENVIRONMENT BRANCH
General Manager Safety and Environment
Richard Craddock (08) 9222 3254
Manager Petroleum Pipelines
Khalil Ihdayhid (08) 9222 3270
Manager Environment
Kim Anderson (08) 9222 3142
Manager Operations Safety
Zbigniew Lambert (08) 9222 3313
Acting Manager Risk Assessment
Brendon French (08) 9222 3488
ADMINISTRATION BRANCH
Manager Administration and IT
Mark Gabrielson (08) 9222 3010
GEOLOGICAL SURVEY DIVISION
Telephone (08) 9222 3222 / 3168
Facsimile (08) 9222 3633
EXECUTIVE
Executive Director
Tim Griffin (08) 9222 3160
General Manager Resources
Rick Rogerson (08) 9222 3170
STATUTORY EXPLORATION
INFORMATION GROUP
Manager Petroleum Data
Jeff Haworth (08) 9222 3214
PETROLEUM SYSTEMS STUDIES
Terraine Custodian - Basins
Roger Hocking (08) 9222 3590
Acting Manager
Arthur Mory (08) 9222 3327
INVESTMENT SERVICES
Telephone (08) 9327 5555
Facsimile (08) 9327 5500
EXECUTIVE
Deputy Director General
Noel Ashcroft (08) 9327 5469
INDUSTRIAL INFRASTRUCTURE COORDINATION DIVISION
Acting Director
Roger Dean (08) 9327 5506
INVESTMENT FACILITATION DIVISION
PWA April Edition - Key Contacts 57
Department of Industry and Resources
Key Contacts
Director
Ross Marshall (08) 9327 5410
Department of
Industry and Resources