More than 90 per cent of Australia’s 164 trillion cubic feet (Tcf) of gas lies in offshore basins. Some of these basins are located in water depths up to 5,495 m, which pose a number of challenges to companies seeking to develop the resources and bring them to market.
Australian Petroleum Production and Exploration Association (APPEA) Chief Executive Belinda Robinson said “A key challenge for government is to persuade a globalised exploration industry to risk its expenditure on exploring in high cost, high risk frontier areas in Australia.”?
An APPEA white paper from April 2009 highlighted that only 17 per cent of Australia’s offshore petroleum basins are covered by petroleum titles.
“Under-explored areas hold the greatest promise of major discoveries but are often high risk and remote from infrastructure and involve high costs for explorers,”? the report states.
There are currently 220 offshore exploration permits, 39 retention leases and 80 production licences governed by state and federal regulatory regimes.
Since Australia’s first offshore petroleum discovery in the Gippsland Basin in 1964, offshore exploration in Australia still predominantly centres around Victoria’s Bass Strait and Western Australia’s North West Shelf. While the majority of offshore gas comes from these abundant basins, other exploration and production projects are also underway in western Victoria, Northern Territory and the offshore Sydney Basin in New South Wales.
Underway in WA
Woodside Petroleum is currently developing the Pluto and Xena gas fields, located approximately 190 km northwest of Karratha in Western Australia, which together hold an estimated 5 Tcf of dry recoverable gas. The development of these resources through the Pluto LNG Project is underpinned by gas sales agreements with Kansai Electric and Tokyo Gas, who are also project participants. LNG from the first train is expected in early 2011, and design work is underway for the second and third trains.
Woodside also operates a number of gas fields in Western Australia’s Browse Basin, including Torosa, Brecknock, Brecknock South, and Calliance. The fields contain a combined contingent resource of approximately 13.3 Tcf of dry gas. In conjunction with joint venture partners BHP Billiton, BP, Chevron and Shell, Woodside has proposed to develop gas from the fields at an onshore LNG plant to be located north of Broome.
The Gorgon Gas Field has certified resources totalling approximately 40Tcf of gas. Operator of the Gorgon LNG Development Chevron has outlined development plans including between 20 and 30 development wells to be drilled in the area over a 30-year period. The wells will be connected to a system of cluster manifolds and flowlines to carry the gas to the 15 million tonnes per annum (MMt/a) LNG facility at Barrow Island.
Major construction activity is expected to commence in the second half of 2010, with construction of the project expected to take five years. First gas is due in 2014.
The North Rankin 2 (NR2) Project will involve the installation of a second 23,600t platform at the North Rankin Field, which will stand in approximately 125 m of water and include gas compression facilities, utilities and new living quarters.
The North Rankin B platform will be connected by a 100 m bridge to the existing North Rankin A platform. The NR2 Project will also include necessary tie-ins and refurbishment of North Rankin A. Upon completion, both platforms will be operated as a single integrated facility.
Woodside has selected Wood Group’s Mustang to provide an independent assessment and verification of readiness for the North Rankin B platform topsides.
Planning for gas
Chevron also operates the Iago Gas Field, and the Wheatstone Gas Field and LNG development, located northeast of the Gorgon fields. Chevron will develop the resources, estimated at 4.5 Tcf of gas, through an onshore LNG processing facility at Onslow, Western Australia. A final investment decision on the project is set for mid-2011.
The facility, which will involve an 8.6 MMt/a LNG plant and a 250 MMcf/d domestic gas plant, will also process gas from the Julimar and Brunello gas fields. The fields are jointly owned by Apache and Kuwait Foreign Petroleum Exploration Company (KUFPEC), who will each gain an interest in the project. The Julimar and Brunello fields have a combined total of 2.1 Tcf of gas reserves.
Shell is planning to develop the Prelude Gas Field, located in the northern Browse Basin 475 km offshore Western Australia, using floating LNG (FLNG) technology.
The Prelude FLNG plant is intended to remain over the Prelude field for 25 years, with the project designed to produce up to 3.6 MMt/a of LNG, 0.4 MMt/a of LPG and 1.3 MMt/a of gas condensate during that time. Shell has said that the production rate may be backfilled in later years with gas sourced from the nearby Concerto, Crux and Libra fields.
The project is expected to be the first of its kind to incorporate FLNG technology in Australia, and will comprise of upstream facilities including wells, four flowlines approximately 4 km in length, umbilicals and flexible risers, as well as the FLNG facility. The plant will include liquefaction units, production storage and loading facilities, associated utility systems and a control room, maintenance facilities and accommodation.
The final investment decision for the project is scheduled for early 2011 and first gas is scheduled for 2016.
The Ichthys Gas Field is located in the Browse Basin, approximately 200 km offshore northwest Australia, holding an estimated 12.8 Tcf of gas and 527 MMbbl of condensate.
INPEX is proposing to develop the resources by constructing offshore processing facilities and condensate storage, and an 885 km pipeline from the field to the 8.4 MMt/a LNG processing facility at Blaydin Point on the Middle Arm Peninsula, Darwin.
BHP Billiton is assessing a number of development options to commercialise an estimated 8-10 Tcf of gas resources in the Scarborough Gas Field, located approximately 285 km offshore from the Pilbara town of Onslow in 900 m of water.
BHP Group President of Petroleum Mike Yeager has said BHP and joint venture partner ExxonMobil were aiming to commence a front-end engineering and design contract and a definitive project schedule in the 2011 financial year. Current work on the project includes collection of field data, engineering and commercial studies for the various options under consideration.
On the NWS, Woodside is currently undertaking predevelopment studies and examining options to target approximately 3 Tcf of gas held in a group of 14 undeveloped fields west of Goodwyn, Western Australia to supply the NWS LNG Project.
The predevelopment studies include geophysical, geotechnical environmental surveys and a metocean program designed to provide data to support project investment, engineering and operational decisions relating to potential platforms, floating production, storage and offtake facilities (FPSO), floating storage and offtake facilities (FSO) and subsea infrastructure including a pipeline, flowlines, manifolds and wellheads.
MEO Australia has proposed the development of two separate methanol plants and an LNG plant which will be grounded in shallow water at Tassie Shoal in the Australian waters of the Timor Sea, approximately 275 km north of Darwin. Approximately 25 Tcf of undeveloped gas lies within 150 km of Tassie Shoal.
When completed, the 3 MMt/a LNG plant will supply export markets, and a storage tank will have capacity for 170,000 cubic metres of LNG.
The project will involve gas supply pipelines from Evans Shoal and other fields to Tassie Shoal; storage tanks for LNG, methanol, condensate, fuel, fresh water and other products; and loadout and mooring infrastructure.
The initial methanol plant phase of the project will be ready for FEED studies later in 2010, as soon as gas supply can be confirmed.
The Sunrise joint venture partners have announced the selection of a Shell-designed floating LNG (FLNG) facility as the preferred processing option for the Greater Sunrise Gas Fields Development, located in the Timor Sea, approximately 450 km northwest of Darwin and 150 km south of Timor-Leste.
The FLNG development would produce approximately 4 MMt/a of LNG for export, plus the associated condensate. The floating facility would store and export LNG via an LNG carrier and condensate via a shuttle tanker.
Development is contingent on the project receiving legal, regulatory, and fiscal certainty for the Timor-Leste and Australian governments. Following the announcement of FLNG as a development concept, there has been ongoing debate between Woodside and the Timor-Leste Government, which has called for further study into development options, including the construction of a pipeline to Timor-Leste shores.
The offshore Petrel Gas Field, discovered in 1969, is located approximately 250 km west of Darwin on the Western Australia/Northern Territory seabed border in the Bonaparte Basin. The offshore Tern Gas Field, discovered in 1971, is located approximately 300 km west of Darwin in Western Australian waters in the Bonaparte Basin.
A joint venture between GDF SUEZ and Santos is planning development of the fields using floating LNG technology and expects to produce 2 MMt/a of LNG. From 2011, the fields will be operated by GDF SUEZ, with the first project phase expected to last approximately three years before FID. A drilling campaign is scheduled by the end of 2010 to confirm reservoir potential.
Under construction in the Bass
Located 45 km from Ninety Mile Beach on Victoria’s Gippsland coast, ExxonMobil’s Kipper Gas Field is estimated to contain approximately 620 billion cubic feet (Bcf) of recoverable gas and 30 million barrels (MMbbl) of condensate/LPG.
The project is being progressed in two major steps. Stage 1 is currently underway with the Ocean Patriot drilling two subsea gas wells and the MV Havila Harmony installing four flowbases and two subsea trees for the Kipper Field.
Gas will be piped to shore via the West Tuna platform and processed through Esso and BHP Billiton’s infrastructure and processing facilities in Longford. Pipelay for the project is scheduled to begin in October 2010 and be completed by December 2010.
Jacket fabrication has been completed, and topside fabrication is continuing, as is retrofit work at the West Tuna platform. Installation of the Marlin B jacket and associated modules will commence in late 2010.
Installation of four subsea coolers and one manifold is scheduled for the first quarter 2011 as is final installation and tie-in activities of new infrastructure using a combination of remote operated vehicles and divers.
Stage 2 will involve new gas compression services at the facility to be completed in 2016.
First gas is expected in the first half of 2011, subject to the finalisation of construction contracts.
Gas for Victoria’s future
In addition to the oil field which is in operation, the Basker-Manta-Gummy fields hold contingent gas and gas liquids estimates, which are about 380 PJ and 19 million barrels, respectively. ROC Oil is proposing to develop a 70 km floating pipeline to shore for distribution through the Eastern Gas Pipeline. The gas project is likely to include a gas treatment plant on a floating facility rather than a land-based plant. First gas is expected in 2011.
Santos has proposed the development of the Sole Gas Field, located off the coast of Victoria.
A 40 km subsea pipeline will connect the field to the existing Patricia Baleen gas plant on the Victorian coast, 10 km from Orbost.
Operations at the Patricia Baleen gas processing plant involve separation, compression and dehydration of raw gas. Sales gas is then transported to the Eastern Gas Pipeline.
Current capacity is approximately 43 terajoules per day (TJ/d), however the plant has been sized to process 75 TJ/d in anticipation of gas from other suppliers in the region.
New South Wales
Preparations are on schedule for Advent Energy and Bounty Oil & Gas to commence its 2010 drilling program in PEP 11, offshore Sydney Basin. Santos and Ampolex have previously conducted seismic studies to evaluate the potential of the permit, but no drilling has occurred in the basin. Advent Energy considers the basin to contain multiple Tcf of gas.
The 2010 Offshore Petroleum Exploration Acreage Release comprises 31 areas, located across five basins in Commonwealth waters in the offshore areas of Western Australia
(26 areas), the Northern Territory (1 area), the Territory of Ashmore and Cartier Islands (2 areas) and South Australia (2 areas).
The release areas are supported by pre-competitive seismic data and seafloor mapping studies of frontier areas off Australia’s west coast conducted by Geoscience Australia (GA).
“The Westralian Superbasin along the North West Shelf continues to feature prominently in the Release and is complemented by a new frontier area in offshore southwest Australia (Mentelle Basin) and by two areas in the Ceduna/Duntroon Sub-basins in the eastern part of the Bight Basin,”? the release states.
John Hartwell Head of Division, Resources, Department of Resources, Energy and Tourism said “The probability of future petroleum finds is significant””more than 40 Australian sedimentary basins await in-depth exploration to determine their full potential.”?