Resource-rich Australia has a solid list of positives when it comes to attracting energy companies – a stable regulatory regime, a skilled workforce, infrastructure in most places, onshore and offshore opportunities, and close proximity to energy-hungry Asia.

Add these to the 25 Tcm (819 Tcf) of identified, potential, and undiscovered gas and 1,264 MMbbl of crude oil the country is believed to hold based on estimates from the Australian Petroleum Production & Exploration Association (APPEA), and it is no wonder that oil and gas companies are drawn to the country.

Australia, however, is not without challenges, most notably costs. Cost overruns for major LNG projects aimed at meeting the world’s growing energy needs – especially in Asia – are running into the billions of dollars, prompting oil and gas stakeholders to find ways to curb costs and improve planning. Solutions have included turning to floating LNG (FLNG) vessels instead of onshore LNG facilities and continuing to form partnerships to jointly explore, produce, and bring hydrocarbons to market.

Economics are forcing companies to rethink investments as budgets are squeezed. While some are sticking with LNG developments, others are selling interests in these projects and redirecting money to other Australian energy projects.

Added to the pot is a mix of variables that could complicate matters. Competition from the US and East Africa, restoration of nuclear power in Japan, and gains on shale development in China – crawling at the moment – could shake up the energy scene and impact planned projects.

But Australia remains well-positioned. With solid conventional resources and a budding unconventional sector, the prize down under is simply too big to pass up. These challenges and opportunities brought top-level executives and government officials to Houston for the Australian American Chamber of Commerce’s annual energy conference in January.

LNG projects take shape

On track to become the world’s largest LNG exporter by 2020, Australia’s energy scene is undergoing a transformation as gas production from both coalseam and conventional gas operations boosts supplies.

“Governments everywhere have moved far too slowly in approving and welcoming new LNG plants, so Australia has a fantastic opportunity to build, to grow, to profit, to reward present and future generations, and to serve energy users worldwide, especially in Asia,” Melody Meyer, president of Asia-Pacific E&P for Chevron, said at the conference.

Global LNG demand is expected to nearly double by 2025, with Asia needing the most.

“When we combine today’s output with LNG projects that are currently under construction, LNG supplies fall short of the 2025 forecast by about 150 million [metric] tons per year. That’s the equivalent of about 10 Gorgons,” Meyer said, referring to the Gorgon LNG project. “Meanwhile, despite lots of speculation, we don’t expect shale gas from Asia or the US or the rest of the world to cover this LNG shortfall.”

Currently, seven LNG projects are under construction. These, according to APPEA, include:

• Queensland: US $24.7 billion Australia Pacific LNG, with a 9 million metric tons per year (MMmt/y) capacity and a 2015 start date; $20.4 billion Queensland Curtis LNG, with a 8.5-MMmt/y capacity and a 2014 start date; $18.5 billion Gladstone LNG, with a capacity of 7.8 MMmt/y and a 2015 start date; and
• Offshore West Australia: $29 billion Wheatstone LNG, with an 8.9-MMmt/y capacity and a 2016 scheduled start date; $13 billion Prelude FLNG, with a 3.5-MMmt/y capacity and scheduled 2017 start date; the $54 billion Gorgon LNG, with a planned 15-MMmt/y capacity and scheduled start date in 2015; and the $34 billion Itchthys, with a 8.4-MMmt/y planned capacity and 2016 scheduled start.

Chevron already has lined up contracts for its Gorgon and Wheatstone projects. Some 65% of Gorgon’s future offtake and 85% of Wheatstone’s are committed under long-term contracts, primarily with Asian customers, Meyer said.

The Gorgon LNG project, among the largest resource development projects in Australia’s history, is more than 76% complete. Most of the turbine generators have been installed, most of the 21 LNG process modules for Train 1 are in place, and the 2.1-km (1.3-mile) LNG jetty is nearing completion with 56 caissons to support key structural elements. Ten offshore wells have been completed as well as the 30-in. offshore pipeline and onshore line to the domestic market.

Wheatstone LNG also is progressing. More than 20% complete as of January, construction continues on the materials offloading facility and permanent foundation. Of the 23,000 piles planned for Wheatstone, about 5,000 are in, platform construction is halfway complete, and most of the critical equipment is on site, Meyer said.
“So far, we’ve logged about 10 Tcf [283 Bcm] within reach at Gorgon and Wheatstone,” she continued.

However, LNG projects, Gorgon in particular, have been rife with ballooning costs.

“We’ve revised our total project cost estimate [for Gorgon] to about $54 billion, due principally to bad weather, island logistics, productivity, a strong Australian dollar, and more,” Meyer said. “But we’ve also increased our ultimate capacity to 15.6 MMmt/y, and we expect first shipments in mid-2015.”

Cost concerns linger

Joe Marushack, president, Asia-Pacific and Middle East for ConocoPhillips, pointed out how the company’s $12 per Mcf landing cost is much higher than in other places such as Canada and Mozambique.

“The Australian projects are expensive; they are challenged. Projects that are on the table right now aren’t going to go through and be completed,” said Marushack. “What we’re finding with our Australian projects – us and other companies – is the actual costs are coming in more than the original FID [final investment decision] estimate. It’s been all of the big projects out there. The percentages can be kind of small in some of these cases, but you’re seeing US dollars in billions. These are very capital-intensive projects. An overrun of 10% might be $2 billion, $3 billion. That’s a lot of money.”

The industry must do a better job at planning, assessing project risks, and working with governments so they understand what the risks are, Marushack continued. One way companies can work together is by developing projects on a brownfield basis utilizing existing infrastructure and lowering project costs.

Imagine if the three biggest Queensland projects on Curtis Island were combined into one six-train project, he posed, noting the efficiency and cost-saving potential.
“It’s very difficult for us to do that. But in other countries that is what happens,” he continued. “In Qatar, the government decides who your partners are and how you’re going to build those projects. It’s very, very efficient. The industry doesn’t really like it all the time, but it’s an efficient way.”

Other opportunities lie in FLNG, an option that also can bring together smaller offshore developments and cut costs.

Unconventional attraction

UK-based BG Group teamed with CNOOC and Tokyo Gas for its Queensland Curtis LNG project. In total, BG Group is pumping more than $20 billion into its Queensland-based projects that focus on converting coalseam gas (CSG) into LNG.

“Queensland’s 25.3 [MMmt/y] of production will be equivalent to 5% of the global supply and will eclipse Russia for sixth place internationally,” said BG Group’s Catherine Tanna, chairman of the company’s Australian operations. Queensland is expected to account for a third of the country’s production by 2020.

The state is home to stacked sedimentary basins that range in age from Paleoproterozoic to Quaternary, according to the Department of Natural Resources and Mines. The Bowen and Surat basins in particular have been the site of significant CSG discoveries. Production from the two basins make up more than 79% of total gas produced in the state.

“Queensland’s gas basins with much of the resource untapped are literally bigger than Texas, and our three LNG projects will supply enough gas to power Asian cities with a total population of 80 million people for 20 years,” Tanna said.

Plans are for more than 18,000 wells to be drilled in the next 20 years. “Our project alone has drilled nearly 2,000 wells, and we have plans for a further 4,000,” Tanna continued. “The pipelines to connect them all for our project alone would reach from Houston to Brisbane and more if laid end to end.”

While CSG has attracted the attention of BG Group and others, other unconventional hydrocarbons – including shale oil and gas as well as tight gas – are beckoning others to the region. The Cooper/Eromanga basin has proven to be a productive play trend straddling the South Australia/Queensland border.

“In that proven productive play trend, where people have acquired 3-D seismic, 56% of the wildcat exploration wells have found oil and an average of 2.5 MMbbl,” said Barry Goldstein, executive director for the energy resources division of South Australia’s Department for Manufacturing, Innovation, Trade, Resources, and Energy.

There are now 23 companies in the play – the latest additions being New Standard and Magnum Hunter – under 10 different operators, Goldstein said.

Companies active in the play include Chevron, ConocoPhillips, Statoil, Total, Hess, and BG Group. Santos Energy was the first to achieve commercial shale gas flow at the Moomba field in the Cooper basin in 2012. Santos, operator of the joint venture (JV) with Beach Energy and Origin Energy, announced in December 2013 that the Moomba-194 vertical shale gas well flowed gas at an average rate of 85 Mcm/d (3 MMcf/d).

What distinguishes the Cooper basin from others is that it’s a basin-centered gas play, Goldstein continued. “This is a stack of rock anywhere from 600 m to 1,200 m [1,969 ft to 3,937 ft] of thickness that is fully gas-saturated and dehydrated. The only water you get out of production in the Cooper basin is water condensation – pristine, no salt in it.”

Another advantage is that operators don’t have to start off drilling horizontals.

“We can actually, like in the Permian play here in the [US], drill verticals and have a kilometer of rock to frac,” he said, adding the verticals are about half the cost of the horizontals, “and that’s going to be a particularly important thing. There is a considerable gas prize in the unconventionals onshore.”

Australia could have an estimated 13 Tcm (437 Tcf) of technically recoverable shale gas reserves – the sixth highest in the world – and more than 17 MMbbl of technically recoverable shale oil reserves, according to the US Energy Information Administration. In addition to the Cooper basin, the eastern Maryborough, offshore Perth, and northwestern Canning basins hold shale resources.

But “that is potential,” Goldstein said. “We’re not sure that it is all going to work economically.”

Watching the rig count will give an indication of the health of this basin. By pairing people in Australia who have the competence and capacity to work with the expertise of companies such as Halliburton, Schlumberger, and Baker Hughes, those operating in Australia can learn and be able to keep costs down, Goldstein continued.

“It’s very much a question of being competitive in an international LNG market,” he said. “There are very few places in the world where you can have a coin toss chance of finding 2.5 MMbbl.”

Beach Energy and its JV partners Icon Energy and Chevron Australia announced in February they hit gas at their Redland-1 well in the Cooper-Eromanga basin. An interpretation of the wireline log data indicates the target interval to be gas-saturated, which is supported by mud gas readings of up to 800 units, according to a news release. Plans were for the well to be cased pending subsequent hydraulic stimulation and flow-tested as part of a multiwell stimulation campaign beginning in 3Q 2014.

Beach Energy unveiled successes earlier this year with its oil development and gas exploration campaigns in Queensland. The Bodalla South-21 was cased and suspended as a future Basal Jurassic oil producer. The Marama West-1 well, with Origin Energy Resources as operator and Santos Ltd. as a partner, along with the Bolah-1 and Kaiden-1 wells, struck gas. More good news arrived with the trio’s five-well Zeus-Minos-Tennaperra oil development campaign in southwest Queensland. The fourth and fifth wells in the campaign were cased and suspended as future oil producers.

Additional gas finds were made by the JV in the South Australian Cooper with the Moomba-197, Moomba-200, and Moomba-201 wells. Big Lake-95 and Big Lake-96 were cased and suspended as Toolachee/Epsilon/Patchawarra/Tirrawarra gas producers. So was the Geoffrey-1 vertical exploration in the Nappamerri Trough, where Beach serves as the operator of a drilling campaign with partners Icon Energy and Chevron.

Offshore potential

While onshore basins have attracted oil and gas companies seeking conventional and unconventional resources, offshore basins remain largely untapped.

The Australian government has proposed offering 30 blocks during the 2014 exploration acreage release. The boundaries of the areas have not been finalized and remain subject to change until the round is officially launched. In the meantime, Round 2 of the 2013 acreage release continues until May 22. Areas being offered are located in the Bonaparte, Browse, Gippsland, Northern Carnarvon, Otway, and Perth basins.

Some of the acreage being offered is near existing developments. In the Bonaparte basin, for example, this includes the Evans Shoal, Greater Sunrise, Caldita, and Barossa gas fields as well as the Darwin LNG plant. Described as an “underexplored gas province, with potential charge from Paleozoic and Mesozoic sources,” the basin has shallow-water depths of up to 200 m (656 ft) and faulted anticlines, tilted fault blocks, and stratigraphic traps.

Only about 20% of the country’s offshore basins are covered by petroleum titles, according to the Australian Government’s Department of Resources, Energy, and Tourism. The agency reported that offshore exploration activity has been steady, with approximately 1,500 offshore exploration wells drilled by mid-2013.

“Although exploration activity is primarily focused on finding resources close to existing discoveries to improve the economics of proposed projects, frontier exploration is growing,” the government said in a 2013 acreage release document. “Australia’s underexplored frontier basins hold the greatest promise of making a new discovery.”

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