Skip to content

To report a serious incident to DSD, as required by Section 85(2) of the Petroleum and Geothermal Energy Act 2000, licensees should phone the serious incident report no: (08) 8463 6666.

Significant potential exists in South Australia's Basins as exploration of new plays is at a relatively early stage.

On this page

Introduction

The Society of Petroleum Engineers (SPE1), American Association of Petroleum Geologists (AAPG2), Society of Exploration Geophysicists (SEG3), World Petroleum Council (WPC); and Society of Petroleum Evaluation Engineers (SPEE) have worked over many years to standardise the definitions of petroleum resources and how they are estimated, culminating in the jointly developed Petroleum Resources Management System in 2007 (SPE-PRMS). The definitions and guidelines in the SPE-PRMS are designed to provide a common reference for the international petroleum industry. The new Australian Security Exchange (ASX) reporting rules effective from 1 December 2013 are generally consistent with SPE-PRMS or provide additional clarification. The Glossary of Terms Used in Resources Evaluations included as Appendix A in the SPE-PRMS has therefore been adopted here, with minimal alteration.

Unconventional resources are defined in the SPE-PRMS as follows:
“Unconventional resources exist in petroleum accumulations that are pervasive throughout a large area and that are not significantly affected by hydrodynamic influences (also called “continuous-type deposits”).

Examples include coal seam gas (CSG4), basin-centred gas, shale gas, gas hydrate, natural bitumen (tar sands), and oil shale deposits. Typically, such accumulations require specialised extraction technology (e.g. dewatering of CBM, massive fracturing programmes for shale gas, steam and/or solvents to mobilise bitumen for in-situ recovery, and, in some cases, mining activities). Moreover, the extracted petroleum may require significant processing prior to sale (e.g. bitumen upgraders).”

The relationship of unconventional to conventional resources is illustrated by a resource triangle (Fig.1), modified from the figure published by Chan (20115). Unconventional gas resources are shown down the right side of the triangle. Coal gasification has been added to the base of the triangle as suitable coals can be converted to synthesis gas (‘syngas’) either underground (in-situ) or through mining and surface processing. Synthesis gas can then be further processed to manufacture high value synthetic diesel (liquid synfuel) and fertilizer. Oil shale and coal gasification resources differ from the other unconventional gas resources in that the enhancement of host rock reservoir quality through either de-pressurisation (as for shallow Coal Seam Gas, CSG) or hydraulic fracture stimulation (as for shale gas, shale oil and CSG) is not the key to yield significant volumes of synthesis gas. Rather, thermal energy is the key to creating synthesis gas from oil shale and coal gasification.

Very large volumes of petroleum exist in unconventional reservoirs, but their commercial recovery often requires a combination of improved technology and higher product prices.

Definitions

The basic characteristics of each of the unconventional gas resource categories, with the exception of gas hydrates, are summarised in Figure 2. Unconventional gas resources have been divided into two broad types – those in which gas has been generated by natural thermogenic and/or biogenic processes6, and those in which gas (synthesis gas) is synthetically generated underground or in a surface plant with a thermo-chemical process.

A more detailed description of the unconventional gas resource categories, including Shale Gas, Tight Gas, Coal Seam Gas and Coal Gasification is included in Chapter 1 of the Roadmap for Unconventional Gas Projects in South Australia.


1The SPE is the peak international professional representative body for petroleum engineers. The SPE has a very active local branch in South Australia.

2The AAPG is the peak international professional representative body for petroleum geologists The Petroleum Exploration Society of Australia (PESA) is the AAPG’s local affiliate. PESA has a very active local branch in South Australia.

3The SEG is the peak international professional representative body for exploration geophysicists. The Australian Society of Exploration Geophysicists (ASEG) is the SEG’s local affiliate. The ASEG has a very active local branch in South Australia.

4 CBM is synonymous with Coal Seam Methane (CSM) and Coal Seam Gas (CSG). CSG is the more widely used term in Australia.

5 Chan, P., Unconventional Resources Estimation – Introduction, Chapter 8 in Guidelines for the Application of the Petroleum Resources Management System, November 2011. Download from: http://www.spe.org/notes/wp- content/uploads/2010/12/ADS_Final.pdf

6 Biogenic gas is formed at shallow depths and low temperatures by anaerobic microbial decomposition of sedimentary organic matter. In contrast, thermogenic gas is formed at deeper depths by: (1) thermal cracking of sedimentary organic matter into hydrocarbon liquids and gas (this gas is co-genetic with oil, and is called "primary" thermogenic gas), and (2) thermal cracking of oil at high temperatures into gas ("secondary" thermogenic gas) and pyrobitumen. Biogenic gas is very dry (i.e. it consists almost entirely of methane). In contrast, thermogenic gas can be dry, or can contain significant concentrations of "wet gas" components (ethane, propane, butanes) and condensate (C5+ hydrocarbons). These definitions come from a subsidiary of Weatherford.


A range of potential resource plays exist in South Australian basins, including shale gas, shale oil, tight gas and gas from coal, via deep coal seam gas (CSG), in situ gasification and surface syngas processes on mined coal. Exploration of these new plays is at a relatively early stage, however significant potential exists and research by explorers, the University of Adelaide and the Department of State Development to understand and evaluate new plays is progressing.  Commercial recovery of gas from unconventional reservoirs requires detailed understanding of reservoir and regional geology, new fracture stimulation technologies and reservoir engineering.

Natural gas trapped in deep unconventional reservoirs (shale, siltstone, tight sandstone and coal) is a new focus for exploration in the SA Cooper Basin, spurred on by emerging export markets for gas as Liquefied Natural Gas (LNG). Cooper Basin gas explorers have been encouraged with results from the first 31 vertical and 4 horizontal wells drilled to target natural gas in deep unconventional reservoirs since 2010.

2013 was an active year with 13 wells drilled to assess gas in unconventional reservoirs in the SA Cooper Basin.  Activity tapered in 2014-15 as explorers assessed and analysed drilling and fracture stimulation results. The most active companies exploring for gas in deep unconventional reservoirs in the Cooper Basin are Santos Limited, Beach Energy, Origin Energy, Senex Energy and Strike Energy (with financial backing from Orica Limited). Chevron announced its withdrawal from the Beach Joint Venture in March 2015.

At this early stage, the South Australian Cooper Basin Joint Venture (operated by Santos) and Beach Energy have established contingent gas resources in unconventional reservoirs totalling 4.6 TCF  (trillion cubic feet) in the SA Cooper Basin.  Contingent resources are potentially recoverable but not (yet) considered commercial due to a lack of gas marketing arrangements, and/or to technical, environmental or political barriers.  This compares to the ~5.2 TCF sales gas produced from the SA Cooper Basin since 1970.  However unconventional gas exploration has only just begun and undiscovered resource estimates are much higher.  Beach has stated there is potential for at least 15 to 20 TCF recoverable gas in PEL 218. Santos estimates for the SACB JV licences range from a low of 22 TCF to a high of 187 TCF of raw recoverable gas.

In the SA Otway Basin in 2014 Beach Energy (operator) and Cooper Energy, drilled two deep gas exploration wells,  Jolly 1 and Bungaloo 1.  Beach reported encouraging results from the wells and that they have identified both deep conventional, as well as unconventional targets.

Linc Energy has been exploring in situ gasification of coal in the Walloway Basin, and for CSG and shale oil in the Arckaringa Basin.

There has been no exploration drilling for unconventional plays in other frontier basins in the State as yet, although prospective shale units are present in the State’s Neoproterozoic-Cambrian basins and prospective coals and shales exist in the Simpson and Pedirka basins.

The geologic attributes and potential extent of unconventional gas plays in the Cooper, Arckaringa, Otway, Gambier, Pedirka, Warburton and Officer basins are described in Chapter 2of the "Roadmap for Unconventional Gas Projects in South Australia".

204218-060
Shale gas plays – Cooper Basin (PDF)
204218-082
Geological cross section,
Nappamerri Trough showing
elevated resisitivities (from Hillis
et al, 2001) (PDF)
204218-083
Evidence for overpressured
compartments in the Nappamerri Trough
(from Hillis et al, 2001) (PDF)
   
204218-045
Coal isopach maps
(a) Patchawarra Fm (PDF)
204218-046
Coal isopach maps
(b) Toolachee Fm (PDF)
 204218-110
Base Patchawarra Formation
Maturity Map (PDF)

Shale Gas (REM) Play

The principal shale gas play is the Roseneath - Epsilon - Murteree (REM) play comprising Early Permian
Murteree and Roseneath shales divided by tight sands of the Epsilon Formation. Cooper Basin shale gas play fairways are defined by the Murteree Shale exceeding 20m thickness, with a total Patchawarra TOC >2% and  the base of the Murteree Shale structure >-2900m.

Moomba 191 on the Moomba North structure has recently been fracture stimulated and flowed gas at 2.7 mmcf/d from shales in the REM section. Moomba 191 is Australia’s first commercial shale gas well.

Beach Energy has publicly discussed the mineral composition of the shales which are high in silica and illite with moderate siderite and absence of swelling clays which collectively are conducive to brittleness and ideal for fracture stimulation.

Well data suggests lower porosity than US shales and highlights requirement for thicker and overpressured shale sections to commercialise the resource.

Basin Centred Gas (BCG) Play (Shale, siltstone, tight sandstone)

The presence of a basin centred gas accumulation (BCGA) in the Nappamerri Trough has been suspected for many years.  Resistivity of the Permian succession exceeds 20Ωm over large intervals (Figure 2), tests have recovered gas with no water, and gas is located within overpressured compartments indicative of hydraulic isolation (Figure 3). The Santos operated Cooper Basin Joint Venture is actively reviewing tight gas associated with conventional trapping mechanisms in Permian strata throughout the basin.  The JV is investigating well spacing, pad drilling, multi-stage fracture stimulation and microseismic monitoring to improve commerciality of the resource and increase recovery factors.

The Permian succession in the Nappamerri Trough easily exceeds 1000m in the deeper parts, comprising very thermally mature, gas-prone source rocks with interbedded sands, ideal for the creation of a basin-centred gas accumulation.  Excluding the Murteree and Roseneath shales, the succession comprises up to 45 percent carbonaceous and silty shales and thin coals deposited in flood plain, lacustrine and coal swamp environments. Thick siltstones of the Nappamerri Group may have been a regional top seal for the pervasive gas accumulation, and the Roseneath and Murteree shales will also have assisted gas containment. Generation and expulsion of hydrocarbons from the Cooper Basin source rocks occurred in the mid Cretaceous, but overpressure has been retained in the Nappamerri Trough (Figure 3). Pressure data from a number of wells  indicates that areas where the base of the Patcahwarra Formation exceeds 2900 m depth are prone to overpressureed reservoirs.

The Early Permian succession in the Patchawarra Trough also has the necessary elements for basin centre gas accumulations (BCGA)  e.g. gas-prone coal beds, sufficient maturity for thermal gas generation, low porosity and permeability reservoirs interbedded with the source rocks and gas shows.  At Wimma 1, in the deepest, most mature part of the Patchawarra Trough, overpressured gas sandstones with poor reservoir properties were encountered in the Early Permian succession.

The Wooloo and Allunga  troughs also contain the known elements for  BCGA, in areas below -2900m (and where  >30m of Nappamerri Formation exists to act as a seal),  although there is no direct evidence of overpressured reservoirs in this area.

Permian Source Rock Play

The Gidgealpa Group is characterised by coal measures, especially in the Patchawarra, Epsilon and Toolachee formations.  Thick, laterally extensive coal seams have been intersected in both the Patchawarra and  Toolachee Formations. (Figure 4a and 4b).

The base Patchawarra Formation maturity map shows that the Patchawarra Formation is sufficiently mature for the generation of gas from coal seams over much of the basin (Figure 5). Using a cutoff of >25m of cumulative coal thickness, and Ro at the base of the Patchawarra less than 2, a least 3 separate sub play areas in the SA portion of the Cooper Basin can be defined (Patchawarra, Wooloo-Allunga and Tenaperra troughs).

The coals are expected to be gas saturated, so de-watering will not be necessary.

The first flow of gas to surface at 100,000 scf/day was from a fracture stimulated Patchawarra Formation coal in Moomba 77 gas development well. Gas desorption analysis of the VC50 coal seam cored in Bindah 3 returned excellent total raw gas results averaging 21.2 standard cubic centimetre per gram2over 10 metres. Elsewhere this may range up to 900 scf/ton.  Whilst the carbon dioxide (CO2) content of the desorbed gas was high, CO2 levels around the Basin are highly variable and lower CO2 contents (and or higher liquids content, eg. Tirrawarra South 1) are expected in other parts of the Basin and may be related to individual coal genesis.

Recent drilling in the Milpera and Weena Troughs has extended the area of known thick coal development in the Cooper Basin, and indications of thermal gas generation will require reworking of thermal maturity maps. Davenport 1 encountered over 110 m of net coal with elevated gas readings, including a 45 m thick Patchawarra coal, the thickest known coal in the Cooper Basin. Net coal thickness is greatest in the southwest corner of the basin with potentially nearly 200 m being present near the Klebb wells in the Weena Trough.

Thick, laterally extensive coal seams are also characteristic of the Toolachee Formation (Figure 4b).  The Toolachee coals are sufficiently mature for thermogenic gas generation in the Nappamerri and Arrabury troughs, and parts of the Patchawarra Trough.

Patchawarra Source Rock (Coaly Shales) Play

Source rock and generation modelling has shown that parts of the Patchawarra Formation have large volumes of liquids that appear to have been generated (some of which has migrated into conventional oil reservoirs (eg Tirrawarra oil field), and some of those areas have retained that generated oil, thus creating an attractive liquids rich unconventional play that is relatively untested.

Deep Coal Seam Gas Play

This play is restricted to the Weena trough, where very large thicknesses of coal are found in the Patchawarra Formation and maturities are less than Ro 0.75 at the base of the Patchawarra. Several wells are currently on long term production test

Shale has such low matrix permeability that it releases gas very slowly and this is why shale is the last major source of natural gas to be developed.  However the upside is that shales can store an enormous amount of natural gas.  Shale is a fissile, very fine grained sedimentary rock comprising clay minerals, very fine grained sand (quartz, feldspar or carbonate) and may contain organic material (kerogen = hydrocarbon source).  Shale has been regarded as an impermeable seal (cap rock) for more porous and permeable sandstone and carbonate hydrocarbon reservoirs.  However, in a shale gas play, it forms both the source rock and a low permeability reservoir.  Shale gas plays are not dependent on structural closure, hence can extend over large areas – the challenge is to find sweet spots that will produce commercially.  The necessary elements for a shale gas play are (Curtis, 2009):

*  laterally extensive, realtively undeformed shale
*  thickness >30m
*  total organic carbon content >3%
*  thermal maturity in gas window (VR = 1.1 to 1.4)
*  good gas content >100scf/ton
*  moderate clay content <40%
*  brittle composition

In gas shales, the gas is generated in place and the shale is both the source rock and the reservoir. The gas can be stored as free gas within pore spaces in both the inorganic sediment component and the organic carbon component of the rock, as free gas in fractures, and as gas adsorbed to the surface of organic components (kerogen).  In-situ generation and storage of hydrocarbons results in volume and pressure changes, and some overpressure is therefore characteristic of gas shales. Shale gas is produced from continuous gas accumulations that are regionally extensive, lack an obvious seal and trap, and have no defined gas-water contact.

As shale matrix permeabilities are very low, operators generally seek to maximise the shale surface area exposed to production. This is achieved by “gas farming” whereby multiple horizontal wells are drilled perpendicular to the direction of maximum horizontal stress and stimulated with multiple hydraulic fracture stages to access the largest volume of reservoir and to intersect the maximum number of (typically) sub-vertical fractures. Microseismic monitoring can be used to identify fracture points in the reservoir during fraccing, to optimally orient follow up drilling, again as per geothermal reservoir stimulation. Natural fractures are beneficial, but usually don’t provide permeability pathways sufficient to support commercial production.  Larger scale faults are generally identified using 3D seismic and avoided as these complicate horizontal drilling (if the target shale bed is offset), inhibit hydraulic fracturing and can be water conduits.

The gas in natural (or induced) fractures, or gas which has migrated into thin sandstone interbeds is produced first. After the initial flush, gas production declines exponentially. Production rates typically flatten out after 3-4 years, as the adsorbed gas is slowly produced and can continue at relatively low rates for decades. Ultimate recoveries are much lower than for conventional gas fields, but completion and production technology advances are increasing recovery factors. Many US shale gas splays are ‘dry’ and water is not produced with the gas. Water is a problem as it will dissolve adsorbed gas which may be lost to the shale reservoir.

In the US, exploration and development of shale gas plays has accelerated over the past decade, and shale gas now provides in excess of 2 TCF gas per annum to the US domestic gas market. It is estimated that shale gas production will overtake coal seam gas production by 2025 (US Energy Information Administration) aided by improvements in exploration, completion and production technologies; gas price increases and emerging plays. No commercial shale-gas projects currently exist outside of the US, exploration is most advanced in Canada and Europe.

In Australia, explorers are in the early stages of identifying shale gas play fairways within prospective basins, and much of the basic data required to assess prospectivity has not yet been acquired.

The term “tight gas sands” refers to low permeability sandstone reservoirs that produce primarily dry natural gas. A tight gas reservoir is one that cannot be produced at economic flow rates or recover economic volumes of gas unless the well is stimulated by a large hydraulic fracture treatment and/or produced using horizontal wellbores (Holditch, 2006). Tight gas includes basin-centred gas systems, defined by Law (2002) as low-permeability, gas-saturated reservoirs that are abnormally pressured, regionally pervasive, and lack down-dip water contacts.

In the United States tight sands produce about 6 trillion cubic feet (TCF) of gas per year, which is 25% of the total gas produced(http://emd.aapg.org/technical_areas/tightGas.cfm). As of January, 2009, the U. S. Energy Information Administration (EIA) estimates that 310 TCF of technically recoverable tight gas exists within the U.S, representing over 17% of the total recoverable gas.

Cooper Basin – Pervasive Tight Gas Accumulation
The presence of a Basin Centred Gas Accumulation (BCGA) in the Nappamerri Trough has been suspected for over two decades. Beach Energy has stated that the Encounter and Holdfast wells confirm the presence of gas in sands outside of structural closure and estimate that gas in place potentially exceeds 200 Tcf in sands across PEL 218.

Cooper Basin – Discrete Tight Gas Accumulations
In the Cooper Basin gas reserves are at commercial rather than technical recovery limits and explorers recognise significant upside reserve potential from unconventional sources. These unconventional sources include Early Permian Patchawarra Formation tight gas sands in the Moomba and Big Lake fields on the southern end of the Nappamerri Trough. Tight gas is the most mature unconventional play in the Cooper Basin. The Santos JV has been exploring the Nappamerri Trough since the mid 1990s and has utilised a range of drilling, development and production technologies to extract tight gas from its existing Cooper Basin fields. Tight gas sands have also been intersected at Wimma 1 in the centre of the Patchawarra Trough.

Coal measures in South Australia are primarily of Permian, Triassic, Jurassic and Tertiary age (South Australia Department of Mines and Energy, 1987). Almost all known deposits have been evaluated for coal extraction potential, but not for coal seam gas potential (CSG). The depth and maturity of the coal deposits and distance to infrastructure and markets have prevented economic exploitation of all except the Leigh Creek Coalfield.

The success of the coal seam gas (CSG) industry in the US and now eastern Australia, and improvements in the economic feasibility of coal gasification have re-focused attention on the South Australian coal deposits. Assessment of the CSG and/or coal gasification potential of some deposits has commenced. A bankable feasibility study is currently underway for mining part of the Wintinna coal deposits in the Arckaringa Basin (10Mt pa base case), supplying coal to coal-to-liquids plant with an output of 10 MMbbls per annum liquid fuels (mainly ultra clean diesel) as well as co-generation power plant delivering 560 MW per annum to the national power grid. In addition a Technical Feasibility Study for Coal to Methanol (CTM) plant based on the Arckaringa coal resources was completed in 2013. The Kingston lignite deposit in the south east of South Australia was assessed for use as a gasification plant feedstock, but surrendered the licence in 2014 after a review of their portfolio.

For more information on coal gasification projects see Chapter 4.2 of the "Roadmap for Conventional Gas Projects in South Australia".

Coal seam gas formation

During coalification, large quantities of methane are generated. This gas is adsorbed onto the coal surface in cleats and pores, and is held in place by reservoir and water pressure. Coal rank, reservoir pressure (related in part to depth) and temperature are important factors controlling the amount of methane held in a coal seam.
For more information on coal seam gas formation see Chapter 1.2.5 of the "Roadmap for Unconventional Gas Projects in South Australia".

The South Australian coals at potentially exploitable depths for CSG (generally between 100–1500 m; Poynton and Simon, 2001) have maturities significantly <0.8% Ro which is the approximate threshold needed for economically significant thermogenic methane production (200–300 scf/t in Scott, 2002). As such all South Australian CSG prospects may need a contribution from a biogenic methane source similar to the Powder River Basin (SanFilipo, 2000) to have economic gas contents.

Coal geology

Extensive and thick Permian coal measures occur in the intracratonic Arckaringa, Pedirka and Cooper basins. These deposits are similar in age to proven eastern Australian CSG producing basins (i.e. Bowen and Surat basins). Coals in the Cooper Basin are a proven source of conventional oil and gas and occur at depths from 2000–3500 m (bituminous to anthracite rank). The Early Permian Patchawarra Formation contains a major coal seam up to 30 m thick and this forms an important seismic reflector in the Cooper Basin. Coals in the Pedirka and Arckaringa basins are shallower and less mature for oil and gas generation (sub-bituminous) than Cooper Basin coals.

Triassic coal measures are intracratonic remnants of broader deposystems and was mined at Leigh Creek. This Triassic coal is sub-bituminous in rank, and was mined at the margins of the Telford Basin, but extends to depths in excess of 1000 m in the basin centre. Jurassic coal measures form a deposit at Lock in the Polda Basin. Jurassic coals also occur in the deeper parts of the Eromanga Basin in the Poolowanna and Birkhead formations. Cretaceous coal measures are known from the Otway Basin (e.g. Eumeralla Formation) and Eromanga Basin (Winton Formation); the latter is a potential exploration target for CSG. South Australia also has significant deposits of very low-grade lignite found in shallow Tertiary basins

Cooper Basin
The Weena Trough in the southern Cooper Basin contains the shallowest occurrences of thick Patchawarra Formation sub-bituminous coal seams (e.g. ~1500 m depth in Tinga Tingana 1 and Weena 1). Minor mud gas indications have been recorded while drilling through coal seams in Kumbarie 1, and the water chemistry in Tinga Tingana 1 suggests some methane is present (Nitschke, 2006). The Weena Trough is currently held by Strike Energy Limited (PEL 96). The company applied for the block in March 1999 as part of the CO98 acreage release, and the licence was granted in May 2009.

Higher rank, thick Permian coal seams in the deeper parts of the Cooper Basin are now being assessed as a source of deep coal gas.  In the US, the deepest CSG production is from 2500m in the Piceance Basin and 2000m is generally considered the floor for CSG production due to cleat closure and permeability reduction at these depths.  However the Cooper Basin coals are characterized by a high inertinite content. Inertinite is essentially non-reactive during the carbonization process, and the cellular structure of the component plant material is preserved. As a result these coals contain significant macro-porosity indication considerable free-gas storage potential, in addition to gas storage by adsorption.

A fracced deep Patchawarra Formation coal in the Moomba 77 vertical well flowed gas at 0.1 mmscf/d. More recently Senex Energy’s Paning 2 vertical exploration well in the northern Cooper Basin flowed gas from a fracture stimulated Toolachee coal seam at peak flows of up to 0.09 mmscf/d. Senex estimates that the dry Toolachee coal has 2.1 tcf of gas in place (>1 tcf 3C resource estimate) across the 9,000 acre Paning structure. Paning 2 intersected 70 metres of Permian coals with excellent gas contents of 25 cubic metres/tonne (~ 800 scf/ton) Given the very high gas content of the coals, the application of drilling technologies to maximize the surface area of coal exposed to production may significantly improve flow rates.

For more information on the deep coal seam gas potential of the Cooper Basin see Chapter 2.1.3 of the “Roadmap for Unconventional Gas Projects in South Australia”.

Pedirka Basin
The Pedirka Basin in South Australia comprises a shallow western depocentre and a deeper eastern depocentre. The Early Permian succession is thickest in the western depocentre (up to 1000m). Coal seams are present in the upper part of the Early Permian Purni Formation, a lateral equivalent of the Patchawarra Formation in the Cooper Basin.

For more information on the deep coal seam gas potential of the Pedirka Basin see Chapter 2.5.1 of the “Roadmap for Unconventional Gas Projects in South Australia”.

Arckaringa Basin
The sub-bituminous coals in the Arckaringa Basin have features (coal thickness, continuity and suitable depth) which make them appealing for CSG feasibility projects, although no significant gas shows were recorded by the two petroleum exploration wells in the basin drilled with mud gas detection equipment (Birribiana 1 and Weedina 1). Linc Energy owns and operates PELs in the basin which were initially granted to SAPEX in October 2006 after the successful negotiation of access agreements with native title claimants and the South Australian Government. Linc is exploring for conventional hydrocarbons, shale oil and CSG in the basin.

For more information on the geology of the Arckaringa Basin see Chapter 2.2 of the "Roadmap for Unconventional Gas Projects in South Australia".

Leigh Creek
There are five discrete basins in the area: North Field (Lobes D and C), Telford Basin (Lobe B), Copley Basin (Lobe A) and, the latest to be discovered, Lobe E.

Lobe B, the largest of the five basins, was mined around the margins, where the overburden is as thin as 10 m. However, the seams have a moderate dip (10–30º) and the depth to coal reaches up to 1000 m in the centre of the basin. The moisture content of the coal is quite high (33%), which may have a negative effect on the amount of gas that could be stored within the coal, but the other characteristics of the deeper sections of Lobe B have good potential for CSG.

Polda Basin
The Jurassic Lock and Mullaquana coal/oil shale deposits occur at mineable depths in the Polda Basin. Overburden ranges from 35 to 230 m but is generally between 50 and 130 m, which may be too shallow to store significant amounts of gas. The sub-bituminous coal has low levels of inertinite and higher levels of liptinite. This makes the composition of the coal very similar to the Walloon Coal Measures of Queensland, which are being successfully exploited for CSG (but typically at greater depths). The Polda Basin is currently under licence by Energy Exploration Limited with PELs 153 and 126.

Tertiary Coals
South Australia also has significant deposits of very low-grade lignite (<100 m deep) that occur in both intracratonic and structurally controlled basins located along Australia’s southern margin. In South Australia this includes the Gambier, Pirie-Torrens, St Vincent and Murray basins. Tertiary coal deposits that were evaluated for coal extraction for power generation in the 1980s include Bowmans, Lochiel and Clinton (St Vincent Basin), and Kingston, Sedan and Moorlands (Murray Basin). Mining some of these deposits for coal gasification projects is also currently being evaluated. Tertiary lignites are typically high in moisture, sulfur, sodium and chlorine and are overlain by unconsolidated Tertiary and surficial sediments. Although thick seams are developed in some deposits, all Tertiary coals are generally shallower than 100 m and this limits reservoir pressure and likely gas content.

Since all of the coal is very low-grade lignite, biogenic activity would be required to generate CSG. Hydrological conditions may provide the trapping and overpressure required to store economic amounts of biogenic gas in some of the coal seams, which have other appealing properties (thickness, continuity etc.).

Hydrocarbons can also be produced from in-situ or mined coal seams.

Underground Coal Gasification(UCG)/In-situ Gasification (ISG)

Underground coal gasification (UCG) also known as in-situ gasification (ISG) of coal takes place underground, generally below approximately 370 m. The underground setting provides both the coal feedstock source as well as pressures comparable to that in an above-ground gasifier, and at a depth less attractive for mining owing to the cost to remove cover.

With most UCG facilities, two wells are drilled on either side of an underground coal seam. One well is used to inject air or oxygen (and sometimes steam) into the coal seam to initiate the gasification reactions. The second well is used to collect the syngas that is formed from the gasification reactions and to transport it to the surface for additional processing and use.

The UCG reactions are managed by controlling the rate of oxygen or air that is injected into the coal seam through the injection well. The gasification process can be halted by stopping the injection of the oxygen or air. After the coal is converted to syngas in a particular location, the remaining cavity (which will contain the left over ash and other solid residue from the coal) may be flushed and then flooded with water and the wells are capped. However, there is also growing interest in using these cavities to store fluids/gases captured from the above-ground syngas processing. Once a particular section of a coal seam is exhausted, new wells are drilled to initiate the gasification reaction in a different section of the coal seam.

The syngas that is produced from UCG is the same as that produced by above-ground gasification processes—it can be combusted in a gas turbine to produce electricity or further processed to produce chemicals, ultra clean transport fuels, or fertilizers.

UCG does face a number of challenges including but not limited to:
- Coal seams may not be suitable for UCG because of composition, thickness, geologic complexities or hydrologic conditions;
- Decommissioning will most usually entail injection of gases and/or fluids to minimise potential hazards of subsidence, and the sustainable and economic availability of water to flush the reaction cavity can be a limiting factor;
- Pending experience in profitable UCG projects in the context of competitive Australian energy markets, UCG project economics are somewhat uncertain; and
- Site selection needs to be done properly to avoid potentially harmful short-term and long-term impacts including but
not limited to: groundwater desiccation; groundwater contamination; surface subsidence; permanent damage to local and regional biota; and the sterilisation of land access for the multiple-use of land for other activities.

These issues can be mitigated through careful project design, site selection, and monitoring. UCG has enormous potential for harnessing the energy of coal resources that would otherwise be too expensive or difficult to reach.

For more information on ISG see Chapter 1.2. of the "Roadmap for Unconventional Gas Projects in South Australia".

Mined Coal Gasification - Gas to Liquids

Mined coal can be gasified to create synthesis gas which is then converted to liquid hydrocarbons using the Fischer-Tropsch synthesis process. For more information see the Altona Energy website.

Permian coals
Extensive and thick Permian coal measures occur in the intracratonic Arckaringa, Pedirka and Cooper basins (figs 1 and 2). Coals in the Cooper Basin are a proven source of conventional oil and gas and occur at depths from 2000–3500 m (bituminous to anthracite rank). The Early Permian Patchawarra Formation contains a major coal seam up to 30 m thick and this forms an important seismic reflector in the Cooper Basin. Coals in the Pedirka and Arckaringa basins are shallower and less mature for oil and gas generation (sub-bituminous) than Cooper Basin coals.

In the Arckaringa Basin seven coal deposits of lignite A/sub-bituminous C rank coal (American Society for Testing and Materials classification) aggregating more than 20 Gt of measured, indicated and inferred resource have been identified in the upper part of the Early Permian Mt Toondina Formation. These are multi-seam deposits with individual seams ranging up to 10m, with a cumulative thickness of up to 35m.

The Arckaringa Basin coals are low rank and therefore are not sufficiently mature to have generated significant thermogenic gas volumes. These coals are likely to have low gas contents unless large volumes of biogenic gas have been generated and trapped. However the coal deposits are suitable for coal conversion processing.Altona Energy is undertaking a Bankable Feasibility Study (BFS) for an integrated Coal to Liquid (CTL) plant with a co-generation power facility. The company’s prefeasibility studies established a base case project comprising:
- An open cut mine at Wintinna producing 10 MTPA coal
- 10 MBPA liquid fuels (mainly ultra clean diesel)
- 1140 MW of power - 560 MW for delivery to the national grid