· web view2015-12-21 · stratigraphy moomba-big lake 3d seismic cube (backé and king, 2010)...

chapter2 Gas Plays in

South Australia

A petroleum play is an area in which oil and/ or gas accumulations exist and/or may exist. The basic independent geologic factors that must operate together a petroleum play to exist can be generalized as: source rockswith a capacity to generate hydrocarbons; rock reservoirs from which petroleum can be produced, and circumstances that enable petroleum to be trapped and accumulate in the subsurface.

Chapter two provides descriptions of the geologic attributes and potential extent of unconventional gas plays in the Cooper, Arckaringa, Otway, Gambier, Pedirka, Simpson, Warburton and Officer basins.

The regulation of projects within plays is addressed in Chapter 5

2.1 Cooper BasinThe Cooper Basin is a Permo-Carboniferous to Triassic intracratonic basin located approximately 800 km north-northeast of Adelaide in South Australia. It lies unconformably over early Palaeozoic sediments of the Warburton Basinand is overlain disconformably by the central Eromanga Basin. In the northern Patchawarra Trough, the Cooper Basin is locally overlain by the Late TriassicCuddapan Formation. Total area exceeds130 000 km2, of which ~35 000 km2 are in NE South Australia (Figure 2.1).

Three major troughs (Patchawarra, Nappamerri and Tenappera) are separated

2 R O A D M A P F O R U N C O N V E N T I O N A L G A S P R O J E C T S I N S O U T H A U S T R A L I A

by structural ridges (Gidgealpa–Merrimelia– Innamincka (GMI) and Murteree) associated with the reactivation of NW-directed thrust faults in the underlying Warburton Basin (Figures 2.2 and 2.3) and contain up to2500m of Permo-Carboniferous to Triassic sedimentary fill overlain by as much as 1300 m of Jurassic to Tertiary cover.

The Basin contains a number of non-marine depositional sequences within the Late Carboniferous to Late Permian Gidgealpa Group and Late Permian to Middle Triassic Nappamerri Group (Figure 2.4).

2.1.1 Shale Gas PlayThe principal shale gas play currently being pursued by several companies in the Cooper Basin is the Roseneath - Epsilon - Murteree (REM) play comprising Early PermianMurteree and Roseneath shales divided by tight sands of the Epsilon Formation. The two shale units are thick, generally flat lying, and laterally extensive, comprising siltstones and siliceous (and sideritic in part) mudstones deposited in large and relatively deep freshwater lakes.

The Murteree Shale is widespread, reaching a maximum thickness of 86 m in the Nappamerri Trough (Figures 2.5 and 2.8)and thins to the north, reaching a maximum thickness of 35 m in the Patchawarra Trough (Figure 2.7). It is absent over crestal ridges. The Roseneath Shale reaches a maximum thickness of 105 m in the Tenappera Trough (Boucher, 2000) and is not present over most of the Patchawarra Trough (Figures 2.6 and2.8).

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MILPERA DEPRESSION

WEENA TROUGH

0 25 50 Kilometres

REG 204218-042

Datum GDA 94 - Projection MGA Zone 54

Figure 2.2 Cooper Basin – Structural elements on Top Warburton (Z Horizon) showing line of section B-B’ in Figure 2.3)


Figure 2.3 Regional N-S log correlation across the Cooper Basin, South Australia, highlighting the shallower occurrence of the prospective Permian succession in the Tenappera Trough/Mettika Embayment compared with the Nappamerri Trough. Senex’s planned Skipton-1 and Talaq-1 unconventional wells will test the Mettika Embayment. The relatively shallow depths mean lower temperatures are encountered, and there is no need for specialised casing or drilling materials. See Figure 2.2 for location of section.

Figure 2.11 shows the Cooper Basin shale gas play fairways defined by the Murteree Shale exceeding 30m thickness, with a minimum maturity (as optically measured with vitrinite reflectance (Ro) at the base of the Murteree Shale of 0.95% (top of the wet gas window).

Total organic carbon (TOC) values average3.9% in the Roseneath Shale and 2.4% in theMurteree Shale. HI vs. Tmax plots confirm a predominantly Type III kerogen for both shales (Figures 2.9 and 2.10).

Although the Roseneath and Murteree Shales are present over much of the Cooper Basin, organic maturity is variable (Figure 2.11). In the Patchawarra Trough, where only the Murteree Shale is present, maturity sufficient for wet gas generation (0.95<Ro<1.7) is only present in the deepest part of the trough. A significant portion

of the Roseneath-Epsilon-Murteree (REM)

section in the Nappamerri Trough lies within the dry gas window (Ro>1.7). This higher maturity is due to an elevated geothermal gradient resulting from high heat producing granites at depths around 4,000 m (Meixner,2009). The REM section in the south western margin of the Nappamerri Trough, northern Tenappera Trough and Mettika Embayment is mature for wet gas generation.

Seismic data in the core Nappamerri Trough area is of variable quality, with good 2D seismic grid coverage over conventional structures (Burley, McLeod, Bulyeroo), grading to reasonable to poor coverage elsewhere. Seismic coverage over the Moomba high on the south-western margin of the Nappamerri Trough is very good and this area was selected in 2010 as the starting point of a fault and fracture systems studyfor application to unconventional gas plays in the Basin. Seismic attribute analysis of the

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SERIES STAGEROCK UNIT

DEPOSITIONAL ENVIRONMENT

LAKE EYRE BASIN

EROMANGA BASIN

Late

Norian toRhaetian

Carnian

Ladinian

PT5

PT4

Cuddapan Formation(36m)

100m

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Kazanian

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PP5

150m(74m)

CallamurraMember

125m(91m)

ToolacheeFormation

DaralingieFormation

ArraburyFormation

(222m)

160m(71m)

Floodplain, lacustrine, palaeosols, moderate/sinuosity fluvial channels.

Meandering fluvial, deltaic in part

Daralingie unconformity

Fluvio-deltaicPP4 (41m)

REM: Lacustrine with

Kungurian Roseneath Shale (50m)

interbedded fluvio-

Artinskian PP3

EpsilonFormation

140m(55m)

80m (40m)

deltaic/local transgressive/regressive

shore face

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PP2

MurtereeShale

Patchawarra Formation

Fluvio-deltaic, lacustrine

PeatswampVc coal

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680m(190m)

Tirrawarra Sandstone75m(37m)

Merrimelia Formation450m(70m)

Proglacial outwash, braided fluvial

Terminoglacial, proglacial, glaciolacustrine, aeolian.

WARBURTON BASIN

204218_076


Figure 2.4 Cooper Basin – Stratigraphy

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Moomba-Big Lake 3D seismic cube (Backé and King, 2010) identified both orthogonal patterns oriented N-S and E-W and curved lineaments that may assist in orientating future horizontal wells and fracture stimulations (Figure 2.12).

These natural fracture systems may have been naturally enhanced by the mineralogy of the clays in these lacustrine shales. 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.

Gas content information is still largely unavailable as data are held confidential for two years after rig release in the case ofa well or sampling event in the case of cores and cuttings. Open file information suggests lower porosity than US shales and highlights requirement for thicker and overpressured shale sections to commercialise the resource.

Shale gas reservoirs contain gas stored as both free gas and gas adsorbed to surfaces of solid organic matter. Gas adsorption capacity is a function of a number of parameters, including organic carbon content, and kerogen type.

139°30'E

QUEENSLAND141°0'E 139°30'E

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Figure 2.5 Murteree Shale isopach Figure 2.6 Roseneath Shale isopach

Wimma 1 Moomba 73

204218_077 204218_078

Figure 2.7 Murteree Shale, Wimma 1, PatchawarraTrough

Figure 2.8 Roseneath and Murteree shales, Moomba73, Nappamerri Trough

1000

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Hydrogen Index (HI)

Munkarie 4Tindilpie 2Toolachee East 2Bulyeroo 1Burley 1Burley 2Darmody 1Kirby 1McLeod 1

II

III

I

VR=0.5%

VR=1.35%

1000

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Hydrogen Index (HI)

Baratta 1Dirkala 1Kobari 1Mudrangie 1Munkarie 2Munkarie 4Murteree 2Snake Hole 1Tindilpie 2Tirrawarra 4Toolachee East 2Wancoocha 1Bulyeroo 1Burley 1Burley 2Kirby 1McLeod 1

I

II

III

0300 320 340 360 380 400 420 440 460 480 500 520 540 0

300 320 340 360 380 400 420 440 460 480 500Tmax (°C) 204218_079 Tmax (°C) 204218_080

Figure 2.9 Van Krevelen plot - Roseneath Shale


Figure 2.10Van Krevelen plot - Murteree Shale

Hydrocarbon generation creates significant microporosity as nanopores within Type II kerogen (Loucks et al, 2012), increasing the surface area available for gas adsorption. As the Roseneath and Murteree shales are dominated by Type III kerogen, maturationis unlikely to result in increased adsorbed gas storage capacity characteristic of Type II source rocks. However being siltstones, these units may have considerable free gasstorage capacity in mineral matrix pores and fractures.

Gas production from the Roseneath and Murteree shales has been observed in the overpressured Nappamerri Trough wells (Holdfast-1, Encounter-1 and Moomba 191) and further appraisal is planned.

2.1.2 Tight Gas PlayThe presence of a basin centred gas accumulation (BCGA) in the Nappamerri Trough has been suspected for many years and the circumstantial evidence was presented by Hillis et al. (2001). Resistivityof the Permian succession exceeds 20Ωm over large intervals (Figure 2.13), tests have recovered gas with no water, and gas is located within overpressured compartments indicative of hydraulic isolation (Figure 2.14). 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. Others can be expectedto follow this lead.

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% carbonaceous and silty shalesand 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 (Deighton et al., 2003),but overpressure has been retained in theNappamerri Trough (Figure. 2.14).

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 (Law, 2002). 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.

Thick coals and organic rich shales in theEarly Permian succession are capable of generating enormous hydrocarbon volumes. The total gas generative potential of the Cooper Basin source rocks has been estimated to be between 4,027 tcf to 8,055 tcf (Morton, 1998). Coal and carbonaceous shale of the Patchawarra Formation represent the principal source rocks of the Cooper Basin, both in source richness and quality, and overall thickness (Borehamand Hill 1998). Rock-Eval data (Figure 2.15) indicates that Patchawarra Formation source rocks contain a mix of both Type II and Type III kerogen1. Toolachee Formation coal and carbonaceous shale represent the second most important source rock unit of the Cooper Basin in terms of richness, quality and thickness. Rock-Eval data (Figure 2.16) indicate that Toolachee Formation source rocks also contain a mix of both Type II and Type III kerogen.

Average porosity and permeability maps for the Patchawarra Formation highlight the low porosities and permeabilities in the

1 For definitions of various types of kerogens– visit www.glossary.oilfield.slb.com/Display.

cfm?Term=kerogen

29°0

'S28

°0'S

2.18) conducive to the development of a BCGA (Heath, 1989). In the Nappamerri Trough and north-eastern Patchawarra Trough average porosities range <7% to 9% and average permeabilities range <0.1mD to1mD. Gas wetness maps for the Patchawarra Formation (Figures 2.19, 2.20) highlight the dry nature of the gas in the deeper parts of the troughs, reflecting the high thermal maturityof the intra-formational source rocks in these areas traditionally viewed as hydrocarbon source “kitchens” (Heath, 1989).

has targeted gas outside structuralclosure. Holdfast-1 and Encounter-1have demonstrated gas production from overpressured tight sandstones in the Epsilon and Patchawarra Formations from structural lows within the Nappamerri Trough. Moomba 191 on the Moomba North structure has recently been fracture stimulated and flowed gas at 2.7 mmcf/d at systems pressures from shales in the REM section. Moomba 191 is Australia’s firstcommercial shale gas well. There is regional

139°0'E 140°0'E

VR=0.95% at base Murteree(top wet gas window)

VR=1.7% at base Murteree

!Daer 1 ! Cuttapirrie 1

Murteree Shale >30m

REM Shale Gas Play

Lamdina 1 ! !Wimma 1

Murteree Shale Gas Play

Cooper BasinPermian edge

Bookabourdie 1 !!

Pondrinie 2

Holdfast 1!

r 1Innamincka ") Encounte !

! McLeod 1

Moomba 73! Corkwood 1 !

") Moomba Dullingari 26 !

Toolachee 24!

! Vintage Crop 1 ! Burruna 1

0 25 50 Kilometres

Datum GDA 94 - Projection MGA Zone 54

204218-060


Figure 2.11Shale gas plays – Cooper Basin.

Coal Seam PatchawarraThickness (m) Formation

ToolacheeFormation

Average 2.1 4.3Maximum 22.3 21.9Minimum 0.3 0.3% seams >2 m 29.8 42.4

204218_081

Figure 2.12 Top Roseneath Shale pattern characterisation from Moomba-Big Lake 3D seismic cube (mapping andattribute analysis by Hani Abul Khair, supervisor Guillaume Backé). See Figure 2.11 for location of 3D survey.

evidence to suggest the entire REM section is part of a BCGA (Figure 2.14).

Regional pressure gradient, average porosity, average permeability and gas saturation maps for the Patchawarra Formation sands and Epsilon Formation sands will assist in defining the areas of BCGA plays in the Cooper Basin. These maps will be prepared for a new edition of the Petroleum Geologyof South Australia, Volume 4, Cooper Basin.

Table 2.1 Coal seam thickness for Patchawarra andToolachee formations.

2.1.3 Deep Coal Seam Gas Play The Gidgealpa Group is characterised by coal measures, especially in the Patchawarra, Epsilon and Toolacheeformations. Thick, laterally extensive coalseams have been intersected in both the Patchawarra Formation and the Toolachee Formation (Figure 2.21).

The Patchawarra Formation was deposited in a coal-dominated fluvial/ lacustrine depositional environment, with fluvial channel and point bar sandstones the principal conventional reservoirs,characterised by relatively low porosity and permeability (Strong et al., 2002). Individual coal seams occur throughout the formation and range in thickness from 0.3 m up to a maximum of 22.3 m (Table 2.1– excludesthe results of recent drilling, in particular Davenport 1) with a combined thickness in excess of 60m in the Patchawarra Trough (Figure 2.21).

The VC50 chronostratigraphic (time-rock) unit corresponds to the thickest laterally extensive coal seam in the Patchawarra Formation,and to the Vc seismic horizon (Strong et al,2002, Alexander et al, 1998). Examples of a thick VC50 coal seam, ranging 13 m to 23 m, are given in Table 2.3.

The base Patchawarra Formation maturity map shows that the Patchawarra Formation is sufficiently mature for the generationof gas from coal seams over much of the basin (Figure 2.22). High mud gas readings2 are generally recorded when mature Patchawarra Formation coals are intersectedin wells (Table 2.2).

The Patchawarra coal seams are deeper 2than 2000 m over most of the Cooper Basin. The floor for CSG production is generally considered to be 2000 m due to cleat closure and permeability reduction atthese depths. However scanning electron microscopy of VC50 coal core samples from Bindah 3 has shown that the coals contain significant mesoporosity3 (ACSLaboratories Report, 2011). The mesoporosity is a consequence of the high inertinite content of the coals (inertinite is derived from charred and biochemically altered plantcell wall material that generally remains intact during the carbonization process. The VC50 coal is thick and laterally continuous

2 Gas chromatography measurements on drilling fluids (drilling mud) pumped from the bit face to the surface enables the detection of rocks with relatively high gas saturations.

3 Micropores with diameters between 2 and 50 nanometers (10-9 metres)

NE

(m)-2050

Bauhinia 1 Kirby 1 McLeod 1 Burley 2 Bulyeroo 1Adori

Sandstone Moomba 73 SW

Hutton Sandstone

? ? ?? ? ?

NappamerriGroup

-2550

-3050

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PIRSA Publishing Services 202341_011

204218_082

Figure 2.13 Geological cross section, Nappamerri Trough showing elevated resisitivities (from Hillis et al, 2001). See inset onFigure 2.11 for line of section.

0

1 000

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4 267

Depth (m)

Hydrostat

Pressure data in regional water system

Pressure data in gas saturated zone

Lithostat

McLeod 1 (Epsilon)

Moomba 55(Patchawarra)

Burley 1 (Epsilon)

Kirby 1 (Patchawarra)

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Hydrogen index (HI)

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Andree 2 (8)

Gidgealpa 1 (3)

Kurunda 1 (11)

Murteree 2 (20)

Pondrinie 2 (17)

Snake Hole 1 (20)

Sturt 3 (1), Sturt 4 (1),Sturt 6 (1), Sturt East 4 (1)

Tibouchina 1 (3)

Tirrawarra West 1 (22)

Baratta 1 (4), Callabonna 1 (3), Cuttapirrie 1 (5), Dirkala1 (1),Fly Lake 3 (1),Gidgealpa 17 (1), Kanowana 1 (2),Kerinna 1 (8), Kobari 1 (6), Lake MacMillan 1 (3), Leleptian 1 (10), Maraku 1 (4), Munkari 4 (7), Nulla 1 (7),Papyrus 1 (7), Spectre 1 (14), Tindilpie 2 (10),Tinga Tingana 1 (30),Tirrawarra 2 (2), Tirrawarra 16 (1), Tirrawarra North 1 (12),Toolachee East 2 (21),Toonman 1 (1), Wancoocha 1 (7)

VR = 1.35 %0 2000 4000 6000 8000

Pressure (psi)10 000 12 000

204218_083 100 III

Figure 2.14 Evidence for overpressured compartmentsin the Nappamerri Trough (from Hillis et al, 2001)

0380 400 420 440 460 480 500 520

T max (°C)

in parts of the Basin and may be suited to gas extraction using horizontal drilling and hydraulic stimulation techniques. Targeting natural fracture systems is likely to enhance production rates and optimise drainage. The coals are expected to be gas saturated, so

204218-085

Figure 2.15Van Krevelen plot – Patchawarra Fm.

Hydrogen Index (HI)1000

I

de-watering will not be necessary.

Assessment of the deep coal seam gas potential of the basin commenced with desorption analysis of a 4m Patchawarra coal seam cored in Dorodillo 2 gas appraisal well in1998. Further assessment of deepcoal seam gas was suspended until 2007,when Santos flowed gas to surface at 100,000 scf/day from a fracture stimulatedPatchawarra Formation coal in Moomba77 gas development well (Figure 2.24). Since then additional deep coal seam gas assessment work, including coring the VC50 coal seam for analysis, has been carriedout in several gas development wells. Gas desorption analysis of the VC50 coal seam

900

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0

II

III

Andree 2 (2)

Leleptian 1 (2)

Murteree 2 (8)

Tirrawarra North 1 (3)

Tirrawarra West 1 (2)

Toolachee East 2 (17)

Toonman 1 (1)

Snake Hole 1 (7)

Baratta 1 (3), Cuttapirrie 1 (4), Dirkala1 (1), Gidgealpa 1 (1), Kenny 1 (2), Kerinna 1 (5), Kurunda 1 (1),Lake MacMillan 1 (3), Munkarie 4 (17), Nulla 1 (1), Pondrinie 2 (3), Spectre 1 (2), Tindilpie 2 (2), Toonman 1 (1)

VR = 1.35 %

cored in Bindah 3 returned excellent total

380 400 420 440 460 480 500 520

raw gas results averaging 21.2 standard cubic centimetre per gram4 (scc/g which

T max (°C)

Figure 2.16Van Krevelen plot – Toolachee Fm

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4 1 scc/g is equivalent to 680 standard cubic feet per ton (scf/ton)

PL20 PL20 2

M E R R I M E L I A - I N N A M I N C K A

"Innamincka

PL5

PL18"

Innamincka

PL5

PL18

" Moomba

PL17 " MoombaPL17

PL15 PL15

PL9 PL9

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Cameron Corner" Cameron Corner

"

PL2 PL1 PL2 PL1T I N G A T I N G A N A

T I N G A T I N G A N A

Pipeline Licence (PL)GasGas and liquidsLiquids

Patchawarra edge

Patchawarra absent

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Patchawarra edge

Patchawarra absent

204218-057

Figure 2.17Average Porosity, Patchawarra Formation(after Heath, 1989)

Figure 2.18Average Permeability, PatchawarraFormation (after Heath, 1989)

is equivalent to 680 standard cubic feet per ton (scf/ton) over 10 metres (ACS Laboratories Report, 2011). Whilst the carbon dioxide (CO2) content of the desorbed gas was high, CO2 levels around the Basin are highly variable and lower CO2 contents are expected in other parts of the Basin.

Recent drilling in the Milpera Trough 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.


Well Name VC50 Seam Thickness

(m)

Total Gas (units)

Bindah 3 19 80 – 500Meranji South 1 16 1000Cowralli 1 18 1000 – 2000Cowralli 10 16 2065 – 3550Kanowana 2 18 600 – 900Tindilpie 7 16 1000Dorodillo 4 13 100 – 1000Battunga 1 23 1835Wimma 1 14 2800

Table 2.2: VC50 Coal seam thickness and mud gasrecorded whilst drilling

PL20PL20



"Innamincka

PL5

PL18"

Innamincka

PL5

PL18

" Moomba

PL17 " PL17

Moomba

PL15 PL15

PL9 PL9

PLs7,8 PLs7,8

Cameron Corner" Cameron Corner

"

PL2 PL1 PL2 PL1T I N G A T I N G A N A

T I N G A T I N G A N A


Patchawarra edge

Patchawarra absent

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Patchawarra edge

Patchawarra absent

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Figure 2.19 Barrels of LPG/mmcf raw gas, PatchawarraFormation (after Heath, 1989)

Figure 2.20Barrels of condensate/mmcf raw gas, Patchawarra Formation (after Heath, 1989)

Thick, laterally extensive coal seams are also characteristic of the Toolachee Formation (Figure 2.21). The Toolachee coals are sufficiently mature for thermogenic gas generation in the Nappamerri and Arrabury troughs, and parts of the Patchawarra Trough (Figure 2.23), and high mud gas readings have been recorded whilst drilling through mature Toolachee coals (e.g. Paning 1).

2.1.4 Eromanga Basin Shallow CoalSeam Gas PlayThe principal shallow coal seam gas play in the Eromanga Basin (which disconformably overlies the Cooper Basin) is the Cenomanian to Turonian Winton Formation that comprises up to 1200 m of non-marine

shale, siltstone with minor coal layers. Individual coalseams appear to be thin (~1 to 2 m) and not laterally extensive.


In late 2009, AGL Energy Ltd, in joint venture with Acer Energy Ltd, conducted a 3 core hole drilling program centred over the Innamincka Dome (Figure 2.11). Merninie1, 2 and 3 wells were drilled to depthsof 699 m, 518 m and 600 m respectively and core samples for desorption analysis taken, although final results are yet to be made available. However, ACER Energy in their quarterly statement in April 2010indicated that preliminary results conclude that whilst coals appear sufficiently mature, coal thickness and gas content are below commercial thresholds within current commercial parameters. As such, the JV partners recognise that a standalone CSG development is unlikely to proceed.

Exploration for shallow Winton Formation coal seam gas has not commenced elsewhere in

20

29°0

'S28

°0'S

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'S26

°0'S

NE

W S

OU

TH W

ALE

S29

°0'S

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°0'S

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'S

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NE

W S

OU

TH

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LES

29°0

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(a) (b) 2

139°30'E

QUEENSLAND141°0'E 139°30'E

QUEENSLAND141°0'E

Metres66

30

0



Metres41

20

0PL20



Innamincka "PL5PL18

Innamincka"

PL5PL18

"Moomba

PL17

PL15

PL9

"Moomba

PL17

PL15

PL9

10

10PLs7,8 PLs7,8

Cameron Corner "Cameron Corner "

REG 204218-045 139°30'E

PL2 PL1

0 10 20 30 40 km

MGA Zone 54

141°0'EREG 204218-046 139°30'E

PL2 PL1

0 10 20 30 40 km

MGA Zone 54

141°0'E

Figure 2.21 Coal isopach maps (a) Patchawarra Fm; (b) Toolachee Fm

the SA part of the basin, and its prospectivity is not yet well understood. Facies mapping within the Winton Formation across thebasin may enable identification of morecoal-prone areas and help focus exploration for this shallow play. In Queensland, coaly Birkhead Formation equivalent (e.g. Walloon Coal) occurs at shallow depths towards the eastern margin of the Eromanga Basin and forms another play. However, in SA finer grained and coaly Birkhead facies best developed in the Cooper depocentre, are laterally equivalent to sandy, braided fluvial Algebuckina Formation and do not occur at shallow

depths on the basin margin.


2.2 Arckaringa Basin

The Arckaringa Basin is a Permo- Carboniferous intra-cratonic basin located approximately 750 km north-west of Adelaide (Figure 2.25).

The Basin comprises two main depocentres, the Boorthanna Trough in the east, and the southern Arckaringa troughs (including the West, Phillipson, Penrhyn and Wallira troughs) in the south, separated by shallow basement with a thin veneer of Permian sediments (Figure 2.26). The troughs contain up to 1300

29°0

'S28

°30'

S28

°0'S

27°3

0'S

27°0

'S26

°30'

S

NEW

SO

UTH

WA

LES

QU

EEN

SLA

ND

29°0

'S28

°30'

S28

°0'S

27°3

0'S

27°0

'S26

°30'

S

29°0

'S28

°30'

S28

°0'S

27°3

0'S

27°0

'S26

°30'

S

NEW

SO

UTH

WA

LES

29°0

'S28

°30'

S28

°0'S

27°3

0'S

27°0

'S26

°30'

SQ

UEE

NSL

AN

D

139°30'E 140°0'E 140°30'E 141°0'E 139°30'E 140°0'E 140°30'E 141°0'E

Vitrinite Reflectance Maturity

Less than 0.81 – Immature

0.81 to 0.95 – Oil

0.95 to 1.7 – Wet gas

1.7 to 2.5 – Dry gas

Greater than 2.5 – Over mature

Patchawarra absent


Cooper Basin edge

Vitrinite Reflectance Maturity

Less than 0.81 – Immature

0.81 to 0.95 – Oil

0.95 to 1.7 – Wet gas

Greater than 1.7 – Dry gas

Toolachee absentCooper Basin edge

Cooper BasinPermian Edge no data

Innamincka" Innamincka

"

Moomba" Moomba

"

Cameron Corner " Cameron Corner "

0 10 20 30 40 km

MGA Zone 54

0 10 20 30 40 km

MGA Zone 54

204218-110 139°30'E 140°0'E 140°30'E 141°0'E 204218-111 139°30'E 140°0'E 140°30'E 141°0'E

Figure 2.22 Base Patchawarra Formation Maturity Map Figure 2.23Top Toolachee Formation Maturity Map

m of Carboniferous-Early Permian sedimentsoverlain by up to 300 m of EromangaBasin sediments and generally less than10 m of Tertiary cover. The BoorthannaTrough is broad, and underlain in partby Neoproterozoic and early Palaeozoic sediments of the Adelaide Rift complex. The southern Arckaringa troughs arenarrow, and underlain by Archaean to Early Mesoproterozoic rocks of the Gawler Craton. Both depocentres show evidence of infill of basement topography.

The Permo-Carboniferous succession in the Arckaringa Basin has been divided

into three formations (Figure 2.27) basedon lithology and stratigraphic relationships


(Hibburt, 1984). The BoorthannaFormation, possibly extending into the Late Carboniferous, comprises a glaciogene sequence with marine facies towardsthe top. Lithologies include diamictite (most probably paleo-glacial deposits), rhythmically bedded sandstone (probably representing deposition by turbidity currents) and laminated mudstone. The overlying Stuart Range Formation is generally homogeneous shale with minor siltstone and sandstone, deposited in quiet, restricted marine conditions but with occasional lacustrine intervals. This is in turn overlainby Mt Toondina Formation consisting of a lowermost deltaic sequence and an

Figure 2.24 Moomba 77 Patchawarra Coal Fracture stimulation coals at 9000ft flows 0.1 mmcf/d.

uppermost fluvio-lacustrine succession withintermittent coal swamp development.

The history of the basin is summarised as follows (see Menpes et al, 2010):

1. Incision of deep glacial valleys (Figure

2.28)2. Valleys fill with glacial and marine

sediments of the Boorthanna and Stuart Range formations – some seismic evidence of sea-level fluctuations and minor contraction.

3. Progradation of the Mount Toondina delta system over the basin. Minor differential growth of

this succession, as indicated by seismic and coal


seam geometries, may be the resultof ongoing minor contraction and differential compaction.

4. Contraction culminates with gentle folding of the succession, uplift and erosion. Vitrinite reflectance profiles from exploration wells suggest that the Permian has been subjected to pre- Jurassic uplift and erosion in the order of 0.5–1 km. Coal seam correlations demonstrate the subcrop relationship of the coal seams beneath the Eromanga Basin, indicating that folding and erosion occurred prior to deposition of the Eromanga Basin.

The absence of sediments younger than Sakmarian in age suggests the termination of deposition in the Arckaringa Basin and gentle folding of the succession may berelated to the breaks in deposition identified in the Patchawarra Formation of the Cooper Basin (Gravestock and Jensen-Schmidt,1998). Alternatively the final end to sediment accumulation event may be related to an uplift and erosion event recognised as the Daralingie unconformity between the Early and Late Permian in the Cooper Basin, or the end of the Hunter-Bowen Orogeny5, which is essentially coincident with the unconformity at the top of the Cooper Basin succession.

To the end of 2011, 7 petroleum wells, 9 coal seam gas exploration wells, 14 stratigraphic wells and many mineral and coal exploration holes have been drilled in the Arckaringa Basin (Figure 2.25). Over 6000 line kilometres of 2D seismic data have also been acquired.

2.2.1 Arckaringa Basin Coal Deposits

Seven deposits of lignite A/sub-bituminous C rank coal (American Society for Testing and Materials classification) aggregating more than 20 Gigatonne (Gt6) of measured, indicated and inferred resource have

5 For definitions of orogeny – visit http://en.wikipedia. org/wiki/Orogeny. For a description of the Hunter-Bowen Orogeny – visit http://en.wikipedia.org/wiki/Hunter- Bowen_orogeny6 One Gt equals 109 tonnes

¨ ª: 20 ¨17

¨ ¨8

14

ª

ª

ª

TAR

CO

OLA

- ALIC

E S

PR

ING

S R

AILW

AY

30°0

'S29

°0'S

28°0

'S

30°0

'S29

°0'S

28°0

'S

ª

2

4 ª

2 Ì

ª

been identified in the upper part of the Mt Toondina Formation (Figure 2.25). These are multi-seam deposits with individual seams ranging up to 10 m, with a cumulative thickness of up to 35 m (DMITRE Resources and Energy Group, 2012).

2.2.1.1 Arckaringa Coalfield:The Arckaringa Coalfield comprises four deposits with a combined resource estimate of 10 billion tonnes of low grade, sub-

bituminous coal (Figure 2.29). Heat value, moisture and ash contents of the coal are relatively uniform through the coalfield (DMITRE Resources and Energy Group, 2012):

• Low ash – 6% in-situ• Low sodium in ash – 0.8 to 2.2%• Heat value of 18 megajoules

per kilogram (MJ/kg)

• Variable sulphur content

132°0'E 133°0'E ª 134°0'E 135°0'E 136°0'E Simpson Desert (RR)

: : ª 1A ªRodda 2

Welbourn Bravo 2Byilkaoo:ra 1ªª25:ª ªªªª

Coongra 1

1A 2

Todmordenª1ª2

Pedirka Basin

"Mintabie ª1¨9ª¨3

2ªª ªª¨

2 ª3 2ª1 ª Yardinna 1ª

ª9 ª 8 3 ª¨ 10 ªª¨ 2 3ª

Trainor Alpha 1 ª¨

ª ª ª 6 225 ª ª15 ª1B 23 ª ª

2 ªOodnadatta 1

Eromanga Basin

Officer 17 ª 616 ªªª

5 24 Lambina 1

ªOodnadatta Town Bore 2

Warburton Basin

6 ªª¨ 3 Moªunt Willoughby 1ªMunyarai 1

5 4 9

Middle Bore 1ª 10 ª

Manya 1ª ª2 ªMurloocoppie

East Wintinna1A::Albany 12 Ì

ªToodla 1

Officer Basin3 ª 8

ªª ª ª ªª 2 ª Ì Toondina 1ªªCootanoorina 1

Comalco Coalhole 1 24 3 2

ngoolya 1

ªKªarlaya

1

5 6 7 4

Mount Furner 1ª :

Mount Bray 1

Maglia 1:Hanns Knob 1ª :U

Lairu 1

WestfieldWintinna Boucªat 1:H:aystack 1

Birribiana 1 Sibsey 1

ª ª Langton 1

ªGiles

Arckaringa Basin ªÌ ªMeramangye 1

11A Wirrangulla Hill 1

Weedina 1

ªEmu 1

ªKarkaro 1

:Nuba 1 Coober Pedy

Arck 1Weedina

Wªilliam Creek

1:ª

Lake Eyre (NP)

ª¨Observatory Hill 1

Murnaroo 1Tallaringa (CP)

ª"

Stuart Range 3

Boorthanna 1 2

ª Phillipson2 ªª Wallira 1

Ingomar:Howard Hill 1

ªª

ÌCairn Hill

Warriner Creek 1ª

Officer BasinWallira West 1

Lake Phillipson Bore 1Arkeeta 1 ª

Muddy Tank 1

Peculiar KnobÌ Peculiar Knob

ª Challenger ÌWirrida

Sequoia Gina

Manxman

ÌProminent Hill

Wilkinsonª1

Wilkinson Lakes 2Hawks NestÌ Hawks Nest

2A ª¨2 ª¨ Giffen Well

Karari 1

Nullarbor (RR)

132°0'E

Ì

Yellabinna

(RR)133°0'E

Yellabinna (WA)

134°0'E


"

Tarcoola 135°0'E 136°0'E

Olymp

ic

D

Øa

Úm

Ì

R

oxby DÚowns "

SAP 1 DW1

137°0'E

REG 204218-034

Tarcoola "Petroleum wells

ª Dry hole

0 50 100 km

MGA Zone 53ª¨ Dry hole with oil shows

SOUTH AUSTRALIA

"

ADELAIDE

: ProposedGeothermal wells

Ú Suspended wellØ Proposed

Seismic – post 2000Seismic – 1950–1999

Ì Selected mine

CoalfieldsIron ore deposit or prospect

Parks with petroleum exploration accessParks with no petroleum exploration access

Figure 2.25 Arckaringa Basin petroleum wells, seismic lines and coal deposits.

30°0

'S29

°0'S

28°0

'S

30°0

'S

600

29°0

'S28

°0'S

The four deposits are summarised in Table 2.3

Weedina DepositThe Weedina Deposit has an estimated coal resource of 7.2 billion tonnes (DMITRE Resources and Energy Group, 2012). The overburden contains the major aquifers of the Great Artesian Basin. The coal is suitable for conventional pulverised (coal) fuel power stations. The deposit is summarised inTable 2.4.

2.2.1.2 Lake Phillipson CoalfieldThe Lake Phillipson Coalfield comprisestwo deposits associated with three glacial

valleys scoured by the Permo-Carboniferous 2Gondwanan glaciation (Figure 2.30). The Phillipson Deposit has an estimated coal resource of 5 billion tonnes and has a comparable coal quality to other Arckaringa Basin coal deposits except for high sodium and chlorine levels (about 2%) (Figure 2.31). The Ingomar Deposit has an approximate inferred resource of 700 million tonnes with generally high levels of impurities such as sulphur, sodium and chlorine (Figure 2.32) (Caplygin and Shaw, 1996). The two deposits are summarised in Table 2.5.

132°0'E 133°0'E 134°0'E 135°0'E 136°0'E

"Mintabie

Arckaringa BasinCoober Pedy"

Southern ArckaringaTroughs

Basement depth (m AHD)-492 –

0 –

1000 –

132°0'E

2000 –

2614 – 133°0'E 134°0'E

Tarcoola"

135°0'E 136°0'E

"Roxby Downs

REG 204218-023

Seismic lines

Basement depth contours (m)

Southern Arckaringa troughs

0 50 100 km

MGA Zone 53


Figure 2.26Arckaringa Basin, Basement Depth Structure Map

EA

RLY

PE

RM

IAN

Ass

elia

nS

akm

aria

n

Bio

stra

tU

nit *

*P

P1

PP

2

Lith

olog

y **

*

Dept

h (m

)AgeARKEETA 1

GR Sonic Density Resistivity Formation andSeismic Horizon

DepositionalEnvironment *

UnconventionalPlay

200

Upper Mount ToondinaFormation

Lower Mount ToondinaFormation

CoalGasification/CSG

400

600

800

Stuart RangeFormation

Stuart Range Formation (as in Arkeeta 1 WCR)

mfs?

SB?

Lacustrine to Brackish - Restricted Marine

Brackish - Restricted Marine

Brackish - Lacustrine

Shale Oil Biogenic Shale

Gas

1000 Boorthanna Formation* Depositional environment interpreted from

Arkeeta 1 palynological study (McBain, 1987)

1200

** Palynological zones from Arkeeta 1 palynological study (McBain, 1987) convertedto biostratigraphic units defined by Price et al, 1985

Basement

*** Lithology modified from Lake Phillipson Bore(after Hibburt, 1984, Figure 12)

DMITRE 204218-087

Figure 2.27 Southern Arckaringa Basin stratigraphy, based on Arkeeta 1. SB = Sequence Boundary; mfs = maximum flooding surface.

2.2.2 Coal Gasification PlayThe coal deposits of the Arckaringa Basin are being explored for their coal gasification and coal seam gas potential.

The Arckaringa Coal-to-Liquids and Power Project, a Joint Venture between Altona Energy and partner CNOOC New Energy Investment Co., Ltd. (CNOOC-NEI), is well advanced. The Joint Venture is completing a bankable feasibility study for mining part of the Wintinna coal deposit (10Mtpa base case) supplying coal to a coal-to-liquids plant with an output of 10 MMbbls perannum liquid fuels (mainly ultra clean diesel) as well as a co-generation power plant delivering 560 MW per annum to the national power grid (Schrape, 2011). Elsewhere in the Arckaringa Basin, Linc Energy is assessingcoal deposits for in-situ gasification and coal

seam gas prospectivity.


2.2.3 Coal Seam Gas PlayThe Arckaringa Basin coals are lignite A/ sub-bituminous C rank coals and are therefore not sufficiently mature to have generated significant thermogenic gas volumes. However the coal seams subcrop the Algebuckina Sandstone aquifer in part, meaning that microorganisms capable of producing methane in anaerobic conditions (methanogenic microorganisms) canbe introduced to the coal seams at the aquifer subcrop, resulting in biogenic gas generation.

2.2.4 Shale Oil and Biogenic ShaleGas PlaysSakmarian organic rich marine shales have been intersected in both the southern Arckaringa troughs and the Boorthanna Trough. In Arkeeta 1 (Phillipson Trough),all twelve samples from a 200 m interval

recorded TOC values >2% (up to 7.4%) and hydrogen index (HI7) values >400 (up to 654). The Tmax8 vs. HI cross plot shows that these organic rich shales are Type II source rocks at the threshold of oil generation (Figure 2.33).In the Boorthanna Trough Linc Energy’s 2011Arck 1 stratigraphic well intersected around70m of organic rich shale (Type I/II kerogen) with very high potential oil yields. Analyses indicate that the shales are at the onset of oil generation (Figure 2.34).

A detailed palynological study of cuttings and sidewall core samples from Arkeeta 1 (ECL Australia report, Appendix 6 in McBain,1987) indicates a lacustrine to brackish- restricted marine environment during deposition of the organic rich shales. High organic carbon contents and hydrogen indices indicate anoxic bottom water

7 Determined from RockEval measurements and is a standard measure of source rock potential to generate petroleum. HI is the quotient of the second peak of gas evolved by heating a sample of rock (S2) and the TOC of the same rock e.g. the fraction (yield) of organic matter that may be converted to petroleum.8 The temperature at which S2 is a maximum is Tmax inRockEval measurements

Table 2.3: Summary of Arckaringa Basin coal deposits

conditions suitable for the preservation of 2organic matter. The presence of mixed lacustrine to brackish marine environments and anoxic bottom water conditions suggests a Baltic Sea analogy, where high fresh-water runoff into a restricted sea-way results in density stratification of the water column. High fresh-water runoff (includingmelt-water) into restricted seaways along the Arckaringa troughs is likely to have resulted in similar conditions. In the Boorthanna Trough an organic petrology study of the organicrich shales has shown that very abundant alginite is present in a significant number of samples, and the dominant alginate form is a small tasmanitid (Cook, 1981, Moore, 1982).

DMITRE’s Energy Resources Division has recently undertaken preliminary workto identify sedimentary packages in the Arckaringa Basin in a sequence stratigraphic framework, focused on understandingthe distribution of the organic rich marine shales. This will contribute to regional studies of aquifers of the Arckaringa Basin and overlying younger basins that will be part of South Australian Government environmental assessments to be undertaken pursuant

Deposit No. of Persistent Seams Cumulative Coal Thickness (m) Top mineable coal (m)Wintinna 8 -10 15-25 104-240East Wintinna 6-7 Up to 20 220-300Murloocoppie 8 Averages 20 140-230Westfield 2 1-9 145-215

Table 2.4: Summary of Weedina Deposit

Deposit No. of Persistent Seams Cumulative Coal Thickness (m) Top mineable coal (m)Weedina 6 major seams

(several minor seams)35 130-150

Table 2.5: Summary of Lake Phillipson coalfield


Deposit No. of Persistent Seams Cumulative Coal Thickness (m) Top mineable coal (m)Phillipson 6 major seams Up to 25 50-143Ingomar Up to 6 major seams Up to 15 60-80

204218-031

210

(a)

(b)

(c)

East Wintinna

Murloocoppie

" Oodnadatta

5 kmWestfield Wintinna

Weedina

DMITRE 204218-029

Figure 2.28 Interpretation of seismic line 86AK-7 (migrated), showing the West Trough (left) and the Phillipson Trough (right). Top - section flattened on the Top Stuart Range horizon (pink). Middle - section flattened on the intra-Mount Toondina horizon (light blue – Note: this is not the MFS horizon). Bottom - Unflattened section. Seismic images from TrapTester.

1.0 secTWT

Arckaringa Basin

Phillipson

86AK-7

Coal deposit

Seismic lines (3D excluded) Seismic – post 2000 Seismic – 1950–1999

Coober" Pedy

Ingomar, Penrhyn

"

Tarcoola

75 km

134° 134°30´ 135°

0 30 km WINTINNA DEPOSIT

CadneyPark ‘Mt Willoughby’ ‘Arckaringa’

28°

EAST WINTINNA DEPOSIT

MURLOOCOPPIE DEPOSIT

WESTFIELD DEPOSIT

INSUFFICIENT DATA

DMITRE 204218-031

CUMULATIVE COAL THICKNESS (IN METRES)

5 to 10

10 to 15

15 to 2020+

Contours of overburden thickness(inmetres)

204218-031

Murloocoppie

Westfield Wintinna

East Wintinna

Weedina

Figure 2.29 The Arckaringa Coalfield.

ArckaringaBasin

Phillipson Ingomar, Penrhyn

Coal deposit 100 km

"

"

29°3

0'S

29°0

'S

85A

K1-3

86A

K-3B

86AK

-2D

29°3

0'S

29°0

'S

to the National Partnership Agreement for Coals Seam Gas and Large Coal Mines9. This will see the State Government act as the accredited one-stop-shop for State and Federal government environmentalassessments pursuant to the Commonwealth Environmental Protection, Biodiversity and Conservation Act 1999. These water resource studies are expected to be referred to the Commonwealth Government’s Independent Expert Scientific Committee to underpin informed regulation of, for example, proposed development of coal resources in the Arckaringa Basin.

A preliminary correlation of the Early Permian succession in the southern Arckaringa

troughs and the Boorthanna Trough has 2been postulated; in particular the organic rich marine shales appear to have been deposited in a transgressive system thatcan be identified in both areas of the basin(Figure 2.35) (Menpes, 2012).

The organic rich shales will be an exciting shale oil target if sufficient maturity levels can be identified in the basin. Alternatively biogenically generated shale gas may be a possibility in parts of the basin.

9 For some details, see: www.pm.gov.au/press-office/south-australia-signs-coal-seam-gas-agreement

134°0'E

"Mabel Creek

: Nuba 1 134°30'E

") Manguri

ªStuart Range 3

" CooberPedy

135°0'E

Tarcoola "

ADELAIDE "

ªWallira 2

: Howard Hill 1

Ingomar

ª Wallira 1

!

Wirrida")

ª Lake Phillipson Bore 1ª Arkeeta 1

"

Garford

" Sandstone

Phillipson ª Muddy Tank 1

" Ingomar

! "Comet

Wirrida

")Wirrida

GinaMcDouall Peak

Jumbuck Sequoia "") Gina

" Commonwealth Hill

"Gina Outstation

Mirikata

Hawks Nest134°0'E 134°30'E 135°0'E

REG 204218-047

Southern Arckaringa troughsGlacier flow

C

oal

fields


Seismic linesGOMA seismic line

Seismic Lines – 1980 to 1989

Petroleum wellsª Dry hole

: Proposed or currently drilling 0 10 20 km

MGA Zone 53

Figure 2.30Southern Arckaringa Basin troughs showing inferred glacier flow direction.

ME

TRE

S

LAKE PHILLIPSON DEPOSIT

PioneerSwamp

Lake Phillipson

Lake Phillipson BoreTROUGH

Lake Wirrida

TROUGH

‘Ingomar’

Coronation Dam

0 10 km

QUATERNARY–TERTIARYSands and clays

CRETACEOUS–JURASSIC Sandstones and gravels overlain in part by mudstones

PERMIANMOUNT TOONDINA FORMATION Siltstones and mudstones with coal; minor sandstones

PRECAMBRIANCrystalline basement

Fault

A WEST TROUGH PHILLIPSON TROUGH A’

120

80 ? ?

INSUFFICIENT DATA40

0

-400 5 km

-80NOTE: 25:1 VERTICAL SCALE EXAGGERATION

Figure 2.31Lake Phillipson Coal Deposit, Phillipson and West troughs

A A

CPC2Depth

(m)0 CPCIR

CPC4R CPC10

CPC5 CPC8R CPC12

50

?

100

?

150?

V/H=1/1000 5

KILOMETRES

Cored interval

CAINOZOIC CRETACEOUS

Bulldog Shale CRETACEOUS – JURASSIC Cadna-

owie Formation and Algebuckina Sandstone

PERMIANMt Toondina Formation, coal

PERMIAN – CARBONIFEROUSStuart Range Formation

LOCALITY

CPC2CPC1R

CPC4R CPC5

CPC10

0 5 10CPC8R

KILOMETRES PENRHYN TROUGH

CPC12204218-089

Figure 2.32Ingomar Coal Deposit, Penrhyn Trough

1000

900

Hydrogen Index (HI)

I

2Hydrogen Index (HI)

I800

800

700 II

600

500

400

300

200

700

600

500

400

300

200

100

II

III

100 III0

380 400 420 440 460 480 500

Tmax (°C) 204218_091

0380 400 420 440 460 480 500 Figure 2.34Tmax vs. Hi cross plot for core

samples from Arck 1, Boorthanna Trough (modifiedTmax (°C) 204218-090 from Linc Energy ASX Announcement, 27

Figure 2.33 Tmax vs. Hi cross plot for cuttings samples from Arkeeta 1, Phillipson Trough (from Appendix 5 in Arkeeta 1 Well Completion Report, McBain, 1987)

September 2011)

TWT (ms)

Weedina Coal Deposit

0

500

1000

Mount Toondina Formation delta progrades into basin from east HST

mfs

SB

Pre-Permian basement

1500

Murloocoppie

WestfieldWintinna

East Wintinna

Weedina5km

ArckaringaBasin 84-XES

204218-030

Phillipson Ingomar, Penrhyn

Figure 2.35Seismic line 84-XES, Boorthanna Trough, flattened on blue horizon interpreted to be a maximum flooding surface. 8 x vertical exaggeration. Organic rich shales marine shales are interpreted between the

Coal deposit100 km yellow horizon (sequence boundary) and blue horizon


(maximum flooding surface).

ª1 ª

ª 2

ª

VIC

TOR

IA37

°0'S

2.3 Otway Basin

The Otway Basin is a Jurassic to Cretaceous rift basin with a Tertiary cover (Gambier Basin) that occurs 300 km south-east of Adelaide (Figure 2.36). The basin extends into Victoria and the offshore in both states. The onshore area in South Australia covers9650 km2 with target depths for petroleumexploration anywhere between 1000 to 4000 m in the onshore portion of the basin.

Two major sedimentary sequences are targets for petroleum exploration in South Australia.

• The Berriasian to Hauterivian sequence (Crayfish Group, early rift) is known only from the northern area, where E–W and NW–SE trending half-grabens (Robe,

Penola, St Clair and Tantanoola Troughs) contain fluvial to lacustrine sediments that are proven gas reservoirs (Figures2.37, 2.38, 2.39).

• The Late Cretaceous sequence (Sherbrook Group) occurs as a deltaic to deep-water wedge south of theTartwaup Hinge (Figures 2.37, 2.38, 2.39).

2.3.1 Shale gas playThe principal targets for shale gas in the onshore Otway Basin are thick basal shale sequences within the Upper and Lower Sawpit shales of the Otway Supergroup, and the underlying Casterton Formation which is separated from the Otway Supergroup bya regional unconformity (Figure 2.40). These non-marine shales all have good shale gas potential in the deeper portions of the basinand are discussed as follows.

Marla ")") Oodnadatta

")

140°0'E 141°0'E

Coober Pedy ") Moomba

")Ceduna

Leigh Creek ")

Port Augusta")

127 610

PL13

Port Lincoln ")")

ADELAIDE Kingstonª") ªª

Mount Gambier ") ª ª ª ªª ª ªPetroleum tenements

Exploration licence (PEL)

Exploration licence application (PELA)

OT2012-A ªª ª¨ ª ª ª

Production licence (PPL)Robe

ª¨ ")186

+ ª+ª

Otway Basin

+ ª¨

ªª ª¨' +ª

Retention licence (PRL)Onshore acreage release block - bids close 4 April 2013Offshore acreage release block -

i'ª154 1

8ª6ª

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ªª ª

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495

¨") Penola

PL16

bids close 8 November 2012

+PL19ªg 1g68¨ ' 1¨

Pipeline licence (PL) – gas ª ª ª ª i2'

+g'g'62 '+2'g0

PL19

Petroleum wells* CO2

g CO2 with oil shows

Beachport ") ª ª+

ª ªªOT2012-A

202202PL3

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ª Dry hole ªªª PL4

ªªª¨ Dry hole with oil shows ª ª' Gas+ Gas showsg Gas well with oil shows

S12-4 154 ªª

496ªªª

ª

38°0

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") ª' Oil Mount Gambier

i' Oil and gas shows ª 82211 Oil and gas ª ªªª g

Otway Basin outlinePark or reserve –no petroleum exploration access

0 10 20 30 40 km

MGA Zone 54

82 496iªi'¨ ª¨

i' 204218-048

Figure 2.36Otway Basin, South Australia. Infrastructure and tenements.

2

P

SOU

TH A

UST

RA

LIA

VIC

T OR

IA

2LIMIT OF

CRAYFISH GROUP

LAKE ELIZA HIGH LUCINDALE

HIGH

WOAKWINE TERRACE

Morum High

CHCHAMA TERRACE BEACHPORT

HIGH

RIVOLI TROUGH Kalangadoo 1

Ladbroke Grove field34% CO

RENDELSHAM HIGH

Tertiary Troughs

Late Cretaceous Highs

Late Cretaceous Troughs

Early Cretaceous Highs

Early Cretaceous Troughs0 25

VolcanicsKILOMETRES

204218-092

Figure 2.37 Structural elements and wells.

Casterton FormationThe Casterton Formation represents the richest source rock of the Otway Supergroup that is thought to be the source of commercial gas accumulations now in production in the Penola Trough region. It comprises pre-rift to early syn-rift interbedded shales, siltstones and sandstones andvolcanic lithologies that have only been sparsely intersected. The formation reaches a maximum known thickness of 230 m in Casterton 1 well (Victorian Type Section) and 43 m in Sawpit 1 (SA reference section;Figure 2.41) although it is thought to be up to500 m in the Robe Trough at depths greater than 4000 m based on seismic interpretation (Morton and Drexel, 1995). To date, the formation has been mostly intersected on the northern flanks where it is marginally mature for oil (as evidenced by oil shows in several wells) but not viable as a shale gas play.

TOC values range from 0.6 to 9%, averaging1.9% (39 samples; 6 wells). The Tmax vs. HI cross plot shows that these organic


rich shales are Type II (algal rich oil prone kerogen) to Type III (Gas prone) at the threshold of the oil window (Figure 2.42). However, in the deeper portions of the Penola, Robe and Saint Clair troughs they are expected to be gas prone with liquids potential (Figure 2.45).

Maturity modelling indicates that the Casterton Formation lies within the gas window at depths in excess of 3800 m in the Penola Trough and Robe Trough (Figure 2.45) but may be locally shallower in the Robe Trough where seismic is poor.

Somerton Energy is exploring the northern margin of the Otway Basin in Victoria and estimates the Casterton Formation Victorian PEP 171 could contain more than 25 trillion cubic feet of gas and significant oil volumes (see Section 4.1.6).

Upper and Lower Sawpit shalesThe Upper and Lower Sawpit shales representlacustrine deposits at the base of the Crayfish

OTW

AY

SU

PE

RG

RO

UP

CR

AY

FIS

H

GR

OU

PW

AN

GE

RR

IP

GR

OU

PH

EYTE

SBU

RY

GRO

UP

SH

ER

BR

OO

K G

RO

UP

SHIP

WR

ECK

SUPG

RO

UP

CO

ND

EN

SE

D S

EC

TIO

N

SH

ALE

GA

S

SHAL

E OI

L

CO

AL

2042

18_0

93

TIME (Ma)

10

CHRONOSTRATIGRAPHY

SERIES DIVISION STAGES

HOLOCENE

PLIOCENE-PLEISTOCENE

ROCK UNIT

RECENT VOLCANICS

OIL AND GAS OCCURRENCES

MIOCENE25

OLIGOCENE

Early

LateEarly

Serravallian

Burdigalian to Rupelian

Gambier Limestone400 m

21 mGellibrand

Marl36

Late Priabonian Compton Cgl 28 m

MiddleBartonian

Lutetian

Narrawaturk Marl Mepunga Fm

EOCENE

54

PALEOCENE

65

Early

Late

Early

Ypresian

Thanetian

Danian

Maastrictian

Dilwyn Formation

Pember Mudstone

Pebble Point Formation

Timboon

593 m

198 m

90 m

Fahley 1

Curdie 1

Lindon 1

73 Sandstone

Campanian

PaaratteFormation

1590 m

83

87.5

Late

SantonianSlope

fan

1987 m

ArgonautMember

Breaksea Reef 1

Port Campbell 1Caroline 1 (Co2)North Paaratte 3

88.5 Coniacian

Turonian

Belfast Mudstone

1362 m

Westgate 1A Minerva 1Normanby 1A

Flaxman Fm Iona 1

91

96 CRETACEOUSCenomanian

Albian

Waarre Ss

Copa Fm167 m

?

Eumeralla

Formation

204 m

unnamed ss

Grumby 1North Paaratte 1Caroline 1Minerva 1La Bella 1Thylacine 1

Geographe 1

Crayfish 1APort Campbell 4Windermere 1Crayfish 1Katnook 2Windermere 2

113

119

125

131

Early

Aptian

Barremian

Hauterivian

2500 m+ 21 m

Windermere Sandstone Member

Katnook Ss690 m

Laira Formation890 m

upper Sawpit shale mbr

Katnook 1

Katnook Field Haselgrove Field Redman Field Ladbroke Grove Field Laira 1Crayfish 1A

138

144

Valanginian

Berriasian

Tithonian

Pretty HillFormation

?5000 mSawpit ss mbr

Wynn 1Jacaranda Ridge 1Killanoola 1

lower Sawpit shale member with unnamed

150

300

550

JURASSIC

PALAEOZOIC

LateKimmeridgian

CastertonFormation

KANMANTOO GROUP EQUIVALENTS

?500 m

shale at base

Sawpit 1

Kalangadoo 1 (CO )2

Figure 2.38 Stratigraphic column, Otway Basin

Two

way

tim

e (s

)

A A’0 5

KILOMETRES

CDP 2800 2600 2400 2200 2000 1800 16000

1400 1200 1000 800 600 400 200 30338500 800 1000 1200 1400 1600 1800 2000 2200 2352

Eumeralla Fm

0.5

1

1.5

2

Upper Laira Formation

sands

Pretty Hill Fm

Laira FmUpper Sawpit shale member

Crayfish Gp

Sawpit ss mbr

Lower Sawpit shale member

Basement

2.5

3

3.224

RESERVOIR SANDS WITH SOME TIGHT GAS POTENTIAL

204218-094

Figure 2.39 Composite seismic section, Penola Trough, Northern Otway Basin.

Group and can reach thicknesses up900 m and 250 m thick respectively (Figures2.38, 2.39 and 2.40). The shales are better developed on the northern flank of the Penola Trough (Figures 2.39 and 2.44), away from the axial drainage in the central part of the trough which is dominated by stacked fluvial channel fill of Pretty Hill Sandstone or Sawpit Sandstone (Boult and Hibburt, 2002).

Rock Eval analyses of samples from theUpper and Lower Sawpit Shales indicate that the shale is dominated by Type III gas prone kerogen with some Type II algal rich kerogen present (Figure 2.43). TOC values range 0.37 to 2.61% and average 1.12% (10 wells, 87 samples).

Maturity modelling in the Katnook area of the Penola Trough indicates that peak gas generation from the Casterton Formation and Upper and Lower Sawpit Shalesoccurred in the Maastrichtian at ~73 Ma and has remained in the gas window to

present day at depths below ~3800 m (Figure 2.45).


Complex faulting resulting from rift tectonics could be advantageous for unconventional gas through enhancement of natural fracture networks that would improve connection with, and drainage of, the rock matrix.

The prospective shale units have yet to be fully penetrated in the centre of the Penola Trough so an understanding of gas saturation and likelihood of water drive is yet to be established.

Access to infrastructure is another key factor in addressing the economic viability of both the Casterton and Sawpit Shale gas plays.

2.3.2 Shale Oil PlayCasterton FormationAs discussed in section 2.3.1, the Casterton Formation is most likely to be prospective for shale oil. The Tmax vs. HI cross plot shows that these organic rich shales are Type II (algal rich oil prone kerogen) to Type III (gas prone) at the threshold of the oil window (Figure 2.42).

Figure 2.40 Crayfish Group of Stratigraphy.

This diagram provides a stratigraphic summary of key units of interest in this study. The left most panel is a dual GR display with lithology colourfill–orange represents sandstone and brown represents mud rocks. Logs are a composite from 3 wells in the Penola Trough and show depths in metres from each of the three well intervals. The blue log represents the Spontaneous Potential log with a variable sand cutoff that has been coloured yellow to highlight the main sandstones. Unit distribution and thickness is based on regional seismic and well analysis along with data from Boultet al. (2002), Camac& Boult(2008)and various well completion reports. Porosity and permeability trends have been generalised from well completion report data and core analyses.

The conclusions and recommendations expressed in this material represent the opinions of the authors based on the data available to them. The opinions and recommendations provided from this information are in response to a request from the client and no liability is accepted for commercial decisions or actions resulting from them. Please cite this work appropriately if portions of it are copied or altered for use in other documents. The correct citation is: Krassay A, et al 2009. Otway BasinHot Sedimentary Aquifers & SEEBASE™ Project, Confidential Report to PIRSA-GA-DPI Vic.

Cas

tert

on

For

mat

ion

Ref

eren

ce

Sec

tion

Bas

emen

t

LCA

-RW

flank of the Otway Basin represents the most prospective area for shale oil play (Figure 2.45) where the Casterton Formation lies in the oil window at depths between2300 m to ~3050 m (early mature for oil;Ro 0.7 to 1.0%) and ~3050 m to 3800 m (later mature for oil; Ro 1.0 to 1.3%) in the Robe, Penola, Rivoli and St. Clair troughs.

2.3.3 Tight gas playPotential also exists for tight gas in the basal sands of the Pretty Hill Formation, particularly in the deeper portions of the Penola and Robe Troughs.

1000

900

800

700

600

500

400

300

200

100

I

II

III

Sawpit 1Robertson 1Camelback 1Lake Hawdon 1Penola 1

0380 400 420 440 460 480 500 520

T max (oC)

Figure 2.42 Van Krevelen plot – Casterton Formation.

SAWPIT 1

Gamma Ray log

0 (API units)

Depth(m)

200 140

Sonic log

(flsec/ft)

40 1000

900

800

700

600

Hydrogen Index (HI)

ICamelback 1Killanoola 1Lake Hawdon 1Penley 1

Pyrus 1Reedy Creek 1Sawpit 1St Clair 1 IIViewbank 1

Wynn 1

2500

500

400

300

200

100 III

PALYNOZONES

204218-096

0UCA = Upper C. australiensis

300 320 340 360 380 400 420 440 460 480 500 520

T max (°C) 204218-098LCA - RW = Lower C. australiensis to R. watherooensis

Figure 2.41Casterton Formation, SA reference section.

Figure 2.43Van Krevelen plot – Upper and LowerSawpit Shales.


Kalangadoo1 Depth

Katnook2 Depth Sawpit 1 Depth

Robertson1 Depth

Robertson2 Depth

BoolLagoon 1 Depth

GR DT (m) GR DT (m) GR DT (m) GR DT (m) GR DT (m) (m)

Eumeralla Formation South Australian reference section

Katnook Sandstone type section

0 0

500 500

1000 1000

1500 1500

2000 2000

Laira Fm.

0

500

1000

1500

2000

Sawpit sandstone

0

500

1000

1500

0

500

1000

1500

Kingston SE

Luncindale

Bool Lagoon 1

0

500

Naracoorte

Less than1% M. evansii

2500 2500 2500 member Robe Robertson 2Robertson 1

Sawpit 1Penola

Laira Formation type section

3000

?Pretty Hill Fm

Casterton Formation South Australian reference section

BeachportKatnook 2

Kalangadoo 1Millicent

MountGambier

Pretty Hill Formation South Australian reference section 204218-099

Lithological zones

Tertiary

Sherbrook Group

Eumeralla Formation

Windermere / Katnook Sandstone

Pretty Hill Formation shales / Laira Formation

Pretty Hill Formation sands

Casterton Formation

Basement

Palynological zones

P. pannosus

C. paradoxa

C. striatus

upper C. hughesi

lower C. hughesi

upper F. wonthaggiensis

undifferentiated F. wonthaggiensis

lower F. wonthaggiensis

upper C. australiensis

lower C. australiensis toR. watherooens

L. balmei

T. longus

Cuttings

Cores and sidewall cores

Figure 2.44 Schematic cross section through Penola Trough.

5-020

-2 5

00

3

0

Sout

h A

ustra

liaV

icto

ria

139 30' E 139 45' E 140 E 140 15' E 140 30' E 140 45' E 141 E2

0 5 10 15 20

Kilometres

37 S

37 15' S 37 15' S

5

3

37 30' S

Vitrinite reflectanceMaturity 8

Depth contour (m)

<0.5% Immature

37 30' S

0.5–0.7% Early mature (oil)

0.7–1.0% Mid mature (oil)

1.0–1.3% Late mature (oil)

1.3–2.6% Gas penetration

Over mature

NO DATA

CO 2

139 30' E 139 45' E 140 E 140 15' E 140 30' E 140 45' E 141 E

204218-100

Figure 2.45 Maturity map, base Casterton Formation.

VIC


2.4 Gambier Basin

The Gambier Basin unconformably overlies the Mesozoic Otway Basin and comprises up to 1000 m of paralic to marine Tertiary sediments. Its northern boundary with theTertiary Murray Basin is diffuse and is generally taken along the basement high of the Padthaway Ridge (Figure 2.46).

2.4.1 Coal Gasification PlayThe Late Palaeocene to Mid Eocene Dilwyn Formation comprises fluvial to restricted marine facies with well developed lignitic intervals that generally occur as a single seam up to 9 m at Kingston where a deposit27 km long and up to 5 km wide was identified by Western Mining Corporation in 1979 with 985 million tonnes resource delineated. In the northern area of the

Kingston Coal Deposit a total thicknessof 12 m is attained where the main seam coalesces with an overlying, less well developed lignite. Overburden thickness ranges from 20 to 80 m.

Hybrid Energy Australia Pty. Ltd (a fully owned subsidiary of Strike Energy Ltd) has successfully gasified the lignite through testing by the University of Adelaide who were able to prove that a continuous operation is technically feasible. The company has identified a 578.3 million tonne coal resource of which 523.5 million tonnes has been measured.

2.5 Pedirka BasinThe Pedirka Basin covers an area of150 000 km2, approximately one fifth ofwhich is in South Australia and the remainder in the Northern Territory (Figure 2.47).The Pedirka Basin overlies the SE Amadeus Basin and western Warburton Basin which were deformed during the Alice Spring Orogeny

KINGSTON COAL

DEPOSIT

Kingston

Robe

Lucindale

MURRAY BASIN

Naracoorte

and possibly during Delamerian Orogenies. A final NW–SE compressional phase of the Alice Springs Orogeny in the Mid to Late Carboniferous initiated deposition in the Pedirka Basin and created thrust faults (e.g. Mt Hammersley). Permo-Carboniferous sediments were subsequently deposited in a tectonically quiescent crustal sag phase.

GAMBIER

Beachport

PenolaThe Pedirka Basin in SA comprises a shallow western depocentre and a deeper eastern depocentre separated by the Dalhousie-

Millicent Kalangadoo

Allen'sMcDills Ridge. This ridge comprises shallow folded and faulted Devonian and older

BASIN SnuggeryTantanoola

Quarry

rocks, with a thin cover of late Palaeozoic

Approximate southern limit

of Tertiary

0 50

KILOMETRES

Mt Gambier

Pt MacDonnell

204218-101

sediments preserved across the ridge, linking the two depocentres (Figure 2.48). The western depocentre contains up to 1000mof Carboniferous-Early Permian sediments generally at depths less than 1500 m whilst to the east, sediments are 300-400 m thick and at depths exceeding 2000 m (Figure 2.49). The Pedirka Basin is entirely overlain by up

to 2500 m of Triassic to Late CretaceousFigure 2.46 Gambier Basin showing extent of KingstonCoal Deposit.

sediments of the Simpson and Eromanga basins.

Mokari 1ª

ª

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27°0

'S26

°0'S

27°0

'S26

°0'S

3

ª

ªª

134°0'E

ª18

135°0'E 136°0'ENORTHERN TERRITORY

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137°0'E

Simpson Desert (RR)

Oolarinna 1

2

ª¨ Erabena 1

ªCur 1 ª14

Witjira (NP)

ªMount Hammersley 1

ªWitcherrie 1

ªMount Crispe 1

ªPurni 1 Glen Joyce 1ª

ª

ªMacumba 1

Simpson Desert (CP)

ª2 ªª4

5ªKillumi 1

Walkandi 1¨

ª

ªEOB 1

Pedirka Basin

Eromanga Basin

Warburton Basin

Simpson Basin

ª1A ª1A 2ª

Miandana 1¨

Nicholson 1

26

Coongra 12 Todmorden 1

Yardinna 12 ªªª¨ 22

ª23

5

Officer Basin

ªLambina 1

ª 3

ªOodnadatta 1

Oodnadatta Town Bore 2ª 24ªComalco Uphole 2

ª9

Arckaringa Basin

ªMount Willoughby 1

ª" Oodnadatta

Toodla 1

10134°0'Eª "

Oodnadatta

SOUTH AUSTRALIA

135°0'E 2::1Aª

136°0'E 137°0'E

DMITRE 204218-049

Petroleum wells

ª Dry hole

Parks with petroleum exploration accessParks with no petroleum

0 25 50 km

Equidistant Conic

ª¨ Dry hole with oil shows exploration access

"ADELAIDE Seismic – post 2000

Seismic – 1950–1999

Figure 2.47 Pedirka Basin, South Australia. Wells and seismic lines.

MUSGRAVE ERINGA DALHOUSIE / McDILLS POOLOWANNABLOCK TROUGH TREND TROUGH

Depth in metres500 AFMECO

CUR 3 MOUNT BARR PROSPECT

MOUNT HAMMERSLEY 1

Approx. 500 m uplift

WITCHERRIE 1 PURNI 1 MOKARI 1 MACUMBA 1 WALKANDI 1

MSLOODNADATTA FM

BULLDOG SHALE

-500

CADNA-OWIE FM BIRKHEAD FM

EQUIV ?.

ALGEBUCKINA SST

WINTON FM

-1000

-1500

-2000

-2500

0 20 40

KILOMETRES

Source Rock Unconformity Fault

CAMBRIAN

ORD?

ORDOVICIAN

? DEV ORDOVICIAN

TOOLEBUC FM

MACKUNDA FM

ALLARU MDS

WALLUMBILLA FM

CADNA-OWIE FM

ALGEBUCKINA SST

Lake Eyre Basin (Tertiary - Recent) Eromanga Basin (Jurassic - Cretaceous)

Simpson Basin (Triassic)

PEDIRKA BASIN

NORTHERN TERRITORY

-3000 Pedirka Basin (Permo - Carboniferous) Amadeus Basin (Cambrian - Devonian) AdelaideanMusgrave Block (Proterozoic)

Mt Hammersley 1

0 100KILOMETRES

SIMPSON

Walkandi 1BASIN

ORDOVICIAN

204218-012


Figure 2.48 Cross-section through the Pedirka Basin.

ªMokari 1ª

ª

ª

ª

27°0

'S26

°0'S

27°0

'S26

°0'S

3

ª

ª

134°0'E

ª18

135°0'E 136°0'ENORTHERN TERRITORY

ªDalmatia 1

Mount Hammersley 1

Witcherrie 1ª

Purni 1 Glen Joyce 1

ª

137°0'E

ªOolarinna 1

ª¨ Erabena 1

ªCur 1 ª

14

ªª

Mount Crispe 1ª

Macumba 1

ª2 ª

ª4

ª5 Pedirka Basin

ªKillumi 1

Walkandi 1¨

ªEOB 1

ª1A ª

1A 2

ª

Miandana 1¨

Marla

Nicholson 1

2

6

Coongra 1

ª2 Todmorden 1

Yardinna 12 ªªª¨ 22

ª ª23

5 ªLambina 1

ª 3

ªOodnadatta 1

Oodnadatta Town Bore 2

ªªª

ª 24ªComalco Uphole 2

ª9 ª

Mount Willoughby 1

"ª Oodnadatta

Toodla 110

134°0'Eª

"

Oodnadatta

SOUTH AUSTRALIA

135°0'E 2::1A

ª136°0'E 137°0'E

DMITRE 204218-050

Petroleum wells

ª Dry hole

0 25 50 km

Equidistant Conic

"ADELAIDE

ª¨ Dry hole with oil shows

Figure 2.49Top Purni Formation depth structure map.

The Permo-Carboniferous succession in the Pedirka Basin has been divided into two formations (Figure 2.50). The lowermostunit, the Crown Point Formation, consists of sandstone and extensive muddy to cobbly diamictite deposited in periglacial,interglacial, fluvioglacial and glaciolacustrineenvironments. The overlying Purni Formation is equivalent to the Patchawarra Formation of the Cooper Basin and was deposited in an extensive coal swamp and floodplain environment crossed by high-sinuosity fluvial channels.

To mid 2012, 10 petroleum wells have been drilled, and almost 6000 line kilometres of2D seismic data have been acquired in thePedirka Basin (Figure 2.47).

2.5.1 Coal Seam Gas Play

Coal seams are characteristic of the upper member of the Purni Formation. A thermogenic coal seam gas play fairway


may be present in the deeper eastern depocentre, and sweet spots for biogenic coal seam gas may be present in parts of the western depocentre.

In the eastern depocentre, thermal maturity increases with increasing depth of burial beneath a thickening Eromanga Basin succession. Ro values range from0.79 to 0.94% in Macumba and Oolarinna respectively at depths greater than 2200 m. Mud gas peaks corresponding to coal seams were recorded in Oolarinna 1, with 82 units total gas recorded over a 6 m coal seamwith shale partings.

The Purni coals are immature for thermogenic gas generation in the western depocentre, with Ro measurements ranging from 0.45 to 0.47%. However the coalseams subcrop the Algebuckina Sandstone aquifer in part, meaning that methanogenic bacteria carried in meteoric waters can be

Coa

l20

4218

-103

Mokari 11800

1850

1900

1950

2000

2050

2100

2150

2200

2250

PurniFormation

Crown PointFormation

PertatatakaFormation

2.6 Simpson Basin 2

The Simpson Basin has an area of100,000 km2, approximately half of which is in South Australia and the remainder in the Northern Territory and Queensland. It is a circular, poorly defined depression with one major depocentre, the Poolowanna Trough (Figure 2.51). The basin unconformably overlies Pedirka Basin and western Warburton Basin and is overlain by the Eromanga Basin.

The Northern Territory Geological Survey has reviewed the Simpson Basin and are proposing to re-define the Triassic Section as part of the Pedirka Basin (Munson, pers comm May 2012).

Simpson Basin stratigraphy has been divided into two formations. The Early to Middle Triassic Walkandi Formation consists ofnon-marine interbedded red-brown shale, green siltstone and fine grained sandstone, restricted to the Poolowanna Trough.The maximum thickness of the WalkandiFormation is 134 m in Poolowanna 2.

The overlying Late Triassic Peera Peera Formation consists of basal grey shale, siltstone, minor sandstone and coal, overlain by upwardly fining sandstone and an upper black carbonaceous shale. The PeeraPeera Formation was deposited in a high- sinuosity fluvial environment with possible development of lakes on the floodplain. The maximum thickness of the Peera Peera Formation is 190 m in Walkandi 1(Figure 2.52).

Figure 2.50 Mokari 1 Permian stratigraphy (being updated).

introduced to the coal seams, and biogenic gas generation is possible. Most significant production of shallow biogenic gas comes from depths of less than 600 m, although the depth of the biogenic floor may vary from basin to basin (Shurr and Ridgley, 2002).

2.5.2 Shale Gas PlayThe absence of thick, laterally

extensive shale and the overall low maturity of the succession downgrades the shale gas potential of this basin.


The Simpson basin is overlain by the non- marine fluvio-lacustrine Early Jurassic Poolowanna Formation, Mid Jurassic Algebuckina Sandstone and Early Cretaceous Cadna-owie Formation (Figure 2.53). The Cretaceous marinetransgression resulted in a thick sequence of shales and shore-face sands with restricted marine conditions during deposition of the Toolebuc Formation. The marine succession is overlain by non-marine fluvial-coal swamp Winton Formation. The Eromanga Basin is unconformably overlain by fluvio-lacustrine sediments and silcretes of the Tertiary Lake Eyre Basin.

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135°0'E 136°0'E 137°0'E 138°0'E 139°0'E 140°0'E 141°0'E

NORTHERN TERRITORY

ª ªª ª ª

ª Witjªira (NP)

ª¨

Simpsoªn Desert (RR)

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Simpson Desert (CP)¨¨

Poolowanna

Simpson Basin

QUEENSLAND

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Pedirka Basin ª¨

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Figure 2.51 Simpson Basin, South Australia. Wells and seismic lines.

To mid 2012, 6 petroleum wells havebeen drilled, and approximately 7200 line kilometres of 2D seismic data have been acquired in the Simpson Basin (Figure 2.51).

2.6.1 Coal Seam Gas PlayThe Poolowanna Trough (Figure 2.52) formsthe major Triassic-Recent depocentre in the region, containing up to 2,500 m of non-marine sandstone, coal and siltstone and marine shales. Significant oil showsin Walkandi 1 and the oil recoveries in Poolowanna 1 indicate that hydrocarbon generation and migration has occurred in the deeper parts of the trough.

The oxidised nature of the WalkandiFormation redbeds downgrades their source

potential. However, the overlying Peera Peera Formation is rich in organic matter (TOC up to 5%) and should be oil mature in the Poolowanna Trough. Further exploration would be needed to determine if the coals are sufficiently mature to have generated significant gas volumes for a Coal Seam Gas play.

2.6.2 Shale Gas PlayThe absence of thick, laterally extensive shale and the overall low maturity of the succession downgrades the shale gas potential of this basin. The Peera Peera Formation is not mature enough to have generated gas, but may have potential for shale oil.

202770

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EROMANGA BASINHutton and Algebuckina Sandstones

Poolowanna Formation

PEDIRKA BASINPurni Formation

Crown Point Formation

Cuddapan Formation SIMPSON BASIN

Peera Peera Formation

Walkandi Formation

WARBURTON BASIN

ADELAIDEAN

202770-018

Figure 2.52 Wireline log correlation from Mokari 1 to Koonchera 1.

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The eastern Warburton Basin (Figures 2.54,2.55) is essentially a fold belt deformed and uplifted during the Carboniferous Alice Springs Orogeny beneath the Cooper Basin. Structural dip varies from sub-horizontal beneath the Patchawarra Trough and GMI Ridge to vertical and locally overturned. Early to Middle Carboniferous Big Lake Suite granitic intrusives beneath the Nappamerri

Trough were responsible for local contact metamorphism of Cambrian country rock.

A stratigraphic summary of the eastern Warburton Basin is shown in Figure 2.56. Four seismic sequence sets have been recognised in Figure 2.56:

• Sequence Є1 comprises Early Cambrian acid-intermediate volcanics and tuff of the Mooracoochie volcanics;

• Sequence Є2 is characterised by dolomite with vuggy and moldic porosity (Diamond Bog Dolomite), indicating a high-stand deposit altered by sub-aerial exposure;

• Sequence Є3 is characterised by aback-stepping style and several stacked cycles of catch-up and keep-up carbonate systems (lower Kalladeina Formation/Dullingari Group);

133°0'E 134°0'E 135°0'E 136°0'E 137°0'E 138°0'E 139°0'E 140°0'E 141°0'E

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204218-052

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Figure 2.54Well and seismic line coverage, Warburton Basin.

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204218-053

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Figure 2.55 Top Warburton Basin depth structure map.

• Sequence Є4 was deposited after a major transgression following low relative sea level (Upper Kalladeina Formation/ Dullingari Group). The succeeding high- stand systems tract can be subdivided into three major parasequence sets: early high-stand aggradation, middle high-stand progradation and late high- stand regression.

The uppermost sequence (Innamincka Formation) is characterised by numerous stacked shoaling-upward parasequences, which may indicate a shallow stable shelf under influence of frequent sea-level fluctuations. An increase in siliciclastic content at the expense of carbonate suggests an approaching shoreline. Shoaling is recorded on the Coongie–Cuttapirrieshelf, and the Innamincka Formation continues this trend to shallow subtidal water depths as part of a deltaic complex with clastics probably derived

from the Proterozoic Arunta Block to the north. The


Pando Formation is an extensive marine shelf sand equivalent to the lower Innamincka Formation. The Narcoonowie Formationis a laterally equivalent lowstand fan(Figure 2.56).

Black shale of the Dullingari Group was deposited in deep water of the Tilparee Trough to the south during the Early Ordovician. This trough, bordered to the north by the Innamincka Shelf and to the south by the Gnalta Shelf, formed part ofthe Larapintine Sea which extended through the Warburton and Amadeus basins to the Canning Basin.

Source rock quality of samples principally from the Kalladeina Formation is poor to fair. With the exception of anomalouslylow maturity indices from Kalladeina 1, the succession below 3000 m is late-mature to post-mature for oil. Organic matter is mainly Type II kerogen derived from marine algal– bacterial precursors.

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MIDDLE CARBONIF

ROCK UNITNW (shelf) SE (basin)

COOPER-EROMANGA BASINS

Big Lake Suite

Mudrangie Sandstone

LITHOLOGY

+ + + + ++ + + + +

STRATIGRAPHIC SEQUENCES COMMENTS

Granodiorite intrusives (310-330 Ma) ALICE SPRINGS OROGENY

Innamincka Formation: extensive deltaic

>55 m

Lower Red Beds

HST

interbedded siltstone and rippled glauconiticsandstone. Acritarchs, bryozoa, conodonts.

Mudrangie Sandstone: prograding shoreline.

Pondrinie Basalt: extrusive basalt.Pondrinie

Basalt30 m

v v v v v

PandoFormation

240 m

upper member

lower member

NarcoonowieFormation

Lycosa Formation

200 m

v

LST

HST

TST

HST

Pando Formation: bioturbated glauconitic 'hot' sandstone, gas in Moolalla/(?low stand wedge), good reservoir properties. Narcoonowie Formation: lowstand fan.Upper Member: shelf carbonates andsiliciclastics, trilobites and conodonts. Dullingari Group and Lycosa Formation: slope (dark grey shale and lime mudstone, slump breccia) and basinal shale, siltstone and thin spicular chert, pyritic. Graptolites, acritarchs.

Kalladeina Formation: shallow shelf(ooid grainstone, dolomitised in places),

slope to basinal carbonate interfingered with basinal shale of Dullingari Group.

Coongie Limestone Member: shelf carbonate prograding into basin, good reservoir quality.

Jena Basalt: within plate basalt and

~550 m

?

Jena

Basalt ?

v v v v

vTST

SB1

agglomerate.

MOOTWINGEE MOVEMENT: Separation of Arrowie and eastern Warburton Basin depositional systems.

Lower Member: Possible source rocksup to 0.85% TOC. Trilobites, brachiopods.

Subaerial exposure, karst development.

Diamond BogDolomite>120 m

Jena Basaltv v v v

v v v v v

HST

TST

Diamond Bog Dolomite: Potentially significantreservoir; Gidgealpa-1 recovered heavily gas cut salt water from this fractured unit.

Carbonate disconformably overlies volcanics.

KANGAROOIAN MOVEMENTS

Volcaniclastics - tuff, ignimbrite; sand and silt.(Taloola Ignimbrite Member >78 m) v v

v v v

v v

v v

Carbonate brecciated, contains Cambrian fossilv

v v v v v fragments.

MooracoochieVolcanics

990 m

v v v v v v v v v vv

v v v v v v v

v v

Oil in Sturt 6U-Pb zircon age 517±9 Ma in Malgoona 1Porphyritic trachyte, shattered and penetrated

by dacitic lavav v v v

PROTEROZOIC

v v v v v v

?Adelaidean and older metasediments(including Willyama Supergroup)

PIRSA 203838_100

Figure 2.56 Geological summary of the eastern Warburton Basin. HST = Highstand Systems Tract; LST = Lowstand Sytems


Tract; TST = Transgressive Systems Tract; SB = Sequence Boundary.

A TEISA–SPIRT project on oil migration in the Cooper and Eromanga basins has recognised pre-Permian inputs to oil poolson or adjacent to the Gidgealpa and Warra ridges, most notably at Gidgealpa, Meranji, Muteroo, Malgoona and Sturt, but also at Cowan and Mudlalee. The most likely source rocks are Cambrian carbonates in the underlying Warburton Basin.

2.7.1 Tight Gas PlayRecognition of a unique alteration profilearound the unconformity betweenthe Cooper and Warburton basins has generated a new play concept thatcould trap Permian sourced hydrocarbons as well as Warburton Basin sourced hydrocarbons. The nature of the alteration remains enigmatic and it is uncertain if itis a palaeosol or a result of hydrothermalalteration.

zircon-rich and consequently has a high 2gamma ray response. Moolalla 1 gas is reservoired in this formation which extends from Pando wells in the west to Moomba wells in the northeast.

Basal and middle Kalladeina Formation dolomites are shelf limestones exposed to meteoric diagenesis during marine lowstands. Although minor gas showshave been recorded, porosity prediction has proved difficult, the dolomites and associated karst breccias proving tight when drilled.

(a)

LATERAL

fracturetrap

shale

This weathered zone is up to 150 m thick comprising altered Warburton Basin strata and the granites in particular, immediately beneath the Cooper Basin unconformity (Boucher, 2001b) that can act as a seal

(b)

sandstone

migrating hydrocarbon

for Warburton Basin reservoirs charged by downdip Permian source rocks and possibly indigenous hydrocarbons (Figures 2.57, 2.58,2.59 and 2.60).

POROUS ZONE

sandstone trap

Fractures in brittle siltstones, such as those in the Dullingari Group in Lycosa 1, are capable of producing commercial oil and gas charged by downdip Permian source rocks (Figures 2.59, 2.61 & 2.62).Lycosa 1 tested a fractured shale, siltstone and sandstone sequence with multiplesets of carbonate-, quartz- and pyrite-filled fractures that produced up to 4.1 mmcfd over the interval 2633 to 2683 m from drill stem test (DST) 1 decreasing to 1.4 mmcfd with trace condensate after extended flow over the interval 2621 to 2697.5 m during DST 4 (Figure 2.62). The DST charts indicate possible formation damage and a dual

porosity system.

(c)

shale

sandstone

sh

ale


no trap

migrating hydrocarbon migrating hydrocarbon

Pando Formation sandstone ranges in porosity from 5 to 20% but relies on fractures for permeability. The unit is glauconitic and

204218-104

Figure 2.57Potential seal configurations for alteredzone basement and related plays (Boucher, 2001b).

Sturt 6 oil was produced from fractured and weathered tuff and ignimbrite of the Mooracoochie Volcanics. Porosity values reach 17% due to dissolution of feldspar and glass shards, fractures create the necessary permeability for flow.

2.7.2 Shale Gas PlayBlack, pyritic shales of the Cambro- Ordovician Dullingari Group were deposited in deep water of the Larapintine Seawhich extended through the Warburton and Amadeus basins to the Canning Basin (currently a focus for shale gas exploration in Western Australia).

Whether the Dullingari Group constitutesa valid shale gas play is yet to be proven. Of the meagre core recovered to date, from wells drilled on structural highs, the formation is consistently deformed and steeply dipping which is undesirable from a shale gas prospectivity perspective. Interms of source richness, TOC values from 4 wells (Dullingari 1, Pandieburra 1, Koochera1 and Kuncherinna 1) average 0.24% (range0.17 to 0.56%; 6 samples). These values are not encouraging and would suggest that gas recorded in Lycosa 1 and other wells with gas shows encountered in the Dullingari Group is migrated via natural fractures, rather than indigenous. The petroleum potential of this formation remains poorly understood and hampered by lack of data.

Altered zone

Onlap

Erosional truncation

Fault

Coal & carbonaceous

shale

Basal conglomerate in Cooper Basin

BleachedUnbleached

NW

PATCHAWARRA TROUGH

Gidgealpa

MoombaField

Big Lake Field

Surface

ALLUNGA TROUGH

Jena/UlandiFields

SE

TENAPPERA TROUGH

Field

P Horizon

LAKE EYRE AND EROMANGA BASINS

COOPER BASIN

1 km Big Lake10 km Suite WARBURTON BASIN AND PROTEROZOIC

Altered zone eroded

Lithological controls

Intra-basement altered zones rare

Altered zone thin on Big Lake Suite, thicker elsewhere

Altered zone widespread on Big Lake Suite, more variable elsewhere

?Altered zone following joints

Maximum thickness >258 metres

Mean thickness >40 metres

?Altered zone in Merrimelia Formation 204218-105

Figure 2.58 Characteristics of altered zone, Warburton Basin (Boucher, 2001b).

Dep

th b

enea

th b

asem

ent u

ncon

form

ity

Q =

0.8

, 2.0

, 4.0

, 9.6

MM

CFD

Q =

RTS

TM

Q =

0.4

4 M

MC

FD

Q =

1.4

, 3.2

, 4.1

MM

CFD

2HIGH PROSPECTIVITY LOW PROSPECTIVITY

0

50

100

150

200

Unaltered ZoneAltered Zone

250

204218-106

Figure 2.59 Altered zone play for wells adjacent to Wooloo and Allunga Troughs. 3 of the 6 wells that penetrated the altered zone and into potential reservoir discovered gas (Boucher, 2001b).

NEW

SO

UTH

WA

LES

QU

EEN

SLA

ND

#


139°140° 141°

Altered zone seal basement prospectivity map

Undrilled, Z horizon palaeohigh(Boucher 1998)

# oil window

# wet gas window

# dry gas window

area outside the oil generative window, on cupolas or ridges likely to have no altered zone

27°

Big Lake Suite granite granite cupola

Patchawarra Formation absent

27°

Cooper Basin edge

0.81 0.95

1.7Immature Oil Wet Gas

Dry Gas

28° 28°

29°29°

0 20 40 60 Kilometres

139° 140° 141°AV3: 200783_019

FFiiggu9re 2A.l6te0red Azoltneeresedalzboanseemseenat lpbroasspeecmtiveintyt mparop.spVeitrcintiivteityremfleactpa.nVceitdriantiateisrefoflrethcetatonpcPeadtcahatawaisrrfaorFtoormpaPtiaotnc.

hTahewBaigrraLaFkoerSmuaitetioannd.

(Bouchaesrs,o2c0ia0t1edb)c.upolas are areas of low or no prospectivity. The map does not show likely basement reservoirs.

2

Figure 2.61 Fractured Dullingari Group shales, siltstones and sandstones – Lycosa 1.

DST

4

DST

3

DST

1


GR &DT DEPTH(m)

Lycosa 1TOTAL GAS Resistivity

0.0GR (gAPI)

200.0DT (us/ft)

TGAS (m3/m3)1.0 1000.0 0.2

MSFL (ohm.m)

LLS (ohm.m)2000.0

140.0 40.0 0.2

0.2LLD (ohm.m)

2000.0

2000.0

2530 93/6/1 Lycosa Formation

2531m

2540

2550

87/11/2

87/10/3

2560

2570

92/7/1

2580

2590

2600

90/9/1

92/7/1

92/7/1

90/9/1Methane/ethane/propane shows

DST 1, 2633-2682 mGTS 1 min. at 4.1 mmcfd with condensate cut muddy spray

DST 3, 2618-2694 m

2610

2620

2630

2640

2650

2660

2670

2680

2690

86/11/3

92/7/193/6/1

92/7/1

91/8/1

94/6/1

95/4/1

92/7/193/6/1

87/10/3

90/9/1

GTS in 3 min. at 3.2 mmcfd with trace and trace filtrate

DST 4, 2621-2697 mGTS in 1 min. at 1.4 mmcfd with trace condenstate

26182621

2633

2682

2700

26942697

204218-107

Figure 2.62 Lycosa 1 composite log showing drill stem test flows over Dullingari Group metasediments.

2.8 Officer BasinThe Officer Basin is an arcuate depression500 km long extending from South Australia to Western Australia with six main depocentres containing flat to gently dipping Neoproterozoic and Palaeozoic sediments (Figure 2.63). About one third (176 000 km2) of the basin occurs in South Australia. Officer Basin sediments crop outin a linear belt south of the Musgrave Block, marking the northern limit of the basin(Figure 2.64). Outcrop is sporadic elsewhere. To the south the basin is overlapped by upto 400 m of Cenozoic, Mesozoic and locally, Permian strata. The eastern margin is ill defined.

Stratigraphy of the eastern Officer Basin and a rock-relation diagram linking the Birksgate Sub-basin, Munyarai Trough and Murnaroo Platform are shown in Figures 2.65 and2.66. The sediment packages of immediate interest are the Neoproterozoic (Willouran, Marinoan) and Cambro-Ordovician.

2.8.1 Tight Gas PlayAlthough no commercial discoveries have been made in the Officer Basin, hydrocarbon shows have been found in 4 formations (the majority in a playa carbonate in the Marla Overthrust Zone) including significant oil bleeds in the Observatory Hill Formation in Byilkaoora 1 stratigraphic well.

Principal source rocks are the Marinoan Dey Dey Mudstone and Narana Formation (Figure 2.65) that have TOC values to 1.47% (87 samples, mean 0.28%) and shallow marine carbonates of the Early Cambrian Ouldburra Formation that has TOC values from 0.4 to 1.87% although the richest source intervals are thin (~1 m). Up to nine recorded oil bleeds have been recorded from vugs and fractures in the Observatory Hill Formation with TOC values ranging from0.5 to 1.4% in Byilkaoora 1.

The Munyarai and Manya Troughs and the Marla Overthrust Zone (Figures 2.64, 2.66) are prospective for conventional oil and gas and unconventional tight gas.


Burial history modelling (Gravestock andHill, 1997) of the Manya Trough (based on Manya 6 well) suggests the entire sequence below ~175 m lies in the gas window with wet gas down to ~944 m. Significantly, source rocks of the Ouldburra Formation have remained in the wet gas window just after the Alice Springs Orogeny (~360 Ma) and have remained in the wet gas windowto present day. It is expected that structures that were in place as a result of the Petermann and Delamerian Orogenies could be charged.

Burial history modelling of the Marla Overthrust Zone (Gravestock and Hill, 1997), based on Byilkaoora 1, suggests that the Dey Dey Mudstone – Karlaya Limestone source rock package entered the wet gas window at ~550 Ma during the Delamerian Orogeny and passed into the dry gas window between ~490 and 475 Ma. In this region, thick sandstone sequences of the Tarlina Sandstone and Murnaroo Formation and interbedded sandstone, siltstone and conglomerates of the Narana Formation represent viable tight gas targets.

133°0'E

ª

:

ho 1

2

3 ª¨ 22

ª

1A

ª

4 ª ª ª

1,1A

ª ª

ª

ªª

32°0

'S31

°0'S

30°0

'S29

°0'S

28°0

'S27

°0'S

26°0

'S

33°0

'S32

°0'S

31°0

'S30

°0'S

29°0

'S28

°0'S

27°0

'S26

°0'S

ª

ª

ª

129°0'E130°0'E 131°0'E 132°0'E NORTHERN TERRITORY 134°0'E

ª18

135°0'E

PedirkaBasin ª

Curª1 ª 3

Dalmatia 1Mount Hamªmersley 1

Mount Criªspe 1

2 ª ª14 Eromanga4 ª 5

ªEOB 1

ª Nic lson 1,

: ª ª

Basin

WarburtonBasin

Rodda 2 ho 1A Coongra 1Welbourn Bravo 1 2

Byilkaoora 1 1 2 21 2

: ªª¨ª::ª ª¨ª3ªª Marla ªªTrainor Ec

" ª¨ " ª ª 2 Todmorden 1Yardinna 1

Mintabieªª¨ ª¨ ªª¨

ª 12 ¨ 5ª¨

10ªª6

2 ªª 3

ª Officer 1Trainor Alpha 1 ª¨ 13ªªªMarlaª1

237 6 515

ª Lambina 1Oodnadatta 1ªOodnadatta ª"

16 ªªªª ª 9

Mount Willoughby 1 Oodnadatta Town Bore 2

2 24¨ 3 ª

Munyarai 1 ª 6 4

Middle Bore 1 ªManya 1,3 ªª

ª 10 ª 28 ª

2

Albany 2 ::Toondina 1ª

ªBirksgate 12

ª 6 ª ª ªComalco Coalhole 1

na 1 ª 2

4 ª ªª ª4 ª C:ootanoori

:Ungoolya 1 5 7

3 Mount Bray 1 Maglia 1Karlaya 1 ªªª

Lairu 1Mount Furner 1 ª

Birribiana 1 ª

Mamungari (CP)

ªMunta 1

Meramangye 1Giles 1

ª" Emu 1 ª Karkaro 1

Wirrangulla Hill 1,1A ªArckaringa BasinArck 1

iMulyawara 1

iKutjara 1

Officer Basin

ª¨ Lake Maurice West 1

Emu

Observatory Hill 1

¨ªMurnaroo 1

Tallaringa (CP)

ª 2

ª

Nuba 1 :

ªWallira 1

Coober Pedyª"Stuart Range 3

H:oward Hill 1

ªLake Phillipson Bore 1

Lake Maurice East 1 ª Wallira West 1 Arkªeeta 1

Muddy Tank 1

ª Wilkinson 1ªWilkinson Lakes 2

ª 2 ª 3

Hughes 1ª ª:Denman 1

Denman North 1

Maralinga "

Ooldea 1 ªªReid 1,1A

ª

¨ 2,2A¨

Karari 1

Tarcoola"

Nullarbor (RR)

DenmanBasin

ª Cook 1 Watson Siding South 1

Yellabinna (RR)

Yellabinna (WA) Lake Harris

Lake Everard

Eucla"

Nullarbor (NP) Nullarbor (NP)ªMallabie 1

Wahgunyah (CP)Boondina (CP)

Yumbarra (CP)Yumbarra (CP)

Lake Gairdner (NP)

Wahgunyah (CP) Chadinga (CP) Ceduna"

Pureba (CP)

Bight Basin

ª Apollo 1 Great Australian BightAcraman Creek (CP)

" Streaky BayGawler Ranges

(NP)


Pinkawillinie (CP)

129°0'E130°0'E 131°0'E 132°0'E 133°0'E 134°0'E K

ullipar1u35(C°

0P'E)204218-054

"Tarcoola Petroleum wells

i Gas shows

Areas with no petroleum access

Park or Reserve

0 25 50 75 100 km

MGA Zone 53

ª¨ Dry hole with oil shows

SOUTH AUSTRALIA

"

ADELAIDE

ª Dry hole: Proposed or currently drilling

Seismic lines (3D excluded)Seismic – post 2000Seismic – 1950–1999

Aboriginal LandsMarine MammalProtection ZoneGreat Australian BightWhale SanctuaryGreat AustralianBight Marine

Areas with petroleum access

Benthic Protection Zone

Park or Reserve

Figure 2.63 Officer Basin, South Australia. Wells and seismic lines.

!(

!(

!(

32°0

'S31

°0'S

30°0

'S29

°0'S

6800

000

28°0

'S27

°0'S

7000

000

6600

000

WES

TER

N A

UST

RAL

IA

Nur

rai

"Rid

ge"?

6600

000

6800

000

7000

000

27°0

'S31

°0'S

30°0

'S29

°0'S

28°0

'S

129°0'E500000

130°0'E 131°0'E750000

132°0'E 133°0'E

Rodda 2

2134°0'E10000E0O0 B 1

!(Bitchera Ridge

MUSGRAVE PROVINCE (! Coongra 1!(!( EOB 2

Trainor Ech!(o!(1 Marla !(!( !(Coongra 1A

!( !(!(!(!(!(!( !(!(!( 3

!(!(T!(ra!(in!(or!(Alpha 1 !(Nicholson 2 Todmorden 2

Officer 1 Comalco Uphole!(7!( !(!( Marla

Overthrust(!(

M!(!(!(arla 7 !( Manya 5 Lambina 1Marla!(1B!(Marla 1!(!( !(

Birksgate Munyarai 1(! Zone Comalco Uphole!(3 !( !(

!(Comalco Uphole 9

!(Comalco Uphole 4 Comalco Up

!(hole 5

WintinnaTrough

Birksgate 1 Man!(ya 3 !(Comalco Uphole 10!(

Sub-basinManya !(!

(2!(

!(

Manya 4(!

!(Mount Willoughby 2

!( !(Karlaya 1

!(Lairu 1 Comalco Coalho!(le 6 !( (!M!(o(!unt Furner 1 Mount Bray 1!( !( Ungoolya 1Munta 1

!( !(Comalco Coalhole 7

(! !(Meramangye 1!(

Giles 1

MurnarooEmu 1

(! Karkaro 1(!

Watson

Ridge

Murnaroo 1(!

Wallira 2(!

Nuba 1(!

Stuart Range 3!(

Howard Hill 1!(

Platform Lake Maurice East 1(!

Wallira West 1(!

Wallira 1(!

!(Arkeeta 1!(

Wilkinson Lakes !(2!(

Wilkinson 1

Lake Phillipson Bore 1!(Muddy Tank 1

Hughes 2!(

Hughes 3 Ooldea 1(!

Karari 2(! GAWLER

CRATONHughes 1

!(

Adi 1 Adi 2!(!(!(!(Denman 1

Cook 1(!

Reid 1A Reid 1!(!(

Watson Siding South 1!(

COOMPANA BLOCK

Mallabie 1(!

Lake Harris

Lake Everard

Great Australian Bight

500000129°0'E 130°0'E 131°0'E

750000132°0'E 133°0'E 134°0'E

1000000135°0'E

204218-055

0 25 50 75 100 km

Petroleum wells!( Dry hole!( Dry hole with oil show

MGA Zone 52"

Tarcoola

Fault line

"

ADELAIDE

SOUTH AUSTRALIA

Figure 2.64 Officer Basin structural elements map.

Chert

(37.8m)

OFF

ICE

R B

AS

INA

RC

KA

RIN

GA

BA

SIN

ER

OM

AN

GA

BA

SIN

PR

EC

AM

BR

IAN

NE

OP

RO

TER

OZO

IC (

AD

ELA

IDE

AN

)

LAKE

MAU

RICE

G

RO

UPM

ARLA

GR

OUP

MU

ND

A G

RO

UP

UNG

OO

LYA

GR

OU

PCA

LLAN

NA G

P

Tran

sgre

ssio

n

SEA

LEVE

L

Reg

ress

ion

STR

ATI-

GR

APH

IC

SEQ

UEN

CES


AGE

EARLY CRETACEOUS

Ma

95

114

130

ROCK UNIT

Bulldog Shale

Cadna-owie Formation

GENERAL LITHOLOGY

(39.54m)

(20.37m)

(T) (R)MFS or HST

HSTJ-K.2

J-K

TECTONIC EVENTS

JURASSICLate

Early toMiddle

140

152

205

Algebuckina Sandstone(68.11m)

TST LST

J-K.1

CONTINENTAL UPLIFT

TRIASSIC

PERMIANLate

250

260270

Mt ToondinaFormation

(53.64m)HST

Early

CARBONIFEROUS

LateDEVONIAN

Early andMiddle

Late andMiddle

SILURIAN

Early

280290

355360

375

417

428435

443

445

Stuart Range Formation (50.17m)

Boorthanna Formation(149m)

Mimili Fm

Alice SpringsOrogeny

Blue Hills Sandstone(174.5m)

?HST?TST

TST

HST

P

ALICE SPRINGS

OROGENY

D

RODINGAN EVENT

OORDOVICIAN

450Indulkana Shale (13.67m) MFS

Early and 455 Mt Chandler Sandstone TST

Middle Late

Late

Middle

457495505

507

510

(244m)Kulyong

Formation

ByilkaooraMember

Delamerian OrogenyV V V

V V

LST

DELAMERIAN OROGENY

C3

516

518

Trainor Hill Sandstone (271.24m)

Mt Johns Conglomerate MemberApamurra Fm (52.66m)

Arcoeillinna Sandstone

HST

TST

LSTC2.2

Oolarinna Mbr

Moyles 520 Observatory

(92.4m) HSTTST C2

C2.1Marker Bed Hill Fm.(141.17m)

LSTCAMBRIAN

Early

522524

Cadney Park Mbr(130m)Relief

Para- Sandstone Walla- HST C1.3

536

keelya Alkaki

Member

(96.34m) tinnaMbr

OuldburraFormation

(434.9m)

TST LST

MFS or HSTTST LSTTST

C1.2 C1

C1.1545

560 PunkerriSst

Petermann Ranges OrogenyMena

LST

HST E.4

PETERMANN RANGES

OROGENY570 Munyarai575

Fm (448m)

Tanana FormationWilariDol

TST HST

IVF & TST E.3585

(343.83m) MbrHST E

MARINOAN590 Karlaya Limestone (47m) TST E.2

STURTIAN

600

615

640

650700

720760

Dey Dey Mudstone (148.13m)

Murnaroo Formation

Meramangye (231.75m)

Formation(195m) (241.52m)

Tarlina SandstoneWantapella Volcanics V V

Chambers Bluff Tillite

Cadlareena

MFS HST

TSTLST

HST MFS

TST LST

E.1

M

S GLACIO- GENIC UPLIFT

TORRENSIAN- 780 Volcanics(110m)

(79.5m)

Coominaree DolomiteV V V

HSTWILLOURAN 800

Alinya Formation (56m) TST W820 Pindyin Sandstone LS

Oil show Oil source rock Evaporite Reservoir Seal Average Thickness (55m)204218-108

Figure 2.65 Stratigraphic framework, eastern Officer Basin. Systems tract acronyms are as follow: HST = Highstand SystemsTract; LST = Lowstand Systems Tract; TST = Transgressive Systems Tract; MFS = Maximum Flooding Surface; IVF = Incised Valley Fill.

2West East

YOWALGA SUB-BASIN WAIGEN-BIRKSGATE SUB-BASINS

MUNYARAI TROUGH

MANYA TROUGH

YILGARN

TABLE HILL - KULYONG VOLCANICS BABBAGOOOLA BEDS

LUPTON - TURKEY HILL BEDS

WIRRILDAR BEDS

PUNKERRISANDSTONE

PETERMANN EROSION

A TRAINOR HILL SST

OBSERVATORY HILL - APAMURRA FORMATIONSE

OULDBURRA FM OULD

CRATON WRIGHT HILL

BEDS

LOWER UNGOOLYA GROUP

Salt Salt

GAWLERVE CRATON

COOMPANA BLOCK

204218-109

Figure 2.66 Basin architecture.

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