Gladstone, a relatively small, laid-back coastal town of about 30,000 in the northeastern Australia state of Queens-land, avoided the devastating floods left behind by Cyclone Oswald in late January, unlike neighbors to the south that were deluged by swollen rivers. Its harbor, though, swirled with the murky brown runoff from the Boyne River, held at bay by the Awoonga Dam above town. Construction on the three massive LNG (liquefied natural gas) facilities on Curtis Island across the harbor returned to action, slowed by the storm and its aftereffects. The adjoining sites hummed with activity as thousands of yellow-jumpsuited workers pressed toward timelines to meet first deliveries.

The little town of Gladstone has risen to global prominence as the epicenter of new LNG supply, with three huge liquefaction plants under construction simultaneously and literally bordering one another. Those facilities represent $60 billion in investments by a host of the world’s premier energy companies. Each is being constructed initially with two liquefaction trains, or processing units, with contracts to deliver 25 million tons per annum (mtpa) of LNG by 2015.

Voracious Asian natural gas appetites are promulgating this eastern Australia LNG rush. Global energy demand is projected to grow 30% between 2010 and 2035, with much of that coming from nearby Asia. Amazingly, a fourth facility is being considered for sanctioning on Curtis Island that could add another 8 mtpa, and a fifth nearby is proposed.

By 2016, when the first six LNG trains are operational, demand for Australian natural gas will leap by 300%, an additional 3.8 billion cubic feet of gas supply per day. Estimates are that 36,000 wells need to be drilled to support the projects through their lives. The big question then becomes: Can Australian natural gas producers meet the challenge?

Banking on coal seams

The principals of the LNG projects are taking no chances. Each has secured reserves in the coal-seam gas—or coalbed methane—fields in the contiguous Surat and Bowen basins nearby.

These high-powered players include Britain-based BG Group, which acquired Australian producer Queensland Gas Co. to supply its Queensland Curtis LNG project (QCLNG); ConocoPhillips and Sinopec, in partnership with Australian E&P Origin Energy for its Australia Pacific LNG (APLNG) feedstock; and Petronas, Kogas and Total, which have teamed with long-time Australian explorer and producer Santos Ltd. to secure production for Gladstone LNG (GLNG). Shell and PetroChina, still in the final-investment-decision (FID) phase for the Arrow LNG project, bought out the local player by the same name, Arrow Energy, for its reserves.

Coal is a thriving industry in Australia, with rich deposits across the continent. It wasn’t until the 1990s, however, that the coal seams were targeted as a commercial resource for natural gas. This development has largely occurred in the Bowen and Surat basins in Queensland, which holds 98% of Australia’s proven and probable reserves of coal-seam gas (CSG), and is near major markets and industry. In just a few years, the CSG industry consolidated from a cottage industry to being dominated by interna- tional majors, with $24 billion changing hands.

Now, with tens of billions being sunk into Curtis Island, the onus is on the upstream to produce the LNG feedstock, first from coal-seam gas, and longer term, from shales.

According to the Australian government, the country holds some 33 trillion cubic feet (Tcf) of economic CSG reserves, and another 60 Tcf of subeconomic resources. CSG, though, is still a relatively nascent industry in Australia, and producers are working through challenges.A small number of vocal land holders, particularly farmers, for instance—who receive no royalty incentive under Australia’s Crown mineral ownership—are pushing back over land usage. Some coal seams produce water for months before gas flows. Regulations for water handling can be onerous and costly. Flooding, which delays drilling, has been a recurring problem. A moratorium on hydraulic fracturing in New South Wales slowed drilling there. The CSG-to-LNG projects are all scrambling to catch up.

Santos, with a 30% stake in the $18.5-billion GLNG project, is one of those committed to doing so. An $11-billion market cap company with onshore and offshore operations throughout Southeast Asia, Santos is Australia’s largest domestic gas producer, and is pursuing growth through exports. The company books some 526 million barrels of oil equivalent (BOE) proved and probable reserves and 680 million BOE 2C contingent resources, or 37% and 35% respectively of its total reserves and contingent resources, in its CSG fields.

The Adelaide-based company has drilled half of the targeted 1,000 wells needed for first LNG delivery by the end of 2015, and is confident it will achieve its target, says Bill Oven-den, Santos acting vice president, exploration and subsurface. It has eight fit-for-purpose rigs active in the CSG plays, and four completion rigs. Its first Environmental Impact Statement was approved for 2,500 locations across its 17,000 permitted acres, more than enough to meet its LNG demand, he says, and it has applied for an additional 7,000 locations. Santos projects its upstream development will be in position to deliver volumes required for the first train within six months, and for the second train in two to three years.

The company, once known as South Australia Northern Territory Oil Search, has been exploring the region conventionally for more than 40 years, and is primarily focused on two CSG fields in Queensland in the overlapping Bowen and Surat basins to supply its LNG trains. The primary target coal seams are at some 500 to 800 meters (1,600 to 2,600 feet), with deeper, higher-risk prospectivity extending into the deeper basin areas.

“The geology here is pretty well understood,” says Ovenden. In its Fairview Field in the Bowen Basin, the Permian-age coals “are world-class assets,” he touts. “These are high-quality coals. We’ve had individual well initial production rates up to 15 million cubic feet (MMcf) per day, which is amazing for coal.” A typical rate averages 1- to 1.5 MMcf per day.

In Santos’ Roma Field just south, the coals are Jurassic age and not of the same high quality, he says. He anticipates rates here will average 500,000 cubic feet per day.

Diana Hoff, vice president, technical and engineering , is a petroleum engineer and U.S. expatriate who worked for Barrett Resources in the 1990s and is a veteran of the Powder River Basin and U.S. Rockies coalbed-methane plays. With Santos since 2010, she says the company has experimented with 16 different well and completion designs to maximize production before full ramp, including vertical, horizontal and directional, underbalanced, overbalanced, slotted liners and surface inseam, to name a few variations.

While production data is still coming in on those, many of which are still dewatering, the company has narrowed to four designs, pending data that could redirect its efforts. “Last year, we were 80% directional wells,” she says.

Two- to four-well multipads are becoming the norm, too. “That’s because we believe opening up more of the coals with directional wells is better for productivity, and because these fields are located in environmentally sensitive areas in agricultural communities.”

Historically, these wells have cost about $2 million each, but efficiencies have driven down these costs by up to 40%. Of note, the company currently is operating no frac fleets in CSG. “We’re only going to frac about 10% of our wells this year,” says Hoff.

The company plans to drill more than 200 CSG wells in 2013, up from the 140 drilled in 2012. “We’re looking to plateau in the future between 250 and 300 wells per year to reach the feedstock delivery,” says Ovenden.

Dewatering wells before production in most cases is a requirement in CSG fields. “Managing water is certainly a challenge,” Ovenden says, “but we have developed and are developing sustainable solutions.” In certain regions, produced water tends to be briny, and regulations require it to be treated. Reverse osmosis plants become part of the cost structure, but the treated water becomes a source of irrigation for farmers.

Related infrastructure build-out to meet the jolt of supply is on schedule as well. Two compressor stations each in Fairview and Roma will add 535 million cubic feet of gas per day capacity, adding to an existing 160 MMcf. A 42-inch, 260-mile pipeline to Gladstone is on track for fourth-quarter 2014 completion, ahead of first LNG delivery.

CSG development phase

QGC Pty Ltd. is the shingle that identifies international LNG supplier BG Group’s upstream operations in Australia, which first partnered with the independent Australian producer Queensland Gas Co. before buying it out in 2008. BG is the money behind Queensland Curtis LNG, a $20.4-billion, two-train project set to deliver 8.5 mtpa that is on track for first LNG next year.

Like the other two LNG projects that are all-in committed with billions at stake, QCLNG controls its own upstream ramp up and midstream build-out to meet the turn-on date. It has more than 9 Tcf of proved and probable (2P) reserves and 25 Tcf of gross resources in the Surat and Bowen basins and presently supplies 20% of the state’s gas. The company has more than 1,100 CSG wells drilled of the 2,000 it is targeting for first LNG in 2014.

“We have enough gas for two trains,” assures Paul Larter, a spokesman for QGC. “We’re happy with the progress in drilling. We’ve got 11 rigs drilling about 50 wells a month. We’re confident we’ll get to our goal.”

The wells, at a cost of approximately $1 million each, target the Walloon coals at 300 to 800 meters (980 to 2,600 feet) depth. Very few of the wells are being fracture stimulated now. “It’s not necessary for the time being,” he says. “In the future, about a third of the wells will be stimulated.”

Like Santos’ Surat coals, QGC’s wells produce large amounts of water. “Water, of course, is a challenge for companies that are not in the water business. But we will invest A$1 billion on treating water for beneficial use by agriculture, industry and towns.”

Regulators are trying to keep up with changing times as well, and have recently revised rules to allow transport of water between leases to centralized water-processing facilities, instead of having to get approval for and build dozens of separate ones.

QGC expects to drill some 6,000 total wells on 4,500 square kilometers by 2030 to support the first two trains. It has approval to operate three trains, with the capacity to build five.

Likewise, APLNG, a partnership between Australia’s Origin Energy, ConocoPhillips and Sinopec, controls 11 Tcf of 2P reserves in the Bowen and Surat basins. APLNG has drilled 209 operated wells through year-end 2012, added to another 220 existing producing wells. Four rigs are running, and it takes about 45 days per well. It anticipates drilling a total of 10,000 wells over the life of the project. Arrow LNG, via national oil companies Royal Dutch Shell and PetroChina, owns another 41,000 square kilometers with 62 Tcf estimated contingent resource potential (7 Tcf 2P). The project awaits FID. Arrow has drilled 1,100 wells to date (600 producing), with a total 15,000 projected during the life of the project.

The four Gladstone-based projects control 86% of eastern Australia’s 2P CSG reserves, and 72% of total 2P gas reserves, according to Jefferies Equity Research.

Unconventional paradigm shift

The massive LNG build-out taking shape in Gladstone represents the first time Australia’s East Coast gas markets will have an international outlet. Australia is no stranger to LNG, of course, with facilities on its north and west coasts, but those rely primarily on offshore production, and garner oil-based pricing of $6 to $8 per thousand cubic feet (Mcf).

Due to vast and desolate distances, no infrastructure connects the two markets, and the East Coast market trades independently. East Coast gas is a domestic product, powering residential and industrial, and historically trades at $2 to $4 per Mcf.

That is changing.

Even before the first LNG deliveries, East Coast natural gas customers are anxious that traditional domestic supply—much of which is delivered by the LNG principals—will be siphoned off to meet contractual LNG obligations. Reports are that new gas-supply contracts (Australia has no spot market, and contract terms are private) are trading in a range of $6 to $9 to assure future delivery. Not everyone believes the CSG ramp will meet the need.

“They were banking on many of their coalbed methane blocks to deliver the majority of gas to supply these projects,” says Chris Jamieson, director of investor relations for independent Beach Energy. “Based on the approaches Beach has had from some of the LNG players regarding gas supply, it is clear that these players are short gas. A portion of the gas that was feeding the domestic market will now be allocated to these offshore facilities. There are a lot of domestic customers that are going to be short gas in 2015,” he says.

The upward pricing trend combined with anticipated scarcity has opened a cornucopia of unconventional resource opportunity elsewhere. No one questions Australia’s bread basket of identified vast natural gas resources. According to the U.S. Energy Information Administration, the gas in place for Australian shales is estimated at 1,380- to 2,300 Tcf, of which 400 is deemed recoverable. That number excludes tight sands and deep coals. Only now have markets and price made them desirable.

Renewing the Cooper

For the first time in Australia, unconventional reservoirs are trending economic. Shale and tight sands beyond the CSG-to-LNG fields are gaining operators’ attention.

The boom to explore for unconventional here began in 2011, according to Morgan Stanley, which pegged the spend on shale exploration at $500 million in 2011, up from negligible capex the year previous. “In Australia, low domestic gas prices are an existing barrier, but by the time the industry is ready to deliver, we anticipate domestic gas shortages and higher prices,” the research firm said in a 2011 report. The prediction is proving accurate.

The Cooper Basin is seeing Australia’s first unconventional action. The Cooper is Australia’s oldest hydrocarbon basin, discovered in the 1960s, with about 1,800 total conventional wells drilled. It is located smack in the middle of the continent, in a flat and remote desert region known as the Red Center, so named for the color of the dirt. Three gas pipelines exit the basin to major domestic markets: one southeast to Sydney; one northeast to Brisbane; another south to Adelaide.

Until 1999, Santos held all permits to the Cooper. The basin was then considered mature and explored, with known conventional targets tapped. At that time the government, which holds all mineral rights in Australia, required Santos to relinquish any unexplored regions, and the northern and southern flanks of the basin opened up to other companies, typically junior explorers.

As it happens, the Cooper features a smorgasbord of shales, tight sand and deep coal seams, all potentially made viable by unconventional technologies developed in the U.S. Yet the remoteness, the lack of services and supplies, and the heretofore low gas prices have stunted interest in appraising these formations.

The East Coast LNG projects are changing this. While operators here, other than Santos, don’t have contracted offtake from the LNG exports, they are anticipating a shortfall in the ability of the CSG fields to deliver the required export volumes, or a need to backfill the domestic gas market as LNG volumes are sent abroad. The basin is seeing a flurry of unconventional activity.

First horizontal shale

Chevron Corp. put a big stamp of approval on the unconventional Cooper Basin when it joined Australian independent Beach Energy in February, the first international major to step into the basin. Chevron is taking an 18% to 30% interest in two licenses, with an option of up to 60%. Beach managing director Reg Nelson, in a statement, said, “This transaction vindicates the vision the company has in relation to the potential of unconventional gas in the Cooper Basin.”

Eyeing the opportunity looming in 2015, Beach, based in Adelaide, has been busy evaluating and appraising two Cooper Basin troughs. To date, Beach has drilled eight vertical wells and fracture-stimulated and flowed back five. “We’re drilling our first horizontal well now,” says Jamieson. “It’s the first horizontal well targeting shale in the Cooper Basin at about 3,400 meters down (11,000 feet), not dissimilar to the Haynesville shale.” (Oil and Gas Investor spoke with Beach in advance of announcing the Chevron partnership.)

Beach, which shares a minority interest in the North Dakota Bakken shale with Helis Oil & Gas, holds the licenses to 48,000 square kilometers (nearly 12 million acres) in the Cooper. Its unconventional program, though, focuses on shale and tight sands in the Nappamerri trough, straddling the South Australia and Queensland border in two permits.

Horizontal wells remain rare in Australia. Holdfast-2, Beach’s first horizontal well, is targeting the Murteree shale, part of the Roseneath-Epsilon-Murteree (REM) section, with a planned 5,300-foot lateral. It is anticipated that it will be fracture stimulated with up to 15 stages in April. This follows two vertical wells drilled through the 1,500-foot section of the REM and fracture stimulated. These were the first drilled off structure, and flowed more than 2 MMcf per day each.

“Those two wells derisked it,” says Mike Dodd, Beach exploration and development manager. “We would have been happy to get half a million per day. To get over 2 million from each of those wells was a fantastic result. It really gave us confidence.”

Jamieson is equally excited about the potential of the Patchawarra tight sands, a basin-centered gas play that sits below the REM. Subsequent appraisals revealed an additional 2,000 feet of gas-saturated zone. Moonta-1, the first vertical testing the zone with nine frac stages, reached a maximum controlled flow rate of 2.6 MMcf per day.

He estimates 300 Tcf of gas in place just for the PEL (Petroleum Exploration License) 218, where Moonta-1 was drilled. “Assuming just 10% recovery,” he says, “that’s 30 Tcf of sales gas. You can see this thing has the potential to be Australia’s largest onshore gas resource.”

And now the company has a partner in Chevron with a $95-million carry. Beach plans 12 vertical and two horizontal wells, all fracture stimulated, to finish its exploration and appraisal program, then move to a pilot program in 2014. The appraisal program thus far “is beyond our expectations,” says Dodd. “We’re further down the road than we thought we would be at this point.”

Existing infrastructure at the Santos-operated facility in the town of Moomba, which is at two-thirds capacity, can handle pilot program production, but full development will require more. “If this play gets industrialized and it’s as big as we think, then you’ll need to either upgrade Moomba or build a stand-alone facility,” says Jamieson.

Prior to Chevron, Beach has funded its unconventional gas exploration program with a strong balance sheet supported by healthy cash flow from its conventional oil production on the western flank of the Cooper Basin. “It’s good to have oil,” he says, which is transported by flowline to the south coast where it receives Brent pricing. “That has allowed us in part to undertake our unconventional exploration program. Should we get to proving up commercial flows from the PEL 218 and ATP (Authority to Prospect) 855 blocks, this will be a massive gas play.”

LNG demand is the catalyst. “If LNG takes off, then there is a need to have plays like this to make sure that Australia gets its supply of gas on the East Coast,” says Jamieson. “Otherwise, Sydney is going to be in a bit of trouble in a few years. As a result of these challenges, there is an opportunity for us to feed into this (demand) wedge.”

Huge resource

Unconventional gas in Australia would not be experiencing drillbits today without the LNG market, reiterates Ian Davies, managing director and chief executive of Senex Energy Ltd., based in Brisbane. “At $3, where the traditional price has been, there’s no chance. All of a sudden you have an export market, and you have a price signal to invest in gas. At $8 per million Btu, you can afford to go after unconventional gas plays in the center of Australia, which is the new source of supply for eastern Australia.”

Senex, which like Beach leans on revenues from conventional oil in the western Cooper Basin, is undergoing an extensive unconventional exploration program in the Cooper, where it holds interests in 1.2 million acres prospective for oil and gas. The 1,500-horsepower Weatherford Rig 826 drilled the company’s fifth vertical well in January 2013. The well is the first of 12 to be drilled over the next 18 months, with the 2,000-horsepower Ensign Rig 969 arriving in Australia in July to drill the remaining wells in the program.

“The quantity of gas in Australia is not a problem,” says Davies. “There’s huge resource potential. But there is not enough gas from existing discoveries to ramp up to 1.3 Tcf a year from zero into international markets, so now you’re heading to new discoveries.”

The company began its unconventional gas program in May 2011. Its first four wells targeted zones in its southern Cooper acreage, south of Beach’s program. These include the Epsilon and Patchawarra sands, Roseneath and Murteree shales, and Patchawarra coals. Gas-in-place in the shales and coals alone is estimated at 100 Tcf.

Paning-2 is the first unconventional gas well testing the company’s northern acreage in the Patchawarra trough for tight sands and deep coals. Senex estimates 2.1 Tcf of gas in place across the 9,000-acre Paning structure.

“These first five or six wells are designed to cut core and try to understand the gas content,” says Senex general manager of exploration Steven Scott. “The results have been extremely encouraging.”

Analysis of the cores is at Weatherford and Core Labs in Australia, with some samples shipped to the Weatherford lab in Denver for special analyses, where Senex rock sometimes waits in line behind U.S. shale cores. “We don’t have all the facilities here,” Scott says. The emphasis starting this year is a five-well fracture-stimulation program. Senex has contracted Halliburton for the work, which has two frac crews in the country, and expects to complete the southern portion of the program in April 2013.

The issue at the moment, however, is costs, according to Davies. “It’s very, very expensive.” A 9,000-foot, fully fracture-stimulated vertical well costs $10 million. The locations are remote, and rigs and services are costly to mobilize. Labor runs some $100,000 a day. “It’s an expensive place to do business when you’ve got low-volume work currently. It’s going to be high cost until the industry matures.”

Davies expects vertical costs will come down to $6 million in time. Horizontal fraced wells run $15- to $20 million, and should level near $10 million. “You can’t just dream that services will just be there. You’ve got to create an environment for it to come.”

The tight Permian sands are the first target, Scott says, likely on a vertical drilling program. “The primary target is the Patchawarra. At some point, the early Permian shales will come in. Once we start appraising and flow testing shales, we’ll need some horizontal wells.” Senex is budgeting $150 million over the next 18 months for its unconventional program.

Infrastructure constraints are a real barrier to entry into the gas business, says Davies. “The Cooper is basically in the middle of the desert. It’s not like the U.S., where you’ve got Henry Hub and can find the nearest pipeline and throw in some raw gas.” Instead, explorers must drill and prove up enough reserves to justify infrastructure. “Then you’ve got to have sales contracts, because there is no spot market for gas in Australia.”

Realistically, he says, it takes four to six years to get a gas business off the ground from the exploration phase, certainly in Australia due to the infrastructure and other constraints. “With the wind behind us, we’d be expecting to be producing gas in 2016 or 2018, into domestic and export markets.”

It’s a huge resource, and it now has a market, says Davies. “Both the lack of supply in the domestic market and the increase in prices through export LNG provide a fantastic opportunity for companies like us with real supply potential.”

Cooper’s deep coals

Strike Energy Ltd. managing director David Wrench is excited, like a kid who’s been given the keys to the candy factory. Strike drilled two wells in 2012 on the southern flank of the Cooper Basin into the coal and shales of the Toolachee, REM and Patchawarra formations, and found more than 300 feet of net coal in six seams.

“We were really surprised,” he says. “We got massively thick coals, way thicker than we had expected. It’s a very thick system.”

And it’s gas-charged too. Core data showed “incredibly high” gas content over an extensive area. “We can map these coals for miles,” he says.

“To put it in context, that’s 6- to 16 Tcf net to Strike, onshore, less than 6,000 feet deep, and under a gas pipeline that’s linking to a market that is short of gas. We believe this is a big discovery, but we haven’t fully grasped it yet.”

Of its total 4 million net permitted acres in the Cooper, 1 million are prospective for unconventional targets. “The leasing game is relatively easy,” he says. “No small company like Strike could get anywhere near this in the US.” He should know, as Strike, headquartered in Perth, participates with nonoperated positions in the Eagle Ford shale and the Permian Basin.

While the center of the Cooper Basin is relatively known from a conventional standpoint, the deep troughs and the flanks are new exploration, he says. “People don’t know what is happening between those ridges in the troughs,” he says. “That’s the kitchen. Not a lot of work has been done there.”

The two Cooper Basin wells, the first targeting coals in this region, were drilled, cased and suspended, but have yet to be fractured or flow tested. “That’s one of the primary objectives in the next round of work, to get that next level of data. No one has drilled these troughs before; we just needed to get baseline data.”

Wrench is equally happy that the unexpected discovery is in coal seams rather than shale, as development costs should be significantly lower. “It’s not like we have to drill very deep or big horizontals. We’re pleased about that—that’s why a company like Strike can have a crack at this sort of thing. We would struggle to do the same in a shale play.”

Strike will drill three to five wells here in 2013 to derisk the play and perform a completion test on one of its previous vertical wells. “We’re going to focus quickly on productive potential,” says Wrench. “This is not an exploration play anymore—we know there’s a huge resource there. Now it’s about finding a way to produce it economically.”

Rather than the geology, the difficult part will be commercialization and development. “You don’t have the same service providers and infrastructure that are taken for granted in the U.S.,” he says. “That’s the biggest challenge.”

Yet one worth tackling, he notes. “We’ve made a potentially game-changing discovery here,” says Wrench. “This is turning out to be way more interesting than when we started. This is an unbelievable opportunity.”

Commercializing unconventional

Santos sports the distinction of bringing online the first commercial unconventional gas well in the Cooper—indeed, anywhere in Australia—with its Moomba 191. The vertical well targeted the Roseneath, Epsilon and Murteree shale formations, with three fracture stimulations placed over a 400-foot gross interval. With some 250,000 pounds of proppant per stage and 35,000 horsepower on location, provided by Halliburton, “These were some of the biggest fracs we’ve ever done,” Ovenden says, “and we’ve been fracing there for over 30 years. We believe they are among the largest pumped in Australia.”

The well, purposefully drilled near infrastructure, came on at 2.7 MMcf per day in October, and is currently producing at 2.3 MMcf per day. “We are pretty delighted with the outcome . That’s the first test in which we’ve been focused on amping up the shale plays. We’re looking at repeating that outcome and bulking up on other plays we’ve identified there.”

Santos retains more than 9.8 million acres across the Cooper, more than any other company, with a total prospective resource of more than 50 Tcf. It now has some 3 Tcf of 2C contingent resources booked, with a goal to prove commercialization and significantly build on this resource base by 2015.

It has four rigs running with a fifth on the way. Two 1,500-horsepower newbuild rigs are on order for early 2014 to handle longer-reach wells. “The 1,500-horsepower rigs are in short supply,” says Hoff. She confirms that Santos employs one full-time frac spread from Halliburton, and another part-time spread from Schlumberger. “We’re trying to bring in new blood on a lot of different services to grow the resource base. Competition is never a bad thing,” she jokes.

Santos has identified six different unconventional plays, ranging from tight gas to pure shale plays, Ovenden says. “We’re trying now to move many of those to discovery and, where possible, target close to infrastructure so we get the benefit of early revenue streams from any success that we derive.”

Next, Santos plans a horizontal offset to Moomba 191, the first of three vertical/horizontal pairs planned, with a 1,000-foot lateral into the lower Murteree shale with five stages. As Santos builds expertise with these new technologies, the subsequent shale tests in the 2013 program will aim to increase reservoir contact through longer laterals and more frac stages to drive gas development costs lower.

Ovenden says Santos plans to drill three vertical wells of a six-well program in 2013 to test the central basin deep-gas play in the Nappamerri trough, where the traditional Toolachee, Patchawarra, Epsilon and Tirrawarra sands are tight and gas-saturated over an extensive area. The REM shale plays intervene but are not the immediate targets of this program.

“We’ve potentially got a very large resource out there. We’re trying to break open the greater resource picture now and see how it responds to stimulation. If it works, we’ll get it onstream as soon as we can, then use that revenue stream coming from the LNG plants to get after it.”

Santos allocates a third of its budget to unconventional exploration. It also holds unconventional prospects in the McArthur and Amadeus basins to the north. “We’ve got a boatload of opportunity,” he says. “It’s exciting, but it’s early days.”

Opportunities west

While the wave of new LNG ramping up in Gladstone has eastern Australian producers hopping on the unconventional train, Western Australia is not to be left out. One company, AWE Ltd., with onshore and offshore assets throughout Southeast Asia, is testing unconventional shale and tight-sand targets in the northern Perth Basin.

Unlike the East Coast market, the West Coast already enjoys international pricing via existing LNG export. “We’re in a good gas market,” says AWE managing director Bruce Clement. “We’re in an infrastructure-rich area of Australia with good demand and pretty good pricing.”

AWE’s footprint in the Perth Basin measures some 600,000 net acres. The Sydney-based company last July began a hydraulic-fracture stimulation program of three proof-of-concept vertical wells. The mission was to test eight separate tight-sand and shale zones. “Those fracs were all completed successfully,” he says. Gas flowed from all eight.

The Senecio-2 perforated a 16-foot interval in the Wagina and Dongara tight sands. It flowed 1.35 MMcf per day stabilized, and 65 barrels of oil and condensate total, before being shut in. The Woodada Deep-1 stimulated two zones in the Carynginia shale.

The third well, Arrowsmith-2, targeted five separate zones. The High Cliff Sandstone and Irwin River coal measures, along with the Kockatea shale and Upper and Middle Carynginia shales, proved successful. The operator, Norwest Energy, has been flow-testing one at a time and the well is now undergoing further cleanup of frac fluids.

“We won’t have the results for a few months yet,” Clement notes. “We’ve had promising results from the top shale, the Kockatea, which produced gas and liquids. We’re now in the second zone, the Carynginia shale, where we’ve seen initial flowback rates of a few thousand cubic feet of gas coming back.”

AWE, too, is an active participant in the U.S. Eagle Ford shale, with a 10% interest in the Sugarloaf project with operator Marathon Oil. AWE is importing shale knowledge adapted from the Eagle Ford, as well as bodies. “We’ve brought people over from Texas to be on the ground with us in Western Australia.”

Could Australia’s shale plays look like the Eagle Ford in a few years? “We don’t see it developing in quite the same way,” Clement says. “In the U.S., a lot of activity was driven by acreage retention requirements. Here, we’re not under those pressures. We can manage the testing of shales in a more progressive and measured way in terms of risk management and value accretion to ensure that developments are staged and managed.”

The next phase, he says, is to put down a proof-of-concept development-type well in the shales. “We need to place a multistage frac into one of the shales to see if a development well can deliver sustainable commercial production. That will be the real test of the shales in the Perth Basin.”

Unconventional exploration in Australia goes beyond these basins as well. The Canning Basin in northwestern Australia, as well as the Beetaloo and McArthur basins in Northern Territory, are examples of emerging plays. International majors Hess, Mitsubishi Corp., ConocoPhillips and BG Group have joined with local shale explorers.

Most operators believe Australia is about 10 years behind the U.S. in unconventional development, and that the pace will be more measured. But none doubt Australia’s unconventional resources are abundant and ripe.

Santos’ Diana Hoff, with the perspective of seeing the evolution of U.S. coalbed methane and shale development, says, “It’s an exciting time to be in Australia. We’re trying to cram into five or 10 years what took us 25 in the U.S. It’s not without its challenges, but it’s a fun time to work here. We wouldn’t have the shale and tight gas if it weren’t for the LNG projects.”