Unconventional Oil & Gas. Spring 2015 Digital Edition by Monkey Media

UNCONVENTIONAL Issue 2 // SPRING 2015

CAN RICHARD COTTEE WORK HIS MAGIC IN THE TERRITORY?

DIGGING DEEPER: BASIN-BY-BASIN ANALYSIS

CAN CSG OUTPACE CONVENTIONAL IN SUPPLYING LNG?

LOGISTICS A-Z: GETTING THE FUNDAMENTALS RIGHT OPINION CRAIG RICATO EYES A SHALE OIL BONANZA

ANALYSIS GEOFFREY CANN ON SHIFTING GEOPOLITICAL SANDS

PAUL CARTER ON THE GREAT DEPRESSION OF 2015

NAVIGATING THE GOVERNANCE MAZE

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UNCONVENTIONAL

OIL GAS UNCONVENTIONAL

WELCOME

Issue 2 // SPRING 2015

UNCONVENTIONAL OIL & GAS

CAN RICHARD COTTEE WORK HIS MAGIC IN THE TERRITORY?

DIGGING DEEPER: BASIN-BY-BASIN ANALYSIS

CAN CSG OUTPACE CONVENTIONAL IN SUPPLYING LNG?

SPRING 2015

LOGISTICS A-Z: GETTING THE FUNDAMENTALS RIGHT OPINION CRAIG RICATO EYES A SHALE OIL BONANZA

ANALYSIS GEOFFREY CANN ON SHIFTING GEOPOLITICAL SANDS

PAUL CARTER ON THE GREAT DEPRESSION OF 2015

NAVIGATING THE GOVERNANCE MAZE

Cover image shows employees at Santos’ GLNG processing facility, highlighting our logistics feature.

Published by

Monkey Media Enterprises ABN: 36 426 734 954 PO Box 3121 Ivanhoe North VIC 3079 P: (03) 9440 5721 F: (03) 8456 6720 monkeymedia.com.au info@monkeymedia.com.au unconventionaloilandgas.com.au info@unconventionaloilandgas. com.au ISSN: 2204-8901

UNCONVENTIONAL

OIL GAS

Publisher and Editor Chris Bland Managing Editor Laura Harvey Associate Editor Michelle Goldsmith Journalist Emily Thomas Marketing Director Amanda Kennedy Marketing Consultant Aaron White Marketing Consultant Jordan Harbinson Creative Director Sandy Noke Graphic Designer Alejandro Molano

SPRING 2015 // ISSUE 2

FROM THE PUBLISHER

recently attended the excellent Developing Unconventional Gas event in Brisbane, organised by Hart Energy. It was great to speak to so many of our readers and to hear the latest developments from some of the biggest industry players. While it’s clearly a quiet time for the industry – you don’t need to be a financial genius to see the effect the oil price has had – anyone who’s been in the industry for more than one cycle knows that what goes down will come up again. What is more interesting is the certainty and confidence about the long-term viability of the industry. The industry has taken a ‘back-to-basics’ approach in the interim, with a focus on cost cutting, continuing technological advances and highlighting the ‘sweet spots’ to move towards when operating costs are down. One question that remains is how long the current paradigm will last. We are currently in an environment where we have a considerable oversupply of oil from the Middle East, a move from OPEC that came in response to the threat of shale in the US. And that’s why this short-term negative is actually a positive in the long run. Unconventional oil and gas resources are revolutionary, they are disruptive, and to the traditional global superpowers in the oil and gas game, they are certainly a huge threat. The other challenge we as an industry face is the increased disconnect people have between their own energy consumption and the way it can be reliably and economically generated. Urban populations are becoming increasingly removed from the realities of the oil and gas industry. The misconception that renewables can meet all our energy needs is more common than many realise, and there is a lack of understanding about the common domestic and industrial applications that do require gas. We interviewed Richard Cottee for this issue, and you can read his thoughts on this disconnect from page 14. Richard shares his thoughts on how we as an industry can regain the ‘social license’ we need from the community in order to do our jobs effectively. In recent years this has been a real challenge for this industry, with companies in New South Wales and Victoria feeling the effects. The simple reality is that these states cannot

continue to expect increased standards of living dependent on increasing energy consumption. The first step for the industry is to focus on regaining its social license by ensuring that ordinary people, who are neither anti-growth activists, nor involved in the petroleum industry, realise the important role energy resources play in their lives. At the moment we know we are needed – but we also need to be wanted by the community in order to do our jobs properly. We are delighted to welcome our new regular columnist, Paul Carter, the author of the wildly successful Don’t tell mum I work on the rigs: she thinks I’m a piano player in a whorehouse. Paul’s musings on life in the oil and gas game have been read all over the world, and we’re thrilled that he’ll now be sharing his thoughts in each issue of this magazine. In this issue, he focuses on the challenging market conditions we’re all currently facing – and as always, he has a humorous take on how things are playing out. Like Paul, we believe that the current downturn is a short rather than long-term thing. Most importantly, we believe that unconventionals will play a major role in the future of energy, internationally and domestically. We are here for the long haul, strapped in and ready to ride the rollercoaster that is the oil and gas industry. Chris Bland Publisher and Editor

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CONTENTS PROFILE

Can Richard Cottee work his magic in the Territory?...............................14

Richard Cottee is a man who has had no shortage of column inches dedicated to his name, almost as well known for his larger-than-life personality as he is for his role in shaping the industry as we know it today. After building the CSG-LNG industry in Queensland, Cottee has turned his attention to the Northern Territory. He wants to bring gas from Central Australia to the eastern seaboard, which currently seems disinterested in meeting demand through its own reserves. Like in Queensland, can Cottee work his magic in the Territory?

RESERVES UPDATE

Digging Deeper: where’s the oil and gas?................................................22

Australia has an array of different geological basins, most of which have some potential for unconventional oil and gas exploration. As companies move to enhance their understanding of the resources in place, we take a closer look at some of Australia’s key basins, where production, assessment and/or exploration are underway to develop coal seam gas, shale and tight resources.

INTERVIEW

Arckaringa unearthed: Craig Ricato eyes up a shale oil bonanza.......30

When Linc Energy launched a prospective drilling program in South Australia’s Arckaringa Basin in the second half of 2014, even they didn’t realise quite how promising the acreage they were sitting on could be. In July, the company revealed the laboratory results from the program and has flagged a shale oil discovery that could kick off the production of this resource in the state. We met with CEO and Managing Director Craig Ricato to learn about his plans for Australia’s shale oil revolution.

ANALYSIS

Shifting geopolitical sands: tips for staying ahead in the global energy game...................................36

We like to think that Australia and its rapidly growing gas industry are immune to the great energy-driven geopolitical issues of the day – but as the market for Australian energy becomes increasingly global, Geoffrey Cann argues we need to expand our view of the role international politics have to play in our domestic and export markets. CSG outpacing conventional in the race to LNG supply........................40

SPRING 2015 // ISSUE 2

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LOGISTICS

Seven years in the making: the logistics of bringing Australia Pacific LNG online..............................44

As the first LNG shipment from the Australia Pacific LNG Project draws nearer, we take a closer look at the development of coal seam gas (CSG) to liquefied natural gas (LNG) in Queensland, and retrace the steps taken towards commercial delivery.

Rules and regulation: navigating the governance maze...................... 50 Innovation instrumental to industry development................................. 56

POLICY

Supply and demand plan in place..............................................................58

As the Queensland gas industry makes the shift from exploration to production and export, the State Government has moved to put plans in place to effectively manage domestic and global supply and demand moving forward.

TECHNICAL

Fraccing 2.0...........................................................................60

Regular contributor Ray Johnson reports on the 2015 Unconventional Resources Technology Conference (URTeC) in San Antonio, Texas, where there was a strong focus on optimising the hydraulic fracturing process.

SPOTLIGHT ON

Surat Basin............................................................................ 63 Developing a strategic resource ��66

REGULARS Publisher’s welcome �� 2 Contributors �� 6 News �� 8 The Good Oil �� 70 Advertisers’ index �� 72 WWW.UNCONVENTIONALOILANDGAS.COM.AU

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CONTRIBUTORS

Richard Cottee

Craig Ricato

Geoffrey Cann

Central Petroleum CEO and Managing Director

Linc Energy CEO and Managing Director

Deloitte Consulting National Director for Oil and Gas

Richard Cottee is the CEO and Managing Director of Central Petroleum, but he’s perhaps best known for his involvement in getting Queensland’s CSG to LNG industry up and running. During his time as Managing Director of QGC, Mr Cottee championed the use of Queensland’s ample coal seam gas reserves to meet domestic and export supply markets. When the idea took off, in the form of the QCLNG project, QGC was purchased by BG Group for close to $5billion; and Origin and Santos quickly moved to commercialise their Queensland CSG resources in a similar manner. Now Mr Cottee has turned his hand to making junior explorer Central Petroleum a major supplier in the east coast gas market. We spoke to him to find out if he can weave his magic in the Territory too.

Linc Energy CEO and Managing Director Craig Ricato has been with the company since 2008, which makes the company’s recent discovery of a massive shale oil reserve in South Australia’s Arckaringa Basin all the sweeter. Mr Ricato brings a broad range of international corporate and commercial experience to Linc Energy across the energy and resources industry. In this issue, he tells us about his company’s plans to commercialise this unique asset, and discusses the benefits of operating in South Australia.

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.

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Ray Johnson

Ian Davies

Paul Carter

Unconventional Reservoir Solutions Principal

Senex Managing Director

SGS Australia Sales and Marketing Manager Upstream

Dr Ray Johnson Jr has been involved with design, execution and evaluation of reservoir stimulation treatments for unconventional projects since 1980, with recent experience and innovations relating to pre-drainage of fluids (i.e. gas and water) for coal mining. Since arriving in Australia in 1998, he has been involved in either senior engineering or management roles in the evaluation, appraisal and development of some of the most successful unconventional projects in Australia spanning several basins. Dr Johnson is an Adjunct Associate Professor at the Australian School of Petroleum, University of Adelaide, and an Adjunct Fellow at the University of Queensland. Dr Johnson’s article in this edition looks at the work he is currently undertaking to help optimise production rates at unconventional wells around Australia.

Ian Davies has been the Managing Director of Senex since June 2010. He has a proven track record in delivering rapid business growth and a deep knowledge of commercial imperatives underpinning successful companies. Mr Davies joined Senex from QGC, where he had been a key member of the senior management team since joining as Chief Financial Officer in 2007. Previously Mr Davies was an investment banker in Melbourne with Austock Corporate Finance and in London with Barclays Capital. He commenced his career in the Energy and Mining Division of PricewaterhouseCoopers in Brisbane. In October 2013, Mr Davies was named Business Person of the Year at the Brisbane Lord Mayor’s Business Awards.

Paul Carter has written three international bestselling books, including the famous (or should that be infamous?) Don’t tell mum I work on the rigs: she thinks I’m a piano player in a whorehouse. Paul has sold over two million books worldwide and his first two books are currently being turned into a feature film. Mr Carter grew up in Aberdeen, Scotland’s oil capital, and moved to Perth at the age of 15. By the time he was 16, he was working on drilling tools. Mr Carter has clocked up 20 years of experience out in the field, working in Australia and far-flung destinations around the world, avoiding coups, jihadists and wars – all in the name of blessed hydrocarbons. Currently he’s the Sales and Marketing Manager Upstream for SGS Australia, based in Perth.

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NEWS

FACE THE CHALLENGES

HEAD-ON

ustralia and other countries need sensible policies to address the opportunities and challenges presented by unconventional gas. The Australian Academy of Technological Sciences and Engineering (ATSE) is holding a two-day conference in Sydney in September to address the complex issues related to this growing industry ATSE believes that unconventional gas, especially shale and coal seam gas, is an issue of profound national and international importance, with the potential to impact on our future prosperity and environment. Exploration and production in many regions has produced new income for some landowners, but led to opposition from others. Being staged from September 22-23, the academy’s interdisciplinary conference will involve scientists, engineers, social scientists, economists and community representatives, recognising that many of the issues surrounding unconventional gas are community issues that need to be informed by science. Topics to be covered during the event include international perspectives

SPRING 2015 // ISSUE 2

on the industry, water management considerations, the economics of unconventional gas, fraccing, induced seismicity and well integrity, community issues and experiences, carbon/climate and energy impacts, land use and biodiversity, regulation and governance, state and territory reviews and more. The event has attracted an impressive line-up of local and international speakers. International speakers include Dr Francis O’Sullivan, Director of Research & Analysis at the Massachusetts Institute of Technology – Energy Initiative; Professor Rick Chalaturnyk, Foundation CMG Research Chair in Reservoir Geomechanics for Unconventional Resources at the University of Alberta, Canada; and Professor Mark Zoback, Professor in Earth Sciences and Senior Fellow, Precourt Institute for Energy at Stanford University. The event is being chaired by Professor Peter Cook from the Peter Cook Centre for CCS Research. Local speakers at the event include Dr James Johnson, Chief of Division & Deputy CEO at Geoscience Australia; Dr Brian Fisher, Managing Director of BAEconomics; Tony Wood, Energy Program Director at the Grattan

Institute; Professor Mike Sandiford, Director of the Melbourne Energy Institute, and Rick Wilkinson, Chief Technical Officer at APPEA. Following the conference a one-day workshop, comprising international Academies of Engineering and Science, will develop a set of findings for future policy development on unconventional gas. The workshop will draw on national reports prepared by international academies, informed by discussions at the conference. Whether you’re a scientist, engineer, social scientist, policy expert, community, government or NGO representative, industry player or academic contributor, ATSE’s line-up of speakers will inform and challenge the way that you think about the opportunities unconventional gas presents. For more information and to register, visit www.atse.org.au.

ATSE: Unconventional Gas 22-23 September 2015 Sofitel Wentworth, Sydney www.atse.org.au

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NEWS

HARVARD: A WIN-WIN OPPORTUNITY

report authored by the Harvard Business School and Boston Consulting Group has highlighted the opportunities that unconventional oil and gas reserves can offer the economy. The report, Americaâ&#x20AC;&#x2122;s unconventional energy opportunity, discusses some of the benefits that would come with developing the unconventional oil and gas industry in the US â&#x20AC;&#x201C; many of which also apply to the unconventional industry Down Under. According to the report, the new abundance of unconventional energy sources cannot only help restore US competitiveness, but can also create geopolitical advantages for the country. These benefits can be achieved while substantially mitigating local environmental impact and speeding up the transition to a cleaner-energy future that is both practical and affordable. However, not unlike Australia, America is currently caught in an unproductive, divisive, and often misinformed debate about its energy strategy, which threatens economic and environmental goals. The paper argues that there is an urgent need for the US to get on a new path. An overall strategy must be set forth for unconventional energy development that meets the most important goals of industry, environmental stakeholders and governments, and allows the US to responsibly achieve the full benefits of this unique and vital opportunity.

FALCON SPUDS IN THE BEETALOO

alcon Oil & Gas has spudded the Kalala S-1 well in the Beetaloo Basin, its first well in a three-well drilling and evaluation program in the Beetaloo for 2015. The program is part of a nine-well exploration and appraisal program planned from 2015 to 2018. Kalala S-1 is targeting the Middle Velkerri formation to assess hydrocarbon saturation and reservoir quality. Kalala S-1 is located within exploration permit 98, with access from the existing Carpentaria Highway, and will be drilled to a total depth of approximately 2,800 metres. Rig 185, an ATS 400, has been commissioned from Saxon Energy Services Australia, a Schlumberger company. Falcon holds a 30 per cent interest in Exploration Permits EP 98, 117 and 76, covering approximately 4.6 million gross acres in the Beetaloo Basin. The Beetaloo Basin is a Proterozoic and Cambrian age tight oil and gas basin that is well suited for unconventional oil and gas projects. Connected to the major industrial and export markets in Darwin 600km to the north, Falcon is well positioned in the Northern Territory to achieve commercial production. Existing infrastructure includes a major highway, two gas pipelines and a railway. Since acquiring the licences in 2008, Falcon Australia has conducted an extensive study of the eleven wells that were drilled by an oil and gas subsidiary of Rio Tinto between 1988 and 1992.

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Oil and gas bleeds from 6,700 metres of core and other well data confirm all necessary elements of productive shale oil and shale gas play exist in multiple independent petroleum systems. Each of these intervals is prospective for oil or gas, providing Falcon with an extensive inventory of drilling opportunities.

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NEWS

EAST COAST GAS REVIEW ENTERS NEXT STAGE

he Australian Energy Market Commission has released the Stage 1 report for its East Coast Wholesale Gas Market and Pipeline Frameworks review and outlined priorities and timelines for Stage 2. Stage 1 recommends a package of immediate actions for consideration by the COAG Energy Council which would make it easier to buy and sell gas. More recommendations for the efficient long-term development of gas markets will be developed throughout Stage 2, with draft recommendations due to be provided to the Energy Council by the end of 2015. AEMC Chairman, John Pierce, said the AEMC east coast gas review was focused on how to get gas to consumers in the most efficient way once it leaves the ground. “Getting gas to well-functioning markets is fundamental to consumers being able to know whether the gas price reflects underlying demand and supply conditions,” Mr Pierce said. “Significant investment in pipelines over the past 15 years means the east coast market is now interconnected, but as export markets open up and unconventional gas resources come online, we need gas to flow easily to where it is most needed. The Stage 1 Final Report, presented to COAG Energy Council Ministers today, includes recommendations to improve price transparency with a new gas price index to show price trends over time starting in 2016. The report also includes recommendations to reduce market complexity by highlighting the need for the same start time for gas trading in all markets. Other recommendations include the ability for rule change requests relating to the Victorian gas market to be submitted by any stakeholder, aligning Victorian requirements with the rest of the east coast markets; and the possible expansion of information required to be published on the Natural Gas Services Bulletin

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Board. This last recommendation is being implemented through the Enhanced Information for Gas Pipeline Capacity Trading rule change currently underway. Mr Pierce said Stage 2 of the review will develop further options to promote long-term gas market development, including: ♦♦ The design of wholesale markets with consideration of options for physical and virtual trading hubs and changes to the short-term trading market and gas supply hub models. ♦♦ Measures to facilitate efficient investment in, and usage of, pipelines including measures to enable secondary trading of contracted but unutilised pipeline capacity. ♦♦ Establishing a one-stop shop for gas market data to improve transparency, lower the costs associated with pipeline capacity trading and improve the operation and monitoring of the market. Extensive consultation is planned to develop these options over the next six months. The AEMC is also reviewing the Victorian Declared Wholesale Gas Market to identify whether reforms are required to enhance the liquidity, transparency and flexibility of the Victorian wholesale gas market in light of the structural changes across the entire east coast. “As Australia’s first gas market, with relatively high levels of retail competition and a highly meshed transmission network, there are material differences between the Victorian system and other jurisdictions,” Mr Pierce said. This review will continue throughout 2015 to consider whether objectives for the Victorian market should change in light of the broader east coast environment, including its potential role in providing an efficient reference price; and the capacity for interregional trade. Consultation on Stage 2 and the review of the Victorian Declared Wholesale Gas Market will be held in the months ahead.

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NEWS

BEACH EYES ASX TOP 50 Beach Energy has completed a strategic review, setting its sights on becoming a top 50 ASX company. The company has developed a three-pronged approach to delivering this aim: ♦♦ Leverage its competitive advantage in the Cooper Basin ♦♦ Become a major supplier to the east coast gas market ♦♦ Execute growth opportunities beyond the Cooper Basin to become a multi-basin producer. In addition, the company has decided to sell off and farm down its overseas interests, in order to focus on market opportunities closer to home. In June the company made its exit from Romanian interests, and the company has entered into an agreement for the sale of its Egyptian assets and is also in the early stages of farming down its Tanzanian permit. Speaking of the opportunities in the east coast gas market, Chief Executive Officer Rob Cole said “We see the increasing demand for gas from the east coast market as a unique opportunity to really build on Beach’s position as a leading supplier to this market. This will involve not only commercialising existing assets within our portfolio, but also building a portfolio of assets in east coast basins that support this endeavour. “Our aim is to be Australia’s premier multi-basin upstream oil and gas company,” he added. “In my mind, Beach has already achieved premier status with its operated oil business on the Western Flank of the Cooper Basin, where we produce oil at an extremely low cost of $25- $30 per barrel. “We now need to harness this expertise as we look to expand into new basins. Production of hydrocarbons from basins beyond the Cooper Basin will further strengthen our position as Australia’s largest onshore oil producer and a leading supplier of gas to east coast markets. “Over the next 10 years, I would like to see a stepchange in our annual production, and similar growth in 2P reserves. Should we achieve this, we will be on the path to becoming a top 50 ASX company.” Beach will also continue to focus on longerterm assets, such as the Nappamerri Trough Natural Gas project (NTNG). The company is continuing the search for a joint venture partner for the project, after Chevron pulled out of the project in March. In addition, the company also has plans to commence a pilot work program for deep coals in the south of the Cooper Basin. Beach’s share price dipped in the immediate aftermath of the strategic overhaul. Analysts responded to the review by predicting that mergers and acquisitions will have a significant role to play in Beach executing its strategic aims.

SPRING 2015 // ISSUE 2

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NEWS

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ew data received by Santos’ Narrabri Gas Project shows the possibility for the project to cut costs, with the number of wells needed to produce gas for NSW able to be reduced. Santos General Manager of Energy NSW, Peter Mitchley, said that new appraisal data has delivered positive results that could significantly enhance the economics of the proposed Santos Narrabri Gas Project. “We know there is an abundance of gas and the local geology is favourable,” Mr Mitchley said. “As we continue to work the field and continue to study the reservoir engineering, we are anticipating that the well count, in other words the number of wells we have to drill to extract the natural gas, could reduce by about 20 per cent.” Santos is currently finalising the Environmental Impact Statement for the proposed Narrabri Gas Project that could supply up to 50 per cent of NSW gas needs. Through the project Santos will directly employ more than 1,200 people during construction and 200 people on an ongoing basis. Mr Mitchley also said that as Santos seeks to develop the Narrabri Gas Project, protection of water is a key priority. “If you are a local resident and your livelihood depends on farming, water is your lifeblood. So extracting natural gas needs to be done in a way that doesn’t threaten that water,” he said. Santos has developed a regional groundwater model to assess the impacts on groundwater from CSG activities in the Gunnedah Basin. The model was peer reviewed by CSIRO, who concluded, “The regional groundwater MODFLOW model for the Gunnedah Basin can be considered state of the art, and is suited to assess potential impacts of water extraction for coal seam gas depressurisation on the surface water and groundwater resources in the Gunnedah Basin district.” “What the CSIRO conclusion confirms is that our groundwater model can accurately predict surface and groundwater impacts from coal seam gas activities in the Gunnedah Basin. This is a significant step forward,” Mr Mitchley said. This finding builds on a range of existing studies that have concluded that coal seam gas would not impact water uses. The independent $4.5 million Namoi Catchment Water Study, for example, found CSG developments far larger than Santos’ proposed Narrabri Gas Project, would have an insignificant impact on water sources across the catchment. Mr Mitchley said Santos Narrabri operations are backed up with an extensive groundwater monitoring network that provides real time monitoring of groundwater across the project area. “Ongoing monitoring is the tool by which we ensure that our activities do not impact water resources and the community, farmers and irrigators can be confident as a result of that monitoring,” Mr Mitchley said. “If there was any question that we would impact water resources we would not go ahead with our project. Local farmers who rely on the water can have absolute confidence that as we develop the Narrabri Gas Project, water resources will not be affected. “In summary this is a great project. Its geological setting means it is sustainable, will not have an impact on water and yet provide the benefits to the economy of more affordable gas and a sustainable and natural product that helps to complement renewables.”

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SPRING 2015 // ISSUE 2

PROFILE

CAN RICHARD COTTEE WORK HIS MAGIC IN THE

TERRITORY? Richard Cottee is a man who has had no shortage of column inches dedicated to his name, almost as well known for his largerthan-life personality as he is for his role in shaping the industry as we know it today. After building the CSG-LNG industry in Queensland, Cottee has turned his attention to the Northern Territory. He wants to bring gas from Central Australia to the eastern seaboard, which currently seems disinterested in meeting demand through its own reserves. Like in Queensland, can Cottee work his magic in the Territory?

SPRING 2015 // ISSUE 2

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PROFILE

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SPRING 2015 // ISSUE 2

PROFILE

ichard Cottee is a charismatic speaker, with a style all his own. In a room full of CEOs who can toe the party line as well as any politician, Cottee is the one who will tell it as he sees it. Ask Cottee about his reputation as an engaging speaker and you’ll get an honest answer. “It’s one of my biggest problems,” he laughs. “I don’t follow my script.” It’s been an interesting few years for Cottee. Since 2012 he’s been running Central Petroleum, a junior explorer with acreage in the Northern Territory. It’s been a process of lining up the metaphorical ducks, and now the company is on the precipice of becoming a major gas supplier to the Australian east coast. Of course it’s not an unfamiliar story. In 2002, Cottee was the Managing Director of Queensland Gas Company (QGC), and under his leadership, the junior coal seam gas explorer and producer went on to establish the CSG to LNG industry in Queensland. There’s little doubt he’s referred to the lessons learned at QGC in his latest venture. Here, he shares some of his insights as an unconventional trailblazer.

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Building a global CSG-LNG industry When Cottee took the helm of QGC in 2002, the state, and indeed Australia, was on an entirely different path to securing its energy source – the industry, and Government, were focused on plans to pipe gas from Papua New Guinean-waters into the country. It wasn’t until 2007 that the project was ultimately shelved amid rising costs and a host of other challenges. While the PNG-Queensland pipeline drama played out, in the background, Cottee was building QGC’s booked gas reserves and methodically establishing the position his company could take in the country’s gas supply market. Like many things it looks like the obvious solution in hindsight; why were we chasing gas from PNG when we had our own plentiful supply in the ground? But of course, coal seam gas wasn’t always viewed this way. And as Cottee recalls, even he himself, with the vision of how CSG could transform our energy markets, couldn’t predict just how big Queensland’s coal seam gas industry would eventually become. Cottee said his vision for the CSG industry began before QGC; it went all the way back to 1998 when he joined

CS Energy, a recently corporatised Government-owned corporation. “We were building a power station at Ipswich called Swanbank B, and we were the first company ever to enter into a CSG only contract with a supplier. “So my belief in CSG started last century, but yes, the extent to which it has taken off has staggered me – although I did realise that the only limit to CSG would be imagination. According to Cottee, his belief started off from the fundamental understanding that Australia has always had methane present in its coals. The US industry was also a critical reference point - in the early 2000s the country was already meeting 15 per cent of its domestic gas needs with CSG. “I always believed that it was going to be a major new source, and I also always believed it would create a connection between Queensland and the rest of Australia via pipeline, which it did.”

Managing the resistance to chance While the vision was there, it doesn’t necessarily mean the road to production was easy. “It’s amazing how fraught the history of the coal seam gas is, how quickly some of the embryonic history of it is being

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PROFILE

ignored, or not being learnt from,” Cottee noted. “Coal seam gas was the first wave of unconventional gas to come through, and there were a lot of lessons learnt.” According to Cottee there were two critical factors in the early days of the industry: gaining political support for the industry; and getting the buy-in from local residents and industrial users. “They’re absolutely essential to your survival if you’re going into a new area, particularly one that is somewhat populated. You also need to recognise that you, by definition of being an employer, are going to be changing a long-established socio-economic order.” Inherent to that is the fact that there’s always winners and losers in any change – hence there’s always resistance to change. According to Cottee, part of managing that change was connecting with local communities. “That’s something that the industry, as a whole, didn’t really need to concentrate on in the past because offshore was offshore and the first onshore developments were in remote locations where engagement was relatively easy,” he said. “It wasn’t necessarily hardwired into the mindset of the industry as to how to go about that. We had to learn it.”

Commercial viability If establishing the community buy-in was a crucial stage in the development of Queensland’s CSG fields, developing a solid economic case was equally important. While Cottee knew he had the gas, he also knew he needed the markets – and the Australian domestic market is relatively small. “Success in Australia has to be of a certain size to pay for the infrastructure, to get to market – and the market itself is fairly small,” he noted. But as always, necessity is the mother of invention, and an innovative solution to the small market size in Australia was brought to the table – supply some of the gas domestically, and offer the rest to the energy hungry Asia Pacific, creating an infinitely larger potential supply base. The idea gained traction, and the Queensland-Curtis Liquefied Natural Gas (QCLNG) project began to take shape. By 2008, the QCLNG project had been awarded major project status by the Queensland Government, and by year’s end, QGC had been taken over by BG Group. Sales contracts followed in 2010, with the final investment decision on the project coming six months later, effectively establishing the CSG fields of Queensland

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as a major global energy supplier. QCLNG began deliveries of gas at the end of 2014, and the other two major CSG-LNG projects – Origin’s APLNG and Santos’ GLNG – are on track for first LNG shipments this year.

Bridging the disconnect According to Cottee, now that the jump from CSG explorer to exporter has been made, in many ways, the industry is now facing its most challenging test. While CSG production has taken off in Queensland, other states don’t seem interested in following the same lead. “I think the really interesting phenomenon is that Australians had, up until about three or four years ago, accepted that the resources sector was an integral part of the Australian economy,” said Cottee. “Now, I think they question that. There’s a total disconnect from users about where things are actually made, and the social license has to be regained.” Cottee does believe that this “social license” will be regained, if only for the reason that the economic stress of not having access to oil and gas is going to be overwhelming. “The reality is, brick manufacturing, glass manufacturing, fertilisers for agriculture, nylons for clothing, it can’t come from electricity, they have to come from natural gas. At some point people will realise ‘I do want housing, I do want fertiliser, and I do want food and I want clothing, not just electricity, thank you very much.’” For Cottee, the positive for the industry here is that there is an enormous opportunity for those operating in the unconventional space – particularly in New South Wales and Victoria, where “the consensus that we do need natural gas for our fundamental existence” has yet to be reached. “Someone will have to rescue them while they go through that cogitation,” he noted – effectively creating a golden opportunity to unconventional explorers such as Cottee himself, who finds himself in the fortunate position of having Northern Territory gas to commercialise, and the country’s biggest markets edging perilously close to falling short of demand. The missing piece of the puzzle Of course one thing missing from that equation falls on the logistics side. To bring the gas from Central’s Palm Valley and Dingo fields, located close to Alice Springs, to east coast markets, Cottee needs a pipeline – so it’s unsurprising that he’s been a vocal champion for the North

East Gas Interconnector (NEGI) pipeline. The project has been granted major project status, and four consortia are currently tendering for the construction contract, should the project go ahead. Two routes are being considered for the pipeline – from Tennant Creek to Mt Isa, and from Alice Springs to Moomba. “The NEGI pipeline should result in the same fundamental change to the market that the initial stimulation for the Cooper Basin had. That required some degree of vision and some degree of Government being able to see the huge benefit by having some investment in infrastructure.” According to Cottee, the Northern Territory has noted the benefits Queensland is seeing – approximately 20 per cent of its revenues from resources royalties, additional benefits in payroll tax – but the problem it faces is its smaller market.

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PROFILE

Drama in the gas fields Cottee’s own personal experience with community engagement with QGC was wide and varied, but one particular example comes to mind. Many of his colleagues thought he was mad, but Cottee created a program of community theatre events and gave them the title of ‘Drama in the gas fields’. The program brought the La Boite Theatre from Brisbane to Chinchilla, staging plays set in the Darling Downs in the middle of QGC’s gas field. Before and after the performances there were no speeches, no ‘sell’ on the development of the gas fields, so to speak – just QGC staff on hand and readily available to answer questions if locals had any. “It showed residents that we, as a business, were willing to be part of that community, not just throw money at it,” said Cottee. “It was a way by which we became accessible and part of the community. It wasn’t a public meeting where we were ramming propaganda down their throat, it was done in a much more country fashion.” It’s a charming example, but surely it took more than the La Boite Theatre to get the development over the line with locals? “Of course,” said Cottee. “There were enormous challenges, enormous challenges. At the end of the day, were there some people that were very upset by it? Yes. Do you expect in any democracy you’ll get 100 per cent support? No. The chances of failure were about ten times greater than the chance of success. “But clearly QGC was very successful at it – there were no locked gates, no real push-back at all around Chinchilla at all whilst it was Australian-owned.”

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PROFILE

Managing community resistance While Cottee faced community resistance during his days at QGC, it’s a stark contrast to the challenges CSG explorers are facing in Victoria and New South Wales today. Both states have more or less brought the exploration for CSG to a shuddering halt – despite forecasts which suggest that NSW in particular will run out of gas in the next two to four years. Again the challenges the industry faces come back to resistance to change. Communities don’t want the hydraulic fracturing that comes with coal seam gas exploration. Of course it’s somewhat of a paradox that communities have suddenly developed a resistance to fraccing – a practice which has been around since 1948. “It’s one of the most tried and tested technologies about, it’s 99.5 per cent sand and water, or brackish water,” said Cottee. “We’ve had umpteen inquiries into it – they’ve thrown every scientific brain at it that they can, and the science is truly settled. Every report that comes out says it’s a totally benign practice with proper regulation and there’s no evidence of any aquifer damage.” So why then has fraccing suddenly become public enemy number one? Cottee for one isn’t entirely sure. “You would have thought they would have found a Fukushima by now,” he mused. “The opposition isn’t necessarily logically based,” he added. “The tactic has been to get the emotive quotient high and the intellectual quotient low on the fraccing debate. But with time, I’m sure the intellectual quotient will kick in – once the boy who cried wolf is shown to be the boy who cried wolf. “As an industry, we need to be patient, we need to campaign locally, and we need to engage the community,” said Cottee.

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PROFILE

“With a smaller population than the ACT – and a lot less home heating in Darwin than in Canberra – the demand is not there,” he said. “I think it should be relatively bipartisan to try and generate royalties and create employment in the Northern Territory. I see it as my last mission, if you like, in life, that I can actually give an economic future to Northern Territory and the Indigenous population in particular. “For example, with Dingo, we’re remote controlling it out of Alice Springs. Our workforce drives to work, they do their shift, they go home at night,” he said. Central has a mandate to employ 30 per cent of its operating staff from the local Indigenous community, and Cottee believes this will help to address some of the challenges the community faces. “For men in particular, part of the dysfunctionality in the community stems from a lack of purpose. By providing employment we are providing purpose, which is what we need in life, not just money.” It’s clear that giving back to Indigenous communities is a large part of what is motivating him to keep pushing on in the oil and gas industry. “I’d love to make a huge difference in Indigenous communities, by helping enable them to preserve their own culture with the pride that their culture deserves. “I feel a certain pride that I’m part of Queensland’s CSG to LNG industry. And now, wouldn’t it be great if the Northern Territory was properly connected, if we could give an economic future to some of the most vulnerable Australians?”

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Laying the foundation Cottee’s plan for achieving his vision for Central is clear. Priority one was ticked off in June when Central acquired a 50 per cent stake in Santos’ Mereenie oil and gas field for $45 million. The benefits of the deal are twofold: through the acquisition, the company is now self-funded; and importantly, it shores up the company’s position as a potential supplier to the NEGI pipeline, should it go ahead. This segues conveniently into the next task on Cottee’s to-do list, which is to continue his campaign for the pipeline to be built. His third priority is for Central to have a meaningful, long-term impact on the eastern seaboard gas market. Cottee believes that should the pipeline go ahead, Central will provide up to 60 per cent of the initial supply. The ducks are lined up, and the next few months will be crucial in the execution of this plan. After three years building the company to where it is now, Cottee is excited to see the next stage unfold. “Having done the hard yards at Central, in my head I’m basically at the same position as I was with QGC in 2006. From that time there was a 28-fold increase in share price at QGC. “If things fall in place, NEGI occurs, our three conventional fields are at full capacity, we continue to explore our unconventional prospects – and I believe we have some of the best unconventional acreage in the Northern Territory – then I think we will have the rock on which the house can be built. “Looking forward a decade or so, I think that we can create incredible employment and wealth for this country, that is sustainable for a hell of a long time.” As always, Cottee is aiming high. But with his familiar script to work from, it’s hard not to see him ticking off every last item on the to-do list.

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DIGGING

whereâ&#x20AC;&#x2122;s the

Australia has an array of different geological basins, most of which have some potential for unconventional oil and gas exploration. As companies move to enhance their understanding of the resources in place, we take a closer look at some of Australiaâ&#x20AC;&#x2122;s key basins, where production, assessment and/or exploration are underway to develop coal seam gas, shale and tight resources.

DEEPER

oil and gas? A

ustraliaâ&#x20AC;&#x2122;s unconventional resources industry is at an exciting point in its development timeline: we are developing an increasingly sophisticated understanding of the coal seam gas, shale and tight resources in the ground; explorers are actively involved in finding the best â&#x20AC;&#x2DC;sweet spotsâ&#x20AC;&#x2122; to produce from; and the industry is making regular breakthroughs when it comes to the extraction of unconventional resources. To gain an understanding of the state of unconventional oil and gas development in Australia, and its potential, Unconventional Oil & Gas has reviewed the major basins of Australia, their resources and their viability for oil and gas production. These include basins that are currently producing gas in commercial or sub-commercial quantities, basins that have had resources formally assessed and quantified, those undergoing assessment to determine the viability of developing their resources, and those with a large amount of exploration activities currently underway. While many potential unconventional basins are underexplored and the quantity of gas in their reservoirs unconfirmed, there is an increasing amount of data available about prospective resources of unconventional oil and gas in Australia. Of course we know the most about the Queensland basins that are already producing commercial quantities of coal seam gas to supply both the domestic market and LNG export projects. In addition, the US Energy Information Administration (EIA) has assessed six Australian basins for shale oil and gas, and small quantities of shale gas have been produced from a number of wells. While no tight gas or oil has yet been produced within Australia, the presence of these resources has been confirmed in a number of basins. Exploration and well-testing activities are underway and a number of prospective areas for these resources have been identified.

RESERVES UPDATE

COOPER BASIN (SA, QLD)

The Cooper Basin is located over 130,000 square kilometres across north-east South Australia and southwest Queensland, and has been supplying Australia with conventional oil and gas for over 40 years, making it the country’s most mature onshore production region. This basin is considered prospective for shale oil and gas, tight oil and gas and deep coal seam gas. Three main deep troughs in the region have the greatest unconventional oil and gas potential – Nappamerri, Patchawarra (including the Arrabury Trough) and Tenappera. The region has particular promise for shale oil and gas development. According to the EIA, the region contains an estimated 325Tcf of shale gas in-place (including gas associated with shale oil), with 93Tcf risked and technically recoverable. The EIA also estimated 29 billion barrels of risked shale oil in-place, with a risked, technically recoverable resource of 1.6 billion barrels. The Cooper Basin is also thought to contain one of the largest tight gas resources in Australia. This basin’s massive potential unconventional oil and gas resources, paired with its existing workforce and infrastructure, mark it as the most promising basin for largescale unconventional development.

UNCONVENTIONAL RESOURCES Shale gas, shale oil, tight gas, tight oil, deep coal seam gas

PROSPECTIVE RESOURCES 325Tcf of shale gas, 29 billion barrels shale oil (EIA, 2013) Tight gas and oil yet to be formally assessed

RISKED RECOVERABLE AMOUNT 93Tcf of shale gas, 1.6 billion barrels shale oil (EIA, 2013) Tight gas and oil yet to be formally assessed

MAIN TROUGHS OR FORMATIONS Nappamerri, Patchawarra and Tenappera troughs

KEY PROJECTS South Australian Cooper Basin Joint Venture, Nappamerri Trough Natural Gas Project

KEY ACTIVE COMPANIES Santos, Drillsearch, Beach Energy, Origin Energy, Senex, Strike, BG, Rawson Resources

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RESERVES UPDATE

CANNING BASIN (WA)

The Canning Basin consists of several sub-basins in the remote north of Western Australia. Overall, it covers approximately 470,000 square kilometres onshore. Until recent years, the basin remained largely unexplored for potential gas resources. However, the amount of exploration activities in the area are increasing, targeting potential shale and tight gas resources. The basinâ&#x20AC;&#x2122;s two main areas of interest are the Goldwyer Formation and the Laurel Formation. Most activities in the region so far have focused on the Goldwyer Formation. In 2013, the EIA suggested that the Goldwyer Formation in the Canning Basin has the largest shale gas potential in Australia, estimated at around 235Tcf of recoverable gas. The Laurel Formation was not covered by this assessment due to a lack of geological data. A number of companies are currently undertaking exploration for shale and tight gas and oil. The main impediment to the exploitation of these resources is the basinâ&#x20AC;&#x2122;s remote location and the lack of existing infrastructure.

UNCONVENTIONAL RESOURCES Shale gas, shale oil, tight gas, tight oil

PROSPECTIVE RESOURCES 1,227Tcf shale gas in the Goldwyer Shale, 244 billion barrels shale oil (EIA, 2013) Tight oil and gas not formally assessed

RISKED RECOVERABLE AMOUNT 235Tcf shale gas in the Goldwyer Shale, 9.8 billion barrels shale oil (EIA, 2013)

MAIN TROUGHS OR FORMATIONS Goldwyer Formation, Laurel Formation

KEY ACTIVE COMPANIES New Standard Energy, Buru Energy

KEY PROJECTS New Standard Energy and Buru Energy, together with their partners, are exploring and evaluating the Goldwyer shale. Buru Energy is also exploring for tight gas.

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RESERVES UPDATE

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RESERVES UPDATE

BOWEN BASIN (QLD)

The Bowen Basin extends over approximately 60,000 square kilometres of Central Queensland. Commercial coal seam gas production began in the Bowen Basin in 1996. Until recently, the Bowen Basin was still the highest producing CSG region per annum in Australia. In 2013/2014, 0.0996Tcf of CSG was produced in the basin. Currently, commercial production occurs in the central and southern parts of the basin known as the Bandanna Formation, Baralaba Coal Measures and Moranbah Coal Measures. Gas resources in the basin will also feed into a number of Queensland’s CSG-LNG projects to supply export markets. Together, the Bowen and Surat basins supply the vast majority of CSG produced in Australia. Shale gas exploration is underway in the basin, focusing on the Black Alley Shale. Tight gas resources are under assessment in the Tinowon and Bandanna formations, while further CSG resources are under assessment in the Fort Cooper and Rangal Coal Measures. Like the Surat Basin, the existing infrastructure and workforce in the Bowen Basin makes it an attractive prospect for further development of unconventional oil and gas.

UNCONVENTIONAL RESOURCES Shale gas, shale oil, tight gas, tight oil, deep coal seam gas

PROSPECTIVE RESOURCES

SURAT BASIN (QLD, NSW)

The Surat Basin incorporates an area of approximately 300,000 square kilometres, around two thirds of which are located in Queensland and the remainder in New South Wales. This basin contains some of Australia’s largest proven coal seam gas reserves and has been the focus of CSG exploration activities since 2000. As of December 2014, the Surat Basin’s proved and probable (2P) CSG reserves were estimated at 33,294PJ (30.62Tcf). Overall, 225PJ (0.21Tcf) of CSG was produced from the Surat Basin in 2014. CSG production from the Queensland parts of the Surat Basin has increased dramatically over the last decade, from none in 2003/2004 up to 0.157Tcf in 2013/2014, making it the highest producing CSG basin in Australia. CSG fields in the Surat Basin supply increasing quantities of gas to the domestic market and will also supply gas to three of Australia’s pioneering CSG to LNG projects, the QCLNG project, the Santos GLNG project and the APLNG project. Exploration and well testing activities targeting tight and shale gas and oil have also taken place in the basin. The infrastructure and regional development spurred by the CSG industry could also increase the commercial viability of developing other unconventional resources in the basin.

UNCONVENTIONAL RESOURCES Proven CSG, potential shale and tight oil and gas

CSG being commercially produced; tight and shale oil and gas not formally assessed

PROSPECTIVE RESOURCES

2P RESERVES

CSG being commercially produced; tight and shale oil and gas not formally assessed

Approximately 8.7Tcf of 2P CSG reserves (DNRM QLD, 2014)

2P RESERVES

MAIN TROUGHS OR FORMATIONS Tinowon Formation (possible tight gas), Bandanna Formation (CSG or tight), Baralaba Coal Measures (CSG), Moranbah Coal Measures (CSG), Black Alley Shale (possible shale), Fort Cooper Coal Measures (possible CSG), Rangal Coal Measures (possible CSG).

KEY PROJECTS QCLNG, APLNG, GLNG, Bowen Gas Project, Moranbah Gas Project, Mahalo Project

Approximately 30.62Tcf of 2P CSG reserves

MAIN TROUGHS OR FORMATIONS Walloon Coal Measures

KEY PROJECTS QCLNG, APLNG, Santos GLNG, Surat Gas project, Western Surat Gas project

KEY ACTIVE COMPANIES BG/QGC, Origin Energy, Santos, Arrow Energy, Senex

KEY ACTIVE COMPANIES BG/QGC, Origin Energy, Santos, Arrow Energy, Comet Ridge, Blue Energy

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RESERVES UPDATE

SYDNEY BASIN (NSW)

The Sydney Basin spans from southern coastal New South Wales to Central Queensland and contains an onshore area of approximately 44,000 square kilometres and 5,000 square kilometres offshore, extending to the edge of the continental shelf. The area has been subject to extensive coal mining but is also considered to be highly favourable to the continued development of an unconventional gas industry. AGLâ&#x20AC;&#x2122;s Camden Gas Project is currently producing coal seam gas from the Illawarra Coal Measures in the south of the basin, with around 86 wells producing. In July, AGL announced it had shelved plans to expand the project due to ongoing opposition in the state to CSG extraction. AGL will continue its current Camden Gas Project operations with a focus on reducing production costs. The Sydney Basin produces approximately 6PJ of CSG per annum and is thought to contain 2P CSG reserves of 103PJ in total. The basin is also considered prospective for tight gas and shale oil and gas, although these resources have not been formally assessed or quantified. Currently tight gas exploration is underway in the Illawarra Coal Measures and exploration targeting further CSG resources is underway in the Wittingham, Newcastle, Tomago and Greta Coal Measures.

UNCONVENTIONAL RESOURCES Coal seam gas production, potential shale gas, shale oil, tight gas

PROSPECTIVE RESOURCES CSG production, other resources not yet formally assessed

2P RESERVES 103PJ (0.086Tcf) 2P CSG reserves (Core group, 2014)

MAIN TROUGHS OR FORMATIONS Narrabeen Group, Bulgo Sandstone, Colo Vale Sandstone, Illawarra Coal Measures, Wittingham Coal Measures, Newcastle Coal Measures, Tomago Coal Measures, Greta Coal Measures, Shoalhaven Group, Clyde Coal Measures

KEY PROJECT Camden Gas Project

KEY ACTIVE COMPANY AGL

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RESERVES UPDATE

Cooper Basin Canning Basin Bowen Basin Sydney Basin Surat Basin

The next part of the story: looking at Australia’s under-explored basins These basins offer a glimpse of Australia’s unconventional oil and gas resources and the activity underway to develop them. However, they do not represent the limit of Australia’s unconventional potential. In the next edition of Unconventional Oil & Gas, we’ll bring you Part 2 of this article, in which we explore a number of additional basins where unconventional activity is underway. These include the Maryborough Basin, the Beetaloo Basin, the Perth Basin, the Georgina Basin, the Galilee Basin, the McArthur Basin and the Arckaringa Basin. Additionally, we’ll offer a bigger picture overview of other basins that may hold potential unconventional resources.

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INTERVIEW

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Craig Ricato eyes up a shale bonanza 30

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INTERVIEW

inc Energy’s drilling program for 2014/15 was designed to assess the potential of the Arckaringa Basin for unconventional hydrocarbon production from the Permian and pre-Permian Formations, and focused on two wells, Pata 1 and Eba 1. In the Stuart Range Formation, the results have shown potential yields of up to 54 litres of oil per tonne; and in the Boorthanna Formation, potential yields of up to 70 litres of oil per tonne. In the Boorthanna, the potential discovery of a new hydrocarbon system has also been flagged. “The program we ran was initially a three-well program, but we pulled it up after the completion of the second well because of the results we’ve had,” said Linc Energy CEO and Managing Director Craig Ricato. “We found a very good prospective shale horizon in the Stuart Range in our first well, and the second well was actually very informative, because it was a lot deeper than we had initially anticipated. “Now we know the zone we want to target as an initial exploration point, and in the next six to nine months we will be working with experts like Baker Hughes, going through our seismic data and looking at the next sweep of exploration targets and developing those prospects.” Favourable comparisons One factor that has Mr Ricato particularly excited about the Arckaringa discovery is how favourably it compares to shale measures in the US. “In the majority of the variables, such as age, lithology, depth, porosity, permeability, total organic compounds and vitrinite reflectance, what we’ve seen so far in the shale measures extracted from our exploration program in the Arckaringa is that they compare very favourably with the prolific shale basins in the United States. “The challenge is to get to the thermal maturity. So we’ve been looking for the shale zones that have these attributes. As I said, in the Stuart Range we have an extremely large – approximately 139 metres thick – shale bed, which has these attributes. “The challenge for our exploration program is now to find that sweet spot – to find it at the right depth, which means the pressure and temperature over time have meant that it’s an active hydrocarbon system. “In some of our earlier shallow exploration we had oil shows, so we know there’s an active hydrocarbon system there, it’s 16 million acres and it’s a matter

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of defining where those areas are.” Mr Ricato has some words of advice for any company considering moving into shale oil and gas exploration – and for any company that’s unsure of the benefits that shale resources have to offer. “If you’re unclear on why we should get involved with shale, you just need to take a look at the US oil and gas industry,” he said. “The shale industry has completely changed their economy, they now have a gas price that is very low, which has meant they’ve had a new manufacturing boom, and their ability to meet Kyoto protocols and go beyond is now a real possibility for them. All of these positive benefits that the US has experienced – Australia can be part of this too, and I think we’ve got to rise to it.”

Partners in arms With the promise of the Arckaringa acreage effectively confirmed, the company acknowledges that one of the next steps it needs to take will be to attract strong strategic partners to the basin. Linc Energy is also clear on the fact that it is looking for a relationship that supports an accelerated exploration and development program. “There’s two types of investors from where we sit, there’s an initial investor and a financial investor,” noted Mr Ricato. “One of the things about Linc Energy is we are a competent oil and gas operator, and we would be happy to work with a financial investor if someone was looking at deploying capital in exploration in South Australia. “Ideally though, it would be fantastic to partner with someone from the industry. There are multinational companies that we have been in communication with regarding what we’re doing in South Australia, and we’d like to continue that discussion. “We’d love to partner with someone who has a specific Asia Pacific focus, which is really where, in terms of our company’s unconventional business, we are focused.” Finding the sweet spot Securing partners for the project is a major piece of the development puzzle, but there’s a number of other important steps that the company is focused on – including finding the sweet spots within an asset that stretches across more than 16 million continuous acres. “The size of the asset still has to be verified; although the important thing to understand about the asset in our lease position is we actually have 16 million continuous acres,” said Mr Ricato.

“So far we’ve been focusing on the Boorthanna Trough because of the previous oil shales that we’ve had in early exploration. “But in terms of the entire Arckaringa Basin, this is going to be a very, very long-term exploration. We know that there is an active hydrocarbon system there. Part of the next phase is to identify, as early as we can, some sweet spots, so we can then assess whether or not they’re economic to bring into production.” In the next 12 to 18 months, Mr Ricato expects to run a further three to four-hole exploration program, and if there is a successful discovery in any of those wells, the company would begin looking at designing an economic business case around bringing those into production. The other factor the company is considering is the basin’s potential for conventional reserves. “The thing about this basin is, you’re not just looking for unconventionals in terms of oil bearing shale, it’s also got potential for conventional oil reservoirs and gas,” noted Mr Ricato. “So if one of our exploration wells resulted in a gas find, then we’d obviously be looking at the best way to bring that to market. This could potentially be through the Cooper Basin network, which has the benefit of not requiring any lead-in time with regard to infrastructure. “For Linc Energy though, ideally what we will do is continue to enhance the data set in what is a very under-explored area. Long term, what we would like to do is bring in industry partners to assist with the exploration so that we could actually accelerate the exploration.”

Managing logistics As with any exploration project, the question of infrastructure is never far from mind when it comes to this resource. “At this stage of the exploration, we are very conscious of the lack of infrastructure in the Arckaringa Basin,” said Mr Ricato. “The advantage we do have with the Arckaringa Basin is the rail line that runs from Adelaide up to the Northern Territory, which could provide opportunities in terms of freighting. “But realistically, it is going to depend on the type of discovery we have. If we have a significant gas discovery, one would assume that the most efficient way of exporting would be via pipeline into the existing infrastructure through the Cooper Basin. “If we have a significant unconventional or conventional oil discovery, our options are a little bit broader. If we wanted to look

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at domestic refining, we’d probably be bringing in industry partners with refining expertise at that point in time. Alternatively, we could work with partners who would look at the discovery as more of an export opportunity,” he said. One area that poses less of a challenge than that of infrastructure is the matter of sales contracts. “That’s the beauty of the oil and gas business,” noted Mr Ricato. “If you do have a discovery, it’s not like you really have to market your product. “Looking at Australia’s oil and gas production at the moment, with gas there’s a lot of talk about our domestic gas needs, and then there’s also talk about feeding into the eastern seaboard network so that there’s gas available for export as LNG. Alternatively, looking at a crude oil or shale oil discovery, then I think that the Australian market has significant capacity domestically for additional production.”

A challenging macro-economic environment While there may be plenty of markets available to Linc Energy, the obvious question for Mr Ricato to consider is whether the current oil price should play a part in the company’s development of the asset. “In terms of actual long-term exploration of the asset, the current oil price isn’t really having an impact,” he said. “While the current macro-economic environment means that the broader ‘gold rush’ mentality towards shale has slowed down somewhat, these assets are still highly sought after. “However, what you do see in the current environment is that most companies don’t have the additional capital that they would have had available in a $100 per barrel price environment to spend on exploration. So you do have to be a lot more prudent, and you have to make sure that your dollar goes as far as possible. “For us, that’s the real effect of the current oil price. We’re fortunate that we’ve gone through a program and we have a very definite plan of how we want to develop this prudently, and it’s not a capital intensive plan over the next six to twelve months.” South Australia – the place to be While the current macro-economic environment might throw up its challenges, one thing Linc Energy doesn’t have to worry about is overhanded regulation, given the asset in South Australia. “In all jurisdictions around the world you

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INTERVIEW

have to deal with regulators. We have found South Australia to be very supportive of exploration – it’s a good place to do business. The regulators here are very technically competent, and being an explorer in this part of the world is something that we find is less problematic than other jurisdictions, particularly within Australia.” It’s a significant contrast to the maze of moratoriums and inquiries currently in place or underway elsewhere in the country, and for Mr Ricato, it’s actually one of the reasons the company was attracted to the asset package in the first place. “South Australia is very positive towards development. They realise that these developments are very good for South Australia, and I think that there’s an appreciation from the South Australian Government and their regulators, that whilst they must prudently regulate, they must also assist industry investment.” The geographic location, combined with the results seen so far and the global appetite for shale oil and gas, has Mr Ricato and the team at Linc Energy excited for this asset’s future development. “We’re in a vast, under-exploited area with huge resource potential. It deserves a very technical, prudent, measured exploration program and that’s what we’re intent on delivering,” said Mr Ricato. “We’re in a really good jurisdiction in South Australia and we look forward to one day having a significant discovery. “Hopefully, the next time we speak we will be talking about the partners we’ve brought in and the next steps we’re taking together.” Watch this space.

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ANALYSIS

Shifting

GEOPOLITICAL tips for staying ahead in the global energy game by Geoffrey Cann, National Director – Oil & Gas, Deloitte

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ANALYSIS

SANDS: We like to think that Australia and its rapidly growing gas industry are immune to the great energy-driven geopolitical issues of the day – but as the market for Australian energy becomes increasingly global, Geoffrey Cann argues we need to expand our view of the role international politics have to play in our domestic and export markets.

o a significant degree, Australia is immune to the geopolitical issues affecting the energy industries. Our nation is far removed from the troubles in the Middle East, and the challenges in the Ukraine. Our gas sector is largely under the control of free market enterprise, which for the most part views geopolitics as just another risk to be managed. And today at least, our gas exports do not play that big a role in our national economy. But as Australia becomes an ever larger gas exporting nation, we will be pulled into some geopolitical issues that have a strong energy flavour, and we will need to have a point of view about our position and role. To get started, here are three high profile geopolitical issues, and their implications for Australia’s unconventional sector.

The rise (and rise) of China Our relationship with China, and the wider Asia Pacific region more generally, is getting more complicated. Despite current softness in its demand for commodities, China is now the second largest importer of crude oil after the US*, with 6.2 million barrels per day. China is building half a dozen coastal regasification plants, has ambitions to turn Shanghai into a regional energy hub to rival Singapore, has big new gas pipeline projects underway with Russia, and has embarked on reform programs for its national oil and gas sector. Chinese news outlets have also raised the prospect of mergers between China’s big national oil and gas companies. Australia’s east coast gas industry is, of course, quite dependent on an ongoing relationship with China’s national oil companies via their local investments. But China continues to assert its interests

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over disputed parts of the South China Sea by converting some shoals into islands, moving oil and gas exploration rigs into the area, and stepping up its naval presence, much to the concern of neighbouring nations, many of whom (Japan, Malaysia, South Korea) are also investors in Australian gas. Japan gets some 20 per cent of its gas from Australia*, while South Korea is set to receive some 10 per cent of its gas from Australia. Australians have been successful in managing relationships with the big customer nations to the north throughout the coal and iron ore booms. But gas is a different commodity. Not only is it necessary for survival in gas-dependent cold northern climates, but also it cannot be stored as easily as coal, and is consumed more immediately. As a result, customers are more sensitive to disruption in supply. Australia needs to anticipate that China

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Australia is tying itself ever more tightly to a fossil fuel future just as big nations such as the US and China begin to turn to alternatives.

may, from time to time, want to assert its influence over its east coast Australian energy assets, particularly if the Chinese majors amalgamate. China’s interests may also occasionally be in conflict with Australia’s desires to maintain good relations with, and among, other Asia Pacific neighbours. As a result, diplomatic efforts may need to adapt accordingly.

The future of carbon Australia is tying itself ever more tightly to a fossil fuel future just as big nations such as the US and China begin to turn to alternatives. The country has made a great living selling coal to the world, and has a long and proud track record of meeting the world’s need for this fuel. Just as the gas sector is launching what will be a long 20-year run as one of the world’s biggest suppliers, Australia will find itself, from time to time, having to defend both its coal and natural gas industries in the face of increasing concerns around fossil fuels. Expanding the industry may therefore be hampered in the face of negative investor reactions and possible bans on imports from unconventional sources. Many US states and the European Union, for example, have attempted to ban oil from Canada’s oil sands, another unconventional resource.

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Australia’s influence over other nations on matters important to Australians (like free trade, human rights, freedom of speech and immigration) may well be lessened as a consequence of a reliance on energy exports that contribute to global emissions. Governments can help by constantly reminding global trading partners of the positive impact gas is having on air quality and emissions, and how, with the right technology and knowhow, gas can be safely extracted from coal.

Sanctions roulette Australia’s gas sector is becoming increasingly bound up in the role of sanctions placed on various global oil and gas rivals. Sanctions on oil and gas countries generally work because of the relative impact of oil and gas revenues on state treasuries. Begin with Russia. Europe is bent on diversifying gas supply away from Russia, initially triggered by the Ukraine gas curtailment by Russia that plunged much of Europe into the freezing dark, but more recently reinforced by the annexation of Crimea, the downing of MH17 and the cancellation of South Stream. Sanctions on Russia by Western nations are severely impacting its ability to extract oil and gas because of restrictions on the supply of Western technology. Its LNG projects have

slowed to a crawl, and it stands accused by its own gas customers in Turkmenistan of not paying its gas bills. Sanctions on Iran are about to be lifted, and the country will shortly begin work on unleashing its pent-up gas resources. Iran today exports a modest 8.9bcm of gas to Turkey each year, and has fully 18.2 per cent of proven gas reserves, the world’s single largest share. Iran’s gas will be able to reach global markets through the Persian Gulf and Europe via Turkey, and oil companies are lined up at Iran’s gate ready to discuss terms. These sanction programs can create windows for competitors to seize market share from those being sanctioned. But they can also come to an end (as with Iran) or can create perverse effects (Russia has turned its attention eastward with the announcement of several pipeline projects to bring Russia’s considerable gas resources into China, Australia’s key market). Australia will find it increasingly difficult to support sanctions programs that ultimately enable key rivals and hurt its economy. So prepare for difficult national conversations and choices in the future. *Taken from BP’s Annual 2015 Statistical Review.

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ANALYSIS

CSG OUTPACING CONVENTIONAL IN THE RACE TO LNG SUPPLY CSG-LNG start-up could prove to be more successful than Australia’s conventional LNG developments – that’s the latest assessment from industry consultants Wood Mackenzie, who have been tracking the progress in building Australia’s major LNG export terminals, leading them to conclude that the CSG-LNG developments will come out on top.

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The Methane Rita Andrea, shipping cargo from QCLNG.

ANALYSIS

ood Mackenzie’s analysts track the progress at the seven major LNG projects around the country: QCLNG, APLNG, GLNG in Queensland; Gorgon, Wheatstone and Prelude offshore Western Australia; and Ichthys offshore the Northern Territory. The results achieved at the Queensland CSG-LNG plants in recent months have led them to view the construction of these projects more favourably than the conventional LNG developments. The first cargo from the first train at QCLNG was delivered in January 2015. With 50.75mmtpa of LNG capacity still under construction around Australia, it marked the beginning of a three-year period during which another 12 LNG trains should be commissioned. The other CSG-LNG projects – APLNG and GLNG – will be eager to replicate BG’s successful ramp-up so far at QCLNG. At the time of going to print, both APLNG and GLNG had brought gas into their production trains, and Wood Mackenzie analyst Adele Long is anticipating first gas deliveries in October 2015. While Ms Long had initially flagged the potential for Train 2 start-up at the CSG-LNG developments to potentially pose some difficulty, QCLNG has relatively seamlessly integrated the start-up of Train 2. “We view this as a major positive for this project,” noted Ms Long. “BG were able to ramp up production of their first train much quicker than anticipated, and their second train has also come online rapidly. While we still think there are some risks for the second train, as we move forward, some of these risks are being mitigated.” It will be interesting to see whether this experience is replicated at APLNG and GLNG. Ms Long noted that QCLNG operator BG Group has significant global LNG start-up expertise to draw on, which may have contributed to its ability to get Train 2 up and running so quickly. While APLNG operator Origin and GLNG operator Santos don’t have this experience to draw from, their joint venture partners (ConocoPhillips and TOTAL, respectively) do, which may mitigate any concerns there. The next challenge will be the operators’ ability to transition from construction to operation, which will require a shift in staff, resources and management approach. “How they perform post start-up will be the next test,” said Ms Long. “But overall, one of the biggest risks was upstream and so far all of the operators are performing quite well in that regard.”

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Adele Long.

The CSG-LNG success story CSG-LNG will be tested this year and next, and of particular concern is how each operator will ramp up a significant volume of gas in a very short time. The most productive wells will supply the first train of each project, and risk remains around the deliverability and consistency of the second and third-tier supply that will feed the second trains. BG has managed the ramp-up of its first train at the QCLNG project well so far. But with only two out of six trains producing, the successful delivery of the remaining trains will dictate whether CSG-LNG rampup is a success. BG has mitigated some of the risk associated with developing new upstream supply by sourcing much of the gas from already producing areas and third-parties. The LNG plant has also required limited downtime so far. Upstream production into the plant will continue to fluctuate, with expectations that it will reach full capacity later in the year. With all three plants expected to be operational by October, a significant volume of gas will need to be supplied into the plants at the same time, and this is a key risk area. Upstream production into the plants will fluctuate but LNG ramp-up should be steady. Supply will be supplemented by gas contracted from third parties or under swap arrangements, particularly for GLNG. In 2015, these volumes could account for up to 40 per cent of the gas supplied from external sources. Close to 1,000 wells will be drilled each year to maintain momentum in the upstream, and the operators’ ability to manage this activity level, as well as an operating LNG plant, has not yet truly been tested. This will partly be managed with

a slower ramp-up period, with GLNG’s second train taking three years to reach full capacity.

The next wave of LNG In contrast, Gorgon, the first of the conventional LNG developments expected to come online, is currently operating around 18 months behind its initial delivery forecast. Construction at Gorgon has been hindered by well-known logistical and productivity challenges. According to Ms Long, these include the complex design and location of the projects. In particular, the Gorgon project being located on a Class A Nature Reserve has led to environmental challenges which have required a unique management approach.

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ANALYSIS

According to Ms Long, once Gorgon comes online, Ichthys, Wheatstone and Prelude will follow, adding another 21mmtpa to Australia’s LNG exports. A few years behind the first tranche of projects, they will be exposed to a different economic climate, labour market and a changing cost environment, while facing their own distinct challenges. Ichthys, Wheatstone and Prelude are yet to have formal cost and timing reviews, typically seen once projects reach between 40-50 per cent completion, so there is not yet clarity whether the projects will suffer cost overruns similar to their predecessors. According to Ms Long cost increases are likely at all three projects, however they should not be to the extent of other Australian projects. Ichthys and Wheatstone

should be cushioned somewhat due to the weakening Australian dollar and more favourable labour market conditions, while Prelude remains somewhat insulated from Australian LNG cost overruns, given the majority of spend is outside Australia. Still a few years away from start-up, scheduling risk will continue. Strong project management will be key to keeping these developments on track and ensuring that they can meet revised timelines.

CSG-LNG could come out on top For the CSG-LNG projects, the operators’ ability to successfully deliver the projects has always concerned the wider LNG industry, mainly because the concept has not truly been tested before. Comparatively, there was a higher level

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of confidence in Australia’s conventional projects Gorgon, Wheatstone and Ichthys. But so far, the delivery of conventional Australian LNG has been disappointing. All projects are between seven to 18 months behind their original schedule, with the second wave being far enough away to potentially warrant further delay (or catch-up). “The CSG-LNG projects, compared to conventional projects, have stayed closer to their initial forecasts in terms of both time and budget,” said Ms Long. “Comparatively the conventional LNG projects are running behind schedule and have seen cost increases – this has led to our conclusion that the CSG-LNG construction phase may actually prove to be more successful than that for conventional LNG.”

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SEVEN YEARS IN THE MAKING:

THE LOGISTICS OF BRINGING AUSTRALIA PACIFIC LNG ONLINE

ueensland’s CSG industry has come a long way since exploration for gas began in the Bowen Basin in 1976. Commercial production of this resource began in 1996, and with advances in technology in the almost 20 years since, CSG has developed into a key energy source which now makes up about 90 per cent of Queensland’s natural gas supply.

Pipe arriving by ship for the APLNG pipeline.

Taking Australian gas to the world Announced in 2008 and approved for development in 2010, the Australia Pacific LNG Project now sits at the precipice of its first LNG export shipment. Including the background development work before the project was announced, getting the project up and running has been an almost decade-long labour of love between the three joint-venture partners Origin (37.5 per cent), ConocoPhillips (37.5 per cent) and Sinopec (25 per cent). The project has involved three key stages: ♦♦ Further development of Australia Pacific LNG’s gas fields in the Surat and Bowen Basins in south-west and central Queensland ♦♦ Construction of a 530km gas

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Welding the APLNG pipeline.

transmission pipeline from the gas fields to an LNG facility on Curtis Island off the coast of Gladstone ♦♦ Construction of an LNG facility on Curtis Island off the coast of Gladstone, with the first two gas production trains processing up to 9million tonnes per annum. In addition to the export markets the project will supply, Australia Pacific LNG will also continue to supply gas-fired power stations, major industrial customers and residents throughout Queensland with natural gas. The project has considerable depth, with approximately 10,000 gas wells to be drilled within the two basins over the next 30 years, meaning there is still a lot of work to be done, and a plentiful supply of gas available. Bringing the team together More than 5,000 jobs were created by the construction of the Australia Pacific LNG Project, and with such a massive workforce to establish, the process of bringing the project construction team together required careful consideration. To manage the recruitment process the task was split between the joint venture partners, with Origin, as upstream operator of the Australia Pacific LNG Project, looking after the recruitment for the construction and operation of the gas

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fields and main gas transmission pipeline, and ConocoPhillips responsible for the LNG facility where construction of the plant was managed by construction firm Bechtel. All partners committed to the sustainable development of the project, which extended to sourcing goods, supplies and services from local businesses and supporting local suppliers whenever it was viable to do so. The project is now moving from the construction phase to the operations phase, with approximately 2,000 jobs expected as part of the ongoing operation of the project, which includes the drilling of future wells and construction of associated upstream gathering infrastructure.

Connecting gas to markets With the teams established, the major project component that needed to be completed was the construction of the 530km main gas transmission pipeline and approximately 150km of smaller transmission pipelines. The main 42-inch pipeline route begins from the main gas processing facility north of Miles, and continues north through Banana Shire before turning east towards the coast just north of Gladstone. It is buried on average to a depth of 750mm and deeper on good quality agricultural land, under water courses, creeks, railway crossings

and road crossings. Two main lateral pipelines, ranging in size from 18 to 36 inches in diameter, feed gas from the gas fields to the west and south of the main transmission line’s starting point. A range of factors were taken into consideration when selecting the best route for the pipeline. These included: ♦♦ Landowner constraints ♦♦ Environmental sensitivity ♦♦ Technical and construction considerations ♦♦ Access for construction and maintenance ♦♦ Physical suitability ♦♦ Cultural heritage/significance ♦♦ Social impacts ♦♦ Existing land use, and consultation with local communities ♦♦ Land marked for future development. A number of alternative pipeline routes were investigated before the final route was decided. The final route that we see today is the result of extensive studies and surveys, including topography, ecology, geology, cultural heritage and landowner and stakeholder consultation. The pipelines were completed in 2014.

Working with landholders Cultivating effective relations with landholders and local communities was a critical aspect of the pipeline project’s success.

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LOGISTICS

A team of pipeline landholder liaison officers was established to maintain relations with local landowners, community groups, and local government to provide information and listen to feedback. These relations and communication lines were essential for managing discussion about issues such as impacts on roads, road use permits, placement of camps, land access negotiations, cultural heritage and environmental permits, and responding to feedback and complaints. Australia Pacific LNG Pipeline Project Manager Graeme Hogarth said the early stages of the pipeline project focused on the critical aspects of gaining necessary approvals, permits and land access agreements. “The first three years of the pipeline project were all about the approvals and the engineering; about defining the route of the pipeline, and then designing the pipeline – taking into account design safety as well. “Gaining necessary approvals involves securing access to land, cultural heritage clearances, environmental permits, working with stakeholders, working with landholders, working with council and working with Government.” During the pipeline project a total of 260 landholder land access agreements were negotiated, along with numerous permits and approvals at federal, state and local government level. Australia Pacific LNG’s pipeline project won the 2015 Contractor Excellence Award at the Infrastructure Partnerships Australia (IPA) National Awards in Sydney in April. The engineering, procurement and construction (EPC) contract for the pipeline project was awarded to MCJV, a joint venture between McConnell Dowell Constructors and Consolidated Contracting Company Australia. Mr Hogarth said MCJV and its subcontractors had worked closely with Upstream operator Origin to develop a ‘one team’ approach that played a key role in delivering best for project outcomes, including a strong focus on excellent safety performance.

Life on site The housing of construction staff is a key consideration for any large-scale construction project. Workers on the Australia Pacific LNG transmission pipeline were supplied with temporary accommodation within close proximity of the site, keeping the team’s travel distances safe and manageable. Accommodating the workforce out of local towns wherever possible

Construction of the pipeline for the APLNG project.

The APLNG Curtis Island LNG facility, in July 2015.

minimised the impact of the project on local communities. Temporary worker accommodation camps were located approximately 100km apart, minimising the travel for each team to their project site. When choosing the sites for worker accommodation, consultation and approval from relevant local councils was required. The factors considered when assessing the most suitable location for the temporary accommodation facility included: ♦♦ Workforce and community safety ♦♦ Suitable arrangements with landowners ♦♦ Environmental constraints ♦♦ Flood mapping

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♦♦ ♦♦ ♦♦

Proximity to worksite Potential impacts to local services Traffic and roads, particularly safe allweather access ♦♦ Working hours and productivity ♦♦ Security ♦♦ Onsite amenities. Temporary accommodation facilities provide a home away from home for the teams working onsite. The amenities include comfortable rooms with ensuites, well-equipped dining rooms with a variety of eating options, communication facilities, general living areas and recreational activities. The sites also include dedicated medical SPRING 2015 // ISSUE 2

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Today, APLNG’s 530km high pressure main export pipeline is today nowhere to be seen, except for the signage showing the underground location.

and security services and are generally self-sufficient in regard to waste, sewerage and electricity generation to avoid impacting on local services. The sites also accommodate workshops, storage, vehicle parking and project offices. Accommodation facilities are operated by specialist facilities contractors who set up and maintain a high standard of care and responsibility for the site. A facility manager is responsible for operation of the site and safety of all personnel, and there are specific codes of conduct that construction teams residing onsite and all employees must adhere to, including when they are visiting neighbouring communities.

Building the LNG facility While the pipeline construction was taking place, the LNG facility construction team was also working around the clock to build the facility. The facility features two 4.5 million tonnes per annum gas production trains and supporting infrastructure. The first train is approaching first LNG production; and the second train is expected to be completed in time to start production in 2016. Compressed CSG from the gas fields will be piped to the LNG plant where it will be treated to remove any impurities including carbon dioxide and water. Next, the treated gas will be chilled to approximately -161 degrees Celsius in successively colder heat exchangers that use propane, ethylene and methane as refrigerants. As the natural gas cools it moves from a gas into a liquid form. The liquefied gas is

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then pumped into insulated storage tanks before being loaded onto double-hulled ships for transportation. The LNG facility will use ConocoPhillips’ Optimized Cascade® technology to transform the CSG into LNG. This technology has been successfully proven in more than 40 years of plant operation, and is currently used in three continents.

Arrival of ‘first gas’ The first delivery of gas arrived at the Curtis Island LNG Facility in February, following the successful commissioning of the 530km high-pressure main gas transmission pipeline. The arrival of gas at Curtis Island enabled the start-up of the commissioning phase of the LNG Facility. This includes the verification and testing of each system of the first processing train, the power generation infrastructure and the two LNG tanks; part of which has already commenced. And the first of seven gas turbine power generators designed to provide electrical power to the Curtis Island LNG Facility was successfully fired up in April. In an elegant design solution, the gas turbine generators use the same gas provided from the gas fields via pipeline as the source of cleaner fuel to generate the electrical power required to operate the LNG Facility. Each Solar Titan 130 gas turbine generator produces a peak output of around 15 megawatts (MW) and combined will deliver a total of 105MW.

The gas turbine generators will meet all electrical power requirements for the LNG Facility, eliminating the need for portable temporary diesel-operated generators currently used onsite. The power generation system will supply electricity for LNG processing and the common utility and offsite areas, such as the Jetty and Materials Offloading Facility. The double-hulled tankers that will soon be shipping LNG have been specially designed and constructed to maintain the low temperature of LNG. The LNG is stored in a special containment system within the inner hull, and the design of this system enables the LNG to stay cold, without the need for pressurisation.

A new dawn for Australian gas As the construction team concludes its undertaking to bring Australia Pacific LNG to the point of first LNG export, the next phase of the project – delivering gas to major export partners – will soon begin. A transformative project, only 15 years ago it would have been hard to imagine that the gas fields of the Surat and Bowen basins would present themselves as a major supplier to export markets. It’s a classic case study in the importance of getting the logistics right from the start. After a solid and focused ten years in planning, building and delivering the project, Origin Energy now has an asset that will be supplying to domestic and export markets for at least 30 years.

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LOGISTICS

RULES AND

REGULATION NAVIGATING THE GOVERNANCE MAZE

by Liz Allnutt, Partner, Norton Rose Fulbright As the regulation of the oil and gas industry around Australia becomes increasingly complex, unconventional resources legal expert Liz Allnutt breaks down the regulatory process state by state, and highlights some of the key legal principles guiding the development of the unconventional sector around the country. General legislative framework In Australia, all six states and the Northern Territory have their own legislative power to govern onshore petroleum exploration and production activities within their boundaries. State legislation also regulates activities within coastal waters extending up to three nautical miles from the coastal baseline. The onshore petroleum regimes in each state are broadly similar but not identical. The onshore petroleum regimes in Australia start from a fundamental position of treating unconventional gas resources in the same manner as conventional petroleum resources. In addition to the petroleum-specific legislation, there is other legislation that applies to petroleum exploration and production activities. This includes environment and heritage protection legislation (at state, territory and Commonwealth level), legislation governing the allocation of onshore water rights, native title and Aboriginal heritage protection legislation, legislation governing industrial relations and workplace health and safety, planning legislation and general land tenure legislation. The Standing Council on Energy and Resources, comprising Australiaâ&#x20AC;&#x2122;s energy and resources ministers, has endorsed and implemented a harmonised framework for the WWW.UNCONVENTIONALOILANDGAS.COM.AU

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Key legislation and administering government agencies

Commonwealth Approvals required for actions that will have a significant impact on a matter of national environmental significance. There is a right to negotiate process, as well as protection of sites or objects of cultural significance to Aboriginal people.

Western Australia At the end of May 2015 the Department of Mines and Petroleum released new regulations, providing a risk-based management scheme for onshore exploration and production activities, for public comment. The scheme includes the requirement for approval of all well management plans for drilling activities, and field development plans for the recovery of petroleum and for the rate of recovery of petroleum.

Northern Territory The Northern Territory Onshore Oil and Gas Guiding Principles are currently available in draft form, with the final version of the guiding principles expected to be released in late 2015.

Queensland Queensland has established a comprehensive governance framework to oversee development of the stateâ&#x20AC;&#x2122;s coal seam gas (and liquefied natural gas) industries.

New South Wales All proposals are required to comply with Strategic Regional Land Use Policy, which the NSW Government introduced in 2012 to better manage the potential conflicts arising from the proximity of mining and coal seam gas activity to agricultural land in some parts of the state. Note also that land access arrangements between stakeholders are overseen by the Land and Water Commissioner.

South Australia South Australia launched a comprehensive plan for the development of its unconventional gas projects in 2012 with the publication of its Roadmap for Unconventional Gas Projects in South Australia.

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Victoria Tasmania In March 2014, the Tasmanian Government introduced a 12-month moratorium on hydraulic fracturing for the purposes of hydrocarbon resource extraction, to enable a review of the potential impacts of hydraulic fracturing in Tasmania. The moratorium has since been extended to March 2020.

A moratorium on hydraulic fracturing, exploration drilling and the granting of new exploration licences for all types of onshore gas has been in place in Victoria since 2012, and a ban on the addition of BTEX (benzene, toluene, ethylbenzene and xylene) chemicals in hydraulic fracturing fluids, has been legislated.

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regulation of coal seam gas. The National Harmonised Regulatory Framework provides a suite of leading-practice principles to be used as a guidance and reference tool for Australian Commonwealth, state and territory government regulators for the coal seam gas industry. The framework focuses on four key areas of operations, covering the life cycle of the development of natural gas from coal seams: well integrity, water management and monitoring, hydraulic fracturing and chemical use. The framework acknowledges that, although shale gas and coal seam gas have some common exploration and development procedures, the geological and hydrological issues that apply to different forms of unconventional gas are also significant. There is no expectation that the harmonised regulatory framework developed for coal seam gas will be extended to apply to shale gas. However, it would be reasonable to expect that a similar harmonisation process may subsequently be implemented for the shale gas industry, and that some of the recommendations in the coal seam gas framework could be incorporated into that process.

Land access In Australia, there is a general principle of multiple land use, which means that different parties may have coexisting rights or interests with respect to the same area of land. The types of land interests that may coexist with onshore petroleum titles include private land; leases from the government for pastoral, agricultural or other commercial purposes; mining (i.e. hard rock mineral)

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tenements; as well as native title rights and interests. Where a petroleum title coexists with private land, operations cannot begin on the private land unless an agreement has been reached with the private landowner as to compensation, or the compensation has been otherwise determined by a court. For other types of land interest, the petroleum title holder is generally not prevented from proceeding with operations, but is required to pay compensation to other lawful occupiers of the land who are adversely affected by the petroleum operations. Where there is conflict between onshore petroleum titles and mining tenements, the relevant state or territory minister makes a decision as to the priority of operations. Registered native title claimants and holders have procedural rights in respect of the grant of new petroleum titles within their native title claim areas. The main native title process that applies is the â&#x20AC;&#x2DC;right to negotiateâ&#x20AC;&#x2122; procedure. This requires the native title parties to be notified of an application for a new petroleum title, be given the opportunity to make submissions with respect to the grant of the title, and negotiate in good faith the conditions on which the title may be granted. This process usually results in the parties also negotiating an appropriate compensation package for the native title party. If agreement cannot be reached, the matter can be determined by a regulatory tribunal. Sites or objects of cultural significance to Aboriginal people are also protected and maintained under legislation. Consent is usually required before Aboriginal heritage sites or objects can be disturbed. Compliance with heritage protection protocols is usually a requirement of most negotiated native title agreements.

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JURISDICTION

LEAD GOVERNMENT AGENCIES

KEY LEGISLATION

Department of the Environment

Environment Protection and Biodiversity Conservation Act 1999

National Native Title Tribunal

Native Title Act 1993

Department of Industry, Resources & Energy

Petroleum (Onshore) Act 1991

Office of Coal Seam Gas

Environmental Planning and Assessment Act 1979

Commonwealth

New South Wales Environment Protection Authority

Water Management Act 2000 NSW Office of Water

Northern Territory

Department of Mines and Energy

Petroleum Act 1984

Environment Protection Authority

Environmental Assessment Act 1982

Department of Land Resource Management

Water Act 1992

Petroleum Act 1923 Department of Natural Resources and Mines

Queensland

Department of Environment and Heritage Protection

Petroleum and Gas (Production and Safety) Act 2004 Environmental Protection Act 1994 Water Act 2000

Department for Manufacturing, Innovation, Trade, Resources and Energy

South Australia

Petroleum and Geothermal Energy Act 2000 Environment Protection Act 1993

Environment Protection Authority

Tasmania

Mineral Resources Tasmania

Mineral Resources Development Act 1995

Department of Primary Industries, Parks, Water and Environment

Environmental Management and Pollution Control Act 1994

Energy and Earth Resources â&#x20AC;&#x201C; Department of Economic Development, Jobs, Transport and Resources

Victoria Environment Protection Authority

Petroleum Act 1998 (coal seam gas) Mineral Resources (Sustainable Development) Act 1990 (tight and shale gas) Environment Protection Act 1970

Department of Mines and Petroleum

Petroleum and Geothermal Energy Resources Act 1967

Environmental Protection Authority

Western Australia

Environmental Protection Act 1986 Department of Water Rights in Water and Irrigation Act 1914

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LOGISTICS

Types of petroleum and related titles Different petroleum titles are required for each stage in the development of a petroleum project. Generally, titles fall into four main categories: exploration titles, retention titles, production titles and infrastructure titles. The terminology varies between Australian jurisdictions, but the most common terms are exploration permit, retention lease, production licence, pipeline licence and infrastructure licence. Exploration titles An exploration title gives the holder the exclusive right to explore for petroleum within the title area. Exploration titles are usually granted for a term of between five and seven years. In most cases they can be renewed, but there is often a requirement to relinquish portions of the title on renewal. Exploration titles usually have minimum work conditions attached to them. Typically, these require a combination of technical, geological and marketing studies, seismic acquisition and the drilling of at least one exploration or appraisal well during the term of the title (and each renewal). The release and award system for petroleum exploration acreage differs between jurisdictions. There is either an invitation and competitive tender process, an open application system or a combination of both. Broadly speaking, for areas where there is significant commercial interest, a competitive tender process is likely to apply. Retention titles In some jurisdictions, a retention title can be obtained over areas where petroleum discoveries are not currently commercially viable but are likely to become commercially viable in the future. The initial term of a retention title is generally five years and may be renewed. When the petroleum discovery is deemed to be commercially viable, the retention title must be converted into a production title. Production titles The holder of an exploration title containing a declared discovery is entitled ‘as of right’ to a production licence over the area containing the discovery. A production title gives the holder an exclusive right to carry out operations (e.g. drilling of developmental wells) for the recovery of petroleum within the relevant licence area. In Western Australia (for production titles granted after May 25, 2011), South Australia and Victoria, onshore production titles are granted on a ‘life of field’ basis. In the remaining jurisdictions (and for Western Australian production titles granted prior to May 25, 2011) the term of a production title can vary from 20 to 30 years, and can be renewed at the discretion of the regulator. Pipeline and infrastructure licences The holder of a pipeline licence has the authority to construct and operate a petroleum pipeline and ancillary storage tanks and facilities. The key difference between onshore pipeline licences and exploration and production titles is that a pipeline licence is usually only a licence to operate the pipeline infrastructure, and appropriate land tenure – for example, an easement over the pipeline land corridor (although separate access rights may need to be obtained). Infrastructure licences are used for the construction and operation of facilities and services outside a production title area. Other petroleum authorities There are also other types of petroleum authorities, such as access authorities and special prospecting authorities. Broadly

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speaking, these authorities allow for the carrying out of certain approved petroleum activities (e.g. seismic surveys) but not the drilling of wells. Access authorities generally only allow exploration survey work to be conducted in areas adjacent to an existing petroleum title. Special prospecting authorities are designed to encourage exploration in areas where little or no exploration has been undertaken. Special prospecting authorities may be applied for with an ‘acreage option’, which enables the holder to apply for an exploration permit within six months of the expiry of the authority. However, the option does not impose any obligation on the Government to grant a title, as title is only granted on the merits of the proposed work program and on satisfying the assessment criteria.

Environmental protection There is a framework of state and Commonwealth legislation applicable to onshore petroleum activities. A number of states have introduced environmental and safety management regulations that are specifically directed at the unconventional gas industry, or primarily impact on it. For example, additional notification and reporting obligations are required for activities involving hydraulic fracturing. This includes disclosure of chemical compounds added to the water injected in fracturing operations. State environmental approvals The environmental regulation of onshore petroleum activity varies between the states and territories, although there are some common features. Most petroleum exploration and production operations require environmental approval under the state or territory petroleum legislation, which is usually issued on the approval of a satisfactory environment management plan. This plan must outline the potential environmental impacts, their significance and how those impacts are to be managed. For hydraulic fracturing activities, it should address, among other things: transport of equipment; fuel, chemical and hazardous materials handling; and management of produced water and flowback fluid. Where onshore petroleum activities are likely to have significant environmental impact, a more comprehensive and detailed assessment is required under the relevant state or territory environmental protection legislation. There are various levels of environmental impact assessment, depending on the environmental significance and complexity of the proposed project. A public consultation process may be required for some projects. Commonwealth environmental approvals Actions that will have a significant impact on a matter of national environmental significance require approval under the Commonwealth environment legislation in addition to state or territory environmental approval. Matters of national environmental significance include listed threatened species and ecological communities, migratory species and areas of high conservation value. Water Access to water is an important consideration for the recovery of unconventional gas. State and territory governments regulate and manage water resources with the aim of protecting them and promoting sustainable and efficient use of water. Licences and permits are issued for water use under specific water rights legislation. Water generally cannot be taken from a watercourse or groundwater aquifer without a licence, and separate licences are required for the operation of artesian wells.

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LOGISTICS

INNOVATION INSTRUMENTAL TO

INDUSTRY DEVELOPMENT

by Bettina Venner and Merril Kirk, South Australian Department of State Development The South Australian Government has been steadily positioning the state as the country’s dedicated champion for the unconventional oil and gas industry. Through its Roundtable for Oil and Gas Projects, the Government is proving to be a critical link in terms of logistics, connecting suppliers of products and services with explorers and producers.

nder the Roundtable for Oil and Gas Projects, the Oil and Gas Supplier Forum (Working Group #6) was established in 2014 to assist in developing South Australian capability in the oil and gas supply chain, and driving down costs for the development of oil and gas resources. This is achieved through educating suppliers about the oil and gas industry, providing opportunities where South Australian businesses could invest, connecting suppliers with oil and gas operators and assisting suppliers to diversify into this sector. On 23 June 2015, around 250 industry people attended the Oil and Gas Supplier Forum held in conjunction with the

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Australian Information Industry Association (AIIA) to hear insights from industry, research institutions and Government. Topics included collaborating to innovate and ICT as an enabling technology for innovation, as well as opportunities in logistics, water and procurement. In the opening session Barry Goldstein, Executive Director Energy Resources, and Paul Goiak, Director Industry Participation, both in the South Australian Department of State Development, set the scene, with the key message being that the industry needs to collaborate and innovate to improve its competitiveness. Innovation will be instrumental in unlocking the value of unconventional gas resources in the Cooper-Eromanga basins, in order to offset the challenges of

operating in remote locations. Examples of challenges include driving in remote areas – a high risk activity with low productivity – and water availability and transport. Procurement managers from Santos, Beach Energy, Senex Energy and Drillsearch Energy spoke about the current state of the oil and gas sector. In the current climate Cooper Basin operators are focusing on decreasing operating costs and positioning their businesses for future opportunities. Companies are now entering shorter-term contracts to share the available work among existing suppliers. Contracting new suppliers is considered to add risk to the business and there is a growing willingness among operators to share equipment and services. Achilles and the Industry Capability

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LOGISTICS

Attendees at the June Oil and Gas Supplier Forum meeting.

Network in South Australia (ICNSA) are independent business networks connecting companies with suppliers. Both networks support suppliers to increase their market reach into the oil and gas sector as well as other sectors. Santos, Senex Energy, Beach Energy and Drillsearch Energy are now requiring their suppliers to be registered with Achilles. As a complementary measure, registering with ICNSA provides an additional platform to connect suppliers with procurement managers across Australia and New Zealand. The water panel consisted of representatives from Santos, Beach Energy, Senex Energy and Strike Energy. They identified opportunities for improving the usage and transport of water in the Cooper-Eromanga basins. There may be opportunities for increased reuse of produced formation water/co-produced water and hydraulic fracturing flowback fluid. Some of this water could be used for enhanced oil recovery and potable water supplies.

The ICT panel representatives from Santos, Beach Energy, Senex Energy and GE Oil & Gas recognised that there is a need to understand technical disconnects between the office, field and overseas workplaces. Cultural change is a key challenge in the introduction of new technology, yet an important issue if these technologies are to be adopted successfully. The top priorities for operators in the Cooper Basin include maximising capability and functionality of existing infrastructure as well as establishing or increasing connectivity in order to create value, improve production, liaise efficiently with multiple locations and improve safety.

What does this mean for suppliers? Suppliers need to work smarter to be competitive, which means thinking differently and approaching old problems with new solutions. First impressions and selling their business value proposition are vital â&#x20AC;&#x201C; explaining how your business will reduce costs and risks, and increase

productivity for your clients. Suppliers need to have a good understanding of the remote environment and infrastructure of the Cooper Basin, how it works and where they might fit in the supply chain. Innovation is key to unlocking the value of the Cooper Basin. The Roundtable for Oil and Gas Projects offers opportunities where businesses with specific capability and expertise are able to pitch to major players in the oil and gas sector. The Oil and Gas Supplier Forum (Working Group #6 under the Roundtable) is planning a meeting on 28 October 2015, focusing on suppliers of water services to the oil and gas industry. The meeting will be held in collaboration with the Water Industry Alliance (WIA), ICNSA and Roundtable Working Group #3 (Efficient and fit-for-purpose water use in the Cooper-Eromanga basins). Companies interested in pitching at this event will need to register their Expression of Interest with the WIA.

For more information on Roundtable for Oil and Gas Projects, see www.petroleum.statedevelopment.sa.gov.au, or to join the Roundtable, submit your contact details to dsd.petroleum@sa.gov.au

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POLICY

SUPPLY AND DEMAND PLAN IN PLACE As the Queensland gas industry makes the shift from exploration to production and export, the State Government has moved to put plans in place to effectively manage domestic and global supply and demand moving forward.

he Gas Supply and Demand Action Plan is being developed in consultation with key industry stakeholders, with the aim of reinforcing Queensland’s status as a lead jurisdiction for onshore gas supply, market development and demand issues. The Queensland Government is committed to effective long-term economic resource planning to achieve state economic objectives which include effective development of the state’s natural gas endowment. The gas sector makes a significant contribution to the state – providing reliable energy and/or feedstock to many households and businesses, and to the world-class LNG sector based in Gladstone, which will deliver billions of dollars of export earnings and royalties over decades to come. It is also a sector undergoing significant transition with a number of opportunities and risks to the state emerging. On the upside, the state’s endowment of gas reserves continues to grow following ongoing land releases and (resources) discovery, but this growth could be stronger. Furthermore, Australian east coast demand for gas is expected to increase from 718PJ to 1,963PJ by 2020 (according to the Australian Energy Market Operator), driven primarily by LNG and also domestic demand. On the downside, high extraction costs and low global oil prices are leading to a scarcity of development capital. Moreover, domestic consumers remain concerned about gas affordability and availability.

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Governments have been responsive to these issues through initiatives such as the COAG Gas Market Development Plan and more recently the Australian Government’s Domestic Gas Strategy. These initiatives aim to increase competitive supply, improve liquidity, transparency, price discovery in trading markets and shore up the sector’s social licence to operate. These are important areas of focus for the next phase of gas market reform and development. Complementing the actions contained in the Domestic Gas Strategy, and working with neighbouring jurisdictions in which Queensland shares its gas resources, now is the time to convert these principles into a holistic, yet focused action plan for the state. The proposed issues paper and Queensland Gas Supply and Demand Action Plan will be developed according to four principal themes: characterising the Queensland gas sector, identifying barriers to achieving least cost supply, ensuring markets are able to continue to evolve and ensuring Queensland capitalises on all possible demand opportunities.

Characterising the Queensland gas sector Including identification of risks and threats to Queensland of exploiting its endowment; defining the gas regions by endowment and likely development and transportation costs under a number of scenarios; defining all existing and potential demand segments and their possible size; and finally, estimating the scope of the potential benefits to Queensland.

Identification of the barriers to achieving least cost supply Including issues around public and private sector Research and Development (R&D) collaboration; adequacy of precompetitive geoscientific information; access to capital, labour and land, including social licence to operate and optimal tenure management and land release strategies; and removing unnecessary regulatory burdens.

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POLICY

Ensuring that markets have adequate information By examining whether markets have enough information to make informed decisions. Ensuring Queensland capitalises on all possible demand opportunities Including opportunities for greater gas fired generation; gas-to-liquid applications; and manufacturing feedstock applications.

The Queensland Government is committed to working closely with stakeholders in the development of the Plan. To be led by the Department of Natural Resources and Mines and the Department of Energy and Water Supply, and with the assistance of the Department of State Development, an issues paper will be released for consultation later this year, with the final plan expected to be completed in the first quarter of 2016.

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Industry and the community will be invited to provide their views.

For more information or to provide input into the Gas Supply and Demand Action Plan, contact the Queensland Government on 13 74 68. SPRING 2015 // ISSUE 2

TECHNICAL

FRACCING 2.0 by Dr Ray Johnson, Principal, Unconventional Reservoir Solutions

Regular contributor Ray Johnson recently attended the 2015 Unconventional Resources Technology Conference (URTeC) in San Antonio, Texas. Here he reports on the latest in technology developments in the unconventional sector, including a continued focus on optimising the hydraulic fracturing process.

SPOTLIGHT ON

recently had the pleasure of serving on the technical committee and attending the 2015 Unconventional Resources Technology Conference (URTeC) in San Antonio, Texas. The event is one of the largest unconventional resource conferences and is jointly hosted by the Society of Petroleum Engineers (SPE), the American Association of Petroleum Geologists (AAPG) and the Society of Exploration Geophysicists (SEG). The event brings in approximately 4,500 delegates from 40 countries and covers all aspects of unconventional reservoir exploration, appraisal and development. URTeC 2016 will again be held in San Antonio, Texas from 1-3 August 2016. With the economic conditions becoming more challenging, you would expect that the downturn would be stifling on a conference being hosted by operators, service providers and technology companies focusing on unconventional resources. Whilst more subdued than 2014, the 2015 exhibition space was large and fairly represented most major suppliers of geophysical, logging, drilling and production technologies. Whilst the industry is being affected by the downturn and many suppliers are being consolidated, developments are continuing and opportunities for production improvement remain a challenge. As many long-term suppliers noted, this isn’t the first downturn in our industry and it certainly won’t be the last! As with previous years, there was particular emphasis in URTeC 2015 on optimising the hydraulic fracturing process and improving the industry’s understanding of the stimulated reservoir volume (SRV) created by the fracturing treatment. This understanding of the SRV is essential to optimise well drainage areas and improve project economics. Despite the number of wells placed in many successful plays, questions remain on how much each horizontal lateral is actually contributing and how stimulation treatments could be optimised further to increase productivity. Whilst many operators are experimenting with lower volumes per stage or reduced perforation clusters to optimise fracturing costs, data analytics and some operator remarks continue to support with data the strong relationship between larger frac volumes, increased number of stages and improved productivity. Hydraulic fracturing fluid load recovery remains an area of uncertainty and several URTeC sessions explored long-term fracture dimensions, whether discrete fracture networks remain open and conductive following a stimulation, and

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Dr Ray Johnson reports on the latest international unconventional developments.

the role of capillary forces in these tight rocks on fluid flowback and recovery after treatments. Increased diagnostic use (e.g. microseismic monitoring) and integration of data with discrete fracture network modelling are being demonstrated as the key to better understanding the role and benefits of fracture complexity to productivity. Whilst the capability of modern computing platforms and models to simulate and history-match treatment diagnostics has improved, there are still concerns over whether we have adequate reservoir information to properly populate these models and provide repeatable solutions to optimise the SRV. As the well drilling activity has slowed, an understanding is starting to emerge of just how large a volume of information was collected at the field and well level by many operators and regulatory agencies during the last period of heightened activity. This data is becoming widely available in the public domain and an area of increased attention by researchers and statisticians, using data mining techniques developed for other large data problems. Unfortunately, without clear guidance from geologists and reservoir engineers to separate this data into representative ‘data domains’, the overall statistics can give vague and sometimes conflicting information, leading to scepticism about whether data analytics alone can provide meaningful trends. From a research perspective, the regulatory stance of gathering adequate completion and production data and

publishing this information for the benefit of the entire industry has been recognised as a key element of the learning process, and may yet identify areas for further technical optmisation. This increased level of data collection and dissemination should be considered for implementation by all Australian state regulatory bodies to increase our understanding of our emerging resource base, especially in areas of high drilling and well density such as Eastern Queensland, where adequate CSG well data could yield a significant and valuable database for further researchers. Ultimately, the main take home message from this meeting continues to be how little of the resource is being recovered on a per well basis from many of these plays despite their overall success. Values of 10-20 per cent recovery are being proposed for many plays that have nonetheless high yield production rates and have effectively changed the domestic energy picture in North America. This illustrates how much technological opportunity still exists in unconventional resource exploitation and how much resource is still unrecovered in many successful North American plays. The emphasis on continuing to share learnings, and the value of multidisciplinary approaches to planning and implementation of exploration, appraisal and development programs continues to be the success story and a continuing theme in the URTeC case history and executive plenary sessions. Planning for the 2016 URTeC is underway and calls for papers will be coming out shortly for the world to again share technical learnings in unconventional resources at the 2016 URTeC. Meanwhile, Australians will have the opportunity to share our unconventional reservoir experiences and hear North American experts discuss their challenges in more detail at the SPE Asia Pacific Unconventional Resources Conference and Exhibition being held in Brisbane from 9-11 November 2015. I encourage all companies to take advantage of this opportunity to participate in a robust technical program and encourage employees to attend, exhibit and share in a multidisciplinary meeting environment covering many Asia Pacific emerging plays. As I noted in my last article, the challenges in Australian unconventional resources are different than North America and will require our combined multidisciplinary experiences to find solutions and develop our vast unconventional resources for the benefit of Australia.

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SPOTLIGHT ON

SURAT BASIN

In this instalment of our regular feature profiling Australian geological basins, we explore the Surat Basin. The Surat Basin contains some of the country’s richest proven coal seam gas resources. The amount of CSG produced from the basin is steadily increasing, and these gas fields are playing a vital role in powering some of Australia’s pioneering CSG to LNG projects. Unconventional gas in the Surat Basin The Surat Basin contains some of Australia’s largest proven coal seam gas reserves. The basin incorporates an area of approximately 300,000 square kilometres, around two thirds of which are located in Queensland and the remainder in New South Wales. Part of the Surat Basin overlies part of the Bowen Basin, which extends over 60,000 square kilometres of Central Queensland. Together these two basins provide the bulk of CSG currently commercially produced in Australia. The basin has been the focus of CSG exploration activities since 2000, and so far significant reserves have been discovered. As of December 2014, the Surat Basin’s proved and probable (2P) CSG reserves were estimated at 33,294PJ (30.62Tcf). Overall, 225PJ (0.21Tcf) of CSG was produced from the Surat Basin in 2014. CSG production from the Queensland parts of the Surat Basin has increased dramatically over the last decade, from none in 2003/2004 up to 0.157Tcf in

2013/2014, making it the highest producing basin in the state. There has also been some exploration and well testing activities targeting tight and shale gas and oil in the basin. Companies including QGC, Beach and Senex have drilled shale gas wells in their acreages. However, the extent of tight and shale oil and gas resources in the basins has not been formally assessed and these resources are not yet being commercially produced.

Unconventional activity in the region Coal seam gas exploration began in the Surat Basin in 2000 and it has since become Australia’s highest producing CSG basin. The potential for commercial CSG production was demonstrated in 2000 with the success of the QGC Argyle 1 well. The first commercial production of CSG in the basin was in the Jurassic Walloon Coal Measures and began in 2006 from the Kogan North CSG area west of Dalby. This was followed in May 2006 by

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production from the Berwyndale South CSG area, south-west of Chinchilla. CSG is also currently produced from several areas between Dalby and Chinchilla. The commercially produced CSG from the Walloon Coal Measures typically comes from seams at depths between 300 and 600m. During the 2011–12 financial year, production of CSG from the Surat Basin surpassed that of the Bowen Basin. Many exploration companies of various sizes operate in the basin, in addition to a number of large energy market players that are producing gas on commercial scale and undertaking other development projects. These include Arrow Energy, Origin Energy, Santos, QGC and Senex. Around 90 per cent of Queensland’s gas needs are currently supplied by CSG, primarily from the Surat and Bowen basins. However, a number of projects are currently underway to realise the potential of this massive gas resource to also supply export markets. Gas fields in the

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SPOTLIGHT ON

Key Statistics Unconventional resources

Proven CSG, potential shale and tight oil and gas Prospective resources

CSG being commercially produced; tight and shale oil and gas not formally assessed 2P reserves

Approximately 30.62Tcf 2P CSG reserves Main troughs

Walloon Coal Measures Key active companies

QGC, Arrow Energy, Origin Energy, Santos, ConocoPhillips, Beach, Senex, APLNG Joint Venture, QCLNG Joint Venture and Santos GLNG Joint Venture. Key projects

QCLNG; Santos GLNG; APLNG; Arrow Surat Gas project; Western Surat Gas project

Surat Basin will also supply gas to three of Australia’s pioneering CSG to LNG projects: the QCLNG project, the GLNG project and the APLNG project. The first shipment of LNG from QCLNG was loaded for export in late 2014. The world-first QCLNG project began construction in 2010 and is one of Australia’s largest capital infrastructure projects, receiving approximately $US20.4 billion of investment from 2010-14. The QCLNG project involves drilling 2,000-plus new wells and constructing 21 new upstream processing facilities in the Surat Basin to expand QGC’s existing natural gas production capacity. A 540km buried natural gas pipeline links the gas fields in the Surat Basin to Gladstone, to be converted to LNG at a plant on Curtis Island, which consists of two processing units, known as trains, with the potential for the construction of a third train. The project is still underway and the second LNG train is scheduled to start up during the third quarter of 2015. After seven years of development, the project

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is expected to reach plateau production in 2016 when it will have an output of around 8.5 million tonnes of LNG a year. The Australia Pacific LNG project (APLNG) will supply gas to both Queensland domestic markets and for export. This project is currently the largest coal seam gas producer in Australia and has passed a significant milestone with the arrival of first gas from the Surat Basin to its LNG facility on Curtis Island in February 2015. This project is a joint venture between Origin (37.5 per cent), ConocoPhillips (37.5 per cent) and Sinopec (25 per cent). The Santos GLNG project is also being developed to convert CSG from the Bowen and Surat Basins to LNG. This $US18.5 billion project is a joint venture between Santos, PETRONAS, Total and KOGAS. The process of commissioning the LNG plant on Curtis Island is underway and the project is on track to deliver its first LNG cargo in 2015. At plateau production it is expected to produce 7.8 million tonnes of LNG each year.

A number of other projects are at various stages of development in the Surat Basin. Arrow Energy intends to expand its CSG exploration, development and production operations in the basin with the Arrow Surat Gas Project. According to the company, the proposed project will provide gas for both domestic and export markets and involve drilling around 6,500 CSG wells. It will also include around 6,000km of gathering lines across the Surat Basin, to move both CSG and water from the wells to centralised gas processing and water treatment facilities. Arrow also proposes the Arrow Surat Gas Pipeline project to construct a major buried gas pipeline from the Surat Basin gas fields to a gas hub 22km west of Gladstone, where it will join the proposed Arrow Bowen Pipeline. Senex has begun an Environmental Impact Assessment process for its proposed Western Surat Gas project. The proposed Western Surat Gas project involves the development of gas fields covering approximately 990 square kilometres of Senex permits north of Roma

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SPOTLIGHT ON

and Wallumbilla in Queensland. These coal seam gas permits are in close proximity to existing gas fields and major transmission infrastructure. Senex expects to submit an Environmental Impact Statement to the Queensland Government in mid-2016 and is targeting first gas production by the end of 2017.

especially when the CSG resources in the area eventually become depleted. The Surat Basin is an extremely significant geological basin for the Australian gas industry and looks set to be increasingly important for both domestic energy and export markets for years to come.

Commercial viability Commercial production of coal seam gas is already established within the Surat Basin and development of further gas fields is underway. The CSG industry has spurred rapid regional development and infrastructure construction in the area, increasing the attractiveness of the region for an increasing number of hydrocarbon exploratory and development activities. The infrastructure associated with the extensive development of coal seam gas in the Surat Basin, including the pipelines connecting the basin to LNG processing facilities, may mean that any tight or shale gas or oil resources confirmed in the future may be more commercially viable,

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Surat Basin

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DEVEL PROJECT

Senex’s acreage in the Surat Basin.

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OPING A STRATEGIC PROJECT

RESOURCE Senex is currently undertaking the Western Surat Gas Project, which aims to develop coal seam gas fields over around 990 square kilometres of the company’s permits north of Roma and Wallumbilla, within Queensland’s Surat Basin. Here, we take a look at what makes this new project particularly exciting for Australia’s unconventional gas industry and examine its progress so far.

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PROJECT

he target for first gas production from the project area is by the end of 2017. The Western Surat Gas Project area includes the highly prospective permits ATP 795, ATP 767 and part of ATP 889, with production expected from the Surat Basin’s Walloon Coal Measures. The target production throughput rate from the project is between 35-50TJ/day. The Surat Basin is already the highest producing CSG basin in Australia and these permits are located adjacent to existing Senex permits and strategic infrastructure. The gas fields also have the potential to feed into Queensland’s LNG export projects once developed. After Senex gained a 100 per cent operated interest in these permits through an asset swap deal with QGC JV in late 2014, the company’s Managing Director, Ian Davies, stated that the Western Surat Gas Project is a key focus for Senex’s long-term strategy. “The completion of this transaction is a milestone in Senex’s longer term strategy to capitalise on the strength of Australia’s east coast gas market. We expect to see unprecedented demand growth resulting in supply pressures and strong gas pricing. The Western Surat Gas Project is ideally located to capitalise on this opportunity, situated within the proven hydrocarbon province of the Surat Basin and with extensive infrastructure adjacent to the acreage. “It’s exciting to now be in a position to progress our work on this project towards on ground activities in FY16,” he said.

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Forging ahead Since the project began in 2014, a number of milestones have already been achieved. These include the initiation of environmental and regulatory approvals processes, and the establishment of a local presence and project team. In its latest quarterly report, Senex reported that the project scope has been defined and planning activities are well progressed. During the quarter ending 30 June 2015, Canadian firm Equinox Engineering delivered the initial Concept Select study to identify the best value surface facility options for the initial phase of a full field development. The cost estimates for the surface facilities were in line with expectations and confirmed the achievability of a low cost approach to full field development. Senex expects to enter into Front End Engineering and Design (FEED) during FY16 to further progress the study’s recommendations and tighten the estimated range over the total installed cost. Early indications suggest that cost savings may be achievable through: ♦♦ Incorporating best practices from low cost examples in the global gas industry. ♦♦ Utilising lessons learned from similar project developments, especially in Queensland. ♦♦ Modularising equipment as far as is practicable to reduce site construction time and expense. ♦♦ Designing equipment and facilities to ensure flexibility to

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PROJECT

accommodate changing field operating conditions. The company intends to commission existing pilots during FY16. The preparatory activities before the pilots are brought online for testing will include land access arrangements, along with the design, engineering and construction of surface infrastructure. Mr Davies commented, “Pilot testing will allow the compilation of dynamic data related to the production characteristics of the reservoir, which is essential for delivering an efficient and cost effective full field development.” Existing and pilot data will be used to confirm development planning assumptions and help determine: ♦♦ Drilling (locations, completion design). ♦♦ Project size (surface facilities, optimal plateau production rates). ♦♦ Water disposal (facilities options). Senex also plans to submit an Environmental Impact Statement (EIS) to the Queensland Government in mid-2016.

Technical studies, environmental surveys and baseline assessments have already taken place, along with key stakeholder consultation activities with landholders, the local community and the native title group for the area. As part of its engagement strategy, Senex also established a local presence by opening a small office in Roma in April 2015. “The Western Surat Gas Project represents a key pillar of our long-held strategy to diversify and build on our oil exploration and production business. The Senex team is working hard towards a Final Investment Decision to bring this material CSG resource to market,” Mr Davies said. Overall, the Western Surat Gas Project presents an extremely exciting opportunity for Senex and for the Australian unconventional gas industry as a whole. This project has the potential to supply both domestic Australian energy markets and help tackle potential LNG export supply shortfalls, putting Senex in a strong position for long-term growth.

The current state of play Senex is currently progressing its regulatory approvals. A draft of the Western Surat Gas Project’s Terms of Reference for the EIS will be released for public comment during 2015. The current environmental approval applications for the project, including the EIS, allow for the staged drilling of up to 1,000 wells over approximately 30 years. However, considering factors such as market conditions, exploration results and technology improvements over time, it is expected that significantly fewer wells will need to be drilled over the period. Ian Davies.

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THE GOOD OIL with Paul Carter

THE GREAT

n breaking news, it turns out the entire planet isn’t a huge ball of oil with a thin layer of topsoil covering it after all. Oh dear. Add to that the current and completely horrible oil and gas ‘downturn’ as it’s being referred to (I prefer the term ‘depression’), and the future for our industry is in a state of flux. Lots of industry experts have an opinion, multinationals spend lots of money trying to predict the future, and there is literally an unprecedented amount of reading material designed to help you see our industry’s trajectory and plan ahead. I have one on my desk right now, as thick as the phone book called The Oil Price Plummet: Deciphering the Fallout. It’s proving useful as a stand for my computer screen but as far as reading it goes – well, I’m waiting for the ‘For dummies’ version. Or even better, the ‘For dummies audio book’, or the pinnacle, ‘For dummies, 3-D, pop-up, scratch-n-sniff free poster edition’. I would totally read that.

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So many colleagues have been made redundant, two-thirds of everyone I know in the energy sector over 40 is currently looking for a job. When I realised this I started worrying about my job and almost tripped over myself in a dash to the bookshelf for my trusty ‘Dealing with Redundancy’ guide book. In the past you could ask the government to help - try that shit now! They have some really good advice on securing the future and job security, provided of course you’re a middle aged, hetero fat cat who has the benefit of a classical education. And by classical, I mean free. In my despair I called a friend, a man I look up to, a man who guided me through my career and once even saved my life. So when he speaks, I listen. I was in Sydney, on my way to meet him at an old pub in Surry Hills – I remember it well from the days when I was offshore but home and getting my drunk on. It loomed over the crest like an old smog stained deco giant, curved fascia bending

the June late afternoon sun across its ajar porthole windows, deflecting its light back toward the sky. But on this day as I walked along a bizarrely chilly Hunt Street in Sydney’s inner east, up the hill from Wentworth Avenue, I thought how apt it was that the man I was coming here to meet should choose a bar called ‘Hollywood’. Back in the day, Sydney’s pubs were named based on the nearest source of business (the Cricketers Arms, the Railway Hotel, The Brothel Creepers Inn, you get the drift). But here in Surry Hills – well, it’s not Hollywood is it? The man I’m about to meet is Erwin Herczeg, my former boss. He’s a ‘company man’ now and has been at the pointy end of oil and gas for almost 40 years. What leaps he has seen over the years – Erwin comes from those hard places where the drill floor was dangerous, because of where it was in the world; and because hi-vis, drug testing, QHSE, preventative maintenance and the internet had not been invented yet. Men threw chain, stood up to

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DEPRESSION

OF 2015

manian

experimental KPH on an untested attEmPtInG 300 ered a perfect way to kill yourself, r at be consid caRter and dange motorcycle could er is still, well, paul d name. but paul caRt secon his is high speed Whether discovering that being dyslexic means delivering your lines to camera back to front in the midst of filming a TV series, or starting a new business and travelling the world, or dealing with life’s more sober moments like the birth of a son or the loss of a father, paul caRter is still the funniest man in the bar and the nicest alpha male you’ll ever meet as he risks all for the sake of a good story.

and bRacE yOURself fOr His so be fOURtH bOoK—we aLl remaIn HOPeful tHat He wilL NOt InstItUtIONalised befOre cOmpletiNG His fiftH.

www.pcarter.com.au

paul carter

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sunDaY tas

YOU’Ll

to come to a Wiggles concert, then smiled, took a deep breath, and, like a man who’s just been asked for the millionth time in his life to explain why grass is green or why women have secrets, he picked up a shot of bourbon, necked it, and slowly he waded into the quiet of the stream. He paused there in its stillness and looked up at the long difficult climb beyond the ceiling, up the Everest of an explanation to the summit of why I need to stop worrying and just start living. Six hours later I was completely clued up and more than a little drunk. The oil ‘caRter is a KInd Of moDERN Da industry is just full of ruthless self-servinga natUYRaiNLDIstaNOraYtJonEs . . . elLER.’ bureaucratic robots now who would gladly take your head off with a shovel, I thought to myself. And guess what? It is. You just have to remember that it will bounce back. And one day, some younger person in the midst of some new depression will be sitting yOURself In straPin their own Hollywood, asking you exactly what the hell they should do.

RIDE LIKE HELl aND Get tHere

pee, and drank to get drunk. I thought about that as I shouldered into the ancient oak and brass bolstered door, keeping my cold hands buried in my trouser pockets. I thought about our impending conversation – don’t mention the smell, open the conversation with something clever and funny. The door’s return spring dragged the leading edge across the remains of my shoulder and slammed shut with a loud resolute bang behind me. The usual ragtag ensemble propped up the bar, nursing their beers and pondering the pokies while Flame Trees hung in the air over an ancient jukebox. There was a “Welcome to Hollywood” nod from the barman and I nodded back, scanning the bar looking for my friend. There he was right at the end. “So,” he opened, grinning at me. “What’s on your so-called mind, son?” Before I can stop myself, I start to ramble on about this great oil and gas depression and what I’ll do if I get my marching orders. He looked at me like I’d just asked him

Paul Carter has written three international best-selling books, including the famous (or should that be infamous?) Don’t tell mum I work on the rigs, she thinks I’m a piano player in a whorehouse and Ride like hell and you’ll get there: detours into mayhem. Paul has sold over two million books worldwide and his first two books are currently being turned into a feature film. Paul grew up in Aberdeen, Scotland’s oil capital, and moved to Perth at the age of 15. By the time he was 16, he was working on drilling tools. Paul has clocked up 20 years of experience out in the field, working in Australia and far-flung destinations around the world, avoiding coups, jihadists and wars – all in the name of blessed hydrocarbons.

RIDE LIKE HELl aND YOU’Ll

Get tHere DEtOURs iNto

maYHem

paul carter

Cover design: Design by Committee

MEMOIR Ride_Fullcover.indd 1

16/08/13 12:44 PM

SPRING 2015 // ISSUE 2

FEATURES SCHEDULE

Summer 2016 MAJOR FEATURE

Autumn 2016 Safety

MAJOR FEATURE

ICT

Personal safety gear, facility safety

Telecommunications, radio, SCADA,

equipment, gas monitoring equipment

IT, security, big data, mobile devices, cloud computing

PRODUCTS SHOWCASE

Pipes and processing

INDUSTRY ANALYSIS

Performance scorecard

BASIN FOCUS

Canning

GEOGRAPHIC FOCUS

South Australia

DISTRIBUTION

Australian Oil & Gas (AOG)

PRODUCTS SHOWCASE

Exploration and seismic

INDUSTRY ANALYSIS

Regulatory review

BASIN FOCUS

Amadeus

GEOGRAPHIC FOCUS

Northern Territory

Perth, February 2016

Winter 2016 MAJOR FEATURE

Spring 2016 Drilling equipment

MAJOR FEATURE

Logistics

Rigs and rig technology, rig maintenance,

Land access and management,

fraccing, fluids and proppants, water

road construction, accommodation,

management

rig maintenance, recruitment and HR

PRODUCTS SHOWCASE

Sustainability

PRODUCTS SHOWCASE

Water management

INDUSTRY ANALYSIS

Global energy outlook

INDUSTRY ANALYSIS

Reserves update

BASIN FOCUS

Beetaloo

BASIN FOCUS

Gunnedah

GEOGRAPHIC FOCUS

Western Australia

GEOGRAPHIC FOCUS

Queensland

ADVERTISERS’ INDEX

ATSE...................................................................................39

Pivotel............................................................................OBC

High Country Fusion �� 3

Pressure And Safety Systems ��13,21

Made to Measure �� IBC

SGS.....................................................................................49

Pipe & Valve Engineering �� 9

Vermeer.........................................................................IFC-1

SPRING 2015 // ISSUE 2

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