Unconventional Oil and Gas Spring 2016 Digital Edition

UNCONVENTIONAL Issue 6 // SPRING 2016

STIMULATING THE SEARCH FOR NEW RESOURCES

GALILEE TO FIRE EAST COAST MARKETS

NATURAL GAS: FROM CLIMATE PARIAH TO CLIMATE SAVIOUR?

NEW OPPORTUNITIES:

THE NEXT WAVE OF PIPELINE PROJECTS

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UNCONVENTIONAL

OIL GAS UNCONVENTIONAL Issue 6 // SPRING 2016

UNCONVENTIONAL OIL & GAS

STIMULATING THE SEARCH FOR NEW RESOURCES

GALILEE TO FIRE EAST COAST MARKETS

NATURAL GAS: FROM CLIMATE PARIAH TO CLIMATE SAVIOUR?

SPRING 2016

NEW OPPORTUNITIES:

THE NEXT WAVE OF PIPELINE PROJECTS

Cover image highlights our logistics feature, focusing on gas pipelines to tie in with the APGA Convention and Exhibition.

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

Publisher and Editor Chris Bland Managing Editor Laura Harvey Associate Editor Jessica Dickers Contributing Editor Michelle Goldsmith Marketing Director Amanda Kennedy Marketing Consultants Aaron White Steven Golding Production and Customer Service Titian Bartlau

WELCOME

ISSUE 6 // SPRING 2016

FROM THE PUBLISHER

T

he fifth COAG Energy Council meeting was recently held in Canberra, and energy ministers from around the country came to a conclusion that we in the petroleum industry have long been aware of – the key for Australia’s energy policy, moving forward, is more natural gas.

As noted during the council meeting, business as usual is no longer an option.

There has been a significant shift in domestic and global energy markets, and we are now feeling the effects of these shifts through increased wholesale gas prices. We need to act now to ensure these impacts don’t become more serious as time goes on. If we want to avoid the predicted gas shortages we’re expected to face, the time to act is now.

It will take a variety of sources of gas to meet the demand we face from our export contracts and our own domestic needs – conventional and unconventional.

The reality is our conventional sources are not providing the volumes they once were – it is unconventionals, such as coal seam gas, that represent the future for the gas industry.

To move forward, the industry needs more supply, and in order to achieve more supply, we need more exploration. This is the only answer, and I’m pleased to see some recognition of this.

I recently attended an Australian Pipelines and Gas Association (APGA) dinner and it was pleasing to see signs of renewed hope. While the industry is a long way from returning to boom times, there is activity going on that is generating work for a number of associated industries.

The challenging market conditions our industry has faced for almost two years now have resulted in significant change – companies that were once strong cease to exist, oil and gas professionals with long

and successful careers have been forced to move on.

Publishers in the energy space have also been affected; I was sad to learn that Oil & Gas Australia would be shutting their doors after 35 years, and that Gas Today, a magazine I previously launched, would be moving to a digital only format.

The industry downturn we’ve experienced has been a once in a generation shift. Those of us that are surviving now are the ones that will benefit when we, as an industry, start to see the benefits of a new focus on delivering more gas to Australia and our international trading partners.

There are still regulatory challenges to be faced; and there are still states that prefer to be part of the problem rather than the solution, but I believe we are starting to take the first steps towards rebuilding the gas industry into the power that it once was.

Chris Bland Publisher and Editor

Senior Designer Alejandro Molano Designer Jacqueline Buckmaster Contributing Designer Sandy Noke

UNCONVENTIONAL

4,724

OIL GAS

This publication has been independently audited under the AMAA's CAB Total Distribution Audit.

Audit Period: 01/10/2015 – 31/04/2016

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CONTENTS EXPLORATION

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East Coast gas prices will stimulate the search for new resources.........................................................................16

Australia’s East Coast is facing significant demand for new gas supply over the next several decades, and the obvious solution to meeting this demand is unconventional gas.

LOGISTICS

22

Where are the opportunities for gas pipeliners?.....................................22

Australia’s gas market is currently in transition, with predicted supply shortages, increased prices and gas moving away from domestic consumers and towards LNG exports. But change also brings opportunity and despite the challenges of the sector, there are many exciting projects underway or planned for the pipeline industry. Here, we look closely at the pipeline sector and consider the opportunities our changing gas supply market is providing.

LOGISTICS

28

The nature of polyethylene pipe failure......................................................28

Polyethylene pipe is widely used for pipelines in the gas industry thanks to its impressive characteristics. At times, however, failures do occur. Here, Chris O’Connor and Simon Brooks detail the types of failures that can affect polyethylene pipes, and how operators can avoid these failures in their networks.

WESTERN AUSTRALIA

34

Journey to the west..........................................................................................34

Western Australia is home to a number of highly attractive unconventional oil and gas development prospects. Located across the state are various basins prospective for shale and tight gas and oil. These include the Canning Basin, estimated to contain Australia’s largest potential shale gas resource, and the Perth Basin, where WA’s first commercial unconventional gas production has occurred.

Increasingly, industry players are evaluating the state’s underexplored basins and bring WA’s hydrocarbon resources to market.

INTERVIEW

40

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Galilee to fire East Coast markets.................................................................40

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.

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LNG

46

Overcoming the obstacles to becoming a global LNG leader..............46

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.

Jexit: What if Japan tears up all its Australian LNG contracts?.............50

OPINION

54

From climate pariah to climate saviour: what the petroleum industry can do about climate change..................54

Natural gas has a clear role to play as part of the transition to cleaner forms of energy. Here, Andrew Hopkins outlines several things that the petroleum industry can do to help combat global warming – while protecting its own economic interests.

BASIN PROFILE

58

EVENTS

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Exploration in the Perth Basin.......................................................................58

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.

Policy on the agenda at APPEA 2016..........................................................62

APPEA 2016 drew more than 2,000 registered attendees from 26 countries and 865 organisations – a strong result in a difficult time for the industry, especially as it was held only two months after LNG18.

REGULARS Publisher’s welcome ������������������������������������������������������������������������������������������������������������������������������������� 2 Contributors ���������������������������������������������������������������������������������������������������������������������������������������������������� 6 News ����������������������������������������������������������������������������������������������������������������������������������������������������������������� 8 Advertisers’ index ����������������������������������������������������������������������������������������������������������������������������������������64 WWW.UNCONVENTIONALOILANDGAS.COM.AU

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CONTRIBUTORS

John Phillips

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Jessica Dickers

Tor McCaul

CEO and Managing Director, Blue Energy

Associate Editor Unconventional Oil & Gas

Managing Director, Comet Ridge

John is a Petroleum Geologist with 30 years experience in the oil and gas industry. John joined Blue Energy as Chief Operating Officer in May 2009, was promoted to CEO in April 2010 and joined the board of Blue Energy in June 2010.

John’s career in industry has involved conventional oil and gas and coal seam gas experience in a variety of petroleum basins both domestically and internationally.

John has gained extensive operational experience through his involvement with Delhi Petroleum, Esso, Conoco, Petroz and Novus, culminating in his role as Chief Operating Officer with Sunshine Gas before its takeover by QGC and subsequently by the BG Group.

Jessica is the Associate Editor of Unconventional Oil & Gas. Jessica’s journalistic experience includes writing for titles like Broadsheet, Time Out Melbourne and The Weekly Review, as well as playing a role in the creation of Switch Magazine.

She has now turned her attention to the energy and infrastructure industries, working on titles in the sector including Utility, Pump Industry and Infrastructure.

Jessica contributed the article Where are the opportunities for gas pipeliners? to this issue, for which she interviewed a number of key players within the pipelines and gas industries.

Tor McCaul has 23 years experience in the oil and gas industry. He graduated with honours in Petroleum Engineering from UNSW in 1987 and spent the next nine years based in Brisbane working for operating companies in technical roles on projects in Queensland, New Zealand and Papua New Guinea. Mr McCaul spent the following 11 years in Asia (Karachi, Jakarta, Chennai and Delhi) working for British independent companies in technical, finance, commercial and management roles which included the 23 milliontonne-per-annum Bontang LNG project in Indonesia. He joined Chartwell Energy Limited in Brisbane as Chief Executive Officer in July 2008 and become Managing Director of Comet Ridge Limited in April 2009 following the merger. Mr McCaul is a member of the Society of Petroleum Engineers and has served in several positions, including Chairman, on the executive committee for the Queensland Section.

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Bernadette Cullinane

Geoffrey Cann

Andrew Hopkins

Asia Pacific Energy Lead, Accenture

National Director for Oil and Gas, Deloitte Consulting

Emeritus Professor, Australian National University

Bernadette Cullinane is Accenture’s APAC Energy Practice Lead and a Managing Director in Accenture’s Perth office. She has previously worked with companies in the upstream, downstream and LNG segments as well as in unconventional oil and gas. Before moving to Perth in 2007, Bernadette was based in Texas, and worked with oil and gas companies throughout North America, South America, Asia and Europe. Bernadette focuses on helping oil and gas companies improve performance through business process improvement, supply chain optimisation, maintenance transformation, operational strategy, finance and cost management, organisation development, change management and technology implementations. Bernadette began her career as a chemical engineer.

Geoffrey Cann is an experienced commentator in the oil and gas industry, with a particular focus on the LNG sector.

Currently he is Deloitte Consulting’s National Director for Oil and Gas industry, operating out of Brisbane. He focuses on helping energy and resources companies solve complex management challenges.

Mr Cann has over 24 years of management consulting experience gained through engagements in Canada, Australia, the United States, South Korea, Hong Kong, China, Japan and the Caribbean.

Emeritus Professor Andrew Hopkins is an internationally-renowned presenter, author and consultant in the field of industrial safety and accident analysis.

Professor Hopkins has been involved in various government occupational health and safety (OHS) reviews and completed consultancy work for major companies in the resources sector.

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NEWS

SHELL CALLS FOR INFORMED DEBATE ON UNCONVENTIONAL GAS

S

hell Australia has called for a constructive debate on unconventional gas and an end to the Victorian and New South Wales moratoriums on unconventional gas development.

In a speech at the Melbourne Mining Club, Shell Australia Chairman Andrew Smith called for Federal and State governments to implement the Australian Competition and Consumer Commission (ACCC) and the Australian Energy Market Commission’s proposed reforms, including lifting the moratoriums on onshore gas development.

Mr Smith said access to onshore gas was one of the most fundamental economic challenges facing south east Australia and said the debate surrounding it had to be informed.

Mr Smith said Victoria and New South Wales are failing to use facts and evidence in this debate, but instead there are “scare

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campaigns from activists in the coffee shops of Fitzroy and Balmain”.

“As an industry we should all urge state leaders in Spring Street and Macquarie Street to address the energy challenges that face consumers if we continue to ignore the scientific data that unconventional gas development can beneficially coexist with agriculture, and the economic data that without additional gas production spikes in energy prices will continue to hurt consumers and manufacturers.”

Mr Smith said that good policy with bipartisan support is vital for the industry to overcome current and future challenges.

“The challenge for us is to confront the detractors of our place in a modern Australia by participating in a constructive debate,” Mr Smith said.

Mr Smith said Australia was moving towards to a lower carbon energy generation system and that Shell Australia

believed the world should move to zero emissions this century.

However, Mr Smith said Australia needed to acknowledge that renewables were intermittent and gas was the most logical backup until energy storage technology improves.

Mr Smith said the June-July 2016 gas market pricing uplift derived from the beginning of LNG exports, which shifted domestic pricing towards parity with LNG netback levels (the price of gas delivered to destinations like Tokyo Bay minus liquefaction and transportation costs).

“All of this points to the fact that gas has a fundamental part to play in the transition and in the end-game,” Mr Smith said.

Mr Smith’s speech also addressed immigration, calling the recent debate around the topic hysterical, and advocated for increased immigration to help boost Australia’s “sluggish economy”.

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NEWS

NEW PROSPECTIVE SHALE RESOURCES IN NT

S

tudies by Empire Energy have confirmed strong shale gas potential in two Tallawah Group shale horizons in the Northern Territory’s McArthur basin.

The Tallawah Group source rocks are a relatively new identified source of oil and gas potential which underlie the highly prospective Barney Creek Shale, the major focus of a development program previously announced

by Empire.

UOG_HALF_SMARTER.pdf 1 4/14/16

Recent studies have confirmed oil and gas generative potential in two Tallawah Group shale horizons, the Wollogorang and McDermott formations.

Other analysis shows that the Tawallah Group shale characteristics compare favorably to other McArthur Basin organic shales, and to the formation characteristics of both the Marcellus and Utica shales.

Work programs to further understand these 9:37 AM horizons are continuing.

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Work completed to date has enabled Empire to confirm that the Wollogorang Formation provides an additional 1.4 million acres of potential petroleum targets.

Further work will be undertaken in relation to the McDermott Formation, which lies beneath the Wollogorang, would add an estimated additional 1.7 million acres of potential petroleum shale targets to the company’s prospective resources.

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NEWS

COAG RELEASES NEW GAS SUPPLY STRATEGY

T

he Council of Australian Government (COAG) Energy Council has decided to implement a new Gas Supply Strategy, which aims to increase gas supply, coordinate exploration efforts, and fast track an assessment of a new interconnector between New South Wales and South Australia.

Federal Minister for Environment and Energy Josh Frydenberg said the implementation of the recommendations would be fast tracked by the formation of a new Gas Market Reform Group headed by Dr Michael Vertigan.

“These are the most significant reforms to the domestic gas market in two decades,” Mr Frydenberg said.

“Council recognised the growing importance of gas as a transition fuel as we move to incorporate more renewables into the system.

“The reforms will improve competition,

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encourage more supply and put downward pressure on prices.”

The Australian Petroleum Production and Exploration Association (APPEA) Chief Executive Dr Malcolm Roberts welcomed the Council’s support for increasing gas supply and the number of gas suppliers.

“The implementation plan for the Gas Supply Strategy is a welcome move to encourage more competition and transparency in the East Coast gas market,” Dr Roberts said.

“APPEA supports the establishment of a reform group to drive the changes recommended by the Australian Competition and Consumer Commission and the Australian Energy Market Commission.”

Dr Roberts said it was important that work on these reforms started quickly but the strategy and market reforms could only achieve so much if some governments maintained or threatened new regulatory restrictions on gas development.

“The essential ingredient for a gas market is gas,” Dr Roberts said.

“The East Coast gas market is at a tipping point. Tight market conditions are already inflicting real economic and social costs.

“Governments have been warned by their own agencies that we risk a supply shortfall by 2019 if new gas reserves are not developed urgently. And the states that are the most vulnerable are the ones that have not developed their own resources.”

Dr Roberts said Victoria must lift its onshore gas moratorium for the sake of local customers and industry, as there is no environmental justification to prohibit onshore gas exploration and development.

“Without firm action from all states, families and businesses will face higher energy costs, investment in manufacturing will be threatened, and Australia’s transition to a low emissions future will be much more difficult.”

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NEWS

SANTOS TAKES HIT ON LNG PROJECT

S

antos has announced it expects to take a US$1,050 million impairment charge on its Gladstone Liquefied Natural Gas (GLNG) project in Queensland due to continuing low oil prices.

The GLNG project produces natural gas from Queensland’s coal seams and converts it to LNG. It involves ongoing gas field development in the Surat and Bowen Basins, a 420-kilometre gas transmission pipeline, and the construction of an LNG plant on Curtis Island, near Gladstone.

The impairment outcome is subject to finalisation of the half-year accounts. It will be a non-cash charge and will not affect the company’s debt facilities.

“The expected impairment charge for GLNG is clearly disappointing but it is a consequence of the challenging

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environment which we now face,” Santos Chairman Peter Coates AO said.

Sustained low oil prices continue to constrain capital expenditure and impact GLNG. During the course of 2016 there was a slower ramp up of GLNG equity gas production and an increase in the price of third party gas causing Santos to adjust its upstream gas supply and third party gas pricing assumptions for GLNG. “Low oil and gas prices continue to challenge our upstream business and the entire oil and gas industry,” Santos Managing Director and Chief Executive Officer Kevin Gallagher said.

“At GLNG we are seeing the effects of ongoing constraints on capital expenditure and a softer LNG market.

“We are experiencing a slower ramp up in production of GLNG equity gas and the

price of third party gas has increased.

“We have therefore adjusted our assumptions regarding upstream gas supply and third party gas pricing. This will not affect GLNG’s ability to meet its LNG off-take commitments.”

Mr Gallagher said the company would continue to maintain a disciplined approach to capital allocation by reducing costs and seeking opportunities to optimise their asset portfolio to deliver value to shareholders.

“We have decided to adjust our longterm operating assumptions for GLNG to reflect the reality of the current oil price environment,” Mr Coates said.

“However, we firmly believe in the strong long-term growth of LNG consumption and demand globally. GLNG will continue to be an important part of our LNG portfolio and a key supplier of LNG to the Asian market.”

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NEWS

VICTORIA BANS FRACCING

V

ictoria will introduce legislation to become the first state in Australia to ban fraccing, effectively prohibiting any onshore unconventional development in the state.

The permanent legislative ban, to be introduced to Parliament later in 2016, is part of the government’s response to the 2015 Parliamentary Inquiry into Onshore Unconventional Gas in Victoria.

The inquiry received more than 1600 submissions, mostly opposed to onshore unconventional gas.

Victorian Minister for Resources Wade Noonan said, “There has been a great deal of community concern and anxiety about onshore unconventional gas – this decision gets the balance right.

“We have carefully considered the parliamentary inquiry’s key findings and recommendations, consulted widely and made our decision on the best available evidence.”

Exemptions to the ban will remain for other types of activities that are not covered by the current moratorium, such as gas storage, carbon storage research and accessing offshore resources. Exploration and development for offshore gas will also continue.

Until the legislation is passed by parliament, the current moratorium on unconventional onshore gas exploration and development will stay in place.

The Victorian Government will also legislate to extend the current moratorium on the exploration and development of conventional onshore gas until 30 June 2020, noting that fraccing will remain banned.

The Australian Petroleum Production and Exploration Association (APPEA) has slammed the move, and said the Victorian government had played politics by extending its restrictions on onshore gas development.

APPEA Chief Executive Dr Malcolm Roberts said there was no environmental reason to ban onshore gas development in Victoria.

Dr Roberts said, “The technology is proven and safe. In the case of conventional gas, Victoria has had decades of safe local production.

“Every independent, scientific inquiry confirms that, properly regulated, unconventional gas is safe. Activist fear campaigns can create confusion and uncertainty in the community but our political leaders have a responsibility to

rise above such campaigns and support an honest, factual debate.

“The decision today is short-term politics that will leave Victoria exposed to unnecessarily high energy prices.

“In April, the Australian Competition and Consumer Commission warned that Victoria was particularly vulnerable to tight market conditions. The ACCC also rejected the use of moratoriums.”

Dr Roberts said that Victoria relied on natural gas more than the rest of Australia, with almost 80 per cent of the state’s

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homes connected to gas.

“Natural gas is the invisible ingredient for manufacturing – 27 per cent of the gas consumed by industry in Victoria is used as feedstock to make essential products such as glass, bricks and fertilisers. Industries such as dairy and food processing are heavy users of gas.

“Both the Australian Energy Market Operator and the Australian Consumer and Competition Commission have warned of gas supply shortfalls as early as 2019. The government has ignored this advice.”

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NEWS

NEW METHOD TO INCREASE CSG YIELD

T

he University of New South Wales (UNSW) has discovered a new method to potentially increase gas yields in coal seam and biogas plants, with the method to undergo its first trial in industrial applications in India.

By adding a common synthetic dye, microbiologists at UNSW demonstrated a ten-fold increase in the volume of methane generated by microbes in coal seams, and even larger gains in biogas derived from agricultural and food waste.

The trial will take place in partnership with India’s largest oil and gas producer, Oil and Natural Gas Corporation (ONGC).

The UNSW team and India’s Energy and Resources Institute (TERI) will work together to develop an industrial application in coal seam gas wells operated by India’s state-owned ONGC, the country’s dominant oil and gas explorer and producer.

In its recent funding round, the Australia India Strategic Research Fund (AISRF) announced a new grant of $1 million to support the project.

UNSW’s researchers have already replicated the gains in gas volumes outside the laboratory, in tests in coal seams west of Sydney. However, the Indian trials will enable a battery of industrial-scale tests factoring in critical variables such as coal seam pressure and temperature, as well as enabling the development of new

technologies to precisely introduce the dye.

In the UNSW research, the crystals formed from neutral red dye were also shown to increase gas yields from microbes living on organic waste by up to 18 times.

The breakthrough could extend the life of coal seam gas wells as well as greatly boost gas yields from bio-digesters that use carbon-neutral organic waste to generate methane for electricity production.

The project’s leader, UNSW Associate Professor Mike Manefield, said, “This is very exciting and likely to be a game changer.

There is a lot riding on natural gas, or methane, to help bring global emissions down as the world transitions to cleaner fuels.

“As gases burn far more efficiently than solids, you emit half as much carbon dioxide for the same amount of electricity when you burn gas, compared to coal.”

Assoc. Prof. Manefield said his team “happened upon” the breakthrough when using the common dye, phenazine neutral red, while investigating methane-producing microbes.

These “methanogenic archaea” live in coal seams and on organic waste, producing one billion tonnes of biogas a year. At the right concentration, the dye forms previously unobserved crystals that act as electron sponges that “power up” the microbes, boosting their growth and methane production.

Assoc. Prof. Manefield said, “It’s simple.

If the microbes grow faster, they emit more methane.”

In India, the national electricity grid is under intense pressure and some areas have no access to power. Accelerated methane production is not only a potential means of extracting much more energy from each coal seam gas well, but the process may also open up new sources of gas.

Much of India’s untapped coal deposits consist of younger, softer coal that is much easier for methane-producing microbes to digest – and, therefore, potentially a much larger source of methane than higher-value hard, black coal.

Using the UNSW synthetic dye process, these currently unviable soft coal deposits may be more commercially attractive for coal seam gas development.

Assoc. Prof. Manefield said, “We could greatly reduce the number of coal seam gas wells needed to deliver the same amount of gas – and also add value to coal deposits that would otherwise be uneconomical to exploit.”

Assoc. Prof. Manefield said the Indianbased project was also expected to deliver new fundamental knowledge about how methane-producing microbes worked.

“We still don’t really understand how they tick. This is a chance to learn more about how they work, and so inform our wider understanding of methane gas production.”

CSIRO TO PUBLISH AIR QUALITY DATA

A

CSIRO program that measures air quality in the Surat Basin has been made available to the public and can be livestreamed.

CSIRO, through the Gas Industry Social and Environmental Research Alliance (GISERA), is leading a study which involves the collection of air quality measurements through a network of five ambient air quality stations in the Chinchilla, Miles and Condamine region of Queensland.

The data collected is updated live on the Queensland Department of Environment and Heritage Protection (DEHP) website.

CSIRO atmospheric researcher Sarah Lawson said live streaming the data showed transparency of the data collection process.

“The data is accessible to everyone which means local communities and the

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general public can stay informed about the air quality in the Western Downs region, how it compares to other parts of Queensland and how levels compare to the government’s air quality standards,” Ms Lawson said.

The Air Quality Monitoring team within the Department of Science, Information Technology and Innovation (DSITI) will be responsible for publishing the air quality monitoring data on the DEHP website.

Queensland Minister for Innovation, Science and the Digital Economy, Leeanne Enoch said this was a great example of scientific collaboration between CSIRO and Queensland Government.

“Hosting the live air quality data from coal seam gas regions to local community and people of Queensland is a great way to show transparency and build confidence in the research that is taking place,” Ms

Enoch said.

An air quality model will also be used to explore the degree to which different emission sources in the Surat Basin contribute to the levels of air pollution.

The model includes a variety of natural and man-made emission sources including the CSG industry, power stations, mines, livestock production, motor vehicles, bushfires, and vegetation.

By running the model with different emission sources switched on and off, the degree of contribution from sourcesincluding the CSG industry- can be investigated.

“Both the air quality data and modelling results can be used by government to inform policy and regulations around CSG development and by industry to focus on improving practices that reduce emissions of pollutants,” Ms Lawson said.

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䠀椀最栀 䌀漀甀渀琀爀礀 昀甀猀椀漀渀 甀渀搀攀爀猀琀愀渀搀 攀砀愀挀琀氀礀 眀栀愀琀 琀栀攀椀爀 挀甀猀琀漀洀攀爀猀 渀攀攀搀Ⰰ 愀渀搀 眀攀 眀椀氀氀 瀀爀漀瘀椀搀攀 礀漀甀 眀椀琀栀 愀 昀甀氀氀礀 椀渀琀攀最爀愀琀攀搀 猀甀椀琀攀 漀昀 猀攀爀瘀椀挀攀猀⸀ 䠀䌀䘀 眀椀氀氀 攀渀最椀渀攀攀爀 瀀攀爀猀漀渀愀氀椀猀攀搀 猀漀氀甀琀椀漀渀猀Ⰰ 戀甀椀氀搀 猀礀猀琀攀洀猀 愀渀搀 渀攀眀 椀渀渀漀瘀愀琀椀漀渀猀 椀渀琀漀 礀漀甀爀 渀攀砀琀 瀀爀漀樀攀挀琀⸀ 圀攀 栀愀瘀攀 瀀爀漀樀攀挀琀猀 爀椀最栀琀 愀挀爀漀猀猀 䄀甀猀琀爀愀氀椀愀 昀爀漀洀 一漀爀琀栀 儀甀攀攀渀猀氀愀渀搀 琀漀 圀䄀

匀愀氀攀猀 ∠ 䠀椀爀攀 䘀氀攀攀琀 ∠ 匀攀爀瘀椀挀椀渀最 ∠ 匀瀀愀爀攀 倀愀爀琀猀

圀攀ᤠ爀攀 渀漀琀 樀甀猀琀 愀 栀椀爀攀 挀漀洀瀀愀渀礀㬀 眀攀 愀爀攀 琀栀攀 氀攀愀搀攀爀猀 椀渀 䴀挀䔀氀爀漀礀 昀甀猀椀漀渀 洀愀挀栀椀渀攀 栀椀爀攀 愀渀搀 猀愀氀攀猀 椀渀 䄀甀猀琀爀愀氀愀猀椀愀⸀ 伀甀爀 爀愀渀最攀 漀昀 昀甀猀椀漀渀 洀愀挀栀椀渀攀猀 愀爀攀 搀攀猀椀最渀攀搀 琀漀 琀愀欀攀 漀渀 䄀甀猀琀爀愀氀椀愀ᤠ猀 琀漀甀最栀攀猀琀 挀栀愀氀氀攀渀最攀猀 愀渀搀 愀爀攀 欀渀漀眀渀 昀漀爀 琀栀攀椀爀 氀漀渀最 氀椀昀攀 猀瀀愀渀 愀渀搀 爀甀最最攀搀 挀漀渀猀琀爀甀挀琀椀漀渀⸀ 圀攀 瀀爀漀瘀椀搀攀 挀甀猀琀漀洀 攀渀最椀渀攀攀爀椀渀最 猀漀氀甀琀椀漀渀猀Ⰰ 愀猀 眀攀氀氀 愀猀 瀀爀漀瘀椀搀椀渀最 愀 昀甀氀氀 爀愀渀最攀 漀昀 猀瀀愀爀攀 瀀愀爀琀猀Ⰰ 攀焀甀椀瀀洀攀渀琀 猀攀爀瘀椀挀椀渀最Ⰰ 琀爀愀椀渀椀渀最 猀漀氀甀琀椀漀渀猀 愀渀搀 挀漀渀猀甀氀琀愀渀挀礀 猀攀爀瘀椀挀攀猀⸀

䌀漀渀琀愀挀琀 甀猀 琀漀搀愀礀 ⬀㘀㄀ ⠀ ⤀㜀 ㌀㠀㠀㌀ ㄀㠀㜀㠀

㈀⼀㌀㔀 刀漀戀猀漀渀 匀琀爀攀攀琀 䌀氀漀渀琀愀爀昀 儀䰀䐀 㐀 ㄀㤀 倀㨀 ⬀㘀㄀ ⠀ ⤀㜀 ㌀㠀㠀㌀ ㄀㠀㜀㠀 䔀㨀 椀渀昀漀䀀栀椀最栀挀漀甀渀琀爀礀昀甀猀椀漀渀⸀挀漀洀⸀愀甀

眀眀眀⸀栀椀最栀挀漀甀渀琀爀礀昀甀猀椀漀渀⸀挀漀洀⸀愀甀

䴀攀洀戀攀爀猀 漀昀㨀

EXPLORATION

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EXPLORATION

EAST COAST GAS PRICES WILL STIMULATE THE SEARCH FOR NEW RESOURCES

by John Phillips, Managing Director, Blue Energy; John Ellice-Flint, Chairman and Executive Director, Blue Energy; and Rod Gould, Exploration Consultant, Hedges Gas Australia’s East Coast is facing significant demand for new gas supply over the next several decades, and the obvious solution to meeting this demand is unconventional gas.

N

atural gas is reservoired in many different types of rocks. Sandstone, limestone, shale, and coal are all capable of reservoiring natural gas. Some are both source rock and reservoir rocks, whilst others are only reservoir rocks that require natural gas to migrate from its source into the reservoir.

However the gas is basically the same – it is natural gas. For this reason we do not use the terms shale gas and coal seam gas; these are terms that were introduced by Wall Street operatives for promotional purposes. The majority of the world’s natural gas is produced from sandstone or limestone reservoirs, yet who uses the term sandstone gas or limestone gas? The industry is the natural gas industry. The real difference between the reservoir types is largely a function of the rock’s permeability. High permeability rock equals higher flow rates and lower cost development by virtue of requiring a lesser number of wells (e.g.

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for sandstone and limestone reservoired gas) and by contrast lower permeability rock (e.g. shale, coal, and tight sandstone reservoired gas) equals lower flow rates and higher cost development as more wells are required to achieve the same flow rate.

As the high permeability, high flow rate and low cost reservoirs were generally found and developed first (e.g. Gippsland Basin, Cooper Basin and North West Shelf), these resources have been in production for many decades and are now, substantially, in decline. However, the development in the United States of specific drilling and completion technologies [such as horizontal drilling and multistage low cost fracture stimulation in horizontal wells] has recently allowed the economic development of lower permeability reservoir rocks. These technologies, coupled with higher gas prices, have brought vast quantities of previously marginal sub-economic gas resources to market. While De Silva and others have discussed the challenges to SPRING 2016 // ISSUE 6

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Galilee Basin

Mt.Isa

Bowen Basin

Adavale Basin Cooper Eromanga Basin Moomba

Brisbane Clarence Moreton Basin Gunnedah Basin Sydney Basin

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Figure 1. Prediction by Steve Davies in 2013 of the gas transmission directions in eastern Australia to come into effect after commissioning of the LNG export trains in Gladstone. This is now the current situation with gas from the Otway Basin going via Adelaide to Moomba and then to Gladstone; similarly gas from Bass Strait is carried to NSW and onto Moomba and then to Gladstone to meet the demand of the LNG plants.

Gippsland Basin

Otway Basin

the development of the Australian tight gas industry, the prospects for low permeability gas resources in eastern Australia should now become more attractive as domestic gas prices rise. Whilst technological advances are the principal reason for allowing economic development of low permeability gas, gas price is clearly a compelling factor.

It could be said that most of the relatively cheap gas for East Coast Australia (from high permeability rocks) has been produced, leaving the more expensive gas from lower permeability rocks now to be developed. This development depends on the market price for gas allowing a reasonable return for those risking the capital expenditure required for exploration success and development.

Gas end users in eastern Australia have been the beneficiaries of available low cost gas for decades, but basic input costs have risen, in part because regulatory requirements have increased to ensure that explorers and producers: ♦♦ Protect the environment

Gloucester Basin

Bass Basin

♦♦

Do not adversely impact social aspects of communities ♦♦ Negotiate and agree on compensation for Traditional Owners and operators ♦♦ Identify, acknowledge and preserve cultural heritage ♦♦ Pay royalties to the relevant government ♦♦ Protect farmers’ rights ♦♦ Identify and protect endangered flora and fauna ♦♦ Keep groundwater pristine ♦♦ Protect the Great Barrier Reef.

All of these contribute to the ultimate cost of getting gas to the market and end users.

In addition, there is now an export LNG market available to gas producers which has a pricing mechanism linked to the oil price. This is different to the basis for the historical Australian domestic gas contracts.

The LNG export market has a very large demand, which will run for many decades.

It is this export market and its historically higher price for gas that has led to the

development of East Coast gas resources that would not have been developed otherwise.

The higher cost, lower permeability gas today would not have been considered a development target without the benefit of the huge amount of capex already spent on the pipelines and processing plants needed to develop the early high permeability sandstone reservoirs.

The recent dramatic fall in the oil price has however affected the international trading price of LNG, due to the link to oil price, and therefore the cost of production becomes critical to the economics of each producing asset. Given that low permeability gas is by definition high cost, the economics of Australian low permeability gas are not currently as favourable for the international LNG market.

In addition, Australian low permeability gas is still largely a work in progress and therefore has uncertainties on both cost and reservoir/field performance.

The projects which use tight gas from Queensland’s Surat Basin as the feedstock

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EXPLORATION

Daily short-term gas prices in the eastern states ($/GJ) 30.00

Victoria wholesale

25.00 20.00 15.00

Sydney

Adelaide

10.00 Brisbane

May1

5

9

13

17

21

25

29

Jun2

6

10

GJ: gigajoule

14

18

22

26

5.00 30

Source: ENERGYQUEST/AMEO

Gas Short Term Trading Market, eastern states Figure 2. Wholesale pipelined gas prices in eastern Australia May-June 2016. Note the spike in prices in late June.

From Ben Potter, Australian Financial Review, 8 July 2016.

for the three Gladstone LNG operations on Curtis Island are a world-first in reliance on this type of gas source. Those responsible for the successful start-up of these projects deserve acknowledgement; but it needs to be recognised that there are three big experiments on Curtis Island – not so much from a liquefaction technology perspective but from the point of feed gas supply.

Additional gas now has to be sourced from other areas.

The evolving supply/demand situation for gas in the East Coast market is resulting in rising wholesale prices. This would ordinarily invigorate a wider search for low permeability gas. However, the east Australian domestic gas market itself is volumetrically too small to underpin development of the large low permeability gas resource. It needs the international export gas market volumes to work, but unfortunately at the moment the international LNG market is oversupplied and priced accordingly.

The ACCC inquiry into the East Coast Gas Market highlighted the uncertainty of the future gas supply for the East Coast market and the requirement for new gas sources to meet demand, particularly to satisfy the need for feedstock at the three LNG export plants in Gladstone, Central Queensland.

There are as yet undeveloped gas resources in organic-rich horizons of

Proterozoic and Palaeozoic basins that could be tapped by the existing east Australian gas pipeline network, including the proposed Tennant Creek to Mt Isa line. In 2013, the US Department of Energy assessed the Beetaloo, Cooper and Georgina Basins as among the four Australian basins with the largest potential for low permeability gas resources. The McArthur Basin can be added to this list.

In addition to technological, higher costs, and pricing issues, there is a lack of practical political support in Australia for the establishment of a viable low permeability gas industry as illustrated by the situation in Victoria and New South Wales where regulatory barriers prevent the development of onshore gas resources.

Five of the six LNG export trains in Gladstone are now on stream, contributing to the country’s balance of payments and to the benefit of Queensland’s economy.

With all six of the Gladstone export plants to be operating by 2017, Australia will become one of the leading LNG exporters in the world. The increased demand for natural gas supplies has, as predicted by Steve Davies of the Australian Pipeline Industry Association in 2013 [Fig. 1], resulted in the reversal of the Moomba to Adelaide and the Moomba to Sydney gas lines so that gas sourced from the Otway Basin and Bass Strait respectively, is being transported to Gladstone via Moomba and

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then through Wallumbilla.

Wholesale gas prices on the East Coast, historically around $3-$4 per GJ, have recently risen generally to around $6-$9, although in late June and early July 2016 headed skywards to $20-$30 per GJ (see Figure 2) following supply disruption and a sudden cold snap in the southern states.

Australia’s historically low gas prices of $3-$4 have been a relic of the initial long-term contracts when natural gas was competing with coal on a non-carbonbased calorific comparison. In actual fact, gas production in the Cooper Basin and the Gippsland Basin was subsidised by the value of the associated oil production.

Without this associated liquid production, many of Australia’s onshore fields would have been uneconomic at these gas prices.

Although drilling activity in the shale revolution in North America has slowed considerably with the dramatic fall in oil prices, the financing of many companies in the sector requires maintenance of cash flow to service the high levels of debt that fund these companies. The petroleum industry has again turned to technological developments to reduce costs and improve efficiency, allowing sustained production levels and cash flow. Advances in drilling have included advanced analysis of real-time downhole subsurface information for increased production, and the use of nitrogen for drilling and fracture stimulation

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which minimises environmental concerns.

All these technological breakthroughs will be required to be implemented at the lowest possible cost for Australia to realise the full potential of its vast natural gas resources.

The demands for natural gas in the East Coast markets are already evident. To meet those demands there will be more and more reliance on low permeability or tight gas reservoirs which have higher costs of production. With the lead time for exploration, discovery and development in Australian jurisdictions, it is pressing that investment in the search for and proving of gas resources for eastern Australia not be impeded. A decade ago the biggest risks to success in the gas business were geological in the subsurface. Fast forward to today and it appears that the biggest risk to the nation’s energy self-sufficiency and security are above ground.

For these high capital intensive, large volume, low permeability accumulations to be developed, Australia’s large gas users can play a significant role in ensuring an efficient industry is developed in a timely manner and secure long-term energy security for their own businesses and the nation. One can argue that if these current gas users had the vision — as AGL did with the 1970s Cooper Basin gas contracts which covered supply for 30 years or so and allowed Santos to finance and build the Cooper Basin gas production infrastructure in arid central Australia — they should now pool their collective gas demand volumes over the next ten to 20 years, and the natural gas extraction industry would be able to make efficient long-term investment decisions to develop this strategic and essential resource for the nation.

It is easy for Australians who live in the

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coastal cities to forget the huge distances and arid environment this gas has to travel through to get to market. The high capex locations of the majority of Australia’s gas resources in both the onshore and offshore settings add considerably to the cost base.

The combination of the tyranny of distance and the harsh remote environmental conditions, both for central Australian locations and for offshore areas like Bass Strait, which has an environment somewhat equivalent to that of the North Sea, predicates that the initial development and ongoing maintenance costs are not cheap.

What the East Coast of Australia is currently missing is a coordinated approach by the explorers, producers, distributors and gas users, and a consistent regulatory framework to ensure Australia has a reliable, relatively low cost, highly efficient natural gas industry.

♦♦

♦♦

♦♦

♦♦

level. Australian Financial Review, w1 July 2016: 17, 20.

Potter, B. 2016. Gas shortage a $100m hit to AGL. Australian Financial Review, 8 July 2016: 19.

Sims, R. 2016. Keynote address: observations on the east Australian gas market. Australian Domestic Gas Outlook Conference, Sydney, 9 March 2016.

Stratas Advisors. 2016. Global LNG outlook. Hart Energy.

32 pages.

Watts, R. 2016. Energized fracturing solutions. Safe, reservoir-friendly and water-saving well stimulation is made possible with N2 and CO2. E & P Magazine, July 2016, 89(7): 56-58.

References ♦♦ Australian Competition and Consumer Commission. 2016. Inquiry into the East Coast gas market. 22 April 2016.

174 pages. ♦♦ Blue Energy Limited. 2016. Quarterly activities report to 31st March 2016.

ASX:BUL 29/4/2016. ♦♦ Blue Energy Limited. 2016. Quarterly activities report to 30th June 2016.

ASX:BUL 29/7/2016. ♦♦ Davies, S. 2013. Making sense of the evolving East Coast pipeline grid. Australian Pipeline Industry Association Ltd. ♦♦ De Silva, N., Simons, S. & Stevens, P. 2016. Shale resource development potential: the Australian context.

Unconventional Oil & Gas, Autumn issue, 4:32-36. ♦♦ Macdonald-Smith, A. 2016. Winter freeze pushes gas price to panic

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EXPLORATION

The obvious solution to our looming gas shortage is to ensure we are able to explore and produce more gas from all kinds of reservoir rocks. This will need a coordinated approach from industry, communities, landholders, traditional owners, regulators and end users.

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WHERE ARE THE OPPORTUNITIES FOR GAS PIPELINERS?

Construction of gathering networks at Gladstone will continue to provide opportunities for pipeliners. Image courtesy QGC.

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LOGISTICS

by Jessica Dickers, Associate Editor, Unconventional Oil & Gas Australia’s gas market is currently in transition, with predicted supply shortages, increased prices and gas moving away from domestic consumers and towards LNG exports. But change also brings opportunity and despite the challenges of the sector, there are many exciting projects underway or planned for the pipeline industry. Here, we look closely at the pipeline sector and consider the opportunities our changing gas supply market is providing.

A

ustralia’s future energy security is currently under scrutiny, with most states experiencing some form of supply or price uncertainty.

As increasing electricity prices and renewables disrupt the market, attention turns to gas and its importance in future energy security.

The development of a substantial gas export industry in Gladstone, Queensland, where coal seam gas is converted to LNG for supply to Asian markets, is also having a considerable impact right around the country.

In an address to the Australian Pipeline and Gas Association (APGA), APA Group Chief Executive Officer and Managing Director Mick McCormack said the gas market is a substantial way through the biggest transition it is ever likely to see – and for the market to adapt and have a continued gas supply, Australia needs reliable pipeline infrastructure.

“The most important thing that came out of the recent ACCC inquiry is that there is sufficient gas forecast to be produced to satisfy both LNG and domestic demand to 2025 – this is good news for consumers,” Mr McCormack said.

“That finding is predicated on forecast production occurring and, one would assume, on the ability for gas to get to

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market. That’s where the pipeline industry comes into play. Pipeline infrastructure is critical to increasing gas supply, and increasing gas supply will put downward pressure on prices.

“The pipeline industry’s success is dependent upon more supply coming into the market, and more customers having access to gas. To this end, the pipeline industry has a demonstrated record of investing and innovating to give customers the services they need to ensure gas projects proceed.”

While major gas projects over the last few years, including those at Gladstone, have already built their main infrastructure and transmission pipelines, APGA Chief Executive Cheryl Cartwright said there would always be opportunities for pipeline workers in the unconventional sector as long as there were developments.

“While there’s coal seam gas development, pipeline gathering systems will be required. Also, should there be sufficient gas in the CSG fields, it could prompt expansion of existing transmission lines or possibly even new transmission pipelines,” Ms Cartwright said.

According to Ms Cartwright, Australia needs more gas, but to achieve this, the sector must have the support of state and federal governments. “We need governments to introduce policies that

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encourage the development of our valuable natural gas reserves.

“Australia has abundant gas reserves – sufficient to supply the export and domestic gas markets. We need a sensible energy policy that will see Australia reduce carbon emissions efficiently and economically, and we need the CSG moratoria to be lifted.

“Government policies can help to ensure there is sufficient gas for both the export and domestic markets by encouraging development of those reserves. Fairer treatment of natural gas in emissionsreduction policies would help to increase supply in the domestic market.”

All eyes on the Territory By far the biggest pipeline project in Australia at the moment is Jemena’s $800 million Northern Gas Pipeline (NGP), running from Tennant Creek in the Northern Territory to Mount Isa in Queensland. The 622km pipeline will connect the Northern Territory to East Coast gas markets, and a large percentage of gas that will be supplied through the pipeline is expected come from unconventional sources.

Construction company McConnell Dowell was selected as the construction contractor for the pipeline and over the course of the project, there will be around 200 subcontracts awarded. So far, 53 work packages have gone out to tender including engineering, procurement and preliminary construction work, and construction on the pipeline is expected to begin in early 2017, with commissioning in 2018.

Jonathan Spink, Northern Gas Pipeline Project Director at Jemena, has said the pipeline will create approximately 900 industry jobs throughout the planning, construction and commissioning phases.

“We will focus on sourcing labour from close to the project area – in the Tennant Creek and Barkly areas of the Northern Territory and Mount Isa region in western Queensland,” said Mr Spink.

“Jemena is also implementing a business investment fund to assist small and medium enterprises in the NT and Mount Isa areas, designed to build local capability and capacity, and assist those businesses to participate in the project.”

Jemena won the contract for NGP with its route between Tennant Creek (Northern Territory) to Mt Isa (Queensland) Northern Territory and Queensland, with the alternative route, proposed by both the DDG Operations (DUET) and Pipeline Consortia Partners Australia (China National Petroleum Corporation) having the pipeline run from Alice Springs in the Northern

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Territory to Moomba in South Australia.

Outgoing Northern Territory Chief Minister Adam Giles was a key figure in the Northern Gas Pipeline project since launching the initial tender process in October 2015. Following recent energy shortages in South Australia, Mr Giles suggested building the second proposed pipeline route, from Alice Springs to Moomba, could help meet energy demand in the state.

“A national energy summit should consider the possible construction of a second gas pipeline from Central Australia to Moomba,” said Mr Giles. “These can both be achieved under the Commonwealth’s agenda to develop Northern Australia.”

Mr Giles was defeated at the August 27 Northern Territory state election, and incoming Chief Minister Michael Gunner has previously announced he would put a fraccing ban in place in the territory until another review of the science behind fraccing could be carried out – effectively canning any short term plans to move forward with this second pipeline.

Australia’s unconventional core In Queensland, there are several other pipeline projects currently underway or in planning in the country’s undisputed hub of unconventional exploration.

Queensland Gas Company (QGC) and its joint venture partners China National Offshore Oil Corporation and Tokyo Gas are creating up to 1,600 industry jobs through their new development, Project Charlie.

Project Charlie is a $1.7 billion investment in gas infrastructure located west of Wandoan within Queensland’s Western Downs Region. In addition to the creation of 300–400 gas wells and a large field compression station, the project will involve associated pipelines including the installation of a 35km 900mm diameter coal seam gas trunkline.

“The Charlie development will help to sustain the benefits of our investment in local communities and the state, including up to 1,600 construction jobs and business opportunities during the twoyear project,” said Tony Nunan, Managing Director at QGC. “This is a vote of confidence in the secure, long-term future of Queensland’s natural gas industry, which will employ Queenslanders for many years to come.”

In addition to Project Charlie, there are a number of other energy producers proposing major pipeline projects that will provide the industry with a stream of opportunities once construction begins.

Arrow Energy currently has four

proposed projects, two of which are pipelines running from the Bowen and Surat basins.

An Arrow spokesperson said the proposed Arrow Bowen Pipeline (ABP) would run from coal seam fields 38km north of Moranbah and extend approximately 430km south to the Gladstone State Development Area (GSDA).

The pipeline’s Environmental Impact Statement (EIS) received Queensland Government approval in March 2013, and environmental approval from the Federal Government in October 2014, but the project has experienced production challenges in 2016.

“Further technical work is currently being undertaken to improve production from parts of the Bowen Basin that contain deeper and tighter coals than the Surat Basin,” the Arrow Spokesperson said.

While this technical work is being completed, Arrow is continuing planning, which includes applying to the Queensland Government for a petroleum pipeline licence and Environmental Authority for the pipeline.

Arrow’s other proposed pipeline, the Arrow Surat Pipeline (ASP), received Queensland Government approval in January 2010 and has already been issued with a pipeline licence and Environmental Authority. The pipeline will transport coal seam gas from Surat Basin to Gladstone and Arrow is continuing to progress the development, with planning underway to identify the best path to monetise the reserves.

Future opportunities Another major proposed pipeline that will link gas to our export markets is Blue Energy’s recently announced Bowen Basin pipeline, a 160km pipeline which will help commercialise Blue’s gas reserves and resources in the Moranbah area.

Blue Energy CEO and Managing Director, John Phillips, said Blue has undeveloped gas reserves around Moranbah and there is currently no connection between Moranbah and the southern gas market (including Gladstone), where the bulk of East Coast gas demand is located.

This pipeline will run from Moranbah to the Northern Denison Trough, linking the Bowen Gas Province to the Brisbane and Gladstone markets.

Mr Phillips said the decision to build the Bowen Basin pipeline had been largely influenced by the high demand for gas on the East Coast, which he believes is likely to continue with the ramp up of liquefaction capacity at Gladstone.

“Clearly there is a need to bring more

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LOGISTICS

Changing energy markets create a need for new transmission pipelines. Image courtesy QGC.

gas to the market – the ACCC states this quite clearly in their report on the East Coast gas market released earlier this year.

Their view is amplified by the recent gas price shock in Sydney and Melbourne ($30/ GJ) with the occurrence of the first real cold weather of a southern winter and the ramp up of LNG production in Gladstone.

“It is therefore vital that Blue’s gas, and gas within the Bowen Gas Province, be fast tracked into the southern market to ease supply pressure and stabilise prices,” Mr Phillips said.

Blue Energy is currently in discussion with several construction companies to build the pipeline, and Mr Phillips said once they were chosen and gas buyers were established, he expects the construction time to be between 12-18 months.

“Several other activities (regulatory approvals and field development) will have to occur in parallel with this to meet the gas demand timeframe of the potential buyers,” Mr Phillips said.

“I expect the planning, approval processes and investment decisions required to happen prior to any actual

construction, which at the moment is at least two years out from now.”

Mr Phillips said that the current state of pipeline infrastructure in Australia is undergoing significant change.

“As the demand centre has shifted to Gladstone, from Sydney and Melbourne, those pipelines constructed to supply that demand centre are and will continue to undergo ownership changes.

“Flow directions on the major pipelines have also commonly reversed nowadays to give that supply flexibility. Who would have thought that Gladstone would be getting some supply from Victoria?”

Mr Phillips said that while the challenge is keeping those big pipelines full, of equal importance is ensuring that new gas provinces are discovered and can be economically developed with infrastructure a timely manner.

“This requires collaboration between explorers, producers, pipeliners, gas end users and regulators, to ensure we avoid duplication or wastage, and supply efficient low cost energy to the nation in a timely manner.”

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Conventional developments The shift in gas demand from Sydney and Melbourne to Gladstone has created new opportunities for pipeliners in other states as well.

The changing market led APA Group to expand its East Coast network through the Victorian Northern Interconnect Expansion (VNIE), supporting gas flows around Eastern Australia.

The extension involves looping sections of the existing APA owned DN300 Wollert to Wodonga Pipeline (Victoria) and DN300 Young to Wagga Wagga Pipeline (New South Wales).

The extension is currently being undertaken by Spiecapag Lucas, a joint venture between Lucas Engineering and Construction and Spiecapag Australia.

Spiecapag Lucas is constructing 165km of pipeline across Victoria and New South Wales, which is further broken down into seven loops.

The extension is scheduled to be complete by February 2017 at which point the pipeline will be fully looped from Wollert to Barnawatha and from Wagga to Young.

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Arrow Energy’s Moranbah Gas Processing Facility. Image courtesy of Arrow Energy.

Extension on the horizon In Western Australia, the Dampier to Bunbury Natural Gas Pipeline (DBNGP) is the state’s critical transmission pipeline, stretching around 1600km from gas fields in the Carnarvon Basin to Bunbury in the state’s south-west.

A plan to extend the pipeline further down to Albany has often been discussed, without progressing any further. However, Western Australian Minister for State Development, Bill Marmion, recently announced that the Government had received a private bid to build the pipeline extension which is now under consideration.

“We have received a strong, unsolicited proposal to build the pipeline, which is currently being examined and assessed.

Obviously, it has to be assessed, but it is very good news,” Mr Marmion said.

“The proposal is being assessed for cost, specifications of the pipeline — the route, and also the commercial viability. It is a very

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good proposal and we are very optimistic that it can be delivered.”

Mr Marmion would not reveal the name of the bidder, but media reports from July said Western Australian Premier Colin Barnett confirmed energy infrastructure company ATCO submitted the bid.

If accepted, Mr Marmion said the new gas pipeline extension to Albany would deliver industry jobs during the pipeline’s construction as well as jobs from new investment in the area.

“Many south west towns will end up being reticulated on to gas, which will save a lot of energy costs. Some of the businesses that might be attracted by lower costs of energy include viticulture, agriculture, mineral industries and timber industries.

“Having cheaper energy in the south west is also likely to encourage new business and new capital investment in the region,” Mr Marmion said.

What needs to happen next?

APGA Chief Executive, Cheryl Cartwright, said that while the pipeline industry is prepared for whatever the future will bring, the best way forward is to have strong policies behind the industry.

“We need policies that encourage the development of natural gas as part of the energy future. Gas, with renewables, will help to reduce Australia’s carbon emissions,” Ms Cartwright said.

“A technology-neutral carbon-reduction policy would help to encourage investment in natural gas, as it would recognise the value that gas brings to the economy, particularly for electricity generation.

“The pipeline industry stands ready with high-quality workmanship to design, construct and operate gas transmission pipelines wherever the demand occurs.”

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LOGISTICS

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LOGISTICS

THE NATURE POLYETHYLE

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LOGISTICS

OF NE PIPE FAILURE

by Dr Chris O’Connor, Principal Consultant and Neil Pollock, Operations Manager East Coast Australia, NZ and PNG.

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LOGISTICS

Polyethylene pipe is widely used for pipelines in the gas industry thanks to its impressive characteristics. At times, however, failures do occur. Here, Chris O’Connor and Simon Brooks detail the types of failures that can affect polyethylene pipes, and how operators can avoid these failures in their networks

P

olyethylene (PE100) pipelines are used extensively in operating gas, water distribution systems safely, reliably and economically, and enjoy an excellent performance track record.

Today’s highly engineered bimodal PE100 provides an exceptional balance of strength, stiffness and toughness. Its chemical inertness, non-corrosive nature and long term durability offers outstanding service life, with conservative estimates standing at 100+ years, consistent with demands of long-term gas and water pressure containment.

PE pipelines are however, susceptible to failure under some circumstances.

Reported failures of PE pipe systems are twofold; older generation PE materials failing due to inferior properties (stress crack resistance) offering limited resistance against severe environmental and operating conditions; and human error, committed in the supply chain and site construction of installed pipe systems.

Today, operators of PE pipeline assets report that the major threat to PE pipeline integrity, other than third party damage, is poor fusion jointing. Joints can be a point of weakness in any engineering system.

Secondary bending and axial induced stress caused by insufficient support, ground movement, thermal expansion or contraction increases the risk of failure of sub-standard joints.

At DNV GL, formerly British Gas/ Advantica, we have over 40 years of experience in PE pipeline technology, and routinely conduct pipeline inspections, audits, product qualification, incident reports and independent forensic failure analysis.

We know first-hand that PE pipe system failure can result in explosion, fire, flood, and loss of life, resulting in costly litigation and damages. In addition, environmental damage, service interruption, and

damage to company credibility are huge threats. For these reasons, we strive to determine an exact cause of failure, and develop remediate, corrective actions to prevent recurrence. We believe in active engagement with operators and all field personnel in order to disseminate knowledge so that lessons can be learned from past mistakes in order to enhance the safety of PE pipeline networks.

The fusion process There are three main types of fusion joint geometry, which include; 1. Butt weld 2. Socket joint a. Electrofusion b. Hot iron socket 3. Saddle joint a. Electrofusion b. Hot iron socket.

The butt fusion technique is a simple one, whereby the two ends of the pipes to be joined are trimmed flat and square to each other and then heated using a flat heater plate under controlled temperature, time and fusion pressure.

Electrofusion socket joints involve the use of injection moulded PE fittings, into which the pipes are inserted. Embedded within the fitting are a series of heating wires, located just below the surface of the internal bore of the fitting, with terminals on the outside for electrical connection. These wires, when energised by a controlled electrical power source for a pre-defined duration, produce the necessary heat to melt the plastic and, once allowed to cool, form a welded joint.

The fusion process involves heating PE, until the material reaches its crystalline melt point, at which it becomes a visco-elastic melt. In this melt state, under the action of pressure, the long chain like molecules of PE can uncoil, disentangle and slide over each other (shear flow) as shown in Figure 1.

Two separate melt phases, pipe and joint interface, can then be brought together

allowing molecules to mix together (i.e. sliding over each other and entangling with each other resulting in molecular mixing). On cooling, chain mobility reduces, the chains re-coil, re-entangle and the crystalline zones are re-instated, resulting in re-solidification. The resultant fusion weld can be as strong as the original parent material.

Successful fusion jointing requires strict control of fusion parameters, and adherence to codes of practice. Industry has continually strived to develop technology to mitigate risks resulting in poor fusion. The process, however, cannot be completely automated and free of operator intervention.

Another difficulty is that reliable inspection of PE pipe joints using nondestructuve testing (NDT) has proven to be problematic, since techniques have not yet proved sufficiently reliable or cost-effective for field implementation.

Consequently, in order to negate fusion joint failure, it is considered a fundamental requirement that simple in field quality assurance and process control techniques are employed. Underpinning this approach must be a strategic mission statement and commitment to training to maintain competent levels of workmanship. Furthermore, there must be continual investment in equipment to ensure tooling is fit for purpose. Finally, the culture adopted by an organisation must drive behavioural change such that joint installers are self-regulating and take ownership and responsibility for the quality of their workmanship.

Polyethylene failure modes Stress crack growth Stress crack growth (SCG) is a phenomenon in PE materials whereby slow growing cracks can occur due to the presence of stress-raising flaws, e.g. void, contaminant, notch defect or degraded material in the material structure.

Early research of HDPE pipes established that SCG was one of three major failure modes, as shown in Figure 2.

Ductile Failure Mode I results in yielding and reflects a material’s propensity to undergo large-scale, irreversible ‘plastic’

Figure 1. Molecular mixing of molecules during fusion.

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LOGISTICS

Flaw, notch

Mode I – Ductile failure Pressure

Micro-yielding, streess field

Caviation, crazing

Fibrillation, fibril rupture, crack & craze growth

Mode II – Brittle failure

Mode III – Brittle – chemical failure Time to failure

Fibril

Figure 2. Failure modes of PE pipe – internal hydrostatic pressure testing.

deformation when under stress. The mechanism results in localised expansion of the wall section and final rupture of the deformed zone.

Failure Mode II is associated with creep and creep rupture. Creep is timedependant, non-reversible deformation when exposed to a constant tensile stress.

Creep rupture is the terminal event of creep and is a measure of the time that a material under a constant, applied tensile load takes to fail. Creep rupture can be accelerated by temperature, stress concentrations, fatigue and the chemical environment.

The events that lead to creep rupture are shown in Figure 3. After crack initiation voids develop ahead of the crack. These voids gradually merge into larger voids that are spanned by highly orientated load bearing fibrils. This process, known as “crazing”, continues until a point is reached when the most highly stretched fibrils will rupture, resulting in fracture.

For PE, the tenacity of fibrils and their resistance to rupture will be highly dependent on molecular architecture, particularly molecular weight, molecular weight distribution, branching, crystallinity and tie molecules. The tie molecules are embedded in the crystallites and transverse amorphous regions, acting as mechanical links between the crystalline domains, and play a decisive role in the resistance to fibril failure and overall mechanical properties when subjected to stress.

Failure Mode III is related to degradation and embrittlement of the plastic due to thermo-oxidation with time.

The general mode of field failure reported for PE pipe is brittle SCG through the pipe wall, due to the formation of stress concentration defects. These brittle failures are typically slit-type fractures that lie parallel to the pipe’s extrusion direction.

Circumferential hoop stress in the pipe wall is the driving force for crack opening.

Figure 3. Sequence leading to SCG.

Circumferential cracks can also be initiated on either the outside or inside surface of pipes due to secondary stresses such as bending or pipe impingement by rocks and tree roots.

Visually, brittle cracks are typically smooth, featureless and devoid of any yielding and deformation process, as shown in Figure 4.

Figure 4. Brittle fracture surface.

The rate of propagation is dependent on the applied stress and can vary from weeks to years, leading to fracture of the complete joint. The amount of gas released in each case is dependent on the internal pressure and diameter of the pipe in question, and can be significant.

In contrast, SCG will propagate through an electrofusion joint interface, leading to premature failure and a leakage of gas analogous to that of a leaking cast iron joint.

Rapid crack propagation In the late 1970s, workers at British Gas R&D (now DNV GL) discovered that thick wall MDPE pipes operated at a critical pressure, and below a critical temperature could also fail catastrophically by sustained, axial rapid crack propagation (RCP), sometimes referred to as a fast brittle fracture or linear split, as shown in Figure 6.

SCG growth will also occur in butt fusion and electrofusion joints due to an array of potential installation defects, which introduce stress concentrations and weak points in the fused material structure.

Secondary bending stresses, typically misalignment, uneven support or pivot points, can drive crack propagation circumferentially round a butt fusion joint until it becomes unstable, resulting in a transition to fast crack growth and catastrophic failure as shown in Figure 5.

Figure 5. Catastrophic failure of butt fusion joint.

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Figure 6. Rapid crack propagation (RCP).

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LOGISTICS

RCP can be initiated due to a defective butt joint, third party damage, such as a high velocity impact from excavation equipment, or a pipeline pressure pulse.

Once initiated, ruptures can travel at high speed along the length of the pipe over significant distances, as long as the stored energy from the contained pressure source is sufficient to drive the crack faster than the rate at which the energy is released.

At a critical speed approaching the speed of sound, the crack will become unstable, typically branching in a sinusoidal pattern, until it slows and stops.

RCP is dependent on several factors: ♦♦ Pipe diameter – as outside diameter increases, the possibility of RCP increases ♦♦ Operating pressure – as pipeline stress/pressure increases, the possibility of RCP increases ♦♦ Operating temperature – as temperature decreases, the possibility of RCP increases ♦♦ The pipe material’s resistance to impact fracture and resistance to RCP. RCP failure of PE pipe is rare but the potential dire consequences are significant for gas distribution. RCP resistance is now designed into pipes so it may be avoided under worst case scenarios. In order to test this requirement, DNV GL has built a full

scale RCP test facility at its Spadeadam test site, which meets the requirements of ISO 13478. The full scale test is considered to be the most reliable method for assessing RCP resistance. It is designed to reproduce idealised service conditions for a pipe in service. Extensive RCP testing conducted

by DNV GL has identified safe operating pressures such that RCP has never been recorded within the UK Gas Distribution Network.

Conclusion The greatest threat to the integrity of PE pipelines other than third party damage is fusion joint quality.

It is considered that the factors contributing to premature failure are a combination of poor training and awareness, non-compliance with industry codes of practice, lack of robust in-field quality assurance and spot check auditing methodology.

It is considered that front end investment to combat these issues would be a cost benefit in terms of reducing the risk to life, property and the environment. The commercial benefits would be greater assurance in the longevity of pipeline lifetime for 100+ years, with minimum intervention and maintenance.

Chris O’Connor is currently Principal Consultant (Pipeline & Materials) and Technology Qualification Leader for DNV GL. Chris’s field of expertise is non-metallics and he currently provides support for the oil and gas sector advancing corporate profitability objectives through the application of new and emerging technologies. Simon Brooks is Country Manager, Australia Inspection Services for DNV GL. In his role he is responsible for business development in Australia, Papau New Guinea and New Zealand on behalf of DNV GL. Chris can be reached at chris.oconnor@dnvgl.com.

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WESTERN AUSTRALIA

JOURN THE W Western Australia is home to a number of highly attractive unconventional oil and gas development prospects. Located across the state are various basins prospective for shale and tight gas and oil. These include the Canning Basin, estimated to contain Australia’s largest potential shale gas resource, and the Perth Basin, where WA’s first commercial unconventional gas production has occurred. Increasingly, industry players are evaluating the state’s underexplored basins and bring WA’s hydrocarbon resources to market.

WA’s unconventional hotspots While some of Western Australia’s most promising potential unconventional hydrocarbon regions remain underexplored, the state is thought to have massive resource potential. WA is considered to hold significant shale and tight gas resources in the Kimberley, East Pilbara and Midwest regions.

Estimates prepared by the Upstream Petroleum Resources Working Group for the COAG Energy Council in late 2015 put Western Australia’s overall 2P unconventional reserves at 37PJ (35.07bcf). WA’s total contingent unconventional resources are estimated at 2,358PJ, while the best estimate of the state’s prospective resources is 146,400PJ of petroleum-initially-in-place.

The WA Department of Mines and Petroleum estimates that the state potentially contains an estimated 1,380Tcf of shale and tight gas.

Currently the only unconventional play producing in the state is tight gas from the Corybas gas field in the Perth Basin.

The Canning Basin is an extremely large, lightly explored sedimentary basin in the remote north of Western Australia. The basin is considered to contain massive prospective unconventional resources including tight gas, shale gas and shale oil.

The basin’s two main areas of interest are the Goldwyer Formation and the Laurel Formation. In 2013, the EIA’s assessment of the Goldwyer Formation suggested that it has the largest shale gas potential in Australia. The EIA estimated the Goldwyer Formation to contain risked shale gas in-place of 1,227Tcf (including

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associated gas), with a risked, technically recoverable gas resource of 235Tcf. The formation was also assessed to have 244 billion barrels of risked shale oil/condensate in-place, with risked, technically recoverable shale oil/condensate resources of 9.8 billion barrels.

The Laurel Formation was not assessed by the EIA due to a lack of geological data.

Meanwhile, the Department of Mines and Petroleum of Western Australia, estimates that the entire Canning Basin potentially contains 980Tcf of shale and tight gas.

The Perth Basin is located across approximately 172,300 square kilometres in Western Australia. It is thought to contain significant tight gas and shale gas and oil resources.

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

The Government of Western Australia’s Department of Mines and

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WESTERN AUSTRALIA

EY TO EST

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Petroleum estimates that the north Perth Basin may hold 220Tcf of shale and tight gas overall and that known Perth Basin tight gas fields hold between 9-12Tcf of recoverable gas, located in the vicinity of existing pipelines (DMP, 2014).

The Perth Basin’s Corybas tight gas field is currently the only unconventional play producing in WA. The Carnarvon Basin includes 115,000 square kilometres onshore and is considered prospective for shale gas. The Department of Mines and Petroleum, Western Australia, estimates that the onshore Carnarvon Basin may hold up to 95Tcf of in-place unconventional resources.

Other WA basins considered prospective for unconventional gas resources include the onshore sections of the Bonaparte Basin (tight gas) and potentially the WA sections of the underexplored Officer Basin.

Exploring WA’s unconventional assets So far, the majority of unconventional activity in Western Australia has centred around the Perth and Canning Basins.

While the Canning Basin is considered to contain the largest resources, its dearth of data, large area and remoteness from existing infrastructure pose challenges to unconventional resource development.

As a result, the Perth Basin is currently the area where WA’s unconventional hydrocarbon development has progressed the furthest.

Companies active in the Perth Basin include AWE, Norwest Energy, Origin Energy, Empire Oil and Gas, Transerv, Alcoa, Bharat PetroResources and UIL Energy. The producing Corybas 1 exploration well is operated by AWE. A range of exploratory activities are currently occurring within the Perth Basin. For instance, AWE and Norwest Energy have been exploring prospective Triassic and Permian shale targets.

The Arrowsmith exploration project is being undertaken within exploration permit EP413, which contains prospective tight gas plays in addition to conventional targets. 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).

Meanwhile, Transerv is undertaking the Warro gas field project (through its subsidiary Latent Petroleum) with funding provided by farm-in partner Alcoa, targeting tight gas plays.

In the Canning Basin, Buru Energy holds the largest acreage.

The company is working in partnership with Mitsubishi and Rey Resources in a number of permits to explore for both conventional and unconventional hydrocarbon resources. In addition to conducting appraisal and exploration drilling, it is collecting seismic and geophysical data.

Buru Energy’s activities in the basin include the Laurel Formation tight gas exploration program, where the company states that a potentially world-scale gas and hydrocarbon liquids resource has been identified.

In the second half of 2015, Buru Energy successfully completed the first phase of its Tight Gas Stimulation (TGS) program at the Asgard 1 and Valhalla North 1 wells.

Additionally, Finder Shale Pty Ltd, in association with the Geological Survey of Western Australia, drilled a well to target wet shale gas in the Goldwyer shale in 2015.

Meanwhile, the other key Canning Basin explorer, New Standard Energy is undertaking the Southern Canning project, targeting liquids rich shale gas in the Goldwyer shale, and the Laurel project, primarily targeting tight and shale gas in the Laurel Formation.

New Standard Energy is also active within the onshore Carnarvon Basin, with its Merlinleigh Project targeting shale & tight gas formations in addition to conventional reservoirs.

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WESTERN AUSTRALIA

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WESTERN AUSTRALIA

Investing in the west The Fraser Institute’s 2015 Global Petroleum Survey rated Western Australia as the second most attractive jurisdiction for oil and gas investment in Australia, and 33rd worldwide. The survey cited favourable fiscal terms and a relatively stable regulatory environment as contributing to this result.

This comes despite the fact that Western Australia has a domestic gas reservation policy in place requiring new gas developments to supply the equivalent of 15 per cent of their gas exports to the Western Australian domestic gas market.

The State Government of Western Australia has a number of

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programs underway intended to increase the attractiveness of the state for oil and gas exploration and development.

Currently, the Perth Core Library is undergoing a $7.3 million expansion to ensure it can continue to assist exploration for mineral and petroleum resources.

In November 2015, the final report of a two-year parliamentary inquiry into fraccing suggested that Western Australia’s regulators were well prepared to manage the developing shale and tight gas industry and associated hydraulic fracturing processes.

The newly established National Energy Resources Australia (NERA), a resources industry growth centre to which the Australian

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WESTERN AUSTRALIA

With many oil and gas companies headquartered or with offices in Perth, Western Australia is an attractive spot for further exploration.

Government has committed funding of $15.4m over four years, is located in Perth. This oil, gas and energy resources growth centre is intended to promote sector competitiveness and productivity via collaboration, innovation and reduced regulatory burden.

Currently, Western Australia also sees the largest share of petroleum exploration expenditure (onshore and offshore) in Australia.

Acreage releases are generally made twice a year in the state.

A number of acreages within the Canning Basin are proposed to be released in mid-September 2016.

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A generally favourable investment environment, combined with an abundance of unconventional oil and gas resource prospects in Western Australian basins, suggest great potential for WA’s budding unconventional hydrocarbon industry. While the state’s underexplored basins still offer opportunities for the discovery of sizable new resources, more mature hydrocarbon provinces such as the Perth Basin pave the way in bringing unconventional gas to market. Western Australia is undeniably one of the country’s top unconventional hotspots to watch.

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INTERVIEW

Galilee to fire east coast markets

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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 Comet Ridge Managing Director Tor McCaul.

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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 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 was 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.

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INTERVIEW

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

“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 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

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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 was 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

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INTERVIEW

Proposed pipeline route.

may well be back to CSG. “Galilee has good solid potential in both CSG and conventional sandstone gas.”

“We think Galilee is going to play a big part in the country’s gas story” Tor McCaul, Comet Ridge Managing Director domestic and international gas markets.

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

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“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 had 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

Unexplored potential Mr McCaul said there had always been an interest in the Galilee Basin among the exploration community, but it was often perceived as further away than it actually was. “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 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 would 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.

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

“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 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.

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“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 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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LNG

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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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 ten 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

LNG

and 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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JEXIT: WHAT IF JAPA ALL ITS AUST CONTRACTS?

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N TEARS UP RALIAN LNG

by Geoffrey Cann, Director, Consulting, Deloitte.

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If Japan successfully concludes that key clauses of current LNG sales agreements are anti-competitive, what will be the impact on global gas markets?

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hoa, back up. What’s this? News sources are reporting that the mighty METI, Japan’s very powerful trade ministry, may have launched a court challenge contesting certain LNG contract clauses as anti-competitive.

Is Japan thinking about tearing up LNG purchase agreements? Can they do that?

What would this mean for the shiny new LNG export industry that Australia has in place? Weren’t these purchase and sale agreements put in place between consenting parties? What does this mean for governments counting on some royalties, on other big importers, on projects not yet launched?

The backstory Global LNG trade is based on the trinity of long duration contracts, oil indexed pricing and destination restrictions. The long contracts align banks, gas sellers and gas buyers and bind them to remove risk (financing, supply and revenue), from the endeavour. Oil indexed pricing gives gas buyers and sellers upside and downside price exposure, access to financial markets for hedging and risk management, and lots of commodity analysis expertise.

Destination clauses prevent gas buyers from turning into gas sellers and competing with their source of supply for markets.

The destination clause is a standard shipping term dating back to the very earliest days of international trading.

It means the buyer of the cargo takes possession as the cargo is offloaded from the ship to the buyer’s dockside facilities (also known as Destination Ex Ship, or DES). Up to that point the cargo is owned by the seller, who has chartered the ship, contracted the crew, financed the journey, paid the insurance, etc. The vast majority of Australia’s LNG shipping is contracted DES. In practical terms, buyers rarely reload the cargo onto a fresh ship and sell it to another party because the costs to do so are too high.

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Much of the new LNG from the US is sold Free on Board (FOB), meaning the buyer takes title as the gas is loaded onto the ship that has been chartered by the buyer. FOB gives the buyer lots more flexibility to either bring the cargo to their home market or to find an alternative market. If buyers are able to on-sell unwanted cargoes to others, it has the effect of creating price competition between LNG cargoes as they seek buyers.

It means LNG competes head on with LNG for markets or LNG on LNG pricing, even LNG that originates from the same plant. It has the potential to delink LNG pricing, somewhat, from oil-indexed pricing.

Why the Japanese challenge In the face of a shrinking population (and with it shrinking demand for energy), deregulating gas and power markets, a government keen to meet climate commitments and restart the nuclear fleet, Japan’s gas buyers find themselves long on LNG – they have over-purchased.

To solve this little dilemma, they could build regasification facilities at all of their gas import terminals. But there are dozens of such plants, there isn’t enough time to carry out the refurb, and who would pay for the retrofits, particularly at a time of market deregulation?

It might seem odd, but the easier path is to challenge the contracts and have them overturned. There is precedent – the EU carried out a similar exercise against Russian pipeline gas that was also contracted in the trinity model (there were other elements of the puzzle, namely the Russians also owned the pipelines and made it difficult for alternative gas to use those pipelines to access European buyers). They simply declared parts of the Russian contracts anti-competitive and that was that.

In May, I identified the possibility of this development based on the discussions at an LNG trading conference sponsored by my firm in Tokyo. I called it the nuclear option, because the consequences of breaking the trinity in this way are pretty profound.

One telling observation was from the European utilities at the conference.

Europeans have some experience with driving gas seller behaviour and it was to simply outlaw destination clauses as anti-competitive. Perhaps Japan will give the market a bit of time to work it out, while keeping this nuclear option at the ready.

The consequences As I’ve already alluded, the consequences of this action, if successful, are truly seismic: ♦♦ Spot markets grow – freeing up LNG to supply any available market (i.e. to behave more like oil) gives a big boost to the emergence of spot (for immediate delivery) and short markets (delivery in a few weeks). Some risk-averse buyers will still want their long contracts, but spot volumes will certainly rise above the 20 per cent today. ♦♦ Demand boosted – many smaller markets that might like to purchase LNG are presently unable because they cannot aggregate enough demand, either in burner tip numbers or seasonal intensity, to match the scale needs for financing or for supply. A bigger, deeper and more liquid spot market takes supply risk away and can help them enter the market without having to meet the upfront commitment demanded by the trinity. ♦♦ Hubs in demand – lively spot markets working in tandem with sophisticated financial markets can help take risk out of the dependency on a steady supply of a commodity without the backstop of a long contract. Forward contracts, swaps and futures become critical tools to succeed, as well as pricing curves, price discovery and market information. Singapore, Tokyo and Shanghai are all vying to set up this infrastructure. ♦♦ FERC defanged – the Federal Energy Regulatory Commission recently blocked a US LNG project from proceeding because the project

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♦♦

♦♦

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developer could not demonstrate there was a market for the LNG (i.e. a customer). If there’s a big, deep and liquid LNG spot market, the FERC argument no longer holds.

This should unlock fresh supply of FOB gas from the proposed US tolling plants.

Pricing basis – if DES clauses are found to be anti-competitive, and FOB becomes contractually dominant, buyers and sellers may need to find a new pricing basis. Today, spot prices are below contract prices based on the oil index formula, and FOB promised to drive all pricing downwards. This won’t work in all cases with gas sellers who have banking obligations to fulfil.

Over time, we might see a progressive adoption of more flexible contractual mechanisms that can benefit both parties, e.g.. profit sharing provisions between buyers and sellers that mitigate the impact of cargo diversions. Buyers and sellers may not have a lot of time to figure this out given low commodity prices and overall industry health.

Pricing falls – when gas meets gas in a market, its price moves up and down as buyers and sellers find the market clearing price. Sometimes the price will go up as buyers compete to access scarce supplies, but in the present oversupplied market, the opposite is the likely outcome.

LNG prices should come under more downward pressure. The gap between spot LNG price and contract price should close, and at the spot level.

More court challenges – if this move is successful in Japan, why wouldn’t Korea, China and Taiwan all follow

♦♦

♦♦

♦♦

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suit and launch their own court challenges, and trigger the death of DES? It would be foolish to ignore the possibility other buyers are not also considering their own challenges.

Greenfield projects slowed – the Canadian greenfield projects and next generation Australian brownfield projects that were based on the trinity are certainly going to slow down while the gas sellers and banks reprocess this development. This will cause area prioritisation of the attractiveness of proposed projects, giving the edge to economically viable FOB projects.

This is a double-edged sword – these greenfield projects help augment and diversify supply which brings its own advantages.

Trading skills in demand – navigating a much bigger and more liquid LNG market will require a step up in trading capabilities. Even without the success of a court challenge, the volume of trading activity was sure to grow just because of the US FOB volumes. The pressure now will be even higher given the size of the Asian market.

Cash flow pressures – Australia’s LNG projects, which are all based on the trinity, will come under more margin pressure if the bulk of their trade is declared anti-competitive.

Cash flow from operations will be further constrained, which will impact available exploration capital, dividends, debt repayments. Even those players that have managed to survive the plunge in the oil market might not be able to handle further decreases in LNG prices, especially those that are still fully exposed. It’s not inconceivable that the pressure will prove too great on the industry’s weaker players, and those more

leveraged will need to raise fresh capital or consider more strategic alternatives such as asset sales or merger with others.

Indeed, why wouldn’t one of the robust players in the industry quickly agree to dismantle DES, which might cause the weaker players to crack under the pressure? ♦♦ Royalty pressures – some governments of gas producing precincts have been counting on getting their share of the rich margins produced by the trinity. The royalty bounty will simply vanish as the market competes away the super profits that this industry generated in its golden age from 2010 to 2014.

It would be logical competition law would need to be consulted in this instance. It surely cannot be the first time a willing contracting party has remorse over the terms of their contracts. METI may not be successful in its endeavour.

That said, players in the market should not fear this development. In the short-term it seems to threaten LNG sellers and producers and benefit buyers, but it’s actually a healthy step towards a more liquid and transparent market, and one taken by the oil industry in the 1980s and more recently by the coal industry. Sure, gas is different (it deteriorates with time, there’s no gas standard spec, shipping is four times more expensive than with oil), but that should not block progress.

My friend and colleague Giulia Gervasoni, a specialist in energy markets, contributed her time and insight to this article.

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OPINION

FROM CLIMATE PARIAH TO

CLIMATE SAVIOUR:

WHAT THE PETROLEUM INDUSTRY CAN DO ABOUT

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OPINION

by Andrew Hopkins, Emeritus Professor, Australian National University Natural gas has a clear role to play as part of the transition to cleaner forms of energy. Here, Andrew Hopkins outlines several things that the petroleum industry can do to help combat global warming – while protecting its own economic interests.

Andrew Hopkins believes the gas industry can provide a solution to methane released from melting polar ice caps.

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OPINION

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nvironmentalists argue that the petroleum industry is contributing to global warming.

The gas industry, on the other hand, sees itself as part of the solution. Its reasoning is as follows. Gas fired power stations produce far less greenhouse gas than coal fired generators. So if gas can replace coal, at least in the short term, this is a win for the industry, and for the environment.

It is worth thinking more systematically about win/win strategies, that is, things that the petroleum industry can do, in its own economic interests, that will help to combat global warming. I list four below.

1. Benefit from a price on carbon.

First, the renewable energy industry is expanding at an ever increasing rate and will eventually replace not only coal but also gas. But there is a window of opportunity for gas. Ironically, the best way to take advantage of this window is to place a price on carbon. This will fall more heavily on coal than on gas, initiating or accelerating the transition to gas. All official pronouncements from the petroleum industry now support a price on carbon, but the industry is not lobbying for it. It should be. When the Abbott government was preparing to abolish the carbon tax

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in 2013, this was an ideal opportunity to argue for the retention of the tax, but with full exemption for the trade exposed sector, in particular, the LNG industry. The industry did not avail itself of this opportunity.

Lobbying for a price on carbon involves a parting of the ways with coal. The petroleum industry has traditionally sought to present its interests as complementary to those of coal. They are not. They are in conflict. It will take political courage on the part of the petroleum industry to lobby for a price on carbon with the intention of taking market share from coal.

2. Develop technologies and systems to minimise methane leaks.

Second, the argument that gas is more environmentally friendly than coal depends on minimising methane leaks.

Methane is much worse than carbon dioxide as a greenhouse gas, and a relatively small amount of leakage can cancel the advantage gas has over coal for electricity generation. There are many potential emission sources. Leakage at the point of production, especially where fraccing is involved, is receiving increased scrutiny. But all along the supply chain – processing, transmission, distribution and storage – there are leaks. A recent blowout from an underground storage facility on

the outskirts of Los Angeles led to the release of 100,000 tonnes of methane over several months. This was a substantial economic loss to the company. In addition, the blowout severely embarrassed the governor of California who had made the reduction of methane emissions one of his signature issues. He responded by imposing a requirement on the storage facility operator that it put in place a methane abatement program (tree planting, etc) that would compensate for the release.

This is an expense that companies can be expected to incur in future in such circumstances. But more importantly, the blowout challenged the social license of the operator and indeed the industry.

This is one of the obvious points at which the interests of the gas industry and environment coincide.

3. Further develop methane capture technologies.

Stopping climate change is not just a matter of reducing human emissions, even to zero. The problem is that there are natural amplifiers or accelerators at work, which mean that the degree of warming the world has already experienced may already have triggered runaway change – unless of course we can find a way to interrupt those natural amplifiers. In actual

OPINION fact, the petroleum industry is particularly well placed to do this. Indeed, it has the potential to make a major contribution to saving the planet as we know it.

Hence the third win/win strategy. One of the consequences of climate change is the melting of the Arctic permafrost. There are massive amounts of methane stored in the permafrost, which are escaping into the atmosphere in ever increasing quantities. Even if emissions directly generated by humans are reduced to zero, the release of methane from the Arctic will probably accelerate. The gas industry has shown itself adept at harvesting widely distributed sources of methane. This raises the possibility of capturing methane releases from the Arctic, particular from the floor of the Arctic Sea, which is releasing streams of methane which bubble to the surface. These releases could either be flared, converting the methane to carbon dioxide and thereby greatly reducing its greenhouse effect, or better still, transported to market.

Capturing methane releases may not be commercially viable. It may therefore be necessary for governments to pay companies to harvest Arctic methane releases, based on a “reverse” carbon price – price paid per tonne of carbon captured. The industry could take the lead

in determining a price on carbon that would make this worthwhile and begin lobbying governments to fund such a project.

4. Look at ways to extract carbon from the atmosphere.

Fourth, even if we were able to reduce human and non-human emissions to zero, this may still not be enough to prevent dangerous global warming because of the concentrations of greenhouse gases already in the atmosphere. We must go further and find ways of extracting carbon from the atmosphere.

Again, this is where the petroleum industry is uniquely placed to contribute.

One of the most promising ways of “drawing down” carbon is by cultivating algae, such as seaweed. The petroleum industry is already experimenting with algae as a second generation biofuel.

However, biofuels are likely to end up back in the atmosphere as carbon dioxide. From a climate point of view this is one step forwards and one step back.

What is needed is a method of converting algae into a stable form of carbon for long term storage. One such method is pyrolysis, which converts biomass, such as algae, into char, a relatively pure form of carbon that is valued by farmers as a soil additive. The petroleum

industry is already funding research on pyrolysis. If the pyrolysis of algae can be perfected, this promises to be an effective way of drawing carbon out of the atmosphere.

Again, this might not be commercially viable and governments may need to pay a price for carbon sequestered in this way.

But again, the industry could take the lead in determining what that price might be, and lobbying for it.

So there are indeed win/win options for the petroleum industry and the environment. Adopting them would transform the industry from a climate pariah, as environmentalists tend to see it, to a climate saviour.

Andrew Hopkins is an internationally-renowned presenter, author and consultant in the field of industrial safety and accident analysis.

Andrew’s ideas as outlined in this article are developed further in a paper available at www.tai.org.au

A price on carbon would fall more heavily on coal than on gas, accelerating the transition to gas.

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FEATURE BASIN PROFILE NAME

UNCONVENTIONAL OIL AND GAS PARTNER CONTENT

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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FEATURE NAME BASIN PROFILE

UNCONVENTIONAL OIL AND GAS PARTNER CONTENT

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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EVENTS

POLICY ON THE AGENDA AT APPEA 2016

APPEA 2016 drew more than 2,000 registered attendees from 26 countries and 865 organisations – a strong result in a difficult time for the industry, especially as it was held only two months after LNG18.

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he event was held at the Brisbane Convention and Exhibition Centre. Its agenda was largely defined by sustained low oil prices and the 2015 Paris Climate Change Summit. Plenary and concurrent sessions examined industry challenges; major policy issues; and the enormous opportunities for energy security, regional development and economic growth that the oil and gas industry offers Australia.

About 40 journalists and other media personnel, representing 28 Australian and international outlets, covered the event.

Several stories made the front pages of major newspapers.

APPEA 2016 featured 19 plenary speakers across five sessions. Plenary speakers included: ♦♦ Federal Minister for Resources, Energy and Northern Australia, The Hon Josh Frydenberg MP ♦♦ Queensland Minister for State Development and Minister for Natural Resources and Mines, The Hon Dr Anthony Lynham MP ♦♦ Shell Australia Country Chair Andrew Smith ♦♦ Oxford University Professor of Environmental Economics Cameron Hepburn

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♦♦

Origin Energy Managing Director Grant King ♦♦ Woodside Managing Director Peter Coleman ♦♦ Rice University and University of Western Australia Professor of Economics Peter Hartley ♦♦ MIT Energy Initiative Director of Research Dr Francis O’Sullivan ♦♦ Clough CEO Peter Bennett ♦♦ Oil Search Managing Director Peter Botten ♦♦ INPEX President Director Australia Seiya Ito ♦♦ GasFields Commission of Queensland Chairman John Cotter.

The technical program was one of the largest at an APPEA event. There were 86 presentations spread across 24 sessions.

These specialist analyses, technical information and case studies covered a wide range of issues, including: ♦♦ Implications of the 2015 UN Climate Summit ♦♦ Technology and innovation ♦♦ Coal seam and shale gas science, technology and operations ♦♦ Liquefied natural gas operations and markets ♦♦ Project development ♦♦ Energy policy ♦♦ Updates from regulators

♦♦ ♦♦

Diversity Community and stakeholder engagement ♦♦ Tax, financial and commercial issues and management ♦♦ Prospectivity of frontier basins ♦♦ Scientific and technological reports ♦♦ Workforce management, including building diversity ♦♦ Tax, commercial and financial management ♦♦ Skills, environmental, safety and operational issues.

The concurrents also included the Commonwealth Government’s annual release session of exploration and the Petroleum Exploration Society of Australia’s annual review of the previous year’s exploration and production figures and highlights.

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EVENTS

APPEA 2017

The 2017 APPEA Conference and Exhibition will be held in Perth, Western Australia from 14-17 May 2017. The Call for Papers is now open and closes on 19 September 2016. For more information see www.appeaconference.com.au

The Exhibition Hall – industry showcase and networking hub The Exhibition Hall covered more than 10,000 square metres and hosted 165 organisations.

It also included spacious networking lounges, full catering facilities, charge zones and a technology and app concierge service. With numerous stands competing to offer quality coffee and happy hour events at the end of each afternoon, the exhibition area offered plenty of opportunities for delegates to exchange news and ideas with industry colleagues and to simply catch up with old friends.

The welcome reception, conference dinner and farewell cocktails provided further platforms for business networking and for delegates to let their hair down.

Delegate feedback Feedback forms from the event showed that: ♦♦ 93 per cent of delegates said they made new business contacts at APPEA 2016 ♦♦ 74 per cent said the APPEA Conference & Exhibition is a key event in their company’s strategic planning for the year ♦♦ 94 per cent said the quality of presentations was “good” or “excellent” ♦♦ 70 per cent said the APPEA Conference was among the top three most valuable of all the conferences they attend.

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