Agua subterránea

The UH industry in Australia is still in a very early stage of development, and the full extent of shale resource opportunities is far from being identified. According to a report published by the US EIA/ARI in 2013, Australia enjoys geologic and industry conditions resembling those of the US and Canada, putting the country in the position of starting commercially viable shale gas and shale oil production in the next few years.

In the ranking provided by EIA for shale gas resources, Australia is placed seventh of the 41 countries, following Mexico and ahead of South Africa. The six major Australian oil and gas basins³⁰ hold an estimated technically recoverable shale gas resource of 437 TCF and an estimated technically recoverable shale oil resource of 17.5 billion barrels. Western Australia alone is estimated to hold the fifth largest reserves of shale gas in the world (Norton Rose Fulbright, 2015), which potentially contain 280 TCF of shale and tight gas.

Of this, 235 TCF are in the Canning Basin (Kimberley and East Pilbara regions) and 45 trillion cubic feet are in the northern Perth basin (Midwest region) (Government of Western Australia, 2014).

Natural gas production in Australia has been increasing steadily for decades and, even though most of the production is derived from offshore conventional resources, coalbed methane (known as coal seam gas, CSG, in Australia) is commercially relevant.

Estimated recoverable reserves of CSG, however, are lower compared to estimated technically recoverable shale gas resources. A picture showing high potential shale basins in Australia is provided in Figure 38.

Figure 37. Assessed Prospective Shale Gas and Shale Oil Basins in Australia

Source: EIA/ARI, 2013; p.III-1

30The six major basins are: the Cooper Basin in South Australia and Queensland, the Maryborough Basin in Queensland, the Perth Basin and Canning Basin in Western Australia and the Georgina Basin and Beetaloo Basin

Estimates of Australian shale resources and their distribution are quite variable. For instance, according to the examination carried out by the Australian Council of Learned Academies (2013) on sixteen shale basins, the volume of potentially recoverable shale gas resources is much larger, corresponding to 1,416 TCF. Estimates of recoverable resources in shale basins included in the evaluation are provided by AERC (2015) and reported in Table 7.

Table 4.Australian shale gas resources by basin

Source: APERC, 2015; p.65

Several other basins in Australia have not been assessed yet and some remain substantially underexplored. This implies that the country has a huge potential for significant additional resources.

The Onshore Hydrocarbons Section at Geoscience Australia, in collaboration with state and territory geological surveys and energy departments, has started to assess the UH potential, both in basins with poor geological knowledge (most of the Australian basins) and in basins where there has already been significant exploration, such as the Cooper Basin, in order to provide a resource assessment on a basin by basin basis.

As far as CSG is considered, reserves have increased markedly from 2007 as drilling accelerated to prove up reserves for the liquefied natural gas (LNG) projects. In Queensland, the drilling activity is increased, and over the last three years, it has focused on development wells (Upstream Petroleum Resources, 2015). This implied a reduction in the number of exploration and appraisal wells, while the number of development wells have substantially increased (Figure 39).

Figure 38. Well drilling rates and cumulative CSG wells drilled

Source: UPR, 2015, p.11

Currently there are only very few wells targeted to shale gas formations drilled in the country. This is due not only to the need of improving the knowledge of resource potential, but also the lack of infrastructures, drilling services and land rigs capable of drilling deeply.

Since 2005, 15 exploration wells have been drilled to search for shale and tight gas resources in Western Australia. Seven of these involved hydraulic fracturing to test the capacity of the reservoir to generate commercial gas flows (Government of Western Australia, 2014). They have been approved by the Department of Mines and Petroleum (DMP), in consultation with the Environmental Protection Authority (EPA), with strict regulatory requirements to ensure they did not have any significant adverse impacts on the environment.

Specifically, the Canning basin, which is considered as having the greatest potential resources in the country (Upstream Petroleum Resources, 2015), has experienced a significant amount of activity in the latest years. Nevertheless, potential challenges to the commercial development in the basin can come from its remote location and lack of existing pipelines, access to roads and water sources. The Northern Perth Basin, on the contrary, is better placed compared to the Canning Basin, because of its close proximity to gas markets, pipeline infrastructure and the Perth city region. Initial results from geological exploration were favourable; in 2012, three shale gas wells were hydraulically fractured in the basin and three prospective formations were identified. It is then more likely that unconventional gas from this basin will reach market first. In the Perth Basin there are also the only tight gas fields currently progressed to the contingent stage of exploration (Government of Western Australia, 2014).

According to the Government of Western Australia, if the current exploration phase proves to be successful, significant commercial production is expected to be five to ten years away.

The greatest potential for commercial development of shale gas in Australia, however, is in the Cooper Basin, where the first two exploration wells were drilled in 2010 and the first, and so far only, commercial shale gas production started in 2012. The initial well flow rate ranged from 1.000 million cubic feet per day (mmcf/d) to 2.600 mmcf/d, in line

with the successful US shale development rates (UCL Australia, 2013). This development has been made possible by processing and transport infrastructure already in place, which allowed the vertical test well to be drilled near existing pipelines and a gas processing plant, even though paved access roads are still lacking.

The availability of existing infrastructure and pipeline network, following decades of conventional oil and gas production in the region, puts the Cooper Basin in a privileged position, as generally other basins do not have infrastructures enabling them to bring the plants online quickly. They will require substantial capital investments to develop the necessary infrastructures, especially remote areas in the north of Western Australia and in the Northern Territory.

A potential risk for commercial development in the Cooper Basins, however, is related to the lacustrine characteristic of the resources, and in particular, their higher clay contents compared to marine shales, which may create difficulties to hydraulic stimulation treatments (see also Section 5.2.3).

In the Northern Territory, the presence of petroleum sources has been identified during drilling and mineral exploration over many years. Some operating companies are actively investigating shale plays in the Beetaloo Sub-basin, where there is evidence of both unconventional and conventional hydrocarbons. The number of wells drilled for unconventional resource exploration passed from two in 2011 to twelve in 2014 (Upstream Petroleum Resources, 2015). At this stage, however, there is no production from unconventional gas resources in the Northern Territory and unconventional gas exploration is still at its early stage. Also in this case, production activities in the area could be made difficult due to basins location; the Beetaloo Sub-basin, for instance, is remote and with very limited access to pipelines and infrastructures.

Finally, the Southern Georgina Basin has proven oil potential and a great potential for very large conventional and unconventional gas deposits. Even though it is almost unexplored, some global energy companies have shown interest in the basin, targeting activities primarily towards oil mature source beds and dry gas mature rocks.

5.2 Development of the UH industry in Australia: driving factors