The Cooper Basin in South Australia and Queensland and the Surat/Bowen Basin in Queensland are seeing unprecedented levels of spending to develop conventional and unconventional oil and gas resources and coal seam gas (CSG), respectively. Export markets for LNG from three plants under construction on Curtis Island near Gladstone, Queensland, are driving domestic gas prices higher, which boosts the drilling and completion of more wells in these basins.

In turn, areas of great gas potential such as the Canning, McArthur, Meerenie/Amadeus and Perth basins benefit from both the higher prices and greater interest from major oil companies such as Statoil, ConocoPhillips, Hess and Chevron.  

“Cooper Basin unconventional gas is no doubt a massive opportunity, whether it is value, production or resource size,” said Ian Davies, Senex managing director and CEO, at the DUG Australia conference in Brisbane Aug. 27. “But it is high-risk. What do we do with that being a smaller company? The oil business is absolutely fantastic for marginal cash flow. It will be a mainstay of the business going forward. Gas, however, is the key to a long-term, stable business, albeit low-margin, high cash flow and much more longevity.”

The goal for every operator in eastern Australia is to be commercial. Many companies focus on areas where there is already infrastructure to get natural gas to markets. Strike Energy, for example, concentrates on areas in the Cooper Basin under the Moomba-to-Adelaide pipeline.

“For any molecule we can get to the surface and produce, we’ve got a market for it and the infrastructure to get it to market,” David Wrench, Strike CEO, explained during the conference.

Barry Goldstein, executive director, Energy Resources Division, Department of State Development, South Australia, also speaking at the conference, emphasized that there are four hydraulic stimulation crews in the Cooper Basin in South Australia. An estimated $3.5 billion is expected to be spent over the next five years in South Australia.

Infrastructure in other areas of the country such as the Northern Territory and Western Australia remains the biggest challenge, driving up especially the logistics cost for drilling and completing wells. Even if a well is commercial, there are not always nearby markets where natural gas can be easily delivered.

That hasn’t dampened the enthusiasm for shale plays, CSG and tight sands in Australia. The momentum to develop unconventional gas reserves is building.

Senex targets conventional, unconventional plays

The Cooper Basin is a major asset portfolio for Senex. The company is spending a lot of time, money and effort to understand every part of the basin from conventional oil and gas to unconventional oil and gas.

In fiscal year (FY) 2015, the company’s 2P reserves were at 41.6 MMboe. Its target for FY2018 is 100 MMboe to 150 MMboe. Oil and gas production in FY2015 was 1.4 MMboe, with a target of 3 MMboe to 5 MMboe in FY2018.

Its growth assets include Cooper Basin unconventional gas, Cooper Basin conventional oil and gas, Cooper Basin tight gas, Surat Basin CSG, the Hornet Tight Gas project and Cooper Basin conventional oil E&P.

For its gas acreage, the company has four principal play types—conventional structural and stratigraphic traps, unconventional gas in shale or coal seams, and tight gas. The Cooper Basin features conventional and unconventional gas and tight gas, while the Surat Basin has CSG.

The Cooper Basin was considered a “dead” basin only five years ago. “We have been successful at finding new conventional oil discoveries. Tens and tens of millions of barrels of oil have been discovered in the last five years. In our conventional oil portfolio, we have a long way to go. It is our core business. We are drilling 16 wells this financial year based on new 3-D seismic. With some success, that grows exponentially,” he continued.

Davies said the company also needs to be successful in finding conventional gas. That consists of shooting new 3-D seismic, using new ways of interpreting that seismic and drilling both structural and stratigraphic natural gas discoveries.

In the Surat Basin, Senex is “working with our partners to try to do appraisals, get pilots up and running and create value from those assets,” he added. “We’re focused on monetizing that position. Surat Basin has 157 Bcf [4.4 Bcm] of 2P reserves.”

Hornet is a tight gas discovery in the South Australia Cooper Basin. The company is currently involved in appraisal drilling on the field. “We’re flow-testing in about a month’s time [late September]. We’ve hooked up to the [South Australia Cooper Basin joint venture], which is a Santos-operated system. We’ve got a gas sales agreement with them for early production,” Davies said.

The company will be doing appraisal of the Hornet discovery and is considering an exploration program in the area to find more gas. The field is being hooked up to the pipeline system and will begin production this year.

For its gas projects, Senex is targeting true unconventional gas—basin-centered shales and deep coals that have not been produced in commercial quantities in the Cooper Basin. “It is all there. It is a massive opportunity for us and all the players in the basin,” he said.

“Unconventional gas is a whole new adventure. We’re conducting 3-D seismic in the next six months and will be drilling on that 3-D seismic in other areas of the basin-centered gas for stratigraphic conventional gas plays in the Patchawarra Trough and the Allunga Trough in the southern Cooper six months after that. It is all rather imminent,” he explained.

The company also is focused on one conventional gas field in the northern part of the Cooper Basin. The Vanessa Field was discovered in 2007. “It is an existing discovery very near a whole heap of other discoveries,” he added. “It produced about 4 MMscf/d to 5 MMscf/d [113 Mscm/d to 142 Mscm/d], and it is wet gas. It produced around 120 bbl/d to 140 bbl/d of condensate. There are many more of these things around that we are going after through 3-D seismic and drilling.”

With about 40% of the acreage in the Cooper Basin, Senex is in position to develop all of its assets. How does the company do that? “You’ve got to put in the effort, put aside the capex, and incentivize the staff and hold them accountable for it in each and every play type. Otherwise it never gets done. What you don’t incentivize your staff to do, you’re not generally going to get a fantastic result,” he continued.

Tapping deep coal measures

Strike Energy has been active in the Eagle Ford and Permian Basin in the U.S. “While what we’re doing in the Cooper Basin geologically is completely different from the U.S., the approach is very similar. We’ve been able to benefit from seeing firsthand how the U.S. industry is doing it,” Wrench said at DUG Australia.

In the Cooper Basin, the company has a number of permits—PEL 94, PEL 95, PEL 96 and CO2013-B—predominantly around the southern flank of the basin. Strike has a project focused on a large gas resource with about 127.4 Bcm (4.5 Tcf) of gas resource net to the company.

“We’re focused in particular on a series of very big coal measures that were discovered over the last few years. We’ve just completed a completion and testing program on these coals. Contrary to our beliefs going into this that we would have a very low permeability system, we actually have a high permeability system. We are planning to continue testing these coals commencing in the next four or five weeks,” he explained.

The company is moving toward reserve certification as quickly as possible on the path to commercialization. Strike is targeting commercial production in 2017.

The blocks cover about 1.7 million acres. Currently the company is focused around three wells—Klebb 1, Le Chiffre 1 and Davenport 1—that are located about 40 km (25 miles) apart. In each of these wells is a series of coal seams that are consistent over the distances between the wells with 65 m (223 ft) of net coal at depths of 1,900 m to 2,000 m (6,232 ft to 6,560 ft).

“We’ve mapped these coals over incredible distances, and they are very, very thick. The seams are Patchawarra coals. There are two main seams—Vm3 and Vu. The Vu seam splits into upper and lower plays,” Wrench said.

Over the past few months Strike has conducted hydraulic stimulation and short-term flow testing. The results were surprising. “We had been expecting permeabilities in the 0.1 mD range for the coals at these depths. We’re seeing permeabilities at the Le Chiffre well at 20 mD to 25 mD. We started getting fluid back at a rate of 5,000 bbl/d as we turned the well back. We got quite an entirely different system than we were expecting,” he explained.

In the Klebb well, the company downsized the scale of the stimulation that was pumped into the upper coal. “We pumped a frack about 10% of the size of the frack that was pumped in the same zone in the Le Chiffre well. This well produced at high rates as well even though we pumped a much, much smaller frack stimulation job,” he said.
The same result occurred in the Davenport well. “What we saw across all these coals were very, very similar reservoir properties. The foundations of this play are pretty clear. We have a very large resource with very low-cost completion potential,” he continued.

Saturation in the coal seams is close to 40% to 50%. EURs are in the 113 MMcm to 170 MMcm (4 Bcf to 6 Bcf) range. “We’re about to go back into the field and start pumping. We did not have the capacity at the surface to deal with the volumes of fluid that we were recovering,” Wrench said.

“Our objective is to achieve sustained gas flows to the surface. We also want to understand water management. We have formation water in the system, and we have to understand what the volumes and rates over time will be,” he added.

The company will go back to the Le Chiffre well and drill offsets, which will be about economics and optimization of the field at that point.

“We are moving to reserve delineation and certification through 2015. We are at the proof-of-concept stage. The next step on that track is understanding the production mechanism of this play. The next step after that is reserve delineation. We are starting to work on the design of surface facilities, capital and opex estimates, and regulatory and environmental approvals,” Wrench continued.

“In 2017 we see a shortfall of gas as all of the LNG trains reach capacity. We see a key time in the marketplace for gas supply. We have signed offtake agreements with a number of industrial customers. As we reach certain milestones, those customers will start making prepayments. Access to capital is key for small companies,” he emphasized.

Small-cap company remains player

Ray James, managing director of Icon Energy Ltd., said the company holds a 35.1% interest in ATP 855 in southwestern Queensland, which covers 414,000 gross acres. Beach Energy Ltd. is the operator and Chevron is the other owner. Chevron can farm in as operator following completion of a second exploration and development phase.

Six unconventional wells have been drilled to date, targeting a Permian-age play. All of the wells had “significant” gas shows, which are a long way from commercial production. The Permian in the Cooper is an HP/HT formation that will require more work to crack the code for commerciality.

Having Chevron, with its extensive research and development capabilities, as a partner is proving to be a valuable asset, he added.

While most operators in eastern Australia are counting on the LNG export market, Icon is focused on rapid growth in the domestic market. The region’s gas demand is expected to triple between 2012 and 2016, he explained.

Santos touts collaboration

To attain commercial development of unconventional resources in Australia, the industry needs to collaborate to avoid repeating mistakes, said Colin Cruickshank, general manager, unconventional resources and exploration for Santos, at the conference.

“We don’t collaborate as well as our North American counterparts,” he explained. With drilling costs in Australia higher than those in North America, operators need to make maximum use of predrilling data, including seismic, drilling cores and other sources and share what they know without delving into proprietary data.

Useful collaboration will help the industry “crack the code” to make that vast potential commercially successful. That will require getting drilling and completion costs down. Support from drilling contractors and other service firms is improving, which is increasing competition and lowering costs, he said.

Santos has three unconventional targets in Australia—the Cooper Basin, McArthur Basin and Mereenie/Amadeus Basin. Santos has been working in the Cooper Basin since the 1960s. Its unconventional plays include tight shales and deep coal seams below 2,500 m (8,200 ft).

The McArthur Basin in the Northern Territory has liquids-rich gas prospects. The Mereenie/Amadeus Basin is in the southern Northern Territory and offers attractive gas-bearing shales, he continued.

He pointed out that the McArthur Basin has some of the oldest hydrocarbon-bearing rock in the world, more than 1 billion years old, rarely found elsewhere but productive in some locations. The Cooper Basin in South Australia and Queensland holds unusual Lacustrine shales that differ from the more typical marine-based shale formations found in North America.

Source:  EP