Whereas development in the Northern Territory and Timor Sea region had previously focussed on oil or wet gas, increasing liquefied natural gas (LNG) prices have propelled gas exploration in what had been stranded fields, located several hundreds of kilometres offshore. These fields are central to the resurgence of the Northern Territory gas industry in the Asia-Pacific region and are spurring a range of exciting and sometimes unique developmental proposals, from conventional onshore and offshore developments to floating LNG (FLNG) and methanol plants.
Supplying domestic demand: from the Amadeus Basin through to Blacktip
In part because of the state’s lower level of domestic gas demand in comparison to other Australian states, the Territory’s gas industry is a relatively late bloomer. Historically, gas production in the Northern Territory has come from the Palm Valley and Mereenie gas fields, both of which are located in central Australia’s Amadeus Basin. Despite the discovery of gas in these fields in 1965 and 1963 respectively, first gas production did not begin until the 1980s.
Magellan Petroleum’s Palm Valley field, located about 120 km west of Alice Springs, produces gas from eleven wells, which is transported to Alice Springs through a 1,628 km pipeline to Darwin.
Development of the field and pipeline was initially underpinned by a 28-year gas supply deal with Northern Territory’s Power and Water Corporation. Proved ultimate recoverable gas reserves at the field are estimated at 226 billion cubic feet (Bcf), with cumulative production until the start of 2007 totalling 145 Bcf.
The Mereenie field, whose gas is also transported through the same pipeline to Darwin, commenced gas production in 1987. The $280 million project has involved development of approximately 57 wells and 80 kilometres of pipelines and flowlines. These connect the fields to the Eastern Satellite Station and the Central Treatment Plant, which comprises oil and gas processing facilities. To date, gas from two fields has produced a combined rate of 20 petajoules per annum with the majority being produced from the Mereenie field.
Though it is one of Australia’s least explored onshore petroleum-bearing basins with proven reserves, supply from the Amadeus Basin has become more costly and difficult to extract over the last few years, with gas sales from the Palm Valley and Mereenie fields declining. Magellan Petroleum has found that in the most recent quarter, production declined by 7 per cent. Instead of focussing on further exploration within the basin, developers have looked further afield to supply gas to generate power for the Top End. Specifically, developers have been focussing approximately 110 km offshore to Eni’s Blacktip field, located in permit WA-279-P of the Timor Sea.
With recoverable reserves of 150 million barrels of oil equivalent (MMboe), development of the Blacktip field has comprised drilling of two development wells. Gas from the field, located in 50m water depth, will be brought onshore through a 110 km offshore pipeline. Gas will be piped to a 1.3 billion cubic metres per annum (Bcm/a) gas processing facility plant at Wadeye and then transported using the Amadeus Basin to Darwin Pipeline and the Bonaparte Pipeline to power stations from Darwin to Alice Springs. Works on the gas development are on schedule to be completed in the second half of 2008. Production is planned to begin in January 2009 at an initial annual rate of 650 MMcm, increasing to 1.1 Bcm.
The Council of Australian Government’s (COAG) report on Northern Territory’s Infrastructure has said that from 2009, the Amadeus Basin fields will be capable of supplying “˜tail gas’ to other customers using existing infrastructure. Similarly, a technical review by Central Petroleum of the Ordovician Horn Valley Siltstone (HVS) petroleum system, located in the Amadeus Basin in the Northern Territory, has found that there may be significant unevaluated potential for non-conventionally reservoired gas. However COAG has also suggested that such supply will be subject to finding sufficient markets for the fields to remain operationally and financially viable.
While demand for gas-fired power generation has grown in the Territory, it remains quite modest and is able to be sourced from current contracts, suggesting that the expansion of gas production for domestic demand in the Territory is likely to require the development of a gas-intensive resource industry.
While Western Australia and Queensland use their gas reserves to service the mining and minerals processing sectors, the Territory’s mineral deposits, which include lead, zinc, gold and silver “” typically require less gas-intensive processing. The exception to this has been the expansion of the Alcan Gove alumina refinery, which will be supplied by gas from Rift Oil’s offshore gas fields in Papua New Guinea.
The Northern Territory Government has been seeking to establish Darwin as a gas manufacturing base and to promote the Territory’s downstream sector. Plants producing petrochemicals, fertilisers and synthetic liquid fuels are being sought as they can utilise the Territory’s abundant gas reserves. A recent example of this is BOC’s plan to develop Australia’s first helium plant, underpinned by gas from the Darwin LNG plant.
Exporting gas: underpinning expansion of the Darwin LNG project
Recently, gas export as LNG has been a key driver of the Territory’s gas development and this is likely to continue given its considerable undiscovered potential and proximity to large gas markets in Asia.
LNG export began in 2006, with the commissioning of ConocoPhillips’ $1.75million Darwin LNG project. The 3.24 MMt/a plant, located at Wickham Point in Darwin Harbour, converts gas from the Bayu-Undan field into LNG, which is then exported to Japan.
Discovered in 1995, the Bayu-Undan field, which is located approximately 500km northwest of Darwin in the Timor Sea, has expected reserves of 3.4 Tcf of gas and 400 MMbbl of condensate and liquefied petroleum gas (LPG). Development of the field has involved the construction of a central production and processing complex, an unmanned wellhead platform, a floating storage and offloading facility (FSO) and a 500 km pipeline that will connect the LNG plant to the Bayu-Undan offshore facilities. Approximately 22 wells are required over the anticipated 25-year life of the project, with twelve already drilled.
The Darwin LNG plant is geared for new gas developments in the Timor Sea, with planning approvals in place for expansion of up to 10 MMt/a of LNG production. The plant’s expanded capacity is likely to be underpinned by discoveries appraised through Santos and ConocoPhillips’ Timor/Bonaparte Basin drilling program, such as the Barossa Caldita, Petrel and Tern fields.
The Caldita field, located about 265 km northwest of Darwin, has been undergoing appraisal, with the Caldita-2 well drilled to a total depth of 3,973 metres last year. Since then acquisition and processing of 3D seismic data over the Caldita and nearby Barossa structures has been completed.
Simultaneous with the analysis of ConoccoPhillips’ Caldita and Barossa fields, development options for Santos’ Petrel and Tern fields are being appraised. The Petrel and Tern fields, discovered in 1969 and 1971 respectively, are located 250 km and 300 km west of Darwin in Western Australian waters in the Bonaparte Basin and are estimated to hold 1.4 Tcf of recoverable reserves. Field development options include installation of unmanned offshore production platforms with a pipeline to the Darwin LNG plant.
Gas from the Ichthys gas field may also supplement expansion of the Darwin LNG plant. Northern Territory Chief Minister Paul Henderson continues to present the Territory’s case for the $12 billion LNG project as Inpex considers both Darwin and the Maret Islands in Western Australia for the project’s development. The two sites would both require long pipelines from the field – Darwin is located 850 km from Ichthys, and the Maret Islands are located 190 km from the field.
ACIL Tasman has forecast that the development would be worth $50 billion to the Territory’s economy over 20 years, from the start of site work in 2010.
“The Territory is best placed to become Australia’s second international gas hub and I’m doing all I can to ensure that happens,”? said Mr Henderson. “The Territory’s business community has a proven track record of delivering major projects like the Wickham Point LNG Plant and we have land available for growth.”?
Flexible LNG through FLNG
Despite the Northern Territory Government’s highlighting the land available for growth there, developers are increasingly considering FLNG plants rather than onshore LNG projects, in order to monetise gas from fields located in the Bonaparte Basin and Timor Sea. This is not only because of fiscal concerns but also because of the potential political and legal divestment of risk.
In 1995, expansion of the Darwin LNG plant was thought to be underpinned by development of the Abadi field, located about 400 km north of Darwin in the Masela block but which lies in Indonesian waters. With an estimated 7 Tcf of gas, Inpex’s Abadi field was thought to be a more viable option for the expansion than the Greater Sunrise gas fields, which are located about 450 km northwest of Darwin.
In June this year, Inpex submitted plans to build a $19.6 billion FLNG plant in order to develop the Abadi field. The company estimates that it has more than 10 Tcf of gas reserves in the field and plans to develop these in a single-train LNG plant with a 4.5 MMt/a capacity. The development, which is scheduled for completion in 2016, would involve a turret moored vessel that would process raw gas and store LNG, LPG and condensate.
FLNG is also being investigated at Woodside’s Greater Sunrise gas fields, located some 500 km northwest of Darwin and near Timor Leste. With estimated recoverable reserves of 7.7 Tcf of gas and condensate, development of the fields is expected to begin in approximately two years with production start up scheduled for 2013.
Project partner Shell had previously considered FLNG but the idea was discarded because of high costs. However Woodside CEO Don Voelte claimed that FLNG was now the cheapest and most effective development option. He said that this is part because of technical developments achieved in FLNG, but also because the increase in price in steel has impacted the cost of seabed gas pipelines more than platform or floating production offtake and storage vessel construction costs. Therefore, the costs of developing a 530 km pipeline to the Darwin LNG plant proved prohibitive. Finally, a pipeline to Timor Leste was associated with a considerable risk given the level of tectonic activity in the Timor Trough. Woodside also considers that a FLNG plant might play a role in overcoming some of the political factors that have delayed the project since 2004.
MEO Australia is presently developing an LNG plant and two Methanol plants to monetise gas in the Timor Sea and in particular from the recent gas discoveries in its exploration permit NT/P68. MEO has acquired 3D seismic over the discoveries and is planning an extensive appraisal drilling program in 2009. While the permit is believed to contain over 10 Tcf of gas, much of this gas has significant carbon dioxide content, which would make conventional commercialisation of the gas very difficult. However this composition made the gas ideal for conversion to methanol.
MEO Managing Director JÃ¼rgen Hendrich recently described the Tassie Shoal as a future gas hub. The Tassie Shoal Methanol and Timor Sea LNG plants are planned to produce 3.5 MMt/a of methanol and 3 MMt/a of LNG.
Given the prohibitively high construction costs associated with development of onshore plants in Australia, MEO said that the Tassie Shoal project concepts are probably the quickest way to develop early production and cash flow for any new discovery. MEO proposes to construct the entire plants in a low cost, highly experienced SE Asian construction facility and then transport the pre-commissioned plants to the shoal. MEO has recently engaged Arup Energy and Leightons Construction to identify and secure a suitable casting basin site to build the first methanol plant’s gravity base structure.
Coogee Resource’s gas-to-liquids project is also planning to use gas as a feedstock to develop a methanol and/or LNG plant. Located further afield – some 650 km west of Darwin in the Timor Sea – the development will commercialise the 830 Bcf of gas and 8.3 MMbbl of condensates, contained predominantly within the Cash/Maple, Padthaway and Tahbilk fields.
A pre-FEED study began this year to assess the viability of using compact methanol technology on an FPSO. Coogee is also evaluating a FLNG production, with a view to selecting a preferred approach by the middle of next year and completing development in 2013. If it goes ahead, the vessel would be capable of producing 1 MMt/a of LNG.
Looking forward: growth, diversity and resilience
The diversity of approaches to the development of gas resources in the Amadeus Basin, Bonaparte Basin and Timor Sea demonstrate the Northern Territory’s resilience in its ability to recreate itself as a central component of Australia’s gas industry. Whereas it once championed the development of a nation-wide grid that would connect its considerable reserves with the Moomba hub in order to ensure the security of the country’s gas supply, today the Territory provides security in a myriad of ways.
Not only has the Top End managed to establish itself in the conventional development of onshore gas resources, it has and will be witness to innovative solutions to gas fields located far from existing infrastructure – such as FLNG plants “” and to gas that is difficult to commercialise through conventional methods, such as methanol production plants. This ability to constantly transform itself to suit the reigning conditions is what will make the Northern Territory, and its considerable unexplored potential, key to Australia’s future energy security.