New onshore field discoveries rich in natural gas and condensate in the Australasian region are giving rise to increased investment in liquefied natural gas (LNG) facilities. This new construction will address the growing demand for methane to fuel Asian economic development. We present an overview of current projects and their anticipated output, starting with:
Several LNG developments are underway that will source from coal seam gas (CSG). These are breakthrough endeavors, as there are currently no operational CSG-LNG export projects in the world.
Queensland is the center of this effort with six LNG projects underway; five are well advanced in planning and development, and all expect to use CSG from onshore basins: Queensland Curtis LNG (QCLNG), Gladstone LNG (GLNG), Australia Pacific LNG (APLNG), Arrow LNG, Gladstone LNG Fisherman’s Landing, and Sun LNG.
Three LNG projects, QCLNG, GLNG, and APLNG, are under construction adjacent to each other on the south coast of Curtis Island and opposite Gladstone on the mainland. Together, they are expected to generate AU$45 billion in capital expenditures and produce 28.8mmt/yr of LNG.
QCLNG (pictured) is being developed by Queensland Gas Co. (QGC), a subsidiary of BG, with the aim of delivering first LNG in late 2013. The plant will have an initial capacity of 8.5mmt/yr and the potential to increase production to 12mmt/yr. Plans include further development of QGC’s CSG fields around Miles in the Surat Basin and construction of a 540km pipeline.
GLNG, a joint venture of Santos, Petronas, Kogas, and Total, anticipates first LNG in 2014, from a plant with a startup capacity of 3.9mmt/yr, possibly increasing to 10mmt/yr. Other short-term projects include the development of the Santos gas fields in the Bowen and Surat Basins, and construction of a 420km gas pipeline.
APLNG, a venture of Origin, ConocoPhillips, and Sinopec, is on-track to produce LNG in 2015 from a plant with a capacity of 4.5mmt/yr. The facility is upgradeable to 18mmt/yr. Future plans involve CSG field development and a 400km pipeline, with the natural gas sourced from the Bowen and Surat Basins.
Arrow CSG (Australia), formerly Shell CSG (Australia), is a joint venture of Arrow Energy, Shell, and PetroChina. The company proposes to develop another LNG plant on Curtis Island, next to GLNG, with an initial capacity of 8-9mmt/yr and potential expansion to 18mmt/yr. Arrow is exploring about 50,000sq. km of CSG acreage throughout Queensland and northern New South Wales. The company estimates reserves at around 70,000 petajoules (62tcf) of methane.
At Fisherman’s Landing in the Port of Gladstone (Queensland), Gladstone LNG is developing a two-train, 3.8mmt/yr LNG plant for export at a projected cost of AU$1.7 billion. The primary gas supply for train-1 will be supplied by PetroChina from its own or third-party natural gas resources that are expected to be secured in 2013.
Finally, the Sun LNG Project proposal, instigated by Sojitz Corp., envisioned a first-stage, 2mmt/yr LNG development at Fisherman’s Landing with a 5km gas pipeline to receive natural gas from the Gladstone City Gas Gate. The application has since lapsed.
New Zealand possesses appreciable unconventional gas resources in coal deposits, shale formations, and subsea gas hydrates. Coal seam gas (CSG) has the potential to become an important energy source for the country. Exploration has accelerated over the last two decades, involving up to eight companies with 17 permits in force. Only one project is sanctioned for commercial production. One CSG investigation indicates a resource of about 2tcf of gas.
Gas is present in extensive shale formations found throughout New Zealand, with exploration and assessment underway onshore in the East Coast Basin where large, fractured, low to moderate total organic content (TOC) mudstones compare well with the Bakken and Barnett shales of North America.
Gas hydrate regions are established along the eastern coast of North Island and between North and South islands.
The East Coast and Pegasus Basins, off the east and southeast coasts of North Island, respectively, are considered to be the most economically promising gas hydrate provinces, in part due to proximity to major population centers.
In addition, evidence for free-gas pockets, likely surrounded by hydrate, has been found in North Island seismic data from the southern Reinga and northern Taranaki Basins. The latter is of economic interest, since it is near Auckland. Initial estimates of potentially recoverable gas hydrate reserves are estimated at 200tcf out of a gross in-place resource of 800tcf, spread over 50,000sq. km.
PAPUA NEW GUINEA
PNG’s crude oil production has averaged around 30,000b/d and that of natural gas about 10.7mmcf/d in 2010, all consumed domestically. Proved reserves were estimated at 182 million barrels of oil and 5.5-8tcf of gas in 2012. The PNG LNG project is likely to be followed by a series of significant gas developments. Oil Search, the country’s largest oil and gas producer, is engaging in an expansion that could culminate in an LNG hub on the Gulf of Papua coast.
InterOil Corp. has received sanction to proceed with a Gulf Province LNG project that entails an initial minimum output of 3.8mmt/yr. This output will come from the Antelope and Elk fields, which hold 8.6tcf of natural gas and 129mmbbl of condensate. Development encompasses two, 120km pipelines to the coast (one for dry gas, one for condensate) and two LNG plants: a 3mmt/yr onshore facility and a 2mmt/yr floating LNG unit, along with storage and a terminal.
These facilities include two onshore condensate stripping projects, revolving around the Antelope and Elk fields, located in the Gulf Province, and a second focused on the Stanley field in PRL4, Western Province. There is also an aggregation of natural gas accumulations in the Western Province, involving such fields as P’nyang, Douglas-Puk Puk, Elevala-Ketu, Kimu, and possibly the offshore Pandora field for an LNG development.
Cumulative project production life is expected to exceed 9tcf of natural gas and 200mmbbl of associated liquids. The gas, once conditioned in the highlands, will be transported through a 248km pipeline to a two-train LNG plant 20km northwest of Port Moresby, and exported by LNG carriers.
Contracted LNG recipients include: Japan’s TEPCO (1.8mmt/yr) and Osaka Gas (1.5mmt/yr), Taiwan’s CPC (1.2mmt/yr), and China’s Sinopec (2mmt/yr). First shipments are designated for late 2014.
InterOil holdings total 16,000sq. km in the onshore Eastern Papuan Basin and extend northwest of Port Moresby for about 300km to the Antelope and Elk fields. InterOil and Pacific LNG Operations have signed a heads-of-agreement contract for the supply of LNG totaling around 3.3-3.5mmt/yr.
Samsung Heavy Industries and Flex LNG are collaborating on a floating LNG (FLNG) vessel design and subsequent construction. This endeavor also offers PNG an additional 27.5% equity interest in the Antelope-Elk gas fields, raising the state’s share to 50%.
InterOil operates, and has a 100% interest in, PRL15, which contains the Antelope-Elk structure. The fields are surrounded by two of the company’s three wholly owned petroleum prospecting licenses. The PPL237 license contains the recently renamed Triceratops gas field.
Furthermore, InterOil has executed an agreement by which Bogotá-based Pacific Rubiales Energy Corp. will acquire 10% net participating interest in PPL237, including the Triceratops field and exploration acreage located within that license.
InterOil anticipates sale of an interest in the Antelope and Elk resource, and the first 3.8mmtpa Gulf LNG train, to a partner or partners. The company is awaiting a final investment decision regarding a proposed condensate stripping plant in joint venture with Mitsui.
Stanley gas and condensate field recovery in PRL4, in the forelands of the Western Province, is being undertaken by the 50:50 joint venture of Sydney-based Horizon Oil Ltd. (operator) and Talisman Energy. Development of the field, with contingent reserves of 380bcf of gas and 11mm bbl of condensate, encompasses a two-train refrigeration plant to strip 4000b/d of condensate, and possibly 40t/d of LPG, from 140mmcf/d of wet gas. The condensate would be sent through a 40km pipeline to the port of Kiunga, on the Fly River, for storage and transport by small tanker. Dry gas, initially to be re-injected, could supply regional domestic and industrial consumers and be sold to customers across the border in West Papua. Front-end engineering and design (FEED) has been completed for the estimated $300 million project, targeted to go online early next year and produce more than eight million barrels of condensate over 10 years.
Another potential gas and condensate development in the forelands is being considered in PRL21, operated by Horizon Oil (45%) in joint venture with Talisman (40%). Also in close proximity to the Fly River, PRL21 has been audited, putting gross proven and probable contingent resources of the Elevala and Ketu fields at 795bcf of natural gas, 40 mm bbl of condensate, and 26 mm bbl of LPG.
New seismic is being acquired over the Elevala, Tingu, and Ketu structures. Horizon Oil reported in late January that its Elevala-2 well confirmed natural gas and condensate in the Elevala sandstone and tested the secondary Toro sandstone target to the northeast. The drilling results “significantly upgrades” the Tingu structure to the northwest, said Horizon CEO Brent Emmett. OE