Maryborough Basin QLD Maryborough Formation Maryborough Formation (including the Goodwood and Cherwell mudstone members); Tiaro Coal Measures None No shale/ tight gas exploration activity. AWT International (2013); Blue Energy (2013); Jell (2013); DNMR (2017) McArthur Basin (including the Beetaloo NT Bessie Creek Sandstone; Moroak Sandstone; Reward Dolostone (fractured reservoir) Kyalla Formation; Velkerri Formation; ?Vaughn Siltstone; Yalco Formation; Lynott Formation; Barney Creek Formation ~35 wells targeting shale gas Early appraisal for shale gas ( 2C resources booked for the Velkerri Formation) Armour Energy (2017b); AWT International (2013); Munson (2014); Close et al. (2017); Scientific Inquiry into Hydraulic Fracturing in the Northern Territory (2018); Revie (2017a,b) Ngalia Basin NT Mount Eclipse Sandstone None No shale/ tight gas exploration activity. Munson (2014); Scientific Inquiry into Hydraulic Fracturing in the Northern Territory (2018) Oaklands Basin NSW ?Coorabin Coal Measures; ?Jerilderie sandstone ?Coorabin Coal Measures ; ?Urana Formation None No shale/ tight gas exploration activity. O’Neill and Danis (2013); UPR (2015, 2016); Resources and Energy, New South Wales (2017a) Otway Basin SA, VIC Eumeralla Formation Crayfish Sub-group; Casterton Formation 3 wells targeting tight gas Exploration underway for tight gas. Goldstein et al. (2012); AWT International (2013); Goldie Divko (2015); GA (2017b) Pedirka Basin NT,SA Purni Formation Purni Formation None No shale/ tight gas exploration activity. AWT International (2013); Munson (2014); Scientific Inquiry into Hydraulic Fracturing in the Northern Territory (2018) South Nicholson Basin NT, QLD Constance Sandstone None None No shale/ tight gas exploration activity Jell (2013); Munson (2014) Surat Basin NSW, QLD None Walloon Coal Measures None No shale/ tight gas exploration activity. (Note some wells targeting tight gas in the underlying Bowen Basin have been incorrectly reported to be associated with the Surat Basin). Jell (2013): DNMR (2017);
Amadeus Basin NT Regional; 3,440 km2 - - - - 5.1 - Tight gas Stairway Sandstone CORE (2017); DWSPET (2011) Bowen Basin QLD Regional; 51,252 km2 - - - - 97 - Shale gas Black Alley Shale AWT International (2013) Basin NSW Regional; 4,407 km2 - - - - 11 - Shale gas Koukandowie Formation AWT International (2013) Basin NSW Regional; 4,407 km2 - - - - 10 - Shale gas Raceview Formation AWT International (2013) Cooper Basin QLD ATP 855 (Nappamerri Trough) Beach 0.34 1.57 5.84 - - - Shale gas, tight gas Various Beach Energy (2015) Cooper Basin SA PRLs 33 to 49 (Nappamerri Trough) Beach 0.95 1.95 3.9 - - - Shale gas, tight gas Various Beach Energy (2015) Cooper Basin QLD ATP 940 (100%) Drillsearch 0.22 0.77 1.85 - - - Shale gas, tight gas At Charal-1 and Anakin-1 Drillsearch (2015) Cooper Basin SA CBJV (PPLs 7, 8, 9, 11, 101, 102, 113) Santos 1.73 3.52 6.84 Shale gas, tight gas Winnie 3D Shale Gas Company Cooper Basin SA PEL 115, 516 Senex 0.15 0.84 2.37 - - - Tight gas Tight sands around the Hornet field Senex (2013) Cooper Basin SA PEL 516 (Allunga Trough) Senex 0.12 0.7 2.05 - - - Shale gas, tight gas Patchawarra Formation and Murterre Shale at Sasanof 1 Senex (2013) Cooper Basin SA PEL 96 (southwestern Cooper Basin) Strike 0.16 0.23 0.34 - - - Tight gas, coal Patchawarra Formation coals at Le Chiffre-1 and Klebb-1 Strike Energy (2015) Moreton Moreton
Otway Basin SA, VIC Regional; wet gas 628 km2; dry gas 369 km2 - - - - 1.6 - Shale gas Crayfish Sub-group; Eumeralla Formation; Casterton Formation GA (2017b); AERA (2018) Otway Basin SA, VIC Regional; 17,233 km2 - - - - 5.8 - Tight gas Casterton Formation; Eumeralla Formation GA (2017b); AERA (2018) Perdirka Basin NT Regional; area unknown - - - - 33.7 - Shale gas Purni Formation NTGS (pers. Comm) TOTAL - 17.1 - - 393.3 -
Table C.2 Summary of shale and tight gas plays compiled from Munson et al. (2014). Formation Age Environment Top depth (m) Thickness (m) Source rock(s) Source rock TOC (%) Source rock maturity Play type Exploration status Stairway Sandstone Early Ordovician epicontinental seaway 750–1,800 < 550 m Some Type III; likely Horn Valley siltstone source Unknown Tight gas ?Preliminary exploration (Central Petroleum, 2017) Horn Valley Siltstone Early Ordovician shallow marine 1,000–1,900 0–422 m Type II; type III 0.2–9.0% Early oil – gas window Shale gas Preliminary exploration (Central Petroleum, 2017) Pacoota Sandstone Early Ordovician outer shelf, estuarine, tidal, barrier island 1,020–2,100 700–800 m Horn Valley Siltstone as above as above Tight gas ?Preliminary exploration (Central Petroleum, 2017)
Table C.8 Summary of shale and tight gas plays compiled from literature and well completion reports. Formation Age Environment Top depth (m) Thickness (m) Source rock(s) Source rock TOC (%) Source rock maturity (Ro) Play type Exploration status Showgrounds Sandstone Middle Triassic <50 Bandanna Fm and equiv. coals and carbonaceous shales (Type II/III) N/A main oil to wet gas; 0.95-1.15% Tight gas preliminary exploration Rewan Formation (lower) Early Triassic fluvial-deltaic <400 Bandanna Fm and equiv. coals and carbonaceous shales (Type II/III) main oil to wet gas; 0.95-1.15% Tight gas preliminary exploration Bandanna Formation late Permian deltaic <180 Type II/III to Type III; coal, DOM coal main oil to wet gas; 0.95-1.15% Shale/tight gas preliminary exploration Black Alley Shale late Permian <60 Type II/III OM; marine shale main oil to wet gas; 0.85-~1.6% Shale gas preliminary exploration Tinowon Formation late Permian shallow 50-100 Wallabella Coal Mb; Bandanna Fm and equiv. coals and carbonaceous shales; early-late Permian marine shales Main oil to dry gas; 0.95-1.15% 1.05-~2.0%; Tight gas preliminary exploration 4,500
Table C.15 Summary of shale and tight gas plays. Formation Age Environment Top depth (m) Thickness (m) Source rock(s) Source rock TOC (%) Source rock maturity (Ro) Play type Exploration status Koukandowie Fm Early Jurassic fluvial m <700 Type II/III; DOM Generally 3.0–>20.0 (includes coal) main oil to dry gas; 0.8–2.0% Tight and/or shale gas preliminary exploration; currently inactive Gatton Sandstone Early Jurassic fluvial m <1,100 m Raceview Fm, Ipswich Coal Measures Generally <1.0–3.0; coal main oil to dry gas; 0.8–2.4% Tight gas preliminary exploration; currently inactive Raceview Fm Late Triassic fluvial m <300 Type III Generally <1.0–3.0 main oil to dry gas; 0.8–2.4% Tight and/or shale gas preliminary exploration; currently inactive 1,500 2,400
Table C.26 Summary of shale, tight and deep coal gas plays (compiled from Hall et al., 2015, 2016a, b, UPR, 2015). Formation Age Environment Top depth (m) Thickness (m) Source rock(s) Source rock TOC (%) Source rock maturity Play type Exploration status Toolachee Formation Late Permian Fluvio-deltaic 0–280 Type II/III to Type III; coal, DOM 0–96 Immature – late gas Tight, deep coal Under assessment/ minor production Daralingie Formation Middle Permian Fluvio-deltaic 0–130 Type II/III to Type III; coal, DOM 0–79 Immature – late gas/ over mature Tight Under assessment/ minor production Roseneath Shale Middle Permian Lacustrine 0–240 Type III; DOM 0–22 Immature – over mature Shale Under assessment/ minor production Epsilon Formation Middle Permian Prograding delta and lacustrine 0–195 Type II/III to Type III; coal, DOM 0–80 Immature – over mature Tight, deep coal Under assessment/ minor production Murteree Shale Early Permian Deep, freshwater lacustrine 0–90 Type III; DOM 0–13 Immature – over mature Shale Under assessment/ minor production Patchawarra Formation Early Permian 0–680 Type II/III to Type III; coal, DOM 0–88 Immature – over mature Tight, deep coal Under assessment/ minor production 3,800
Table C.35 Summary of shale and tight gas plays (compiled from Draper, 2007; Dunster et al., 2007; Munson, 2014; UPR, 2015; DNRM, 2017). Formation Age Environment Top depth (m) Thickness (m) Source rock(s) Source rock TOC (%) Source rock maturity Play type Exploration status Arrinthrunga Formation (Dulcie and west Toko synclines) late Cambrian shallow marine 0–830 Max 975 m Type II; type II-III Av 1.8 %; 0–11% Immature-gas mature Shale gas, tight gas Unknown Georgina Limestone (east Toko Syncline) late Cambrian deep water 0–2,500 ~400 m Unknown Unknown Unknown ?Shale gas, tight gas Unknown Arthur Creek Formation (Dulcie and west Toko synclines) middle Cambrian dysoxic to anoxic, deeper marine 0–1,550 Max >438m Type II; type II-III Av 1.6 %; 0–14% Immature-gas mature Shale gas, tight gas Preliminary exploration (e.g. Petrofrontier, 2011; Central Petroleum, 2017) Inca Shale (Burke River Structural Belt) middle Cambrian marine 0–3,220 3–150 m Unknown Unknown Unknown ?Shale gas, tight gas Unknown Beetle Creek Formation (Burke River Structural Belt) middle Cambrian marine 0–1,020 75–90 m Unknown Unknown Unknown ?Shale gas, tight gas Unknown Thorntonia Limestone / Hay River Formation middle Cambrian peritidal to marine, 0–3,200 23 m to >400 m Type II; type II-III Av 1.5%; 0– 8.3% Immature-gas mature Shale gas, tight gas Preliminary exploration (e.g. Petrofrontier, 2011; Central Petroleum, 2017)
Table C.41 Summary of shale and tight gas plays with the potential to supply gas to market in a 5 to 10 year timeframe. Compiled from Goldie Divko (2015) and GA (2017). Note too little is understood about the shale gas potential for development of any shale gas play in the basin within a 10 year timeframe, so this play is not included here. Formation Age Environment Top depth (m) Thickness (m) Source rocks(s) Source rock TOC (%) Source rock maturity Ro(%) Play type Exploration status Strzelecki Group Early Cretaceous Fluvial 1400 up to 3000 Type II/III to Type III; coal, DOM 0.4–20 0.5–1.3 Tight gas Preliminary exploration
Table C.48 Summary of shale and tight gas plays (from DNRM, 2017). Formation Age Environment Top depth (m) Thickness (m) Source rock(s) Source rock TOC (%) Source rock maturity Play type Exploration status Lawn Hill Formation Mesoproterozoic Mid to outer shelf Outcrop to 2,000 m up to 2,200 m Algal up to 7% Dry gas Shale gas Preliminary exploration Riversleigh Siltstone Paleoproterozoic- Mesoproterozoic Mid to outer shelf Outcrop to m up to 2,900 m Algal up to 8% Dry gas Shale gas Preliminary exploration
Table C.54 Summary of shale and tight gas plays (compiled from Munson et al., 2014; UPR, 2015; Revie, 2017a). Formation Age Environment Top depth (m) Thickness (m) Source rock(s) Source rock TOC (%) Source rock maturity Play type Exploration status Kyalla Formation (Roper Group) Mesoproterozoic shallow to moderately deep marine 550–990 0–800 Type I to II 2–3% Max 4% Early oil–gas window shale gas Active exploration (Origin, 2017) Moroak Sandstone (Roper Group) Mesoproterozoic tide-dominated shoreline 320–1,715 2.5–485 N/A N/A N/A tight gas Unknown Velkerri Formation (Roper Group) Mesoproterozoic shallow to nearshore marine 80 to >350 Type I to II 2-6 %. Max 12.5% Early oil–gas window shale gas Under assessment (Origin, 2017) Bessie Creek Sandstone (Roper Group) Mesoproterozoic tide-dominated shoreline 440–1230 20–422 N/A N/A N/A tight gas Unknown Vaughton Siltstone (Balma Group) Paleoproterozoic deep subtidal ? 600–1000 unknown unknown ?shale gas Unknown Yalco Formation (McArthur Group) Paleoproterozoic shallow-marine ? 0–250 Type II Max. 6% Marginally mature–over mature shale gas Unknown Lynott Formation (McArthur Group) Paleoproterozoic subtidal marine to intertidal ? 50–600 ?Type II 0.2–3.4% Marginally mature–over mature shale gas Active exploration (Armour Energy, 2017) Reward Dolostone (McArthur Group) Paleoproterozoic deepwater to shallow marine 260–615 30–350 N/A N/A N/A tight gas, natural fractures Active exploration (Armour Energy, 2017) Barney Creek (McArthur Group) Paleoproterozoic deeper-water marine 60–650 <200–1,200 Type I to II 0.6–10.4% Immature–over mature shale gas Active exploration (Armour Energy, 2017)