General Manager, Petroleum Resources,
and Karina Jonasson,
Petroleum Resource Geologist
Petroleum and Royalties Division,
Department of Industry and Resources
Over the past decade, Perth has become the centre of petroleum activities in Australia. Western Australia (WA) is currently the nation’s largest petroleum producer and holds 57% of Australia’s oil, 71% of its condensate and 79% of its gas reserves. The petroleum industry has been the fastest growing economic sector in WA since the 1990s.
Since the 1980s, petroleum production in WA has increased substantially particularly with the development of the North West Shelf project. The primary focus of petroleum exploration has been the offshore northern Carnarvon basin, where field development and infrastructure continue to grow.
Planning is underway for 20 new petroleum projects involving a minimum $22 billion investment over the next few years. Most of the future oil developments come from Exmouth Sub-basin fields and contain heavy oil. The current boom in the liquefied natural gas (LNG) market underpins a number of LNG developments, and it is expected that industry will apply to develop other LNG projects in the near future. The majority of these oil and LNG developments are expected to come on stream during the coming decade.
These petroleum development projects will benefit Western Australians through an increase in royalty revenue for the government, new employment, regional development, and infrastructure development, and are crucial to both State and nation as they provide Australia with a greater degree of self-sufficiency in liquid production, as well as additional security
Australia needs to grow its domestic reserves base, particularly its liquids. Unless there are increased industry efforts, along with government assistance in this respect, Australia’s self sufficiency in liquid hydrocarbon production will drop from 75% to 25% by the year 2020, according to the Australian Bureau of Agricultural and Resource Economics (ABARE). This will have a significant impact on Australia’s balance of payments and Government
Production and reserves
The northern Carnarvon basin at present is by far the largest producing basin in Western Australia with 97% of WA’s oil and gas production. Western Australian sedimentary basins currently hold more than 80% of Australia’s discovered natural gas resources. The number of developed and producing fields has almost doubled over the past decade. Currently there are 67
A peak in oil production is expected around 2008-09 mainly attributable to the development of heavy oilfields in the Exmouth Sub-basin), though there is a sharp decline after this point. Between 2010 and 2020, condensate production from gas condensate fields will play a key role in maintaining WA liquid hydrocarbon production in the future. Since condensate production comes principally from LNG developments, the forecast decline in condensate production is much slower than the decline in oil production. Future gas production is committed to upcoming LNG projects.
WA’s total P50 estimated liquid and gas petroleum reserves at the end of December 2005 were 293 GL (1.84 Bstb) and 1390 Gm3 (49.1 Tscf), respectively. At 31 December 2005, a cumulative total of 194 GL (1.22 Bstb) crude, 80 GL (505 MMstb) condensate and 386 Gm3 (13.6 Tscf) gas had been produced from Western Australian oil- and gasfields.
Future oil developments
The majority of WA’s new oil developments are located in the Exmouth Sub-basin. These include a series of significant discoveries, namely, Enfield, Vincent, Pyrenees, Stybarrow and Laverda, which contain more than 48 GL (300 MMbbl) of heavy crude reserves. These fields are expected to come on stream before the end of this decade and their combined initial production is estimated at nearly 40 000 kL/d (250 000 bbl/d).
The development of these fields represents a number of technical challenges. The oil in these fields is heavy (17–22° API), has relatively high viscosity (7–11 cp), and some of these fields have thin oil legs. As such, their production would decline very rapidly. These fields are situated close to an environmentally sensitive area: the Ningaloo Marine Park, which requires additional precautions in the development process.
Stybarrow-Eskdale Development (Operator, BHP Billiton)
The Stybarrow oilfield is located in WA-255-P (2) in the Exmouth Sub-basin, approximately 65 km from Exmouth. Stybarrow is a joint venture with Woodside Energy Limited.
At a water depth of 825 metres, this will be by far the deepest oilfield development ever undertaken in Australia. The Eskdale oil- and gasfield is situated 12 km northwest of Stybarrow in the same permit block. Mean recoverable oil reserves are estimated at
14.3 GL (90 MMbbl) of oil.
The proposed development includes a Floating Production Storage and Offloading (FPSO) facility. First production is expected in the first quarter of 2008 with an estimated economic life of about 10 years.
Pyrenees Development (Operator,
BHP Billiton has announced its intention to develop the Pyrenees cluster of oilfields (Ravensworth, Crosby, Stickle and Harrison). These fields are situated in the Exmouth Sub-basin about 45 km northwest of Exmouth, in water depths of approximately 200 metres. Potential recoverable oil reserves are estimated at 47.7 GL (300 MMbbl) of oil equivalent.
Subsea wells will be connected to a FPSO facility. It is planned that first oil will be produced from these fields in late 2008. The expected field life is 20 to 25 years.
Vincent Development (Operator, Woodside Energy)
The Vincent oilfield is located in Production Licence WA-28-L and Exploration Permit WA-271-P, about 50 km northwest of Exmouth. The water depth is about 350 metres.
Woodside is the operator (60%) on behalf of its joint venture partner Mitsui E&P Australia Pty Ltd (40%).
With estimated recoverable reserves of around 11.4 GL (72 MMbbl), first oil is targeted for 008. Field life is estimated at 10 to 20 years.
Future gas and gas condensate developments
WA’s North West Shelf has estimated natural gas resources of more than 3168 Gm3 (130 Tcf). Australia is strategically located to supply LNG throughout the Asia Pacific region with LNG exports playing an increasingly important role in the Western Australian energy scene.
In the next decade several significant gas discoveries such as Greater Gorgon, Jansz-Io, and Scott Reef-Brecknock, each in excess of 560 Gm3 (20 Tcf), will be bought on stream supplying export LNG. These forthcoming developments include fields that were regarded as stranded gas when they were discovered 20 to 30 years ago.
While some of these gasfields contain significant condensate reserves, producing this condensate would depend on the timeframe of the LNG contracts. Fields with a low condensate-gas ratio (CGR), i.e. less than 56 m3/Mm3 (10 bbl/MMscf), such as Gorgon, Jansz-Io, and Scarborough, would not have a significant contribution to condensate production. However, for Ichthys, with a CGR of over 280 m3/Mm3 (50 bbl/MMscf), and Brecknock fields, which are expected to have a combined daily condensate production of 12.7 ML/d (80 000 bbl/d) sustainable for more than 20 years, the contribution is much more significant.
Angel Development (Operator,
The Angel gas-condensate field is located approximately 53 km east-northeast of the North Rankin A platform (NRA) and some 123 km northwest of the onshore gas plant at Dampier in 80 metres of water. The field lies entirely within Production Licence WA-3-L. Woodside Energy Ltd operates the Angel field on behalf of the North West Shelf Joint Venture (made up of Shell Development (Australia) Pty Ltd, BHP Petroleum (North West Shelf) Pty Ltd, BP Developments Australia Pty Ltd, Chevron Australia Pty Ltd, Japan Australia LNG (MIMI) Pty Ltd, and Woodside Energy Ltd, each having a one-sixth share).
Development includes the installation of a platform based production infrastructure with a design life of 20 years, which may facilitate future, phased development of satellite fields. The field is expected to come on stream by the third quarter 2008.
Gorgon Development (Operator, Chevron)
The Gorgon gasfield is situated 130 km off the northwest coast of WA and 65 km from Barrow Island. The Gorgon gasfield has certified proven hydrocarbon gas reserves of around 280 Gm3 (10 Tcf). The field is jointly owned by Chevron (50%), Shell (25%), and ExxonMobil (25%).
The field development concept consists of sub-sea wells arranged in several production centres over the field, tied back to gas processing facilities on Barrow Island via a 70 km pipeline. A gas connection will be installed from Barrow Island either to the mainland direct or to the existing offshore network some time in the future, thereby allowing Gorgon gas to be sold into the domestic market.
The Gorgon Joint Venture is committed to the responsible management of greenhouse gas emissions and plans to inject Gorgon CO2 into a saline aquifer under Barrow Island. The Gorgon project is envisaged to come into operation in 2010 with two 5 million tonnes per annum LNG trains on Barrow Island.
Jansz-Io Development (Operator, ExxonMobil)
The Jansz-Io field extends across the
WA-18-R, WA-25-R and WA-26-R retention leases.
WA-18-R covers the central and northwestern part of the field and is operated by ExxonMobil (with a 50% equity), with the remaining interest being held by Chevron Australia Ltd. WA-25-R and WA-26-R are operated by Chevron (50%) on behalf of a joint venture that also includes ExxonMobil (25%), BP Exploration (Alpha) Ltd (12.5%) and Shell (12.5%). ExxonMobil, as the operator of the Jansz-Io development project, intends to develop the Jansz-Io resource in a cooperative development linked to the Gorgon Development Project. Both the Gorgon field development and the LNG plant construction will be operated
A framework Agreement was reached in May 2005 between some of the companies having equities in the Greater Gorgon – Jansz area (Chevron, ExxonMobil and Shell). The Joint Venture participants have agreed to align their equity interests in individual licences in the Greater Gorgon area.
The development scheme proposed by the operator is based on gas production for more than 40 years with an average annual rate of 210 Mm3/d (740 MMscf/d). It is estimated that the field will produce at a plateau rate for approximately 20 years. The field is expected to come on stream by 2012.
Pluto Development (Operator, Woodside Energy)
The Pluto field is located in permit WA-350-P (100% Woodside), about 185 km northwest of Dampier. Pre-drill assessment suggests that the Pluto prospect could contain about 70.7 Gm3 (2.5 Tcf) of gas.
Woodside plans to have the project on stream by late 2010. As sole owner of the Pluto field, Woodside is eager to build a five to seven million tonnes per year project to boost its direct share of the world LNG trade.
Scarborough Development (Operator, ExxonMobil)
The Scarborough gas field is located in around 900 metres of water and about 280 km offshore, with probable reserves of approximately
226 Gm3 (8 Tcf) of gas. ExxonMobil announced in May 2006 that it is now interested in assessing the potential development. Joint venture partner BHPB is also conducting a pre-feasibility study to assess the viability of providing Scarborough gas to its proposed Pilbara LNG plant
Brecknock / Brecknock South and Scott Reef Development (Operator, Woodside Energy)
Woodside’s extensive gas reserves in the Browse Basin, off WA’s Kimberley coast, have the potential to create a major gas production hub for Australia. Combined, the fields represent a substantial undeveloped gas and
The initial development concept for Woodside’s Browse project involves offshore facilities and from one to three LNG processing trains with the capacity to process about 7 to 14 million tonnes a year. Browse could also supply natural gas to Australian markets. The first LNG cargo from Browse could be delivered by 2014.
If both Pluto and Browse are developed as hoped, Woodside’s LNG production could rise fivefold by the middle of the next decade, making it one of the world’s single
Ichthys Field Development (Operator, INPEX)
INPEX Browse Ltd, had a 100% interest in Exploration Permit WA-285-P and Total has recently signed an agreement to acquire a 24% interest. Project start up is expected in the next five to eight years.
North West Shelf expansion
Following the approval for a 5th LNG train, the North West Shelf Venture is now progressing a number of offshore projects to meet gas supply requirements. Some of the projects under consideration are:
Perseus-over-North Rankin / Perseus-over-Goodwyn (Operator, Woodside)
Woodside Energy Ltd operates the Perseus field on behalf of the Northwest Shelf Joint
The Perseus field, located in WA-1-L in 130 metres of water, is currently developed by three ‘Big Bore’ wells drilled from the North Rankin (NRA) facility located approximately 135 km offshore from Dampier in the northwest of Western Australia. Three further ‘Big Bore’ wells were being drilled in 2006 from the NRA platform (‘Perseus-over-North Rankin’). Future phases will include further platform wells and gas compression on the NRA platform.
The subsea development in the southern and western parts of the Perseus field, with gas exported via the Goodwyn (GWA) facility, has a planned startup date of early 2007. This two-stage component of the development, which includes the Searipple accumulation, is known as ‘Perseus over Goodwyn’ and involves new wells and a new trunkline to GWA. Work started in 2004 and is scheduled for completion in 2007. Perseus has an expected ultimate recovery of 280 Gm3 (10 Tcf) of gas.
Goodwyn Western Flank Development (Operator, Woodside)
The Goodwyn gasfield is located 23 km southwest of North Rankin field. The phased development of Goodwyn satellite gas and oil accumulations includes Goodwyn South, Dockrell, Keast, Echo-Yodel, Sculptor-Rankin, Tidepole, and Wilcox. Development will most likely consist of subsea developments tied back to the GWA platform. Approximate start up is 2008–2011.