Unconventional Oil and Gas Winter 2016 Digital Edition

UNCONVENTIONAL Issue 5 // WINTER 2016

DISCOVERING THE PERTH BASIN

EXPLORATION ACTION: WHERE ELSE BUT QUEENSLAND?

OVERCOMING THE OBSTACLES TO BECOMING A GLOBAL LNG LEADER

GALILEE TO FIRE EAST COAST MARKETS

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UNCONVENTIONAL

OIL GAS UNCONVENTIONAL Issue 5 // WINTER 2016

CONTENTS

Issue 5 // WINTER 2016

INTERVIEW

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UNCONVENTIONAL OIL & GAS

EXPLORATION IN THE PERTH BASIN

EXPLORATION ACTION: WHERE ELSE BUT QUEENSLAND?

OVERCOMING THE OBSTACLES TO BECOMING A GLOBAL LNG LEADER

Galilee to fire east coast markets

In the midst of uncertainty surrounding future gas supply to Australia’s east coast gas, coal seam gas explorer Comet Ridge has signed a Memorandum of Understanding (MOU) with APA Group to transport gas from the largely unexplored Galilee Basin to east coast gas markets.

WINTER 2016

GALILEE TO FIRE EAST COAST MARKETS

Cover image shows one of Comet Ridge’s CSG exploration wells.

QUEENSLAND

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Published by

Monkey Media Enterprises ABN: 36 426 734 954 PO Box 1763 Preston South VIC 3072 P: (03) 9988 4950 F: (03) 8456 6720 monkeymedia.com.au info@monkeymedia.com.au unconventionaloilandgas.com.au info@unconventionaloilandgas. com.au ISSN: 2204-8901

Where else but Queensland?

Queensland undeniably leads the rest of Australia when it comes to unconventional oil and gas development.

The sunshine state contains an array of geological basins prospective for unconventional sources of oil and gas, including coal seam gas, shale gas and oil, and tight gas and oil.

OPINION

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Overcoming the obstacles to becoming a global LNG leader

Australia has dominated global LNG capital expenditure in recent years. Last year, Accenture reported that the Australian LNG industry has the potential to become the world’s largest and most technologically advanced industry, contributing more than $55 billion to Gross Domestic Product in 2020.

Publisher and Editor Chris Bland Managing Editor Laura Harvey Associate Editor Jessica Dickers

BASIN PROFILE

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Contributing Editor Michelle Goldsmith Marketing Director Amanda Kennedy Marketing Consultant Aaron White

Exploration in the Perth Basin

In this instalment of our regular feature profiling Australian geological basins, we take a closer look at the Perth Basin. This WA basin is thought to contain significant tight gas, shale gas and shale oil resources, which may be suitable for commercial development. As a result, exploration activities in the basin have increased in recent years.

Senior Designer Alejandro Molano

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Designer Jacqueline Buckmaster

REGULARS

Contributing Designer Sandy Noke

News................................................................................................................. 6

WINTER 2016 // ISSUE 5

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NEWS

QLD RELEASES FIRST EXPLORATION PLAN

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he Queensland Government has released its first exploration plan which outlines the land that will be made available across the state for mineral, coal and gas exploration over the next 12 months.

Queensland Minister for State Development and Natural Resources and Mines, Dr Anthony Lynham released the first annual exploration program, that sets out the 826 sq km of land to be made available for exploration.

The seven areas range from Cloncurry in the north-west, though the Bowen Basin in central Queensland, to near Surat in the south-west.

“The Palaszczuk Government recognises that exploration is vital to discovering the resources that will drive the resources industry and help to deliver job creation, regional development and economic growth for Queensland,” Dr Lynham said.

“I’ve listened to industry and I have listened to the community, as we committed to do as a government.

“They want clear information that is timely and no surprises, and that’s what an annual exploration program will deliver.”

The areas to be released include: ♦♦ 102 sq km for minerals exploration in Queensland’s North West Minerals Province, to be released by September 2016 ♦♦ 451 sq km for petroleum and gas exploration near Surat and Injune between October and December 2016 ♦♦ 273 sq km for coal exploration between Middlemount and Blackwater in the Bowen Basin between April and June 2017.

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Australian Petroleum Production and Exploration Association (APPEA) Chief Executive, Dr Malcolm Roberts, said the plan will open prospective areas for natural gas exploration near Surat and Injune.

“Finding and developing gas reserves in this area will deliver significant benefits to local communities and Queensland as a whole,” Dr Roberts said.

“Past exploration successes have led to Queensland’s world-class LNG industry and ensured secure local supply of gas for Queensland households and industry.

“More than 13,000 people are directly employed in Queensland’s gas industry.

Developing new gas reserves is essential to sustaining these jobs and, in time, creating more jobs.”

The seven areas will be released for competitive tenders, and the successful tenderers will have to meet environmental and other requirements, including negotiating land access and compensation agreements with landholders and, where applicable, negotiate native title arrangements with traditional owners.

“The forward plan follows extensive consultations with local communities, farmers, traditional owners and the industry,” Dr Roberts said.

“Early consultations help build community understanding and confidence. It is far better to engage people early and to hear their views before decisions are made.

“For its part, the gas industry relies on the support of local communities. It is important that local people are part of the process from the very beginning.”

The release of the plan follows exploration concessions announced in early 2016, which allow explorers a reduction of up to 50 per cent over 2016 and 2017 on the expenditure they have to commit under their exploration permit.

“An annual forward program will allow resources explorers and miners to plan ahead for future opportunities,” Dr Lynham said.

“The resource sector is critical to our economy and our regional communities and that’s why we continue to provide a positive investment environment with our royalties freeze, the lowest payroll tax rate in the country and our heavy investment in innovation.”

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NEWS

NEW SA GAS

SUPPLY TRADING HUB

T

he Australian Energy Market Operator (AEMO) has officially opened a new gas supply trading hub in Moomba, South Australia.

The Moomba Gas Supply Hub is an exchange for the wholesale trading of natural gas at a location that serves as a major transit point for Cooper Basin gas connecting Queensland to New South Wales and South Australia.

It allows market participants to place bids on quantities of gas, and makes it easier for smaller participants to trade in the market.

South Australian Energy Minister Tom

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Koutsantonis called on AEMO to establish the trading hub in Moomba 12 months ago after Santos, Beach Energy and Origin Energy indicated they also back the establishment of an alternative trading location.

This hub follows the successful introduction by AEMO of the Wallumbilla Gas Supply Hub in Queensland, established in 2014 to enhance the transparency of gas supply by creating a voluntary market that offers a low-cost, flexible method to buy and sell gas at interconnecting transmission pipelines.

The Moomba trading location uses the same trading platform, settlement systems

and regulatory framework as those at Wallumbilla.

Mr Koutsantonis said this is good news for both gas suppliers and customers, because it offers market participants a cheap method of buying and selling gas and that increased competitive tension will put downward pressure on gas prices.

“It also allows a greater number of participants to engage in the energy market and improves the efficiency and transparency of pricing.

“Moomba is the perfect location for this hub because it sits at the intersection of pipelines to New South Wales, Queensland and South Australia.”

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NEWS

STRIKE’S FRACCING OPERATIONS COMPLETE

P

roduction testing and fraccing operations at Strike Energy’s Southern Cooper Basin Gas Project in Queensland have been successfully completed and have shown increases in productivity.

Strike Energy Managing Director David Wrench said, “The productivity improvements we have seen at Klebb 3 and the fact that we have now successfully completed seven fracs in the Patchawarra coals are important milestones – they’re further confirmation of our confidence in

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the long term productive capacity of the field and our ability to commercialise it.

“We are looking forward to having all four Klebb wells working together to accelerate progress towards commercial gas flows.”

Production testing at Strike’s Klebb operations were shut ahead of Klebb 4 fracture stimulation and flowback operations. Testing of Klebb 2 and 3 has also recommenced with Klebb 1 to restart in the near term.

The performance of the wells since recommencement of testing had been

consistent with previous production rampups and Strike was particularly pleased with the improved productivity of Klebb 3.

At Klebb 3, the current water production rate had recorded a 20–25 per cent improvement in productivity.

The sustained increase in productivity at Klebb 3 was typical of the performance of many highly productive fields.

The higher water rates implied that the well was de-pressuring a larger volume of coal, which would lead to higher gas rates than those previously achieved as the coal approached critical desorption pressure.

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NEWS

NEW SUSTAINABLE ONSHORE OIL AND GAS REGULATIONS

N

ew Petroleum (Environment) Regulations in the Northern Territory aim to ensure onshore oil and gas development in the state is ecologically

sustainable.

The regulations have now come into effect, following recommendations by energy law experts Dr Tina Hunter and Dr Allan Hawke.

The Liberal Government also consulted local communities and scientific experts regarding concerns on the safe and environmentally responsible conduct of onshore gas and oil activity in the state.

Northern Territory Minister for Mines and Energy David Tollner said the new Petroleum (Environment) Regulations will form an important part of the regulatory framework for the onshore oil and gas industry and are key to ensuring environmental protection.

“The regulations require that approved environment management plans must be in place for all onshore oil and gas activities that have an environmental impact,” Mr Tollner said.

“The plan must demonstrate that all environmental risks and impacts are identified and reduced to an acceptable level and a level that is as low as reasonably priced.

“The regulations incorporate best practice from other Australian and international jurisdictions and deliver on relevant recommendations and findings by Dr Allan Hawke AC about the introduction of a best-practice regulatory framework for the NT.” The new regulations embrace the principles of ecologically sustainable development and focus on reducing environmental impacts to levels that are both acceptable and as low as reasonably practicable.

Approved Environment Management Plans will become public and legally binding documents, meaning that companies must fully comply with their approved plans.

“Dr Hunter’s findings found that the regulations were ‘a quantum leap forward’ from the previous regulatory framework and ‘herald a new era of objective-based regulation,” Mr Tollner said.

“Dr Hunter specifically praised the requirement that any petroleum development must be assessed by the Mines Minister for its risks and impacts against the principles of Ecologically Sustainable Development to determine whether or not the activity can go ahead.

“The Country Liberals Government is determined to implement the world’s best practice environmental regulation,

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particularly the protection of our water supply and assets.

“The new Petroleum (Environment) Regulations will ensure the Territory’s environment is protected and that any onshore oil and gas activity can only occur if it is ecologically sustainable for the Northern Territory.”

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INTERVIEW

Galilee to fire east coast markets

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INTERVIEW

Comet Ridge drilling a coal seam gas exploration well.

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INTERVIEW

In the midst of uncertainty surrounding future gas supply to Australia’s east coast gas, coal seam gas explorer Comet Ridge has signed a Memorandum of Understanding (MOU) with APA Group to transport gas from the largely unexplored Galilee Basin to east coast gas markets.

C

omet Ridge Managing Director Tor McCaul believes the Galilee Basin, located 200 kilometres west of Queensland’s Bowen Basin, will play a big part in Australia’s future gas story.

The recently signed MOU with Australia’s largest natural gas infrastructure business, APA Group, further highlights the basin’s exploration potential.

APA Group has agreed to work with Comet Ridge to transport gas from Galilee

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to the East Coast via a new transmission pipeline and associated midstream infrastructure that APA will build, own and operate.

Mr McCaul said the main aim of the transportation project is to work with APA and its extensive network to connect Galilee to markets in Gladstone and Brisbane, but this could also extend to markets further south.

“We think Galilee is going to play a big part in the country’s gas story,” Mr McCaul said.

“It’s one of the few remaining places in Queensland where there’s actually large volumes of gas that can be gathered up and sent to industrial buyers or to places like Gladstone for LNG. “What we do best is work on the subsurface, so having someone like APA in there means that we can potentially say to someone in Brisbane, you can sign up for a Galilee molecule, and APA’s got the capacity to actually get it to you. That’s what’s significant.”

The MOU provides a framework of

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INTERVIEW

A production test at Gunn 2 aiming to establish water flow rate and water samples.

cooperation between the two parties with the next steps involving confirmation of the pipeline’s exact route.

Mr McCaul said the two companies are currently working out what is the most logical route and what are the connection points that will take full advantage of the supply.

“I think logically the gas should come out of the basin south-easterly because that’s where the major market is, down towards Gladstone or Brisbane,” Mr McCaul said.

“We’re probably a little bit too far to the east, and too close to the coast to really be considering a westerly connection

over to the Carpentaria line. APA’s got the Carpentaria line that runs up to Mount Isa in the west and because Galilee is such a big basin, for us, going west would just be the least practical.”

APA Managing Director Mick McCormack said the company is pleased to be working collaboratively with Comet Ridge to provide customers with a new gas transportation service.

“The interconnected nature of APA’s East Coast Grid enables potential new producers such as Comet Ridge to explore opportunities to market their gas in multiple domestic and international gas markets.

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“Our infrastructure continues to connect more gas resources with more gas markets to proactively meet the needs of our customers,” Mr McCormack said.

Galilee’s CSG boom Comet Ridge has been active in Galilee since 2010 with nine coal seam gas wells booking 1,870 petajoules of 3C contingent resource, as well as the completion of a detailed 250km 2D seismic survey.

Production tests in the basin also focused on producing water flow from the coals.

“The basin’s actually quite large, it’s around 250,000 square km and there’s WINTER 2016 // ISSUE 5

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INTERVIEW

Proposed pipeline route.

only been a couple of hundred wells drilled in it since the 1920s,” Mr McCaul said.

“Compared to a lot of other places, it’s pretty under-explored.”

Mr McCaul said initially Comet Ridge focused purely on coal seam gas, but over the last year, conventional exploration for sandstone gas has become a more significant focus for the company.

“I see conventional gas and CSG as complementary, because they’re so close together – our resource bases are 30-40km apart – so if you’re out there working on one, it’s tempting to go and get the other one going,” Mr McCaul said.

“All of our field focus over the last five or six years has been on CSG, and it’s really

just in the last year where we’ve gone back to look more in detail on the conventional gas. I see the next wells out there being conventional, but the next set after that may well be back to CSG. “Galilee has good solid potential in both CSG and conventional sandstone gas.”

Unexplored potential Mr McCaul said there has always been an interest in the Galilee Basin among the exploration community, but it’s often perceived as further away than it actually is.

“Where we are in Galilee is roughly the same distance from Gladstone to Wallumbilla along the pipeline. Everyone knows Wallumbilla as the Surat Basin hub

“We think Galilee is going to play a big part in the country’s gas story.”

Tor McCaul, Comet Ridge Managing Director

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and a lot of gas goes from Wallumbilla through to Gladstone, but Galilee is not that much further. We’re in the same sort of ballpark.”

With more pipelines and infrastructure now available, the demand for gas is increasing and Mr McCaul said Galilee’s significant resource volumes will be an asset in the future.

“The numbers are actually quite large so when you look at the unit cost of moving gas around, if you’re moving big volumes the unit cost becomes more manageable,” Mr McCaul said.

“Nothing has moved yet from the contingent resource category up into the reserves category, but we see this as the next step because there’s just not anywhere around Queensland where this sort of volume of gas is available at this stage.”

Putting the pieces together While LNG projects like Santos’ GLNG in Gladstone have dramatically changed the demand picture in the sector, gas WWW.UNCONVENTIONALOILANDGAS.COM.AU

Harrington 1 well site in Galilee Basin drilled by Comet Ridge.

is becoming harder to get in Eastern Australia.

“Victoria and New South Wales have been difficult to get boots on the ground and get work done but Queensland has been the progressive state in terms of moving gas forward,” Mr McCaul said.

“People sometimes talk about the major demand in LNG, but there’s also good demand from industrial customers. There’s been industrials buying gas around this part of the world for nearly 50 years and part of our goal is to fulfil that demand and move

gas from Galilee through to the customers, wherever they may be.”

Construction phases in unconventional and gas transportation projects generate a lot of interest and opportunities in the sector. Mr McCaul said this is only the beginning, not only for Comet Ridge and their project with APA Group, but for the basin in general.

“I have no doubt Galilee will have its day in the sun. It’s had people exploring for a long, long time, but no one’s yet been able to put all the jigsaw bits together to make it

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a producing project. Higher gas prices are also a major driving factor now as well.

“The ingredients are there; the volumes and contingent resource volumes are very large and we see a real demand for gas coming. Actually it’s here already, and I think it’s going to get stronger. So the pieces are all there, and with APA, we’re working to put them all together,” Mr McCaul said.

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E S L E E R E H W N A L S N E E U Q

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QUEENSLAND

T U EB ?

D N

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QUEENSLAND

Queensland undeniably leads the rest of Australia when it comes to unconventional oil and gas development.

The Sunshine State contains an array of geological basins prospective for unconventional sources of oil and gas, including coal seam gas, shale gas and oil, and tight gas and oil. Queensland already produces the bulk of coal seam gas in the country and is home to Australia’s three CSG to LNG export projects. Additionally, a range of other projects to develop unconventional oil and gas are underway in basins across the state. In this article, we take a look at the story so far and what’s next for Australia’s unconventional hydrocarbon hotspot.

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Massive unconventional potential Queensland’s geological basins contain large resources of unconventional hydrocarbons, with suggestions that currently producing gas fields could just be the tip of the iceberg.

Estimates prepared for the COAG Energy Council by its Upstream Petroleum Resources Working Group in late 2015, put Queensland’s 2P unconventional reserves at 42,434PJ (approx. 40.3tcf). Total contingent unconventional resources are estimated at 936PJ 1C resources; 24,841PJ 2C resources; and 13,768 3C resources.

The best estimate of Queensland’s total undiscovered prospective resources is 174,719PJ of petroleum-initially-in-place.

The most recent Queensland Government data estimates the remaining proved and probable CSG reserves in the Bowen Basin at 9392PJ (8.86tcf) and in the Surat Basin at 33,342PJ (31.44tcf).

Queensland’s coal seam gas industry is its most advanced unconventional gas industry with the most well characterised resources. However, tight and shale plays are also in various stages of exploration, assessment and development in basins within the state.

In addition to CSG, the Surat Basin is thought to contain potential tight and shale oil and gas resources. However, the total extent these unconventional resources has not been formally assessed.

Parts of the Bowen Basin are also prospective for tight and shale oil and gas, although these resources are also yet to be quantified.

The Cooper Basin is the most well characterised Queensland basin that is considered prospective for tight and shale hydrocarbons. This large basin covers 130,000 square km across northeast South Australia and south-west Queensland and contains Australia’s most mature conventional oil and gas fields.

Queensland sections of the Cooper Basin are prospective for tight gas and oil, shale gas and oil, and CSG. In its 2013 world shale gas and shale oil resource assessment, the US Energy Information Administration (EIA) assessed the three troughs within the Cooper Basin thought to have the largest shale oil and gas potential, the Nappamerri trough (Qld and SA), Tenappera trough (SA only) and the Patchawarra trough, including the Arrabury Trough (Qld and SA).

Overall, the Cooper Basin was estimated to contain 325tcf of shale gas in-place (including gas associated with shale oil), with 93tcf of this risked and technically recoverable.

Additionally, the EIA estimated that the basin also contained around 29 billion barrels of risked shale oil in-place, with a risked, technically recoverable resource of 1.6 billion barrels.

The existing infrastructure and workforce from conventional oil and gas activities in the Cooper Basin make the basin especially attractive for unconventional activities. As a result it is considered likely to be the first Australian basin to develop a commercial shale gas industry.

The Cooper is also thought to contain

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one of the largest tight gas resources in Australia, and have potential for deep coal seam gas.

The Maryborough Basin in coastal Queensland is thought to contain potential tight gas, shale gas and CSG resources.

However, the full extent of these resources is difficult to quantify because the basin is underexplored and therefore lacks the required geological data. However, the EIA did assess the northern section of the basin, for which geological data exists.

The EIA estimated the risked gas in-place for the assessed shales in the Maryborough Basin at 64tcf, with a risked, technically recoverable shale gas resource of 19tcf. The areas assessed were dry gas prone and not prospective for shale oil.

The Georgina basin, which straddles the border between Queensland and the Northern Territory, is considered prospective for shale and tight gas and oil.

The EIA estimated the total risked wet and dry shale gas in-place for the Maryborough Basin, including the Queensland sections, at 67tcf, with a risked, technically recoverable shale gas resource of 13tcf. The total risked shale oil and condensate in-place was estimated at 25 billion barrels, with a risked, technically recoverable shale oil and condensate resource of 1.0 billion barrels.

Some of the other promising unconventional basins in Queensland include the Clarence-Morton Basin, prospective for CSG; the Laura Basin, which has potential tight gas, shale gas and CSG resources; the Eromanga Basin, thought

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QUEENSLAND

to contain shale oil and gas; the Galilee Basin, which has potential tight gas, shale gas and CSG resources; the Adavale Basin, which potentially contains sources of shale and tight gas; the Mount Isa Superbasin, thought to contain shale gas; the Styx Basin, with potential CSG; and the Ipswich Basin, also with potential CSG resources.

Australia’s unconventional hotspot Queensland is by far the biggest unconventional gas producer in Australia, with a commercial CSG industry providing large amounts of gas to market.

Gasfields in both the Surat and Bowen basins produce large amounts of coal seam gas, and CSG makes up around 90 per cent of the Queensland’s gas production.

Together, these basins supply the vast majority of CSG produced in Australia and contain well over 4000 producing CSG wells, in addition to many exploration and appraisal wells.

During the first six months of 2015, a total of 53.21PJ of CSG were produced from the Bowen Basin and 216.63PJ from the Surat Basin. This brings the total CSG production for the period to 269.8PJ. As well as supplying the domestic market, Queensland CSG wells also supply the state’s three CSG-LNG plants with gas for export.

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CSG wells in the Surat Basin supply gas to the Queensland Curtis LNG project (QCLNG), the world’s first dedicated CSG-LNG project, which loaded its first cargo for export in late 2014. The QCLNG project has booked 2P reserves of 11.6tcf (12,296PJ) and is contracted to produce 10.6tcf (11,236PJ) (COAG Energy Council, 2015). This project was one of Australia’s largest capital infrastructure projects, receiving approximately $US20.4 billion of investment from 2010-14 and is operated

by QGC, part of BG Group, which was acquired by Royal Dutch Shell in early 2016.

Additionally, in late 2015, QGC announced a $1.7 billion (AUD) project, named Charlie, which will see the company and its joint venture partners, China National Offshore Oil Corporation and Tokyo Gas, develop CSG tenements in the Surat Basin south of Wandoan. The project will involved the construction of 300-400 wells, a large field compression station and associated pipelines and facilities which will feed into existing gas processing and water infrastructure. The project will help sustain supply for both domestic customers and the Queensland Curtis LNG (QCLNG) liquefaction plant on Curtis Island, near Gladstone.

The Australia Pacific LNG project (APLNG) supplies gas from CSG wells

in the Surat and Bowen basins to both Queensland domestic markets and for export. This project is currently the largest coal seam gas producer in Australia. Its first LNG cargo departed from the LNG facility on Curtis Island for export in January 2016.

This project is a joint venture between Origin (37.5 per cent), ConocoPhillips (37.5 per cent) and Sinopec (25 per cent).

This project currently has booked 2P CSG reserves of 13.3tcf (14,098PJ) and contracted volumes of 8.6tcf (9,116PJ) (COAG Energy Council, 2015).

The Santos GLNG project also converts CSG from the Bowen and Surat Basins to LNG for export. This US$ 18.5 billion project is a joint venture between Santos, PETRONAS, Total and KOGAS. The project’s first LNG cargo left the Curtis Island plant in late 2015, bound for South Korea. The GLNG project has currently booked 2P CSG reserves of 6.4tcf (6,784PJ) to supply contracted volumes of 7.0tcf (7,420PJ) (COAG Energy Council, 2015). As a result additional sources of gas may be required to meet contract commitments.

Other major unconventional oil and gas projects underway in the Surat Basin include the Arrow Surat Gas Project and the Western Surat Gas Project.

Arrow Energy’s Surat Gas Project will provide gas for both domestic and export

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QUEENSLAND

markets and involve drilling around 6,500 CSG wells. It will also include around 6,000km of gathering lines across the Surat Basin, to move both CSG and water from the wells to centralised gas processing and water treatment facilities.

Arrow also proposes to construct a major buried gas pipeline from the Surat Basin gas fields to a gas hub 22km west of Gladstone, where it will join the proposed Arrow Bowen Pipeline. This project has received approval and work is underway to prepare the site.

The Western Surat Gas Project will develop coal seam gas fields over approximately 993 square km of Senex permits, north of Roma in Queensland. In late 2015, Senex entered into a 20-year binding gas sales agreement to supply up to 50 TJ/day to GLNG. Senex is currently progressing planning and appraisal activities including pilot testing, concept engineering studies, stakeholder engagement and environmental impact assessment. First gas production from the project is expected by the end of 2017.

Projects underway in the Bowen Basin include Arrow’s Bowen Gas Project (BGP), which will see a phased expansion of Arrow’s CSG production volumes in the basin to supply LNG exports; the Mahalo Gas project (a joint venture project between Comet Ridge, Santos

and APLNG), which has seen increased CSG reserves in the Mahalo block west of Gladstone; and various other exploration and appraisal activities for CSG, tight and shale gas.

In the Queensland sections of the Cooper Basin various projects targeting shale oil and gas are underway, including the Nappamerri Trough Natural Gas project (Beach and Icon). Tight gas exploration activities are also occurring.

Preliminary exploration for shale gas, tight gas and CSG is also occurring throughout a variety of other Queensland basins.

Blue Energy currently holds all three exploration permits for the Maryborough Basin and is currently seeking a projectbased consolidation of the permits, with a view towards selecting the optimum geological location for testing wells and reducing effort duplication and surface impacts.

In the Galilee Basin, Galilee Energy’s Galilee Gas Project is targeting prospective CSG resources. Meanwhile, in the Queensland sections of the Georgina Basin, the South Georgina Exploration Program (Central and Total Oil) is evaluating the unconventional resource potential of the lower Arthur Creek Formation.

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Staying ahead of the game The Queensland Government is highly supportive of unconventional oil and gas development, with a range of initiatives in place to support its further development.

These include the $30 million Future Resources Program, which aims to maximise exploration success by supporting Queensland’s resource and exploration industries; the $18 million Greenfields 2020 program; the ResourcesQ Cooper Basin Industry Development Strategy; and the Queensland Gas Supply and Demand Action Plan, currently being developed to identify barriers and incentives to further unconventional gas development in the state.

Queensland is already reaping the benefits of an unconventional gas industry, both to supply the domestic market and lucrative overseas exports. With a range of projects underway to increase reserves in producing basins and to assess the potential of CSG, shale gas and oil, and tight gas and oil resources in the state’s underexplored basins, Queensland is likely to remain a leader in Australian unconventional oil and gas development for many years to come.

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OPINION

OVERCOMING

THE OBSTACLES TO BECOMING A GLOBAL LNG LEADER

by Bernadette Cullinane, Asia Pacific Energy Lead, Accenture

Australia has dominated global LNG capital expenditure in recent years. Last year, Accenture reported that the Australian LNG industry has the potential to become the world’s largest and most technologically advanced industry, contributing more than $55 billion to Gross Domestic Product in 2020.

H

owever, in order to continue on its path to becoming a global leader there are a number of significant obstacles the Australian industry still needs to overcome.

1. Australia is resource rich but has an unclear path to growth Although Australia is rich in resources, the economic extraction of those resources to supply market demand is a limiting

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factor to its future growth. Large gas deposits, limited recent oil discoveries and a saturated and stagnant domestic gas market have led to Liquefied Natural Gas (LNG) exports becoming the only viable means of growth. However, Australian LNG projects on both coasts have also been hit by cost blowouts, which have contributed to investors’ reduced appetite for new mega projects. While the resources within Australia are by no means scarce, achieving growth will become increasingly difficult, particularly after the two last mega

projects start production – INPEX’s Ichthys and Shell’s Prelude FLNG.

2. East Coast production combines two incompatible business models East Coast coal seam gas (CSG) LNG operations are at the upper end of the LNG cost curve. Such projects blend two exploration and production business models into one; the high up-front debtfinanced capex of an LNG mega project, with the treadmill sustaining capex of US unconventionals. As a result these projects

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OPINION

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OPINION

have become increasingly difficult to manage. Furthermore, with the persistently low oil price leaving organisations struggling to find cash flow to invest in higher margin projects, organisations are beginning to see a flow on impact to their share prices. Though unconventional players in the United States have worked closely with services companies to achieve significant cost reduction, east Australian CSG does not have a comparable services ecosystem to support such collaboration.

cargoes, Asia, could itself be at the cusp of a gas revolution. To date, most of the easy to produce resources in Southeast Asia have been developed, leaving the region to face dwindling reserves and difficult challenges, such as marginal fields and deepwater. However, with a mere 10 per cent reduction in wells and facilities costs, significant gas resources could be unlocked. If sufficient scale is achieved, Australian producers could struggle to place LNG in Southeast Asia.

3. The West Coast has lost its lustre for mega projects A lack of oil discoveries on the West Coast in recent years is causing a significant decline in Australian oil production, while the lifting cost associated with mature oil fields has contributed to reduced profits. Gas on the other hand has the reverse problem, with West Coast basins awash with undeveloped resources that are often hundreds of miles from shore in remote areas of Australia. When this is coupled with an operating environment of endemic high costs and limited crossoperator collaboration, it makes West Coast investment far less attractive.

5. Cost reduction needs to be replaced with cash flow management Over the past two years Australian operators have attempted to reduce costs to remain competitive in a low oil price market. However, organisations must now steer away from attempting to mitigate costs in the execution space and instead begin to change the fundamentals of business portfolios and operating models, as well as improve the enabling environment of the supply chain and use of digital.

4. LNG competition could come from Asia The main destination for Australian LNG

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The way forward The response of operators, the services sector and government to these challenges will determine whether Australia is ready to become a leader in the oil and gas industry, and it is the role of industry leaders to step

up and map out a clear path for growth.

By simplifying how organisations do business with one another the industry could improve its overall competitiveness.

The focus should be on improving communication and creating forums to allow operators, service providers, regulators and government to come together to discuss key areas and opportunities for change, including turnaround planning and execution, standardisation and shared infrastructure.

To support this, operators need to recognise the pivotal role the services sector plays in research, technology and innovation, which is critical to wider industry success.

For instance, Subsea Energy Australia (SEA) is a not-for-profit industry association which aims to champion the Australian subsea industry and promote Australian capabilities to the wider regional and global markets. SEA has over 90 members including operators, service providers, suppliers, SMEs and universities that are engaged in activities across the subsea oil and gas supply chain. SEA provides a forum for networking and the advancement of the subsea industry and helps to organise, develop and export Australia’s capabilities. With cross-industry involvement and a wide range of members, SEA’s model helps drive collaboration and

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OPINION

allows new ideas that could advance the overall industry to be developed and tested.

Additionally, the global shift towards an increased use of digital technology creates a huge opportunity for Australia’s LNG sector to increase efficiency and value.

Through the adoption of technologies such as the Industrial Internet of Things, predictive analytics, mobility solutions, social media and 3D printing, organisations now have the potential to improve integrity and reliability, workforce productivity and overall efficiency, as well as driving down operational costs.

For Australia to reach its potential as a leader in the oil and gas industry local players need to rethink their current operating models, create more supportive ecosystems and invest in new technologies to ensure safe, reliable and highly productive operations. Additionally, to be recognised globally for expertise in LNG operations, Australian operators and service providers must develop a shared vision for the future that enables the deployment and adoption of innovative new technologies and services to support its continued growth.

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BASIN PROFILE

EXPLORATION IN THE PERTH BASIN

In this instalment of our regular feature profiling Australian geological basins, we take a closer look at the Perth Basin. This WA basin is thought to contain significant tight gas, shale gas and shale oil resources, which may be suitable for commercial development. As a result, exploration activities in the basin have increased in recent years. The Perth Basin also contains Western Australia’s only currently producing unconventional play, in the Corybas tight gas field.

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BASIN PROFILE

Key Statistics Unconventional resources

Tight gas, shale gas, shale oil Prospective resources

160Tcf shale gas overall; 14 billion barrels shale oil, tight gas not formally assessed (EIA, 2013) Risked recoverable amount

32Tcf shale gas; 0.5 billion barrels shale oil (EIA, 2013) Main unconventional formations

Dandaragan Trough, Carynginia Formation, Kockatea Formation, Irwin River Coal Measures, Yarragadee Formation, Dongara/Wagina Sandstone, High Cliff Sandstone, Sue Coal Measures Key active companies

AWE Limited, Norwest Energy, Origin Energy, Empire Oil and Gas, Transerv, Alcoa, Bharat PetroResources, UIL Key projects

Arrowsmith Exploration Project (AWE Energy, Norwest, Bharat PetroResources) Warro Gas Field Project (Transerv, Alcoa)

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BASIN PROFILE

Unconventional gas in the Perth Basin The Perth Basin is an onshore and offshore sedimentary basin located across approximately 172,300 square km in Western Australia. The basin has seen commercial oil and gas production from conventional reservoirs since 1964. The majority of conventional activity has been located in the northern onshore sections of the basin, which are extensively explored, with fewer discoveries in the onshore southern sections.

The Perth Basin is also thought to contain significant tight gas and shale gas and oil resources.

The northern basin’s primary depocentres with unconventional hydrocarbon potential include the Carynginia Formation (prospective for shale gas and oil), the Kockatea Shale (prospective for shale gas and oil); the Irwin River Coal Measures (prospective for tight gas, shale gas and shale oil); the Yarragadee Formation (prospective for tight gas); the Dongara/Wagina Sandstone (prospective for tight gas and shale oil); and the High Cliff Sandstone (prospective for tight gas and shale oil).

The primary depocentre in the south of the basin is the Sue Coal Measures, prospective for tight gas.

Currently the only unconventional play producing in the Perth Basin is the Corybas tight gas field, located in the Irwin River Coal Measures.

The US Energy Information Administration (EIA) has assessed the potential shale gas and oil resources of two main shale formations in the basin, the Permian Carynginia and the Triassic Kockatea shales. The Carynginia Shale is estimated to contain 124Tcf of gas in-place, with a risked, technically recoverable shale gas resource of 25Tcf (EIA, 2013). The prospective area was inclined to dry gas, and not thought to contain shale oil.

The Triassic Kockatea Shale was estimated to contain gas in-place of 36Tcf, with a risked, technically recoverable shale gas resource of 7Tcf. It is also estimated to

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contain 14 billion barrels of shale oil-inplace, with a risked, technically recoverable shale oil/condensate resource of 0.5 billion barrels.

The Government of Western Australia’s Department of Mines and Petroleum (DMP) estimates that known Perth Basin tight gas fields hold between 9-12Tcf of recoverable gas, located in the vicinity of existing pipelines (DMP, 2014).

Unconventional activity in the region A number of exploration, assessment and development activities are underway targeting the Perth Basin’s unconventional oil and gas resources. Companies currently active in the basin include AWE, Norwest Energy, Origin Energy, Empire Oil and Gas, Transerv, Alcoa, Bharat PetroResources and UIL Energy.

Western Australia’s first producing tight gas well is the Corybas 1 exploration well.

This well was drilled in the northern section of the Perth Basin in 2005 by ARC Energy (which was acquired by AWE in 2008) and flowed gas from the Irwin River Coal Measures.

In 2009, AWE conducted hydraulic fracturing on the vertical well, increasing gas flow rates. Following encouraging results, the well was linked by pipeline to the nearby Dongara gasfield’s processing facility. An extended production test from April to September 2010 resulted in a recoverable reserves estimate of 2.9Bcf (DMP 2014). A number of other production tests followed and the well is currently the only commercially producing tight gas well in Western Australia.

AWE and Norwest Energy have been targeting prospective Triassic and Permian shale targets within the Perth Basin.

The first well targeting shale gas, Woodada Deep 1, was drilled in 2010

by AWE to investigate the Carynginia Formation, the Kockatea Shale, and the Irwin River Coal Measures. The initial core testing results for the middle interval of the Carynginia Formation were favourable compared to US gas shales, resulting

in further evaluation. Extensive coring programs were carried out at Woodada Deep 1 and Arrowsmith 2 in 2011. In 2012 three shale gas wells were fracced in the northern Perth Basin (Woodada Deep 1, Senecio 2, and Arrowsmith 2) (DMP 2014).

The Arrowsmith exploration project is located within exploration permit EP413, north of the town of Eneabba.

This permit is operated by AWE Energy (44.252 per cent via subsidiaries) with Norwest Energy (27.945 per cent) and Bharat PetroResources (27.803 per cent) and contains prospective tight gas plays in the Carynginia Formation, Irwin River Coal Measures, High Cliff Sandstone and fractured lower Kockatea Shale, in addition to containing conventional gas targets.

Norwest fracture stimulated Arrowsmith 2 in 2012 to assess the Carynginia Formation for its shale gas potential. Five zones over four formations (the High Cliff Sandstone, Irwin River Coal Measures, Carynginia Formation and Kockatea Shale) were fracced. Gas flowed from the tight sands in the High Cliff, the Irwin River Coal Measures and the lower and middle Carynginia shales, culminating with both oil and gas in the Kockatea Shale (DMP 2016).

Testing on Arrowsmith 2 was completed in early 2014 and results suggested that the Carynginia Formation and the Irwin River Coal Measures were potentially suited for development. A 3D seismic acquisition program was conducted in 2015 and the data is being used to identify the optimal targets for a shale gas well in the field, as well as conventional hotspots.

Additionally, AWE holds stakes in a number of other permits in both the northern and southern sections of the Perth Basin (including permits in the Woodada gas field, Dongara and Yardarino gas field and Watsia gas field), and has conducted a range of exploration activities targeting both conventional and unconventional oil and gas.

Norwest operates within a range of permits in the northern sections of the basin, and is expanding its footprint in the

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BASIN PROFILE

southern sections. Norwest retains interests in seven permits within the northern Perth Basin, and is operator of four of these, with a significant total net footprint of 3,100 square km. According to Norwest, the company’s current primary focus is on progressing the emerging shale gas industry in the northern Perth Basin.

The Warro gas field project is operated

by Transerv (through its subsidiary Latent Petroleum) with funding provided by farm-in partner Alcoa. This project is targeting tight gas within Retention Leases 6 and 7.

Transerv estimates that the field contains 7-10Tcf in place and potentially 1-3Tcf of recoverable gas. The field is located conveniently close to both the DampierBunbury Natural Gas Pipeline and the Dongara-Perth Parmelia Pipeline.

In 2012, independent analysis of the available data (including 3D seismic data) on the Warro Gas Field by a group of experts confirmed significant quantities of gas are held within the field with the potential to flow at high rates.

As a result, the Warro Joint Venture decided in late 2014 to continue its evaluation of the field by the drilling of Warro 5 and 6 during the second half of 2015. These wells were completed in early 2016 and are currently part of an extended well test program.

In March 2016, it was announced that the Warro-4 well would be re-entered and tested to gain further insight to the whole of field. The results of the re-testing, released in July 2016, were encouraging.

Transerv stated that the increased flow rates achieved were in line with outcomes seen in US tight gas fields where sweet zones are targeted for production. The newly acquired data will now be analysed along with data from Warro-5 and 6 to determine the appropriate next steps for the Warro project.

Meanwhile, Empire Oil and Gas holds the largest net acreage in the highly prospective Perth Basin with its production licenses and permits covering more than 10,000 square km. While the company is

Perth Basin

primarily targeting conventional oil and gas plays, independent analysis suggests that considerable unconventional targets may also be located within its permits.

UIL Energy is targeting onshore conventional and unconventional oil and gas plays within the north and central Perth Basin. In 2016 it acquired two additional permits from Eneabba Gas. In late 2015, Pilot Energy acquired the exploration permits EP416 and EP480, originally owned by Empire Oil and Gas. Origin Energy, which holds a number of stakes in both conventional and unconventional plays in the Perth Basin, is currently looking to sell its WA assets as part of its plan to sell at least $800 million of non-core assets by the end of 2017. The Perth Basin assets are reported to be receiving interest from a number of industry participants.

Commercial viability The proximity of parts of the Northern Perth Basin to pipelines and other vital infrastructure means that it is likely to be the first area in Western Australia to supply shale gas to the market.

Furthermore, the basin contains the

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only tight gas fields in the state that have progressed to the contingent stage of exploration, and the producing Corybas 1 well.

It is likely that the unconventional plays located close to existing infrastructure will be developed first, with resources located further from infrastructure in the southern parts of the basin taking longer to be developed.

The regulatory environment in WA is generally favourable to oil and gas development, with a number of initiatives underway to support the industry. However, Western Australia currently has a domestic gas reservation policy in place which requires new gas developments to supply the equivalent of 15 per cent of their gas exports to the Western Australian domestic gas market.

The Perth Basin is one of WA’s most attractive unconventional oil and gas hotspots, and is likely to see further exploration and continued development over the coming years.

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FEATURES SCHEDULE Spring 2016 MAJOR FEATURE

Deadline: 12 August 2016

Logistics

Summer 2017 MAJOR FEATURE

Deadline: 9 December 2016

Safety

Land access and management,

Personal safety gear, facility safety

road construction, accommodation,

equipment, gas monitoring equipment

rig maintenance, recruitment and HR PRODUCTS SHOWCASE

Water management

PRODUCTS SHOWCASE

Pipes and processing

INDUSTRY ANALYSIS

Reserves update

INDUSTRY ANALYSIS

Performance scorecard

BASIN FOCUS

Gunnedah

BASIN FOCUS

Canning

GEOGRAPHIC FOCUS

Queensland

GEOGRAPHIC FOCUS

South Australia

DISTRIBUTION

APGA 2016

Autumn 2017 MAJOR FEATURE

ICT

TBC

Winter 2017 MAJOR FEATURE

TBC

Drilling equipment

Telecommunications, radio, SCADA,

Rigs and rig technology, rig maintenance,

IT, security, big data, mobile devices,

fraccing, fluids and proppants, water

cloud computing

management

PRODUCTS SHOWCASE

Transport

PRODUCTS SHOWCASE

Power generation

INDUSTRY ANALYSIS

Regulatory review

INDUSTRY ANALYSIS

Global energy outlook

BASIN FOCUS

TBC

BASIN FOCUS

TBC

GEOGRAPHIC FOCUS

TBC

GEOGRAPHIC FOCUS

TBC

ADVERTISERS’ INDEX AJ Lucas Group Ltd ������������������������������������������������������������������������������������������������������������������������������������������������������������������5 Infrastructure Magazine ����������������������������������������������������������������������������������������������������������������������������������������������������������7 LAB SA ��������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������� 11 Pivotel �����������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������9 Vacuworx Australia ����������������������������������������������������������������������������������������������������������������������������������������������������������������� 10 Vermeer ���������������������������������������������������������������������������������������������������������������������������������������������������������������������������������� 2,3

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