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Upstream Petroleum and Offshore Minerals Working Group Inaugural Report to the

Standing Council on Energy and Resources on Unconventional Reserves, Resources, Production, Forecasts and Drilling Rates

Canberra, September 2013

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Contents

The Task 2 Key points 3 Australian Unconventional Gas Reserves/Resources 4 Scope and assumptions 4 Definitions 4 SPE PRMS 5 Rate decline in unconventional wells 6 Resource potential by jurisdiction 7 General references 8 Summaries: Queensland 9 New South Wales 15 Victoria 18 Tasmania 20 South Australia 21 Western Australia 24 Northern Territory 26 Offshore areas 28

The Task

SCER Task 24: Task Geoscience Australia with preparing a standardised national approach to the combining of jurisdictionally based unconventional gas reserves/resources and production data, including approaches to dealing with any confidentiality issues.

Due to their common basis, related UPOM Tasks also incorporated in this report are:

SCER Task 23: UPOM to provide regular and nationally consistent reports to SCER … on unconventional gas reserves/resources and production, including new well drilling rates …

SCER Task 25: UPOM to develop a means of collecting and reporting unconventional gas production forecasts … for inclusion in the periodic reporting on unconventional gas data …

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Key points

Current booked coal seam gas reserves exceed current LNG contract requirements

Current Queensland coal seam gas reserves allocated to LNG projects total 25.3 Tcf (26 600 PJ) while contracted volumes total 18.5 Tcf (19 400 PJ) of gas. Arrow Energy have an additional 9.5 Tcf (10 000 PJ) of currently uncommitted gas. In addition, Santos have secured access to an additional 1.3 Tcf (1350 PJ) of conventional gas from the Cooper Basin and third party supply agreement.

Current drilling rates meet estimated required drilling rates for coal seam gas 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

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Australian Unconventional Gas Reserves/Resources

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.

TOTA

L PETROLEUM

INITIALLY‐IN‐PLACE (PIIP)

DISCOVER

ED PIIP

COMMER

CIAL

PRODUCTION

RESERVES 1P: 117.7 PJ

RESERVES 2P: 38 336 PJ

RESERVES 3P: 6745 PJ

SUB‐COMMER

CIAL

CONTINGENT RESOURCES 1C: 7822 PJ

CONTINGENT RESOURCES 2C: 17 600 PJ


UNRECOVERABLE

UNDISCOVER

ED PIIP

PROSPECTIVE RESOURCES Low Estimate: 45 000 PJ

PROSPECTIVE RESOURCES Best Estimate: 752 060 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 coal seam gas 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 to 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 good brief 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 below) and in the “Roadmap for Unconventional Gas Projects in South Australia” (see link below) which also includes a brief description of the SPE PRMS resource reporting system in Chapter 1.

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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.

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.

TOTA

L PETROLEUM


DISCOVER

ED PIIP

COMMER

CIAL

PRODUCTION

RESERVES 1P

RESERVES 2P

RESERVES 3P

SUB‐COMMER

CIAL

CONTINGENT RESOURCES 1C



UNRECOVERABLE

UNDISCOVER

ED PIIP

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.

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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 a 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 resource.

A description of the definitions used in the system is on the SPE website (see link below). A non‐technical guideline and the full guideline, including sections on estimation of different types of unconventional resource are also available (see links below).

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.

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0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

Feb‐13 Mar‐13 Apr‐13 May‐13 Jun‐13 Jul‐13 Aug‐13

million

cubic

feet per day

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:

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Source: Moore, T. A., Coalbed methane: A review

Figure 1.2: Coal seam gas well decline

Figures B and C show wells where the gas production has reached a peak and is now declining; to 60% of peak after one year in Figure B (from the Bowen Basin) and to 30% 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.

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The reserves/resources section is a compilation of the reserves and resources 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/ACOLA/index.php/projects/securing‐australia‐s‐future/project‐6

Beach Energy http://www.beachenergy.com.au/irm/archive/asx‐announcements3.aspx

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

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_rfc‐ambrian_australian‐unconventional_oil_and_gas_report_.pdf

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http://www.armourenergy.com.au/assets/downloads/investment_research/2013/09-2013_rfc

http://www.spe.org/industry/docs/PRMS_guide_non_tech.pdf

http://www.spe.org/industry/docs/Petroleum_Resources_Management_System_2007.pdf

http://www.spe.org/industry/docs/PRMS_Guidelines_Nov2011.pdf

http://www.eia.gov/analysis/studies/worldshalegas

http://www.postcarbon.org/reports/DBD-report-FINAL.pdf

http://www.beachenergy.com.au/irm/archive/asx-announcements3.aspx

http://www.acola.org.au/ACOLA/index.php/projects/securing-australia-s-future/project-6

Queensland

Unconventional resource potential:

Basin/Formation Tight gas Shale gas CSG Status Laura Basin Dalrymple Sandstone Inactive

Maryborough Basin Maryborough Formation Inactive Tiaro Coal Measures Inactive

Clarence‐Moreton Basin Walloon Coal Measures Preliminary exploration

Surat Basin Walloon Coal Measures Producing

Bowen Basin Black Alley Shale Preliminary exploration Tinowon Formation Under assessment Moranbah Coal Measures Producing Baralaba Coal Measures Producing Fort Cooper Coal Measures Under assessment Rangal Coal Measures Under assessment Bandanna Formation Producing

Eromanga Basin Winton Formation Inactive Toolebuc Formation * Preliminary exploration Birkhead Formation Inactive Westbourne Formation Inactive Poolowanna Formation Inactive

Cooper Basin Toolachee Formation Under assessment Roseneath Shale Under assessment Epsilon Formation Under assessment Murteree Shale Under assessment Patchawarra Formation Under assessment

Galilee Basin Betts Creek Beds Preliminary exploration Aramac Coal Measures Preliminary exploration Lake Galilee Sandstone Preliminary exploration

Adavale Basin Log Creek Formation Inactive Lissoy Sandstone Inactive Cooladdi Dolomite Inactive

Georgina Basin Arrinthrunga Formation Inactive Inca Shale Inactive Thorntonia Limestone Inactive Beetle Creek Formation Inactive Georgina Limestone Inactive

Mount Isa Superbasin Lawn Hill Shale Preliminary exploration Termite Range Formation Inactive Riversleigh Siltstone Preliminary exploration

*Unconventional oil and gas potential

Table 2.1: Queensland unconventional resource potential

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Reserves/Resources: TO

TAL PETROLEUM


DISCOVER

ED PIIP

COMMER

CIAL

PRODUCTION: 254.5 PJ (2011‐12)*

RESERVES 1P

RESERVES 2P: 35 435 PJ**

RESERVES 3P

SUB‐COMMER

CIAL




UNRECOVERABLE

UNDISCOVER

ED PIIP


PROSPECTIVE RESOURCES Best Estimate: 164 000 PJ***


UNRECOVERABLE

Source: *Queensland production and reserves statistics as at 31/12/2013, **Queensland’s petroleum exploration, development and potential 2011‐12, ***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 two years has not seen significant changes in reserves. This may be due to infill drilling of currently booked areas to provide enough wells to supply gas at a sufficient rate for the LNG plants.

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0.0

2.0

4.0

6.0

8.0

10.0

12.0

1/01/2005 1/01/2007 1/01/2009 1/01/2011 1/01/2013

Reserves (Tcf)

GLNG QGCLNG APLNG 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 300 PJ in 2012 (37 PJ of conventional gas and 269 PJ of coal seam gas, the equivalent of about 5.5 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.

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0

5

10

15

20

25

30

Contracted

volumes (M

T/a)

Contracted volumes

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.

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0

1000

2000

3000

4000

5000

6000

0

20

40

60

80

100

120

140

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Cumulative

number of w

ells

Number of w

ells

per month

Year

Queensland CSG drilling activity

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.

0

2000

4000

6000

8000

10000

12000

14000

16000

Cumulative

number of w

ells

Year

Queensland CSG drilling activity

Cumulative wells Projected drilling

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Figure 2.4: Historic and proposed cumulative coal seam methane wells

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) Contracted volume Tcf (PJ) APLNG 9.3 (9800) 6.5 (6800) GLNG 6.0 (6300) 5.3 (5600) QCLNG 10.0 (10500) 6.7 (7000) Arrow 9.5 (10 000) ‐

Table 2.3: Coal seam gas resources and LNG contracted volumes

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.

QUARTER GLNG APLNG QCLNG TOTAL 2014 1Q 0.290 0.132 2014 2Q 0.275 0.125 2014 3Q 0.262 0.119 2014 4Q 0.250 0.113 2015 1Q 0.115 0.565 0.284 2015 2Q 0.217 0.536 0.298 2015 3Q 0.412 0.390 0.510 0.453 2015 4Q 0.393 0.371 0.486 0.433 2016 1Q 0.421 0.433 0.465 0.451 2016 2Q 0.403 0.411 0.445 0.433 2016 3Q 0.429 0.634 0.427 0.501 2016 4Q 0.411 0.605 0.410 0.483 2017 1Q 0.435 0.578 0.395 0.476 2017 2Q 0.418 0.553 0.380 0.461 2017 3Q 0.440 0.531 0.367 0.456 2017 4Q 0.425 0.510 0.355 0.442 2018 1Q 0.444 0.491 0.343 0.438 2018 2Q 0.430 0.473 0.332 0.426 2018 3Q 0.416 0.457 0.322 0.415 2018 4Q 0.404 0.441 0.312 0.404 2019 1Q 0.434 0.427 0.303 0.405 2019 2Q 0.421 0.414 0.295 0.395 2019 3Q 0.410 0.401 0.287 0.386 2019 4Q 0.398 0.389 0.279 0.378 2020 1Q 0.388 0.378 0.272 0.370 2020 2Q 0.378 0.367 0.265 0.362 2020 3Q 0.368 0.357 0.258 0.355 2020 4Q 0.359 0.348 0.252 0.348 2021 1Q 0.351 0.338 0.246 0.341 2021 2Q 0.342 0.328 0.241 0.334 2021 3Q 0.335 0.319 0.235 0.328 2021 4Q 0.327 0.311 0.230 0.322 2022 1Q 0.320 0.302 0.225 0.316 2022 2Q 0.313 0.295 0.220 0.311 2022 3Q 0.306 0.288 0.216 0.306 2022 4Q 0.300 0.281 0.211 0.301

Table 2.4: Coal seam gas resources and LNG contracted volumes

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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 and 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 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 7‐day 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.

Information on individual well productivity for the currently producing wells is not available 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

Queensland’s petroleum exploration, development and potential 2011‐12 http://mines.industry.qld.gov.au/assets/coal‐pdf/queenslands‐petroleum‐2013.pdf

Queensland’s unconventional petroleum potential http://mines.industry.qld.gov.au/assets/petroleum‐pdf/cc12‐pet007_q_unconvent.pdf

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http://mines.industry.qld.gov.au/assets/petroleum-pdf/cc12-pet007_q_unconvent.pdf

http://mines.industry.qld.gov.au/assets/coal-pdf/queenslands-petroleum-2013.pdf

http://www.empireenergy.com/pdf/McArthur%20Basin%20Armour%20Co%20Ltd%20Ind.%20Geo's%20R

http://www.armourenergy.com.au/investors/investment-research

Queensland’s coal seam gas overview http://mines.industry.qld.gov.au/assets/coal‐pdf/csg‐update‐2013.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

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http://www.santos.com/Archive/NewsDetail.aspx?p=121&id=1367

http://mines.industry.qld.gov.au/mining/production-reserves-statistics.htm

http://mines.industry.qld.gov.au/assets/coal-pdf/csg-update-2013.pdf

New South Wales


Basin/Formation Tight gas Shale gas CSG Status Clarence‐Moreton Basin Walloon Coal Measures Preliminary exploration Ipswich Coal Measures Inactive Nymboida Coal Measures Inactive

Surat Basin Walloon Coal Measures Preliminary exploration

Gunnedah Basin Black Jack Formation Preliminary exploration Maules Creek Formation Preliminary exploration

Sydney Basin Narrabeen Group Inactive Bulgo Sandstone Inactive Colo Vale Sandstone Inactive

Illawarra Coal Measures Producing Wittingham Coal Measures Preliminary exploration Newcastle Coal Measures Preliminary exploration Tomago Coal Measures Preliminary exploration Greta Coal Measures Preliminary exploration Shoalhaven Group Inactive Clyde Coal Measures Inactive

Gloucester Basin Gloucester Coal Measures Preliminary exploration

Ashford Basin Ashford Coal Measures Preliminary exploration

Table 3.1: New South Wales unconventional resource potential

Reserves/Resources:

TOTA

L PETROLEUM


DISCOVER

ED PIIP

COMMER

CIAL

PRODUCTION: 6 PJ/a

RESERVES 1P: 117.7 PJ



SUB‐COMMER

CIAL




UNRECOVERABLE

UNDISCOVER

ED PIIP




UNRECOVERABLE

Source: NSW Department of Resources and Energy, August 2013 (CSG in the Sydney, Gunnedah, Gloucester and Clarence‐Moreton Basins)

Table 3.2: New South Wales unconventional resources

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The only unconventional gas produced in NSW is from AGL’s Camden Gas Project, which produces about 5% of the State’s gas supply, averaging approximately 6PJ per annum. NSW currently consumes approximately 138PJ per annum of natural gas (ACIL Allen Consulting, 2013 in Inaugural Report to the Standing Council on Energy and Resources (SCER), NSW Department of Resources and Energy, August 2013).

No significant increases in production are forecast in the short to term but in 2011 Santos provided Allen Consulting with a forecast of coal seam gas production from a new project, presumably based on the Eastern Star Gas Narrabri Coal Seam Gas Project in the Gunnedah Basin.

EXPECTED ANNUAL NORTHWEST NSW CSG PRODUCTION

Source: Provided by Santos.

Source: The Allen Consulting Group

Figure 3.1: Proposed gas production from the Narrabri Coal Seam Gas project


Currently low.

In 2010, Eastern Star gas made a drilling application for 550 coal seam gas wells in the Gunnedah Basin. The application was withdrawn after the takeover of Eastern Star Gas by Santos and it has not been resubmitted but Santos provided Allen Consulting with the forecast shown above in 2011. AGL made a drilling application in 2010 for 72 wells as the Northern Expansion of the Camden Gas Project but this was subsequently withdrawn due to “community concerns”. Recent changes to legislation that have resulted in the downgrading of AGL reserves may also have contributed to the observed decline in activity.

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Number of Boreholes Drilled per Year

0

10

20

30

40

50

60

70

80

90

100

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Bo

reh

ole

s D

rille

d

Source: NSW Department of Resources and Energy, August 2013

Figure 3.2: Drilling activity in New South Wales

Commentary:

In addition to the coal seam gas 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 rapid declining rate from vertical wells, indicating tight reservoirs or limited reservoir extent. Current drilling technology may make further investigation of these discoveries viable.

References:

AGL Annual Reserves Assessment, 2013 http://www.agl.com.au/about‐agl/media‐centre/article‐list/2013/aug/agl‐annual‐reserves‐assessment

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

Clarence‐Moreton Basin – Geological Overview http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary‐basins/clarencebasin

Coal seam methane in New South Wales http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary‐basins/methanensw

Gunnedah Basin – Geological Overview http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary‐basins/gunnedah

New South Wales drillhole data http://dwh.minerals.nsw.gov.au/CI/warehouse

Surat Basin – Geological Overview http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary‐basins/suratbasin

Sydney Basin – Geological Overview http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary‐basins/sydbasin

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

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http://www.allenconsult.com.au/resources/acgeconomicimpactcoalseam2011.pdf

http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary-basins/sydbasin

http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary-basins/suratbasin

http://dwh.minerals.nsw.gov.au/CI/warehouse

http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary-basins/gunnedah

http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary-basins/methanensw

http://www.resources.nsw.gov.au/geological/overview/regional/sedimentary-basins/clarencebasin

http://www.agl.com.au/about-agl/media-centre/article-list/2013/aug/agl-annual-reserves-assessment

Victoria


Basin/Formation Tight gas Shale gas CSG Status Gippsland Basin Lakes Entrance Formation * Inactive Strzelecki Formation * Under assessment**

Otway Basin Pretty Hill Formation Inactive Sawpit Shale Preliminary exploration Casterton Formation * Preliminary exploration

*Unconventional oil and gas potential **Activities suspended due to current State moratorium on fracture stimulation.

Table 4.1: Victorian unconventional resource potential

Reserves/Resources:

TOTA

L PETROLEUM

INITIALLY‐IN‐PLA

CE (PIIP)

DISCOVER

ED PIIP

COMMER

CIAL

PRODUCTION

RESERVES 1P

RESERVES 2P

RESERVES 3P

SUB‐COMMER

CIAL




UNRECOVERABLE

UNDISCOVER

ED PIIP


PROSPECTIVE RESOURCES Best Estimate: 452 PJ*


UNRECOVERABLE

Source: Lakes Oil, includes Wombat, Trifon, Gangell and North Seaspray tight gas except for *Wombat only

Table 4.2: Victorian unconventional resources


None.


Currently low.

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

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stimulation which will be required to prove the commercial viability of these reservoirs. This has provided little incentive to explore further in the region.

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

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http://www.lakesoil.com.au/index.php/reports-and-announcements/category/announcements-2009

http://www.lakesoil.com.au/index.php/reports-and-announcements/category/announcements-2010

Tasmania


Basin/Formation Tight gas Shale gas CSG Status Tasmania Basin Tasmanite Oil Shale * Inactive


Table 5.1: Tasmanian unconventional resource potential

Reserves/Resources:

None.


None.


None.

Commentary:

While there is prospectivity for both conventional and unconventional resources in Tasmania, the only current activity is exploration for and production of conventional petroleum in the offshore Bass Basin.

References:

The Tasmania Basin – Gondwanan Petroleum system http://www.mrt.tas.gov.au/mrtdoc/tasxplor/download/02_4832/Tasmaniax.pdf

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http://www.mrt.tas.gov.au/mrtdoc/tasxplor/download/02_4832/Tasmaniax.pdf

South Australia


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”.

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Reserves/Resources: TO

TAL PETROLEUM


DISCOVER

ED PIIP

COMMER

CIAL

PRODUCTION

RESERVES 1P

RESERVES 2P

RESERVES 3P

SUB‐COMMER

CIAL

CONTINGENT RESOURCES 1C:1725 PJ*

CONTINGENT RESOURCES 2C: 5395 PJ**

CONTINGENT RESOURCES 3C: 6807 PJ*

UNRECOVERABLE

UNDISCOVER

ED PIIP

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


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 page 158 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. Cooper Energy is investigating the shale gas potential of the Otway Basin. There is no production forecast associated with this activity.


Moderate.

Current drilling activity is mainly focussed on establishing well productivity and determining the optimal well completion strategy.

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

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Patchawarra Formation sequence that contain the shale gas and coal seam gas resources. 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 4027 and 8055 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.

It should be noted that 750 PJ of Santos operated Cooper Basin gas have been committed to the GLNG project from a 2012 reserves base of 1213 PJ. Santos Cooper Basin gas production in 2012 was 66.6 PJ, suggesting only 7 years of domestic gas supply remain from current Cooper Basin reserves at the current rate of production.

References:

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

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http://www.santos.com/library/121112_EABU_Cooper_Basin_Unconventional_Gas_Opportunities_and

http://www.santos.com/Archive/NewsDetail.aspx?p=121&id=1367

http://www.pir.sa.gov.au/petroleum/prospectivity/basin_and_province_information/unconventional_gas

Western Australia


Basin/Formation Tight gas Shale gas CSG Status Northern Perth Basin Yarragadee Formation Under assessment Kockatea Shale * Under assessment Dongara/Wagina Sandstone Under assessment Carynginia Formation Under assessment Irwin River Coal Measures Under assessment High Cliff Sandstone Under assessment

Southern Perth Basin Sue Coal Measures Inactive

Canning Basin Laurel Formation Preliminary exploration Goldwyer Formation * Preliminary exploration

Bonaparte Basin Milligans Formation Inactive “Bonaparte Formation” Inactive


Table 7.1: Western Australian unconventional resource potential

Reserves/Resources:

TOTA

L PETROLEUM


DISCOVER

ED PIIP

COMMER

CIAL

PRODUCTION

RESERVES 1P

RESERVES 2P

RESERVES 3P

SUB‐COMMER

CIAL




UNRECOVERABLE

UNDISCOVER

ED PIIP


PROSPECTIVE RESOURCES Best Estimate: 427 000 PJ**


UNRECOVERABLE

Source:* Norwest Energy, Transerv, ** 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


None


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Moderate.

Commentary:

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.

References:

Arrowsmith http://www.norwestenergy.com.au/index.php/asx‐releases/announcements/2013/ 2‐August‐2013

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:development‐concept&catid=37:ep408&Itemid=69

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http://www.whicherenergy.com/index.php?option=com_content&view=article&id=60:development

http://www.transerv.com.au/images/stories/2012-11-05_Warro_Final_Commitment.pdf

http://www.eia.gov/analysis/studies/worldshalegas

http://www.norwestenergy.com.au/index.php/asx-releases/announcements/2013

Northern Territory


Basin/Formation Tight gas Shale gas CSG Status Bonaparte Basin Milligans Formation Inactive “Bonaparte Formation” Inactive

Georgina Basin Arthur Creek Formation * Preliminary exploration

McArthur Basin/Beetaloo Sub‐basin Kyalla Formation Inactive Velkerri Formation * Inactive Barney Creek Formation Preliminary exploration

Mount Isa Superbasin Lawn Hill Shale Preliminary exploration Riversleigh Siltstone Preliminary exploration

Amadeus Basin Pacoota Sandstone * Inactive Horn Valley Siltstone * Inactive Stairway Sandstone * Inactive Eromanga Basin Poolowanna Formation Inactive

Pedirka Basin Peera Peera Formation Inactive

Ngalia Basin Inactive


Table 8.1: Northern Territory unconventional resource potential

Reserves/Resources:

TOTA

L PETROLEUM


DISCOVER

ED PIIP

COMMER

CIAL

PRODUCTION

RESERVES 1P

RESERVES 2P

RESERVES 3P

SUB‐COMMER

CIAL




UNRECOVERABLE

UNDISCOVER

ED PIIP




UNRECOVERABLE

Source: Empire Energy

Table 8.2: Northern Territory unconventional resources

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None.


Moderate.

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 in the Georgina Basin (tight oil) and Armour Energy in the Glyde Sub‐basin of the McArthur Basin and in the Queensland portion of the Mount Isa Super‐basin, both of which have yielded significant flows of gas.

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 development of the Dingo accumulation from existing wells by 2015.

References:

Armour Energy http://www.armourenergy.com.au/investors/investment‐research 7‐August‐2013

EnergyNT 2012 http://www.core.nt.gov.au/Content/File/commodities/2012_EnergyNT.pdf

Independent Expert’s Report for Armour Energy Limited http://www.empireenergy.com/pdf/McArthur%20Basin%20Armour%20Co%20Ltd%20Ind.%20Geo's%20R eport.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‐for‐dingo‐field.html

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http://www.ogj.com/articles/2013/09/magellan-signs-long-term-gas-supply-deal-for-dingo-field.html

http://www.empireenergy.com/pdf/McArthur%20Basin%20Armour%20Co%20Ltd%20Ind.%20Geo's%20R

http://www.core.nt.gov.au/Content/File/commodities/2012_EnergyNT.pdf

http://www.armourenergy.com.au/investors/investment-research

Offshore areas


None

Reserves/Resources:

None


None


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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energy council | - page 1 of 32 · 2017-02-16 · (26600 pj) while contracted volumes total 18.5...

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