mentioning of exoma

Courtesy of Wilto on SXY post. Mentions Exoma.

http://www.epmag.com/item/Australian-unconventional-plays-remain-proof-of-concept-stage_114356

Australian unconventional plays remain in proof-of-concept stage

With only four hydraulic fracturing crews in the country and few drilling rigs capable of performing horizontal drilling, Australia’s oil and gas shale and tight sand development is in its infancy.


The first unconventional horizontal well in the Cooper basin in Australia was being drilled at the end of January 2013 by Beach Energy Ltd. Even with current exploration programs, shale oil or gas production in the country is very limited. Australia does have gas production from tight sands and coalseam gas (CSG). However, there are millions of acres in untested exploration licenses, which make Australia’s unconventional resources a tempting target.

The Australian unconventional plays are so tempting that Beach Energy announced Feb. 25 that Chevron would spend up to US $349 million to farm in on Beach’s Petroleum Exploration License (PEL) 218 in South Australia and Authority to Prospect (ATP) 855 in Queensland. The farm-out will position Beach for long-term appraisal and development of unconventional exploration in the Nappamerri Trough.

“Shale oil/gas has been a game changer in the US. While the Australian shale sector is at an early stage, the potential size of the resource base (estimated at 396 Tcf by the US Energy Information Administration) holds long-term promise. With the country poised to become a major LNG exporter (about 80 million metric tons [MMmt] per year capacity by 2018), we believe shale could represent the next avenue of development that can feed LNG supply,” said Asit Sen, director, Dahlman Rose & Co., in a March 4 analysis.

“We view Chevron’s recent investment in the Cooper basin as strategically significant. Estimated shale resource potential in the country appears massive with proximity to robust Asia-Pacific LNG markets. We expect activityin Aussie unconventional plays to build momentum,” he continued. “Chevron has become the first oil major to invest in the Cooper basin. We view Chevron’s entrance in the Aussie shale arena, while initially relatively small, as strategically significant,” he added.

“While several international oil companies, including Hess, ConocoPhillips, BG Group, Chevron, Total, and national oil companies have announced investments, we expect activity to pick up momentum. Local companies such as Santos, Beach Energy, Senex Energy, Drillsearch Energy, Icon Energy, and Linc Energy, among others, are leveraged to shale plays in Australia,” Sen emphasized.

Investments in developing the potential of unconventional gas in the Cooper basin bode well for the nascent industry in Australia. When coupled with the development of CSG reserves, primarily in the Bowen and Surat basins to supply LNG export projects on Curtis Island near Gladstone, the pace for development of unconventional oil and gas resources in Australia is ready to move forward much faster.

Issues facing unconventional development

“The issue in Australia at the moment fundamentally is cost,” Ian Davies, managing director and CEO, Senex Energy Ltd., told E&P. “It is very, very expensive. A vertical well drilled to 2,000 m to 3,000 m [6,600 ft to 9,900 ft] and fully fracture-stimulated costs $10 million. Horizontal fraced wells run $15 million to $20 million. The locations are remote, and rigs and services are costly to mobilize. Labor sometimes runs to $100,000 a day. It is an expensive place to do business when you have a low volume of work.

“It is going to be high-cost until the industry matures. You don’t have the number of service companies here. You choose from one or two service companies for drilling, cementing, fracturing, and logging. You can’t just dream that services will just be there. You’ve got to create an environment for it to come, and we’re working with government and other operators to make that happen,” he continued.

David Wrench, managing director, Strike Energy Ltd., agreed. “Exploration and development status in Australia is in the early stages. When we look at what we know in the Eagle Ford [in the US] and compare it to the Cooper basin, we are many years behind in our understanding of how to develop the resource. Even in the Cooper basin, which is the most prolific hydrocarbon basin in Australia, we drilled wells last year that surprised the industry.”

Added Diana Hoff, vice president, technical and engineering, Santos, “If shale takes off, we’re going to need a lot more [services and equipment]. That’s the bottom line. Right now, companies are very eager to bring additional crews into Australia. This is seen as a good market with great potential, particularly when it comes to unconventionals.”

The biggest attraction for unconventional resources in Australia is the potential volume of natural gas. The Petroleum Exploration Society of Australia (PESA) estimated that the Cooper basin could hold unconventional gas resources of 250 Tcf. PESA put estimates for the Canning basin at 229 Tcf, the Perth basin at 71 Tcf, and the Maryborough basin at 23 Tcf. The Australian Bureau of Agricultural and Resource Economics (ABARE) estimated potential CSG resources in eastern Australia of 250 Tcf, which includes the Bowen and Surat basins.

Australian companies are faced with the challenge of unlocking unconventional gas and oil development. Many of those same companies have holdings in US shale plays, which have provided impetus for Australian efforts.

The unconventional plays in Australia have some distinct differences from the major North American plays, Wrench explained. The depositional environment in Australia is predominantly terrestrial vs. marine in North America. The predominant source rocks are coal and lacustrine shales as opposed to marine shales in North America. In Australia the hydrocarbons are mostly gas with some NGL compared to oil, gas, and condensate in the US.

There are other problems facing unconventional oil and gas operators. “In Australia all mineral rights are owned by the state. We have no private mineral ownership,” Wrench said. “A major problem is that the surface owner has no economic interest in the subsurface rights. There is an inherent conflict of interest over the surface and subsurface rights. We have a more difficult process in terms of land access, particularly in developing a resource play where activity is very intense.”

The CSG developers are facing a different problem: water. Since most of the hydraulic fracturing in Australia is in vertical wells, the demand for water for fracing is not as high as it is in the US. However, a tremendous amount of water is produced with the CSG. Galilee Energy had to build a fully engineered dam to hold the water produced from its pilot gas project in the Galilee basin in Queensland.

“It’s an ongoing conversation with landowners and local neighbors since they would like to use that water. It is not freshwater in that it doesn’t meet the requirements according to the regulators in terms of its fluoride content. It is not just understanding the coal itself and the right engineering mixes to dewater so the gas can flow; it is also dealing with helping the regulators get up to speed and having the right strategies in place,” Glenn Haworth, CEO, Galilee Energy, told E&P.

Cooper/Eromanga basin

Santos is the original, as well as the largest, leaseholder in the Cooper basin, which stretches across the northeast corner of South Australia and the southwest portion of Queensland. Until 1999 Santos had a monopoly in the basin. From 1999 to 2000, the government had the company relinquish acreage that was undeveloped.

The company focused on conventional oil and gas development and is now turning its attention to unconventional resources. “We’ve been exploring conventionally over a significant portion of that acreage for 30 to 40 years,” Bill Ovenden, acting vice president, exploration and subsurface, said. “This year we will spend about one-third of our exploration drilling budget on the Cooper unconventional plays.”

“We have different plays in the basin,” Hoff added. “That is what makes the Cooper basin fun. We have the shale that we are just getting started on, and there are actually deep coals as well that my geoscientist friends tell me are quite intriguing.”

Ovenden added that these coals “have great gas saturations. We’ve got six different unconventional plays, ranging from tight gas sands to pure shale plays. We’re trying now to move many of those to discovery.”

One discovery was made close to gas gathering infrastructure, allowing the company to begin Australia’s first commercial shale gas production from its Moomba-191 well within 30 to 40 days. On Oct. 19, 2012, Santos announced the shale well flowed at a stabilized rate of 2.7 MMcf/d from the Roseneath, Epsilon, and Murteree (REM) shales. “The connection of the Moomba-191 well is a significant step forward as we work to unlock the vast unconventional potential of the Cooper basin,” James Baulderstone, vice president, eastern Australia, Santos, said in the press release.

Each of the REM formations was fraced in the vertical well. “Those were big fracs with approximately 600,000 pounds of proppant. They are probably the largest fracs pumped in Australia. We had 32,000 hp on location. It was the largest for us for sure. Halliburton pumped it,” Hoff said.

“That is the first test in which we have been focused on amping up the shale plays,” Ovenden continued. “We’re looking at repeating that outcome and bulking up on some other plays we have identified out there.”

Santos is drilling a horizontal well near the Moomba-191 and will frac the REM section to see what a horizontal section will flow, he said. “This year we are drilling three vertical-horizontal pairs close to infrastructure to try to replicate the Moomba-191 result and test [to see if we get the desired result]. We will vary the horizontal lengths and number of frac stages,” he added.

“We’re also drilling three vertical wells in another part of the basin in the Nappamerri Trough to get some core control on the shales there. We will also test the basin-centered gas play that we feel has a lot of merit,” Ovenden said.

Another company heavily involved in the Cooper basin is Senex, with close to 73,000 sq km (28,185 sq miles) of exploration permits. “Even in the Cooper basin, which contains 130,000 sq km [50,193 sq miles], only about 3,000 wells have been drilled. If this were Canada or the US, you would have 100,000 wells. It is very immature in terms of what you are used to in North America. As a result, you have this big opportunity,” Davies said.

Steven Scott, general manager, exploration, Senex, noted that in the Cooper basin there are two shales with sandstone sandwiched in between. “It is like the Piceance basin. The shales are not deep, black shales. These are not marine shales like the Haynesville or Barnett. These are fluvial lacustrine shales, which is more like the Piceance.”

The top of the Permian sequence is the Toolachee formation. At the bottom of the sequence are the Patchawarra and Tirrawarra sandstones. In between is the REM group. In early February Senex started a large-scale fracture stimulation program on its unconventional gas wells in the South Australian Cooper basin.

The five-well program involves three wells in its southern permit (Skipton-1, Kingston Rule-1, and Talaq-1), one well in its northern permit (Paning-2), and the existing Hornet-1 well. Senex expects the program to provide information on production rates after fracing.

On March 11, Senex announced the completion of a multizone fracture stimulation of the Kingston Rule-1 well with gas flowing to the surface at a constrained rate of 1.2 MMcf/d. The Kingston Rule-1 targeted the tight gas sands of the Patchawarra Formation with a vertical well drilled to 2,872 m (9,478 ft). Davies was enthusiastic about the preliminary flows during cleanup and flowback. “Initial gas flow rates from Kingston Rule-1 have met and exceeded the prime objective of mobilizing significant gas to the surface from a tight sand reservoir. The result confirms our confidence in the Cooper basin as a world-class energy precinct,” he said.

“Unconventional gas in Australia is in its infancy. We’re probably 10 years behind the US. Given that we don’t have an integrated spot market, it is just a step harder,” Davies told E&P.

“We’re at the beginning. We have drilled five wells out of a 16-well program. We have another 11 wells to go in the current budgeted program. These are vertical wells since they are exploration wells, which we will fully fracture-stimulate and flow-test.”

One of the most active companies in the unconventional play in the Cooper basin is Beach Energy. “The Cooper basin is a great place to work as it is strategically located within reach of the East Coast Australian gas markets with infrastructure on our doorstep. An added bonus is we have strong working relationships with both the South Australian and Queensland governments,” said Chris Jamieson, general manager, investor relations, Beach Energy.

“The work we are undertaking in terms of fracture stimulation has been ongoing in the Cooper basin for 30 years, with around 700 wells fracture-stimulated in the Cooper basin to date. So what we are doing is nothing new.”

Neal Gibbins, Beach COO, said, “From our point of view there are two components to our unconventional play. The first component and initial target was shale gas, and the second is basin-centered gas, which is focused mainly on tight sandstones. The Cooper basin has two troughs: the Patchawarra Trough and Nappamerri Trough.

“From the work we have undertaken to date in the Nappamerri Trough, we have discovered there is gas saturation through the Permian target zone. The exciting thing from Beach’s perspective is that we have more than 1 km (0.6 miles) of gas saturation in this zone, which we believe extends under our two permits, which has an areal extent in excess of 3,200 sq km (1,235.5 sq miles),” he continued.

So far the company has drilled eight out of 12 vertical appraisal wells in its current program. All of these wells will be fracture-stimulated. The company also will drill two horizontal wells – Holdfast-2 and Encounter-2 – for a total of 14 wells.

In February 2013 one of the wells – the Halifax-1 on ATP 855P in Queensland – flowed 4.2 MMcf/d during flowback. The well was drilled to a total depth of 4,267 m (14,081 ft). Fracture stimulation over 14 stages was performed over the entire gas-saturated Permian target zone. Seven stages were completed in the Patchawarra sandstone, one in the Murturee shale, two in the Epsilon sandstone, two in the Roseneath shale, one in the Daralingie formation, and one in the Toolachee formation.

“We have started our first horizontal well,” Gibbins continued. “We have drilled eight vertical wells to date, all of which have been cored with a substantial amount of data acquired. The approach to this unconventional play has been very methodical. We are moving up the learning curve and seeing improvement in each well drilled and fracture-stimulated along the way.

“This is the most aggressive program Beach has undertaken,” Gibbins added. “Our operations also deliver production and cash flow, which means we are comfortably funded from a capital expenditure program perspective over the coming years.”

The company is evaluating the unconventional play and getting Beach into a position to tap either the domestic gas market or international LNG exports by 2015 to 2016. With the infusion of capital from Chevron, the company should be able to accelerate its unconventional program.

Exploring western, southern basin flanks

As the third largest leaseholder in the Cooper basin behind Santos and Senex, Drillsearch recognizes robust opportunities for conventional and unconventional resources. “In looking at the Cooper basin, what you see is a cornucopia of opportunity,” said Brad Lingo, managing director, Drillsearch. “There are clear indications that the geoscientists have realized that there are large parts of the basin where there are significant unconventional resources.

“First and foremost, the Cooper basin has been historically underexplored and underexploited. Looking at the South Australian part of the basin around 2010, only 850 exploration wells had been drilled over 25,000 sq km [9,652 sq miles]. That is basically one exploration well per 20 sq km [7.7 sq miles], and that is clearly not dense activity,” he continued.

“We realized that our acreage position represented significant holdings within the core of the Cooper basin. Various components of our acreage represented oil-prone and wet gas-prone areas. Then there are areas that are likely to be purely unconventional plays,” Lingo said.

Technology is important to the company. Drillsearch was one of the first companies to use 3-D seismic as a regional exploration tool in Australia. The company utilized the proprietary WesternGeco UniQ 3-D seismic acquisition system with the survey incorporating some of the most advanced technology currently available to the onshore seismic industry. Drillsearch’s Winnie seismic program was the largest 3-D seismic survey ever acquired onshore Australia – 1,054 sq km (407 sq miles).

“We’ve redeployed the team to another part of the Cooper basin. It has already completed two surveys for us – one in the shale gas fairway and another in one of our oil project areas,” he said.

Lingo explained that the company built a three-legged business model. Drillsearch focuses its business around conventional oil in the Western Flank Oil Fairway, conventional wet gas, and tight sandstones.

“Our unconventional activities are largely focused on tackling the Permian-aged sequences. These include the shale sequences associated with the REM package, the tight sands associated with the Patchawarra formation, and the tight oil associated with the Tirrawarra formation,” Lingo explained.

On the conventional side, Drillsearch is going back into its oil fairway on the Western Flank of the basin. “One of the first wells we drilled with Beach was based on 3-D seismic. We believe there was an oil discovery that was made on the Western Flank in our permit in the mid-1980s. We recently acquired 3-D over the area, looked at the well log, and what we interpreted was that it looked as though it was a missed oil discovery,” Lingo said.

Strike Energy is focused on the southern flanks of the Cooper Basin in South Australia. “We have three main permits relevant to the unconventional play. The biggest hydrocarbon source rocks in the Cooper basin are the coals. Where there are coals, there is gas,” Wrench told E&P.

The company has a play in the Eagle Ford in the US. “We’ve learned very quickly, as we’ve developed that play, of the importance of understanding precisely which generation window you are in. The gas-condensate window is really where your dollars are, but you’ve got the liquids that are driving your revenue,” he continued.

Strike has drilled two wells in the southern part of the basin. The company was looking for shales and coals and was trying to understand thermal maturities. In the Permian section Strike found both shales and coals.

“We got gas shows and heavy hydrocarbons. We know we’re in a hydrocarbon-generating window. With the second well drilled (Davenport 1), we really were surprised. We got massively thick coals, way thicker than we expected. In that well we found more than 100 m [330 ft] of net coal in three or four seams. In the rest of the Cooper basin you are getting maybe 30 m to 50 m [100 ft to 165 ft] of coal in that same interval,” Wrench said. “We now have a play, net to Strike, in the coals alone of 6 Tcf to 16 Tcf. We believe this is a big discovery, but we have not fully grasped it yet.”

In 2013 the company plans to do more targeted evaluation work in Block PEL 96 and also is planning a three-well drilling program. Strike is proposing to go back into the Davenport-1 to frac and flow-test the well. This is not an exploration plan any longer. There is a huge resource there, and now it is about finding a way to produce it economically, he added.

Like other companies, Strike faces challenges. “We have almost a million net acres – it is massive by US standards. No small company like Strike could get anywhere near this in the US.

“The more difficult part is commercialization and development,” Wrench continued. “We don’t have the same infrastructure and service providers. Things that are taken for granted in the US are not available in Australia. That is the biggest challenge. We’ve got the resource, lease packages, land, and very interesting market dynamics. We don’t have the capacity within the industry in Australia currently to do all the work that needs to be done.”

Surat, Bowen basins

CSG has been produced from the Surat and Bowen basins in Queensland for decades for the domestic market. Now there is impetus for developing these reserves – the export of LNG from the Queensland Curtis LNG, Gladstone LNG, and Australia-Pacific LNG plants on Curtis Island near Gladstone.

A huge number of wells will be drilled, up to 32,000 total. Queensland Gas Co. (QGC) has drilled about 1,100 wells and expects to drill a total of 6,000 wells over more than 4,500 sq km (1,737 sq miles) by 2030 to supply the Queensland Curtis LNG project. Each well costs a little more than $1 million to drill, according to BG, QGC’s owner. The company expects to have drilled a total of 2,000 wells by 2014 when the plant begins exporting.

Arrow Energy, a joint venture (JV) of Shell Australia and PetroChina, has not made a final investment decision on its LNG plant. The company has drilled about 1,000 wells so far and expects to drill a total of 15,000 wells to support its planned two-train plant with a capacity of 8 MMmt/year.

Australia-Pacific LNG has more than 17,000 sq km (6,564 sq miles) of CSG acreage in the Surat and Bowen basins and 18,000 sq km (6,950 sq miles) in the Galilee basin, which “will provide the potential CSG production capacity required to feed the LNG facility for decades,” according to the company’s executive summary. “A total of 10,000 wells are anticipated over the life of the project.”

Hoff said that Santos’ first environmental impact statement had 2,500 wells. “Now we’ve applied for more wells, and we’ll be drilling 300 wells per year over the next several years,” she added.

“The Bowen basin has Paleozoic coals with Permian coals associated with that,” said Ovenden. “Those are high-quality coals. The Surat basin sequence is Mesozoic and Tertiary. At the base of that sequence is a series of well-developed Jurassic coals, which don’t have the same quality.”

To drill the coals, Santos has to determine whether to go with fluids or underbalanced drilling. “If we go with fluids and we are overbalanced, we tend to frac those wells. Some of the coals are so permeable that you can’t even hold a column of fluid in them. We tend to drill them underbalanced so that we don’t frac them,” Hoff said. “We stimulate less than 10% of our CSG wells.”

Senex also has a legacy CSG position in Queensland. The company has four CSG permits – two in the eastern Surat basin and two in the western Surat basin. Total recoverable reserves are expected to be about 500 Bcf, according to Davies.

“We’re still in a quite early stage with those permits. We are doing exploration in terms of core holes and early-stage appraisal. We are working to come up with a development plan in the next 12 to 18 months,” he said.

In late February, Senex increased it CSG asset base by 15% with net reserves and resources increased to 570 Bcf as a result of exploration and appraisal success.

Perth basin

There is a huge potential for unconventional gas onshore Western Australia, according to Jeff Haworth, director of technology, petroleum division, Western Australia Department of Mines and Petroleum. With 3.5 times the land area of Texas, the Australian state contains an estimated 300 Tcf of unconventional gas resources.

The shale in the Goldwyer formation in the Canning basin has estimated shale gas resources of 229 Tcf, while the Carynginia and Kockatea shales in the Perth basin have an estimated 59 Tcf of gas resources.

Currently, there is a lack of modern drilling rigs capable of drilling deep horizontal holes 1 km to 2 km (0.6 miles to 1.2 miles), he said. Other service units such as wireline equipment are old. There is a need for training or for importing foreign-trained workers.

“Unconventional gas development is in the exploratory stage in Western Australia,” he said. “Opportunities exist for both explorers and service providers to invest in Western Australia.”

Of all the active basins with unconventional plays, the Perth basin in Western Australia faces challenges in terms of rig and frac spread availability but is well served by existing infrastructure. AWE Ltd. did fracing in three proof-of-concept wells between July 2012 and September 2012. However, to do that the company had to have one of the two frac crews in eastern Australia at that time move the men and equipment all the way across the continent.

The fracing of the three vertical wells – Senecio-2, Woodada Deep-1, and Arrowsmith-2 – was successful. Eight separate zones in tight sands and shales were stimulated, with hydrocarbons flowing from each zone. “The Arrowsmith well was drilled specifically to test shale and tight gas opportunities in the northern Perth basin,” Bruce Clement, AWE CEO, told E&P. “The Woodada Deep was an existing gas production well that was deepened to test the underlying shale.”

Norwest Energy is the operator for the Arrowsmith well with a 27.95% interest. AWE has a 44.25% interest, and Bharat PetroResources Ltd. has a 27.8% interest. The Arrowsmith well was a pure exploration well for the company. “We’re continuing the flowback testing from that well. We fraced five zones and isolated each zone with cement plugs. We are progressively going down and testing the individual zones, but we won’t have the results for a few more months,” Clement said.

“We had some promising results from the top shale, the Kockatea shale, which produced some gas and liquids. We’re now in the second zone, the Carynginia shale, where we’ve seen some initial flowback rates of a few hundred thousand cubic feet. There are a couple of deeper zones – the Irwin River Coal Measures (a sequence of coals, tight sands, and shales) and the High Cliff sandstone,” he said.

The High Cliff is the deepest zone. During the initial testing, AWE was able to flow 750,000 cf/d. “That looks very promising for a tight gas development,” he added.

“The plan going forward is to finish the work on Arrowsmith. If we are satisfied with the potential there – and at this stage it looks like there is potential – the next logical step is to drill a horizontal proof-of-concept development well and a multistage frac into one of the shales to see if it can deliver sustainable commercial production,” Clement said. “That’s a decision that we have not made yet. We will consider opportunities elsewhere in the basin because we have a very large acreage position, and it is a very large opportunity.”

The next stage for the company is to go forward with a development feasibility study at the Senecio tight gas field. The Wagina and Dongara sandstones were perforated and stimulated over a 5-m (16.5-ft) interval. The latest flow test in September 2012 achieved a stabilized flow rate of 1.35 MMcf/d. Data from the flow test will be combined with 3-D seismic to build the reservoir model to evaluate potential development.

Northern Territory basins

Willem Westra van Holthe, minister for Mines and Energy, Northern Territory, is squarely behind the shale oil and gas industry. “I think we’ve attracted an enormous amount of interest in unconventional gas in the Northern Territory,” he said. “PetroFrontier is the first company to actually do horizontal stimulations in the territory. Emphasis on unconventional oil and gas in the territory is fairly new. We’ve only got two horizontally fraced wells done by PetroFrontier.

“Interest is probably a little more prominent now for two reasons: Technology is more readily available, and evidence is now mounting to suggest the Northern Territory is highly prospective for unconventional oil and gas. Only in the past few years interest has started to peak up,” he said.

“An ABARE report dated Oct. 2012 notes gas projects are the main contributor to the value of the Northern Territory potential investment pipeline. The Northern Territory is ideally placed to provide a full range of onshore conventional oil and gas and onshore unconventional gas services,” he told participants at the Australian-American Chamber of Commerce meeting Feb. 18 in Houston.

When it comes to investment in the territory, Westra Van Holthe pointed to the $34 billion being invested by Total and Inpex in the offshore Icthys project and new LNG plant in Darwin. “There are companies like Santos and Hess talking about hundreds of millions of dollars in investment over the next couple of years.”

Added Ovenden, “[Santos has] taken a 23,000-sq-km [8,880-sq-mile] position in the McArthur basin in the Northern Territory. That is oil shale. Our acreage footprint has gone from 117,000 sq km [45,174 sq miles] at the end of 2011 to 230,000 sq km [88,803 sq miles] onshore Australian unconventional exposure in net acreage position.”

Westra Van Holthe explained that a Country Liberal government was elected in August 2012, replacing the Labor government. For companies looking to invest, there is a new paradigm. “If a proposal stacks up on its ability to meet all the requirements, then it should go ahead,” he said. “I think we’re able to provide a stable political climate that helps companies focus their interest on the reserves we have. My mantra is to be very supportive of responsible exploitation of our resources.”

About 50% of the land area in the territory is owned by aboriginal land trusts. “Without a doubt, the aboriginal aspect is encapsulated under the need to obtain cultural licenses as well as social licenses,” Westra Van Holthe said. “For companies to operate on those lands

there are additional regulatory hurdles the companies have to get through. The process can be quite slow at times. The government works with the land councils to expedite the process. I think it is one of the biggest nonfinancial impediments to developing resources in the territory.

“We are a stable government that is concerned more about the process than politics. The mining and energy sector fits into what we have termed our three-hub economy. The three hubs for us are mining and energy, food production and export, and tourism and education. With the new government and a new paradigm, no doubt we consider ourselves open for business,” he added.

Galilee basin

One of the most underexplored basins in Australia is the Galilee basin in Queensland. Exoma Energy and Galilee Energy Ltd. are two small companies tackling the great expanses of the basin, which is in the middle of central Queensland. In this area the Galilee basin (Permian/ Triassic) is under both the Great Artesian basin and the Eromanga basin (Jurassic/Cretaceous).

“Coal mines have been proposed on the eastern periphery of the basin – 30-million-metric-ton scale mines,” Haworth said. “It’s a region receiving significant investment, and some serious players are in that region.”

The unconventional oil and gas prospecting is not moving nearly as fast as coal mining. Galilee Energy has about 7,000 sq km (2,703 sq miles) in the underexplored basin. The founding of the company is tied to former Houston company Enron. “When Enron Northern Gas came to Australia in the early 1990s, the company reviewed CSG across Queensland. Enron thought the Galilee basin offered the greatest value. The origin of our company is a JV with Enron,” he said.

Some of the legacy assets include the Rodney Creek gas field. One of the tenements the company has is a 50:50 JV with Australia Gas and Light (AGL) on ATP 529P with AGL as the operator. The company’s midterm strategy is to deliver CSG. Short term, Galilee wants to acquire oil and gas projects to provide positive cash flow. Cash on hand as of Sept. 30, 2012, was $33.1 million.

The CSG potential is in the Betts Creek beds (Permian) with coal intervals up to 35 m (115 ft) net. In drilling the basin, “we go all the way through the Eromanga. We get into the top of the Galilee and keep going until we hit what is called the Betts Creek beds. We then enter what is called the Aramac coal measure or the early Permian sequence. In our tenement depths range from 900 m to 1,400 m [2,970 ft to 4,620 ft],” Haworth continued.

The company is tapping into different seams to learn about those formations. The Glenaras anticline is a “sweet spot” with good to moderate permeability from natural coal fractures. “Part of the Glenaras pilot project is to see the interconnectivity between the wells. We wish to demonstrate gas flow,” he added.

The company was using a UDL1200 trailer-mounted drilling rig. Simon Brodie, CFO, Galilee, said, “We’re a long way inland with no real infrastructure to support us. The planning and organizing of a drilling campaign [and] management of water treatment is a skill base of itself, which has to develop and is developing. We still struggle to get the people with the equipment that is reliable.”

Exoma Energy has a different strategy for working in the basin. “For a junior [company] we are quite unusual in our strategy,” said Rob Crook, CEO, Exoma. “We’re in the Galilee basin doing solely exploration at the moment. We have a JV partnership with the gas and energy division of China National Offshore Oil Corp. [CNOOC]. It is a frontier basin. CNOOC has funded two years of pretty extensive exploration.

“In two years we’ve drilled 19 wells, mostly CSG wells. The Galilee basin has been explored for conventional oil for 40 some odd years. That has given us some seismic and stratigraphic hole information, but none of those were looking for CSG or shale plays,” he said. “It is fair to say CSG has not been successful. Coals in the Galilee basin are unstaturated with very low gas content.

“We’re in the process with our JV partner to work out whether to continue to identify sweet spots that are favorably endowed geologically. For CNOOC it might make perfect sense to throw a lot of money at it. For a small company that is probably too risky. We’re also looking at shales. The Toolebuc overlays the CSG, and it is a highly organic shale. We’ve done a lot of geochemical work in the US, and obviously the US demand for shale laboratory work displaces us. We’re back down the queue a little bit,” Crook continued.

“The Toolebuc is at the oil window. In some places we’re getting generation and then expulsion. We’re waiting for data. We’ve drilled 11 shale core wells. We have cuttings from a further seven wells. We’ve got 18 datapoints. That’s a work in progress, but I suspect it is going to give us a direction in which to go. We have recovered oil in the core barrel from one of them,” he added.