Upstream Petroleum and Resources
Working Group Report to
COAG Energy Council
on Unconventional Reserves, Resources,
Production, Forecasts and Drilling Rates
Canberra, November 2014
Contents
Introduction
Key points
Australian Unconventional Gas Reserves/Resources
Scope and assumptions
Definitions
SPE PRMS
Rate decline in unconventional wells
Resource potential by jurisdiction
General references
Summaries:
Queensland
New South Wales
Victoria
Tasmania
South Australia
Western Australia
Northern Territory
Offshore areas
2
3
4
4
4
5
6
8
9
10
18
21
23
24
28
31
33
Introduction
This report updates the 2013 report produced for the former Standing Council on
Energy and Resources (SCER; now COAG Energy Council).
The significant changes from the 2013 report are:



Increase in Queensland’s 2P reserves from 35 435 PJ to 41 124 PJ,
Decrease in New South Wales’ 2C resources from 7443 PJ to 4128 PJ,
Northern Territory now reporting 257 276 PJ of prospective resources.
In addition, some operators are now releasing more information on well
production performance, but these are still limited to the average maximum rates
and still do not provide the detailed well performance to fully assess deliverability
risks.
Page 2 of 33
Key points
 Current booked coal seam gas (CSG) reserves exceed current liquefied
natural gas (LNG) contract requirements
Current Queensland CSG reserves allocated to LNG projects total 28.8 Tcf (30 600 PJ)
while contracted volumes total 24.3 Tcf (25 700 PJ) of gas. Arrow Energy has an
additional 9.9 Tcf (10 500 PJ) of currently uncommitted gas. In addition, Santos has
secured access to an additional 1.3 Tcf (1350 PJ) of conventional gas from the Cooper
Basin and over 2 Tcf (2200 PJ) third party CSG supply agreements.
 Current drilling rates meet estimated required drilling rates for CSG wells
Current drilling rates are similar to projected required drilling rates so should be
sustainable in the longer term (see Figure 2.4).
 There is a risk of shortfall in rate of gas supply due to production capacity
that is dependent on actual well production rates. The data required to
estimate the magnitude of the risk is not currently available to Geoscience
Australia
The contracted gas volumes and projected drilling rates set a critical period from late
2015 through early 2019 where the required production rate per well will be at a
maximum of between 400 000 and 500 000 cubic feet per day per well (if only gas
resources allocated to the projects are considered) (Table 2.4). It is not clear to
Geoscience Australia that production will be able to be sustained at this level for that
duration and we do not currently have access to the data required to assess the risk.
 It is unlikely that other sources of unconventional gas will be able to supply
any shortfall in production rate before 2020
The most mature source of unconventional gas that may be developed in the
medium term is in the Cooper Basin. It is not anticipated that significant volumes of
this gas will become available before 2020 and so will not be available to meet any
shortfall in gas demand during the critical period for the CSG LNG projects. The
future of coal seam gas resource development in New South Wales is not clear but it
is unlikely that production could be ramped up in time to contribute to the current
gas contracts.
 It is likely that any shortfall in production rate will be met firstly by transfer
of gas between LNG projects including incorporation of Arrow’s gas
reserves and secondly by diversion of conventional gas production from the
Cooper Basin
Page 3 of 33
Australian Unconventional Gas Reserves/Resources
COMMERCIAL
SUB-COMMERCIAL
DISCOVERED PIIP
UNDISCOVERED PIIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
The following table is used to sum the reserves and resources presented in the sections on each
jurisdiction. This summation is not strictly correct for reasons discussed below but does give an
indication of overall resource potential.
PRODUCTION: 283 PJ in 2013
RESERVES
1P: 284 PJ
RESERVES
2P: 43 743 PJ
RESERVES
3P: 3 919 PJ
CONTINGENT RESOURCES
1C: 5 933 PJ
CONTINGENT RESOURCES
2C: 14 897 PJ
CONTINGENT RESOURCES
3C: 17 015 PJ
UNRECOVERABLE
PROSPECTIVE RESOURCES
Low Estimate: 45 000 PJ
PROSPECTIVE RESOURCES
Best Estimate: 980 729 PJ
PROSPECTIVE RESOURCES
High Estimate: 268 000 PJ
UNRECOVERABLE
NOTE: Not all jurisdictions have reported volumes for each category so totals may not be indicative of the
distribution of resources across each category
Table 1.1: Australian unconventional resources
Scope and assumptions
This report covers potential for tight oil and gas, shale oil and gas and CSG sourced from
publicly available data published by operating companies, States authorities and other
reporting bodies.
Resource data is not available for many prospective basins and formations, so the following
estimates of unconventional resources are likely to understate the potential. To become
reserves, however, these resources will need a commercially viable gas price, suitable
infrastructure and a market. It is probable that the majority of the resources, if proven to exist,
will not be produced for decades.
Unconventional resource potential from other resources such as oil shale, coal gasification or
offshore methane hydrates has not been considered.
Definitions
A useful summary of the types and setting of unconventional resources can be found in Chapter
1 of ACOLA Report 6 “Securing Australia’s Future – Engineering energy: unconventional gas
production” (see link in Reference) and in the “Roadmap for Unconventional Gas Projects in
South Australia” (see link in Reference) which also includes a brief description of the Society of
Petroleum Engineers Petroleum Resources Management System (SPE PRMS) resource reporting
system in Chapter 1.
Page 4 of 33
The following definitions have been adopted in listing the prospective formations in each
jurisdiction:
Inactive – The formation may contain a resource but there is no current activity
Preliminary exploration – The formation is being actively explored
Under assessment – The formation is being tested for its ability to produce commercially
Producing – The formation is currently producing
SPE PRMS
The Society of Petroleum Engineers has published the Petroleum Resources Management
System (SPE PRMS) to standardise the reporting of petroleum reserves and resource volumes.
The reporting matrix lists reserves and resources by chance of commerciality in the vertical
direction and technical uncertainty in the horizontal direction.
PRODUCTION
COMMERCIAL
SUB-COMMERCIAL
DISCOVERED PIIP
UNDISCOVERED PIIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
It should be noted that only petroleum that is developed or is part of a current development
project can be booked as reserves and petroleum that has been demonstrated to exist through
exploration and testing can be booked as a contingent resource; the remainder should be
booked as a prospective resource. There is a possibility that a contingent resource or a
prospective resource may never become recoverable due to cost or the limitations of
technology. A prospective resource may not exist at all as the assumptions or correlations used
to predict its existence may found to be invalid.
RESERVES
1P
RESERVES
2P
RESERVES
3P
CONTINGENT RESOURCES
1C
CONTINGENT RESOURCES
2C
CONTINGENT RESOURCES
3C
UNRECOVERABLE
PROSPECTIVE RESOURCES
Low Estimate
PROSPECTIVE RESOURCES
Best Estimate
PROSPECTIVE RESOURCES
High Estimate
UNRECOVERABLE
Table 1.2: PRMS matrix
Resource estimates range from estimates of the number of methane molecules in all the rocks
in a basin, through estimates of the volume that could be produced without consideration of
technical factors and economics to the amount likely to be produced given current technology
and commercial considerations. It is important to consider the nature of these different types
of estimates when looking at resources in the PRMS matrix. Geoscience Australia’s view of the
relationship between these types of estimate is summarised below.
Page 5 of 33
The published literature indicates that, for shale gas wells at least, only the volume accessed by the
fracturing process (the “stimulated rock volume”) contributes to production. Within this volume the
recovery can be as high as 70% of the petroleum initially in place (PIIP in the PRMS matrix above). This
stimulated rock volume does not, however, connect with all of the petroleum-bearing rock as the fractures
are not evenly spaced and new fractures generated too close to current fractures or natural fracture
networks may follow the pre-existing fractures. This means that, even with a recovery as high as 70%, the
overall production may only recover about 30% of the petroleum initially in place in the developed area. In
addition, not all of the petroleum-bearing rock has properties that are suitable for commercial
development. The rock layers may become too thin or not contain sufficient petroleum to support
commercial operations or the rock properties may vary so a suitable fracture network cannot be
established. This may further reduce overall recovery so that the recoverable portion of the resource is of
the order of 5 to 10% of the petroleum initially in place.
As a result, when a prospective formation is explored and developed the assessed petroleum volumes
associated with the formation can decrease markedly as the resource estimates mature from petroleum in
place and prospective resource to contingent resources, reserves and production. It is probable that this
sort of relationship between initial in place volumes and reserves and production holds for other types of
unconventional resources.
A description of the definitions used in the system is on the SPE website (see link in Reference).
A non-technical guideline and the full guideline, including sections on estimation of different
types of unconventional resource are also available (see links in Reference).
Rate decline in unconventional wells
Conventional gas wells in good quality reservoirs typically sustain high rates of production over
many years. This is due to the high degree of connectivity in the reservoir; the well is connected
to a substantial portion of the gas in place and can produce gas from distant parts of the
petroleum bearing rock.
Unlike conventional gas wells, both shale gas wells and coal seam gas wells are only connected
to the coal or rock immediately surrounding the well bore or adjacent to any natural or induced
fracture network that may be present. This results in a production profile that is characterised
by an initial period of high production followed by a steep decline in production rate and a long
production “tail” that may last for a decade or more. This is caused by initial rapid depletion of
the gas in the fractures followed by slower desorption of gas from the organic material in the
shale or coal as reservoir pressure is lowered during production. This is shown in the production
performance for Beach Energy’s Halifax 1 shale gas well in the Cooper Basin.
Page 6 of 33
4.50
million cubic feet per day
4.00
3.50
3.00
2.50
2.00
1.50
1.00
0.50
0.00
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Month
Halifax 1 production rate (million cubic feet per day)
Source: Beach Energy press releases
Figure 1.1: Halifax 1 gas production
While not directly comparable, coal seam gas wells follow a similar production profile to shale
gas wells after an initial period of dewatering. This is illustrated in the figures below:
Source: Moore, T. A., Coalbed methane: A review
Figure 1.2: Coal seam gas well decline
Page 7 of 33
Figures B and C show wells where the gas production has reached a peak and is now declining;
to 60 per cent of peak after one year in Figure B (from the Bowen Basin) and to 30 per cent of
peak after four years in Figure C.
While the overall production profile is usually similar, the timing of peak and decline has been
observed to vary markedly, even within a small area of the same resource. This is discussed
further in the section on Queensland resources.
Resource potential by jurisdiction
The body of the report presents data on unconventional resources in each onshore jurisdiction.
The unconventional resource potential section includes listing of the basins and formations
that are currently thought to be prospective, including the type(s) of resource thought to be
present and the current exploration and development status of the formation.
The reserves/resources section is a compilation of the reserves and resources, which are listed
according to Geoscience Australia’s best estimate of where they should be placed in the SPE
PRMS matrix. The totals are a summation of each of the categories of reserve or resource but it
should be noted that this is not strictly statistically correct except for 2P/2C/Best Estimate
categories and will underestimate 1P/1C/Low Estimate reserves and resources and
overestimate 3P/3C/High Estimate reserves and resources. This is due to the probabilistic
nature of the estimates. For this reason, only the 2P/2C/Best Estimate reserves and resources
summation should be regarded as a reliable estimate of potential.
The production/forecasts section forecast has been prepared from published contracted gas
volumes for LNG in Queensland.
The unconventional resource drilling activity section tabulates drilling activity.
The commentary section includes Geoscience Australia’s observations on the status of
unconventional resources in the jurisdiction and any caveats that should be applied in
interpreting the data.
General references
ACOLA Report 6 Securing Australia’s Future – Engineering energy: unconventional gas
Production
http://www.acola.org.au/PDF/SAF06FINAL/Final%20Report%20Engineering%20Energy%20June%202013.
pdf
Beach Energy
http://www.beachenergy.com.au/irm/archive/asx-announcements3.aspx
DMITRE South Australia
http://www.petroleum.dmitre.sa.gov.au/__data/assets/pdf_file/0008/179621/Roadmap_Unconventional
_Gas_Projects_SA_12-12-12_web.pdf
Drill, Baby, Drill
http://www.postcarbon.org/reports/DBD-report-FINAL.pdf
EIA/ARI World Shale Gas and Shale Oil Resource Assessment
http://www.eia.gov/analysis/studies/worldshalegas/
Moore, T. A., Coalbed methane: A review, International Journal of Coal Geology 101 (2012) 36–
81
SPE Guidelines for Application of the Petroleum Resources Management System
http://www.spe.org/industry/docs/PRMS_Guidelines_Nov2011.pdf
Page 8 of 33
SPE Petroleum Resources Management System
http://www.spe.org/industry/docs/Petroleum_Resources_Management_System_2007.pdf
SPE Petroleum Resources Management System Guide for Non-Technical Users
http://www.spe.org/industry/docs/PRMS_guide_non_tech.pdf
RFC Ambrian Australian Unconventional Oil & Gas
http://www.armourenergy.com.au/assets/downloads/investment_research/2013/09-2013_rfcambrian_australian-unconventional_oil_and_gas_report_.pdf
Page 9 of 33
Queensland
Unconventional resource potential:
Basin/Formation
Laura Basin
Dalrymple Sandstone
Maryborough Basin
Maryborough Formation
Tiaro Coal Measures
Burrum Coal Measures
Clarence-Moreton Basin
Walloon Coal Measures
Surat Basin
Walloon Coal Measures
Bowen Basin
Black Alley Shale
Tinowon Formation
Moranbah Coal Measures
Baralaba Coal Measures
Fort Cooper Coal Measures
Rangal Coal Measures
Bandanna Formation
Eromanga Basin
Winton Formation
Toolebuc Formation
Birkhead Formation
Westbourne Formation
Poolowanna Formation
Cooper Basin
Toolachee Formation
Roseneath Shale
Epsilon Formation
Murteree Shale
Patchawarra Formation
Galilee Basin
Betts Creek Beds
Aramac Coal Measures
Bandanna Formation
Lake Galilee Sandstone
Adavale Basin
Log Creek Formation
Lissoy Sandstone
Cooladdi Dolomite
Georgina Basin
Arrinthrunga Formation
Inca Shale
Thorntonia Limestone
Beetle Creek Formation
Georgina Limestone
Mount Isa Superbasin
Lawn Hill Shale
Termite Range Formation
Riversleigh Siltstone
Styx Basin
Tight gas
Shale gas
CSG
Status



Inactive






Inactive
Inactive
Preliminary exploration

Under assessment

Producing





Preliminary exploration
Under assessment
Producing
Producing
Under assessment
Under assessment
Producing




*


















Inactive
Preliminary exploration
Inactive
Inactive
Inactive
Under assessment
Under assessment
Under assessment
Under assessment
Under assessment
Preliminary exploration
Preliminary exploration
Preliminary exploration
Preliminary exploration






Inactive
Inactive
Inactive








Inactive
Inactive
Inactive
Inactive
Inactive




Preliminary exploration
Inactive
Preliminary exploration

Page 10 of 33

Styx Coal Measures
Ipswich Basin
Tivoli Formation
*Unconventional oil and gas potential

Preliminary exploration

Preliminary exploration
Table 2.1: Queensland unconventional resource potential
COMMERCIAL
SUB-COMMERCIAL
DISCOVERED PIIP
UNDISCOVERED PIIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
Reserves/Resources:
PRODUCTION: 264.3 PJ (2012-13)*
RESERVES
1P
RESERVES
2P: 41 124 PJ*
RESERVES
3P
CONTINGENT RESOURCES
1C
CONTINGENT RESOURCES
2C
CONTINGENT RESOURCES
3C
UNRECOVERABLE
PROSPECTIVE RESOURCES
Low Estimate
PROSPECTIVE RESOURCES
Best Estimate: 164 000 PJ**
PROSPECTIVE RESOURCES
High Estimate
UNRECOVERABLE
Source: *Queensland production and reserves statistics as at 31/12/2013, Queensland’s petroleum exploration,
development and potential 2012-13,**ACOLA Report 6 Securing Australia’s Future – Engineering energy:
unconventional gas production (Bowen and Clarence-Moreton shale gas), EIA/ARI World Shale Gas and Shale Oil
Resource Assessment (Maryborough shale gas), Independent Expert’s Report for Armour Energy Limited (Mount Isa
Superbasin)
Table 2.2: Queensland unconventional resources
Coal seam gas reserves have increased markedly from 2007 as drilling accelerated to prove up
reserves for the LNG projects as shown in the graph below (1 Tcf is approximately equal to 1000
PJ). Sustained drilling in the last three years has not seen significant changes in reserves, except
for the QGCLNG project, which booked about 3 Tcf additional gas reserves in 2013 through its
drilling program (Figure 2.1).
Page 11 of 33
14.000
12.000
Reserves (Tcf)
10.000
8.000
6.000
4.000
2.000
0.000
1/1/2005
1/1/2007
GLNG
1/1/2009
QGCLNG
1/1/2011
APLNG
1/1/2013
Arrow
Figure 2.1: Queensland reserves growth in coal seam gas for LNG projects
Production/Forecasts:
The current total annual gas production for the State was about 320 PJ in 2013 (41 PJ of
conventional gas and 280 PJ of coal seam gas, the equivalent of about 6 MT/a LNG). In contrast,
the forecast gas demand to supply the CSG LNG projects will be about 25 MT/a or almost 1400
PJ/a for a total of 18.5 Tcf (19 400 PJ) of gas. This is shown by contract in the graph below,
compiled from published LNG export volumes. A portion of the QCLNG gas (top light blue bars)
may be sourced internationally.
Page 12 of 33
Contracted volumes
30
Contracted volumes (MT/a)
25
20
15
10
5
0
GLNG
GLNG
APLNG
APLNG
APLNG
QGCLNG
QGCLNG
Figure 2.2: Contracted volumes by year for Queensland coal seam gas for LNG projects
Unconventional resource drilling activity:
High.
Drilling activity has been high, in preparation for LNG exports. The number of wells drilled per
month and the cumulative total of coal seam gas wells are shown in the graph below.
Page 13 of 33
140
6000
120
5000
100
4000
80
3000
60
2000
40
Cumulative number of wells
Number of wells per month
Queensland CSG drilling activity
1000
20
0
0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Year
Cumulative wells
Completed wells
Abandoned wells
Figure 2.3: Well drilling rates and cumulative coal seam methane wells drilled
In order to sustain the high rate of production required for the LNG projects, an equally high
rate of drilling will be required. The graph below shows the projected drilling for the LNG
projects, based on published data. This by far exceeds all other petroleum related activity in the
State.
Queensland CSG drilling activity
16000
Cumulative number of wells
14000
12000
10000
8000
6000
4000
2000
0
Year
Cumulative wells
Projected drilling
Figure 2.4: Historic and proposed cumulative coal seam methane wells
Page 14 of 33
Commentary:
Coal seam methane reserves booked by the three CSG LNG projects along with contracted LNG
volumes are tabulated below. The current reserves appear to be sufficient to cover the current
contracts.
Project
Reserves Tcf (PJ)
APLNG*
12.6 (13 382)
GLNG#
6.4 (6780)
QCLNG@
12.4 (13 200)
Arrow
9.9 (10 500)
Table 2.3: Coal seam gas resources and LNG contracted volumes
Contracted volume Tcf (PJ)
8.6 (9116)
7.2 (7600)
8.5 (9000)
-
*: 2P value, see http://www.originenergy.com.au/news/files/asx_investor_site_tour_presentation.pdf
#: 2P + 2C value. See http://www.santos.com/library/2014_09_15_%20CLSA%20presentation.pdf@: Resource
estimates from Queensland Department, contract information from
http://www.qgc.com.au/media/239458/bg_fsheet_2013_lng_v2.pdf
@: http://www.qgc.com.au/media/239458/bg_fsheet_2013_lng_v2.pdf
The current reserves for GLNG project may not be adequate to fulfil the contracts. Over 2 Tcf
(2200 PJ) third party gas supplies have been arranged (Table 2.4).
Supplier
Santos
portfolio
‘Horizon’
Origin
Origin
Other
suppliers
Meridian JV
Combabula/
Spring Gully
Quantity
750 PJ
365 PJ
194 PJ1
TJ/day
Starts
Delivery
point
Term
Price
basis
2015
2015
2016
2015
2016
2015
15 years
10 years
5 years
7 years
21 months
20 years
Wallumbilla
Wallumbilla
Wallumbilla
Oil-linked
Oil-linked
Oil-linked
85 PJ
445 PJ2
140
100
50-1001
10-15
60-100
20-65
Wallumbilla
GLNG GTP
Oil-linked
Oil-linked3
355 PJ4
30-50
2015
30 years
Fairview
Oil-linked
Table 2.4: Third party gas supplies arrangement for GLNG project
1 100 PJ firm volume over 5 years. Origin has the option to supply additional volumes of up to 94 PJ during the same period.
2 Source: WestSide Corporation Target Statement of 16 May 2014. Excludes additional gas production by the Meridian Joint
Venture beyond 65 TJ/day. Volumes subject to Meridian field production performance and implementation of expansion plans.
3 Oil-linked from 2016.
4 Santos share 2P reserves in the APLNG-operated Combabula, Spring Gully and Ramyard fields at the end of 2013.
The CSG LNG projects have also published projected drilling programs and these can be
combined with the contracted LNG volumes to estimate a required average production rate per
well. These are tabulated for the three projects below in millions of cubic feet per well per day.
Page 15 of 33
QUARTER
2014 1Q
2014 2Q
2014 3Q
2014 4Q
2015 1Q
2015 2Q
2015 3Q
2015 4Q
2016 1Q
2016 2Q
2016 3Q
2016 4Q
2017 1Q
2017 2Q
2017 3Q
2017 4Q
2018 1Q
2018 2Q
2018 3Q
2018 4Q
2019 1Q
2019 2Q
2019 3Q
2019 4Q
2020 1Q
2020 2Q
2020 3Q
2020 4Q
2021 1Q
2021 2Q
2021 3Q
2021 4Q
2022 1Q
2022 2Q
2022 3Q
2022 4Q
GLNG
0.115
0.217
0.412
0.393
0.421
0.403
0.429
0.411
0.435
0.418
0.440
0.425
0.444
0.430
0.416
0.404
0.434
0.421
0.410
0.398
0.388
0.378
0.368
0.359
0.351
0.342
0.335
0.327
0.320
0.313
0.306
0.300
APLNG
0.390
0.371
0.433
0.411
0.634
0.605
0.578
0.553
0.531
0.510
0.491
0.473
0.457
0.441
0.427
0.414
0.401
0.389
0.378
0.367
0.357
0.348
0.338
0.328
0.319
0.311
0.302
0.295
0.288
0.281
QCLNG
0.290
0.275
0.262
0.250
0.565
0.536
0.510
0.486
0.465
0.445
0.427
0.410
0.395
0.380
0.367
0.355
0.343
0.332
0.322
0.312
0.303
0.295
0.287
0.279
0.272
0.265
0.258
0.252
0.246
0.241
0.235
0.230
0.225
0.220
0.216
0.211
TOTAL
0.132
0.125
0.119
0.113
0.284
0.298
0.453
0.433
0.451
0.433
0.501
0.483
0.476
0.461
0.456
0.442
0.438
0.426
0.415
0.404
0.405
0.395
0.386
0.378
0.370
0.362
0.355
0.348
0.341
0.334
0.328
0.322
0.316
0.311
0.306
0.301
Table 2.5: CSG production rates needed to fulfil LNG contracted volumes (mmscf/well per day)
The table shows that for the period 3Q 2015 to 1Q 2019, the production rate will need to be
maintained at between 400 000 and 500 000 cubic feet per day per well across all three
projects. Within each project the required peak rate can be even higher. The risk associated
with this may explain the recent gas sharing agreement between the CSG LNG projects and the
connection of the Arrow resources.
While the projected drilling rate appears to be sustainable, based on drilling rates to date, the
estimation of required wells is only valid for a given productivity per well; that is, if the peak
production per well is less than anticipated or the production rate per well declines more
rapidly to a lower production “tail” with time, more wells will be required to meet the
contracted volumes. The actual well productivity is only known after dewatering has been
completed and it is unlikely that this has occurred for the majority of coal seam gas wells for
the LNG projects. Limited data on well rates is available in the public domain suggests “peak 7day average gas rate” of 650 000 cubic feet per day per well with a median rate of 550 000
cubic feet per day per well in the Berwyndale South Walloon Coal Measures accumulation. The
longer term sustained production rate is not known.
Recently, Origin presented that for wells that have been online for more than six months, the
observed maximum average well production rates were 2.1 TJ/d per well (equivalent to 2
mmscf/d per well) for the Talinga project and 1.1 TJ/d (about 1 mmscf/d per well) for the Spring
Gully project, higher than its expectation of 1.2 TJ/d per well on average of its Phase 1 drilling
Page 16 of 33
operation (see link below). These production rates appear to meet the required rates for the
contracted demand (Table 2.5). For GLNG project, Santos stated that the performance of
Fairview wells continues to exceed expectations with average optimum gas capacity of 2.2
TJ/day per well. Roma wells are on line and are dewatering, supporting individual well capacity
of 0.5 TJ/day; Roma 02- 04-01 well are producing over 1 TJ/day. All this information is still
limited to the average peak production rates per well. No longer term sustained production
rates are available to us. So, no definitive statement can be made about the likely long term
rate from coal seam gas production in Queensland although it seems likely that additional
sources of gas may be required to meet contract commitment. If required, the most probable
source of this gas outside the area of coal seam gas development would be the conventional
resources in the Cooper Basin. This was indicated in the Santos Annual Report 2012 which
stated
GAS SUPPLY BUILD CONTINUES
To execute the most efficient gas supply for the project, gas will be sourced from the
dedicated CSG fields, underground storage, supply from Santos’ portfolio and third
parties.
In 2012, 143 wells were drilled in the project’s CSG acreage, with the gas produced
supplied to domestic gas contracts and the remainder injected into underground
storage. A further 200 to 300 wells are planned to be drilled each year from 2013 to
2015.
Additional gas supply agreements for a total of 595 PJ were signed with third parties in
2012 for gas supply to the GLNG project, adding to the 750 petajoules that Santos has
agreed to supply, primarily from the Cooper Basin.
References:
Armour Energy
http://www.armourenergy.com.au/investors/investment-research (7-August-2013)
Changes in Completion Strategy Unlocks Massive Jurassic Coalbed Methane Resource Base in
the Surat Basin, Australia, R.L. Johnson, SPE, S. Scott and M. Herrington, Queensland Gas
Co. Ltd., SPE 101109
Independent Expert’s Report for Armour Energy Limited
http://www.empireenergy.com/pdf/McArthur%20Basin%20Armour%20Co%20Ltd%20Ind.%20Geo's%20R
eport.pdf
Origin APLNG Operational Review and Asset Visit (May 2014)
http://www.originenergy.com.au/news/files/asx_investor_site_tour_presentation.pdf
BG Group’s LNG business: http://www.qgc.com.au/media/239458/bg_fsheet_2013_lng_v2.pdf
Queensland’s petroleum exploration, development and potential 2012-13
http://mines.industry.qld.gov.au/assets/coal-pdf/queenslands-petroleum-2014.pdf
Queensland’s unconventional petroleum potential
http://mines.industry.qld.gov.au/assets/coal-pdf/qld-unconventional-2014.pdf
Queensland’s coal seam gas overview
http://mines.industry.qld.gov.au/assets/coal-pdf/csg-update-2014.pdf
Queensland production and reserves statistics
http://mines.industry.qld.gov.au/mining/production-reserves-statistics.htm
Santos Annual Report 2012
http://www.santos.com/Archive/NewsDetail.aspx?p=121&id=1367
Santos GLNG contracted resources and well production rates
http://www.santos.com/library/2014_09_15_%20CLSA%20presentation.pdf (pages 113-14)
Page 17 of 33
New South Wales
Unconventional resource potential:
Basin/Formation
Tight gas
Clarence-Moreton Basin
Walloon Coal Measures
Ipswich Coal Measures
Nymboida Coal Measures
Surat Basin
Walloon Coal Measures
Gunnedah Basin
Black Jack Formation
Maules Creek Formation
Sydney Basin
Narrabeen Group
Bulgo Sandstone
Colo Vale Sandstone
Illawarra Coal Measures
Wittingham Coal Measures
Newcastle Coal Measures
Tomago Coal Measures
Greta Coal Measures
Shoalhaven Group
Clyde Coal Measures
Gloucester Basin
Gloucester Coal Measures
Ashford Basin
Ashford Coal Measures














Shale gas















CSG
Status



Preliminary exploration
Inactive
Inactive

Preliminary exploration


Preliminary exploration
Preliminary exploration





Inactive
Inactive
Inactive
Producing
Preliminary exploration
Preliminary exploration
Preliminary exploration
Preliminary exploration
Inactive
Inactive





Preliminary exploration
Preliminary exploration
Table 3.1: New South Wales unconventional resource potential
COMMERCIAL
SUB-COMMERCIAL
DISCOVERED PIIP
UNDISCOVERED PIIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
Reserves/Resources:
PRODUCTION: 3 PJ in 2013
RESERVES
1P: 284 PJ
RESERVES
2P: 2 619 PJ
RESERVES
3P: 3 919 PJ
CONTINGENT RESOURCES
1C: 527 PJ
CONTINGENT RESOURCES
2C: 4 128 PJ
CONTINGENT RESOURCES
3C: 3 757 PJ
UNRECOVERABLE
PROSPECTIVE RESOURCES
Low Estimate
PROSPECTIVE RESOURCES
Best Estimate: 14 401 PJ
PROSPECTIVE RESOURCES
High Estimate
UNRECOVERABLE
Source: NSW Department of Resources and Energy, July 2014 (CSG in the Sydney, Gunnedah, and Clarence-Moreton
Basins); APPEA 2013 production statistics
Table 3.2: New South Wales unconventional resources
Page 18 of 33
Production/Forecasts:
The only unconventional gas produced in NSW is from AGL’s Camden Gas Project, which
produces about 5 per cent of the State’s gas supply, averaging approximately 6 PJ per annum.
NSW currently consumes approximately 160 PJ per annum of natural gas (Santos Ltd 2013).
No significant increases in production are forecast in the short term but applications have been
submitted to the NSW Department of Planning for AGL’s Gloucester Gas Project and Santos’s
Narrabri Gas Project. The Gloucester Gas project proposes to produce up to 30 PJ per annum
for 30 years, and the Narrabri Gas project proposes to produce up to 73 PJ per annum for 25
years. For now it is uncertain as to when these projects will finalise the approval process and
begin producing.
EXPECTED ANNUAL NORTHWEST NSW CSG PRODUCTION
Source: The Allen Consulting Group (2011)
Figure 3.1: Proposed gas production from the Narrabri Coal Seam Gas project
Unconventional resource drilling activity:
Currently low.
Number of Unconventional Petroleum Wells Drilled in NSW
90
80
70
60
50
40
30
20
10
0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Source: NSW Department of Resources and Energy, July 2014
Figure 3.2: Drilling activity in New South Wales
Page 19 of 33
Commentary:
In addition to the CSG resources identified to date, conventional and tight gas resources may
also be present, either in sandstones associated with the coal seams or independent of them. A
number of gas accumulations have been discovered in the Sydney Basin but these typically
produce gas at a rapidly declining rate from vertical wells, indicating tight reservoirs or limited
reservoir extent. Current drilling technology may make further investigation of these
discoveries viable.
References:
APPEA Petroleum Production Statistics 2013
http://www.appea.com.au/?attachment_id=5432
Cadman, S. J. and Pain, L., (1998) Bowen and Surat Basins, Clarence-Moreton Basin, Sydney
Basin, Gunnedah Basin and other minor onshore basins, Queensland, NSW and NT.
Australian Petroleum Accumulations Report 11, Bureau of Resource Sciences, Canberra
Inaugural Report to the Standing Council on Energy and Resources (SCER), NSW Department of
Resources and Energy, August 2013
The Allen Consulting Group, The economic impacts of developing coal seam gas operations in
Northwest NSW, Report to Santos, December 2011
http://www.allenconsult.com.au/resources/acgeconomicimpactcoalseam2011.pdf
Santos Ltd (2013) Inquiry into downstream gas supply and availability in NSW, Santos
submission to NSW Legislative Assembly, State and Regional Development Committee,
21st June 2013,
http://www.santos.com/library/Inquiry_into_downstream_gas_supply_and_availability_
Santos_submission.pdf
Page 20 of 33
Victoria
Unconventional resource potential:
Basin/Formation
Tight gas
Shale gas
CSG
Gippsland Basin
Lakes Entrance Formation
*

Strzelecki Formation
*
Otway Basin

Pretty Hill Formation


Sawpit Shale

Casterton Formation
*
*Unconventional oil and gas potential
**Activities suspended due to current State moratorium on fracture stimulation.
Status
Inactive
Under assessment**
Inactive
Preliminary exploration
Preliminary exploration
Table 4.1: Victorian unconventional resource potential
PRODUCTION
COMMERCIAL
SUB-COMMERCIAL
DISCOVERED PIIP
UNDISCOVERED PIIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
Reserves/Resources:
RESERVES
1P
RESERVES
2P
RESERVES
3P
CONTINGENT RESOURCES
1C: 403 PJ
CONTINGENT RESOURCES
2C: 755 PJ
CONTINGENT RESOURCES
3C: 1 212 PJ
UNRECOVERABLE
PROSPECTIVE RESOURCES
Low Estimate
PROSPECTIVE RESOURCES
Best Estimate: 452 PJ*
PROSPECTIVE RESOURCES
High Estimate
UNRECOVERABLE
Source: Lakes Oil, includes Wombat, Trifon, Gangell and North Seaspray tight gas except for *Wombat only
Table 4.2: Victorian unconventional resources
Production/Forecasts:
None.
Unconventional resource drilling activity:
nil.
Commentary:
The difficulties of developing the tight gas resource in proximity to ample supplies of
conventional gas offshore have been compounded by the recent moratorium on fracture
stimulation which will be required to prove the commercial viability of these reservoirs. This
has provided little incentive to explore further in the region.
Page 21 of 33
References:
Lakes Oil website
http://www.lakesoil.com.au/index.php/reports-and-announcements/category/announcements-2010
10-August-2010
http://www.lakesoil.com.au/index.php/reports-and-announcements/category/announcements-2009
1-July-2009
Page 22 of 33
Tasmania
Unconventional resource potential:
Basin/Formation
Tight gas
Shale gas
CSG
Tasmania Basin
Woody Island Formation
*+
*+
*Unconventional oil and gas potential + nature of resources yet to be determined
Status
Inactive
Table 5.1: Tasmanian unconventional resource potential
Reserves/Resources:
None.
Production/Forecasts:
None.
Unconventional resource drilling activity:
None.
Commentary:
While there is prospectivity for both conventional and unconventional resources in Tasmania,
there have been no discoveries and limited exploration undertaken to date.
References:
The Tasmania Basin – Gondwanan Petroleum system
http://www.mrt.tas.gov.au/mrtdoc/tasxplor/download/02_4832/Tasmaniax.pdf
Page 23 of 33
South Australia
Unconventional resource potential:
Basin/Formation
Tight gas
Shale gas
CSG
Status
Eromanga Basin

Winton Formation
Inactive**
Cooper Basin


Toolachee Formation
Under assessment***

Roseneath Shale
Under assessment***

Epsilon Formation
Under assessment***

Murteree Shale
Under assessment***



Patchawarra Formation
Under assessment***
Warburton Basin

Pando Formation
Inactive



Dullingari Group
Inactive



Kalladeina Formation
Inactive


Mooracoochie Volvcanics
*
Inactive
Pedirka Basin

Purni Formation
Inactive
Simpson Basin

Peera Peera Formation
Inactive
Officer Basin

Observatory Hill Formation
*
Inactive


Ouldburra Formation
Inactive


Narana Formation
Inactive


Dee Dee Mudstone
Inactive
Arckaringa Basin

Mount Toondina Formation
Preliminary exploration
Stuart Range Formation
*
Preliminary exploration
Otway Basin

Pretty Hill Formation
Inactive


Sawpit Shale
Preliminary exploration

Casterton Formation
*
Preliminary exploration
*Unconventional oil and gas potential
**Preliminary exploration showed coal thickness and gas content currently below commercial thresholds
***Minor production
Table 6.1: South Australian unconventional resource potential
The nature of these resource plays is fully described in Chapters 2 and 4 of the “Roadmap for
Unconventional Gas Projects in South Australia”.
Page 24 of 33
PRODUCTION
COMMERCIAL
SUB-COMMERCIAL
DISCOVERED PIIP
UNDISCOVERED PIIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
Reserves/Resources:
RESERVES
1P
RESERVES
2P
RESERVES
3P
CONTINGENT RESOURCES
1C: 1 725 PJ*
CONTINGENT RESOURCES
2C: 5 395 PJ**
CONTINGENT RESOURCES
3C: 6 807 PJ*
UNRECOVERABLE
PROSPECTIVE RESOURCES
Low Estimate: 45 000 PJ***
PROSPECTIVE RESOURCES
Best Estimate: 118 000 PJ*
PROSPECTIVE RESOURCES
High Estimate: 268 000 PJ***
UNRECOVERABLE
Source: *Roadmap for Unconventional Gas Projects, pages 91-2, Santos Cooper Basin Unconventional Gas
Opportunities and Commercialisation, page 6, includes PGA Prospective Resource Best Estimate,
** As for * plus Beach Energy,
*** As for * plus Roadmap for Unconventional Gas Projects, page 108
Table 6.2: South Australian unconventional resources
Production/Forecasts:
Minor production from recent shale gas exportation wells.
Santos plan “material commercial shale production and reserve bookings by 2015/16
underpinning Cooper development beyond 2020” suggesting larger scale production by the end
of the decade (Santos Cooper Basin Unconventional Gas Opportunities and Commercialisation).
The challenges associated with accelerating shale gas production are described at pages 158
and 159 of the Roadmap for Unconventional Gas Projects in South Australia (see link below).
Beach Energy, Drillsearch and Senex are also actively exploring the REM and Patchawarra
resource while Beach Energy and Strike Energy are assessing coal seam gas potential in the
southern Cooper Basin. Beach booked 2P+2C unconventional resources of 362 mmbbloe in the
Cooper Basin, equivalent to 2.168 Tcf of gas. For PRLs 33 to 48 and ATP 855 along, net 1.6 Tcf
2C resources was booked for Beach Energy (see the link below). Contingent unconventional gas
resources totalling more than 5 Tcf have been identified in the South Australian Cooper Basin
by the Cooper Basin Joint Venture (operated by Santos), Beach Energy and Senex Energy,
approaching the total sales gas production from the Basin to date. Cooper Energy is
investigating the shale gas potential of the Otway Basin. There is no production forecast
associated with this activity.
Unconventional resource drilling activity:
Moderate.
Explorers have accelerated appraisal of Cooper Basin unconventional plays since the first
exploration well to test these plays was drilled in 2010 (Table 1). Following on from 13 vertical
Page 25 of 33
wells to test unconventional gas plays in 2012, 13 wells were drilled during 2013 (Table 6.2). In
December 2012, Beach Energy spudded Holdfast, the first dedicated horizontal well to test
shale gas deliverability in the State. Fracture stimulation and flow testing programs have also
gathered pace.
Year
2010
2011
2012
2013
No. of Wells Drilled
2
2
13
13
Source: Department of State Development, South Australia
Table 6.2. Number of wells targeting natural gas in unconventional reservoirs, SA.
In 2013, Santos drilled Moomba 192, Moomba 194 and Roswell 2 horizontal wells targeting
deep unconventional gas plays in the Moomba Field and Van der Waals 1 and Langmuir 1 in the
Nappamerri Trough. Santos announced in December 2013 that the Moomba 194 vertical shale
gas well, adjacent to Moomba 191, flowed gas at an average rate of 3 mmscf/d. The well
appraised the gas potential in various unconventional and shale plays, five standard fracture
stimulation stages were run to test the Patchawarra deep coal, Patchawarra tight sand, upper
Patchawarra hybrid shale, as well as the Murteree shale and Epsilon hybrid shale zones.
Moomba 195 horizontal well is expected to test the Murteree Shale.
Beach Energy continued to explore Nappamerri Trough shale gas and basin centred gas plays in
PEL 218; a total of ten vertical and two horizontal exploration wells have been drilled, eight of
these have been fracture stimulated and four flow tested. The first horizontal well to test
Cooper Basin shale gas deliverability, Holdfast 2, spudded in December 2012 and on 22 January
2013, the vertical section was completed and the well was deviated towards the horizontal
section through the Murteree Shale target.
Senex drilled 6 exploration, 4 appraisal and 4 development wells in Cooper Basin Permits. Senex
also acquired 2140 km2 3D from the Dundinna, Cordillo and Lignum seismic surveys. Burruna 2
oil discovery was their outstanding success in 2013 with flows in excess of 3600 barrels of oil
per day (BOPD). Production rates are expected to be restricted to 800 BOPD. Successful
fracture stimulation of Senex unconventional gas wells in 2013 include favourable results with
Hornet 1 flowing at 2.2 million standard cubic feet per day (mmscfd) and Kingston Rule 1
flowing at 1.2 mmscfd. Senex also fracture stimulated Paning 2 deep coal exploration well. The
Toolachee coal successfully demonstrated the ability to flow gas at 90 000 standard cubic feet
per day on a four day production test.
PEL 96 in the southern Cooper Basin was granted to Strike Energy in May 2009 and exploration
for moderate to deep Permian coals commenced in 2010 with the drilling of Forge 1. In
November 2013 Le Chiffre 1 was drilled and encountered 105 m of Permian coal of which 86 m
was cored and recovered. The well is currently cased for future fracture stimulation. Mid
December 2013, Klebb 1 was spudded and plans for extensive wireline logging to be acquired.
Strike plan for the well to be cased and suspended for future production testing.
Commentary:
Over 700 fracture stimulations have been undertaken in the Cooper Basin since production
commenced in 1969. Some of these stimulations were in tight sandstones in the REM and
Patchawarra Formation sequence that contain the shale gas and coal seam gas resources.
Page 26 of 33
Better than expected well performance suggests that these wells have been producing from the
unconventional reservoirs adjacent to the tight sands.
The potential from these reservoirs is very large. Morton (1998) has estimated that the Cooper
Basin source rocks have the potential to have generated between 4 027 and 8 055 Tcf of gas
although only a small portion of that could reasonably be regarded as a resource.
With regard to the timing of production, it is unlikely that substantial volumes of gas from this
resource will be available to the East coast gas market in the short term.
References:
Beach Energy, FY14 Full Year Results Roadshow in September 2014
http://www.beachenergy.com.au/IRM/Company/ShowPage.aspx/PDFs/358179282719/FY14FullYearResultsRoadshowSeptember2014
Morton, J.G.G., 1998. Undiscovered petroleum resources. In: Gravestock, D.I., Hibburt, J.E. and
Drexel, J.F. (eds) The Petroleum Geology of South Australia, Volume 4: Cooper Basin.
South Australian Department of Primary Industries and Resources. Report Book 203-09
Roadmap for Unconventional Gas Projects in South Australia
http://www.pir.sa.gov.au/petroleum/prospectivity/basin_and_province_information/unconventional_gas
/unconventional_gas_interest_group/roadmap_for_unconventional_gas_projects_in_sa
Santos Annual Report 2012
http://www.santos.com/Archive/NewsDetail.aspx?p=121&id=1367
Santos Cooper Basin Unconventional Gas Opportunities and Commercialisation
http://www.santos.com/library/121112_EABU_Cooper_Basin_Unconventional_Gas_Opportunities_and_
Commercialisation.pdf
http://www.santos.com/library/121112_EABU_Cooper_Basin_Unconventional_Gas_Opportunities_and_
Commercialisation.pdf
Page 27 of 33
Western Australia
Unconventional resource potential:
Basin/Formation
Tight gas
Northern Perth Basin
Yarragadee Formation
Kockatea Shale
Dongara/Wagina Sandstone
Carynginia Formation
Irwin River Coal Measures
High Cliff Sandstone
Southern Perth Basin
Sue Coal Measures
Canning Basin
Laurel Formation
Goldwyer Formation
Bonaparte Basin
Milligans Formation
“Bonaparte Formation”
*Unconventional oil and gas potential
Shale gas
CSG

*











Status
Under assessment
Under assessment
Under assessment
Under assessment
Under assessment
Under assessment
Inactive

*



Preliminary exploration
Preliminary exploration
Inactive
Inactive
Table 7.1: Western Australian unconventional resource potential
PRODUCTION
COMMERCIAL
SUB-COMMERCIAL
DISCOVERED PIIP
UNDISCOVERED PIIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
Reserves/Resources:
RESERVES
1P
RESERVES
2P
RESERVES
3P
CONTINGENT RESOURCES
1C: 3 275 PJ*
CONTINGENT RESOURCES
2C: 4 599 PJ*
CONTINGENT RESOURCES
3C: 5 898 PJ*
UNRECOVERABLE
PROSPECTIVE RESOURCES
Low Estimate
PROSPECTIVE RESOURCES
Best Estimate: 427 000 PJ**
PROSPECTIVE RESOURCES
High Estimate
UNRECOVERABLE
Source:* Norwest Energy, Transerv,,AWE ** Norwest Energy, EIA/ARI World Shale Gas and Shale Oil Resource
Assessment, AWT data in ACOLA Report 6 Securing Australia’s Future – Engineering energy
Table 7.2: Western Australian unconventional resources
Production/Forecasts:
None
Page 28 of 33
Unconventional resource drilling activity:
Moderate.
Since 2005 towards end 2013, 15 exploration wells have been drilled to search for shale and
tight gas resources in Western Australia. Seven of these involved hydraulic fracturing to test the
capacity of the reservoir to generate commercial gas flows.
Commentary:
WA is considered to hold significant shale and tight gas resources in the Kimberley, East Pilbara
and Midwest regions. DMPWA has shown that the state potentially contains an estimated 280
trillion cubic feet in place resources of shale and tight gas. Of this, approximately 235 trillion
cubic feet are in the Canning Basin (Kimberley and East Pilbara regions) and 45 trillion cubic feet
are in the northern Perth basin (Midwest region).
The Canning Basin is recognised as having great potential, if only for the vast size of the basin.
Prospective formations have great areal extent although the extent of unconventional
resources within them is currently unknown. Resource estimates assessing the whole of a
formation across the basin should, therefore, be suitably discounted for this uncertainty. Due
to the remoteness of the basin, transport and infrastructure will also be a significant issue in
any unconventional resource development.
The Northern Perth Basin, however, is however better placed near infrastructure and pipelines
and is more likely to see unconventional gas reach market first.
If exploration in Western Australia proves successful, significant commercial production is
anticipated to be five to 10 years away.
References:
Arrowsmith
http://www.norwestenergy.com.au/assets/files/ASX%20Announcements/2013/2013%2008%2002%20EP
413%20DM%20Contingent%20Resource%20Estimate.pdf
AWE 2014FY Results
http://www.awexplore.com/IRM/Company/ShowPage.aspx/PDFs/3270
DMP, 2014 Natural Gas from Shale and Tight Rocks
http://www.dmp.wa.gov.au/documents/Natural_Gas_from_Shale_and_Tight_Rocks__An_overview_of_Western_Australia_regulatory_framework.pdf
EIA/ARI World Shale Gas and Shale Oil Resource Assessment
http://www.eia.gov/analysis/studies/worldshalegas/
Warro
http://www.transerv.com.au/images/stories/2012-11-05_Warro_Final_Commitment.pdf
Western Australian Atlas of Petroleum Fields, Vol. 1, Onshore Perth Basin, Owad-Jones, D. and
Ellis, G., 2000
Western Australia Atlas of Petroleum Fields, Volume 2, Part 1, Onshore Canning Basin,
Jonasson, K.E., 2001
Western Australia Atlas of Petroleum Fields, Volume 2, Part 2, Onshore Carnarvon Basin, Ellis,
G.K. and Jonasson, K.E., 2001
Whicher Range Development Concept
http://www.whicherenergy.com/index.php?option=com_content&view=article&id=60:developmentconcept&catid=37:ep408&Itemid=69
Page 29 of 33
Northern Territory
Unconventional resource potential:
Basin/Formation
Onshore Bonaparte Basin
Milligans Formation
“Bonaparte Formation”
Georgina Basin
Arthur Creek Formation
Thorntonia Limestone
Chabalowe Formation
McArthur Basin/Beetaloo Sub-basin
Kyalla Formation
Velkerri Formation
Barney Creek Formation
Coxco Dolostone
Bessie Creek Sandstone
Moroak Sandstone
Mount Isa Superbasin
Lawn Hill Shale
Riversleigh Siltstone
Amadeus Basin
Pacoota Sandstone
Horn Valley Siltstone
Stairway Sandstone
Eromanga Basin
Toolebuc Formation
Oodnadatta Formation
Tight gas
Shale gas




Inactive
Preliminary exploration




















Preliminary exploration
Preliminary exploration
Inactive
















Inactive
Inactive





Pedirka Basin
Peera Peera Formation
Purni Formation
Ngalia Basin
Mount Eclipse Sandstone
Wiso Basin
Montejinni Limestone

CSG
Status
Preliminary exploration
Preliminary exploration
Preliminary exploration
Preliminary exploration
Preliminary exploration
Preliminary exploration
Preliminary exploration
Preliminary exploration
Preliminary exploration
Inactive
Inactive


Inactive
Inactive
Inactive
Inactive
Table 8.1: Northern Territory unconventional resource potential
Page 30 of 33
PRODUCTION
COMMERCIAL
UNDISCOVERED PIIP
SUB-COMMERCIAL
DISCOVERED PIIP
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
Reserves/Resources:
RESERVES
1P
RESERVES
2P
RESERVES
3P
CONTINGENT RESOURCES
1C: 3.2 PJ
CONTINGENT RESOURCES
2C: 19.6 PJ
CONTINGENT RESOURCES
3C: 61.1 PJ
UNRECOVERABLE
PROSPECTIVE RESOURCES
Low Estimate
PROSPECTIVE RESOURCES
Best Estimate: 257 276 PJ
PROSPECTIVE RESOURCES
High Estimate
UNRECOVERABLE
Source: Munson (2014)
Table 8.2: Northern Territory unconventional resources
Production/Forecasts:
None
Unconventional resource drilling activity:
The number of wells drilled for unconventional resource exploration since 2011 are shown in
Table 8.3 and Figure 8.1.
Year
No. of Wells Drilled
2
2011
5
2012
10
2013
Table 8.3: Number of unconventional wells drilled since 2011
Number of Unconventional Gas Wells Drilled per
Year
12
10
Wells drilled
10
8
6
5
4
2
2
0
2011
2012
2013
Figure 8.1: Number of Unconventional Gas Wells Drilled per Year
Page 31 of 33
Commentary:
The rapid uptake of acreage in the Northern Territory is an indication of the interest in the
prospectivity of the basins in this region. There have been widespread indications of petroleum
during petroleum and stratigraphic drilling, and mineral exploration over many years. Some
operating companies are currently following up these indications, notably PetroFrontier
previously and now Statoil in the Georgina Basin, and Armour Energy in the Glyde Sub‐basin of
the McArthur Basin. Santos, Origin Energy and Sasol, and Pangaea Resources are actively
investigating shale plays in the Beetaloo Sub-basin.
In the Amadeus Basin, tight gas resources were identified during exploration drilling in the
1960s and 1980s, most notably in the Ooraminna and Dingo tight gas discoveries and follow up
work by Central Petroleum has confirmed their potential. A recent agreement will see
production from the Dingo accumulation by 2015. Beach Energy has commenced drilling wells
for unconventional targets within the Onshore Bonaparte Basin.
Basins in the Northern Territory, such as the McArthur Basin (including the Beetaloo Sub-basin)
host some of the oldest potentially recoverable unconventional gas resources in the world.
Recent seismic data has demonstrated the undercover continuity of the McArthur Basin over
more than 20 per cent of the Northern Territory.
At this stage there is no production from the unconventional gas resources in the Northern
Territory. Unconventional gas exploration is still at its early stage.
References:
Armour Energy
http://www.armourenergy.com.au/investors/investment-research 7-August-2013
Energy NT 2013
http://www.nt.gov.au/d/core/Content/File/commodities/2013_EnergyNT.pdf
Independent Expert’s Report for Armour Energy Limited
http://www.empireenergy.com/pdf/McArthur%20Basin%20Armour%20Co%20Ltd%20In
d.%20Geo's%20Report.pdf
Magellan signs long-term gas supply deal for Dingo field
http://www.ogj.com/articles/2013/09/magellan-signs-long-term-gas-supply-deal-fordingo-field.html
Munson TJ, 2014. Petroleum geology and potential of the onshore Northern Territory,
2014. Northern Territory Geological Survey, Report 22.
Page 32 of 33
Offshore areas
Unconventional resource potential:
None
Reserves/Resources:
None
Production/Forecasts:
None
Unconventional resource drilling activity:
None
Commentary:
While unconventional resources undoubtedly exist in offshore jurisdictions, the current cost of
recovery is likely to be prohibitive, even where significant liquids recovery is possible.
It is unlikely that changes in price or technology will change this situation in the foreseeable
future.
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