Oil and Gas 2003 - Department of Mines and Petroleum - The ...

W E S T E R N A U S T R A L I A N
oil + gas industry
Department of
Industry and Resources

Western Australian Oil and Gas Industry 2003 has been
compiled in good faith by the Department of Industry and
Resources from information and data gathered in the course of
producing this document. The Department believes information
contained in this document is correct and that any opinions and
conclusions are reasonably held or made as at the time of
compilation. However, the Department does not warrant their
accuracy and undertakes no responsibility to any person or
organisation in respect of this publication.
ISSN 1443-9352

Contents
Foreword 3
Western Australian Oil and Gas 2002
The year in review 4
Gas-to-Liquids (GTL)
Project developments in Western Australia 10
Major growth markets for LNG Trade
North West Shelf Venture and second seabed
12
trunkline project 14
Map 1: Significant hydrocarbon discoveries in Western Australia 15
Map 2: North West Shelf Oil and Gas 16
Oil and Gas Projects (Index)
Operating Projects
17
Airlie Island 19
Athena 20
Barrow Island 21
Beharra Springs 23
Blina–Boundary–Lloyd–Sundown–West Terrace 24
Buffalo 26
Dongara–Mondarra–Yardarino 27
East Spar 29
Griffin–Chinook–Scindian 30
Harriet area fields 32
Hovea 37
Laminaria–Corallina 39
Legendre 41
Mount Horner 42
North West Shelf Gas Project 43
Stag 47
Thevenard Island 48
Tubridgi 50
Wandoo 51
Woodada 52
Projects under consideration
Black Tip 53
Cliff Head 53
Coniston 53
Gorgon 54
Jansz 56
John Brookes 56
Macedon–Pyrenees 57
Scarborough 57
Scott Reef–Brecknock–Brecknock South 58
Tern–Petrel 58
Vincent–Enfield–Laverda 59
Whicher Range 59
Woollybutt 60
Western Australian petroleum fact sheet 61
Abbreviations, permits and conversions 64
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 1

Strategic position: In 2002, partners in Western Australia’s North West Shelf Project signed a $25-billion contract to become the inaugural supplier
of LNG into China.

Clive Brown, MLA
Minister for State Development
Government of Western Australia
Foreword
Iam pleased to be able to release the 2003 edition of the review of the Western
Australian Oil and Gas Industry. As in previous years, this publication provides a
comprehensive and detailed summary of oil and gas projects currently in
production or under consideration within Western Australia.
The petroleum industry is an important part of the State’s economy. It is the largest
resource sector in Western Australia, with the value of petroleum sales in 2002
amounting to more than $10 billion, or 37% of the total value of the State’s mineral
and petroleum sales. Furthermore, Western Australia is the country’s premier
petroleum producer, accounting for approximately 57% of the nation’s crude oil
and condensate production and 54% of natural gas production.
In 2002, the petroleum industry continued to grow in Western Australia with a 10%
increase in crude oil and condensate production to a record 139 million barrels.
Western Australia has vast natural gas reserves off its northwest coast and the State
is the sole source of Australia’s liquefied natural gas (LNG) production. The
significance of this strategic position was underlined in 2002 when the nation’s
biggest export deal with a single customer was secured as partners in Western
Australia’s North West Shelf Project signed a $25-billion contract to become the
inaugural supplier of LNG into China.
Western Australia has an estimated 120 trillion cubic feet of gas which continues to
provide a range of new investment opportunities within the State. Using a range of
gas-to-liquids technologies, these gas reserves could be used to significantly
increase Australia’s production of chemical products such as ammonia, methanol
and other clean fuels.
Western Australia’s petroleum resources have already captured the attention of
resource developers worldwide. Much of this recent interest from investors has
centred on new gas-processing projects. To cater for the unprecedented level of
interest by investors in proposed gas-processing ventures on the Burrup, the
Western Australian Government has committed a $138-million multi-user
infrastructure package for the Burrup Peninsula. The State Government has also
secured native title agreements for the development of industrial land in the area.
The continued development of Western Australia’s oil and gas resources will
provide jobs and opportunities for all Western Australians. For example, the
increasing demand for construction and fabrication services is driving the growth of
the Australian Marine Complex at Henderson, a world-class ship-building and
fabrication precinct. In addition, investment in major projects is providing benefits
for a broad range of support industries, including information technology,
communications, hospitality and tourism.
This year’s Western Australian Oil and Gas Industry has been produced by the
Department of Industry and Resources (DoIR). The Department of Industry and
Resources is a merger of the former Department of Mineral and Petroleum
Resources (MPR) and the industry, trade and physical infrastructure divisions of the
former Department of Industry and Technology. This merger has created an
opportunity for the Government to place greater focus on economic development
in Western Australia. A focus of this Department will continue to be on assisting
investors wanting to develop petroleum and other resource-related industries in
Western Australia.
I commend this year’s Western Australian Oil and Gas Industry to you with
confidence that the petroleum industry will continue to provide a foundation for
strong economic growth in Western Australia.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 3

Western Australian Oil and Gas 2002
The year in review
Significant contribution: Liquified Natural Gas (LNG) is amongst one of Western Australia’s most valuable petroleum products. In 2002, LNG
accounted for 27.4% of the State’s total petroleum sales.
Petroleum overview
During 2002, world oil prices
increased from under US$20/bbl in
January 2002 (average of Brent, Tapis
and West Texas Intermediate (WTI)
prices over the course of the month)
to nearly US$30/bbl at the end of the
year, averaging around US$25.50/bbl,
2% up on the previous year’s average
of US$25/bbl. Major factors
underpinning the firmness of oil
prices included intensified unrest in
the Middle East, fears over the US-led
war against Iraq and a weaker US
currency. The A$, at US54.39 cents
during 2002, was 5% up on 2001
when the average was US51.74 cents.
As a result of the appreciation of the
Australian currency, the average oil
price in A$ terms during 2002 was
3.2% down on the previous year,
despite oil prices being higher in US$
(figure 1).
Firmer oil prices and a stronger A$
saw sales volume of condensate and
crude oil in Western Australia grow
faster than the value of sales in 2002.
Figure 1: Average Oil Prices and Exchange Rate 2001-2002
$
60
4 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
50
40
30
20
10
Oil Price US$ Oil Price A$ Exchange Rate (RHS)
Mar-01 Jun-01 Sep-01 Dec-01 Mar-02 Jun-02 Sep-02
Western Australia’s condensate and
crude oil sales increased by 14% and
8% to record levels of 43 and
96 million barrels (MMbbl),
respectively. However, reflecting the
appreciation in the value of the A$
against its US counterpart, the value
of condensate and crude oil sales
increased by a lower rate in 2002 —
US$/A$
0.58
condensate up 8% to $1 929 million
and crude oil up 5% to $4 457
million.
Western Australia’s liquefied natural
gas (LNG) sales in 2002 were
marginally up by 1% to 7.6 million
tonnes (Mt). Due to the stronger A$
however, LNG sales value suffered a
5% drop to $2 791 million.
0.56
0.54
0.52
0.50
0.48
0.46
Source: WA Treasury Corporation

The Goodwyn A is one of two platforms producing gas and condensate from the North Rankin, Goodwyn, Perseus and Echo-Yodel fields .

Go
13
The decrease in the value of LNG
sales negated much of the increases
attained by crude oil and condensate.
As a result, the overall value of
Western Australia’s petroleum sales
increased by only 2% in 2002 to
$10 200 million, despite total sales of
petroleum (by volume in terms of oil
equivalent) in 2002 increasing by
6.5% (figure 2). This result is still
impressive given the higher sales
value base the industry has been
operating from since the 106%
increase in sales value achieved in
2000.
The petroleum sector retained its
dominant position in the Western
Australian economy in 2002. The
share in the State’s total value of
mineral and petroleum sales
accounted for by the petroleum
industry increased marginally from
36.6% in 2001 to 37.3% in 2002.
Crude oil is the major petroleum
product, accounting for 43.7% of
total petroleum sales, followed by
LNG (27.4%) and condensate (18.9%)
(figure 3).
Crude oil exports from Western
Australia were up by 4.7% to $2 838
million in 2002. However, the value
Figure 2: Western Australia's Petroleum Sales in 2002
20%
15%
10%
5%
0%
-5%
-10%
-15%
Figure 4: Petroleum Exports from Western Australia
of exports for LNG and condensate
was down by 14.7% and 6.2%,
respectively, on the previous year. As
a result of decreased LNG and
condensate exports, petroleum
exports from the State were down by
5.7% to $7 296 million in 2002,
compared to $7 740 million in 2001
(figure 4).
Japan was the dominant consumer of
Western Australia’s LNG, accounting
for over 99% of the State’s LNG
exports in 2002. Major overseas
Condensate Crude Oil LNG LPG Natural Gas Petroleum
Figure 3: Sales by commodity
Nickel
11%
Petroleum
37%
$ Million
3,500
3,000
2,500
2,000
1,500
1,000
Sales Volume Sales Value
Crude Oil
44%
Natural
6%
Source: DoIR
Source: DoIR
6 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
500
0
Crude Oil Condensate LNG Other
Source: DoIR
19%
2001 2002
LPG Butane
G
%
pane
markets for Western Australia’s crude
oil in 2002 included Japan
(absorbing 33%), South Korea (30%)
and the United States (21%). The
State’s condensate was mainly
exported to Singapore (36%), Taiwan
(21%), South Korea (20%) and the
United States (13%) (figure 5).
Crude Oil
Western Australia’s crude oil sales
reached a new high of 96 MMbbl in
2002, up by 8% on the previous
year. This was largely due to a full
year of production from the Legendre
oil field, increased output from
Wanaea and commencement of
production from other new fields.
World oil prices rose towards the end
of 2002 and on average, over the
course of the year were 2% higher
compared to 2001. The price
increase was negated however by a
5% appreciation in the exchange rate
of the A$ relative to the US$.
Consequently, the value of Western
Australia’s crude oil sales increased
by 5% in 2002 to $4 457 million.
Crude oil reinforced its dominant
position in the petroleum industry in
2002. The share of total petroleum
sales in Western Australia accounted
for by crude oil increased by one
percentage point to 43.7% from
42.5% in 2001.
Oil was produced from 39 fields in
Western Australia in 2002. The
largest oil producing field is Wanaea
(figure 6). During 2002, the Wanaea
field alone produced 28.7 MMbbl,
accounting for nearly 30% of the
State’s total. Other fields with an
output exceeding 1 MMbbl in 2002
include Legendre North 9.2 MMbbl,
Griffin 8.0 MMbbl, Cossack

Figure 5: Crude oil and condensate export destinations in 2002
New Zealand
China
Singapo
Crude oil exports
TOTAL VALUE $2.8 billion
Oth
6.4 MMbbl, Hermes 5.6 MMbbl,
Stag 5.3 MMbbl, Chinook–Scindian
5.1 MMbbl, Buffalo 4.7 MMbbl,
Wandoo 4.3 MMbbl, Barrow Island
3.6 MMbbl, Simpson 3.1 MMbbl,
Lambert 3.0 MMbbl, Legendre South
2.1 MMbbl, Laminaria East
1.6 MMbbl, Roller 1.4 MMbbl and
Saladin 1.1 MMbbl.
A number of new fields commenced
oil production in Western Australia in
2002. These included Gibson, South
Plato, Little Sandy, Victoria and
Pedirka in the offshore Carnarvon
Basin and Hovea in the onshore Perth
Basin. Total output from these new
fields in 2002 was about
1.65 MMbbl.
Condensate
Sales volume of condensate in
Western Australia increased by 14%
to a record high 43 MMbbl in 2002.
This was largely due to a full year’s
Figure 6: Top Five Oil, Condensate and Gas Fields in WA in 2002
%
100
80
60
40
20
0
Hermes
Cossack
Griffin
Legendre N.
Wanaea
East Spar
North Rankin
Perseus–Athena
Echo–Yodel
Goodwyn
Condensate exports
TOTAL VALUE $1.6 billion
Ta
2
Oth
J
Source: DoIR
production from the Athena and
Echo–Yodel fields. Again however,
appreciation of the A$ eroded the
value of this increase with condensate
sales rising by 8% to $1 929 million.
Condensate is a by-product from
offshore gas fields. There were 27
fields producing condensate in
Western Australia in 2002. The
Goodwyn field remained the largest
condensate contributor in the State.
In 2002, it produced 19.1 MMbbl of
condensate, accounting for about
43% of the State’s total. Nevertheless,
the Goodwyn field’s share in total
production has contracted
significantly compared to 66% in
2001. Echo–Yodel which
commenced production in late 2001
became the second-largest
condensate field, producing
12.5 MMbbl of condensate or 28% of
the State’s total in 2002, surpassing
the Perseus–Athena field (7.6 MMbbl
or 17%).
East Spar
Echo–Yodel
North Rankin
Perseus–Athena
Goodwyn
Oil Condensate Gas
Source: DoIR
ea
Liquefied Natural Gas
(LNG)
LNG is Western Australia’s most
valuable petroleum product. In 2002,
sales were marginally up by 1% to
7.6 Mt. Due to price lags and
contractual arrangements, the value of
LNG shipments did not fully benefit
from the slightly higher oil prices.
This, in combination with the stronger
A$ translated to a 5% drop in sales
value to $2 791 million.
LNG has been the second-largest
sector within Western Australia’s
petroleum industry since 2000. In
2002, LNG accounted for 27.4% of
the State’s total petroleum sales, down
slightly on the previous year’s 29.1%.
The North West Shelf Gas Project is
the only LNG project in Australia.
Japanese power utilities have been the
principal purchasers of Western
Australia’s LNG since 1989. In 2002,
the North West Shelf Venture (NWSV),
consisting of Woodside Energy Ltd,
BP Developments Australia Ltd,
ChevronTexaco Australia Pty Ltd, BHP
Billiton Petroleum (NWS) Pty Limited,
Shell Development (Australia) Pty Ltd
and Japan Australia LNG (MIMI) Pty
Ltd, delivered 127 cargoes of LNG to
Japanese customers. In addition to
the contract sales, three spot cargoes
were sold to Korea Gas Corporation
and one cargo to BP Gas Marketing in
2002.
Natural Gas
In addition to gas used as feedstock
for LNG production, Western
Australia also produces natural gas for
domestic State consumption in
industry and households. Natural gas
sales account for about 6.5% of the
State’s total petroleum sales. In 2002,
natural gas sales in Western Australia
increased by 1.4% to 7.9 billions of
cubic metres (Bcm). The sales value
of natural gas also experienced a rise
of 2.1% to $659.9 million.
The five largest gas fields in Western
Australia in 2002 were Goodwyn,
Perseus–Athena, North Rankin,
Echo–Yodel and East Spar. Production
from these five fields accounted for
about 87.5% of the State’s total
(figure 6).
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 7

Progress proceeds: The $2.4-billion expansion of the North West Shelf Venture’s gas-processing facilities on the Burrup Peninsula was 60% complete
by the end of 2002.
Liquefied Petroleum Gas
(LPG)
2002 was not a favourable year for
Western Australia’s LPG industry.
LPG sales (including both butane and
propane) amounted to 815 566
tonnes (t), down by 5.3% on the
previous year. As LPG produced in
the State is mainly for overseas
markets, the appreciation of the A$
exacerbated the deterioration,
resulting in a 9.7% fall in the value of
LPG sales to $363.4 million.
Consequently, the share of LPG in the
State’s total petroleum sales fell
slightly from 4.0% in 2001 to 3.6% in
2002.
Highlights of 2002
The $2.4-billion expansion of the
NWSV’s gas-processing facilities
remained a major focus of
development efforts during 2002.
Construction of the fourth LNG
processing train commenced in
September 2001 and was 60%
complete by the end of 2002. Work
on the second trunkline started in
June 2002 and was more than 30%
complete by December.
In 2002, the Western Australian LNG
producer continued to successfully
market LNG into the North Asian
region. With the announcement in
August 2002 that Australia LNG (the
NWSV’s marketing agency outside of
Japan) had been selected as the
preferred supplier to China’s first LNG
project in the Guangdong Province in
southern China, the WA LNG industry
broadened its customer-base beyond
its long-standing relationships with
Japanese customers. Sales and
Purchase Agreements were signed in
October 2002 for the supply of
approximately 3.3 Mt/a of LNG for 25
years, starting in 2006. The $25billion
contract is the biggest export
deal with a single customer in
Australian history. It will further
strengthen LNG’s role in Western
Australia’s petroleum industry in the
future.
In terms of oil fields development, the
Harriet Joint Venture, brought new
wells in the Simpson, Pedirka, Little
Sandy, Victoria and the nearby
Gibson–South Plato oil field into
production in late 2002.
ARC Energy NL (Operator) and its
equal joint venture partner Origin
Energy Developments Pty Ltd
concentrated their activity on the
development of the Hovea oil field in
2002. The Hovea field has been
transformed from a greenfields site
into a production facility with a
handling capacity in excess of 5 000
barrels per day (bbl/d) of oil in less
8 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
than six months. The Hovea
development is the first commercial
oil discovery in the Perth Basin since
1966 and the first onshore oil field in
Western Australia brought into
commercial production in the past 20
years.
To deal with the rapid decline in
production from the Laminaria field,
Woodside Energy Ltd and its joint
venture partners completed the $123million
Laminaria Phase II
development consisting of two
additional infill production wells in
June 2002. Initial production from
these wells increased the combined
field production from 75 000 to
140 000 bbl/d.
The outlook for the WA
petroleum sector
A record level of crude oil and
condensate production combined
with winning the $25-billion contract
to export LNG to China made 2002
an impressive year for the Western
Australian petroleum industry.
Looking into the short to medium
term, the outlook for the oil and gas
industry in Western Australia remains
extremely positive. Significant
additional oil and gas production for
the State will emanate from the
proposed development of new fields.

Oil and gas upstream projects which
have been committed, or anticipated
to be committed, during 2002-2004
total $5.23 billion (table 1). Of these
projects, the Double Island–Simpson
North and Hovea fields are under
development, and the Woollybutt
project began production in May
2003.
A positive development for the
Western Australian gas industry in
2002 was the increased momentum
of initiatives which add value to the
vast gas reserves in the north of the
State. Between 2002 and 2004, total
capital expenditure for gas-based
downstream projects which are
committed, or expected to be
committed, will be more than
$10 billion. These include the
NWSV’s LNG expansion,
ChevronTexaco’s Gorgon LNG
onshore project and several
substantial gas-to-liquids (GTL)
projects proposed for the Burrup
Peninsula (table 2).
Of the six GTL projects, the Burrup
Fertiliser project commenced
construction in May 2003, while the
Methanex project has been granted
environmental clearance. The initial
plant considered by Methanex had a
capacity of up to 5 million tonnes per
annum (Mt/a) of methanol. But the
company announced in March 2003
that it would be suspending
development pending a review of
construction costs and its initial level
of capital commitment to the project.
One option under review involves a
two-stage development. A smaller
capacity plant of 1.3 Mt/a with capital
costs of US$500 million would be
built in the first stage and operational
in 2006. In the second stage, another
1 Mt/a production capacity would be
built-up in 2009.
The gas that would be required for the
six GTL projects is estimated to be at
least double that of Western
Australia’s total domestic
consumption. Amongst the most
significant potential large gasconsuming
GTL projects would be the
development by Sasol Chevron of its
proposed synthetic diesel plant. This
would represent the biggest resource
project since the North West Shelf
was brought into production. The
project involves the expenditure of up
to $2.2 billion during the first stage of
development. With an estimated gas
Table 1: Proposed major upstream oil and gas projects in WA
Project Capital expenditure
($ million)
Gorgon Offshore Gas Facilities 2 000
Enfield–Laverda Oil Development 600
Norfolk–Exeter–Mutineer Oil Development 800
Cliffhead/Other Nearby Fields Oil Development 300
Double Island–Simpson North 100
Woollybutt Oil Development 80
Linda–Rose–Lee Gas Development 80
Blacktip Gas Development 300
Onshore Tight Gas Development: Whicher Range 150
Hovea Onshore Oil Development 20
Angel NWS Gas and Condensate Development 800
Total 5 230
Table 2: Proposed gas-to-liquids (GTL) projects in WA
Company Project Production capacity Capital
expenditure
($ million)
Sasol Chevron synthetic diesel 45 000 bbl/d (stage 1) 2 200
Dampier Nitrogen ammonia/urea 100 000 t/a of ammonia
1.2 Mt/a of urea 900
Burrup Fertiliser ammonia 760 000 t/a 630
Japan DME Dimethyl-ether 1.7 Mt/a 1 000
GTL Resources
(Liquigaz) methanol 1 Mt/a 770
Methanex methanol 1.3 Mt/a (stage 1) 800
Total 6 300
intake of 20 trillion cubic feet (Tcf)
over the 25-year life of the project,
only the Carnarvon Basin or the North
West Shelf have the capacity to meet
the plant’s gas needs. The project
would aim to initially produce
45 000 bbl/d of synthetic diesel,
building up to 200 000 bbl/d at some
point. The plant would operate for
around 25 years and would
potentially coincide with the
development of the expansive gas
reserves in the Gorgon area.
In contrast to the promising outlook
for the petroleum industry in Western
Australia, there continues to be
uncertainty surrounding the outlook
for the global oil market as well as
the world economy. Although oil
prices eased from a 12-year high of
US$40/bbl after the war in Iraq, prices
remained very volatile. On the
demand side, growth in the US
remains weak and Asian economies,
already struggling to boost business
and consumer confidence, are now
feeling the effects from the outbreak
of Severe Acute Respiratory Syndrome
(SARS). On the supply side, the war
in Iraq ended quicker than expected
and the damage to oil infrastructure in
Iraq appears limited so far. Although
OPEC has decided to cut production
levels recently, other countries have
increased production markedly in
recent months. As a result, the
international oil market could well be
faced with a situation of excess
supply and an even larger decline in
prices once inventories have been
replenished. However, continuing
geopolitical tensions around the
world (including post-war Iraq) and
lingering terrorist threats are still
imposing considerable risk to the
world oil market.
Nevertheless, the increasing
development activities in both the
upstream and downstream sectors in
Western Australia highlight the State’s
attraction as a place to invest in
petroleum-based production for
international investors. With
abundant petroleum resources, a
highly skilled workforce, well
established financial and physical
infrastructure, geological proximity to
burgeoning Asian markets, and
supportive and efficient public
services, Western Australia is a key
location for a growing petroleum
industry.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 9

Gas-to-Liquids (GTL)
Project developments in Western Australia
The Burrup Peninsula, located
near Karratha in the State’s
northwest, is set to become a
world-class hub for gas-based
industries. A group of gas-to-liquids
(GTL) projects, worth in excess of
$3.8 billion are under development.
Vast natural gas reserves exist off
Western Australia’s northwest coast.
With an estimated 120 Tcf of gas
reserves, Western Australia has
captured the attention of resource
developers worldwide.
Much of the recent interest from
investors has centred on new gasprocessing
projects, with Western
Australia seen as an excellent
location.
Western Australia’s biggest onshore
gas-processing facility is located on
the Burrup Peninsula. The North
West Shelf Joint Venture, operated by
Woodside Energy Ltd and other
partners, produces liquefied natural
gas (LNG), liquefied petroleum gas
(LPG), domestic gas (Domgas) and
condensate.
To cater for the unprecedented level
of interests by investors in proposed
gas-processing interests on the Burrup
Peninsula, the Western Australian
Government has committed a multiuser
infrastructure package for the
Burrup Peninsula worth $136 million.
The package includes a seawater
supply and brine return, pipeline
corridors, port development and
roadworks to improve site access.
London-based GTL Resources PLC,
proposes to build a $770-million
Liquigaz plant to produce 1 Mt/a of
methanol from mid-2005. The plant
will be situated on 35 hectares of
land at the Withnell East industrial
area, east of the North West Shelf gas
plant on the Burrup Peninsula. The
project will employ more than 600
people during construction and about
60 permanent employees when it
begins operating.
On 17 October 2001, GTL Resources
signed a Memorandum of
Understanding with Apache
Processing power: The Burrup Peninsula is already
home to Western Australia’s largest onshore gasprocessing
facility.
Corporation, Globex Energy Inc. and
Santos Ltd for the purchase of
108 TJ/d of natural gas to supply the
plant.
An offtake agreement has been signed
with Swiss trading house Vitol SA.
The agreement involves a
Memorandum of Understanding for
the marketing and sale of 100% of the
methanol from the plant. GTL
Resources is close to securing project
finance for its development.
Burrup Fertilisers is developing an
ammonia plant at the King
Bay–Hearson Cove industrial area on
the Burrup Peninsula. Around
760 000 t/a of liquid ammonia will be
produced and exported to India and
other world markets for the
manufacture of fertilisers. The
company has secured project finance,
land tenure, water supply and port
infrastructure services agreements.
Environmental and Aboriginal
Heritage approvals and Native Title
agreements have been obtained. The
Harriet Joint Venture has an
agreement to supply 82 TJ/d of natural
gas to the project for 25 years.
10 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Construction is scheduled to
start in the second quarter of
2003 and production in the
third quarter of 2005.
Canadian-based Methanex
Corporation is considering the
establishment of a methanol
plant on the Burrup Peninsula.
Methanex supplies about a
quarter of the world’s methanol
market and more than 30% of
the Asia–Pacific market, the
latter from production facilities
in New Zealand and Chile.
The initial plant considered by
Methanex had a capacity of up
to 5 Mt/a of methanol and an
agreement with the six partners
in the North West Shelf project
for the supply of 200 TJ/d of gas
over 25 years.
Feasibility and approvals work
have commenced but the
Company announced in March
2003 it will be suspending
development pending a review of
construction costs and its initial level
of capital commitment to the project.
One option under review is a smaller
capacity plant with a lower capital
cost. A decision on whether to
proceed to a smaller scale project
(1 Mt/a) is expected in mid-2003.
Agrium Inc. of Canada, Plenty River
Corporation Ltd, Thiess Pty Ltd and
Uhde GmbH of Germany have signed
a Project Development Agreement to
complete a bankable feasibility study
for the construction of a
A$900 million ammonia and urea
plant on the Burrup Peninsula. The
world-scale plant will produce around
1.2 Mt/a of granular urea and
100 000 t/a of ammonia. Urea is
widely used as a fertiliser, while
ammonia is used in fertilisers,
explosives and as a chemical
feedstock.
Japan DME Ltd, a joint venture of
Japanese companies comprising
Mitsubishi Gas Chemical Company,
Itochu Corporation, Mitsubishi Heavy
Industries and JGC Corporation, plans
to develop a world-scale dimethyl-

Poised for potential: The Burrup Peninsula is set to become a world-class hub for gas-processing projects. A group of gas-to-liquids (GTL) projects,
worth more than $3.8 billion is currently under development.
ether (DME) plant on the Burrup
Peninsula near Karratha. DME is used
as an aerosol propellant and is a
likely future environmentally clean
fuel for the power generation and
transportation industries. The
proposed plant will produce
methanol for conversion into 1.7 Mt/a
of DME from around 220 TJ/d natural
gas. Detailed feasibility studies are
underway. A commitment to proceed
is expected in the latter half of 2003.
The current plan is for the plant to be
operating by late 2006.
Sasol Chevron has plans to establish a
world-class synthetic diesel GTL plant
in the Asia–Pacific region. The full
3-phase development will be the
largest resource project that the State
has seen since the $12-billion North
West Shelf project in the 1980s,
involving the expenditure of up to
A$2.2 billion during the first stage of
development.
A potential site option under
consideration is Barrow Island.
Location at Barrow, however, is
subject to the outcome of an
extensive Environmental, Social and
Economic Review initiated by the
Gorgon Joint Venture. Cabinet is
expected to make a decision on the
question of access by the beginning of
the third quarter of 2003.
The project planned by Sasol Chevron
would need access to more than
20 Tcf of uncommitted gas. The
proposed project will be developed in
three phases, with the initial phase
being capable of processing
320-480 TJ/d of gas for the production
of 45 000 bbl/d of synthetic diesel.
This would make a significant
contribution to the nation’s energy
security, as Australia’s oil selfsufficiency
declines over the next
decade.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 11

Major growth markets for LNG trade
World trade in liquefied
natural gas (LNG) has been
growing at an average rate
of around 6.7% per annum since
1990. Almost a third of
internationally traded gas is now
delivered as LNG although this
represents only a small proportion of
the global natural gas market (about
6%). Its share is expected to grow
strongly this decade. Asia remains by
far the major market for LNG and is
the region where the greatest growth
will be experienced. Japan started
importing LNG in 1969 and volumes
have increased every year since.
South Korea began importing in 1986
and rapidly overtook Spain and
France to become the second largest
importer of LNG. Taiwan began
imports in 1990. New LNG trade
entrant, China, is this century’s
emerging major consumer and is
poised to begin imports from 2006.
Current LNG demand in the
Asia–Pacific region is around 82 Mt/a
and is forecast to grow by 50% by
2010.
LNG demand outlook
in China
China is the world’s most populous
country and the second largest energy
consumer. Natural gas, however,
accounts for about 3% of its total
energy consumption. China’s 10th
Five-Year Plan (2001-2005) has gas
expansion both upstream and
downstream as one of its priorities.
The Government of China confirmed
its determination to increase the share
of natural gas in the country’s energy
supply mix within the next five years
and beyond. Evidence of this
includes the construction of the
massive West-East Gas Pipeline
Project and China’s first LNG import
terminal in Guangdong. A second
LNG import terminal is progressing in
Fujian province, adjacent to
Guangdong. Further LNG import
terminals are possible in Shandong
province and in the East China region
including Shanghai, Zhejiang and
Jiangsu Provinces to fuel economic
growth in the prosperous coastal
Developing demand: By 2010, requirement for LNG in the Asia–Pacific region is forecast to
grow by 50%
Asian LNG Demand Growth
India
South Korea
Taiwan
China
Japan
region. LNG into East China will
complement the 4 000 km long
“West-East Pipeline” that will bring
natural gas from the Tarim basin in
China’s far west to Shanghai in the far
east. The target is to double the
share of natural gas in China’s total
primary energy supply by 2010 from
the current level of about 3% and to
build a well-interconnected national
gas supply network by 2020. Based
on expected delivery schedules to
Guangdong and Fujian, conservative
forecasts are for LNG supplies to grow
to 10 Mt/a by 2010.
A number of energy policy challenges
confront both the Chinese
Government and industry as it moves
ahead to increase production of
indigenous gas while at the same time
increasing imports. Meeting these
targets will depend on China’s ability
12 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Mt/a
40
30
20
10
0
2004 2006 2008 2010
Source: DoIR estimate
to effectively develop the downstream
gas market along with the gas
industry’s technical and financial
ability to prepare infrastructure.
Government will also be tasked with
further planning and implementation
of power sector reforms. These
reforms will need to facilitate
increasing the share of natural gas in
the country’s energy supply mix.
China is ranked 19th in terms of
world gas production, with 30.3 Bcm
(1.07 Tcf) produced in 2001. Its 2001
estimates of proven gas reserves were
about 1.35 Tcm (48.3 Tcf),
representing only 1% of the world’s
gas reserves. The major gas
companies of China — PetroChina,
Sinopec and China National Offshore
Oil Corporation (CNOOC) produce
most of the gas. Analysts forecast that
by 2020, China will need to import
70% of its crude oil and 50% of its
natural gas requirements. This will be
necessary to support predicted
economic growth and improve living
conditions, whilst simultaneously
reducing coal consumption and the
level of pollution, particularly in
populous coastal regions.
LNG demand outlook in
South Korea
Since LNG usage in South Korea
began in the mid-1980s, infrastructure
has grown rapidly and South Korea is
now the second largest importer after

Japan and has one of the highest rates
of consumption growth in Asia.
Unlike China, it has negligible
indigenous hydrocarbon resources.
The demand for LNG in South Korea
has dramatically increased to 14.6
Mt/a today. There are three LNG
receiving terminals in South Korea,
located in Pyeongtaek, Incheon and
Tongyeong. A total of 20 tanks are in
commercial operation, 13 tanks under
construction and a trunk line network
spanning some 2 056
km throughout the six regional sectors
of South Korea.
According to government projections,
South Korea’s future demand for LNG
is expected to increase to as much as
21 Mt/a by 2010, with a share of
12.1% of the total primary energy
consumption. With the projected
annual growth rate of 4.7% the future
of the South Korean LNG industry is
very prospective. As a member of
OECD, South Korea is making every
endeavour to contribute to a cleaner
environment for the future. As such,
LNG is expected to dominate the
Korean energy market, and South
Korea, as a major consumer, has the
ability to play a strong role in the
expansion of the global LNG industry.
North West Shelf
Venture Project
In October 2002, the North West
Shelf Venture (NWSV) Project in
Western Australia secured a A$25billion
contract to become the
inaugural supplier of 3.3 Mt/a of LNG
for 25 years to the Guangdong LNG
Terminal and Trunkline Project
commencing from around 2006. In
March 2003, key agreements were
finalised by project sponsors of the
Guangdong project with the
downstream gas end users. The
agreement is a key milestone in the
history of global LNG trading.
The contract with China has now
introduced a seventh investor,
CNOOC in the NWSV’s “China LNG
Joint Venture” (CLJV). In May 2003,
the NWSV partners and CNOOC
formalised the agreement for CNOOC
to acquire interest in the upstream
production and reserves of the NWSV
project. This involves CNOOC
acquiring a 25% stake in the CLJV.
This is CNOOC’s first investment in
Australia and an important milestone
in the strengthening trade and
Positive position: Australia is ideally placed to be the LNG supplier of choice, particularly
throughout Asia and the Pacific Rim.
investment relationship between
China and Western Australia. The
success of the venture has potential to
lead to further Chinese investment in
the State’s petroleum industry, as
China has successfully carried out in
the State’s iron ore industry during the
past 30 years.
The NWSV also finalised, in March
2003, a sale and purchase agreement
with Korea Gas Corp (KOGAS),
marking its first LNG term (or nonspot)
contract with South Korea’s
state-owned utility. The 7-year
contract formalises a letter of intent
signed by KOGAS and the NWSV in
January 2003. Initial LNG deliveries
are scheduled to commence in the
fourth quarter of 2003 and annually
comprise 0.5 Mt. The agreement
follows the sale of numerous spot
LNG cargoes to South Korea by the
NWS project.
Also in March 2003, NWSV signed a
Sale and Purchase Agreement with
Tohoku Electric, a new long-term
Japanese customer, for the supply of
0.4 Mt/a for 15 years from 2005.
There are eight existing Japanese
customers taking 7.5 Mt/a.
Potential LNG projects
Australia is ideally placed to be the
LNG supplier of choice, particularly
throughout Asia and the Pacific Rim.
Since gas exploration off the nation’s
northwest coast commenced in the
early 1970’s a string of large
discoveries has led to the
establishment of an outstanding
inventory of gas resources.
Remarkably, most of Western Australia
remains relatively under-explored,
even in the basins with extensive
production history.
Gorgon, Scott Reef and Brecknock,
for example, are major uncommitted
gas fields in the highly prospective
waters off the Pilbara and Kimberley
coastline of Western Australia. These
are additional resources with the
potential to be developed into major
LNG production facilities.
The recent LNG trade and investment
contracts with the People’s Republic
of China and South Korea are
mutually beneficial and significantly
extend Western Australia’s trade
relationship with these rapidly
growing nations. Winning new longterm
customers in addition to Japan,
means a vote of confidence for
Australia as a long-term secure,
reliable and preferred LNG supplier to
multiple markets, which also offers
upstream and downstream
opportunities to investors.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 13

North West Shelf Venture and second
seabed trunkline project
At the time of going to print the
North West Shelf Venture’s
Liquid Natural Gas (LNG) Train
4 was about 55% complete, with
construction 25% complete. Train 4
will have a production capacity of
4.2 Mt/a of LNG, with first LNG
scheduled for mid-2004.
The new facility, the first to be
designed in Australia, will increase
total LNG production capacity from
the North West Shelf project to
around 11.5 Mt/a.
The intricate meshing of over 375 km
of cabling and the weaving of more
than 100 km (7 000 t) of steel piping
within 8 500 t of structural steel is an
engineering celebration. All this, fixed
to a base of more than 1300 m3 of
concrete in foundations, will be
covered with about 84 000 litres of
paint.
Over 1 000 people are now working
on the LNG Train 4 construction site
and this is expected to increase to
nearly 2000 by mid-2003.
The six equal participants in the
North West Shelf Venture, Woodside
Energy Ltd. (operator); BHP Billiton
Petroleum (North West Shelf) Pty Ltd;
BP Developments Australia Pty Ltd;
ChevronTexaco Australia Pty Ltd;
Japan Australia LNG (MIMI) Pty Ltd;
and Shell Development (Australia) Pty
Ltd will expend $1.6 billion on the
development of Train 4 and an
additional $800 million to complete
the installation of the second subsea
trunkline.
The 1.07 m (42 inch) diameter subsea
trunkline will provide raw gas for
Train 4 (and Trains 5 and 6, when
built) plus 900 TJ/d of gas for Western
Australian consumption. It will sit in
water depths of between 48 and
130 m.
The trunkline will be the largest
offshore pipeline installed in Australia
and will employ up to 400 people
offshore at peak installation.
Over 85 000 t of steel piping will be
partially covered by more than
400 000 m3 of rock and anchored
down, from about 50 km offshore to
14 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
GWA
30" IFL
NRA
12" GEL
40" NRA Trunkline (1TL)
Wanaea/Cossack
42" NB Trunkline (2TL)
LNG PLANT
Dampier
Karratha
WESTERN AUSTRALIA
the North Rankin A platform, by
900, 31 t precast iron ore
aggregate and heavy-weight
concrete-mix gravity anchors.
The anchors are designed to
minimise the effects of strong
seabed currents, which have the
potential to displace the trunkline
under cyclonic conditions.
Resembling horse saddles, the
anchors are being cast at the Joint
Venture’s King Bay Supply Base
on the Burrup Peninsula at the
rate of 55 units per week.
When placed in the water, the
weight of each anchor is reduced
to 21 t.
Completion date for the second
seabed trunkline is mid-2004.
Labour demand: At peak installation, the trunkline will employ up to 400 people, including 70
specially trained Australian welders.

20^
22^
Map 2: North West Shelf Oil and Gas
50 km
nwoil&gas drd02-3GDA.lat
114^
116^ Mutineer
Exeter
Norfolk
Pitcairn
Scarborough
Io
Jansz
Geryon
Urania
Iago
Eaglehawk
Athena Egret Lambert/Hermes
Capella
Angel Talisman
Perseus
Cossack
Goodwyn North
Wanaea
Echo/Yodel
Gaea Rankin
Legendre
Keast
Legendre South
Rankin Tidepole
Dockrell
West Dixon Dixon
Sage
Wilcox
Reindeer/Caribou
Orthrus Dionysus
Withnell Corvus
Maenad
Wandoo A
Chrysaor
B
West Tryal Rocks See Varanus Area Map
Stag
North Gorgon Montebello Islands
INDIAN
Central Gorgon John Brookes
Burrup
OCEAN
Gorgon Maitland
Spar
East Spar Barrow Island
Antiope
Varanus Island
Peninsula
DAMPIER
KARRATHA
ROEBOURNE
Woollybutt
Pasco
Flinders Shoal
See Thevenard Area Map
Coniston
Vincent
Novara
Airlie Island
Bandar Phantom
Thringa Mardie
Enfield Macedon/
Laverda Pyrenees Outtrim
Scafell Blencathra Caretta
Leatherback
Thevenard Island
ONSLOW
Carnie
EXMOUTH
Rivoli
Yardie East Cape Range
Rough Range
Parrot Hill
114^
HYDROCARBON DISCOVERIES
Gas
Oil
Oil & Gas
PRODUCTION FACILITIES
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
LNG storage tanks
Oil storage tanks
Onshore production facility
Under construction
Proposed development
Abandoned field
INDIAN
Maitland
OCEAN
16 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Peck
Commonwealth Jurisdict ion
State Jurisdiction
Chamois
Montebello Islands
Wonnich
Campbell
Sinbad
Endymion
Doric
Bambra
Linda
B Lee
116^
C Rose
Varanus Harriet Monty
A Island
North Gipsy
Rosette Gipsy Josephine
Agincourt
Baker
Alkimos/Tanami/Simpson
Gibson/South Plato
Little Sandy/Pedirka
Hoover
Victoria
Double Island
Barrow Island
Barrow Island
115 30
115^ 30’
Department of
Industry and Resources
Commonwealth Jurisdiction
State Jurisdiction
0 5 10
km
116
Oryx
20^ 30’ 20
GEOCENTRIC DATUM of AUSTRALI A
NTv2 GRID FILE TRANSFORMATION
INDIAN
Chinook/Scindian
Griffin
OCEAN
21^ 30’
Corowa
Ridley
GEOCENTRIC DATUM of AUSTRALIA
NTv2 GRID FILE TRANSFORMATION
Nimrod
Coaster
Tubridgi
VARANUS AREA MAP
THEVENARD AREA MAP
Rosily
State Jurisdiction
Commonwealth Jurisdiction
Thevenard Island
Yammaderry
Cowle
A B
C
Onslow
Roller
115^
Taunton
C
Skate
Australind
A
B Saladin
Crest
Department of
Industry and Resources
115^
ONSLOW
Topaz
Chervil
Airlie Island
Cadel 1
0 5 10
km
Tusk
South Pepper
North Herald
Nasutus
2

Oil and Gas Projects 2003
Projects are listed either under their name or under the
processing facility details
Agincourt 32
Airlie Island 19
Alkimos 34
Angel 62
Antiope 16
Athena 20
Australind 49
Baker 36
Bambra 35
Bambra East 62
Bandar 16
Barrow Island 21
Beharra Springs 23
Beharra Springs North 23
Blacktip 53
Blencathra 62
Blina 24
Boundary 24
Brecknock 58
Brecknock South 58
Buffalo 26
Cadell 19
Campbell 32
Capella 62
Cape Range 16
Caretta 16
Caribou 47
Carnie 16
Chamois 63
Chervil 19
Chinook-Scindian 30
Chrysaor 54
Cliff Head 53
Coaster 49
Coniston 53
Corvus 62
Corallina 39
Cornea 15
Corowa 16
Cossack 41
Cowle 49
Crest 49
Cudalgarra 15
Dinichthys 63
Dionysus 54
Dixon 62
Dockrell 62
Dongara 27
Doric 35
Double Island 35
Eaglehawk 63
East Spar 29
Echo-Yodel 43
Egret 62
Endymion 32
Enfield 59
Eurythion 62
Exeter 16
Flinders Shoal 62
Gaea 62
Geryon 54
Gibson 32
Gingin 15
Gipsy 32
Goodwyn 43
Goodwyn South 62
Gorgon 54
Gorgonichythys 63
Griffin 30
Gwydion 63
Harriet 32
Hermes 43
Hoover 35
Hovea 37
Iago 54
Io 54
Io South 62
Ishmael 63
Janpam North 25
Jansz 56
Jingemia 28
John Brookes 56
Josephine 36
Keast 62
Lambert 43
Laminaria 39
Laverda 59
Leatherback 63
Lee 36
Legendre 41
Linda 35
Little Sandy 32
Lloyd 24
Looma 15
Macedon 57
Maenad 54
Maitland 63
Mardie 63
Mondarra 27
Montague 63
Monty 36
Mount Horner 42
Mungenooka 23
Mutineer 16
Narvik 36
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 17

Oil and Gas Projects 2003
Nasutus 62
Nimrod 63
Norfolk 16
North Alkimos 36
North Gipsy 32
North Gorgon 54
North Herald 19
North Rankin 43
North West Shelf 43
Novara 62
Onslow 16
Orthrus 54
Oryx 63
Outtrim 63
Parrot Hill 16
Pasco 16
Peck 16
Pedirka 32
Perseus 43
Petrel 58
Phantom 16
Pictor 15
Pitcairn 16
Point Torment 15
Prometheus 63
Pueblo 62
Pyrenees 57
Reindeer 47
Ridley 16
Rivoli 16
Roller 49
Rose 36
Rosette 32
Rosily 16
Rough Range 16
Rubicon 63
Saffron 62
Sage 62
Saladin 49
Saratoga 15
Scarborough 57
Scarfell 63
Scott Reef 58
Sculptor 63
Searipple 62
Simpson 32
Sinbad 32
Skate 49
South Chervil 19
South Pepper 19
South Plato 32
Spar 29
Stag 47
St George Range 15
Sundown 25
Talisman 16
Tanami 32
Taunton 16
Tern 58
Thevenard Island 48
Thringa 16
Tidepole 62
Titanichthys 15
Topaz 16
Tubridgi 50
Turtle 63
Tusk 63
Ulidia 35
18 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Urania 54
Victoria 32
Vincent 59
Waggon Creek 15
Wanaea 46
Wandoo 51
West Dixon 62
West Tryal Rocks 24
West Terrace 24
Whicher Range 59
Wilcox 63
Withnell 16
Wonnich 32
Woodada 52
Woollybutt 59
Yammaderry 49
Yardarino 27
Yardie East 16
Yulleroo 15

Operating Projects
Airlie Island provides the base
for the processing and storage
of oil produced from the
Chervil field. It also served as the
base for production from the North
Herald and South Pepper fields before
they were decommissioned in
December 1997. The island
infrastructure includes oil processing
and water separation facilities, two
150 000 bbl storage tanks, pipelines,
a power generation plant and a flare
tower.
Chervil
Chervil was discovered in August
1983 and commenced production in
August 1989 using a two-well
monopod platform. The field currently
has one operating well, Chervil 6,
which commenced production in
August 1997. The oil (44° API gravity)
is transported to processing facilities
on Airlie Island through a 150 mm,
7 km pipeline. It is then pumped via a
508 mm, 2 km pipeline to an offshore
tanker loading facility and is shipped
to the BP refinery in Kwinana for
processing.
Chervil 6 ceased production in March
2002. The joint venture may consider
drilling Chervil 7 to further improve
the recovery from the field.
Potential Developments
The joint venture is continuing to
examine potential developments
within the permit area with the aim of
extending production operations on
Airlie Island. The Airlie facilities may
also have an ongoing value as a
storage facility for other oil and gas
projects.
South Chervil
In November 1983, the South Chervil
1 well intersected a 3.5 m oil-column
overlain by a 10 m gas cap and tested
a separate structure to Chervil.
Around one-third of the field lies in
TL/2 with the remainder in TP/7.
South Chervil may be developed
using a single well, similar to the
approach undertaken with Chervil 6,
and tied back to production facilities
on Airlie Island.
Average oil production (bbl/d)
Location
35 km north of Onslow
Basin,
Carnarvon, offshore
Permit/Licence
TP/7, TL/2
Ownership
7,000
6,000
5,000
4,000
3,000
2,000
1,000
Chervil, North Herald and South Pepper
Airlie Island | oil
TL/2 TP/7(Pts 1-3) TP/7 (Pt 4)
Apache Oil Australia Pty
Limited (Operator) 51.834% 39.658% 64.658%
Pan Pacific Petroleum NL 23.166% 4.157% 4.157%
Santos Limited
Mobil Exploration & Producing
15.000% 43.711% 18.711%
Australia Pty Ltd 10.000% 12.474% 12.474%
Contact
Apache Energy Limited
Level 3, 256 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9422 7222 • Fax: +61 8 9422 7447
Web: www.apachecorp.com
Production – Oil (bbl)
Field 2001 2002
Chervil 85 334 3 928
Cadell
The Cadell 1 well, located 7 km from
Airlie Island in TP/7, intersected a
75 m gas column in November 1999.
The joint venture estimates that the
field contains gas reserves of
0.5–1 Bcm (20–40 Bcf). Subject to
further detailed analysis, Cadell is
unlikely to be economic for a standalone
development.
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 19
project details

Athena | gas and condensate
Location
134 km northwest of Dampier
Basin,
Carnarvon, offshore
Permit/Licence
WA-248-P, WA-17-L
Ownership
Mobil Exploration & Producing Australia Pty Ltd (Operator) 50%
Phillips Oil Company Australia 50%
Contact
Mobil Exploration & Producing Australia Pty Ltd
12 Riverside Quay
SOUTHBANK VIC 3006
Tel: +61 3 9270 3333 • Fax: +61 3 9270 3493
Web: www.exxonmobil.com
project details | OPERAT ING PROJECTS
Production of gas and condensate from the Athena
field will be from the North Rankin A facility.
20 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
The Athena field was discovered
in October 1997 and is an
extension of the North West
Shelf Gas project’s Perseus gas field.
The Athena 1 well was drilled in a
water depth of 120 m and reached a
total depth of 3364 m. The well was
tested over four zones and achieved a
combined flow rate of 1340 kcm/d
(47.4 MMcf/d) of gas and 2133 bbl/d
of condensate. A production licence
over the Athena field was awarded in
January 1999.
In early March 2001 Mobil Australia
Resources Company Pty Ltd and
Phillips Australia Gas Holdings Pty
Ltd signed an agreement with the
North West Shelf Venture participants
in relation to the development of the
Perseus–Athena gas field. Under the
agreement, Woodside, as operator of
the North West Shelf Venture, will
produce gas from the WA-17-L permit
on behalf of the permit holders.
Production will be through the North
Rankin A production facility and the
term of the contract is for the life of
the Perseus field.
The Athena field commenced
production in late 2001.

The Barrow Island oil field was
discovered in July 1964 beneath
the 233 km2 island and is the
largest oil field discovered in Western
Australia. Production commenced in
April 1967 and peaked at
50 000 bbl/d in 1971. Barrow Island
was originally envisaged to have a
30-year life, but as a result of careful
management of the reservoirs using
more than 800 oil and water-injection
wells, the life of the field has been
extended until 2019. The joint venture
estimates that the field will have
produced 330 MMbbl of oil by 2019,
approximately a third of the known
oil-in-place.
In February 2000, Chevron Australia
assumed the operatorship of Barrow
Island from West Australian Petroleum
Pty Ltd (WAPET) and in 2001 Shell
Development (Australia) Pty Ltd
completed the sale process of its
Barrow exploration and production
assets to Santos Offshore Pty Ltd. In
October 2001, Chevron and Texaco
merged to form ChevronTexaco
Corporation. This resulted in a
majority-combined interest in the
Barrow Island assets. In 2002,
Chevron Australia Pty Ltd changed its
name to ChevronTexaco Australia Pty
Ltd, by registration at the Australian
Securities and Investment
Commission.
Production facilities
Barrow Island currently consists of
454 oil production wells (mostly in
the Windalia reservoir), 271 waterinjection
wells, and a number of gas
producer and water disposal wells. In
the majority of producing wells, oil is
pumped to the surface using beam
pumps (nodding donkeys). The
remaining producing wells use gas-lift
or are on natural flow.
The fluids produced from each well
are piped to one of ten separator
stations, each capable of handling up
to 60 wells. A typical separator station
has an oil storage tank and a tank in
which produced water settles before
being piped to a deepwater disposal
facility for re-injection into reservoirs.
Location
88 km north of Onslow
Basin
Carnarvon, onshore and offshore
OPERATING PROJECTS |
Barrow Island | oil
Permit/Licence
L1H, WA-7-L, L10, TL/3, TPL/9
EP 61, EP 62, TP/2
Ownership
ChevronTexaco Australia Pty Ltd (Operator) 28.57%
Texaco Australia Pty Ltd 28.57%
Santos Offshore Pty Ltd 28.57%
Mobil Australia Resources Company Pty Ltd 14.29%
Contact
ChevronTexaco Australia Pty Ltd
Level 24, QV1 Building
250 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9216 4000 • Fax: +61 8 9216 4444
Web: www.chevrontexaco.com
Production
2001 2002
Oil (bbl) 3 839 470 3 580 931
Average oil production (bbl/d)
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
Barrow Island
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
Clean oil is pumped from the stations
to the main oil storage facility,
comprising five 200 000-barrel oil
tanks. At present, only three of the
tanks are in service. The oil (37.7° API
gravity) is then transported via a
508 mm, 10.4-km submarine pipeline
to an offshore mooring system, where
tankers are berthed for loading.
In February 1999, the joint venture
announced that the facilities on
Barrow Island could be utilised by
third parties for processing oil and gas
production from nearby operations.
Reservoirs
Barrow Island contains at least 30
different reservoirs of oil and gas.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 21
project details

| OPERATING PROJECTS
Barrow Island | oil
Currently there are eight oil
producing formations, with the
Windalia reservoir containing 95% of
known reserves. All producing
reservoirs were recently assessed as
part of the Barrow Island
Development Plan, a multidisciplinary
study aimed at optimising
well production performance and
increasing the mature field’s reserves.
The three-year study included recompletions,
additional infill and
extension drilling, workovers,
refracture stimulation, artificial lift
optimisation and facility expansion.
Production from the Windalia
reservoir is by way of secondary
recovery conditions known as “waterflooding”.
Water is injected into more
than 270 wells to displace oil towards
producing wells. The joint venture
estimates that about 540 MMbbl of
oil remains in the ground, and while
some will be recovered with the
existing water-flood technique, it
presents a major challenge to develop
innovative tertiary recovery
techniques. Non-water-flood reserve
potential is also under review and
includes the Windalia extension areas
around the flanks of the field, as well
as the development potential in other
reservoirs under Barrow Island.
Development and
exploration drilling
Since 1995, a total of 76 infill wells
have been drilled in Windalia
reservoir on Barrow Island, and waterinjection
volumes increased from less
than 50 000 bbl/d to in excess of
90 000 bbl/d. These strategies are
designed to increase the field life and
enhance oil recovery from the
reservoir.
Reprocessed 3D seismic data in the
northern Barrow Island area around
the Obiwan oil field was reinterpreted
during 2002. The
prospect portfolio for the northern
part of the field is being updated and
exploration opportunities are being
considered for inclusion in the 2004-
2005 exploration plan.
22 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Oil-gathering station on Barrow Island.
Revegetation at the edge of a production well on Barrow Island.

The Beharra Springs field was
discovered in April 1990 and
commenced production in January
1991 using a temporary production
facility. The field operates with three
producing wells.
Production facilities
A $9.4 million permanent gas-processing
plant, with a capacity of 15 TJ/d, was
commissioned in May 1992 and replaced
the temporary facility. Plant capacity was
increased to 25 TJ/d following the
completion of a $2.2 million expansion
in November 1993. Compression
facilities were commissioned in 1996 at a
cost of $8 million. Production rates in
excess of 30 TJ/d have been achieved
through the more efficient use of existing
equipment.
The gas-processing plant features low
temperature separation for the removal of
condensate and water from the natural
gas. In addition, semi-permeable
membranes purify the gas for sale by
removing carbon dioxide and hydrogen
sulphide. Treated gas is pumped via a
168 mm, 1.6 km pipeline lateral into the
Parmelia pipeline and is then transported
to customers, south of Perth. Condensate
(62° API gravity) is stored in a 600-barrel
tank and is then trucked to the BP
refinery in Kwinana for processing.
Gas sales contract
An initial gas sales contract with Alcoa
was signed in 1990 for the supply of up
to 39.5 PJ of gas at rates of up to 15 TJ/d
from January 1991 to January 2002. A
second contract with Alcoa was signed in
April 1991 for additional gas supplies of
up to 40.5 PJ from January 1996. It was
also agreed that Alcoa could accelerate
its gas offtake to up to 25 TJ/d over the
initial period. As a result, total gas sales
far exceeded the contractual take-or-pay
requirement since mid-1992. In 1998,
Alcoa chose to cut its offtake to 8 TJ/d.
Following a re-negotiation of the Gas
Sales contract in late 1999, this offtake
increased and was maintained at
17.5 TJ/d for most of 2000. This contract
expired in January 2002. A new
arrangement with Alcoa commenced in
May 2002 to supply gas at rates up to
8 TJ/d to the end of 2003.
Average condensate production (bbl/d)
OPERATING PROJECTS |
Beharra Springs | gas and condensate
Location
350 km north of Perth
Basin
Perth, onshore
Permit/Licence
EP320, L11, PL/18
Ownership
Origin Energy Developments Pty Ltd (Operator) 67%
Australian Worldwide Exploration Limited 33%
Contact
Origin Energy Developments Pty Ltd
34 Colin Street
WEST PERTH WA 6005
Tel: +61 8 9324 6111 • Fax: +61 8 9321 5457
Web: www.originenergy.com.au
Production
2001 2002
Gas (kcm) 141 779 97 773
Condensate (bbl) 7 131 6 548
120
100
80
60
40
20
Condensate
Gas
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
Gas sales contracts are also held with
Origin Energy Retail and Hardman
Resources.
Exploration drilling
The Mungenooka 1 well, located
10 km northeast of Beharra Springs,
was drilled in June 1998 and
intersected a tight gas column. The
well was plugged and suspended for
possible re-entry, however a reevaluation
of well results concluded
that the commercial potential was
minimal. The well was plugged and
abandoned in July 2000.
Beharra Springs
1,200
1,000
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 23
800
600
400
200
A 3D seismic survey covering the L11
licence area and parts of the surrounding
EP320 permit was completed in August
1999. On the basis of this data Beharra
Springs North 1 and South 1 were drilled
in the second half of 2001. Beharra
Springs North 1 intersected a gross gas
column of 28 m. Subsequent testing of
the well produced gas flow rates of up to
30 MMcf/d.
Beharra Springs South 1 was plugged
and abandoned. Beharra Springs North
1 commenced production in August
2002.
0
Average gas production (kcm/d)
project details

Blina–Boundary–Lloyd–Sundown–West Terrace | oil
Location
80 km east of Derby
Basin
Canning, onshore
Permit/Licence
EP129, L6,L8, PL/7
Ownership
Producing Fields
Kimberley Oil NL 100%
Deep Rights Area
Kimberley Oil NL 100%
Contacts
Kimberley Oil NL
Suite 12B, 573 Canning Hwy
ALFRED COVE WA 6154
Tel: +61 8 9330 8876 • Fax: +61 8 9330 8896
Email: ko@iinet.net.au
Production — Oil (bbl)
Field 2001 2002
project details | OPERAT ING PROJECTS
Average oil production (bbl/d)
Blina 17 486 11 666
Boundary 3 356 2 193
Lloyd 3 095 1 860
Sundown 3 648 3 012
West Terrace 4 899 8 961
TOTAL 32 485 27 692
450
400
350
300
250
200
150
100
50
Blina–Boundary–Lloyd–Sundown–West Terrace
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
24 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Kimberley Oil took over as
operators and interests in the
exploration and production
licences covering the
Blina–Boundary–Lloyd–Sundown–
West Terrace fields from Capital
Energy in March 1999. Kimberley Oil
also took over the direct management
of the operations from Gearhart
Australia Ltd in December 1999.
Production facilities
The Blina field produces into the
Blina Battery where the oil and water
are separated, and the oil is stored in
two tanks. It is then transported via a
114 mm, 29 km underground
pipeline to the Erskine truck-loading
terminal on the Great Northern
Highway for storage in two tanks. The
other fields produce oil via well
flowlines into the Meda Battery,
which consists of four storage tanks.
Oil (30–38° API gravity) from the
Erskine Terminal and Meda Battery is
transported by trucks 220 km to
Broome where it is stored in a
120 000-barrel tank.
PRODUCING FIELDS
Kimberley Oil considers that the areas
in and around the existing fields
present opportunities for further
commercial accumulations. As a
result, work is continuing to delineate
potential prospects for drilling in
2003. Infrastructure is in place, which
will allow any new discovery to be
brought on-stream quickly and
economically.
Blina
The Blina field, located 105 km
southeast of Derby, was discovered in
May 1981 and commenced
production in September 1983. Eight
wells have been drilled in the field,
three of which are currently
producing.

The Operator is currently looking at
ways of increasing production from
inactive wells in the field by
perforating oil-bearing zones, which
were not properly tested, or never
tested at all during the original
production phase. There appears to
be the potential for by-passed oil in
the main reservoir, the Nullara
Limestone, because of very restricted
perforation intervals in the original
wells, and for production from the
secondary reservoir, the Yellowdrum
Dolomite, which has been produced
in only two wells to date.
Furthermore, the field has only been
drilled on its southwestern flank, and
there are no wells on the northeastern
flank, and therefore, no confirmation
that the current drilling has penetrated
the highest point on the structure.
Sundown
The Sundown field, located 26 km
northwest of Blina, was discovered in
November 1982 and commenced
production in July 1984. Sundown is
currently producing from one well
only, Sundown 3H.
West Terrace
Located 8 km north of Sundown, the
West Terrace field commenced
production in June 1985 from one
well. A second well was drilled and
produced oil for a short time in 1987
before being abandoned because of
what was considered then to be
excessive water cut. The well was
brought back on production in 2001
and is now out-producing West
Terrace 1.
Lloyd
The Lloyd field, located 30 km from
Blina, was discovered in July 1987
and commenced production a month
later from one well. A second well,
Lloyd 3, was put on an extended test
in August 1998 and significantly
increased the output from the field.
Lloyd 3 has now ceased production.
Boundary
Located 2.2 km south of Lloyd, the
Boundary field was discovered in
August 1990 and commenced
production in December 1990 from
one well.
OTHER PROSPECTS
The joint venture is currently
assessing the further potential of the
area, including a dolomite section in
the Janpam North 1 well. At the time
of its drilling, a drill stem test (DST) of
this zone recovered 2.5 bbl of 23° API
gravity oil. Following acid stimulation,
the well produced 50 bbl of oil over
five days. It is believed the zone is
equivalent to the main producer in
the Blina field. The Janpam North 1
well is currently under consideration
as a candidate for re-entry to test the
zone.
Kimberley Oil’s rig 6.
OPERATING PROJECTS |
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 25
project details

Buffalo | oil
Location
560 km northwest of Darwin
Basin
Bonaparte, offshore
Permit/Licence
WA-19-L, WA-21-L
Ownership
Nexen Petroleum Australia Pty Limited 100%
Contact
Nexen Petroleum Australia Pty Limited
Level 18
44 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9218 8911 • Fax: +61 8 9218 8922
Web: www.nexeninc.com
Production
project details | OPERAT ING PROJECTS
Average oil production (bbl/d)
2001 2002
Oil (bbl) 3 739 078 4 700 000
50,000
40,000
30,000
20,000
10,000
Buffalo
0
Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02
26 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
The Buffalo oil field, located
9 km southeast of Laminaria in
the Timor Sea, was discovered
in October 1996 and commenced
production in December 1999. It is
estimated that the field contains
proven and probable oil reserves of
around 15–20 MMbbl. Buffalo crude
is a light oil (53.3° API gravity) with a
gas-oil ratio of 3.4 m3/bbl (120 cubic
feet per barrel).
Nexen Petroleum Australia Pty
Limited (formerly Canadian Petroleum
Australia (Operations) Pty Ltd) is now
the 100% operator of the field
effective from 1 July 2001.
Production facilities
Field development utilises four wells
on a five-slot unmanned wellhead
platform, linked to a permanently
moored floating production storage
and offloading (FPSO) facility, the
Buffalo Venture. The platform is
situated on top of a shallow bank in
27 m of water and is operated by
remote control from the FPSO,
located 2 km away in 300 m of water.
The 103 000 dwt vessel is operated
by Nexen and is leased from Modec
Inc. (part of the Mitsui group). It is
designed to separate the oil, gas and
water, fully stabilise the oil, provide
gas-lift, fully treat and discharge
produced water, and flare quantities
of excess gas not consumed by the
system. The FPSO has a storage
capacity of 725 000 bbl of oil which
is offloaded to shuttle tankers.
Initial oil production peaked at
52 000 bbl/d and current oil rates are
around 10 000 bbl/d.
Nexen drilled two development wells
in the second quarter of 2002, which
gave a significant production
increase.

OPERATING PROJECTS |
Dongara–Mondarra–Yardarino | gas, oil and condensate
The Yardarino field was the first
field discovered in the North
Perth Basin in May 1964 and
was followed by discoveries at
Dongara in June 1966 and Mondarra
in 1968. First gas deliveries from the
Dongara field commenced in October
1971 via the Parmelia pipeline. The
Mondarra field commenced deliveries
in April 1972 and ceased production
in July 1994. The Yardarino field came
on-stream in October 1978 and
ceased production in April 1989. ARC
Energy drilled an unsuccessful well at
Yardarino in mid-2001.
Production and
transportation facilities
Twenty-nine wells have been drilled
on, or near, the Dongara field of
which eight are currently in
production. Gas from these wells is
transported by flowlines to gasprocessing
facilities and, after
treatment to remove liquids, is
compressed and sent down the
Parmelia pipeline.
CMS Gas Transmission of Australia
owns and operates the gas-processing
facilities and is responsible for
transportation of the processed gas to
sales outlets via the Parmelia pipeline.
ARC Energy owns the Dongara field
(L/1 and L/2) and has an agreement
with CMS for it to process and
transport its gas at an agreed toll fee.
The gas-processing plant includes
three-stage gas compression, primary
fluid separation and glycol
dehydration, a water treatment and
disposal plant, an oil/condensate
storage and loading plant, and welltesting
equipment. The 350 mm,
420 km high-pressure Parmelia
pipeline, which extends from
Dongara to Pinjarra, has a design gas
capacity of around 124 TJ/d and
currently transports about 30 TJ/d.
Gas reserves
ARC Energy maintains a program of
well pressure testing and reservoir
simulation. Using this data, the
remaining proven, plus probable,
Average oil and condensate production (bbl/d)
Location
65 km south of Geraldton
Basin
Perth, onshore
Permit/Licence
L/1, L/2, PL/1, PL/2, PL/3, PL/5, PL/23
Ownership/Contact
Production Licences
ARC Energy NL (Operator) 100%
46 Ord Street
WEST PERTH WA 6005
Tel: +61 8 9486 7333 • Fax: +61 8 9486 7322
Email: arc@arcenergy.com.au
Web: www.arcenergy.com.au
Pipeline Licences, Gas-processing Facilities, Mondarra Storage Facility
CMS Gas Transmission of Australia (Operator) 100%
8 Marchesi Street
KEWDALE WA 6105
Tel: +61 8 9353 7500 • Fax: +61 8 9353 2452
Email: acmswa@cmsenergy.com.au
Web: www.cmsenergy.com.au
Production — Dongara
2001 2002
Gas (kcm) 63 785 43 355
Oil (bbl) 3 908 3 876
Condensate (bbl) 2 048 1 277
100
80
60
40
20
Dongara
Oil and condensate
Gas
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 27
600
500
400
300
200
100
0
Average gas production (kcm/d)
project details

| OPERATING PROJECTS
Dongara–Mondarra–Yardarino | gas, oil and condensate
economically recoverable reserves of
sales gas in the Dongara and
Yardarino fields have been
independently estimated to be in
excess of 19 PJ. Maintaining field
production will require an ongoing
program of well workovers and new
wells. ARC Energy installed a
wellhead compressor on the Dongara
18 well during 2002 to assist in
ultimate reserve recovery.
Gas sales contracts
ARC Energy currently supplies gas to
Midland Brick and other industrial
companies in Perth, and commenced
sales of gas to another industrial
customer in January 2002.
Dongara is currently producing at full
capacity and additional gas sales are
dependent on the success of well
workovers and development and
exploration drilling.
Exploration drilling
No further exploration drilling has
been carried out in the field area.
Work has concentrated on the
development of the Hovea oil field.
However, an active exploration
program is planned for the area
following the success at Hovea and
the nearby Jingemia oil discovery in
the adjacent EP413 permit.
Oil potential
In March 1999, ARC Energy entered
into a Heads of Agreement with
Amalgamated Scottish Oil Ltd
(AMSOL) for the production of oil in
the Dongara field, estimated to be in
excess of 100 MMbbl of oil-in-place.
After the failure of the Dongara 29/30
to provide a definitive answer
regarding recoverabilities, ARC is
currently carrying out a detailed
evaluation of the field using the
results of the full-field reservoir
simulation.
Mondarra gas storage
facility
The depleted Mondarra field was
retained by CMS at the time of the
sale of the Dongara and Yardarino
fields to ARC Energy, in order for it to
be developed as the Mondarra gas
storage facility.
CMS is continuing to evaluate the
commercial and technical feasibility
of developing the depleted Mondarra
field into a natural gas storage facility
for service in the Western Australian
natural gas industry. The Mondarra
field is considered well suited as a gas
storage facility due to its close
proximity to both the Dampier to
Bunbury Natural Gas pipeline
(DBNGP) and the Parmelia pipeline.
Part of Dongara’s gas-processing facilities
28 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003

The East Spar field was discovered
in April 1993 and commenced
production in November 1996.
The field is expected to have an
operating life of 20 years and can
produce gas at peak rates of 120 TJ/d.
Total capital cost of the development
was $250 million.
Production facilities
East Spar comprises Australia’s first
fully-automated all subsea production
and gathering system operated via an
unmanned navigation control and
communication (NCC) buoy.
Controlling an entire subsea facility via
an unmanned NCC buoy is a worldfirst.
Electro-hydraulic umbilicals
connect the buoy to all control and
monitoring devices on the subsea
components. A telemetry
communication system, with radio and
satellite links, allows the remote
control of the offshore facilities from a
computerised master control system on
Varanus Island. The buoy also includes
chemical storage for corrosion and
hydrate inhibitors, which are injected
via umbilicals into the wellheads.
Gas and condensate are currently
produced from two wells, which, after
cooling in heat exchangers is conveyed
to a manifold via 1.8 km, 150 mm
flexible flowlines. Provision for the tiein
of two further wells and a future
pipeline from another field is included
in the manifold design. The combined
wet gas production fluid is transported
from the manifold via a 356 mm,
63 km carbon steel pipeline to
processing facilities on Varanus Island.
Varanus Island processing
facilities
In November 1996, two 120 TJ/d gasprocessing
trains were commissioned
on Varanus Island adjacent to the two
existing 60 TJ/d trains used by the
Harriet joint venture. The processing
trains remove condensate, water and
other minor impurities from the gas,
conditioning it to pipeline
specifications. Sales gas is then
transported to the mainland through
either of two 100 km sales gas
pipelines (324 or 406 mm) connecting
Average condensate production (bbl/d)
OPERATING PROJECTS |
East Spar | gas and condensate
Location
40 km west-northwest of Barrow Island
Basin
Carnarvon, offshore
Permit/Licence
WA-214-P, WA-13-L, WA-5-PL, TPL/12, TPL/13, PL/29, PL/30, PL/42
Ownership
Apache Oil Australia Pty Ltd (Operator) 55%
Santos Limited 45%
Contact
Apache Energy Ltd
Level 3 256 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9422 7222 • Fax: +61 8 9422 7447
Web: www.apachecorp.com
Production
2001 2002
Gas (kcm) 1 081 226 1 153 793
Condensate (bbl) 2 367 874 2 366 346
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
Condensate
Gas
0
Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
with the DBNGP and Goldfields gas
transmission (GGT) pipeline at
Compressor Station No.1. The
406 mm gas pipeline, with a capacity
in excess of 300 TJ/d, was
commissioned by the East Spar (70%)
and Harriet (30%) joint ventures in
July 1999. Condensate (58° API
gravity) is stored in existing tanks on
Varanus Island and exported via
tanker.
The East Spar and Harriet joint
ventures entered into an
infrastructure-sharing agreement in
East Spar
4,000
3,500
3,000
2,500
2,000
1,500
1,000
January 1997 whereby the Harriet gas
transportation and liquids storage
facilities on Varanus Island could be
utilised by the East Spar joint venture.
In addition, the two joint ventures
agreed to share the cost of all
operating resources and contract
services such as supply boats and
helicopters. This was the first
infrastructure-sharing agreement made
in the North West Shelf gas province.
Initial proven gas reserves are
estimated to be around 13 Bcm
(535 Bcf).
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 29
500
0
Average gas production (kcm/d)
project details

Griffin–Chinook–Scindian | oil and gas
Location
68 km northwest of Onslow
Basin
Carnarvon, offshore
Permit/Licence
WA-210-P, WA-10-L, WA-3-PL, TPL/10, PL/20
Ownership
BHP Billiton Petroleum (Australia) Pty Ltd (Operator) 45%
Mobil Exploration & Producing Australia Pty Ltd 35%
Inpex Alpha Ltd 20%
Contact
BHP Billiton Petroleum Pty Ltd
Level 42, Central Park
152-158 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9278 4888 • Fax: +61 8 9278 4899
Web: www.bhpbilliton.com
Production
project details | OPERAT ING PROJECTS
Average oil production (bbl/d)
Oil (bbl) Gas (kcm)
Field 2001 2002 2001 2002
Griffin 9 008 210 8 035 899 113 007 98 467
Chinook–Scindian 2 902 886 5 133 625 198 822 239 155
TOTAL 11 911 096 13 169 524 311 829 337 622
90,000
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
Griffin–Chinook–Scindian
Oil Gas
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
1,600
1,400
1,200
1,000
30 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
800
600
400
200
0
Average gas production (kcm/d)
The Griffin oil and associated gas
development comprises the
Griffin and Chinook–Scindian
fields which were discovered in
1989-90. First oil production from
Griffin commenced in January 1994,
with production from
Chinook–Scindian starting in March
1994.
Initial recoverable oil reserves were
estimated at 115–130 MMbbl, which
is expected to yield a production life
of 10–15 years. Total capital cost of
the development was $600 million.
Production facilities
The Griffin development utilises the
100 000 dwt double-hulled Griffin
Venture FPSO, which comprises a
disconnectable mooring riser and
production system. All production is
from subsea-well completions linked
back to the centrally located FPSO via
flexible flowlines. The vessel and its
mooring riser system are configured
to accommodate a total of 11
production wells. The FPSO stores up
to 820 000 bbl of oil, which is then
pumped to stern-moored offtake
tankers through a floating hose system
at a rate of 2500 bbl per hour.
Cargoes of the light Griffin crude
(55° API gravity) are sold to markets
in Australia, Singapore and Japan.
Gas-processing facilities
The Griffin Venture also has gasprocessing
facilities on board which
makes commercial use of the
associated gas produced with the oil.
This gas is either sold into the
domestic gas pipeline system, used as
gas-lift or used as fuel on the FPSO,
except when safety dictates that
flaring is necessary.
Gas is transported from the FPSO to
shore via a 200 mm, 68 km pipeline.
Up until January 2001 Griffin Gas
was processed at the Griffin Gas
Treatment Plant. Located about
30 km southwest of Onslow, the plant
commenced full operations in
November 1994. It processed the
gas-to-sales-specification standards by
removing unwanted inert gases, such

as nitrogen and carbon dioxide, and
other contaminants. The LPG
component (up to 68 t/d) was
separated and transported to a
loading terminal at Onslow via a
50 mm, 24 km pipeline and it was
then sold by Wesfarmers Kleenheat
Gas Pty Ltd into the domestic market.
The Griffin Joint Venture recently
entered into a blending arrangement
with Epic Energy (operator of the
DBNGP) to blend Griffin Gas into the
DBNGP without the need to process
the gas. Accordingly, from February
2001 onwards the majority of the
Griffin Gas Treatment Plant was to be
bypassed and the facility eventually
decommissioned and mothballed.
The LPG agreement with Wesfarmers
Kleenheat Gas Pty Ltd has been
terminated and the LPGs will remain
within the gas stream. Wesfarmers
will extract the LPGs at Kwinana. All
other sales agreements remain in
place.
Up to 40 TJ/d of sales gas is metered
and sold to the Tubridgi joint venture.
It is then delivered into the DBNGP
via a 250 mm, 90 km pipeline and
on-sold into the domestic gas market.
Alcoa is committed to purchase at
least 25 TJ/d under a 10-year take-orpay
contract ending in December
2004.
Additional drilling
On 28 November 2001 the Griffin
Joint Venture drilled Griffin 9. The
well added 25 000 bbl/d to Griffin
production and increased the field
reserves.
The Griffin Venture FPSO is configured to accommodate 11
production wells.
OPERATING PROJECTS |
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 31

Harriet area fields | gas, oil and condensate
Location
120 km west of Dampier
Basin
Carnarvon, offshore
Permit/Licence
TL/1, TL/5, TL/6, TL/8, TP/8, TPL/1, TPL/2, TPL/5, TPL/8,TPL/13, PL/12, PL/17,
PL/42
Ownership
Apache Northwest Pty Ltd (Operator) 68.5000%
Kufpec Australia Pty Ltd 19.2771%
Tap (Harriet) Pty Ltd 12.2229%
Contact
Apache Energy Ltd
Level 3
256 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9422 7222 • Fax: +61 8 9422 7447
Web: www.apachecorp.com
project details | OPERAT ING PROJECTS
Production
Field Gas (kcm) Oil (bbl) Condensate (bbl)
2001 2002 2001 2002 2001 2002
Agincourt 4 124 3 122 428 419 98 805 1 995 1 992
Campbell 196 840 267 933 - - 171 692 221 901
Endymion - 21 085 - - - 20 913
Gibson - 1 505 - 168 070 - 269
Gipsy 51 910 11 144 1 318 576 505 408 12 703 1 776
Harriet 10 633 12 591 302 467 412 334 3 288 2 258
Little Sandy - 610 - 73 628 - 455
North Gipsy 77 318 864 627 065 27 953 35 323 154
Pedirka - 1 081 - 201 265 - 807
Rosette 10 051 51 452 - - 3 559 37 552
Simpson 3 104 24 714 665 348 3 063 131 2 093 17 174
Sinbad 247 623 25 607 - - 165 411 18 176
South Plato - 6 888 - 953 301 - 1 244
Tanami 5 891 4 429 216 700 212 760 3 179 2 952
Victoria - 1 052 - 73 027 - 795
Wonnich 388 158 506 489 - - 270 750 382 434
TOTAL 995 653 940 674 3 558 575 5 789 682 669 992 710 853
32 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Varanus Island provides the base
for the Harriet gas-gathering
and oil export projects, which
currently involve production from the
Harriet, Tanami, Campbell, Sinbad,
Rosette, Gipsy–North Gipsy,
Agincourt, Wonnich and Simpson
fields. The island infrastructure
includes oil-processing facilities, three
250 000 bbl oil tanks, a twin-train
low temperature separation gas plant,
two 60 TJ/d gas-processing trains, gas
compression units, water treatment
and disposal facilities, pipelines, a
power station and gas turbine
generators. In addition, two 120 TJ/d
gas-processing trains were
commissioned on the island in
November 1996 as part of the East
Spar gas development.
In January 1997, the Harriet joint
venture entered into an infrastructure
sharing agreement with the East Spar
joint venture. Under the agreement,
the Harriet joint venture will provide
gas transportation and liquids storage
services for the East Spar gas field
utilising existing Harriet facilities on
Varanus Island. In addition, the two
joint ventures agreed to share the cost
of all operating resources and contract
services such as supply boats and
helicopters.
Production operations
The oil project commenced in January
1986 and currently involves the
transport of oil and condensate from
the Harriet, Tanami and Agincourt
fields, as well as condensate from the
gas fields, to Varanus Island where it
is processed and stored. A 762 mm,
3.5 km subsea pipeline then transfers
the commingled crude to offshore
tankers berthed at an eight-point
spread mooring system. The crude
(38–48° API gravity) is sold to
refineries in Australia and overseas.
The $150 million Harriet gasgathering
project was commissioned
in July 1992 and was Western
Australia’s first offshore gas project to
tap associated gas, which is produced
during the oil recovery process. The
project currently involves the
transport of gas from the Campbell,

Average condensate production (bbl/d)
25,000
20,000
15,000
10,000
5,000
Harriet area fields
Oil and Condensate Gas
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
Rosette, Sinbad and Wonnich fields,
as well as associated gas from the oil
fields, to Varanus Island.
The separation gas plant removes
water, excess natural gas liquids and
other minor impurities from the
gathered gas, conditioning it to
pipeline specifications. Separated
liquids are then commingled with the
crude oil. Sales gas is transported
through either of two 100 km
pipelines (324 or 406 mm)
connecting with the DBNGP and
GGT pipeline at Compressor Station
No.1. The 406 mm gas pipeline, with
a capacity in excess of 300 TJ/d, was
commissioned by the Harriet (30%)
and East Spar (70%) joint ventures in
July 1999.
Harriet
Harriet was discovered in November
1983 and became the first offshore oil
producer in Western Australia when
production commenced in January
1986. The field currently produces
from 15 wells, which are linked to a
fixed platform (Harriet A) and two
offshore fixed monopods (Harriet B
and C). Crude oil flows from the
Harriet A platform through a 219 mm,
6.5 km subsea pipeline to Varanus
Island while associated gas is
transported via a 168 mm, 6.5 km
subsea gas pipeline.
3,500
2,800
2,100
1,400
700
In July 1999, the North Harriet 1 well
intersected a 8.7 m net hydrocarbon
column including 6 m of oil. The well
confirmed the existence of oil in the
northern area of the Harriet field. This
oil is now being developed by the
Harriet B-5H well which commenced
production in September 1999.
The joint venture plans to drill an
infill production well to establish the
existence of an undrained oil pool
lying between the Harriet A and C
platforms.
Tanami
The Tanami 1 well was directionally
drilled from Varanus Island in July
1991 and commenced production
under an extended test in October
1991. Production facilities were
installed in December 1993. Tanami
6 was drilled and completed in
October 2002 as the second drainage
point.
Campbell
Located 25 km north-northeast of the
Harriet A platform, the Campbell gas
field was discovered in 1979 and
commenced production in October
1992. The field produces through two
wells linked to an offshore fixed
monopod, situated in 40 m of water.
0
Average gas production (kcm/d)
OPERATING PROJECTS |
Sinbad
The Sinbad gas field, located 16 km
northeast of Harriet A, was discovered
in 1990 and commenced production
in November 1992. The field operates
with two wells which are linked to an
offshore fixed monopod.
Gas and condensate from the
Campbell and Sinbad fields are
transported to Varanus Island via
324 mm, 30 km gas-gathering
pipelines.
Rosette
The original Rosette well was
directionally drilled to the west from
Varanus Island in 1987. The field
commenced a production test as an
oil field in April 1988 but ceased
production in September 1988 after
producing 6900 bbl of oil. Rosette
recommenced production as a gas
field in July 1992. A workover was
successfully conducted on the Rosette
well during 1999 that substantially
increased production from the field.
The Rosette field watered out in
November 2002. Rosette 1 will be
converted into a water disposal well.
Gipsy–North Gipsy
The Gipsy oil and North Gipsy oil-gas
fields are part of the
Rose–Lee–Gipsy–North Gipsy group
of fields. They have hydrocarbon
reservoirs in up to four separate units
— the North Rankin Formation, the
Brigadier Formation and the
Mungaroo A and B units. The
reservoirs are highly faulted and the
gas-water and oil-water contacts vary
significantly between the fields. The
fields were developed using subsea
horizontal wells and they came on
production in February 2001.
Agincourt
Agincourt was discovered in June
1996 and commenced production in
August 1997 at a total cost of around
$33 million. The joint venture
estimates that the field contains
around 3.5 MMbbl of recoverable oil
reserves and is expected to have an
operating life of around 7–10 years.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 33

| OPERATING PROJECTS
Harriet area fields | gas, oil and condensate
Current production is from one
horizontal well linked to an
unmanned offshore monopod. The
platform has been designed to support
up to three wells. A 150 mm, 6.5 km
pipeline transports oil, condensate
and gas to facilities on Varanus Island.
Gas is compressed for access to the
separation gas plant. It is also used for
Agincourt lift gas which is transported
back to the monopod via a 100 mm,
6.5 km gas-lift pipeline. No flaring of
the associated gas occurs unless
required for an emergency.
Wonnich
Wonnich was discovered in August
1995 and commenced production in
July 1999 utilising one well linked to
an unmanned monopod. The platform
lies in 30 m of water and has been
designed to support up to four wells.
The field can produce gas at a rate of
up to 80 TJ/d. Gas and condensate is
transported 33 km to the separation
gas plant on Varanus Island via two
200 mm pipelines. Total capital cost
of the development was about $60
million.
The joint venture estimates proven
and probable reserves to be 186 PJ of
gas and 2.8 MMbbl of condensate,
which is expected to provide a field
life of around 20 years.
Simpson
The Simpson oil field was discovered
in June 2000 by Tanami 4 well which
was intended to be an exploration/
appraisal well in the nearby Tanami
field. Tanami 4 encountered a 17.5 m
gross oil column and is quite clearly
located in a separate accumulation
from the main Tanami field.
The Simpson 1 appraisal well was
drilled in February 2001 and
encountered a 33.5 m gross oil
column. Simpson 1 and Tanami 4 are
located in the same oil accumulation,
which has been named the Simpson
field. Both wells have been
completed as production wells.
Simpson 2 appraisal well was drilled
in March 2001 and encountered an
oil-water contact similar to Simpson 1
well. The well increased the proven
bulk rock value considerably from
that established by Tanami 4 and
Simpson 1 wells.
The Simpson field was developed in
November 2001 utilising Tanami 4
and Simpson 1 plus one 500 m long
horizontal well, Simpson 3H, located
southwest of Simpson 1 with the toe
of the well located near the Simpson
2 pilot hole location. Simpson 3H
watered out in July 2002 and was
followed by the drilling and
completion of Simpson 4H and South
Simpson 1 wells.
Simpson 1 has produced a total of
2.02 MMbbl as at end December
2002 with an end month water-cut of
90%. Simpson 3H watered out in
July 2002 after a total production of
only 0.40 MMbbl. Simpson 4H was
drilled and completed in August 2002
and has produced a total of
0.62 MMbbl of oil. Tanami 4 has
produced a total of 0.57 MMbbl as at
the end of December 2002 with an
end-month oil rate of about 800 bbl/d
and water-cut of 77%.
South Simpson 1 drilled and
completed in October 2002 has
produced a total of 0.12 MMbbl of
oil.
Recent reservoir simulation modelling
of the Simpson field predicts that the
existing five wells in the Simpson field
will recover about 5.8 MMbbl of oil
and that an additional four infill wells
will increase the ultimate oil recovery
from the field to 13.7 MMbbl. The
first two of these infill wells will be
drilled in the first quarter of 2003.
Alkimos
The Alkimos 1 deviated well was
drilled from Varanus Island in August
1994 and was completed as an oil
producer a month later. In November
1995, Alkimos was re-completed as a
gas producer and produced almost
120 000 kcm until being shut down
in March 1997.
Endymion
The Endymion field was discovered in
34 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
October 2002 by Endymion 1, which
encountered a 20.6 m gross gas
column in the Flag Sandstone
Formation with an average porosity of
20.7%, a net-to-gross of 90.4% and
water saturation of 11.6%. The
Endymion gas field lies about 2 km to
the south of the Sinbad platform.
Production commenced in mid-
November 2002 with an initial well
deliverability of 35 MMcf/d.
Gibson
The Gibson field was discovered in
March 2001 by Gibson 1, which
encountered a 12.6 m gross oil
column. The field is located about
2 km south of the Tanami 4 well and
contains under-saturated oil similar to
that found in the Simpson field.
The field commenced production
from Gibson 1 in June 2002 at a
monthly average oil rate of
2500 bbl/d and water-cut of 40%. An
additional development well (Gibson
2H) is planned for early in 2003.
Little Sandy
The Little Sandy field was discovered
in March 2002 by Little Sandy 1,
which encountered a 20.3 m gross oil
column within the Valanginian Flag
Sandstone. The Little Sandy field is
located about 5 km south of the South
Plato and Gibson oil development
and contains under-saturated oil,
similar to that found in the Gibson,
Simpson and South Plato fields.
Little Sandy 1 commenced production
in November 2002 and averaged
2206 bbl/d through December 2002.
Pedirka
The Pedirka field was discovered in
February 2002 by Pedirka 2 which
encountered a 7.1 m gross oil column
within the Valanginian Flag
Sandstone. The Pedirka field is
located about 4.6 km south of the
South Plato and Gibson oil
development and contains undersaturated
oil, similar to that found in
the Gibson, Simpson and South Plato
fields. The field commenced
production at the end of November

2002. Average oil production in
December 2002 was 6084 bbl/d at a
36% water-cut.
South Plato
Plato 1, located some 2.8 km north of
South Plato 1 was drilled in 1986 and
was dry. The South Plato field was
discovered in February 2001 by South
Plato 1 and encountered a 27.4 m
gross oil column. The South Plato
field is located 2 km southwest of
Gibson 1 and 4 km southwest of the
Tanami 4 well. The oil field contains
under-saturated oil, similar to that
found in the Simpson field. South
Plato 2 appraisal well was drilled in
October 2001 between South Plato 1
and Plato 1 and encountered a 3.8 m
net oil column, thereby confirming
the northern extent of the South Plato
field.
As at 31 December 2002 South Plato
1 was producing about 2550 bbl/d
with 45% water-cut. A second South
Plato production well (South Plato
3H) is scheduled for the first quarter
of 2003.
Victoria
The Victoria field was discovered in
February 2002 by Victoria 1 which
encountered a 33.0 m gross oil
column primarily in sandstones,
above the main massive Flag
Sandstone, which are interpreted as
being the feather edge of the younger,
Double Island Sandstone Member.
Victoria 2 was drilled in September
2002.
Upside reserves were tested by
Victoria 2 well in the second half of
2002 and have led to a downward
revision in reserves. The Victoria field
is located about 5 km south of the
South Plato and Gibson oil
development and contains slightly
under-saturated oil. Victoria 1
commenced production in November
2002 and at 31 December 2002 was
producing 2260 bbl/d at a 42% watercut.
POTENTIAL
DEVELOPMENTS
The joint venture has made a number
of oil and gas discoveries in close
proximity to the existing facilities on
Varanus Island. These discoveries may
be developed in the future to
maintain/increase production and to
secure new gas contracts.
Bambra
Discovered in 1983, the development
of the Bambra field was deferred early
in the planning phase of the gasgathering
scheme because sufficient
gas reserves were available from the
Sinbad, Rosette and Campbell gas
fields.
In December 1997, the Bambra 4
well successfully appraised the
southern extension of the existing gas
field indicating an oil field. The well
encountered a hydrocarbon column
interpreted to comprise 9 m of grossgas
and 5 m of net oil, overlaying a
residual oil leg of approximately 2 m.
The current estimated proven and
probable gas reserves are 20 PJ and
about 8 MMbbl.
The close proximity of Bambra to the
Varanus Island facilities enhances the
economics of developing the field in
the future. Possible project features for
Bambra include a small offshore
platform, 6 km of infield gas pipeline
and a small deck with a test
production separator.
Doric
The Doric field was discovered in
November 1992 by Ulidia 1, which
encountered a 6.7 m gross gas
column in the Flag Sandstone
Formation. Doric 1, drilled in 1996,
confirmed the field to the southwest
of Ulidia 1 with a common gas water
contact (GWC). The field has been
remapped following the drilling of
Dawn 1, which was drilled in
December 2002 into a deeper
Biggada target.
OPERATING PROJECTS |
The field will be drained by two
crestal wells drilled in conjunction
with the proposed platform
development of the Linda gas field.
The Doric reserves are considered to
be undeveloped as of 31 December
2002.
Double Island
The Double Island field was
discovered in January 2002 by
Double Island 1, which encountered
a 16.9 m gross oil column in
sandstones informally referred to as
the Double Island Sandstone Member
of the Flag Sandstone Formation.
Reservoir properties within the
Double Island Sandstone Member are
excellent and similar to that of other
Flat sandstone discoveries to the
north. The Double Island field is
located about 8.8 km southwest of
the South Plato and Gibson oil
development and contains undersaturated
oil similar to that found in
the Gibson, Simpson and South Plato
fields. The field will be drained by
the existing horizontal sidetrack well.
The Double Island reserves are
considered to be undeveloped as of
31 December 2002.
Hoover
The Hoover field was discovered in
April 2002 by Hoover 1, which
encountered a 6.0 m gross oil column
within the Valanginian Flag
Sandstone. The Hoover field is
located about 2.8 km east of the
Victoria oil development and contains
under-saturated oil similar to that
found in the Gibson, Simpson and
South Plato fields.
Hoover 1 has been abandoned and it
is anticipated that a development well
could be drilled from the Victoria,
Pedirka and Little Sandy
developments.
The Hoover field is considered
undeveloped as of 31 December
2002.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 35

| OPERATING PROJECTS
Harriet area fields | gas, oil and condensate
North Alkimos
The North Alkimos field was
discovered in June 2000 with the
drilling of North Alkimos 1
exploration well. The well intersected
a 5.6 m gas column overlying a 6.5 m
oil-column with an oil-water contact
at 1937.6 m true vertical-depth
subsurface.
The field is considered sub-economic
at the P90 level of reserves but may
become economic when
infrastructure (pipelines from the
proposed Bambra development to
Varanus Island) is put in place.
The field was undeveloped as of 31
December 2002.
Gipsy–Rose–Lee trend
In 1998, the joint venture confirmed a
new hydrocarbon trend in the
Gipsy–Rose–Lee series of complex
fault blocks to the east of the Harriet
field. It is the first major trend in the
deeper and older Jurassic and Triassic
aged reservoirs within the Carnarvon
Basin, outside the deepwater Rankin
trend. The majority of the Harriet area
wells in the Carnarvon Basin only
intersect the lower Cretaceous age
formations.
A total of 11 wells have been drilled
in the Gipsy–Rose–Lee trend, which
are located around 20 km eastnortheast
of Varanus Island in TL/1.
Proven and probable reserves
estimated at 50% probability are
shown in the table below. Reserve
estimates for the Monty, Josephine
and Baker discoveries are yet to be
determined.
Field Oil Condensate Gas
(MMbbl) (MMbbl) (PJ)
Gipsy 5.0 - 1.0
North Gipsy 1.1 - 0.8
Rose - 2.5 73.0
Rose–Lee
In July 1998, the Rose 1 well was
drilled to a total depth of 2643 m and
identified a gross hydrocarbon
column of up to 245 m. The well flow
tested at a combined rate of
2520 kcm/d (89 MMcf/d) of gas and
3100 bbl/d of condensate over three
separate intervals. The Rose 2 well
was drilled in November 1998 but
did not encounter hydrocarbons. Rose
3 was subsequently drilled and
intersected the same three intervals as
Rose 1.
Lee 1 was drilled in January 1999 to
test a separate fault compartment to
the north of the Rose structure. The
well intersected a 112 m gross
hydrocarbon column within the same
three intervals intersected by the Rose
wells and a deeper fourth interval
containing oil. In May 1999, Lee 2
intersected hydrocarbons at the same
four intervals as Lee 1, thereby
proving the northern extent of the
field.
The joint venture considers that the
Rose and Lee fields are commercial
and are likely to be developed when
additional gas is required.
Monty
Monty 1 was drilled to a total depth
of 2492 m in December 1999 and
intersected a 38.5 m gross
hydrocarbon column in four separate
reservoirs containing both gas and
condensate. Monty 2 was
subsequently drilled to evaluate the
discovery but it did not encounter
hydrocarbons. The well determined
that the gas accumulation intersected
in Monty 1 did not extend down to
the Monty 2 location. Consequently,
the joint venture has evaluated the
Monty structure as containing a small
volume of gas.
36 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Josephine
In January 2000, the Josephine 1 well
was drilled to a total depth of 2678 m
and intersected a 43.5 m gross
hydrocarbon column in three separate
reservoirs containing both gas and
condensate. Josephine 1 was
subsequently plugged and abandoned
as a gas discovery.
Baker
The Baker 1 well was drilled to a total
depth of 2512 m in January 2000. The
well intersected a 31.5 m gross
hydrocarbon column in three separate
reservoirs in which both gas and
condensate were recorded. Baker 1
was subsequently plugged and
abandoned as a gas discovery.
Narvik
Located 25 km southeast of the
Harriet field in TP/8, the Narvik 1
well was drilled to a total depth of
820 m in November 1999. The well
identified a 31 m gross gas column, of
which 10.7 m is interpreted to be a
productive reservoir. Narvik 1 was
subsequently plugged and abandoned
as a gas discovery. Reserves are yet to
be established for the field.

The Hovea oil field is located
within the ARC Energy-operated
L1 production licence,
approximately 15 km southeast of the
township of Dongara. L1 is located in
the western portion of the onshore
northern Perth Basin. The Joint
Venture consists of ARC Energy NL
(50%) and Origin Energy
Developments Pty Ltd (50%).
Discovery
Hovea 1 was drilled in October 2001
to a total depth of 2126 m rotary
table (RT). The well was located on
2D seismic data and intersected a
5 m gross vertical oil column in the
Permian Dongara Sandstone
immediately beneath the regional
marine Kockatea Shale. An oil water
contact of 1932 m total vertical
distance subsea (TVDSS) was
determined from wireline logs. A
subsequent DST (1995-2002 m RT) of
the interval flowed (estimated)
41.5° API gravity crude oil at a rate of
approximately 950 bbl/d with a low
gas-to-oil ratio.
Prior to the acquisition of the Hovea
3D seismic survey post-Hovea 1, the
area was covered by, at best, a 1 km
spaced grid of 2D data of varying
vintages and processing. In the
vicinity of Hovea, the quality of the
2D data is typically poor due to the
effects of the outcropping Coastal
Limestone Formation. A combination
of poor energy penetration and
scattering of the reflection energy
resulted in very low signal-to-noise
ratios. Whilst noise levels in the 3D
data are still very high, the higher
density of data as well as the 3D
migration of the reflection data has
produced a much more coherent
image of the sub surface.
Location
689 km south of Geraldton
Basin
Perth, onshore
Permit/Licence
L/1
OPERATING PROJECTS |
Ownership
ARC Energy NL (Operator) 50%
Origin Energy Developments Pty Ltd 50%
Contact
ARC Energy NL
46 Ord Street
WEST PERTH WA 6005
Tel: +61 8 9486 7333 • Fax: +61 8 9486 7322
Email: arc@arcenergy.com.au
Web: www.arcenergy.com.au
Average oil production (bbl/d)
Production
2001 2002
Oil (bbl) 0 175 317
2000
Hovea
Hovea | oil
0
Oct-01 Dec-01 Feb-02 Apr-02 Jun-02 Aug-02 Oct-02 Dec-02
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 37
project details

| OPERATING PROJECTS
Hovea | oil
Development and
appraisal
To date seven wells have been drilled
on the structure using the Century 24
drilling rig, i.e. Hovea 1, 2, 3/3ST,
4/4ST, 5, 6 and 7.
Appraisal drilling commenced in June
2002. Hovea 2 was drilled vertically
to 2687 m RT and reached total depth
in granitic basement. Gas was
encountered in the lower High Cliff
Sandstone. An open hole DST
(2370–2419 m RT) flowed gas at a
stabilised rate of 0.467 Mm3/d (16.5 MMcf/d) through a 19 mm (3/4
inch) choke. A separate tight gas
column was also intersected above
this zone in the Irwin River Coal
Measures. The well was cased and
suspended as a future gas producer.
Hovea 3 was proposed as a deviated
well to appraise/develop the Dongara
oil pool and to appraise the extent of
the High Cliff gas discovery. The basal
Kockatea Shale, Dongara Sandstone
and the upper portion of the Wagina
Formation were cored in this well.
The well intersected a 22.5 m gross
vertical oil-column in the Dongara
Sandstone. The well was drilled in
August 2002 to 2357 m RT prior to
the drill pipe becoming stuck. Fishing
was unsuccessful and the well was
sidetracked. Hovea 3ST was drilled to
2500 m RT and intersected a 25 m
gross vertical oil-column confirming a
common oil/water contact in the
Dongara Sandstone at 1932 m
TVDSS. Common gas/water contacts
to those encountered in Hovea 2
were also confirmed. A DST (2465-
2475 m RT) in the High Cliff
Sandstone was undertaken to gain
pressure information and a water
sample.
Hovea 4 was proposed to
appraise/develop oil reserves in the
northern portion of the field. Hovea 4
was drilled in November 2002 as a
deviated well to a total depth of
2530 m RT prior to the drill pipe
becoming stuck. The well intersected
a 42 m gross vertical oil column in
the Dongara Sandstone. Fishing was
unsuccessful and the well was
sidetracked. Hovea 4ST was drilled to
a total depth of 2486 m RT and
intersected a 44 m vertical oil-column
with a common oil/water contact at
1932 m TVDSS.
Hovea 5 was proposed to
appraise/develop oil reserves in the
southern portion of the field. The well
was drilled in January 2003 and
reached a total depth of 2105 m RT.
Dip-meter data revealed the potential
for the field to continue up-dip to the
southeast. Accordingly the well was
plugged and abandoned and kick-off
plug set at 1991 m RT to drill Hovea
6.
Hovea 6 was drilled in February 2003
to a total depth of 2126 m RT. A gross
vertical oil intersection of 22 m was
intersected with an oil/water contact
at 1932 m TVDSS. Once again dipmeter
data indicated up-dip potential
to the southeast. Accordingly the well
was plugged and abandoned and
kick-off plug set at 1659 m RT to drill
Hovea 7.
Hovea 7 was being drilled in February
2003 at the time of this report.
Production and transport
ARC has adopted an aggressive
approach to the field development
aiming for the earliest practical onstream
date and production level
increases, at the same time ensuring
38 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
the work is undertaken in a safe,
environmentally sound manner,
including use of the smallest
‘footprint’ possible. The field is
currently being produced on test
production to quantify reservoir and
fluid parameters. The permanent
production facilities are scheduled for
commissioning in mid-March 2003
including separation, storage and
load-out facilities and this will
provide production capacity in excess
of 5000 bbl/d.
The following basis of development
for the field has been adopted:
• Centralise wells and equipment at
the Hovea Production Facility to
the extent operationally
practicable;
• Minimise the number of
development wells by using
directional wells with horizontal
sections;
• Recycle produced water into the
producing formation;
• Utilise the off-gas either onsite or
for sale; and
• Optimise the oil transport system
to reduce the number of trucks
required.
Future activity
No further wells are planned for the
Hovea oil field in this current drilling
campaign finishing with Hovea 7
(February 2003). Depending upon
production results from the existing
wells, additional development and/or
water-injection wells (possibly
horizontal) may be required. An
extended flow test for the High Cliff
Sandstone gas pool is currently being
planned to demonstrate the
commerciality of the accumulation.

The Laminaria field was
discovered in October 1994
within the Territory of Ashmore
and Cartier Islands area in permit
AC/P8 (subsequently production
licence AC/L5).
A separate field, Corallina, was
discovered in December 1995 within
AC/L5. Laminaria and Corallina are
administered by the Northern Territory
Department of Mines and Energy on
behalf of the Commonwealth of
Australia.
A unitisation agreement was
concluded in July 1998 between the
AC/L5 and WA-18-L participants
which allowed the entire Laminaria
field to be developed. The agreement
concluded that 89.85% of the
Laminaria field is situated in AC/L5.
The joint venture estimates that the
Laminaria and Corallina fields have
an expected production life of about
14 years. On the basis of a greater
than 50% probability of recovery, the
remaining proven oil reserves
(Western Australian proportion only)
as at the end of 2002 was
11.2 MMbbl. Production in the
Laminaria field commenced in
November 1999 and was among the
first developments in this part of the
Timor Sea, following Elang–Kakatua
which are located in the zone of
cooperation.
In 2002, the Laminaria East field (WA
proportion only) produced
approximately 1.64 MMbbl oil and
193 591 bbl condensate.
Production facilities
Development of the
Laminaria–Corallina fields utilises the
world’s largest new-build FPSO, the
Northern Endeavour, which is
permanently moored between the
fields by means of an internal turretmooring
system. It is moored in a
water depth of 390 m, making it
Australia’s deepest offshore site for an
oil production facility.
OPERATING PROJECTS |
Laminaria–Corallina | oil and condensate
Location
550 km west-northwest of Darwin
Basin
Bonaparte, offshore
Permit/Licence
AC/P8, AC/L5, WA-18-L
Ownership
Laminaria–Corallina (AC/P8, AC/L5)
Woodside Energy Ltd (Operator) 50%
Shell Development Australia Pty Ltd 25%
BHP Billiton Petroleum (NWS) Pty Ltd 25%
Laminaria Unitisation Agreement
Woodside Energy Ltd (Operator) 44.9%
BHP Billiton Petroleum (NWS) Pty Ltd 32.6%
Shell Development Australia Pty Ltd 22.5%
Contact
Woodside Energy Ltd
1 Adelaide Terrace
PERTH WA 6000
Tel: +61 8 9348 4000 • Fax: +61 8 9325 8178
Web: www.woodside.com.au
Production — Laminaria East (WA portion only)
2001 2002
Oil (bbl) 2 195 999 1 638 531
Condensate (bbl) 137 035 193 591
Average oil /condensate production (bbl/d)
Western Australian propoertion only
10,000
8,000
6,000
4,000
2,000
Laminaria–Corallina
0
Jan-01 Jul-01 Jan-02 Jul-02
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 39
project details

| OPERATING PROJECTS
Laminaria–Corallina | oil and condensate
The Northern Endeavour comprises
hydrocarbon separation, stabilisation
and testing facilities which are
designed to handle a maximum oil
production rate of 170 000 bbl/d.
Facilities have been provided for
produced water treatment, gas
compression, gas-lift, power
generation, cooling water and fiscal
metering. In addition, a stabilisation
column reduces LPG content and
improves crude value.
The two fields produce from diver-less
subsea facilities consisting of eight
production wells (six in Laminaria
and two in Corallina), two manifolds
and a network of subsea flowlines
and dynamic risers which are
connected to the FPSO. Surplus gas is
re-injected through a dedicated gas
disposal well. The internal turret
system includes provisions for future
risers and riser tubes, as well as future
piping arrangements, thereby allowing
the tie-in of additional
Laminaria–Corallina wells and further
discoveries in the area.
Stabilised oil (58º API gravity) is
stored onboard the FPSO, which has
a storage capacity of 1.4 MMbbl, and
is then transferred via an offtake
loading hose to an export tanker
moored astern of the FPSO.
Total capital cost of the
Laminaria–Corallina development was
$1.37 billion.
As a result of excellent uptime of the
facility, oil production from the
Northern Endeavour FPSO exceeded
expectations, despite the onset of
natural decline in early 2001. Of
particular note was the significantly
better than expected production from
the Corallina field. Estimated oil
recovery for the Laminaria and
Corallina fields was also upgraded
following technical studies, with the
bulk of the increase being attributed
to the Corallina field.
To deal with the rapid decline in
production from the Laminaria field,
the $123-million Laminaria Phase II
development was completed in June
2002. The development consists of
two vertical infill wells tied-back to
the Northern Endeavour FPSO. Initial
production was approximately
65 000 bbl/d. 2002 production from
the two infill wells was approximately
5 MMbbl.
Development of the Laminaria–Corallina fields utilises the
world’s largest new-build FPSO, the Northern Endeavour
40 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003

The Legendre North and Legendre
South oil fields are located 35 km
southeast of the Wanaea–Cossack
fields in water depths of 45–60 m in
Production Licence WA-20-L. Legendre
North was discovered in 1968 with the
drilling of Legendre 1, however, it was
considered uneconomic to develop at
that time. In 1997, Jaubert 1 confirmed
the potential of the field. In April 1998,
Legendre South 1 proved to be a
separate accumulation with the
intersection of a 21 m oil column,
3.5 km southwest of Jaubert 1.
The joint venture estimates that the two
fields contain probable oil reserves of
44.1 MMbbl, which is expected to
provide an operating life of four to eight
years.
Field development
In October 1999, the joint venture
formally approved the development of
the Legendre oil fields at an estimated
cost of $110 million. The development
will comprise four horizontal production
wells (three in Legendre North and one
in Legendre South) and one gas reinjection
well.
Good progress was made during the first
half of 2001 in the development of the
Legendre South and Legendre North oil
fields. Hook-up, testing and
commissioning activities commenced in
mid-January 2001 with the arrival of the
Ocean Legend on site. The drilling of the
production wells commenced shortly
thereafter and first oil was achieved in
mid-May after the completion of the first
production well. In mid-June, the first
cargo of Legendre crude oil was loaded
onto an offtake tanker having been sold
to Shell International Eastern Trading
Company. The cargo containing
approximately 630 000 bbl of oil was
delivered to oil refineries on the east
coast of Australia. The successful
execution of the final stages of the
Legendre oil field development in mid-
2001 provided additional oil production
during the second half of 2001.
By early July 2001 four production wells
and a single gas re-injection well had
been completed and commissioning of
the gas re-injection facilities
commenced.
Average oil production (bbl/d)
Location
104 km northwest of Dampier
Basin
Carnarvon, offshore
Permit/Licence
WA-20-L
OPERATING PROJECTS |
Legendre | oil and gas
Ownership
Woodside Energy Ltd (Operator) 45.94%
Apache Energy Limited 31.50%
Santos Limited 22.56%
Contact
Woodside Energy Ltd
1 Adelaide Terrace
PERTH WA 6000
Tel: +61 8 9348 4000 • Fax: +61 8 9325 8178
Web: www.woodside.com.au
Production
2001 2002
Oil (bbl) 6 474 391 10 482 399
Gas (kcm) 179 080 384 697
50,000
40,000
30,000
20,000
10,000
Oil
Gas
0
Jan-01 Jul-01 Jan-02 Jul-02
Unfortunately mechanical problems
were experienced with the gas reinjection
compressor which were not
resolved until late 2001. As a
consequence, gas disposal constraints
limited total production in 2001 to
6 474 391 bbl.
Legendre crude oil is a 43° API
gravity, light, sweet crude oil. Sales of
Legendre crude oil commenced soon
after production started in July and
the attractive qualities of this crude
Legendre
1,250
1,000
have enabled the Company to
establish new markets in Thailand,
New Zealand and Indonesia.
Woodside sold its entire entitlement
on a spot basis. Approximately 20%
of sales were to Australian refineries
with the balance exported to South
Korea, China and the new markets
described above.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 41
750
500
250
0
Average gas production (kcm/d)
project details

Mount Horner| oil
Location
380 km north of Perth
Basin
Perth, onshore
Permit/Licence
L7
Ownership
Petroenergy Pty Ltd 100%
Contact
Petroenergy Pty Ltd
242 Railway Parade
WEST LEEDERVILLE WA 6007
Tel: +61 8 9381 4744 • Fax: +61 8 9382 2899
Email: admin@petroenergy.com.au
Production
2001 2002
Oil (bbl) 38 888 32 208
project details | OPERAT ING PROJECTS
The Mount Horner oil field was
discovered in 1965 but did not
commence production until
May 1984. The field is currently at a
mature stage of its life.
In December 2000, Petroenergy Pty
Ltd acquired the assets of Australian
Worldwide Exploration Limited as
owner-operators after a fire destroyed
storage tanks in April 2000.
Production facilities
Eight wells have been
recommissioned after the restoration
of the process facilities in December
2000 to comply with stringent safety
case requirements set by the
Department of Industry and
Resources. Currently production is at
98% water cut and producing crude
oil (37.6° API gravity) at the rate of
88 bbl/d.
Beam pumps at Mount Horner
42 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003

OPERATING PROJECTS |
North West Shelf Gas Project | gas, oil and condensate
The North West Shelf Venture
(NWSV) is Australia’s largest
natural resources development.
It produces gas for Western Australia’s
domestic market and gas, condensate
and oil for export from its vast
offshore gas and oil fields and is
located about 130 km north of
Karratha in northwestern Australia.
Gas and condensate is produced from
the North Rankin, Goodwyn, Perseus
and Echo-Yodel fields on board the
Goodwyn A and North Rankin A
production platforms.
The gas is transported by a subsea
pipeline to the NWSV onshore gas
plant at Whithnell Bay on the Burrup
Peninsula 20 km north of Karratha.
The plant currently produces LNG,
natural gas, LPG and condensate.
A $2.4-billion expansion of the
NWSV’s facilities is in progress with
the construction of the LNG Train 4
project and a second offshore
trunkline.
The NWSV also produces crude oil
from its Wanaea, Cossack, Lambert
and Hermes fields. The oil is
processed on board the Cossack
Pioneer FPSO before being loaded on
to crude oil tankers for transport to
customers.
OFFSHORE GAS FIELDS
North Rankin
Discovered in 1971, the North Rankin
gas and condensate field is 140 km
offshore from Karratha in
approximately 125 m of water.
Following installation and
commissioning of the North Rankin A
platform (NRA), production
commenced in July 1984 with initial
deliveries of gas to the market one
month later.
The NRA was originally designed to
drill a maximum of 34 production
wells up to a 3.4 km vertical depth,
deviated up to 60°. The drilling
facilities were upgraded in 1990 to
extend the rig's drilling capability to
Location
134 km northeast of Dampier
Basin
Carnarvon, offshore
Permit/Licence
WA-28-P, WA-1 to 6-L, WA-9-L, WA-11-L, WA-16-L, WA-1-PL, WA-2-PL
Ownership
Domestic gas
Woodside Energy Ltd (Operator) 50.00%
BP Developments Australia Ltd 16.67%
ChevronTexaco Australia Pty Ltd 16.67%
BHP Billiton Petroleum (NWS) Pty Limited 8.33%
Shell Development (Australia) Pty Ltd
LNG, Oil, LPG, Gas recycling
8.33%
Woodside Energy Ltd (Operator) 16.67%
BP Developments Australia Ltd 16.67%
ChevronTexaco Australia Pty Ltd 16.67%
BHP Billiton Petroleum (NWS) Pty Limited 16.67%
Shell Development (Australia) Pty Ltd 16.67%
Japan Australia LNG (MIMI) Pty Ltd 16.67%
Contact
Woodside Energy Ltd
1 Adelaide Terrace
PERTH WA 6000
Tel: +61 8 9348 4000 • Fax: +61 8 9325 8178
Web: www.woodside.com.au
Production
2001 2002
Domestic gas (kcm) 4 803 884 4 786 411
LNG (t) 7 750 218 7 636 112
Oil (bbl) 42 886 774 43 746 570
Condensate (bbl) 34 876 390 41 094 005
LPG (t) 803 597 811 128
drill wells up to 70° deviation and up
to 6.2 km along-hole depth.
The last North Rankin field well was
drilled in 1992. In 2000, a rig
refurbishment campaign enabled the
drilling of production wells into the
eastern flank of the Perseus field.
During 2002, the North Rankin field
produced 3.21 Gm3 (0.11 Tcf) of
gross gas and 0.36 Gl (2.28 MMbbl)
of condensate.
Perseus
Discovered in 1972, the Perseus gas
field is about 135 km northwest of
Karratha in 131 m of water and
started production in 2001.
During 2002, the Perseus field
produced a total of 4.75 Gm 3
(0.17 Tcf) of gross gas and 0.95 Gl
(5.99 MMbbl) of condensate.
Goodwyn
The Goodwyn gas field was discovered
in 1971, 23 km southwest of North
Rankin field.
The Goodwyn A platform (GWA) was
designed for 30 wells and started
production in February 1995.
The initial drilling program of 13 wells,
including four horizontal, world-class,
long-reach wells producing from up to
7.4 km from the platform. The second
phase of drilling, included four longreach,
horizontal and deviated wells
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 43
project details

| OPERATING PROJECTS
North West Shelf Gas Project | gas, oil and condensate
and was completed during 1999. The
third phase of two wells was
completed in 2001.
Debottlenecking of the GWA, in
support of NWS expansion activities,
was also undertaken in 2001 and the
Production Licences over the field
were extended for a further 21 years.
In 2002, a total of 9.86 Gm 3
(0.35 Tcf) of gross gas and 2.86 Gl
(18.03 MMbbl) of condensate were
produced from the Goodwyn field.
Echo–Yodel (gas and
condensate)
The Echo–Yodel field was discovered
in 1988, 25 km southwest of the
GWA in 140 m of water.
In 2001, Production Licences were
granted over the field and two subsea
horizontal wells were completed and
tied back to GWA.
Coming on-stream at the end of
2001, the Echo–Yodel Field in 2002
produced 2.60 Gm3 (0.09 Tcf) of
gross gas and 1.96 Gl (12.35 MMbbl)
of condensate.
DOMESTIC GAS
PRODUCTION
The onshore gas treatment plant on
the Burrup Peninsula was
commissioned in August 1984 to
process gas and condensate piped
from NRA.
The plant currently consists of two
parallel processing trains with the
main components of each train being
the dehydration units, which separate
water from the gas, and the extraction
unit, which removes the heavier
hydrocarbons.
After processing, the bulk of the gas
is compressed, metered for delivery
to customers in the Pilbara and fed
into the 1500 km DBNGP to the
southwest of Western Australia. Gas
is also supplied to Boodarie Iron (a
BHBP subsidiary) via the Burrup
Extension Pipeline (BEP) and the
Pilbara Extension Pipeline (PEPL).
LNG PRODUCTION
The LNG plant was commissioned in
July 1989 and currently consists of
three liquefaction trains with a total
capacity of 7.5 Mt/a of LNG, four
65 000 m3 storage tanks and a jetty
dedicated to the loading of LNG.
Key elements of each LNG train
include:
• the sulphinol units, which remove
carbon dioxide from the gas;
• dehydration units for removal of
water;
• a mercury removal unit;
• a scrub column, which removes
the heavier gases;
• a liquefaction unit which reduces
the temperature of the gas from
minus 35°C to minus 138°C; and
• two end flash vessels, where a
reduction to atmospheric pressure
leads to further cooling, achieving
the cold temperature boiling point
for methane of minus 161°C. At
this point, the gas condenses to a
liquid at 1/600th of its gaseous
volume.
The LNG is stored before being piped
to the LNG jetty for offloading onto
purpose-built LNG ships for transport
to Japan and other international
markets.
The $2.4-billion expansion of the
NWSV’s gas-processing facilities
remained a major focus of
development efforts during 2002.
Construction of the fourth LNG
processing train commenced in
September 2001 and was 60%
complete by the end of 2002. This
facility will have the capacity to
process 4.2 Mt/a of LNG. The first
LNG from the fourth train is expected
mid-2004.
The total capital investment for this
project is $1.6 billion and at year-end
2002, $1.252 billion in contracts and
services had been awarded. Of the
total contract amount, about $822
million has been awarded to
44 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Australian companies and Woodside
expects this figure to reach $1 billion
at the completion of the construction
project.
Work on the second trunkline started
in June 2002 and was more than 30%
complete by December. The project
requires a capital investment of $800
million. The trunkline will have a
diameter of 1.07 m (42 inches),
providing additional capacity to meet
expected demand from gas-related
industries on the Burrup Peninsula
and overseas customers.
By the end of 2002, $436 million in
contracts and services for the second
trunkline had been awarded, with
about $219 million of the contracts
won by Australian companies.
To support the expansion, an LNG
ship at an approved capital
investment of $300 million and a
capacity of 137 500 m 3 is
being built in South Korea with the
first steel cut in September 2002.
With delivery expected in early 2004,
the new ship will take the Venture’s
fleet to nine purpose-built LNG ships.
Sales contracts
LNG is sold to eight Japanese gas and
electricity utilities under 20-year
contracts, which started in 1989, as
well as to the spot market when
deliveries are available.
The first shipment to Japan left the
Burrup Peninsula for Japan on 28 July
1989 on board the Northwest
Sanderling.
In 2002, the NWSV continued to
successfully market LNG into the
north Asian region.
It also broadened its customer-base
beyond its long-standing relationships
with Japanese customers with the
announcement in August 2002 that
Australia LNG had been selected as
the preferred supplier to China’s first
LNG project in the Guangdong
Province in southern China.
(Australia LNG is the North West
Shelf’s marketing agency outside
Japan.)

Sales and Purchase Agreements were
signed in October for the supply of
approximately 3.3 Mt/a of LNG for 25
years, starting in 2006. A Key Terms
Agreement was also signed in
October by the NWS LNG sellers and
China National Offshore Oil
Company (CNOOC), allowing
CNOOC the opportunity to acquire a
participating stake in the NWSV gas
reserves and production that will
supply gas to Guangdong.
Discussions between the NWSV and
Chinese shipping companies on
shipping arrangements to service the
China trade route were progressed
during late 2002.
A number of other important Sales
and Purchase Agreements were signed
by the Venture in 2002, these being
with:
• Korea Gas Corporation for the
supply of 220 000 t of LNG. This
volume will comprise one spot
cargo and three cargoes to be
redirected from existing contracted
customers where they are surplus
to current requirements.
• BP Gas Marketing for the supply
of 125 000 m3 of LNG.
• Shell Eastern LNG for the sale of
up to 3.7 Mt of LNG over five
years between 2004 and 2009.
• Kyushu Electric Power Co., Inc. for
the supply of 0.5 Mt/a of LNG,
commencing in 2006.
• Osaka Gas Co. Ltd for the supply
of 1 Mt/a of LNG, commencing in
2004.
Average condensate production (bbl/d)
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
The Venture also continued to assess
opportunities to supply LNG to
Taipower’s proposed Tatan power
station in Taiwan.
Future LNG opportunities include
extensions of contracts with existing
Japanese customers, pursuit of new
markets in South Korea as deregulation
continues and additional volumes in
emerging Chinese markets.
Total LNG production from the NWSV
in 2002 was 7.64 Mt. The Venture
delivered 127 cargoes of LNG to
Japanese customers in 2002 and three
spot cargoes were sold to Korea Gas
Corporation and one cargo to BP Gas
Marketing.
For the year 2002, the NWSV again
proved its reliability with an
outstanding 100% LNG cargo delivery
rate.
CONDENSATE
PRODUCTION
The NWSV has, since 1984, produced
condensate, a light oil which is used as
a feedstock to manufacture automotive
and aviation fuels and for chemical
plants and is a by-product from the
offshore gas fields.
OPERATING PROJECTS |
NWS Condensate
Perseus, Goodwyn and North Rankin
The following are the maximum contract quantities for the eight Japanese buyers:
NORTH WEST SHELF LNG BUYERS
Buyers Contract (Mt/a)
Tokyo Electric Power Co 1.18
Kansai Electric Power Co 1.13
Chugoku Electric Power Co 1.11
Chubu Electric Power Co 1.05
Kyushu Electric Power Co 1.05
Tokyo Gas Co 0.79
Osaka Gas Co 0.79
Toho Gas Co 0.23
Total 7.33
Source: Woodside Energy Ltd
0
Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
The onshore gas-processing plant
separates condensate from the dry gas
in a 350 m-long slugcatcher.
The liquid moves through five
stabilisation units, each capable of
processing 2750 t of condensate a day.
Water and remaining gas are removed
before the condensate is stored in two
73 000 m3 and 90 000 m3 tanks
for shipment to oil refineries around
the world.
Total condensate production in 2002
was 41.09 MMbbl, an 18% increase
on 2001. This increase was largely
due to the Echo–Yodel condensate
development start-up in December
2001.
LPG PRODUCTION
The onshore LPG plant on the Burrup
Peninsula was commissioned in
November 1995 and extracts propane
and butane from the gas originating
from the NWSV’s offshore gas fields.
The facilities include a 52 000 m3 liquid propane storage tank, a
65 000 m3 liquid butane storage tank,
a 450 m long load-out jetty with
berthing facilities for both LPG and
condensate tankers and a chiller plant
to reliquefy boil-off gases. System
capacity of the plant is 2500 t/d.
LPG production in 2002 averaged
2222.3 t/d, an increase on 2001 due to
the recovery of LPG from increased
condensate production.
Sales contracts
The Owners of the NWSV makes sales
arrangements of LPG on an individual
basis and the Operator, Woodside, in
2002 sold its entire LPG entitlement
into Japan under a three-year term
contract, which started in January
2001.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 45

| OPERATING PROJECTS
North West Shelf Gas Project | gas, oil and condensate
CRUDE OIL
PRODUCTION
First oil production from the NWSV
started in November 1995 and
currently comprises production from
the Wanaea, Cossack, Lambert and
Hermes fields.
The oil development utilises an FPSO
vessel, the Cossack Pioneer, which is
moored by its bow to a
disconnectable riser turret over the
Wanaea field. It is capable of
producing up to 140 000 bbl/d of oil
and 3700 kcm/d (118 MMcf/d) of gas.
Fluids from the four fields are
transported to the Cossack Pioneer
where processing facilities separate
the oil, water and gas. Stabilised oil
is stored in the FPSO’s tanks, which
have a capacity to hold up to
1.15 MMbbl. The oil (49° API gravity)
is offloaded by flexible hose to shuttle
tankers moored astern of the FPSO.
Associated gas from the separation
process is partly used to fuel power
generation to service the FPSO vessel.
The remainder is exported via a
300 mm, 33 km subsea pipeline to
the NRA platform where it joins the
main trunkline to the onshore gas
treatment plant.
After its $196 million maintenance
and upgrade in 1999, operational
performance of the Cossack Pioneer
continued to exceed expectations.
Crude oil production from the
Cossack Pioneer in 2002 averaged
119 900 bbl/d due to improved
reservoir performance, supported by
the reliability of the FPSO’s
production facilities.
All Woodside’s 2002 Cossack crude
oil entitlement was sold on the spot
market with cargoes mainly exported
to Asia.
OFFSHORE OIL FIELDS
Wanaea and Cossack
Discovered in June 1989, Wanaea is
located 30 km east of the North
Rankin field in 80 m of water and was
Average oil production (bbl/d)
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
followed in December with the
discovery of the Cossack field.
Production started in November 1995
and there are now five deviated wells
producing from Wanaea and one
horizontal well from Cossack.
Oil production from the Wanaea field
in 2002 was 4.57 Gl (28.70 MMbbl)
while production from the Cossack
field was 1.01 Gl (6.40 MMbbl). The
Cossack Pioneer also exported
1.0 Gm3 of raw gas via the inter-field
line to NRA.
Lambert and Hermes
The Lambert and Hermes are two
separate oil accumulations in 125 m
of water, 15 km north of the Wanaea
and Cossack fields and 145 km north
of Karratha.
Lambert was discovered in 1973,
Hermes in February 1996 and both
have been developed as subsea
satellites to the Cossack Pioneer
FPSO.
Oil production from the Lambert and
Hermes Fields in 2002 was 0.48 Gl
(3.03 MMbbl) and 0.89 Gl
(5.59 MMbbl) respectively.
NWS Oil
Cossack, Wanaea, Hermes and Lambert
0
Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
46 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
OIL PRODUCTION (MMbbl)
Field 2000 2001 2002
Wanaea 27.04 27.23 28.73
Cossack 7.73 6.92 6.39
Hermes 4.71 5.50 5.60
Lambert 2.90 3.21 3.03
TOTAL 42.38 42.86 43.75

The Stag field was discovered in
June 1993 and commenced
production in May 1998. The
joint venture identified initial proven
and probable oil reserves of around
44 MMbbl, giving the field a
minimum life of 13 years. Total
capital cost of the development was
around $200 million.
Production facilities
The development utilises a central
processing facility (CPF), which
comprises a fixed production platform
consisting of a six-leg piled
substructure, topsides and processing
facilities. The platform is able to
accommodate up to 12 wells and has
a processing capacity of 50 000 bbl/d
of liquids, including 40 000 bbl/d of
water-injection.
Stag crude has an API gravity of 19°
with low-wax and low pour-point
properties. Artificial lift with electric
submersible pumps is therefore
required to lift the oil to the surface at
commercial rates. The oil is
processed on the CPF and then
exported through a 200 mm, 2 km
subsea flowline to a calm buoy. The
buoy forms a mooring for a floating
storage and offloading (FSO) facility,
the Dampier Spirit, which has a
storage capacity of 700 000 bbl.
In 2000, one new production well
and one re-drilled well were placed
on-stream. In 2001, Stag 23 was
drilled and Stag 10 was sidetracked.
In 2002, a further development well,
Stag 24 was added. The field is now
operating with eleven producing wells
and three water-injection wells with a
current production rate of
17 000 bbl/d.
Reindeer
The Reindeer field, located 32 km
north of Stag in permit WA-209-P, was
discovered in October 1997 when the
Reindeer 1 well encountered a 65 m
gas column. Located 3.2 km south of
Reindeer, the Caribou 1 well
intersected a 19 m gas column in
April 1998 and confirmed the
southern extension of the Reindeer
Average oil production (bbl/d)
Location
65 km northwest of Dampier
Basin
Carnarvon, offshore
Permit/Licence
WA-209-P, WA-15-L
OPERATING PROJECTS |
Ownership
WA-15-L
Apache Northwest Pty Ltd (Operator) 33.3334%
Santos Limited 54.1666%
Globex Far East Ltd 12.5000%
WA-209-P
Apache Northwest Pty Ltd (Operator) 45%
Santos Limited 36%
Globex Far East Ltd 19%
Contact
Apache Energy Ltd
Level 3
256 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9422 7222 • Fax: +61 8 9422 7447
Web: www.apachecorp.com
Production
2001 2002
Oil (bbl) 6 956 926 5 375 858
30,000
25,000
20,000
15,000
10,000
5,000
0
Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
field. Caribou 1 tested at a combined
rate of 1470 kcm/d (51.9 MMcf/d) of
gas and 850 bbl/d of condensate from
two zones. The joint venture
estimates that Reindeer could contain
gas reserves of around 11 Bcm
(400 Bcf).
Stag
Stag | oil
Roebuck 1 was drilled in February
2000 but was plugged and
abandoned as a dry hole.
Development options, such as the
supply of gas to nearby offshore oil
developments for use in field
operations, will also be investigated.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 47
project details

Thevenard Island | oil
Location
25 km northwest of Onslow
Basin
Carnarvon, onshore and offshore
Permit/Licence
TP/3 (Pt 1 and 2), TL/7, TL/4, TPL/6, TPL/1, PL/15, PL/21, L12 and L13
(Note: EP65 has been replaced by production licences L12 and L13)
Ownership
ChevronTexaco Australia Pty Ltd (Operator) 25.713%
Texaco Australia Pty Ltd 25.713%
Santos Offshore Pty Ltd 35.713%
Mobil Australia Resources Company Pty Ltd 12.861%
Contact
ChevronTexaco Australia Pty Ltd
Level 24,
QV1 Building
250 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9216 4000 • Fax: +61 8 9216 4444
Web: www.chevrontexaco.com
project details | OPERAT ING PROJECTS
Average oil production (bbl/d)
Production
Field Oil (bbl) Gas (kcm)
2001 2002 2001 2002
Saladin 1 673 360 1 063 909 88 087 40 773
Roller 996 998 1 369 291 28 265 22 451
Skate 38 380 3 902 4 443 1 324
Yammaderry 34 122 19 023 6 789 1 668
Cowle 186 436 95 646 10 912 2 582
Crest - 5 437 - 1 319
TOTAL 2 929 297 2 557 208 138 496 71 428
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
Thevenard Island fields
Oil
Gas
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
48 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
800
700
600
500
400
300
200
100
0
Average gas production (kcm/d)
Thevenard Island provides the base
for the processing and storage of
hydrocarbons produced from the
Saladin, Roller, Skate, Yammaderry and
Cowle fields. The island infrastructure
includes facilities capable of handling
up to 120 000 bbl/d of mixed oil/water
production, three 350 000 bbl oil tanks,
water treatment and disposal facilities,
pipelines, three gas turbine generators, a
gas treatment plant, a 55 m3 capacity
slug-catcher/separator vessel and gas
compression units. The joint venture
announced in February 1999 that the
facilities could be utilised by third
parties for processing oil and gas
production from nearby operations.
In February 2000, Chevron Australia Pty
Ltd assumed the operatorship of
Thevenard Island from West Australian
Petroleum Pty Ltd (WAPET) and in 2001
Shell Development (Australia) Pty
Limited sold its interests in the
Thevenard Island area production and
exploration assets to Santos Offshore Pty
Ltd. In October 2001, Chevron and
Texaco merged, forming ChevronTexaco
Corporation. This resulted in a
combined majority holding in the
Thevenard assets.
In 2002, Chevron Australia Pty Ltd
changed its name to ChevronTexaco
Australia Pty Ltd by registration with the
Australian Securities and Investment
Commission. Registration of this name
change has been made on all relevant
Title Instruments.
Production operations
Fluid produced from the five fields is
piped to Thevenard Island where it is
separated into oil, water and gas. The
water is re-injected into the reservoirs
while the oil is processed and blended
together before being stored in tanks. It
is then transported via a 610 mm, 7 km
pipeline to offshore tankers berthed at a
10-point spread mooring system. The
crude (48° API gravity) is sold to
refineries in Australia and overseas.
Gas is conditioned and compressed
before being transported via a 150 mm
44 km export line extending from
Thevenard Island to the mainland via
each of the Roller and Skate monopods,
and then overland to the Tubridgi

facilities at a maximum rate of
20 TJ/d. The bulk of the gas is then
transported via the onshore Tubridgi
pipeline and the DBNGP to the
Mondarra gas field in the Perth Basin.
The $20-million gas-gathering system
was commissioned in November
1994.
Saladin
The Saladin field was discovered in
June 1985 and commenced
production in November 1989.
Currently, two wells are producing
from the Barrow Group reservoir and
twelve wells are producing from the
Mardie Greensand reservoir. Seven
wells are located offshore on three
fixed mini-platforms and seven wells
are located on Thevenard Island. Fluid
produced from each offshore platform
and onshore well is transported
through either 150 mm or 200 mm
pipelines to separation facilities on
Thevenard Island.
The Mardie Greensand formation is a
secondary producing horizon in the
Saladin field to the main Flacourt
formation of the Barrow Group
reservoir. However, with the original
completions in the Flacourt formation
continuing to water-out and with
several new wells drilled in the
Mardie Greensand, it is now the
dominant producing formation. The
joint venture estimates that the
Mardie Greensand formation contains
oil-in-place of 55 MMbbl, with
potential recoverable oil of
26 MMbbl.
Gas injection through three wells is
currently used to support pressure in
the Mardie Greensand formation. In
addition, one horizontal producer has
been converted to a water-injection
service, following the installation of a
water filtration system and a waterinjection
pump.
Roller and Skate
The offshore Roller field was
discovered in January 1990 and
commenced production in May 1994.
The field consists of four production
wells and one gas injection well
which are linked to three unmanned
monopods. Discovered in October
1991, the offshore Skate field
commenced production in July 1994.
A 508 mm, 27 km three-phase
production pipeline transports
commingled oil from the two fields,
together with associated gas and
water, to separation facilities on
Thevenard Island.
Total capital cost of the Roller and
Skate development was $170 million.
Yammaderry and Cowle
Yammaderry and Cowle were each
developed as single well fields linked
to separate offshore-unmanned
monopods at a total capital cost of
$30 million.
Discovered in July 1988, the
Yammaderry field commenced
production in March 1991. After
being shut-in throughout 1998 the
field produced intermittently during
1999 following a workover of the
Yammaderry 2 well. Production
continues from this well, at a very
low rate. Fluid is transported to
Thevenard Island via a 150 mm, 2 km
flowline that is connected to the
Saladin C platform for processing with
Saladin crude.
The Cowle field was discovered in
December 1989 and commenced
production in May 1991. The Cowle 4
well was completed in the Mardie
Greensand as an oil producer in May
1999 and resulted in a four-fold
increase in production for the year.
Following the success of Cowle 4,
Cowle 5 was also drilled into the
Mardie Greensand, although with less
encouraging results. A 200 mm,
10 km flowline transports fluid
directly to Thevenard Island.
Crest
The onshore Crest field was
discovered in February 1994 when
the deviated Crest 1 well encountered
hydrocarbons under Thevenard Island.
The well was placed on an extended
production test in June 1994.
OPERATING PROJECTS |
In 1998, Crest 1 was abandoned and
Crest 6 was drilled horizontally into
the overlaying Mardie Greensand
reservoir. Crest 6 produced at low oil
rates and was shut-in in October
1998, pending the applications for a
production licence. A production
licence application over the Crest
field (EP65) triggered the Native Title
Act 1993 and the Right to Negotiate
provisions. Extensive negotiations
occurred with the Thalanyii people
since November 1998. The matter
ended in a determination in WAPET’s
favour. Legal discussions were
finalised in 2002 and two production
licences were granted over Thevenard
Island (Production Licences L12 and
L13). Production recommenced in
December 2002 from the Mardie
Greensand horizontal well Crest 6.
POTENTIAL
DEVELOPMENTS
The joint venture is continuing to
evaluate potential developments
within the permit areas that could be
tied into existing production facilities
on Thevenard Island.
Australind
Additional hydrocarbons were
discovered in permit TP/3 (Pt 1) with
the successful drilling of the offshore
Australind 1 well in September 1993.
Located about 5 km northeast of
Thevenard Island, the well was drilled
to a total depth of 1310 m in the
Barrow Group formation and
encountered a 12 m gas column
associated with a minor oil-column.
Australind 1 was abandoned. The
development of this field remains
marginal. The field is now covered by
retention lease TR/4.
Coaster
In January 2000, the offshore Coaster
1 well intersected an 11m net oilcolumn
(30° API gravity) in the
Barrow Group formation after
reaching a total depth of 1112 m.
Located 5 km from Roller, the well
was suspended as a potential oil
producer.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 49
project details

Tubridgi | gas
Location
25 km southwest of Onslow
Basin
Carnarvon, onshore
Permit/Licence
L9, PL/16, PL/19
Ownership
SAGASCO Southeast Inc.* (Operator) 51.15%
Pan Pacific Petroleum NL 43.00%
Origin Energy Petroleum Pty Ltd 2.80%
Origin Energy Amadeus NL 2.70%
Tubridgi Petroleum Pty Ltd 0.35%
*SAGASCO is a wholly-owned subsidiary of Origin Energy Limited
Contact
Origin Energy Resources Ltd
34 Colin Street
WEST PERTH WA 6005
Tel: +61 8 9324 6111 • Fax: +61 8 9321 5457
Web: www.originenergy.com.au
project details | OPERAT ING PROJECTS
Average gas production (kcm/d)
Production
2001 2002
Gas (kcm) 124 716 87 056
800
700
600
500
400
300
200
100
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
The Tubridgi gas field was
discovered in June 1981 and
commenced production in
September 1991. The project
incorporates gas production and
transportation operations, as well as
re-injection and storage facilities. The
joint venture expects the field to
continue production until at least
2005.
Tubridgi
Production facilities
There are now six producing wells in
the field (two of which can also be
used for gas re-injection purposes)
following the tie into production
facilities of three new wells in
September 1999. Gas is piped from the
producing wells via 30 km of flowlines
to a central processing plant, consisting
of dehydration, separation and
50 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
compression facilities, located on the
Tubridgi field. The conditioned gas may be
transported via a 150 mm, 90 km gas
pipeline, with a capacity of 30 TJ/d, to
Compressor Station 2 on the DBNGP or via
the Griffin pipeline.
In 1997, the Tubridgi hub was connected to
the adjacent Griffin gas plant so that
Tubridgi sales gas could be processed or
blended to meet normal sales gas
specifications for the DBNGP.
Gas sales contract
The joint venture had a 1-year contract,
ending in December 2003, to supply
AlintaGas with up to 25 TJ/d.
Reserves
Ongoing decline analysis by the Joint
Venture of Tubridgi production indicates
recoverable gas reserves of 4-8 PJ.
GAS TRANSPORTATION
FACILITIES
The Tubridgi project was expanded in 1994
to act as a transportation and storage facility
for associated gas from the Griffin and
Thevenard Island fields.
The strategic location of the gas-gathering
facilities and the substantial spare pipeline
capacity, may assist in the transport of gas
from other offshore oil and gas fields in the
southern area of the Carnarvon Basin. The
facilities are capable of delivering around
120 TJ/d of gas and further increases are
possible with additional compression.
Griffin
Associated gas from the Griffin Venture
FPSO is transported via a 200 mm, 68 km
offshore pipeline to the Griffin onshore gas
treatment plant, adjacent to the Tubridgi
facilities. The gas is then transferred via a
250 mm, 90 km onshore pipeline lateral
into the DBNGP. The onshore pipeline, with
a capacity of more than 90 TJ/d, was built
by the Tubridgi joint venture and parallels
its 150 mm pipeline.
The Tubridgi joint venture can purchase up
to 40 TJ/d of the Griffin gas for resale into
the domestic gas market. Alcoa is
committed to purchase at least 25 TJ/d
under a 10-year contract ending in
December 2004.

The Wandoo oil field was
discovered in June 1991 in a
water depth of 55 m. Production
commenced in October 1993 under an
extended production test using the
Wandoo A platform. First oil production
from the Wandoo B platform
commenced in March 1997 and full
field development was completed in
June 1997. Total capital cost of the full
development was $600 million.
There were three further horizontal
wells drilled in late 2000, two on
Wandoo A and one on Wandoo B.
Initial recoverable oil reserves were
estimated at 75 MMbbl, giving the field
a production life of around 20 years.
The Wandoo crude has an API gravity
of 19° with low-wax and low pourpoint
properties, but high viscosity.
Production facilities
Wandoo A is a single column,
monopod wellhead platform, which
supports a deck and five production
wells. Fluid produced from the wells is
piped to the Wandoo B platform,
located to the northeast. Wandoo B
consists of a concrete gravity
substructure (CGS) which supports steel
topsides and provides storage capacity
for 400 000 bbl of crude oil.
The 81 000 tonne CGS was constructed
at a casting basin in the Port of Bunbury
inner harbour. The completed CGS was
floated out of Bunbury harbour, towed
1760 km to the Wandoo field and then
sunk into position on the seabed in
October 1996. It was the first concrete
seabed storage facility to be installed in
Australia.
In January 1997, the topsides were
installed on the CGS using the floatover
method for the first time in
Australian waters. The topsides support
processing facilities, ten horizontal oil
production wells, one gas injection well
and an accommodation module. The
processing facilities, which can handle
more than 140 000 bbl/d of total fluid,
separate and process the fluids
produced from both platforms. Typical
production rates are 22 000 bbl/d of oil,
Location
75 km northwest of Karratha
Basin
Carnarvon, offshore
Permit/Licence
WA-14-L
OPERATING PROJECTS |
Ownership
Mobil Exploration & Producing Australia Pty
Ltd (Operator) 60%
Wandoo Petroleum Pty Ltd 40%
Contact
Mobil Exploration & Producing Australia Pty Ltd
12 Riverside Quay
SOUTHBANK VIC 3006
Tel: +61 3 9270 3333 • Fax: +61 3 9270 3493
Web: www.exxonmobil.com
Production
Average oil production (bbl/d)
50,000
40,000
30,000
20,000
10,000
132 000 bbl/d of water and 500
kcm/d (18 MMcf/d) of gas. The water
is treated and discharged into the
ocean. Gas is used for reservoir gaslift
and for fuel.
Oil is stored in the CGS and then
offloaded through two 348 mm
flexible pipelines to a loading buoy
located 1.2 km north of Wandoo B. A
floating hose is used to transfer the oil
to export tankers at a mooring facility.
Markets for the oil are mainly Japan
Wandoo
Wandoo | oil
2001 2002
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
and South Korea with a small amount
also being shipped to the Altona
refinery in Victoria.
Production alliance
In 1997, the Wandoo Production
Alliance was formed to provide field
operations, engineering and other
support functions. It comprises Mobil,
ABB Engineering Construction,
Mermaid Marine Australia, Stolt
Comex Seaway and Nalco-Exxon
Energy Chemicals Australia.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 51
project details

Woodada | gas and condensate
Location
275 km north of Perth
Basin
Perth, onshore
Permit
L4, L5, PL/6
Ownership
Hardman Oil & Gas Pty Limited (Operator) 100%
Contact
Hardman Oil & Gas Pty Limited
5 Ord Street
WEST PERTH WA 6005
Tel: +61 8 9321 6881 • Fax: +61 8 9321 2375
Email:office@hdr.com.au
Production
2001 2002
Gas (kcm) 40 893 33 026
Condensate (bbl) 1 154 834
project details | OPERAT ING PROJECTS
Average condensate production (bbl/d)
12
10
8
6
4
2
Woodada
Condensate
Gas
0
Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02
52 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
180
150
120
90
60
30
0
Average gas production (kcm/d)
Located 13 km northwest of the
township of Eneabba, the
Woodada field was discovered in
May 1980 and commenced
production in May 1982. Production
is expected to continue for at least
another seven years.
Production facilities
Facilities at Woodada include
separation and compression units, a
gas drying and sweetening unit,
evaporation ponds and a condensate
storage tank.
A total of 17 wells have now been
drilled in the field, seven of which are
currently producing.
Gas and condensate from the
producing wells are collected by a
150 mm gas-gathering system. After
separation and dehydration, the gas is
transported via the Parmelia pipeline,
located 11 km northeast of the field.
Condensate (53.6º API gravity) is
piped to a storage tank and is then
transported by truck to the BP refinery
in Kwinana for processing.
Gas sales contracts
Woodada currently supplies gas to
Tiwest, Midland Brick and Whitemans
Brick under long-term contracts.

Projects under consideraton
project details
Blacktip | gas Cliff Head | oil
Location
50 m of water approximately 245
km southwest of Darwin and 90
km north of Wyndham.
Basin
Bonaparte Basin
Permit
WA-279-P
Ownership
Woodside Energy Ltd 70%
Agip Australia B.V. 30%
Contact
Woodside Energy Ltd
1 Adelaide Terrace
PERTH WA 6000
Tel: +61 8 9348 4000
Fax: +61 8 3925 8178
Web: www.woodside.com.au
The Blacktip gas field (permit
WA-279-P) contains around
1.1 Tcf of gas and 1.7 MMbbl of
condensate and was discovered in
August 2001. It is currently being
evaluated as a potential source of
natural gas to supply customers in the
Northern Territory.
Development of Blacktip is contingent
on securing foundation customers in
the Northern Territory and the
feasibility and approval of an onshore
gas treatment plant and onshore gas
delivery pipeline. As such, the timing
of firm development plans is
dependent on the project gaining the
full support from the foundation
customers, various Northern Territory
traditional pwners, the Northern Land
Council, impacted upon pastoralists
and other community and
government stakeholders.
All preliminary environmental datagathering
has been completed,
although the Statutory Environmental
Approvals process will not proceed
until a market is secured.
project details
Location
20 km southwest of Dongara
Basin
Perth, offshore
Permit
WA-286-P
Ownership
Roc Oil (WA) Pty
Ltd (Operator) 37.5%
AWE Oil (Western
Australia) Pty Ltd 27.5%
Wandoo Petroleum
Pty Ltd 25.0%
Voyager Energy Limited 5.0%
Norwest Energy NL 5.0%
Contact
Roc Oil (WA) Pty Ltd
16/100 William Street
SYDNEY NSW 2000
Tel: +61 2 8356 2000
Fax: +61 2 8356 2066
Web: www.rocoil.com.au
Cliff Head was discovered in
December 2001 with the drilling
of Cliff Head 1 and subsequent
appraisal with Cliff Head 2. The Cliff
Head field is in a water depth of
approximately 16 m, 11 km offshore
and is located southwest of Dongara.
Cliff Head 1 intersected a 5 m oilcolumn
within the Irwin River Coal
Measures. Cliff Head 2 intersected a
36 m oil-column also within the Irwin
River Coal Measures. No production
testing was undertaken in either well
and they were plugged and abandoned.
At this stage the estimated initial oil in
place was 80 to 100 MMbbl.
In October 2002 the Joint Venture
announced that further studies,
including analysis of reprocessed
seismic data and reservoir simulations,
had increased the estimates of original
oil in place to between 100 and
140 MMbbl in place.
Further appraisal of the Cliff Head field
was undertaken with a small 2D
seismic survey in October 2002 and in
January 2003 with the drilling of Cliff
Head 3, 2.4 km northwest of the Cliff
Head 2 well, followed by Cliff Head 4,
1 km south of Cliff Head 3, in March
2003. The oil–water contact
encountered in Cliff Head 3 and
Cliff Head 4 is the same as that for
Cliff Head 1 and 2. Production
testing was undertaken in Cliff Head
3 over 27 m of the reservoir for a
period of 3 days. The maximum
flow rate was 3000 bbl/d on a
downhole pump through an 11mm
choke. Post-appraisal studies are in
progress
project details
Coniston | oil
Location
50 km north of Exmouth
Basin
Carnarvon, offshore
Permit/Licence
WA-255-P
Ownership
BHP Billiton Petroleum
(Australia) Pty Ltd
(Operator) 50%
Mobil Exploration
& Producing Australia
Pty Ltd 50%
Contact
BHP Billiton Petroleum Pty Ltd
Level 42, Central Park
152-158 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9278 4888
Fax: +61 8 9278 4899
Web: www.bhpbilliton.com
In February 2000, the Coniston 1
well was drilled in a water depth of
389.5 m and reached a total depth
of 1350 m. A production test
achieved a maximum unassisted oil
flow rate of 2119 bbl/d.
Coniston 1 is located 25 km north of
the BHP-operated Macedon–Pyrenees
field and 10 km north of the
Vincent–Enfield oil fields, operated by
Woodside Energy.
Following initial assessment of this
relatively heavy oil discovery
(15°API), it is not considered
commercial as an independent
development at this time. However,
subject to potential nearby
developments, a commercial tie-back
development scheme could become
possible in the future.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 53

|PROJECTS UNDER CONSIDERATION
project details
Gorgon | gas
Location
200 km west of Dampier
Basin
Carnarvon, offshore
Permit
WA-205-P, WA-253-P, WA-
267-P, WA-268-P, WA-2-R to
5-R, WA-14-R to WA-18R
Ownership
WA-2-R to 5-R, WA-14-R,
WA-16-R
ChevronTexaco Australia
Pty Ltd (Operator) 28.57%
Texaco Australia
Pty Ltd 28.57%
Shell Development
(Australia) Pty Limited 28.57%
Mobil Australia
Resources Company
Pty Ltd 14.29%
WA-253-P, WA-15-R and WA-17-R
ChevronTexaco Australia
Pty Ltd (Operator) 50%
Texaco Australia Pty Ltd 50%
WA-267-P
ChevronTexaco Australia
Pty Ltd (Operator) 25%
Texaco Australia Pty Ltd 25%
Mobil Australia Resources
Company Pty Ltd 25%
Shell Development
(Australia) Pty Limited 12.5%
BP Exploration
(Alpha) Ltd 12.5%
WA-18-R
Mobil Australia Resources
Company Pty Ltd
(Operator) 50%
Texaco Australia Pty Ltd 50%
WA-268-P
Texaco Australia
Pty Ltd (Operator) 100%
WA-205-P
ChevronTexaco
Australia Pty Ltd
(Operator) 28.57%
Texaco Australia Pty Ltd 20.00%
Mobil Australia
Resources Company
Pty Ltd 10.00%
Shell Development
(Australia) Pty Limited 26.43%
AEC International 12.86%
Woodside Energy Ltd 2.14%
Contact
ChevronTexaco Australia Pty Ltd
Level 24, QV1 Building
250 St Georges Terrace
PERTH WA 6000
Tel:+61 8 9216 4000
Fax:+61 8 9216 4444
Web:www.chevrontexaco.com
0 40
Kilometres
Io/Jansz
Maenad
Eurytion
Orthrus
North Gorgon
SouthGorgon
54 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
N
The ChevronTexaco operated
joint ventures are currently
planning the development of the
large natural gas reserves of the
Greater Gorgon fields to support a
major LNG and domestic gas project.
Recent exploration success in
WA-267-P has increased the gas
reserve base significantly.
The Greater Gorgon area contains an
estimated gas resource in excess of
40 Tcf and is made up to two
groupings of fields: the Gorgon area
gas fields in the shallower water; and
the deeper water fields which include
the Io–Jansz fields located further
offshore.
The Gorgon Area contains certified
gas reserves of 12.9 Tcf and includes
the Gorgon field, West Tryal Rocks,
Spar, Chrysaor and Dionysus fields.
The Gorgon gas field is the largest
field in this group, and one of the
largest ever discovered in Australia.
EXPLORATION AND
APPRAISAL DRILLING
West Tryal Rocks was the first of the
Greater Gorgon gas fields to be
discovered in 1973 and this was
followed by Spar in 1976. Up to 1999
a total of 14 appraisal wells had been
drilled in the Greater Gorgon fields,
comprising Gorgon (8), West Tryal
Rocks (3), Chrysaor (1), Dionysus (1)
and Spar (1). Guaranteed work
commitments in exploration permits
WA-205-P, WA-25-P and WA-267-P
over the last four years have increased
Geryon
Urania
Dionysus
Chrysaor
Spar
Barrow Island
Iago
West Tryal Rocks
Certified Reserve
Discovery
Montebello
Islands
State-Commonwealth
Water Boundary
Lowendal
Islands
Town Point
ChevronTexaco Camp
the number of wells in this area. Of
the seven wells drilled in the last two
years, there have been six discoveries
in the Greater Gorgon area. These
are Geryon 1, Orthrus 1, Maenad 1A,
Urania 1 and Io 1 in WA-267-P and
Iago 1 in WA-25-P.
Gorgon
The Gorgon field was discovered in
1980 and was initially appraised with
the drilling of North Gorgon 1 in
1982 and Central Gorgon 1 in 1983.
In July 1994, the North Gorgon 2
appraisal well was drilled to obtain a
more accurate definition of the
Gorgon reserves. The well flowed gas
at a maximum rate of 1764 kcm/d
(62 MMcf/d) during DSTs. The North
Gorgon 2 well confirmed the northern
extension of the Gorgon field and the
existence of gas-bearing sands
previously inferred from 3D seismic
data.
To delineate further reserves and to
aid in the selection of development
options and sites within the North
Gorgon field, two appraisal wells
were drilled in 1995-96. The North
Gorgon 3 vertical appraisal well was
drilled to a total depth of 4628 m in
December 1995 and intersected a gas
column. The well helped define the
northern extension of the Gorgon
field.
The North Gorgon 4 vertical appraisal
well was drilled to a total depth of
4170 m in February 1996. The well
flowed gas at a maximum rate of

1050 kcm/d (37 MMcf/d) during
DSTs. The results of the tests indicated
the presence of gas-bearing sands in a
previously undrilled North Gorgon
fault block.
In October 1998, the Gorgon 3
appraisal well was drilled to provide
critical data on well productivity and
fluid compositions. The well
encountered over 398 m of
permeable gas sands and flowed gas
at a maximum rate of 1790 kcm/d
(63.2 MMcf/d) during testing of two
separate intervals. The high flow rates
confirmed the enormous delivery of
the Gorgon reservoirs.
North Gorgon 6, the final appraisal
well in the Gorgon field, was drilled
to a total depth of 4290 m in
November 1998. The well
encountered a total net gas pay of
157 m and confirmed the continuity
of the reservoir.
Chrysaor
Located 19 km northeast of the North
Gorgon field in 806 m of water, the
Chrysaor 1 exploration well was
drilled to a total depth of 3597 m in
December 1994. The well flowed gas
at a maximum rate of 1798 kcm/d
(63.5 MMcf/d) during production
testing. Although the well was drilled
within permit WA-205-P, the majority
of the Chrysaor structure extends into
adjoining permit WA-253-P. Two
retention leases have been granted
over the entire field, WA-14-R (from
WA-205-P) and WA-15-R (from
WA-253-P).
Dionysus
The Dionysus 1 well was spudded in
1100 m of water in June 1996 and
was drilled to a total depth of
4417 m. The well flowed gas during
two DSTs at a maximum rate of
1804 kcm/d (63.7 MMcf/d).
Dionysus 1 intersected separate gas
accumulations from those
encountered in the Chrysaor field and
established the presence of a second
major gas field in permit WA-253-P.
A retention lease (WA-15-R) was
awarded over the Dionysus field on
the 20 April 2000.
WA-267-P
In August 1999, the joint venture
commenced a significant deepwater
drilling program involving six
commitment wells in permit
WA-267-P, located to the west of the
Greater Gorgon fields. Drilling to
date has resulted in five significant
gas discoveries, Geryon 1, Orthrus 1,
Urania 1, Maenad 1 and Io 1. The
exploration success rate for this
permit’s drilling program was 83%.
Geryon 1 was drilled in 1232 m of
water and reached a total depth of
3515 m in September 1999. The well
encountered a total net gas pay of
113 m in three high-quality reservoir
zones. Located 28 km southwest of
Geryon in 1200 m of water, the
Orthrus 1 well was drilled to a total
depth of 3570 m in October 1999.
The well encountered a total net gas
pay of 53 m in a high-quality
reservoir zone.
In February 2000, 21 km northeast of
Geryon, Urania 1 was drilled in
1200 m of water, reaching a total
depth of 4010 m and encountering
two high-quality reservoir zones with
54.5 m of total net gas pay. Maenad
1, located 50 km southwest of Urania
in 1220 m of water was drilled in
March 2000. The well was drilled to
a total depth of 2690 m and
encountered two high-quality
reservoir zones with a total net gas
pay of 20 m.
In January 2001, 2.5 km southsoutheast
of Geryon, Callirhoe 1 was
drilled. While an unsuccessful
exploration test of deeper reservoirs, it
successfully appraised the Geryon gas
accumulation.
The latest gas discovery, Io 1, was
made in January 2001. Located
40 km northwest of Maenad in 1350
m of water, Io reached a total depth
of 3020 m and encountered a single
gas-bearing zone.
Locations have been nominated and
awarded for all the recently
discovered gas in WA-267-P.
Retention lease applications have
been submitted to the Joint
Authorities.
WA-253-P and WA-25-P
In December 2000, the joint venture
fulfilled permit obligations by drilling
Iago 1 in WA-25-P. Situated 6.4 km
north of North Tryal Rocks 1, Iago 1
was drilled in 118 m of water,
reaching a total depth of 3354.5 m. A
single reservoir with 20 m of net gas
pay was encountered. Retention
Lease WA-16-R (from WA-25-P) and
PROJECTS UNDER CONSIDERATION|
WA-17-R (from WA-253-P) were
granted in 2002 over the Iago field.
The WA-25-P permit has since been
relinquished.
THE GORGON AREA GAS
RESERVES
In January 1999, international
petroleum consultants Netherland
Sewell and Associates of Dallas Texas
independently certified that proven
hydrocarbon reserves for the Gorgon
area fields were 360 Bcm (12.9 Tcf),
including 270 Bcm (9.6 Tcf) for the
Gorgon field itself. Proven and
probable reserves exceed 500 Bcm
(17.6 Tcf) and possible reserves
extend the total to 608 Bcm
(21.5 Tcf). The raw gas from these
fields contains 12-15% carbon
dioxide.
The joint venture considers that the
reserves are sufficient to support a
major LNG development as well as
providing gas to the domestic market.
For comparison, the North Rankin
field was developed by the North
West Shelf Gas joint venture based on
proven gas reserves of around
200 Bcm (7 Tcf), with around 3%
carbon dioxide.
LNG DEVELOPMENT
The current greenfield Gorgon LNG
development plan is based on a
development of a single 5 Mt/a
liquefaction train. Feedstock for the
LNG plant is to be supplied initially
from the Gorgon field, starting in
North Gorgon. The Chrysaor,
Dionysus, West Tryal Rocks and Spar
fields provide opportunities for
contract extensions, expansion of the
number of liquefaction trains or
domestic gas sales.
The ‘base case’ development plan
consists of a series of subsea well
completions in around 200 m of
water in the North Gorgon field. The
subsea wells will be connected via
gas-gathering lines to a subsea
manifold. Raw gas will then be
transported via a 26 inch, 70 km
subsea trunkline to Barrow Island.
A stand-alone liquefaction, storage
and LNG shipping facility located on
Barrow Island are under
consideration.
A development decision on the LNG
project is subject to market
commitments and the joint venture is
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 55

|PROJECTS UNDER CONSIDERATION
targeting the markets in China, South
Korea and US West Coast. Total
capital cost of the initial 5 Mt/a
development is estimated at $6
billion. The project is expected to
require a site workforce over four
years peaking at around 2500 people.
Access to Barrow Island for this initial
development will be subject to a
Western Australian Government
decision in the third quarter of 2003.
The decision will be based on an
environmental, social and economic
review being undertaken by the
Gorgon Venture.
Domestic gas
development
Since August 1999, the joint venture
has been actively marketing domestic
gas aimed at supplying Greater
Gorgon gas to industrial users in the
northwest region of Western Australia.
This initiative complements the joint
venture’s continuing LNG
development plans.
ChevronTexaco acts as the domestic
gas-marketing agent on behalf of the
joint venture. The marketing effort is
seeking to attract new industrial gas
users to Western Australia such as
methanol, gas-to-liquids and
ammonia/urea projects, as well as
meeting growth in the existing
industrial gas market. Gorgon would
require about 300 to 500 TJ/d of gas
demand to justify the infrastructure
needed to bring the Gorgon gas to
shore for processing.
56 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Jansz | gas John Brookes |
gas and condensate
project details
Location
250 km northwest of Dampier
Basin
Carnarvon, offshore
Permit
WA-18-R
Ownership
Mobil Exploration &
Producing Australia
Pty Ltd (Operator) 50%
Texaco Australia Pty Ltd 50%
Contact
Mobil Exploration &
Producing Australia Pty Ltd
12 Riverside Quay
SOUTHBANK VIC 3006
Tel: +61 3 9270 3333
Fax: +61 3 9270 3493
Web: www.exxonmobil.com
The Jansz 1 discovery well was
drilled in April 2000 and
intersected 29 m of net gas pay.
A second well Io 1 (18 km from Jansz
1) was drilled in January 2001 and
intersected the same sandstone
reservoir with a total of 44 m of net
gas pay. The Jansz gas field was
confirmed by another well Jansz 2
drilled in November 2002 (18 km
from Jansz 1).
Development
The joint venture is now assessing a
range of options to commercialise this
substantial gas resource.
project details
Location
60 km northwest of Varanus
Island
Basin
Carnarvon, offshore
Permit
WA-214-P
Ownership
Apache Oil Australia
Pty Ltd (Operator) 28.75%
Santos (Bol) Pty Ltd 28.75%
Encana International
(Australia) Pty Ltd 25.00%
Mobil Exploration &
Producing Australia
Pty Ltd 17.50%
Contact
Apache Energy Limited
Level 3, 256 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9422 7222
Fax: +61 8 9422 7447
Web: www.apachecorp.com
In November 1998, the John
Brookes 1 well was drilled to a total
depth of 3741 m in a water depth
of 20 m and intersected an 80 m
gross hydrocarbon column. The well
was tested over two separate zones
and achieved a combined flow rate of
1510 kcm/d (53.4 MMcf/d) of gas and
460 bbl/d of 46° API condensate.
The joint venture estimates that the
John Brookes field could contain
recoverable gas reserves of more than
28 Bcm (1 Tcf). The proximity to
existing infrastructure provides the
potential for an early development.
A second well in the permit, Moon 1,
was drilled to a total depth of 3035 m
in October 1999 but was plugged and
abandoned as a dry hole

project details
Macedon and
Pyrenees |
gas and oil
Location
40 km north of Exmouth
Basin
Carnarvon, offshore
Permit/Licence
WA-12-R
Ownership
BHP Billiton Petroleum
(Australia) Pty Ltd
(Operator) 71.43%
Mobil Exploration &
Producing Australia
Pty Ltd 28.57%
Contact
BHP Billiton Petroleum Pty Ltd
Level 42, Central Park
152-158 St Georges Terrace
PERTH WA 6000
Tel: +61 8 9278 4888
Fax: +61 8 9278 4899
Web: www.bhpbilliton.com
The West Muiron 1 and 2 wells
were drilled by West Australian
Petroleum Pty Ltd in 1972 and
1975 respectively, but both wells
failed to provide oil or gas shows.
BHP Billiton Petroleum drilled a
further three wells at West Muiron
during 1992 and 1993. Subsequent
analysis of well and seismic data
indicated that the West Muiron
structure comprised two adjacent but
separate hydrocarbon fields –
Macedon (gas) and Pyrenees (oil and
gas).
Macedon
The Macedon field was discovered in
November 1992 by the West Muiron
3 well which encountered a gas
column in excess of 81 m but did not
establish a hydrocarbon-water
contact. The well was subsequently
plugged and abandoned as a gas
discovery after being drilled to a total
depth of 1200 m. In May 1993, the
West Muiron 4 well was drilled to a
total depth of 1550 m and was
suspended as a potential gas
producer.
In November 1994, the joint venture
successfully completed a five-well
appraisal-drilling program in the
Macedon field. The wells confirmed
the structural interpretation, gas-water
contact, reservoir distribution and
production of the field. All the wells
were plugged and abandoned, as
programmed, with the exception of
Macedon 4, which was suspended as
a potential gas producer.
Gas marketing and
development
The joint venture estimates that
Macedon contains a gas resource of
up to 1.2 Tcf. Gas recovered to date
is dry containing no condensate or
LPG. The resource size and
composition suggest development as
either industrial gas feedstock for
power generation or for commodity
chemicals such as methanol or
ammonia/urea.
Marketing opportunities, together with
ways to develop the field and
transport the gas to market, were
stepped up in the second half of 2000
and were further pursued in 2002.
Pyrenees
The Pyrenees field was discovered in
July 1993 by the West Muiron 5 well,
which perforated a low to
intermediate quality reservoir in the
oil zone and flowed oil at a rate of
550 bbl/d with associated gas. A
better quality overlying zone in the
gas column tested 475 kcm/d
(16.7 MMcf/d) of gas. West Muiron 5
was drilled to a total depth of 1526 m
and was suspended as a potential oil
and gas producer. Two additional
wells, Pyrenees 1 and 2, were drilled
in 1994 but failed to intersect
significant hydrocarbons.
There are no plans for the immediate
development of the Pyrenees field.
PROJECTS UNDER CONSIDERATION|
Scarborough | gas
project details
Location
270 km northwest of Onslow
Basin
Carnarvon, offshore
Permit
WA-1-R
Ownership
Esso Australia Resources
Ltd (Operator) 50%
BHP Billiton Petroleum
(Australia) Pty Limited 50%
Contact
Esso Australia Ltd
12 Riverside Quay
SOUTHBANK VIC 3006
Tel: +61 3 9270 3333
Fax: +61 3 9270 3493
Web: www.exxonmobil.com
The Scarborough gas field was
discovered in 1979 with the
drilling of the Scarborough 1
well in more than 900 m of water.
The gas field is a relatively flat
structure at a depth of roughly
1800 m. At the time of this discovery,
the available technology and
undeveloped LNG market made the
remote, deepwater gas field
uneconomic to develop. As a result,
follow-up appraisal work was
deferred.
In early 1996, a 2440 km 2D seismic
survey was completed over the field
to define possible well locations for
appraisal drilling. Based on this data,
the Scarborough 2 appraisal well was
spudded in June 1996 and drilled to a
total depth of 2068 m. A production
test was carried out in January 1997
and the well flowed gas at a rate of
905 kcm/d (32 MMcf/d).
Development
The joint venture is now assessing a
range of options to commercialise this
substantial gas resource, taking into
account information gained from the
Scarborough 2 well.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 57

|PROJECTS UNDER CONSIDERATION
Scott Reef–
Brecknock–
Brecknock South
| gas and
condensate
project details
Location
350 km north-northwest of Broome
Basin
Browse, offshore
Permits
WA-33-P, EP36, TP/4
Brecknock South extends
WA-275-P
Ownership
WA-33-P WA-275-P
Woodside Energy
Ltd (Operator)
BP Developments
50.00% 25%
Australia Ltd
ChevronTexaco
16.67% 20%
Australia Pty Ltd
BHP Billiton
Petroleum (NWS)
16.67% 20%
Pty Ltd
Shell Development
8.33% 20%
(Australia) Pty Ltd
Contact
8.33% 15%
Woodside Energy Ltd
1 Adelaide Terrace
PERTH WA 6000
Tel: +61 8 9348 4000
Fax: +61 8 9325 8178
Web: www.woodside.com.au
The Scott Reef deposit was
discovered in 1971, 350 km
north of Broome and recorded
gas flows of up to 1270 kcm/d
(45 MMcf/d). In 1979, the Brecknock
1 well intersected a net gascondensate
interval of 68m.
The Brecknock South gas discovery
was made in 2000 and intersected a
net gas column of 107 m. Water
depth was 30-70 m in the Scott Reef
Lagoon and 400-1,000 m over the
open water parts of Scott Reef.
The joint venture estimates the
combined probable reserves of the
fields to be 21.7 Tcf of dry gas and
311 MMbbl of condensate.
The joint venture participants have
applied for retention leases covering
the gas and condensate discoveries.
project details
Tern–Petrel | gas
Location
250 km west of Darwin
Basin
Bonaparte, offshore
Permit
WA-18-P, WA-6-R, NT/RL-1
Ownership
Tern
Santos Ltd Group 100%
Petrel
Santos Ltd Group 95%
Origin Energy Bonaparte
Pty Ltd 5%
Contact
Santos Limited
Level 14, Santos House
60 Edward Street
BRISBANE QLD 4000
Tel: +61 7 3228 6666
Fax: +61 7 3228 6675
Petrel
The Petrel field is located on the
Western Australian – Northern
Territory seabed border in permits
WA-6-R and NT/RL-1. Six wells have
been drilled in the field, including the
discovery well in May 1969. Petrel 2
was drilled in 1971 and recorded gas
flows at rates of up to 410 kcm/d
(14.5 MMcf/d). In 1982, Petrel 3
flowed gas at rates of up to
630 kcm/d (22.2 MMcf/d). In 1988,
Petrel 4 flowed gas at rates of up to
813 kcm/d (28.7 MMcf/d), indicating
that a complex reservoir distribution
exists in the field.
Petrel 5 flowed gas at a rate of
980 kcm/d (34.6 MMcf/d) and
condensate at a rate of 16.6 bbl/d in
October 1994. Located in the western
side of the field within WA-6-R, the
well was not completed as a gas
producer because it was not optimally
located for field development, and
was subsequently plugged and
abandoned.
In November 1995, Petrel 6 was
drilled to a total depth of 3915 m but
was plugged and abandoned after
failing to intersect the reservoir sands
that were targeted.
58 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
Tern
The Tern field is located
approximately 60 km from Petrel in
Western Australian waters within
permit WA-18-P. It was discovered in
1971 when the Tern 1 well
encountered more than 36 m of gross
pay and flowed gas at a rate of
200 kcm/d (7 MMcf/d). In 1982, Tern
2 intersected over 28 m of gross pay
and flowed gas at rates of up to
420 kcm/d (14.8 MMcf/d). The Tern 3
well, drilled in 1988 on a satellite
structure to the south, was dry.
Tern 4 was drilled to a total depth of
2633 m in October 1994 and
confirmed the existence of gas in the
southeast area of the field. Tern 4 was
not completed as a production well
as the hole was specifically designed
to provide information on the
reservoir.
In January 1998, the Tern 5 well
flowed gas at a rate of 447 kcm/d
(15.8 MMcf/d) and indicated a gross
gas column of 35 m after reaching a
total depth of 2702 m.
Development options
The joint venture estimates that the
Tern and Petrel fields contain proven
and probable gas reserves in excess of
28 Bcm (1 Tcf), with upside potential
in the Petrel field.
In 2002, the joint venture completed
a preliminary development plan
aimed at using gas from the Tern and
Petrel fields to supply the Northern
Territory domestic market. The first
phase of the plan proposes the initial
development of the Petrel field via an
unmanned offshore production
facility. Gas would be piped to an
onshore gas treatment plant south of
Darwin for conditioning to sales
quality before delivery to customers.
The recent Blacktip discovery to the
south of Petrel may tie-in with Petrel
and Tern to service domestic gas
customers.
The joint venture is currently
conducting discussions with potential
customers with the aim of entering
into a commercial development.

Vincent–Enfield–
Laverda | oil
project details
Location
50 km northwest of Exmouth
Basin
Carnarvon, offshore
Permit
WA-271-P
Ownership
Woodside Energy Ltd
(Operator) 100%
Contact
Woodside Energy Ltd
1 Adelaide Terrace
PERTH WA 6000
Tel: +61 8 9348 4000
Fax: +61 8 9325 8178
Web: www.woodside.com.au
The Vincent, Enfield and Laverda oil
fields are located west of Exmouth in
northwest of Western Australia in
permit 271-P.
In December 1998, Vincent 1 well
was drilled to total depth of 1560 m
and intersected a 19.3 m oil-column
with an overlaying gas cap. A
production test of the well resulted in
a maximum flow rate of 4301 bbl/d of
17°API gravity oil accompanied by
54 kcm/d (1.9 MMcf/d) of gas. An
extension well, Vincent 2, was drilled
to a total depth of 1490 m in June
and indicated a 13 m oil-column.
Located 10 km southwest of Vincent,
the Enfield 1 well was drilled to total
depth of 2192 m in April 1999 and
encountered a 33 m gross
hydrocarbon column in two separate
reservoirs. Production testing resulted
in a maximum flow rate of 4800 bbl/d
of 22°API gravity oil accompanied by
1.17 MMcf/d of gas. In July 1999, the
Enfield 2 appraisal well intersected
the reservoir interval below the oilwater
contact.
Enfield 3 was drilled to total depth of
2521 m in October 2000. About
48 m of gross hydrocarbon column
was encountered. The well was
tested for a period of five days to
examine the possibility of
compartmentalisation and reservoir
quality.
Laverda 1, located 14 km west of
Enfield, was drilled in November
2000. A gross hydrocarbon column
of 69 m was encountered which
comprised 9 m of gas and 60 m of oil
with a 19.6° API gravity rating.
Further appraisal and technical
studies were carried out on the three
fields during 2001 and early 2002. In
February 2002, Enfield 4 well
demonstrated the presence of oil in a
fault block adjoining the main field.
The well encountered an 18.1 m
gross oil column which subsequently
production tested at 5626 bbl/d and
1.38 MMcf/d.
Enfield 5 was drilled in September
2002 to appraise the gas cap. The
well penetrated a 55.8 m reservoir
interval and encountered a gross oil
column at 1973 m in line with
seismic prediction. The well was not
tested.
Laverda 2, located 3.4 km north of
Laverda 1, was drilled in December
2002. The well encountered a grossgas-bearing
column of 33.5 m within
the Macedon sandstone. The well
results are currently being evaluated.
Woodside is currently deciding
between two development options:
• an Enfield stand-alone which would
commence with first oil in 2006; or
• a combined Enfield–Laverda
development starting at the same
time with the possibility of other
tiebacks at a later stage.
The fields will be developed using an
FPSO with subsea wells. The
development is the subject of an
Environmental Impact Statement (EIS)
under the Environment Protection and
Biodiversity Conservation Act 1999
(EPBC Act). The EIS was published for
a comment period of eight weeks
closing on December 16, 2002 and
was scheduled to be with
Environment Australia at the end of
March 2003 for assessment.
Whicher Range |
gas
project details
Location
21 km south of Busselton
Basin
Perth, onshore
Permit
EP408
Ownership
Amity Oil Limited
(Operator) 29.665%
Southern Amity Inc. 44.115%
GeoPetro Resources
Company 26.220%
Contact
Amity Oil Limited
2nd Floor, 18 Richardson Street
WEST PERTH WA 6005
Tel: +61 8 9324 2177
Fax: +61 8 9324 1224
Email: mail@amityoil.com.au
The Whicher Range gas field was
discovered in 1969 by Union Oil
when the Whicher Range 1 well
flowed gas at rates of up to 54 kcm/d
(1.9 MMcf/d). However, the low, gas
flow rate rendered the prospect
uneconomic. Two subsequent
appraisal wells were drilled in 1980
and 1982 by Mesa Petroleum and
British Petroleum, respectively. These
wells confirmed the significant size of
the field, however, the flow rates from
the extremely tight sands were again
too low for economic development.
Hydraulic fracture
stimulation
Amity Oil took over the rights to the
Whicher Range permit in July 1997
with the intent of increasing the gas
flow rates from the field using
hydraulic fracture stimulation
technology (fraccing). Amity farmedin
Pennzoil Exploration Australia to
apply its experience in fraccing tight
gas wells to Whicher Range, in order
to demonstrate that the field could be
commercially developed.
Pennzoil operated the drilling of the
Whicher Range 4 well and re-entered
Whicher Range 1 in 1997. Pennzoil
then fracced the reservoir in four
zones in the Whicher Range 4 well
and three zones in Whicher Range 1.
The program was completed in June
1998 and produced stabilised gas
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 59

|PROJECTS UNDER CONSIDERATION
flows of approximately 40 kcm/d
(1.4 MMcf/d) from each well. However,
the gas flow rates were much lower
than expected from the measured
reservoir characteristics.
Remedial stimulation —
Whicher Range 4
Subsequent laboratory work on a drill
core from the field, carried out for
Amity by Stimlab Inc, concluded that
the reservoir formations were damaged
(reduced in permeability) by the waterbased
hydraulic fracture fluids used in
the stimulation procedure. Stimlab
recommended a program of remedial
work involving the high pressure
injection of liquid carbon dioxide into
the Whicher Range 4 well.
In late 1999, Amity (86%) and GeoPetro
Resources Company (14%) undertook
the remedial program which resulted in
the well flowing gas at a stabilised rate
of 87 kcm/d (3.08 MMcf/d) from three
zones. Whicher Range 4 was suspended
as a future commercial production well.
The success of the remedial program in
more than doubling the gas flow rate
indicates a significant reduction in
reservoir damage.
Whicher Range 5
Analysis of the flow tests from Whicher
Range 4 indicates that the reservoir is
capable of higher flow rates in a new
well using an appropriate nondamaging
drilling and stimulation
program. As a result, the joint venture is
planning to drill the Whicher Range 5
well in 2003 after Amity has farmed-out
its interest from 73.78% to about 50%
in the permit. A 100 km seismic survey
was completed in February 2000 to
assist with site selection for the well.
Gas marketing
The joint venture estimates that the
Whicher Range field contains in-place
gas resources of 28 – 113 Bcm
(1–4 Tcf). The field is just 65 km from
the end of the DBNGP and is in close
proximity to the growing mineral
processing industry market in the
southwest of Western Australia, as well
as to the towns of Busselton, Margaret
River and Dunsborough. Gas quality
from Whicher Range is suited for
domestic consumption as it contains
less than 1.5% inert gases and no
sulphur.
Woollybutt | oil
project details
Location
44 km west of Barrow Island
Basin
Carnarvon, offshore
Permit
WA-234-P
Ownership
Agip Australia Limited
(Operator) 65%
Mobil Exploration
& Producing
Australia Pty Ltd 20%
Tap Oil NL 15%
Contact
Agip Australia Limited
Level 3, 40 Kings Park Road
WEST PERTH WA 6005
PO Box 1265,
WEST PERTH WA 6872
Tel: +61 8 9320 1111
Fax: +61 8 9320 1100
Email: info@agipaustralia.com.au
The Woollybutt field was
discovered in April 1997 when
the Woollybutt 1 well
intersected a 19 m gross oil-bearing
reservoir. The well flow tested
7600 bbl/d of 49° API gravity oil,
confirming the potential of the field.
The extent of the field was appraised
by Woollybutt 2 in 1997 and
Woollybutt 3 in 1999.
Development plan
A development plan for the field was
approved by the joint venture partners
in the fourth quarter of 2001. The
plan comprises tie-back of two subsea
production wells to a leased FPSO
facility. A contract with Vanguard
SPC was executed in November 2001
for provision of the FPSO. The
Woollybutt 1 and 2 exploration and
appraisal wells were re-entered in
2002 and sidetracked horizontally
prior to completion as production
wells. Peak production rate is
expected to be some 40 000 bbl/d,
with first production expected late in
the first quarter of 2003.
60 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003

Western Australian petroleum fact sheet
TABLE 1. PRODUCTION AND RESERVES AS AT 31 DECEMBER 2002 — DEVELOPED FIELDS
Field Operator Annual Production # Reserves ##
Oil Condensate Gas Oil Condensate Gas
(bbl) (bbl) (kcm) (MMbbl) (MMbbl) (Bcm)
2002 2002 2002 90% 50% 90% 50% 90% 50%
Agincourt Apache 94 321 1 849 3 077 0.44 1.01 0.01 0.01 0.01 0.01
Barrow Island ChevronTexaco 3 579 167 0 75 001 24.11 38.78 0.00 0.00 0.42 0.66
Beharra Springs Origin 0 3 284 58 022 0.00 0.00 0.00 0.00 0.21 0.25
Beharra Springs N. Origin 0 3 034 39 092 0.00 0.00 0.01 0.01 0.01 0.02
Blina Kimberley 12 053 0 0 0.01 0.01 0.00 0.00 0.00 0.00
Boundary Kimberley 2 171 0 0 0.00 0.00 0.00 0.00 0.00 0.00
Buffalo Nexen 4 714 010 0 17 556 3.23 5.71 0.00 0.00 0.01 0.03
Campbell Apache 0 200 781 267 946 0.00 0.00 0.06 0.31 0.35 0.60
Chervil Apache 3 598 0 12 0.00 0.00 0.00 0.00 0.00 0.00
Chinook–Scindian BHP 5 131 773 0 238 851 2.91 2.91 0.00 0.00 0.22 0.22
Cossack Woodside 6 382 637 0 30 637 13.84 25.16 0.63 0.63 0.02 0.07
Cowle ChevronTexaco 95 599 0 2 582 0.16 0.26 0.00 0.00 0.01 0.01
Crest ChevronTexaco 5 434 0 1 319 0.10 0.11 0.00 0.00 0.01 0.01
Dongara ARC Energy 3 876 1 277 43 355 0.12 1.13 0.00 0.00 0.28 0.31
Double Island Apache 0 0 0 3.84 4.53 0.06 0.06 0.04 0.04
East Spar Apache 0 2 243 812 1 093 818 0.00 0.00 19.62 25.60 8.38 11.02
Echo/Yodel Woodside 0 12 529 007 2 638 440 0.00 0.00 17.61 28.93 5.30 8.68
Endymion Apache 0 20 904 21 085 0.00 0.00 0.38 0.50 0.53 0.72
Gibson Apache 168 736 247 1 509 0.94 1.32 0.00 0.00 0.01 0.01
Gipsy Apache 509 318 1 793 11 219 1.76 2.77 0.01 0.01 0.03 0.05
Goodwyn Woodside 0 19 070 628 9 848 532 0.00 0.00 105.67 161.65 102.57 136.83
Griffin BHP 8 028 466 0 98 771 2.07 10.08 0.00 0.00 0.04 0.04
Harriet Apache 409 708 2 120 11 973 1.32 1.95 0.01 0.01 0.03 0.04
Hermes Woodside 5 593 393 0 55 738 5.66 11.95 0.00 0.00 0.04 0.11
Hovea ARC Energy 175 438 0 1 576 5.20 9.40 0.00 0.00 0.00 0.00
Lambert Woodside 3 029 608 0 23 697 8.81 18.87 1.26 2.52 5.75 7.56
Laminaria East Woodside 1 645 342 180 807 6 328 0.94 2.77 0.00 0.00 0.00 0.00
Legendre North Woodside 9 240 433 0 318 955 12.58 21.39 0.00 0.00 0.00 0.00
Legendre South Woodside 2 094 176 0 65 743 1.26 1.26 0.00 0.00 0.00 0.00
Little Sandy Apache 73 591 478 610 1.26 1.57 0.00 0.00 0.01 0.01
Lloyd Kimberley 1 810 0 0 0.01 0.01 0.00 0.00 0.00 0.00
Mount Horner Petroenergy 32 343 0 0 0.01 0.01 0.00 0.00 0.00 0.00
North Gipsy Apache 29 920 266 1 415 0.25 0.44 0.01 0.06 0.05 0.06
North Rankin Woodside 0 2 271 876 3 214 630 0.00 0.00 54.72 79.25 154.29 176.94
Pedirka Apache 201 163 806 1 081 0.75 0.94 0.00 0.00 0.01 0.01
Perseus–Athena Woodside 0 7 558 704 6 025 890 0.00 0.00 163.53 213.22 204.06 259.89
Roller ChevronTexaco 1 368 616 0 22 361 3.14 5.04 0.00 0.00 0.02 0.03
Rosette Apache 0 37 746 51 452 0.00 0.00 0.31 0.44 0.36 0.48
Saladin ChevronTexaco 1 065 649 0 42 084 1.62 2.82 0.00 0.00 0.03 0.05
Simpson Apache 3 062 128 18 581 24 650 10.00 13.21 0.06 0.06 0.06 0.08
Sinbad Apache 0 18 303 25 802 0.00 0.00 0.00 0.00 0.01 0.02
Skate ChevronTexaco 3 900 0 1 324 0.00 0.00 0.00 0.00 0.00 0.00
South Plato Apache 954 412 1 143 6 887 4.78 6.42 0.00 0.00 0.03 0.04
Stag Apache 5 324 160 0 26 134 20.95 31.01 0.00 0.00 0.05 0.03
Sundown Kimberley 2 992 0 0 0.12 0.12 0.00 0.00 0.00 0.00
Tanami Apache 214 412 2 884 5 141 0.75 0.63 1.01 0.06 0.02 0.03
Tubridgi Origin 0 240 83 747 0.00 0.00 0.01 0.01 0.36 0.45
Victoria Apache 72 989 795 1 033 0.44 0.63 0.00 0.00 0.01 0.01
Wanaea Woodside 28 687 275 0 969 361 72.33 98.75 3.77 5.03 2.48 4.10
Wandoo Exxonmobil 4 299 261 0 53 250 15.90 27.73 0.00 0.00 0.02 0.11
West Terrace Kimberley 8 691 0 0 0.01 0.01 0.00 0.00 0.000 0.000
Wonnich Apache 0 370 412 506 243 0.00 0.00 2.14 2.77 2.740 3.560
Woodada Hardman 0 834 33 026 0.00 0.00 0.01 0.01 0.676 2.046
Woollybutt Agip 0 0 0 10.57 19.88 0.00 0.00 0.000 0.000
Yammaderry ChevronTexaco 19 014 0 1 668 0.07 0.08 0.00 0.00 0.003 0.004
Yardarino ARC Energy 0 0 778 0.00 0.00 0.00 0.00 0.001 0.001
Total 96 341 582 44 542 611 26 073 401 232.26 370.62 370.89 521.15 489.56 615.26
# Production figures were provided to the Department of Industry and Resources by operating companies.
## Reserve figures are based on those provided to the Department of Industry and Resources by operating companies at 31/12/02.
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 61

WESTERN AUSTRALIAN PETROLEUM FACT SHEET|
TABLE 2. RESERVES AS AT 31 DECEMBER 2002 — UNDEVELOPED FIELDS
Category 1: Potential for Short Term Development
Field Operator Reserves ##
Oil (MMbbl) Condensate (MMbbl) Gas (Bcm)
90% 50% 90% 50% 90% 50%
Angel Woodside 0.00 0.00 59.12 84.28 38.79 52.67
Bambra Apache 5.54 7.30 1.89 1.89 0.41 0.49
Bambra East Apache 0.00 0.00 1.20 1.51 0.71 0.91
Caribou Apache 0.00 0.00 0.44 1.64 0.30 1.16
Coaster ChevronTexaco 2.77 3.84 0.00 0.00 0.00 0.00
Coniston BHP 11.00 20.00 0.00 0.00 0.00 0.00
Corvus Apache 0.00 0.00 1.20 1.70 1.40 3.70
Doric Apache 0.00 0.00 0.19 0.25 0.55 0.67
Enfield Woodside 93.72 144.67 0.00 0.00 0.00 0.00
Hoover Apache 0.38 0.44 0.00 0.00 0.02 0.03
John Brookes Apache 0.00 0.00 0.00 0.00 17.85 24.99
Laverda Woodside 33.96 56.61 0.00 0.00 0.00 0.00
Lee Apache 0.00 0.00 0.94 1.20 1.15 1.45
Linda Apache 0.00 0.00 4.47 5.22 3.17 3.69
Monty Apache 0.00 0.00 0.19 0.19 0.36 0.55
Narvik Apache 0.00 0.00 0.00 0.00 0.52 0.69
Nasutus Apache 1.57 6.23 0.00 0.06 0.31 0.57
North Alkimos Apache 0.69 1.13 0.00 0.00 0.03 0.05
Novara BHP 3.90 6.30 0.00 0.00 0.00 0.00
Reindeer Apache 0.00 0.00 1.20 1.70 7.56 10.53
Rose Apache 0.00 0.00 1.76 2.45 1.16 1.70
Sage Apache 1.20 1.38 0.00 0.00 0.00 0.00
Total 154.72 247.89 72.58 102.08 74.29 103.85
Category 2: Expected Medium-to-long-term Development
Field Operator Reserves ##
Oil (MMbbl) Condensate (MMbbl) Gas (Bcm)
90% 50% 90% 50% 90% 50%
Woodside 0.00 0.00 1.26 1.89 19.88 32.25
Dockrell Woodside 0.00 0.00 7.55 15.72 8.88 17.79
Gaea Woodside 0.00 0.00 1.89 3.14 1.95 3.68
Goodwyn
S/Pueblo Woodside 0.63 2.52 0.00 0.00 2.64 8.20
Keast Woodside 0.00 0.00 4.40 10.06 5.42 10.00
Saffron Woodside 0.00 0.00 0.00 0.00 0.46 0.57
Searipple Woodside 0.00 0.00 3.14 4.40 0.76 0.99
Tidepole Woodside 2.52 9.43 6.29 15.72 6.26 18.69
Vincent Woodside 52.83 71.70 0.00 0.00 0.51 0.56
Total 55.98 83.65 24.53 50.95 46.76 92.73
Category 3: Not currently viable; Held under Retention Lease
Field Operator Reserves ##
Oil (MMbbl) Condensate (MMbbl) Gas (Bcm)
90% 50% 90% 50% 90% 50%
Australind ChevronTexaco 0.00 0.00 0.00 0.00 0.00 0.00
Brecknock Woodside 0.00 0.00 52.02 103.03 104.77 150.08
Brecknock South Woodside 0.00 0.00 59.75 86.80 79.01 112.41
Blencathra Apache 2.45 4.03 0.00 0.00 0.02 0.03
Capella Woodside 0.00 0.00 5.03 13.21 5.92 15.83
Chrysaor–
Dionysus ChevronTexaco 0.00 0.00 34.00 39.54 94.86 112.94
Dixon/W.Dixon Woodside 18.24 25.79 5.66 8.18 3.14 4.35
Egret Woodside 4.40 11.32 0.00 0.00 0.14 0.39
Flinders Shoal Apache 0.38 1.82 0.00 0.00 0.43 0.74
Geryon ChevronTexaco 0.00 0.00 67.43 86.80 73.00 94.00
Gorgon ChevronTexaco 0.00 0.00 107.00 132.00 436.50 520.43
Iago ChevronTexaco 0.00 0.00 7.60 15.80 17.52 27.67
Io–Eurythion ChevronTexaco 0.00 0.00 19.81 30.95 105.16 164.86
Io South ChevronTexaco 0.00 0.00 4.15 6.23 21.89 33.90
Jansz Mobil 0.00 0.00 29.44 82.84 156.31 439.48
Macedon BHP 0.00 0.00 0.00 0.00 15.18 21.69
Orthrus–Meanad ChevronTexaco 0.00 0.00 13.90 31.20 15.00 33.95
Petrel Santos 0.00 0.00 0.00 0.00 0.00 0.00
## Reserve figures are based on those provided to the Department of Industry and Resources by operating companies at 31/12/02.
62 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003

WESTERN AUSTRALIAN PETROLEUM FACT SHEET|
TABLE 2. RESERVES AS AT 31 DECEMBER 2002 — UNDEVELOPED FIELDS (CONTINUED)
Category 3: Not currently viable; Held under Retention Lease
Field Operator Reserves ##
Oil (MMbbl) Condensate (MMbbl) Gas (Bcm)
90% 50% 90% 50% 90% 50%
Prometheus–
Rubicon Kerr-McGee 0.00 0.00 0.00 0.00 6.91 10.45
Pyrenees BHP 0.50 3.90 0.00 0.00 0.16 1.08
Rankin–Sculptor Woodside 0.00 0.00 1.26 13.84 1.09 11.45
Scarborough Esso 0.00 0.00 0.00 0.00 133.00 170.00
Scott Reef Woodside 0.00 0.00 63.02 121.02 172.73 325.64
Spar ChevronTexaco 0.00 0.00 3.70 11.60 1.69 9.91
Tern Santos 0.00 0.00 2.23 5.65 9.91 11.76
Turtle Basin Oil 5.22 7.74 0.00 0.00 0.00 0.00
Urania ChevronTexaco 0.00 0.00 6.33 7.80 6.14 7.54
West Tryal Rocks ChevronTexaco 0.00 0.00 53.00 72.00 68.80 99.48
Wilcox Woodside 0.00 0.00 15.10 20.13 7.00 9.69
Total 31.19 54.60 550.41 888.59 1536.27 2389.74
## Reserve figures are based on those provided to the Department of Industry and Resources by operating companies at 31/12/02.
TABLE 3. UNBOOKED RESOURCES AS AT 31 DECEMBER 2002
Oil in place Condensate in place Gas in place
Field Operator MMbbl MMbbl Bcm
Baker Apache 11.70 0.00 0.00
Cadell Santos 0.00 0.19 1.44
Chamois Apache 4.09 0.00 0.00
Cliff Head Roc Oil 100-140.00 0.00 0.00
Dinichthys Inpex 0.00 8.81 4.85
Eaglehawk Woodside 1.01 0.00 0.00
Gorgonichthys Inpex 0.00 556.02 303.00
Gwydion Nexen 5.98 0.00 0.00
Ishmael Woodside 0.00 3.90 2.26
Josephine Apache 0.00 0.00 0.06
Leatherback Apache 2.08 0.00 0.00
Maitland Apache 0.00 0.00 5.00
Mardie Tap Oil 0.00 0.00 17.71
Montague Woodside 0.00 2.52 2.79
Nimrod BHP 0.00 0.00 0.77
Norfolk–Exeter–Mutineer Santos 50-130.00 0.00 0.00
Oryx Apache 31.70 0.00 0.00
Outtrim BHP 8.99 0.00 0.00
Point Torment Gulliver 0.00 0.00 0.25
Scafell BHP 0.00 0.00 7.08
South Chervil Apache 4.84 0.00 0.51
Tusk Apache 23.27 0.00 0.00
Ulidia Apache 0.00 0.00 0.41
Whicher Range Amity 0.00 0.00 45.00
Total 93.66 571.43 391.12
* Unbooked resources are resources that may or may not eventually prove viable.
They are resources which have not at present been delineated, audited or appraised by an independent third party as at the time of
writing this publication.
Reserves in Western Australia
Petroleum Reserves in Western Australia have been compiled under two main headings, Developed Fields and Undeveloped Fields.
Developed Fields are those currently producing fields located offshore in either Commonwealth or State waters or onshore within Western
Australia.
Undeveloped Fields have been sub-divided 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.
In all of the above categories reserves or resources have been quoted at the 90% and 50% probability of recovery levels.
There are also a number of discoveries with unbooked resources which may or may not eventually prove viable. Figures for these potential
resources are shown in the Unbooked Resources table and are quoted as Hydrocarbons Initially In Place (IIP).
WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003 • 63

Abbreviations, permits and conversions
ABBREVIATIONS
API standard method of measuring density of
crude oils by the American Petroleum
Institute
APPEA Australian Petroleum Production &
Exploration Association
bbl barrels
bbl/d barrels per day
bbl/MMcf barrels per million cubic feet
Bcf billion cubic feet
Bcm billion cubic metres
Btu British thermal unit
CALM catenary anchor leg mooring
CGS concrete gravity substructure
DBNGP Dampier to Bunbury natural gas pipeline
DCQ daily contract quantities
DST drill stem test
dwt dead weight tonnes
EOI expression of interest
FPSO floating production storage and offloading
FSO floating storage and offloading
GGT Goldfields gas transmission
GJ gigajoules
Gl gigalitres
Gm gigametres
GWC gas water contact
HBI hot briquetted iron
kcm thousand cubic metres
kcm/d thousand cubic metres per day
km kilometres
km 2 square kilometres
l litres
LNG liquefied natural gas
LPG liquefied petroleum gas
m metres
m 3 cubic metres
m 3 /bbl cubic metres per barrel
m 3 /d cubic metres per day
MMcf million cubic feet
MMcf/d million cubic feet per day
mm millimetres
MMbbl million barrels
MOPU mobile offshore production unit
Mt/a million tonnes per annum
MW megawatts
n/a not available
NCC navigation, control and communication
NWS North West Shelf
NWSGP North West Shelf Gas project
PJ petajoules
RTM riser turret mooring
RT rotary table
t tonnes
64 • WESTERN AUSTRALIAN OIL AND GAS INDUSTRY 2003
t/a tonnes per annum
t/d tonnes per day
Tcf trillion cubic feet
TJ terajoules
TJ/d terajoules per day
TVDSS total vertical distance subsea
UAE United Arab Emirates
WA Western Australia
2D two-dimensional
3D three-dimensional
$ Australian dollars unless otherwise noted
PERMITS/LICENCES
State Petroleum Act 1967
EP1 Exploration Permit
L1 Production Licence
State Petroleum Act 1936 and 1967
L1H Petroleum Licence
State Petroleum Pipeline Licences Act 1969
PL/1 Pipeline Licence
State Petroleum (Submerged Lands) Act 1982
TP/1 Territorial Sea Exploration Permit
TL/1 Territorial Sea Production Licence
TPL/1 Territorial Sea Pipeline Licence
Commonwealth Petroleum (Submerged Lands) Act 1967
WA-1-P Exploration Permit
WA-1-L Production Licence
WA-1-PL Pipeline Licence
WA-1-R Retention Licence
AC/P1 Ashmore/Cartier Production Licence
NTRL-1 Northern Territory Retention Licence
CONVERSIONS
1 barrel of oil = 0.158987 kilolitres of oil
1 kilolitre of oil = 6.28981 barrels of oil
1 standard cubic = 35.3147 cubic feet of
metre of natural gas natural gas
1 billion cubic metres = 730 000 tonnes of LNG
of natural gas
1 terajoule = 26 300 cubic metres of
natural gas
= 0.929 million cubic feet of
natural gas
1 metric tonne of LNG = 1333 cubic metres of
natural gas at 0°C
1 million tonnes of = 1.333 billion cubic metres
LNG per year per year
= 3.65 million cubic metres of
natural gas per day

As at September 2003
INSET B
u u !
!
!
6
O
SEE INSET C
!
Exeter Norfolk
MontaguePitcairn
Mutineer
Eaglehawk Egret!
Hermes
Searipple Lambert
Capella O O uAngel
Perseus u Cossack
North
Gaea
Wanaea
u Rankin
Legendre North
uu
Goodwyn
Echo/Yodelu
u
Sage
Burrup
Legendre
!
Ammonia
Dixon/West Dixon
South
@
Ammonia-urea
Iago/N Tryal Rocks
Saffron
@
N
N Desalination
u u
@ Dimethyl Ether
N
Synthetic Fuels
Wandoo
@
!
u
and Lubricants
O
u
O Stag
@ LNG
@Methanol
N
Cape Lambert
u N
Dampier
N
s Dampier salt
East Spar N
Karratha
N
O
!
u
Dockrell
Keast
; Tidepole
UraniaN
NJansz
;
Geryon N
Reindeer
Wilcox
Caribou
Maenad
Corvus
N N
Orthrus
Chrysaor/Dionysus
West Tryal Rocks
Tusk
Oryx
N Chamois
John Brookes
Gorgon Maitland
Spar
OO
O
u
Goodwyn South/Pueblo;
O
Chinook/Scindian
Griffin !
Chervil
O
Coniston
O
Novara
Vincent Yammaderry
! ! Crest
Cowle!!
Saladin
Skate
! Roller
Onslow
Tubridgi
Nimrod
!
u
Enfield
O
Laverda !
s
N
O
Woollybutt
! Pasco
Flinders Shoal
Mardie
South Chervil !Nasutus
N
O
!
O
N Australind!
Cadell
Pyrenees
OOuttrim
! N
N ; Blencathra
Scafell
Macedon
Coaster
O
O
Leatherback
O Rough Range
s Exmouth
Scarborough N
Perth-Dampier Natural Gas Pipeline
Lake MacLeodqx
Lake MacLeod
s
q q
Wonnich
;
N
!
O
!Little Sandy/Perdika/
O ! u
EndymionuuSinbad
NUlidia
Bambra Linda
B Harriet C O uMonty
Varanus Island A
Josephine
Baker
Barrow Island
N
LeeN
Roseu
Rosette N.Gipsy!
Agincourt u Gipsy
! ! u
Alkimos/Tanami Gibson/S.Plato
/Simpson
N Victoria
Hoover
Barrow Double
Island Island
NNarvik
0 100 j Paulsens
Nammuldi/Silvergrass I
Brockman No. 2 I
200 km
Carnarvon
SEE INSET B
Major Resource Development Projects: Western Australia
Fortescue
I
Austeel DRI/HBI
I
Robe River
I
nRadio
Hill
K Munni Munni
Port Hedland
Port Hedland Salt
Boodarie HBI Y q
y Hitec EMD
Yarrie
I
Whim Creek Cu
Wodginat Panorama Zn Cu
Woodie Woodier
Nifty Cu
Marandoo
Marillana Creek Yandi/BHPB
I
Yandicoogina/HI
Tom Price
I
I
I
Mining Area C I Hope Downs
West
I Rhodes Ridge
Paraburdoo I AngelasI
I
Eastern Range II
Orebody 23 & 25
Channar
Giles Mini I I I
Jimblebar
Mt Whaleback
I
j
Coobina
Mt Olympus
c
Plutonic j
Dinichthys
Gorgonichthys N O Cornea
N
N
NN Titanichthys
Scott Reef Brewster
N Brecknock
N Brecknock South ! Gwydion
Broomeq
6 West Kimberley
Jundee/Nimary
j
j
j
j
j
j Bronzewing/Mt McClure
j
j
j
j
j
j
j
j
j
j
j
jj
j
v
j
j j
?
?
j
q
Bluebird
Weld Range
Magellan Pb Z
Wiluna
Big Bell
Gidgee
Hill 50 Bulchina Agnew
Darlot
Port Gregory
Lawlers
G ITallering
Peak
V Windimurra
jThunderbox
Oakajee
jKirkalocka
q
Tarmoola
Granny Smith
Narngulu Synthetic Z Golden Grove Zn Cu
Geraldtonq
P
JRutile jMinjar
Sons of Gwalia j
R
Mount Horner
Yardarino
Sunrise Dam
Nu
Dongara
I Koolanooka
Mt Ida Timoni j
Cliff Head O
Three Springs
T
Nu
I
Davyhurst
um
Eneabba j
j
Mt Gibson
Paddington
Carosue Dam
Lady Ida
Kanowna Belle/Red Hill
Cooljarloo m
Koolyanobbing I
j
j j Super Pit
j Kalgoorlie Ni Smelter
j j Jubilee
Westonia j
St Ives
Marvel Loch/
j
Southern Cross Yilgarn Star
t Bald Hill
j Central Norseman
O'Sullivans
Jangardup
m Manjiump
Mirambeena
OO s
m Coburn
Kwinana/Rockingham
q AIS Jetty
a Alumina Refinery
@ BP Oil Refinery
C Cement and Lime Chandala
@ Chlor Alkali
J Synthetic
@ Chemicals
Rutile
@ Chemicals/ 1
Fertilizers Flynn Dr
@ Fused Alumina
@ Fused Zirconia
HIsmelt
Fremantle
@ LPG
v Nickel Refinery
8 Power Station
@ Sodium Cyanide
J Titanium Pigment
@ Zirconia
aPinjarra
ab
Huntly
Pinjarra Gallium
m Waroona
aWagerup
b
Saddleback
@ Chlor Alkali Kemerton
X Silicon Smelter w Sandlewood
m
J Titanium
aWorsley
Pigment
h8 Collie
qBunbury m Ewington h Premier
Dardanup 1 Dardanup h Muja
Capel m Collie Pig Iron 8
Capel SyntheticJ
Gwindinup
Rutile
Donnybrook
Tutunup m
m Yoganup
tGreenbushes
Mt Weld
Hovea
Om
Jingemia Dongara
Beharra Springs/
Windarling Range
North Beharra
I
Springs Woodada
Mt Jackson I
Mt Pleasant
Kundana/
Frogs Leg
White Foil
Coolgardie
New Celebration
Forrestania
Scaddan
8
q
mJangardup South I Southdown
Y
I Honeymoon Well n
INSET A
Y
q
0 50km
j
Boddington Au Cu
Kemerton
m
1
Whicher Range
N
Mt Keith
Yakabindie n
Cosmos n
Leinster n
Murrin
Murrin
Goongarrie n
Cawse
SEE INSET A
Miitel
Emily Ann/Maggie Hays
Rav 8
Ravensthorpe/BHPB n
Shark Bay
PERTH
Marshall Pool
Jaguar-Teutonic Bore
Comet Vale
Long/Victor
PERTH
Esperance
1
1 Albany
INSET C
Z
PILBARA
Campbellu
Z
n
n
n
n
rAnt Hill
Z
Z
n Black Swan
n
Koolan Island
Cockatoo Island II
jTelfer
Au Cu
0 100 200 300 400
km
n
n
n
n
Z
n Bulong
n Kambalda
OJabiru
O Challis
O
O
N
OliverN
Tenacious N Audacious
!
Maple N
Puffin Swan
Padthaway Talbot
Tahbilk N O Montara
N Crux
N
Prometheus/Rubicon
N Point Torment
Derbyq Lloyd O Boundary
West Terrace O
Sundown O d Ellendale
Blina
Maroochydore Cu Co
Loxton Shoals N
Troubador N
Bard N N
Sunrise
NKelp
Deep
Jahal
Laminaria East O
O Kuda Tasi Chudditch
!
N
Buffalo OO
Krill
O Elang-Kakatua
N Hingkip
! Bayu-Undan
b Mitchell Plateau
Z
N Tern
Blacktip N
Ord Stage 2-M2
6
Ord Stage 2-Mantinea Flats 6
6
Ord Stage 1
6
q
Wyndham
Lake Argyle Hydro
KIMBERLEY
Pillara Zn Pb
Argyle d
Sally Malayn
Panton Sill K
RESOURCE SYMBOLS
Bauxite-Alumina
a Alumina refineries
b Mines and deposits
Chemicals / Petrochemicals / Petroleum
@ Processing plants / refineries
N Natural gas field
O Oil field
! Natural gas / oil field
u Natural gas / condensate field
; Natural gas / oil / condensate field
Chromite
c Mines and deposits
Coal
h Coal mines and deposits
? Lignite mines and deposits
Copper-Lead−Zinc
Z Mines and deposits
Diamonds
d Mines and deposits
Gold
j Mines and deposits
Gypsum
x Mines and deposits
Heavy mineral sands
m Mines and deposits — titanium-bearing sands
G Mines and deposits — garnet-bearing sands
J Ti02 pigment and synthetic rutile plants
Iron ore
I Mines and deposits
Y Downstream processing plants
Limestone−Limesand
4 Mines and Deposits
C Cement plants
Manganese ore
r Mines and deposits
y Downstream processing plants
Nickel
n Mines and deposits
v Smelters and refineries
Phosphate
P Mines and deposits
Platinoids
K Mines and deposits
Rare earth elements
R Mines and deposits
Salt
s Production facilities / pans
Silica − Silica Sand
w Mines and deposits
X Silicon smelters
Talc
T Mines and deposits
Tantalum
t Mines and deposits
Vanadium−Titanium
V Mines and deposits
NON-MINERAL PROJECTS
6 Irrigation/water schemes
q Major port handling facilities
8 Major power stations
1 Downstream timber processsing plant
GAS PIPELINE
OPERATING PROJECTS ARE SHOWN IN BLUE
POTENTIAL PROJECTS ARE SHOWN IN RED
PROJECTS ON CARE AND MAINTENANCE ARE
SHOWN IN PURPLE
Western
Australia
Petrel
Turtle

Department of
Industry and Resources
Head office:
Mineral House
100 Plain Street
EAST PERTH WA 6004
Telephone: +61 8 9222 3333
Facsimile: + 61 8 9222 3430
email: enquiries@doir.wa.gov.au
This publication is now available on our website:
www.doir.wa.gov.au