Unconventional OIl & Gas Summer 2016 Digital edition by Monkey Media

UNCONVENTIONAL Issue 3 // SUMMER 2016

RISKY REWARDS AND INDUSTRY SAFETY

SOUTH AUSTRALIA:

THE HOME OF UNCONVENTIONALS?

THE FRACCING MEDIA: FROM GOOD NEWS FOR BUSINESS TO GOOD FOR THE NEWS BUSINESS

STATE BY STATE REPORT CARD: WHO PASSED AND WHO FAILED THE UNCONVENTIONAL TEST?

OPINION PETER COOK: THE SCIENCE ON UNCONVENTIONALS IS IN

TECHNICAL JOHN HODAY ON WELL ENHANCEMENT

RAY JOHNSON: WHAT CAN WE POSSIBLY LEARN FROM ANOTHER UNCONVENTIONAL CONFERENCE?

STORAGE GLEN GILL ON OPTIMISING CSG PRODUCTION

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UNCONVENTIONAL

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Issue 3 // SUMMER 2016

UNCONVENTIONAL Issue 3 // SUMMER 2016

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UNCONVENTIONAL OIL & GAS

RISKY REWARDS AND INDUSTRY SAFETY

SOUTH AUSTRALIA:

THE HOME OF UNCONVENTIONALS?

THE FRACCING MEDIA: FROM GOOD NEWS FOR BUSINESS TO GOOD FOR THE NEWS BUSINESS

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STATE BY STATE REPORT CARD: WHO PASSED AND WHO FAILED THE UNCONVENTIONAL TEST?

OPINION PETER COOK: THE SCIENCE ON UNCONVENTIONALS IS IN

TECHNICAL JOHN HODAY ON WELL ENHANCEMENT

RAY JOHNSON: WHAT CAN WE POSSIBLY LEARN FROM ANOTHER UNCONVENTIONAL CONFERENCE?

STORAGE GLEN GILL ON OPTIMISING CSG PRODUCTION

27/11/2015 9:19:44 AM

Cover image highlights our report card analysis on the way the states and territory view and regulate the unconventional oil and gas industry.

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

Publisher and Editor Chris Bland Managing Editor Laura Harvey Associate Editors Michelle Goldsmith Emily Thomas Journalist Jessica Dickers Marketing Director Amanda Kennedy

FROM THE PUBLISHER

new year brings the chance for reflection on the year that was; and for reinvigorating and recharging for what lies ahead. There’s no denying the challenging conditions we’re currently facing in the oil and gas industry – the market remains in a chronic state of oversupply and prices are at levels few would have predicted as little as two years ago. But when times are tough, one thing that we can focus on is the opportunity for innovation. We need to look for new ways of doing things, the industry as a whole needs to be leaner than it has ever been before, and we need to be smarter in our operations. In short, we need to be unconventional in our thinking. The companies that survive this downturn will be those that can be quick, agile and capable of thinking a little bit differently to solve the problems they face. In many ways these challenges have been somewhat of a theme in this issue, with technical experts including Peter Cook, Ray Johnson, Glen Gill and John Hoday sharing their expertise in subjects including well enhancement and CSG production optimisation. While our business as magazine publishers is a little different to the explorers, producers and suppliers in this industry, we too have had to be unconventional in our thinking in order to keep moving forward in the current climate. Where many publishers have reduced their circulation or moved their print publications online, we’ve taken the opposite approach and grown our

circulation - to the point where Unconventional Oil and Gas is now Australia’s most widely circulated oil and gas magazine. Each quarter, 4,921 copies of this magazine are distributed amongst the industry, more than any other oil and gas title published in Australia. We understand that our audience is our greatest asset; and reducing the number of people we communicate to would be a short term strategy that would ultimately fail. I’m proud of the fact that we are Australia’s most widely read oil and gas magazine, and together with the entire Unconventional Oil & Gas team, I look forward to bringing you more news, opinions and insights into riding out the challenges we’re currently facing, towards a more fruitful future. Chris Bland Publisher and Editor

Marketing Consultants Aaron White Jordan Harbinson Graphic Designer Alejandro Molano Creative Director Sandy Noke

UNCONVENTIONAL

4,921

OIL GAS

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

Audit Period: 01/04/2015 – 30/09/2015

SUMMER 2016 // ISSUE 3

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CONTENTS PERFORMANCE SCORECARD Unconventional attitudes: a state-by-state analysis.................................12

Australia has significant unconventional oil and gas potential, with prospective resources identified in a large number of basins around the country. However, policies regarding and attitudes towards unconventional gas development vary greatly across Australia. In this article, we explore the status of unconventional oil and gas development in each state.

SOUTH AUSTRALIA

There’s something about South Australia................................................ 18

South Australia has huge potential when it comes to unconventional hydrocarbon resources, with potential reservoirs of shale oil and gas, tight oil and gas, and CSG identified in basins across the state. We take a closer look at what makes South Australia the place to be for unconventional oil and gas.

SAFETY

Safety first: how bonuses affect organisational safety..........................24

The oil and gas industry is committed to ensuring the health and safety of its operations, but major catastrophes can and do occur. Occupational health and safety experts Professor Andrew Hopkins and Assistant Professor Sarah Maslen have conducted groundbreaking research into the impact corporate pay packages can have on the overall safety of companies in the resources sector, and the authors share some of their insights here.

TECHNICAL

Evaluation of thermal maturation (rank) of sedimentary rocks – more than just vitrinite reflectance..............................................30

Vitrinite reflectance (Vr ) has many advantages in evaluating the degree of thermal maturation of sedimentary rocks. Values are tightly constrained for a given palaeo temperature and change rapidly as a function of temperature. It is extensively used in modelling basin history. Indeed, it is so valuable a tool that it is commonplace to see Vr quoted for pre-Devonian rocks even though it is not possible for vitrinite to be present.

COMMUNITY

SUMMER 2016 // ISSUE 3

From good news for business to good for the news business.............34

At the turn of this century, unconventional gas was just another mostly positive resources story running in the Australian business news sections. By 2011, the industry’s media coverage was vast in volume and rancorous in tone. To unravel what happened to precipitate the media storm, media scholar Libby Mitchell teamed up with computer scientist Dan Angus to conduct a systematic, longitudinal analysis of what was, at that time, the most toxic and polarised public controversy in Australia.

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CONFERENCES

The science on unconventionals is in........................................................40

The ATSE International Conference on Unconventional Gas was an unprecedented gathering of the global scientific community, providing an opportunity to critically analyse the evidence relating to the opportunities and the challenges of unconventional gas.

What can we possibly learn from another unconventional conference?.......................................................................46

OPINION

Well enhancement: the production perspective..................................... 50

Here, John Hoday asks - is the practice of well enhancement overused or simply misunderstood?

STORAGE

Optimising CSG production with underground gas storage facilities.....................................................................................54

With Queensland’s CSG to LNG industry now exporting to the world, we take a look at the innovative technology that can help to optimise production, protect against outages and ensure security of continuous supply to our valuable international trading partners.

RESOURCES

Further afield: where’s the oil and gas?................................................... 60

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. All cylinders firing: GLNG joins the export ranks.................................... 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

Andrew Hopkins

John Hoday

Peter Cook

Professor Australian National University

VP Energy Services NauticAWT Energy Solutions

Professorial Fellow The University of Melbourne

Emeritus Professor Andrew Hopkins is an internationally-renowned presenter, author and consultant in the field of industrial safety and accident analysis. Professor Hopkins has been involved in various government occupational health and safety (OHS) reviews and completed consultancy work for major companies in the resources sector.

John Hoday has several decades of expertise in the area of well enhancement production and optimisation. Currently he is the VP Energy Services for NauticAWT Energy Solutions, offering subsurface, subsea and surface facilities, engineering services and contracting solutions for field exploration, field development and field refurbishment for mature and ageing oil and gas assets. Mr Hoday has previously worked for companies including Petro King and Arrow Energy, where he was responsible for guiding the Petroleum Technology Engineering group in well design and sub-surface technologies.

Professor Peter Cook is one of Australiaâ&#x20AC;&#x2122;s foremost scientists in the areas of energy and greenhouse technology. Professor Cook has occupied a number of senior executive positions during his career. He was Executive Director of British Geological Survey (1990â&#x20AC;&#x201C;98) and prior to that, Associate Director of the Bureau of Mineral Resources (now Geoscience Australia). In 2003, following five years as the Executive Director of the Petroleum Cooperative Research Centre, Professor Cook initiated the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) and served as its Chief Executive until 2011. He has been a consultant and adviser on resource and energy issues in Australia and internationally for many years.

SUMMER 2016 // ISSUE 3

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Glen Gill

Ray Johnson

Paul Carter

Managing Director Innovative Energy Consulting

Principal Unconventional Reservoir Solutions

Sales and Marketing Manager Upstream SGS Australia

Glen Gill is a senior Energy Executive/Gas Advisor who has worked with a number of world leading companies operating across the gas industry value chain. He has been providing advisory services to companies, industry associations and governments on a variety of commercial gas industry issues and opportunities since the late 1990s. He has a track record of leading very successful gas supply and marketing operations while optimising assets associated therewith.

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.

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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SUMMER 2016 // ISSUE 3

NEWS

NEGI GIVES UNCONVENTIONALS A BOOST

hen the Northern Territory Government confirmed Jemena as its proponent for the North East Gas Interconnector (NEGI) pipeline, it provided unconventional gas explorers with a major boost. The new pipeline, linking gas in the Northern Territory with east coast markets, provides a huge incentive for explorers to head to the Territory and investigate the production of previously trapped resources, just as the domestic east coast market faces considerable shortages and Asian export markets remain hungry for Australian gas. The 622km pipeline will cost $800million to construct and the chosen route will run between Tennant Creek in the Northern Territory and Mount Isa in Queensland. The chosen route was one of two options, with the other proposal running from Alice Springs in the Northern Territory to Moomba in South Australia. Of the two routes, the chosen route is considerably cheaper and quicker to construct, and it doesn’t rely on government funding. The proposed southern route would have been more expensive to construct and may have needed government funding. However, its supporters argued that it would have provided more long term benefits for the east coast domestic gas market. The project is expected to stimulate exploration and production of shale gas resources in the Territory, as well as promote infrastructure and economic development in Australia. Northern Territory Chief Minister, Adam Giles, said “This nationbuilding project will generate investment in regional infrastructure and deliver real jobs with no financial commitment from taxpayers. This is a great outcome and shows governments can deliver major infrastructure projects through a robust competitive process. “Without this pipeline, the populated parts of Australia would have huge difficulty securing their energy needs.” It is estimated that the Territory has more than 200 trillion cubic feet of gas – potentially enough to power Australia for more than 200 years. Mr Giles said the reason the northern route proposal from Jemena was chosen was because it offered cheaper tariffs, cheaper gas processing costs and the option to increase the capacity of the pipeline prior to the laying of the first pipe if market conditions support increased capacity. Jemena Managing Director, Paul Adams, said the pipeline would fast-track development of the Northern Territory’s gas industry. “Building the NEGI will drive commercial exploration and development of currently untapped gas reserves, unlocking the next phase of economic growth for the Territory and helping build a stronger Northern Australia,” Mr Adams said. “The pipeline is cost-effective and relatively quick to build, so it will support a strong gas industry for the Territory by getting gas to market at a competitive price, accelerating development of NT gas fields and helping create jobs and opportunities in the gas industry. “As further reserves in the NT are proved up, we can expand our scalable pipeline to meet strong demand from east coast customers.” Mr Adams said he believed routing the pipeline to Mt Isa was the most efficient way to get gas to the east coast, as it reduced potential construction risks and required lower volumes of gas to be contracted to be viable. “As soon as sufficient gas is proven in the Northern Territory, Jemena will seek to build a further link connecting Mt Isa to

SUMMER 2016 // ISSUE 3

The route for the NEGI Pipeline.

the Wallumbilla hub in Queensland. This will vastly improve the reliability of the gas transmission network by reducing sole reliance on Moomba as the hub for supplies. It will also introduce some much-needed competition into the east coast market, while accelerating the growth of the NT gas sector. “By linking the Territory’s vast resources into the east coast network, NEGI will be the foundation of a more robust, competitive Australian gas market,” Mr Adams said. The first supplies of gas to sustain the pipeline will come from existing offshore and onshore gas reserves. Power and Water Corporation (PWC) will supply gas to the NEGI from its contracted suppliers, as the quantity of gas PWC is entitled to under its contracts far exceeds the amount needed to meet the NT’s energy needs. PWC will use a gas sales agreement with Incitec Pivot to lock in a guaranteed gas supply for approximately 10 years from the completion of the NEGI to 2028. Incitec Pivot Chairman, Paul Brasher, said the long term gas supply agreement with Power and Water Corporation and pipeline development is a step change in the continuing development of Northern Australia. “It will underpin existing regional jobs and create opportunities for many future investments,” Mr Brasher said. Mr Giles said the new pipeline sets up a long term framework to increase gas supply, create a more competitive energy market and provide increased access to clean energy for local industry, Territory electricity generation and the eastern Australian gas market more generally. Construction of the NEGI pipeline will create more than 900 jobs during construction, 600 of which will be for locals and offer up to 100 contracts for local businesses worth about $112million. There will be ongoing maintenance and operations teams based in Tennant Creek and Mt Isa. Jemena expects construction of its 14 inch pipeline to be completed by 2018.

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NEWS

WESTERN SURAT GAS PROJECT FINALISED

enex Energy Limited and GLNG have finalised the transaction for the development of the Western Surat Gas Project in Queensland. Senex’s Western Surat Gas Project represents an opportunity to develop a major new revenue stream from a large 2P reserve base in a strategically located gas producing region. The combined effect of the two agreements is to significantly de-risk the advancement of the project by delivering a clear commercialisation and financing pathway, allowing access to GLNG infrastructure, and providing valuable subsurface data. The binding 20-year sales agreement means Senex will supply up to 50TJ/day of sales gas from its Western Surat Gas Project to GLNG. Senex Managing Director, Ian Davies, said it was a transformational deal for the company, and would underpin the development of a long term, material and sustainable East Coast gas business for Senex. “The completion of this transaction is a milestone in Senex’s strategy to capitalise on the growth in Australia’s East Coast gas market. The transaction enhances our financial position today, and should result in the Western Surat Gas Project contributing material gas volumes and significant cash flow to Senex over the next 20 years,” Mr Davies said. Mr Davies said the gas sales agreement they struck with GLNG gives Senex optionality over their gas profile, allowing them to stage development and ramp up volumes to ensure the optimum economic outcome for the project. “We are hard at work defining the economic and operating parameters of the project and will commence on the ground appraisal activities in the second half of FY16,” Mr Davies said. Senex has received $42million in cash and a comprehensive suite of subsurface, production and other technical data, in exchange for the sale of the Maisey block to GLNG.

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SUMMER 2016 // ISSUE 3

NEWS

BEACH, DRILLSEARCH MERGE

each Energy and Drillsearch have agreed to merge, coming together to create an oil and gas mid-cap powerhouse of the Cooper Basin. The two companies have been on the same page strategically for some time – both are focused on the Cooper Basin, and using a strong position in the basin to exploit opportunities in the east coast gas market and underwrite emerging opportunities in Australia and nearby. Further adding to the strong logic for combining the two companies is the fact that more than 90 per cent of Drillsearch’s FY2015 production has been in joint venture with Beach. In the current climate, where merger and acquisition activity is strong, verging on frantic, the coming together of these two companies has been seen by many as almost a foregone conclusion. This has particularly been the case since May 2015, when the Kerry Stokes-controlled Seven Group Holdings increased its ownership in each company to 19.9 per cent – the maximum level of ownership one company can have over another before launching a takeover bid.

SUMMER 2016 // ISSUE 3

The combined entity, which will see Drillsearch shareholders come out of the deal with 1.25 Beach shares, will emerge as Australia’s largest onshore oil producer with a market capitalisation of more than $1.5billion. In presenting the merger to shareholders, Beach and Drillsearch have positioned the combined entity as being primed to pursue growth opportunities with emphasis on the opportunities presenting themselves in the east coast gas market. From an operational perspective, the coming together of the two companies will be focused on retaining the best talent from both companies. Clearly there will be job losses as the two companies merge to create a more streamlined entity. Drillsearch Chairman Jim McKerlie and Director Phil Bainbridge will join the Board of combined group, with two Beach Directors to step down. Beach is currently in the process of recruiting a Chief Executive Officer who will ultimately lead the merged group.

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NEWS

SHELL, BG GROUP MERGER CROSSES FINAL HURDLE

he merger of Shell and BG Group has crossed its final hurdle, receiving final clearance from the Chinese Ministry of Commerce (MOFCOM) – but the news came as the oil and gas giant warned the merger may cost up to 2,800 jobs. The Chinese antitrust clearance marks the final pre-conditional approval required, following previous acceptance by the Australian Foreign Investment Review Board (FIRB). The merger will include restructuring of both groups in order to achieve the expected benefits of the recommended combination, including previously disclosed and reported-on pre-tax synergies of $3.5billion. Shell’s expectation is that BG’s business will be integrated into Shell’s businesses and office consolidation will take place around the world, where practical. Shell said it expects a loss of 2,800 roles globally across both companies, or approximately 3 per cent of the total combined

group workforce. These reductions are in addition to the previously announced plans to reduce Shell’s headcount and contractor positions by 7,500 globally. Further detailed work will be undertaken on the details of the proposed operational and administrative restructuring as part of ongoing integration planning. Shell CEO, Ben van Beurden said, “We’re grateful to MOFCOM for its thorough and professional review of the recommended combination, and I am delighted we now have all the preconditional approvals needed to move to the next important phase. “This is a strategic deal that will make Shell a more profitable and resilient company in a world where oil and gas prices could remain lower for some time. We will now seek approval from both sets of shareholders as we move towards deal completion in early 2016.”

METGASCO ACCEPTS BUYBACK OFFER

etgasco shareholders have voted to accept the NSW government offer to buy-back three exploration licences for a sum of $25million. Under the accepted agreement, the NSW Government has acquired Metgasco’s three Northern Rivers petroleum exploration licences, PEL 13, PEL 16 and PEL 426. The agreement also settles legal disputes with Metgasco in relation to the unlawful suspension of its Rosella drilling approval. Prior to the vote, Metgasco’s Board of Directors told shareholders that acceptance of the proposal was in the company’s best interest. Metgasco Chairman, Leonard Gill, in his address prior to the vote said, “It must be recognised that today is a very disappointing day for all those who have believed in a vision of gas production

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in the Northern Rivers region and in particular for our long term shareholders.” “Shareholders have a right and responsibility to consider the resolutions put forward today through the prism of the impact on their individual interests. “The responsibility of the Board is different. The Board must act and make recommendations in the best interests of the company, and consider the interests of all shareholders. “We invite shareholders to support the Board’s recommendation to accept the NSW Government’s $25million buy back offer. Irrespective of which way individual shareholders vote, if shareholders as a whole vote to accept the offer, we invite all shareholders to support the new direction for your company,” Mr Gill said.

SUMMER 2016 // ISSUE 3

PERFORMANCE SCORECARD

Unconventio a state-by-state analysis

SUMMER 2016 // ISSUE 3

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PERFORMANCE SCORECARD

nal attitudes: Australia has significant unconventional oil and gas potential, with prospective resources identified in a large number of basins around the country.

However, policies regarding and attitudes towards unconventional gas development vary greatly across Australia. While some states actively seek to develop their unconventional gas industry others have moratoriums on unconventional exploration and development activities. In this article, we will explore the status of unconventional oil and gas development in each state, examining the existing policies and prevailing attitudes of state governments towards the industry and how these relate to the attractiveness of each state for unconventional oil and gas investment.

South Australia South Australia has very large potential unconventional gas resources, including those within the Cooper Basin – considered one of the most prospective areas for shale gas and oil development within Australia – with a number of producing wells already drilled. A variety of significant projects are underway to develop the state’s unconventional resources, including the South Australian Cooper Basin Joint Venture exploration program. Exploration activities are also underway in the Arckaringa and Otway basins. Unconventional oil and gas exploration and development activities within the state are regulated by South Australia’s Petroleum and Geothermal Energy Act 2000 (P&GE Act) and the accompanying Petroleum and Geothermal Energy Regulations 2000. The State Government is generally very supportive of unconventional oil and gas development, and South Australia was the first Australian state to launch a comprehensive plan for the development of its unconventional gas resources in their Roadmap for Unconventional Gas Projects in South Australia. Yearly roundtables are held to discuss ways to implement the recommendations from the Roadmap for Unconventional Gas

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A Projects in South Australia and report on its progress. These include representatives from local and multinational companies, peak representative bodies for industry and environment, agencies from Australian States and Territories, Federal Governments and research institutions. Research activities that have been funded to better understand the scale of SA’s unconventional resources and how best to develop them include the creation of the Cooper Basin atlas: understanding Australia’s premier onshore hydrocarbon province, GeoFrac and an Australian Research Council (ARC) project to develop an integrated approach to unconventional gas exploration and development. A number of working groups have also been established to address issues facing the industry. The Fraser Institute’s 2015 Global Petroleum Survey ranked South Australia as the twelfth most attractive jurisdiction for oil and gas development in the world, the highest rank of all Australian states.

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PERFORMANCE SCORECARD

The CSG to LNG industry in Queensland is well-established and now delivering gas to international trading partners.

Queensland Queensland is currently the largest unconventional gas producer in Australia, with a well-established coal seam gas industry producing gas from the Surat and Bowen basins. Commercial coal seam gas production began in the Bowen Basin in 1996. In 2013/2014, 0.0996Tcf of CSG was produced in the basin. 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 Australiaâ&#x20AC;&#x2122;s pioneering CSG to LNG projects, the QCLNG project, the GLNG project and the APLNG project. Shale and tight oil and gas assessment activities are also underway in these basins, as well as within the Queensland parts of the Cooper Basin. Other Queensland basins with unconventional

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A potential include the Clarence-Moreton Basin (CSG), the Maryborough Basin (tight gas, shale gas, CSG), the Galilee Basin (tight gas, shale gas, CSG) and others. The Queensland Government is highly supportive of unconventional oil and gas development, with initiatives in place such as the $30million Future Resources Program, which aims to maximise exploration success by supporting Queenslandâ&#x20AC;&#x2122;s resource and exploration industries; the $18million Greenfields 2020 program; the ResourcesQ Cooper Basin Industry Development Strategy; and the Queensland Gas Supply and Demand Action Plan, expected to be finalised in the first quarter of 2016. Some of the largest unconventional gas projects underway in the state include the Surat Gas project, Western Surat Gas project, Bowen Gas project, Moranbah Gas project and Nappamerri Trough Natural Gas project.

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PERFORMANCE SCORECARD

Western Australia Potential tight and shale oil and gas resources are thought to exist throughout Western Australia, including within the Perth, Canning and Bonaparte basins. 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. A number of companies are currently undertaking exploration and well testing activities in order to determine whether these resources can be developed economically. The Western Australian Government has a number of programs underway to support development of hydrocarbon resources in the state. In December 2015, the government awarded a $5million contract as part of a $7.3million expansion of the Perth Core Library to assist exploration for mineral and petroleum resources. In November 2015, the final report of a two-year parliamentary inquiry into fraccing suggested that Western Australia’s regulators were well prepared to manage the developing shale and tight gas industry and associated hydraulic fracturing processes. In July 2015, the Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations 2015

B+

came into effect. These regulations provide a risk-based management scheme for the exploration for, and production of, petroleum energy resources. A range of resource management and administration matters are covered by the regulations, including well management plans for the approval of all drilling activities (including shale and tight gas), notification and reporting of discovery of petroleum; field management plans and approvals of petroleum recovery. Acreage releases are generally made twice a year for the areas within Western Australia’s jurisdiction. Currently, the government is accepting applications for PELs within the Canning Basin and Northern Carnarvon Basin. However, Western Australia currently has a domestic gas reservation policy in place which requires new gas developments to supply the equivalent of 15 per cent of their gas exports to the Western Australian domestic gas market.

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PERFORMANCE SCORECARD

Northern Territory The Northern Territory’s unconventional oil and gas industry is still at an early stage, although potential resources have been identified in a large number of basins around the state, including the Georgina Basin, McArthur Basin/Beetaloo Sub-basin, Amadeus Basin and Eromanga Basin. The Northern Territory Coalition Government has selected Jemena to construct and operate the North East Gas Interconnector (NEGI) Pipeline, in order to connect NT gas to the eastern gas markets. The pipeline is intended to encourage new oil and gas developments in the state by ensuring that they have an existing buyer for the produced gas. In 2014, the state government commissioned a review into the practice of hydraulic fracturing, which found that the industry could be developed safely and effectively with the right regulation and would bring significant economic benefits to the state. In November 2015, the government released its Oil and Gas Industry Development Strategy outlining its plans to foster development of the state’s hydrocarbon resources. The four main priorities focused on in the report include increasing awareness of and access to the Northern Territory’s oil and gas resources; the capital, development pathways, and market access needed to bring new resources into production; balanced legislation and regulation; and a competitive, highly skilled, local gas supply and service sector. The government has also recently granted a number of new PEL applications throughout the state. However, two of these,

Tasmania Tasmania’s unconventional gas industry is still in its infancy with very little exploration activity yet undertaken, although the possibility of shale and/or tight oil and gas exists in some areas. Currently, there is a moratorium on fraccing until March 2020, although other exploration activities for unconventional gas resources are allowed. This fraccing moratorium was introduced in March 2014 after the election of the Liberal Government, and was originally intended to last for 12 months as the government undertook a review into the practice. After the review concluded, the government announced that it would extend the moratorium for another five years due to community concerns. The current government’s policy statement states: “fraccing in Tasmania is a possibility, not a probability”.

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In the Northern Territory, the government has put measures in place to attract explorers to the region.

one for Palatine Energy in relation to the Watarrka National Park, and one to NT Gas, in relation to the Coomalie Council Region, were rejected due to not meeting the requirements of the new process for land-access agreements introduced in late November 2015. The effect these new requirements might have on the attractiveness of the state for unconventional oil and gas development remains to be seen.

D Another review into hydraulic fracturing in Tasmania will be undertaken before the moratorium expires. While exploration activities for unconventional gas resources other than fraccing are permitted within Tasmania, the moratorium on fraccing and the largely unknown status of the state’s unconventional resources and whether they can be extracted economically makes the future of its unconventional oil and gas industry uncertain.

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PERFORMANCE SCORECARD

D-

New South Wales New South Wales is thought to contain significant potential unconventional gas resources in the Surat, Sydney, Gunnedah, Gloucester and Clarence-Moreton basins. Currently, NSW imports 95 per cent of its gas from other states, with the remaining 5 per cent produced by AGL’s Camden Gas Project, which produces coal seam gas in the Macarthur region. Two large unconventional gas projects are under development to help meet the state’s energy needs: AGL’s Gloucester Gas Project and Santos’s Narrabri Gas Project. On 26 March 2014, the NSW Coalition Government announced a moratorium on the approval of petroleum licence applications, which was later extended until 31 December 2015 as a series of reviews were undertaken as part of the NSW Gas Plan. The NSW Gas Plan is currently in the process of reviewing regulations in regards to the development of coal seam gas and other unconventional gas resources across the state, tightening regulations and placing new restrictions on exploration and

Victoria While Victoria has a number of potential unconventional resources, such as those in parts of the Gippsland and Otway basins, the unconventional gas industry in the state remains underdeveloped. Currently, there is a moratorium on unconventional oil and gas activities within Victoria, in addition to a hold on various approvals for new onshore conventional oil and gas development. Under the terms of the moratorium no new exploration licences are to be granted for any type of onshore gas (including tight, shale, coal seam and conventional gas) and no applications will be approved for hydraulic fracturing or exploratory drilling. The use of BTEX (benzene, toluene, ethylbenzene, xylene) chemicals is also banned. This moratorium has been in place since 2012 when it was introduced by the Coalition Government of the time. Originally it covered only activities related to coal seam gas, however it was extended to cover all onshore gas exploration in 2014. When the Andrews Labor Government was elected in 2015, it launched an inquiry into onshore gas in Victoria to investigate the possible impacts of onshore gas development activities. The inquiry’s report was tabled in December 2015 and the moratorium will continue at least until the government formulates its gas policy, which is expected to occur in the first half of 2016. However, the Victorian Liberal Opposition recently announced that it would extend the moratorium until at least 2020 if elected in the 2018 state election. The future of Victoria’s oil and gas industry is uncertain, especially in relation to unconventionals, preventing the state from being attractive to investment. Until the moratorium is lifted and regulatory conditions are less volatile, it is unlikely that a productive unconventional oil and gas industry will develop in Victoria.

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development activities. A PEL buy back scheme was also implemented with a number of licences bought and cancelled by the government, reducing the footprint of petroleum titles from 60 per cent to around 8.5 per cent of NSW. Certain areas of urban and agricultural land are now off-limits to unconventional gas activities, as are national parks, areas close to water catchments and where other land use conflicts may occur. According to the industry, the restrictions imposed by the NSW Gas Plan and continuing policy uncertainty are strong deterrents to unconventional oil and gas investment. As a result, the state ranked last out of all Australian jurisdictions in the Fraser Institute’s 2015 Global Petroleum Survey, which evaluates the attractiveness to oil and gas investment of jurisdictions across the globe based on barriers such as fiscal terms, environmental regulations, regulation uncertainty and other factors.

In Victoria, state governments have bowed to activist pressure and the oil and gas industry is at a complete standstill.

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SOUTH AUSTRALIA

Access to existing infrastructure adds to South Australia’s appeal.

i h t e m o s s re’

The

South

Evaluating South Australia’s assets South Australia contains a number of sedimentary basins thought to contain substantial unconventional oil and gas resources with the potential for development. These resource plays include shale gas, shale oil, tight gas and gas from coal, via deep coal seam gas (CSG). The basin in which these potential resources are best understood, and where exploration and development activities

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have progressed the furthest so far, is the Cooper Basin. The Cooper Basin, which covers 130,000 square kilometres across north-east South Australia and south-west Queensland, is Australia’s most mature conventional oil and gas basin and has been supplying oil and gas to the market for over 40 years. More recently, the basin has also been assessed as containing some of the largest potential unconventional oil and gas resources in Australia.

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SOUTH AUSTRALIA

South Australia has huge potential when it comes to unconventional hydrocarbon resources, with potential reservoirs of shale oil and gas, tight oil and gas and CSG identified in basins across the state. In the recent Fraser Institute Global Petroleum Survey, South Australia was rated the most attractive Australian jurisdiction for oil and gas investment due to factors that included its favourable regulatory environment. In this article, we take a closer look at what makes South Australia the place to be for unconventional oil and gas.

t u o b ng a

Australia In its 2013 world shale gas and shale oil resource assessment, the US Energy Information Administration (EIA) assessed the three troughs within the Cooper Basin thought to have the largest shale oil and gas potential, the Patchawarra (SA), Tenappera (SA) and Nappamerri (SA and Qld) troughs. Overall, the Cooper Basin was estimated to contain 325Tcf of shale gas in-place (including gas associated with shale oil), with 93Tcf of this risked and technically recoverable. Additionally, the EIA estimated that the basin also

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contained around 29 billion barrels of risked shale oil in-place, with a risked, technically recoverable resource of 1.6 billion barrels. A large percentage of these potential resources are located within the South Australian parts of the basin. Other assessments confirm the basinâ&#x20AC;&#x2122;s unconventional potential, with Santosâ&#x20AC;&#x2122; estimates of the raw recoverable unconventional gas resources located within the South Australian Cooper Basin Joint Venture licences ranging from a low of 22Tcf to a high of 187Tcf.

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SOUTH AUSTRALIA

Wide open spaces and an attractive regulatory environment make South Australia an appealing place for the development of unconventionals.

The South Australian Cooper Basin also contains the first shale gas wells flowing gas at commercial quantities. In 2012, Santos announced that its Moomba 191 shale gas well had begun production and was flowing gas at 2.7mmcf/d. In late 2013, a second shale gas well drilled by Santos, Moomba 194, also began flowing gas. While the basin’s deep coal seam gas and tight gas and oil resources are yet to be formally assessed, and recoverable amounts are largely unknown, the Cooper is thought to contain one of the largest tight gas resources in Australia, and have potential for deep coal seam gas. The existing infrastructure and workforce in the Cooper Basin from conventional oil and gas activities make the basin especially attractive for unconventional activities. The EIA states that the Cooper will likely be the first area in Australia to develop a commercial shale gas industry. However, while the Cooper may be leading the game, it is far from the only South Australian basin with the potential to supply large quantities of unconventional gas. Some of the other most promising basins in the state include the Arckaringa Basin, which has potential CSG, tight gas and tight oil resources; the Otway Basin, thought to have potential tight gas and shale oil and gas resources; the Warburton Basin, with potential tight gas and oil, and shale gas; and the Officer Basin, which is thought likely to contain tight gas and oil, and possible coal seam gas.

The story so far – unconventional activity in SA To date, companies exploring for unconventional gas in South Australia have achieved encouraging results. The companies actively exploring for unconventional resources in the Cooper Basin include Santos, Beach Energy, Origin Energy, Senex Energy and Strike Energy (with financial backing from Orica Limited). Formerly, Chevron was also involved with Beach Energy’s

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Nappamerri Trough Natural Gas, but they announced their withdrawal from the project in March 2015. At this early stage, the two largest exploration projects, the South Australian Cooper Basin Joint Venture (operated by Santos) and Beach Energy’s Nappamerri Trough Natural Gas project have established contingent gas resources in unconventional reservoirs totalling 4.6Tcf in the SA Cooper Basin. The Moomba 191 and Moomba 194 shale gas wells are also operated by Santos as part of the South Australian Cooper Basin Joint Venture. Meanwhile, in the SA Otway Basin, Beach Energy (operator) and Cooper Energy, identified both deep conventional and unconventional targets from two deep exploration wells, Jolly 1 and Bungaloo 1, in 2014. Linc Energy has been examining the potential for CSG and

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SOUTH AUSTRALIA

shale oil development within the Arckaringa Basin. The company’s 2014/15 drilling program drilled two wells, with test results comparing favourably with successful shale plays in the US, confirming the basin’s significant hydrocarbon potential. In the basin’s Stuart Range Formation, the results suggested 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.

Supporting unconventional development A supportive regulatory environment is a vital factor in South Australia’s attractiveness to investment in unconventional oil and gas. The South Australian State Government is undertaking a large number of programs to help get the unconventional oil and gas WWW.UNCONVENTIONALOILANDGAS.COM.AU

industry off the ground in the state, and was the first jurisdiction in Australia to develop a comprehensive plan for the development of its unconventional gas resources, called the Roadmap for Unconventional Gas Projects in South Australia. This roadmap defines the key priorities to ensure that the state makes the most of its unconventional oil and gas resources and contains 125 recommendations covering the full life cycle of unconventional gas projects, from exploration to production and even to possible LNG exports. This roadmap was the result of both community consultation processes and the first annual Roundtable for Oil and Gas Projects in South Australia (formerly known as the Roundtable for Unconventional Oil and Gas Projects in South Australia), which took place in 2012.

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SOUTH AUSTRALIA

Since then, the roundtables have been held each year to facilitate discussion between government and industry bodies in order to achieve the best outcomes for all parties. These roundtables now include over 800 organisations, including local and multi-national companies, peak representative bodies for industries and environment, research institutions and state and federal government agencies. Seven working groups have also been established to implement the highest-ranking recommendations regarding areas such as hydrocarbon transport infrastructure, water use, efficient regulation and ensuring a highly skilled workforce is in place for unconventional oil and gas projects. The roundtable meetings discuss the progress made towards achieving the goals outlined in the roadmap, with reports from each working group. Any possible updates to the recommendations themselves are also discussed. Additionally, the meetings involve various presentations and discussions regarding updates on current exploration and development projects, research projects relating to unconventional oil and gas, stakeholder engagement, water management,

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logistics/infrastructure, resource estimations and best practice technologies, as well as any other issues of importance to the industry. A number of research projects are also underway to better understand South Australia’s unconventional hydrocarbon resources and provide better data to encourage their safe, economical and effective development. A data project known as the ‘Cooper Basin atlas: understanding Australia’s premier onshore hydrocarbon province’ focuses on updating the existing datasets relating to the Cooper Basin’s unconventional hydrocarbon accumulations – many of which have not been significantly updated since their development in the 1990s to early 2000s. These new datasets will help properly identify and assess the various continuous gas plays in the basins to inform exploration and development decisions, attract investment and provide the Department of State Development with the necessary knowledge to develop appropriate policy and energy planning advice to government. Meanwhile, the GeoFrac project, supported by the University of

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SOUTH AUSTRALIA

Adelaide’s Institute for Mineral and Energy Resources, Centre for Tectonics, Resources and Exploration, and the Australian School of Petroleum, aims to improve the understanding of different geomechanical and geochemical contributions to variations in wellbore productivity from unconventional reservoirs. It also aims to increase the recovery of gas from unconventional reservoirs by improving targeting, to reduce the cost of drilling for gas production, and reduce the environmental and societal impact of developing unconventional reservoirs by minimising the number of wells that need to be drilled. Additionally, in 2012 an Australian Research Council grant of $750,000 over four years was awarded to a project intended to develop an integrated approach to unconventional gas exploration and development in the state. The project, called ‘From organo-mineral nanocomposite to Australian basins; an integrated approach to unconventional gas exploration and development’, is headed by Professor Martin Kennedy and involves the Department of State Development and industry partners Santos, JRS Petroleum Research, Central Petroleum and Petrofrontier (Australia).

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In 2015, construction also begun on a new $32.2million Drill Core Reference Library within a new resources hub at Tonsley to bring together more than 7.5million metres of drill core material currently held in four libraries across the state. All considered, abundant potential unconventional oil and gas resources, along with strong support for their development by the state government, makes South Australia the place to be when it comes to unconventionals in Australia. This combination looks set to benefit industry, government and the state’s economy as a whole in years to come, setting South Australia up as the likely launching point for Australia’s own tight and shale oil and gas industry. The South Australian story showcases the benefits of a cooperative and interactive relationship between government and industry when it comes to unconventional hydrocarbon resources and addressing issues related to their development.

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SAFETY

Safety in the oil and gas industry begins at the executive level.

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SAFETY

SAFETY FIRST:

HOW BONUSES AFFECT

ORGANISATIONAL SAFETY The oil and gas industry is committed to ensuring the health and safety of its operations, but major catastrophes can and do occur. Occupational health and safety experts Professor Andrew Hopkins and Assistant Professor Sarah Maslen have conducted groundbreaking research into the impact corporate pay packages can have on the overall safety of companies in the resources sector, and the authors share some of their insights here.

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SAFETY

rganisations often act in ways that seem irrational or contrary to their interests. In particular, they sometimes fail to attend properly to hazards that

lead to disaster. Such irrationalities make a lot more sense, however, when we recognise that organisations themselves don’t act – individuals within them do. In order to explore the question of how bonus structures impact organisational safety we did an empirical investigation that targeted a total of eleven companies in the resources sector, mainly multinationals, focusing on CEOs. Our research included interviewing a large number of senior managers in these companies. Major accidents in the oil and gas industry are rare, and underinvestment can continue for years without giving rise to disaster. On the other hand, managers are judged on their performance annually, especially with respect to profit and loss, so spending money on the prevention of major accidents is not necessarily in their short-term interest. For them, cutting expenditure on maintenance, supervision and training may actually enhance shortterm profits, while increasing the risk of disaster in the longer term. Staying ahead of the pack Two of the events studied in the book were BP’s Gulf of Mexico oil spill in 2010, and their Texas City Refinery explosion in 2005. Both events were catastrophic: the Gulf of Mexico spill is the largest marine oil spill in history, during which eleven workers were killed and 17 were injured; and the Texas City Refinery explosion killed fifteen workers and injured more than 170. In the case of both of these disasters, reports following demonstrated how bonus arrangements had distracted attention from major hazard/process safety. Bonuses were paid to people at all levels of the company largely on the basis of productivity and cost minimisation. There was a safety component, but this was largely determined by injury statistics which are ‘personal safety hazards’, not ‘process hazards’, which include the release of potentially dangerous materials or energy (such as fires and explosions). There was nothing in the bonus structure at BP that focused attention on how well major hazard risk was being managed. Bonuses are an extremely important component of the remuneration paid to the top people in corporations we investigated, as they are potentially worth several times

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more than their fixed salary. In the case of one CEO, this variable component of remuneration could be up to eight or nine times the fixed component. In other words, the stakes are very high for people at the top. CEOs are paid in company shares and are awarded annually on the basis of company performance, largely economic performance. However these awards are not paid in the year in which they are earned. Rather, they vest, meaning they are actually paid some years later, typically three. This in itself could motivate CEOs to ensure the priority of long term safety in the organisation. However, the shares only vest if a company does well in comparison to its direct competitors. It’s not enough that the company does well with shareholders, as they only receive their long term bonus if the company’s return is at least equal to that of a middle ranking competitor. This puts enormous pressure on CEOs to not just earn a profit but to do whatever is necessary to ensure that the company is up with, or better still, ahead of the pack.

How does this impact safety? The result of this style of bonus structure is not necessarily positive when it comes to the overall safety of an organisation. Most accidents have no effect on profit, so the CEOs therefore have no incentive to reduce the number of accidents. Quite the opposite in fact, as long term bonuses could provide an incentive to maximise profit at the expense of safety, if need be. There is one possible exception to this idea. Major accidents like the BP Gulf of Mexico spill, though rare, can have a substantial effect on shareholder return. This provides an incentive to manage catastrophic hazards effectively, especially if the vesting period was prolonged for up to ten years. This could encourage CEOs to look at the long term picture and recognise that it is in their interest to manage the risk of rare but catastrophic events. However, the specific structure of long term pay bonuses undermines this potential. It’s true that a major accident could wipe out the CEOs long term bonus, but an accident like this is very unlikely to occur. It is more likely that spending more money on the safety management of major hazards may reduce profit sufficiently to put the company fractionally behind its competitors, again wiping out the long term bonus. Annual bonuses and evaluations The stakes are high for CEOs because we’re talking about a lot of money, vested over several years. The other type of

organisational bonus being paid to more people at different levels of management is the short term or annual bonus. As you go further down the hierarchy the smaller the bonus becomes, but for many senior managers, their annual bonus can equal or exceed their fixed salary. Annual bonuses are awarded in two ways, one is based on the performance of the organisation as a whole and the other is an evaluation of an individual’s performance. Safety is incorporated into the calculations for short term bonuses, so in theory they have the potential to enhance personal and process safety. The group performance, based on the performance of the organisation as a whole, is generally evaluated using a series of quantitative measures that deal with things like profit, production and injury rates for the

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SAFETY

Ensuring remuneration balances risk and reward can be a challenge.

whole corporation. Targets are set for each of these, and results are compared with the target results to provide a score for each of these indicators. If managers annual bonuses are dependent on the results of the corporation as a whole, there is little they can personally do to vary the results, which can inadvertently disincentivise them from changing or upholding safety performance. In our research, the weight given to safety in these target scores was quite low, in the range of 10-30 per cent and, with a few exceptions, the targets referred mainly to personal safety, such as slips, falls, vehicle accidents and recordable injuries requiring first aid; rather than process safety, which indicates the potential for major hazards. The other component that determines annual bonuses is individual performance, based on a performance agreement that

each person has with their supervisor. The performance agreements often specified group targets- production, profit, injury rates etc. for which the group manager is held personally accountable. We found that safety was also a relatively small component in these agreements, less than 25 per cent, particularly for people who could not be held accountable for group rates. These performance evaluations were often conducted through interviews with supervisors who then make a subjective assessment. This is possibly the best explanation for why it is that personal injury rates were such a focus of attention in the companies we studied rather than process safety- not because injury rates appeared in performance agreements, but because supervisors emphasised it in their performance reviews. This was part of the

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culture of these organisations, set in place by the priorities of the CEO, that said focus should be on personal injury statistics rather than process safety that could prevent a major accident. These performance agreements set goals for individuals to follow in order to receive their bonuses, so itâ&#x20AC;&#x2122;s worth ensuring that safety, particularly in relation to catastrophic risk, is included as effectively as possible. Including process safety indicators is also relevant in some of these cases.

Process safety indicators Some companies have done good work in developing sets of process safety indicators or scorecards that can be included in performance agreements to evaluate bonuses. While there is a tendency to assume that loss of containment is the best indicator SUMMER 2016 // ISSUE 3

SAFETY

of risk for the whole of the industry, this is not the case. Different businesses need to identify the major accidents in which they are at most risk and what the relevant safety precursors are to these accidents. The indicators of the frequency of such events should then be included in their specific scorecards, linking directly to evaluations and bonuses. For instance, loss of containment is not the best indicator for drilling, shipping, aviation, road tanker operations or pipelines. More relevant to these activities may be kicks, vessels on collision course, sudden breaking, and third party incursions or strikes, respectively. Once this context is set, companies can better develop indicators of how well these risks are being managed. The crucial question, though, is the extent to which these scorecards should be incorporated into bonus arrangements. The only way that scorecards, as a whole, can be included is if they are summarised in some way, such as per cent green. However, such summaries inevitably lose sight of the reality of process safety and almost inevitably give rise to attempts to massage the measure. Itâ&#x20AC;&#x2122;s far better if particular indicators are included in the

performance agreement of particular managers who have the capacity to influence them. It is generally agreed that a good safety culture is one where incidents are reported and lessons are effectively learned.

Future possibilities So how do we change the organisational structure and use of corporate pay packages to incentivise employees to bring safety to the forefront? Well, to finish where we began, we agree with the commentators who claimed that the bonus structure at BP Texas City constituted a systematic disincentive to attend to process safety. We endorse the idea that managers should be held accountable for process safety indicators in their performance agreements, which link to their bonuses. However, the pay of lower level managers and non-managerial workers should not depend on these indicators or on injury statistics. We want lower level personnel to have incentives to report bad news, not suppress it. One alternative proposal for CEOs is the idea that a sizeable proportion of deferred bonuses be paid as cash directly into a

bonus pool, that could be drawn on to pay for damages in the event of catastrophic incidents. People whose money was tied up in such a trust fund or unit trust would therefore have a vested interest in minimising the risk of catastrophic incidents. This idea separates bonuses from safety as the value of units in a trust will not be affected by a companyâ&#x20AC;&#x2122;s financial performance (as they should not be invested in the company itself). Rather the value of units will be much more directly affected by how well the firm is managing catastrophic safety and environmental risk, which is highly desirable for the present industry to improve organisational safety.

This article is an edited extract from Professor Andrew Hopkins and Assistant Professor Sarah Maslenâ&#x20AC;&#x2122;s book Risky rewards: how company bonuses affect safety, which can be purchased through publisher Ashgate at: www.ashgate.com/ isbn/9781472449849.

The structure of executive pay packages can have serious impacts on organisational safety.

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TECHNICAL

EVALUATION OF THERMAL MATURATION

(RANK) OF SEDIMENTARY ROCKS â&#x20AC;&#x201C;

MORE THAN JUST VITRINITE REFLECTANCE by Dr Peter Crosdale, Energy Resources Consulting Vitrinite reflectance (Vr) has many advantages in evaluating the degree of thermal maturation of sedimentary rocks. Values are tightly constrained for a given palaeo temperature and change rapidly as a function of temperature. It is extensively used in modelling basin history. Indeed, it is so valuable a tool that it is commonplace to see Vr quoted for pre-Devonian rocks even though it is not possible for vitrinite to be present. Unfortunately, Vr is used ubiquitously without much thought as to its strengths, weaknesses and indeed even if it is possible for vitrinite to be present.

he great strength Vr in lies in it being a property of a single type of organic matter. Most chemical or physical tests to evaluate maturation use the bulk properties of the rock. There are a great variety of types of organic matter present within rocks, including marine / non-marine types and oxidised / reduced types. Each type has its own set of physical and chemical properties. Bulk analytical results therefore depend upon the relative proportions of each organic matter type present, making it very difficult to evaluate the degree of thermal maturation and interpret basin history, oil generation potential and so on. Systematically measuring vitrinite reflectance in well cuttings enables experienced petrographers to identify cavings, thus giving a more reliable indication of maturation

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levels compared to organic geochemical methods in the similar circumstances. There are many cases in which vitrinite is not present in the rocks but it is still essential to assess the thermal maturation. Such cases include all pre-Devonian rocks (vitrinite is derived exclusively from land plants) and distal marine rocks. It is therefore necessary to use other organic matter types or bulk analyses. The trick and the danger lies in equating the maturation data back to a Vr equivalent value. The fact that this equivalence has been made is often lost and the data treated as if it is genuinely a measurement of the reflectance of vitrinite. Measurement of the reflectance of vitrinite in dispersed organic matter (DOM) is not a trivial matter. Rare and isolated fragments of organic matter can be extremely difficult to accurately identify, a WWW.UNCONVENTIONALOILANDGAS.COM.AU

TECHNICAL

Figure 1. Identification of vitrinite in DOM is not a trivial matter. Inertinite particles (light grey) and sporinite (strong yellow fluorescence) are shown – there is no vitrinite in this field despite it being rich in organic matter. Reflected white light (left) blue light fluorescence (right), oil immersion, 500X total mag, width field of view = 0.2mm.

Figure 2. In Ordovican rocks, graptolite reflectance can be very useful as graptolites have properties similar to vitrinite. Reflected white light, oil immersion, 500X total mag, width field of view = 0.2mm.

fact which results in a great deal of spurious data being reported. In many cases, it is essential to use fluorescence observations to decide if the particle being measured is vitrinite or not (Figure 1). Inaccurate identification of organic matter type results in incorrect assessment of the degree of maturation, maturation patterns and basin history. It is essential to use a well established laboratory, preferably with analysts accredited by the International Committee for Coal and Organic Petrology (ICCP). It is also essential to use Vr data in conjunction with a variety of other analytical techniques. When vitrinite is not present, the reflectance of other organic matter types may be used to assess maturation trends. Such organic matter includes graptolites (Figure 2), chitinozoans, algae, bitumen and indeed any sort of organic matter that can be found, including inertinite. When present, graptolites can be especially useful as they have many characteristics similar to vitrinite. Bitumen reflectance is also very useful as it commonly occurs in more recent rocks in conjunction with vitrinite such that equivalences can be established. However, there are different forms of bitumen and the experience of the petrographer to adequately discriminate them may limit the value of the measurements. Algae are also common in older rocks where vitrinite is absent. Algal maturation parameters, including reflectance, increase very rapidly in comparison to vitrinite. Even inertinite can be used in the absence of vitrinite. Inertinite reflectance increases in a manner similar to vitrinite and will provide a limit to the maximum possible Vr value. Other optical properties of the organic matter are also useful. Quantitative measurement of the fluorescence spectra of single organic matter types (often spores or algae) shows a systematic shift from blue to green to red as a function of increasing

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maturation. This can be assessed by the intensity of the spectrum at 546nm wavelength (green) and by the red/green quotient (intensity at 650nm/intensity at 500nm). Simple observation of fluorescence colours are also a useful guide to degree of maturation. One of the most commonly used techniques additional to reflectance is that of pyrolysis. Here, powdered rock samples (typically less than 0.25mm in size and around 70mg mass) are heated to 650°C in the absence of oxygen and the amount of hydrocarbons, carbon monoxide (CO) and carbon dioxide (CO2) evolved is measured as a function of temperature. Parameters determined from pyrolysis include: S1 (oil yield); S2 (kerogen yield) and Tmax (the temperature at which the maximum generation of hydrocarbons from pyrolysis cracking of the kerogen occurs, see Figure 3). Many derived parameters are also useful, such as: hydrogen index (HI); oxygen index (OI); production index (PI) etc. These have many uses including organic matter typing via the pseudo van Krevelen plot. Following pyrolysis, the sample may also be subjected to an oxidation phase (i.e. heating to 750°C in the presence of air) and the amount of CO and CO2 evolved used to determine the total organic carbon (TOC) present. The pyrolysis parameter of Tmax relates to thermal maturity and is widely used in its own right as well as to calculate a Vr equivalent value. However, it is not widely appreciated that Tmax is a property of the bulk organic matter and is strongly affected by organic matter type. There are very good relationships between Tmax and Vr for coals (see Figure 4) but it is important to remember that for a bulk rock sample, the correlations may be weak and basin dependent. These issues do not prevent the commonplace

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TECHNICAL

Figure 3a. The pyrolysis parameter Tmax is the temperature at which the maximum generation of hydrocarbons from pyrolysis cracking of the kerogen occurs. It is often used to assess thermal maturation as it increases regularly as a function of maximum burial temperature.

Figure 3b. However, Tmax is strongly affected by organic matter type. For the same degree of thermal maturation, Type I organic matter will exhibit a lower Tmax than Type II, which in turn is lower than Type III organic matter.

Figure 4. Strong relationships can be observed between Vr and Tmax when the organic matter type has low variability. The orange outlier at low Vr and low Tmax is from xylite (woody material) of brown coal whereas the matrix material from the same samples plots on the trend – it illustrates dramatically the influence of organic matter type on Tmax. Data from internal study at the Energy Resources Consulting laboratory.

calculation of Vr from Tmax and the bemusement that follows when the Vr ‘data’ does not behave as expected! Colour and transparency of organic matter are also functions of maturation. Palynological description often includes these parameters. Most unoxidised organic matter can be useful, such as spores, algae, conodonts, foraminifera, chitinozoans, scolecodonts and so on. They go under names such as spore coloration index (SCI), thermal alteration index (TAI) etc. At low maturation, the organic matter tends to be pale and highly translucent. As maturation increases, translucency decreases and colour changes, often through yellows, oranges, browns and to black at highest maturity. They are very useful in defining broad maturation trends but the fine definition allowed by reflectance cannot be obtained. Biomarkers, especially Methyl Phenantherene Index (MPI), are also in use. Phenantherene is a tricyclic aromatic compound that forms the base for important biological molecules such as steroids and triterpinoids. During the thermal maturation of kerogen, thermodynamically stable 2- and 3-methylphenantherene are derived from methylation of free phenantherene as well as rearrangement of less stable 1- and 9-methylphenantherenes. The ratio of the abundance of the catagenically produced 2- and 3-methylphenantherene to the sum of phenantherene, 1- and 9-methyl phenantherene is a parameter called Methylphenantherene Index (MPI) which appears empirically to follow a maturity-related trend. Inorganic parameters may also be of use. The two most common are the illite crystallinity index and apatite fission tracks. Illite crystallinity index relates to the disappearance of smectite and kaolinite during burial and diagenesis, which favours illite formation. Crystalline organisation of the illite increases with maturation and

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can be assessed by the width of the illite peak at 10Å at half its height. Apatite fission tracks are formed by fission of a single 238U atom and form continuously through time by radioactive decay. Tracks have the same initial length ~ 16 µm and shorten (anneal) at a temperature dependent rate. The higher the maximum temperature, the shorter the track length, and with cooling, the track is ‘frozen’ at the shortened length. In samples shallower than the paleo-110°C isotherm, they can be used to assess the maximum palaeotemperature and the onset of cooling; in samples deeper than the paleo-110°C isotherm they can be used to minimum estimate of the maximum palaeotemperature as well as the onset of cooling. Very good relationships are found between fission track temperature and mean maximum vitrinite reflectance. Vitrinite reflectance is a sensitive indicator of thermal maturation and is highly reliable, being from a single organic matter type. In the absence of vitrinite, other proxies used to calculate an equivalent Vr value are useful guides but will be subject to varying degrees of uncertainty. Chemically based measures of rank using whole rock samples are highly dependent on organic matter type. Such measures include the widely used Tmax . They are extremely useful in their own right but caution must be exercised when relating back to equivalent Vr values and the user of the data should be consciously aware that they do not have actual Vr values. Relationships between vitrinite reflectance and other physical and geochemical parameters are best if established on a basin by basin case if possible. Whether vitrinite is present or not, evaluation of thermal maturity is best attained by integration of a number of data sets. Only in this way can a proper understanding be attained of uncertainties due to organic matter type.

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From good news to good for the At the turn of this century, unconventional gas was just another mostly positive resources story running in the Australian business news sections. By 2011, the industryâ&#x20AC;&#x2122;s media coverage was vast in volume and rancorous in tone. To unravel what happened to precipitate the media storm, media scholar Libby Mitchell teamed up with computer scientist, Dan Angus, to conduct a systematic, longitudinal analysis of what was, at that time, the most toxic, polarised public controversy in Australia. by Dr Libby Mitchell and Dr Dan Angus, UQ Centre for Coal Seam Gas

More than 14,000 Australian news articles published between 1996-2013 and more than 17,000 news articles from the United States were analysed as part of the study.

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for business news business

The study “Using an innovative set of techniques including text and visual analytics, we analysed and compared over time the topical content and stakeholder voices captured by news coverage of unconventional gas,” said Dr Libby Mitchell. “Given the parallels in industry development, we also thought it would be useful to compare Australia’s news coverage with that of the industry in the United States. Our sample was very large – more than 14,000 Australian news articles

published between 1996-2013 and more than 17,000 news articles from the United States. “Given the intensity of the debate here, we wanted evidence-based answers to questions about the topics attracting the most attention and controversy over time. We wanted to know who the stakeholders were, when they emerged in the news, the relative prominence of the voices of these stakeholders, which topics compelled the

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biggest share of news coverage, and how this array of voices changed over time and the critical turning points. “We considered the interplay between the news media, industry, political agents, activists, and communities and escalating

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Note on method: The text analytic software Leximancerâ&#x201E;˘ 6 was used to identify and visually map the thematic content of each of the data sets (Australia and US). The change in thematic content was mapped over time by pairing Leximancer with Discursis7. A combination of computerbased scripting techniques and the entity extraction methods contained in the Stanford Natural Language Processing Library were used to identify name (or name-like entities) and count the number of news articles in which the individual is mentioned. The number of news articles in which the individual is mentioned (rather than all mentions) was used as the unit of measurement to ensure an accurate representation of prominence.

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News media are an important lens through which people understand their world – the more complex and unfamiliar the topic, the more we rely on media in all its forms to help make sense of it.

controversy. We thought there were many lessons to be learned by everyone – the industry, the news media, the activists and academia,” said Dr Mitchell. “Our rationale for using news reports was two-fold. First, news media are an important lens through which people understand their world. The more complex and unfamiliar the topic, the more we rely on media in all its forms to help make sense of it. Second, it was possible to use news coverage to see what was being said by the politicians, by disaffected landholders, by supporters, by industry and so on. This also gave us insights into who was able to attract the most attention – whose voices were the ‘loudest’,” Dr Mitchell said.

increase in media attention occurred in the US. “As news media attention intensified, it shifted focus,” said Dr Mitchell. “In 2008, stories of business deals and infrastructure projects dominated both Australian and US news coverage. Over time, the balance tipped, and stories of environmental risk, land access disputes, and protest dominated.” The ‘business versus environment’ shift in Australia was more pronounced than in the US. In Australian news coverage, the narrative surrounded water security. In the US, the focus was on energy security and the need to have an independent domestic energy supply.

The findings The study revealed that news coverage of unconventional gas in Australia – and its prominence as a public issue – began intensifying in early 2008 and peaked in late 2011. A similar, although less dramatic,

Shift in focus 2008-2011 “The rise and fall in prominence of stakeholder voices in news coverage was a critical piece of evidence,” said Dr Mitchell. “In Australia and the US, the antiunconventional gas movement emerged in

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mid-2008. Media attention intensified and as reports of risk to the environment and landholder rights escalated, the industry’s share of voice declined.” The study showed that shifts in the coverage of issues and topics were more moderate in the US media coverage, and there was less volatility in the intensity of media coverage. The heightened politicisation of unconventional gas in Australia, and the engagement of disparate political voices in the debate, precipitated intense news coverage. Many spokespeople and advocates representing a vast and confusing array of viewpoints emerged in the news coverage. “In Australia, between 2008 and 2011, issue advocates and activists as well as politicians became the dominant voices. Over time, they carved out a large and growing voice compared with the unconventional gas industry. Rising community concern – as represented by the many vocal industry opponents –

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By the fourth quarter of 2011, activists were among the five most prominent voices in the news on the topic of unconventional gas.

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COMMUNITY as well as increased news media coverage, propelled unconventional gas into the political agenda in Australia,” said Dr Mitchell.

More voices emerging post 2008 More than 7,000 individual stakeholders and ‘stakeseekers’ emerged in the news data between 2008-2013. Between 2008-2013, industry consistently lost share of voice to competing stakeholders and stakeseekers, including federal and state government representatives and industry opponents, like Lock the Gate. For example, in the third quarter of 2009, the five most prominent individuals quoted or discussed in news coverage were four elected representatives and one corporate leader: Martin Ferguson, Federal Minister for Resources and Energy; Kevin Rudd, Prime Minister of Australia; Peter Garrett, Federal Minister for Environment; Colin Barnett, Premier of Western Australia; and David Knox, CEO of Santos.

By the fourth quarter of 2011, the five most prominent voices in the news were a little more diverse and included two industry opponents: Tony Windsor, Independent Federal MP for New England; Anna Bligh, Premier of Queensland; Julia Gillard, Prime Minister of Australia; Drew Hutton, leader of Lock the Gate; and Chris Hartcher, NSW Minister for Resources & Energy. By the beginning of 2013, the powerful voices were elected officials vigorously opposed to the industry, specifically, Tony Burke, Federal Minister for the Environment; Barry O’Farrell, Premier of New South Wales; Tony Windsor, Independent Federal MP for New England; Chris Hartcher, NSW Minister for Energy & Resources; and Jeremy Buckingham, NSW Greens Legislative Council.

Alternative media strategies? So could the toxicity of the public debate about unconventional gas in Australia have

been defused in advance of the evident crisis of public confidence that emerged in news reports from 2010? According to Dr Mitchell and Dr Angus, the answer is a qualified ‘maybe’. “We can’t answer that specific question,” said Dr Mitchell. “However, we can say that there were plenty of warning signs that the debate was escalating. There was also plenty of evidence of the entry of many voices into that debate. But you had to look at the whole picture over time and not just at a point in time or from the particular viewpoint of one vested interest or another. Collaboration between key stakeholders certainly shaped different outcomes and different reporting of outcomes in the United States. At the end of the day, the most vocal opponents to unconventional gas in Australian news coverage were elected representatives. That wasn’t evident in the US news coverage.”

The study was funded by the UQ Centre for Coal Seam Gas (UQ Unconventional Gas). The Centre is currently funded by the University of Queensland 25 per cent ($5million) and Industry members 75 per cent ($15million) over five years. For more information about the Centre’s activities and governance, see www.ccsg.uq.edu.au/aboutus. The information expressed in this article does not necessarily represent those of UQ or its constituent members or associated companies.

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CONFERENCES

The ATSE International Conference and associated Workshop on Unconventional Gas was held in Sydney in September 2015 and brought together academicians, experts and other participants from nine countries: Argentina, Canada, China, Germany, South Africa, Switzerland, United Kingdom, United States and Australia. This unprecedented gathering of the global scientific community provided an outstanding opportunity to critically analyse the evidence relating to the opportunities and the challenges of unconventional gas developments.

The scien on unconventio 40

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ce nals is in

Experts from around the world gathered in Sydney to critically analyse the evidence relating to the opportunities and the challenges of unconventional gas developments.

by Peter J. Cook CBE FTSE, and Vaughan Beck ATSE

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CONFERENCES

he discovery and development of unconventional gas has been one of the most significant technology-driven energy developments of the past decade. The exploitation of shale gas has allowed the USA to become self-sufficient in natural gas, and far less dependent on imports of liquid hydrocarbons. Coal seam gas (CSG) has enabled eastern Australia to become one of the world’s great exporters of LNG. But whilst these developments have produced major economic benefits, they have also resulted in concerns regarding their environmental and social impacts. The meetings covered both CSG and shale gas, and whilst there are a number features common to both, there are also some significant differences. These relate not to the composition of their gas (both are methane), but to their geological setting. For example, shale gas is commonly found at depths of 3km or more in impermeable shales, which have to be hydraulically fractured in order to produce the gas locked in the shales. This process may require significant volumes of water initially, but once fractured and initially produced (the flow-back stage), there is then very little water produced subsequently from the shale formation. Conversely, CSG is produced from coal seams at much shallower depths (typically 300-1000m). These formations may or may not require hydraulic fracturing: the gas within the formation is held under pressure by groundwater and it is commonly necessary to withdraw large quantities of water from the coal seam on an ongoing basis in order to produce the gas locked in the coals. The conference brought together 150 participants (researchers, NGOs, governments, regulators, industry, as well as academicians) from Australia and around the world for a series of keynote presentations and panel discussions that served not only to summarise the current state of knowledge regarding unconventional gas, but also to highlight the areas of dispute and uncertainty. The workshop involved academicians, invited experts and government observers. The participating academicians considered the conclusions and observations arising from the conference, as well as recent national unconventional gas (and oil) reviews in reaching a number of conclusions. In all 35 key findings were made and these are summarised below under eight main themes.

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Unconventional gas resources Unconventional gas can be produced in a manner that is environmentally responsible and that provides significant societal benefits, provided leading practice is followed. There is an ongoing need to better understand the properties of the rocks hosting unconventional gas resources, including their geology and structure, fracture mechanics, anisotropy adsorption characteristics and hydrogeology. This knowledge can potentially improve the economics of gas recovery and help to minimise environmental impacts. Future technological innovations also have the potential to increase the unconventional gas resources base, with targeted exploration, improved efficiency and cost effectiveness of production, better monitoring of impacts and by decreasing the potential for adverse hydrological and other environmental and social impacts. Addressing community concerns Unconventional gas developments can and do bring significant socio-economic community benefits at local, regional and national levels, but as part of leading practice, it is essential to gain community support. Gaining community support requires sustained engagement, recognition of prevailing community values, communication of scientific, technical and socio-economic information by trusted sources, certainty in the regulatory regime and confidence that long term socioeconomic benefits will accrue. Credible, impartial and trusted sources such as scientists, engineers and other stakeholders need to actively engage with communities in an open and transparent manner. When engaging with communities affected by unconventional gas developments, the extent of change in the communities needs to be documented, based on agreed indicators, rather than perceptions. It is also important to recognise that communities attitudes and concerns differ, so information provided needs to be within the context of their community values. The cumulative socio-economic impacts of unconventional gas require particular attention, as there hasn’t been enough focus on the impact of the ‘boom-bust’ phenomenon experienced by some unconventional gas communities. Community concerns over health and safety impacts also need to be addressed, with a need to collect more community health data (both baseline and operational)

There is an ongoing need to better understand the properties of the rocks hosting unconventional gas resources, including their geology and structure, fracture mechanics, anisotropy adsorption characteristics and hydrogeology.

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including data for remote, vulnerable and disadvantaged communities where unconventional gas developments are planned or underway.

New knowledge If unconventional gas resources are to be continually developed, there

needs to be new knowledge and a new understanding of technologies, regulations and economics. Prevailing baseline conditions, natural variability, cumulative effects (social, environmental, economic), groundwater hydrology, emissions, and community values and expectations are all areas that

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can be researched further. There is a need for more comprehensive research into, and documentation of, sedimentary basin resources and processes, and the cumulative impacts of basin developments on the natural and human environment, as this is often poorly understood.

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Protecting the surrounding environment needs to be at the forefront of the sustainable development of unconventional reserves.

Research in sedimentary basins will improve our knowledge of unconventional gas and other resources, decrease project costs and impacts, improve regulations and contribute to the development of a risk-based approach to regulation and to the management of environmental and community impacts.

Hydraulic fracturing Provided leading practice is followed and there is comprehensive knowledge of the subsurface, hydraulic fracturing is most unlikely to cause damaging induced seismic events or result in widespread,

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systemic impacts on drinking water resources. Induced seismic events associated with hydraulic fracturing are almost always minor (generally less than 1 on the Richter Scale) and the likelihood of structural damage occurring from them is very low. Disposal of produced water by reinjection is more likely to trigger seismic events in the 1-3 range, but this can be minimised by avoiding injection of fluids into areas with potentially active faults. There is also scope for ongoing improvement in fracturing technologies, including through decreased use of water

and chemicals, along with full public disclosure of the composition of hydraulic fracturing fluids.

Groundwater Poor well construction and improperly decommissioned wells are risks to groundwater, and it is important to be able to demonstrate life-time well integrity and remediation responsibility for unconventional gas wells and adopt leading practice for waste water disposal and management of materials and chemicals. The impact of CSG developments on

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groundwater arises not from the use of water but from the large quantities of produced formation water associated with gas production and from related impacts, such as the lowering of the water table. To minimise the impact on water resources, unconventional gas developments need to adopt leading practice for monitoring, water treatment and reuse and for minimising spillage or leakage of used or produced water. Appropriately treated produced water can be used as a source of water for agriculture, or re-injected into aquifers.

Protecting landscape and the environment Cumulative environmental and biodiversity impacts can be minimised, using a risk-assessment framework along with better planning of infrastructure and integrated land management. Better planning of infrastructure, such as positioning of well pads, access roads and gathering and transmission pipelines is important if integrated land management is to be followed and environmental and biodiversity impacts minimised. The environmental review process must be capable of assessing and adapting to new technological advances in production, new codes of behaviour, liability rules, outcomes of benchmarking and cumulative assessment practices. Emissions Fugitive methane emissions, which can be material over the lifetime of an unconventional gas project, need to be monitored and a baseline established, in order to remove uncertainties regarding the magnitude of these emissions and provide a basis for remedial action. The majority of fugitive methane is emitted from just a few points in the production-transport chain (‘super emitters’). These can be remediated through measures such as green completions and application of leading practice. More consideration could also be given to opportunities for using carbon dioxide in enhanced gas recovery and hydraulic fracturing and for applying carbon capture and storage to gas separation, gas-based power generation and gas-using industrial processes.

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Regulation Some regulatory regimes can be so complex (with hundreds of conditions placed on a single project), that the effective regulation of the industry and the meeting of community expectations regarding the reduction of risk, can be jeopardised. If regulations are to meet community expectations, protect the environment and reduce costs to industry, they must have clarity of purpose, transparency and engender trust. Regulations should be outcome-focused, adaptive to new data and conditions, and be informed by the best available science, technology and practice. This ‘adaptive management’ approach allows new data to inform the decision makers. Regulatory leading practice can be achieved when operators are required to identify and manage agreed risks consistent with the ‘as low as reasonably practicable’ (ALARP) principle. The 2015 ATSE International Unconventional Gas Conference and Workshop provided an outstanding example of how Academies can work together to bring a credible and informed perspective to an important and, for many, controversial topic. In so doing, Academies can assist government, industry and the community at large by communicating the technical issues and challenges, thereby contributing to developing a way forward that

ari valves solutions for pipelines.

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What can we possibly

another unconventi by Dr Ray Johnson, Principal, Unconventional Reservoir Solutions With a spate of conferences recently held targeting the unconventional sector, Ray Johnson finds that each has still provided its attendees with useful knowledge in the pursuit of unconventional extraction.

irstly, my thanks to all who attended the Society of Petroleum Engineers (SPE) 2015 Asia Pacific Unconventional Resources Conference and Exhibition (AP-URCE) held in Brisbane from 9-11 November 2015. The event was highly successful bringing together over 845 delegates from 18 countries and covered most technical aspects of unconventional reservoir exploration, appraisal and development of coals, tight gas and shale reservoirs. This conference firmly

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positioned Brisbane as a future location for this meeting in the Asia-Pacific region, based on the good participation and support, despite a truly challenging environment for conference planning and execution. The technical program committee brought together a number of key papers, highlighting coal seam gas (CSG) and other unconventional gas environments, and addressed both business and technical issues. As we are largely addressing emerging unconventional plays, the technical program this year again contained

a number of sessions pertaining to new technologies such as imaging or defining small scale processes and upscaling those images into more accurate working models for reservoir simulation and well planning. Another topic that seemed to carry on from my attendance at the US-URTeC 2015 meeting (which I wrote about in my column in the last edition of this magazine) was the theme of optimising the hydraulic fracturing process in horizontal shale gas wells. However, this year at AP-URCE, there was more emphasis on how to target intervals with the optimal well configurations and

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learn from

onal conference? strategies, rather than just optimising volumes and operating practices. Progress Energy from Canada made an excellent presentation from a business perspective on their successful strategy of using overlapping wellbores drilled from minimal pads to optimise the development of a very thick, highly prospective Montney shale interval. This detailed drainage strategy was derived from the understanding that this resource could not be reasonably drained by a single horizontal well with multiple fractures and evolved as a better understanding of reservoir drainage patterns improved. Although the presentation is not available post-conference, I presented a paper co-authored from the Bone Springs Fm, in the Delaware Basin of West Texas and New Mexico, where my co-authors improved fracture stimulation of a highly stratified,

carbonate and sand sequence (SPE Paper 176828, Delaware Basin Bone Springs - A Study of the Evolving Completion Practices to Create an Economically Successful Play). In this North American case study, the implementation of several optimisation steps increased the well performance above previous wells. Further, as a result of successful implementation of these processes, the operator’s overall perspectives as to the rock quality and expected results per well also improved, enhancing the value of the play. This workflow focused on several key elements to improve hydraulic fracture effectiveness, including: • Development of a reliable stress profile • Determining a well and fracture placement strategy that matched the reservoir and stress conditions

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•

Optimising fluid and proppant characteristics to maximise overall fracture effectiveness from a ‘wholelife-of-well’ standpoint • Modelling potential hydraulic fracture placements from various vertical perspectives of the lateral intersecting the reservoir, by optimising rate, fluid and proppant characteristics for overall fracture effectiveness • Placing the fractures at appropriate locations in the reservoir along the wellbore and assuring positive fracture placement at those locations rather than pre-determined patterns of perforation clusters along the wellbore and relying on pressure differentials to stimulate all intervals. This continuing theme of acquiring

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the necessary data, stepping back and reviewing what has been done right and adjusting the data collection and operational requirements to meet continuing challenges in each unique environment was presented in a number of papers at the conference, based on case studies from North America, the Middle East and China. The overall trend from these papers focused on the development and tailoring of an effective reservoir development strategy earlier in the process in these emerging areas where a lower well density is required, as opposed to the large scale trial and error strategy that has been successfully used in North American developments. Nevertheless, in most paper Q&A sessions, the audience again queried many of the authors on how each emerging area plans to reduce overall expenditures and improve project economics as they upscaled their pilot projects to larger developments, the key to unconventional success in North America. In addition to shales, there were a number of key papers on improving the stimulation, production management, and modelling of key processes pertaining to CSG and relevant to developments in Eastern Queensland. Origin updated the audience on the project and continuing

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challenges relating to their Walloon hydraulic fracturing program, based on hydraulic fracturing diagnostics (i.e. microseismic, surface deformation tiltmeters). Origin and Santos detailed studies of production analysis and forecasting methods. Finally, there were a number of papers on improved understanding of desorption, gas testing, stimulation of tight coal cleats and fractures as well as several sessions on managing societal expectations and long term abandonment strategies. Finally, the overall topic that unconventional well planning needs to be tailored for our stress conditions (and the differences from North America) was effectively highlighted in several paper and panel sessions at AP-URCE. The most notable expression was in the panel session regarding geomechanics with respect to hydraulic fracturing. Starting off in this session, Sau-wai Wong from Shell International noted that the pumping side (e.g. fluids, rate, proppants) was as important as understanding the geomechanics in the process. Jeremy Meyer with Ikon Sciences highlighted the importance of correctly processing the rock data before upscaling to stress models. Rob Jeffrey, formerly of CSIRO

now SCT, noted the complexity we actually find in hydraulic fractures based on mine backs and instrumented studies as opposed to our simplified models. Finally, in this session, I highlighted how well a designed diagnostic fracture injection test (DFIT) strategy and resulting data can be effectively upscaled to create the more accurate, strain-based stress profiles required to perform frac treatments in our stress regimes. Then once defined, I noted how these compressional and transpressional stress regimes require more focused and specialised technologies to recreate the â&#x20AC;&#x2DC;North Americanâ&#x20AC;&#x2122; experience of transverse, hydraulic fractures, with respect to horizontal wells. Overall, the challenges and solutions emerging for Australian unconventional resources were discussed and dialogue emerged on how we can tailor North America technologies and strategies to better develop our vast unconventional resources. The papers from the 2015 AP-URCE as well as those previously discussed from US-URTeC conference are available on the One-Petro website, which houses the breadth of conference and peer-reviewed papers from the varying societies supporting our industry (www.onepetro.org/conferences).

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OPINION

WELL ENHANCE

e h t PROD

PERSP by John Hoday, VP Energy Services, NauticAWT

ell enhancement. Two words, with a very broad definition. Is it the newest technology to steer five kilometre horizontal wells in the making? Or perhaps is it automation that monitors and tweaks parameters every second of a well’s life? The truth is, it can

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be much simpler than that. In looking at a production well in its simplest form, it is derived of basic services delivering components that culminate in opening a valve on the surface and flowing oil and gas. Each time one of these components gets a ‘new and improved’ makeover it enhances that part of the operation. And ergo, Aristotle’s advice that

‘the whole is greater than the sum of its parts’ takes effect. Technology in the oil and gas world has mimicked NASA in attempts and complexity for trialling concepts and developing systems that have changed the industry. New products and services have been in abundance in every sector, non-stop for years. And that’s a good thing!

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OPINION

MENT:

UCTION

ECTIVE Here, John Hoday asks - is the practice of well enhancement overused or simply misunderstood?

As with anything – toasters to Lamborghinis – it all starts with an idea that develops into a prototype that develops into a trial that develops into a full steam form of something. But the issue seems not to be introducing a concept, it’s accepting it. Production of oil and gas is reliant upon these technologies to maximise returns as cheaply as possible, and that’s the thinking

that innovators in the service sector need to bring to the table. But the operator needs to provide the platform to develop this on, and in Australia, that seems to be a lot tougher than imagined.

Develop, trial, operate The answer to the well enhancement puzzle lies in sharing the road to the

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rewards. Solutions that are effectively a product that increases production by a point or two may sound appealing, but might not shave millions of dollars off the cost of the overall operation. Some techniques may be routine in other parts of the world; but for them to work in Australia, outside of the box thinking is required to get the job done.

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OPINION

While sharing the rewards (financial or production) is doable, one unique approach is to share the risk as well. Producers should not simply demand lower costs for services – another option is to establish KPIs for service providers throughout a project, that make them a lot more accountable to providing quality rather than routinely average results. Partnering with a shared risk commercial proposal becomes a lot more appealing for a stronger partnership to work through the development and trial stages. It demands cooperation from both sides; one provides data and opportunity, the other brings a proven solution that solves an issue or two.

Synergy time The tender process is a necessary evil that takes a great deal of time and energy to complete. Although it is a reasonably tolerable way to make ‘like’ comparisons, at the end of it, the question always remains: did the best and brightest really make it to the top of the heap? And will a well really be ‘enhanced’ or merely budgeted for? Stepping back and looking at the technologies available, it’s difficult to run those through an actual tender process

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without looking like an apple in an orange bin sometimes. Using the risked methodology opens the door to putting the onus squarely on the vendor’s shoulders, as long as there is a fair set of terms for ample opportunity to get a project through to the operation stage. The resultant synergy will be beneficial to both sides. The producer will be comfortable knowing they have guided a vendor through their contract to operational practices and fully understand and trust the project. The service provider will have made a truly fit-for-purpose solution that has addressed a range of issues along the way. And a long term working relationship will be magically born.

Technologies A good example of technology that can fit anywhere in Australia, both on and offshore, is rigless completions with coil tubing (CT). Long regarded as the Swiss Army knife of the industry, the multi-capable units are merely brushing the surface in Australia – both in number and in work performed. Drilling, fracturing, stimulation/acidising, unloading, cleanout, velocity strings,

fishing, tool conveyance, logging (realtime and memory) plug operations – all completed efficiently and economically with reduced HSE risk due to less time around the wellhead and less manpower required. Now add some real value to the equation, by actually making the process a well enhancement project.

Well enhancement in action Some other technologies exist that are add-ons to the above-mentioned CT list. Concentric coil is used in conjunction with a specialised tool to clean out solids from wells extremely efficiently in a live underbalanced state, drastically reducing well damage from over-pressured cleanouts. Added to this is also the ability to perform a detailed pin-point flow test. Running artificial lift is another common practice. Combined with some of the newer, high efficiency jet pumps or gas lift in concentric coil, formation interference is eliminated and optimisation is a much more fine-tuned process. Abrasive perforations with sand produce increased and cleaner reservoir communication, eliminating the associated crush zone from explosives, not to mention

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OPINION

removing the explosive and radiation hazards entirely. But the true value of well enhancement comes from the fact that these services can all be performed by the same unit without rigging out of the way, and in a much shorter period of time. The results have been excellent and future well interventions have been greatly reduced because of that.

Made in Australia Best of all, these well activities are all proven and available in Australia. Looking at the vast opportunity to improve on the existing infrastructure in most of the basins has been discussed at great length in every industry conference with the synergy concept coming up again and again. Producers need to look for a better way to allow the service sector to do what they do best in bringing proven technology to the table. Maybe sharing risks with the vendor will not only throw a challenge for improvement, but the performance levels will undoubtedly reach where they need to be in Australia. Now that would be well enhancement!

SUMMER 2016 // ISSUE 3

STORAGE

underg

Optimising CSG production with

STORAGE

ground gas storage facilities by Glen W. Gill, Managing Director of Innovative Energy Consulting

uch has been written and discussed regarding the tremendous unconventional gas resource potential located in Australia, and coal seam gas development in South East Queensland has led the charge. After a rather slow start, CSG reserves and production in the region has exploded and now dominates eastern Australia’s gas supply. The major CSG producers have been preoccupied with a build-up of CSG production capability in preparation for the start-up of the six new LNG trains located at Gladstone. Operations are transitioning from project construction and deliverables to the commissioning stage, soon to be followed by the long term production operations stage which includes a very high annual well production replacement challenge. This is new ground for Australia’s upstream gas sector and new paradigms and new tools will have to be embraced in order to meet the challenge. Unconventional gas is by definition difficult to produce (refer to Figure 1) and this challenge increases as sweet spot wells age and as wells are added, connecting poorer quality resources. The ‘difficult to produce’ term describing unconventional resources in Figure 1 has many dimensions including very high capex per GJ of deliverability capacity, high operating costs on a per GJ of gas production, unpredictable new well performance, low production rates for a long period of time, relatively low recoverable gas reserves per well and a deterioration in well performance and gas recovery factor when well production is turned down, ramped up or shut-in by operators.

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STORAGE

100 md MEDIUM QUALITY

lity ua

10 md UNCONVENTIONAL Large Easy to find Difficult to produce

COALBED METHANE

TIGHT OIL

0.1 md

TIGHT GAS

GAS SHALES

1 md

LIQUIDS RICH SHALE GAS

0.01 md

LOWER QUALITY

Increased Technology Requirements

HIGH QUALITY

Increased Cost to Develop

ing as cr e De

1000 md

ir Q rv o se Re

CONVENTIONAL Small Hard to find Easy to produce

0.001 md “GAS HYDRATES”

0.00001 md

Figure 1. The Gas Resource Pyramid. Source: Canadian Society for Unconventional Resources.

How underground gas storage creates value Incorporating special purpose underground gas storage facilities into upstream unconventional gas operations can add significant value to any unconventional gas production operation. Access to gas storage can optimise CSG production operations by adding value in a number of ways. These include: • Outage protection during adverse weather conditions, unplanned outages and scheduled maintenance • Improving operational efficiency by levelling wellhead production rates regardless of the gas feedstock demand swings at Gladstone and any demand swings in the domestic gas market served by CSG. CSG producers derive a considerable benefit from greater field production efficiency. If suitable gas storage capacity is not available, CSG producers would have to meet monthly variations in the feedstock gas demand at Gladstone by either over building production deliverability or by acquiring peaking gas supplies from third parties. The former results in more wells and higher gas plant costs; and the latter is not that practical given the tight gas supply/demand scenario in eastern Australia and the pipeline distances to Gladstone from any peaking gas supplier (i.e. Bass Strait, Otway Basin or the Cooper Basin) • Mitigating the many risks associated with the uncertainty of drilling, completing and dewatering new gas wells each year to replace gas deliverability decline • Providing a sink for gas when either a planned or unplanned outage occurs at an LNG train

SUMMER 2016 // ISSUE 3

•

Enhancing the ultimate reserve recovery per well by minimising the fluctuation of well production rates. Furthermore, in the case of South East Queensland, it can also enhance the utilisation rate of the capital intensive LNG liquefaction trains by providing an alternative gas supply during unplanned gas processing plant outages, delivery interruptions associated with third party gas supplies and/or insufficient initial production rates from new wells. The recent collapse in oil linked LNG prices has accelerated the need to implement optimisation tools and strategies within the three CSG to LNG projects located in South East Queensland. Unconventional gas producers overseas rely on access to gas storage capacity and on liquidity in the short term physical gas trading market in order to ensure the optimisation of production operations, enhancing the net present value of reserves and enhancing the recovery factor or ultimate gas reserves recovered per well. South East Queensland not only has negligible liquidity in the short term trading market at Wallumbilla, but also very limited access to gas storage facilities and services. Incorporating a high performance, quick cycle gas storage facility, utilising either a field of solution mined salt caverns or high quality depleted gas reservoirs, downstream of gas processing plants and upstream of the LNG liquefaction trains, would significantly optimise the net present value of the future CSG to LNG operations. While it is generally understood that unconventional gas resource development requires a very different approach from a technical perspective than conventional gas operations, it is not generally understood that unconventional

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STORAGE

gas resource development also requires a very different business model. All three LNG export projects located in South East Queensland are facing tough economic conditions and this tool, if utilised, would create a greater resilience to low LNG prices by enhancing profit margins at whatever the LNG price is under their LNG export contracts. It is a proven tool that has been demonstrated to work for unconventional gas producers in competitive gas industries, such as those across North America where very low gas prices have generally existed for decades and yet unconventional gas supplies have flourished.

Gas storage potential The type of underground gas storage that would best serve future South East Queensland CSG production is, as has been previously mentioned, a high deliverability, high injection, quick cycling facility. This facility would be used to respond to high demands for gas injection or withdrawal, depending on whether an LNG train or a large gas plant is temporarily out of operation. Under normal steady state conditions, it would have to respond to much smaller short term gas supply disruptions and fluctuations in feedstock requirements at Gladstone due to operational capacity changes with ambient temperatures. There are two types of underground gas storage facilities available and their general performance characteristics vary considerably and are described in Table 1. Gas storage facilities utilising high quality depleted gas reservoirs, large compression facilities and many large diameter WWW.UNCONVENTIONALOILANDGAS.COM.AU

horizontal injection/withdrawal wells could accommodate the long term requirements of the South East Queensland CSG to LNG operations, but such reservoirs do not appear to exist in either Queensland nor in South Australia. Geologically, depleted reservoir formations must have high permeability and porosity for gas storage application, and these reservoir parameters must be extremely high for cycling gas more than once per year. Injecting and withdrawing gas at high rates from depleted reservoirs is a challenge even when they are of very high quality. Geographically, depleted reservoirs would be best located in South East Queensland or within a reasonable distance from Roma in order to minimise the length of a large gas pipeline connecting the storage facility with existing and future large diameter pipeline infrastructure serving Gladstone. While gas storage facilities utilising depleted reservoirs, on average, are the lowest cost and easiest to develop, operate and maintain for seasonal gas storage operations, they are not the preferred option for the optimisation of the CSG production operations located in South East Queensland and the associated gas pipeline and LNG liquefaction trains. Both AGL and the GLNG joint venture have recently converted depleted reservoirs located in the Surat Basin into gas storage facilities. Their respective projects are known as the Silver Springs and the Roma Underground Gas Storage (RUGS) facilities, both located near Wallumbilla and both driven by the new CSG to LNG industry. The preferred method of gas storage for the optimisation of unconventional gas operations involves the use of large underground salt caverns solution mined in thick relatively pure

SUMMER 2016 // ISSUE 3

SAFETY

Facility

Description

Injection Period Required to Fill

Withdrawal Period Required to Empty

Operating Costs

Depleted Reservoirs

Low deliverability, low cycling, high working gas capacity

120-200 days

20-120 days

High with possible gas losses

Salt Caverns

High deliverability, 20 days multiple cycles per year, low working gas capacity

2-20 days

Low with no gas losses

Table 1. Generic gas storage facility characteristic (Eydeland and Wolyniec 2003).

4 6

3 5

No of Salt Deposits

Sedimentary Basin

Age of Main Salt Formation

Bonaparte Gulf

Devonian

Canning

Silurian

Officer

Precambrian

Amadeus

Precambrian, Cambrian

Arckaringa

Cambrian

Adavale

Devonian

Figure 2. Known underground major salt deposits in Australia. Source KBB Underground Technologies

SUMMER 2016 // ISSUE 3

salt deposits. Salt caverns brined out of thick salt beds or domes are essentially large pressure vessels that, unlike depleted gas reservoirs, can cycle gas in and out at tremendous rates. Thousands of salt caverns have been made in Europe and in North America for the sole purpose of underground gas, oil or natural gas liquids (NGL) storage. While this is a new concept for Australia, salt caverns have been solution mined in North America and Europe since the 1940s. While first used to store NGLs, LPGs and oil, salt caverns used to store and cycle gas commenced in Canada in 1961 and this concept quickly spread to the US and Europe. As of 2003 the number of salt caverns used for the storage and cycling of hydrocarbons exceeded 1,000 in the US (over 650 in Texas alone), 100 in Canada and 200 in Europe. Salt domes are specifically sought after for this application around the world. The much more common bedded salt deposits can be used for liquid hydrocarbon storage but the much smaller caverns associated with bedded salt are rarely used for gas storage. Australia is rather lucky for it has a relatively widespread distribution of world class salt domes (refer to Figure 2) and one is located in relatively close proximity to the CSG production operations in South East Queensland. Innovative Energy Consulting has secured a large mining tenement over the Boree Salt immediately south of Blackall, Queensland in the Adavale Basin, and has been promoting the development of a world class high performance gas storage facility utilising solution mined large salt caverns. This is the only large salt deposit known to exist in eastern Australia and can easily accommodate existing and future gas storage requirements for unconventional gas feedstocks to LNG export facilities at Gladstone.

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4th annual

7-10 March 2016 I Four Seasons Hotel Sydney

Australiaâ&#x20AC;&#x2122;s premier event for all domestic gas market stakeholders

With key industry speakers including:

Jeff Makholm Senior Vice President NERA Consulting (USA)

Steve Bielby Chief Executive Officer Gas Industry Company (New Zealand)

Rod Sims Chairman Australian Competition and Consumer Commission

David Baldwin Chief Executive Officer Integrated Gas Origin Energy

Martin Ferguson Group Head of Natural Resources Seven Group Holdings Chairman APPEA Advisory Board

Rod Duke Vice President Downstream Santos

Paul Adams Managing Director Jemena

Stuart Jeffries Director Gas Marketing ExxonMobil

Rob Wheals Group Executive Transmission APA Group

Mark Cully Chief Economist Department of Industry, Innovation and Science

Graeme Bethune Chief Executive Officer EnergyQuest

Gary Barnes Coordinator General, Office of Major Projects, Infrastructure and Investment Northern Territory Government

Malcolm Roberts Chief Executive Officer APPEA

Clare Savage Richard Cottee Executive Director Policy Managing Director Business Council of Central Petroleum Australia

Barry Goldstein Executive Director, Energy and Resources South Australian Department of State Development

Peter Geers Executive Group Manager, Markets Australian Energy Market Operator

David Rynne Chief Economist Queensland Department of Natural Resources and Mines

Kylie Hargreaves Deputy Secretary, Resources and Energy NSW Department of Industry

Innes Willox Chief Executive Officer Australian Industry Group

Rosemary Sinclair Chief Executive Officer Energy Consumers Australia

Ian Davies Chief Executive Officer Senex Energy

Additional conference day on 10 March!

ly te ra ble pa ka Se oo b

New for 2016

Gas Networks Future Forum

Tim Nelson Head of Economics, Policy and Sustainability AGL Energy

Cheryl Cartwright Chief Executive Officer Australian Pipelines and Gas Association

PLUS! Full day in-depth learning sessions on Monday 7 March In-depth Learning Session A:

Forecasting gas prices across jurisdictions and understanding potential scenarios and their implications for users

Creating a more efficient gas market Encouraging new supply Meeting the needs of users

Facilitated by Oakley Greenwood

In-depth Learning Session B:

Early Bird Discount

Learning from international experiences in designing a more efficient gas market - what does a competitive gas market need?

Facilitated by NERA Consulting

Endorsing bodies:

Supporting partners:

Official media partner:

Content partners:

Organised by:

Media partners:

+61 (0) 2 9977 0565

+61 (0) 2 9977 0567

info@questevents.com.au

www.questevents.com.au

RESOURCES UPDATE

FURTHER

where’s the

SUMMER 2016 // ISSUE 3

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RESOURCES UPDATE

AFIELD

oil and gas? A

cross Australia, geological basins containing potential sources of unconventional oil and gas are being explored and assessed to determine their suitability for commercial development activities. Enhancing our understanding of the quantity of potential resources and the conditions within each basin is vital for the continuing forward momentum of Australiaâ&#x20AC;&#x2122;s unconventional oil and gas industry. In the previous edition of Unconventional Oil & Gas we examined some of the basins where unconventional development has progressed the furthest, including those already producing commercial quantities of gas to the market. In Part 2 of this article, we explore a range of additional unconventional basins throughout Australia where exploration activities are underway, including a number of underexplored basins with significant unconventional potential waiting to be unlocked.

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SUMMER 2016 // ISSUE 3

RESOURCES UPDATE

MARYBOROUGH BASIN (QLD)

The Maryborough Basin is a largely unexplored basin that occupies 9,100 square kilometres onshore and 15,500 square kilometres offshore in South East Queensland. Although more data must be gathered on the basin’s conditions before the full extent of its unconventional resources can be evaluated, parts of the basin are considered prospective for shale gas, CSG and tight gas. While the Maryborough Basin was included in the 2013 EIA/ ARI World Shale Gas and Shale Oil Assessment, due to a lack of geologic data only the northern portion of the basin was evaluated, focusing on the Maryborough Formation as the basin’s primary shale gas target. The risked gas in-place for these shales was estimated at 64Tcf, with a risked, technically recoverable shale gas resource of 19Tcf. Due to its high thermal maturity, the Maryborough Formation is dry-gas prone and thus is not considered prospective for shale oil. Exploration of the area’s resources is currently still in the frontier stage. Blue Energy holds all three exploration permits for the basin and is currently seeking a project-based consolidation of the permits, with a view towards selecting the optimum geological location for testing wells and reducing effort duplication and surface impacts.

UNCONVENTIONAL RESOURCES

ARCKARINGA BASIN (SA)

The Arckaringa Basin is a frontier South Australian basin that has recently shown impressive potential shale oil and gas resources, and may also contain other unconventional hydrocarbons. The 2014/15 exploratory drilling program by Linc Energy discovered both shale gas and oil resources with potential yields of up to 54L of oil per tonne in the Stuart Range Formation and potential yields of up to 70L of oil per tonne in the Boorthanna Formation. Linc Energy now plan to drill a number of additional exploration wells and assess whether bringing the resource to commercial production is economically viable at this point in time.

UNCONVENTIONAL RESOURCES Potential shale gas, shale oil, CSG, tight oil, tight gas

MAIN TROUGHS OR FORMATIONS Mount Toondina Formation (possible CSG), Stuart Range Formation (possible shale oil and gas), Boorthanna Formation (shale oil)

KEY ACTIVE COMPANIES Linc Energy

Assessed shale gas, possible CSG and tight gas

KEY ACTIVITY

PROSPECTIVE RESOURCES

2014/15 drilling program by Linc Energy showed shale gas and oil

64Tcf shale gas (EIA, 2013), CSG and tight resources not formally assessed

RISKED RECOVERABLE AMOUNT 19Tcf shale gas (EIA, 2013)

MAIN TROUGHS OR FORMATIONS The Maryborough Formation (potential shale or tight gas) including the Goodwood/Cherwell Mudstone, the Tiaro Coal Measures (potential CSG or shale gas) and the Burrum Coal measures (potential CSG)

KEY ACTIVE COMPANIES Blue Energy

SUMMER 2016 // ISSUE 3

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RESOURCES UPDATE

PERTH BASIN (WA)

The Perth Basin is an onshore and offshore sedimentary basin that covers approximately 172,300 square kilometres in Western Australia. Various parts of the basin are considered prospective for tight gas and shale gas and oil. The EIA has assessed the potential resources of two main shale formations in the basin, the Permian Carynginia and the Triassic Kockatea shales. The Carynginia Shale is estimated to contain 124Tcf of gas in-place, with a risked, technically recoverable shale gas resource of 25Tcf. This prospective area is inclined to dry gas, and not thought to contain shale oil. The Triassic Kockatea Shale was estimated to contain gas in-place of 36Tcf, with a risked, technically recoverable shale gas resource of 7Tcf. It is also estimated to contain 14billion barrels of shale oil-in-place, with a risked, technically recoverable shale oil/condensate resource of 0.5billion barrels. Tight gas resources are being assessed in the Yarragadee Formation, Dongara/Wagina Sandstone, Irwin River Coal Measures and High Cliff Sandstone. The proximity of parts of the Northern Perth Basin to pipelines and other vital infrastructure means that it is likely to be the first area in Western Australia to supply shale gas to the market.

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

PROSPECTIVE RESOURCES 160Tcf shale gas overall; 14billion barrels shale oil, tight oil and gas not formally assessed (EIA, 2013)

RISKED RECOVERABLE AMOUNT 19Tcf shale gas (EIA, 2013)

MAIN TROUGHS OR FORMATIONS Dandaragan Trough, Carynginia Formation, Kockatea Formation, Irwin River Coal Measures, Yarragadee Formation, Dongara/Wagina Sandstone, High Cliff Sandstone, Sue Coal Measures

KEY ACTIVE COMPANIES AWE Limited, Norwest Energy, Origin Energy, Empire Oil and Gas, Latent Petroleum JV with Transerv and Alcoa, Bharat PetroResources, Warrego, UIL, Pilot Energy

KEY PROJECTS The Warro Gas Project is targeting tight gas, Dandaragan deep exploration, Arrowsmith exploration. AWE is exploring for shale and tight gas and has drilled a number of appraisal wells. Empire are appraising shale and tight gas potential in their acreages. Warrego is appraising tight gas in the West Erregulla gas field.

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SUMMER 2016 // ISSUE 3

RESOURCES UPDATE

BEETALOO BASIN (NT)

The Northern Territoryâ&#x20AC;&#x2122;s Beetaloo basin is considered prospective for shale and tight oil and gas, primarily within its Middle Velkerri and Lower Kyalla shales. A number of appraisal wells targeting unconventional hydrocarbons have been drilled within the basin in recent years. The EIA estimates that the Beetaloo Basin contains 194Tcf shale gas in places and 93billion barrels of shale oil/ condensate. This includes 94Tcf shale gas and 28 billion barrels shale oil/condensate from the Middle Velkerri Shale and 100Tcf shale gas and 65billion barrels shale oil/condensate from the Lower Kyalla Shale. The risked recoverable amounts are 44Tcf shale gas and 4.7 billion barrels shale oil/condensate. A number of exploration activities are underway in the basin to determine whether these resources are suitable for commercial development.

UNCONVENTIONAL RESOURCES Assessed shale gas, possible CSG and tight gas

PROSPECTIVE RESOURCES

The Georgina Basin is a large frontier basin that straddles the Northern Territory/Queensland border and is thought to have significant unconventional oil and gas resource potential. The EIA has assessed oil and gas resources for two prospective areas: an eastern region covering the Dulcie Syncline and surrounding area, and a western region covering the Toko Syncline and surrounding area. The total risked wet and dry shale gas in-place in both areas was estimated at 67Tcf, with a risked, technically recoverable shale gas resource of 13Tcf. Total risked shale oil and condensate in-place was estimated at 25 billion barrels, with a risked, technically recoverable shale oil and condensate resource of 1 billion barrels.

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

PROSPECTIVE RESOURCES 67Tcf shale gas, 25 billion barrels shale oil/condensate

64Tcf shale gas (EIA, 2013), CSG and tight resources not formally assessed

RISKED RECOVERABLE AMOUNT

MAIN TROUGHS OR FORMATIONS

44Tcf shale gas; 4.7billion barrels shale oil/condensate; tight gas and oil not formally assessed

L. Arthur Shale (Dulcie Trough), L. Arthur Shale (Toko Trough), Arrinthrunga Formation (shale, tight), Inca Shale (shale, tight), Thorntonia Limestone (shale, tight), Beetle Creek Formation (shale), Georgina Limestone (shale, tight)

MAIN TROUGHS OR FORMATIONS M. Velkerri Shale (tight and shale), L. Kyalla Shale (shale)

KEY ACTIVE COMPANIES

13Tcf shale gas, 1 billion barrels shale oil/condensate

KEY ACTIVE COMPANIES

Falcon Oil and Gas Ltd, Hess, Origin, Pangaea Resources

Statoil, Petrofrontier Corp., Central Petroleum, Total, Armour Energy

KEY PROJECTS AND ACTIVITY

Beetaloo Basin Project (Origin, Sasol and Falcon Oil & Gas JV), Falcon Oil and Gas Ltd and Hess JV

GEORGINA BASIN (NT, QLD)

SUMMER 2016 // ISSUE 3

South Georgina Exploration Program (Central and Total Oil)

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RESOURCES UPDATE

GALILEE BASIN (QLD)

The Galilee Basin is located in western Queensland and covers around 247,000 square kilometres. Various exploration activities are currently underway in the area to determine its suitability for unconventional gas development, with potential hydrocarbon resources including coal seam gas, tight gas and tight oil and gas. Greenfields exploration for CSG has focused mostly on the region’s Permian coal measures, while the area’s shale has been recognised as a promising potential resource of shale gas and oil, due to its high organic matter content, extensive natural fracturing and isolation from aquifers.

MCARTHUR BASIN (NT)

The McArthur Basin is a large underexplored Northern Territory basin covering an area of approximately 180,000 square kilometres. While it is still considered a frontier basin, the McArthur Basin is thought to have very high unconventional gas and oil potential, particularly in thick black shale units in McArthur Group (Barney Creek Formation) and Roper Group (Kyalla and Velkerri Formations).

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

UNCONVENTIONAL RESOURCES

MAIN TROUGHS OR FORMATIONS

Potential CSG, shale gas, shale oil, tight gas

McArthur Group (Barney Creek Formation) and Roper Group (Kyalla and Velkerri Formations)

MAIN TROUGHS OR FORMATIONS Betts Creek Beds (potential CSG and shale), Aramac Coal Measures (potential CSG and shale), Bandanna Formation (potential CSG), Lake Galilee Sandstone (potential tight)

KEY ACTIVE COMPANIES Comet Ridge, CNOOC, Galilee Energy Limited

KEY ACTIVITY

KEY ACTIVE COMPANIES Armour Energy, Santos, Origin Energy, Sasol Petroleum Australia, Pangaea (NT), Imperial Oil and Gas, Inpex Oil and Gas Australia

KEY PROJECTS AND ACTIVITY Various exploration and appraisal activities are underway

Galilee Gas Project

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SUMMER 2016 // ISSUE 3

ALL CYLINDERS FIRING: GLNG JOINS THE EXPORT RANKS

SUMMER 2016 // ISSUE 3

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As the Gladstone Liquefied Natural Gas project began its first export deliveries in October, it marked the successful completion of all three CSG-LNG mega projects delivering Queensland coal seam gas to Asian markets. With cylinders now firing on all three projects, we take a look back at the road from concept to construction to completion of the project.

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SUMMER 2016 // ISSUE 3

PROJECT

he Gladstone Liquefied Natural Gas (GLNG) project was first floated by project owner Santos in July 2007, when it proposed a project encompassing the planning, construction and operation of three major components including:

•

Upstream gas fields development of predominately coal seam gas (CSG) deposits in the Bowen and Surat basins • A 420km gas transmission pipeline linking the upstream gas fields to an LNG liquefaction and export facility located on Curtis Island, near Gladstone • An LNG liquefaction and export facility development (comprising LNG facility and associated infrastructure including bridge and access road) on Curtis Island, near Gladstone. Santos’ announcement was followed in 2008 by Origin Energy’s Australia Pacific LNG (APLNG) project and BG’s Queensland Curtis LNG (QCLNG) project, establishing Gladstone, Queensland as a major hub for the export of Australian LNG to Asian trading partners. Construction of the GLNG project began in 2011 and has ultimately involved more than 95 million work hours. More than 10,000 people have worked on the project which saw more than $15billion invested Australia- wide, including $8billion in Queensland alone.

The GLNG story The GLNG project was led by Santos, in partnership with three of the world’s leading energy companies – PETRONAS from Malaysia, Total from France, and KOGAS from South Korea. The groundbreaking US$18.5billion project, which will export 3-4 million tonnes per annum of LNG, became operational in October 2015 when its first export cargo set sail, bound for South Korea.

SUMMER 2016 // ISSUE 3

Behind the scenes, more than seven years went into the construction of the LNG plant on Curtis Island, and the pipeline that delivers gas from the fields into the processing plant. Including the planning and environmental impact study stages, Santos has invested almost a decade in bringing the project to fruition. The Final Investment Decision to proceed with the project was made in January 2011, and construction at the LNG plant kicked off in May 2011 amid much fanfare, at a ceremony attended by the Prime Minister, Queensland Premier and senior representatives of the project partners. The commencement of works on the GLNG plant was the culmination of more than three years of planning and preparation. The construction of the LNG plant in turn took three and a half years, with the final module installed on its two LNG processing trains in November 2014. Santos GLNG General Manager Downstream Operations Brenton Hawtin said the construction of such a vital part of the plant, often referred to as ‘the big fridge’, was a key milestone for the project. “LNG trains are essentially big refrigerators that will take natural gas piped from our Queensland gas fields and condense it into liquid form so it can be safely and efficiently shipped. “Once we’re in full production, these massive pieces of infrastructure will together produce up to 7.8 million tonnes of liquefied natural gas each year. “Each module had to be built with a margin of error of only 2mm – which is amazing when you think the heaviest weighed more than 2,500 tonnes and longest stretched nearly 75 metres,” Mr Hawtin said. The modules were constructed in Batangas in the Philippines and shipped to Curtis Island individually. At the peak of construction, a 2,000-strong workforce was stationed on Curtis Island, constructing the GLNG processing facilities.

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PROJECT

Connecting gas to markets The other critical element during the construction phase was the building of the transmission pipeline from the gas fields to Curtis Island. Construction of the pipeline commenced in September 2012, with the pipeline build undertaken by contractor Saipem Australia. Construction works commenced in Arcadia Valley, traversing north and then north-east to cross the Expedition Range towards Curtis Island. Construction of the pipeline took two years to complete, with first gas fed into the pipeline via the project’s primary compressor station in the Fairview field in south-west Queensland. In total, the construction process involved more than six million work hours, and saw the welding of more than 36,000 segments of 1.05 metre diameter pipe, weighing in excess of 250,000 tonnes in total. Individual land access agreements were also successfully negotiated with more than 120 landholders. The construction of the pipeline also involved building a challenging crossing between the mainland and Curtis Island, under the Gladstone Harbour. The 4.3km pipeline was constructed by Thiess, traversing under the sea bed and crossing the narrows in Gladstone without dredging or trenching, minimising the project’s impact on the harbour. First gas to Curtis Island Following the construction and commissioning of the pipeline, the focus turned to delivering first gas to the LNG plant on Curtis Island. This important milestone was achieved in August 2015, signalling that the construction team was closing in on start-up for the project. The delivery of gas into Train 1 was a key milestone in the ongoing plant testing and commissioning process, and allowed the

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team to move forward with other critical tasks that needed to be completed before first gas deliveries, including the start up Train 1’s ‘front end’ pre-treatment units and the chilling down of the ‘cold end’ refrigeration units to make LNG. Santos recently announced the GLNG project has started producing its first liquefied natural gas (LNG) on Curtis Island, Queensland, on schedule and within budget. LNG production from Train 1 quickly followed in September, and Train 2 also moved quickly towards first production. The first LNG shipment from the plant was recorded in October 2015. The first cargo was carried by the Malaysian-owned LNG ship Seri Bakti and delivered to South Korea.

An historic journey The first shipment marked the culmination of an historic journey from Santos; one which had stretched almost ten years from initial concept to project delivery. GLNG is the largest project Santos has ever undertaken as a company, and over its life, the GLNG project will deliver millions of tonnes of LNG to Asian trading partners – and billions of dollars in tax revenues to governments. At the time of the first delivery, Santos’ then CEO David Knox said “Successfully delivering our first operated LNG project is a testament to our dedicated employees and contractors, the support we have received from governments, local communities, our customers and shareholders, as well as the strong relationships we enjoy with our joint venture partners. “The first cargo from GLNG strengthens our position as a major and competitive LNG supplier to Asia. “GLNG is a robust project and will generate strong cash flows for the business for decades to come.”

SUMMER 2016 // ISSUE 3

THE GOOD OIL with Paul Carter

ADAPT OR DIE

he Western Australian health department has just given a clean bill of health to the contentious and entirely misunderstood gas extraction technique known as hydraulic fracturing. Which is great, given that it’s already in use by 90 per cent of the modern world. They said: “It can be done safely and that it would under no circumstances turn into a cluster frack at all.” Over here in the west, you know, the “minted” state, well, sadly, the minty fresh veneer has gone. No longer riding the wave of grossly overpaid hedonism – that is, everyone not involved in state politics or dialled into a major government construction projects – is doing it tough right now. We have amongst the highest unemployment, domestic violence, work related suicide and drug related crime figures in the country. I called the police the other day because a relatively well dressed middle aged man was keen on coming into my home and stabbing me, my dog, the goldfish and the kids in the face with a fountain pen. The police didn’t turn up, but did call me back an hour later to check if indeed we had

SUMMER 2016 // ISSUE 3

been stabbed. Luckily the man hissed at me and moved on after I started quizzing him on the use of domestic frac sands. But he did glare over his shoulder at me in that knowing way. All jokes aside, the point is this – the number of recently redundadised oil and gas men and women is frightening. They’re dropping like flies and equally despised. It would be interesting to know how many ‘young people’ (I use the term loosely as I’m over 45 now) are deferring their studies away from a trajectory that would have lead them into drilling. They are directing their bright young talent toward other industries. Just look at how our drilling industry has changed in the last twelve months. Drilling rigs are being retrofitted into workover rigs at an alarming rate as everyone tries to adapt. The talent pool of experience is flaking off like dandruff. The entire unconventional drilling industry on our eastern seaboard is in limbo. Five years ago you’d jump on LinkedIn to look for a drilling hand – and up pops his details, with a photo, the one with him on the drill floor, exposed to the elements, covered in crap, leathery hand resting on the brake, large wad of chew smashed into

his bottom lip. This is a man who knows how to rope a barmaid, he can understand and repair all in his domain, one look in his steely eyes tells you instantly, he will drive the drilling rig in all weather 24/7 and do it well. Today, completing the same search, up pops a buff hipster sipping a foamy latte in a Captain Kirk cyber chair reclined in hi-vis air conditioned comfort. He’s got the full all-singing, all-dancing 21st century modern seventh-gen robotised drilling rig under him. He’s got the all you can eat wi-fi salad bar, and why not – it’s the future right? The only way he’s going to damage his back or cut his fingers off is if he overdoes it in the gym or in the kitchen. For me, this is exactly what I grapple with day in and day out – I find myself bridging the gap between the old and the new, but as the drilling work slows down, the gap is increasing exponentially. Today, the young Jedi’s of the drilling world are not learning all the ways of the force from the old and mostly redundant. I walk into countless meetings now, and everyone’s still got there blast shields down on their helmets, waving their lightsabers about like drunks at a piñata. I jest of course, I represent the

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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

on drilling rigs is so competitive now that an operator will pick up a brand new deepwater rig with the plastic covers still on the cyber-chair, ‘new rig’ smell still in tact for a bargain $US250,000 a day. A year ago it would have cost more than twice that. It’s the year of collapses and acquisitions, and all the while, big oil wades through the detritus, scanning the depths of maritime acreage from the Atlantic Rim to the entire length of the West African coast. All those basins with definitive petroleum systems will soon be drilled at rock bottom rates. I shall continue to bridge the gap, after all, the government wants me to continue knocking my pan out til 75. I will not panic after we win that massive tender because I’m looking at a dozen 28 year olds doing ‘caRter is a KInd moDERN Da Of a good impression of a scared horse. It’s a natUYRaiNLDIstaNOraYtJonEs . . . elLER.’ one massive waiting game – remember life before the China boom, when oil was $US33/b and stayed there for almost 20 years? Remember when oil and gas people actually put a proper signature at the footer of their email and carried a business card? Our drilling industry is a wild thing, straP a yOURself In coyote, a fringe dweller caught in the worst drought since the end of world war two. Will she eat her young to survive?

RIDE LIKE HELl aND Get tHere

bog standard middle-aged, middlemanagement oil man. I’m no Jedi, but I am not the only one who walks into these meetings knowing all I will be asked for is another pricing reduction and all I will walk out with is no definitive idea of what’s going to happen next year. No one is interested in the pool of experience I’m desperately trying to keep employed. It’s just the cycle isn’t it, and there is lots of collateral damage. I see people use the term ‘cleansing’ to describe the programs of redundancy that are happening across the country and at the end of the day, it’s actually fascinating to watch. Operators will relentlessly push all those below them into a war of attrition, based entirely on price, while they continue to move forward. The oil price is no longer above $US100/b, it’s below $US50/b now. What this means is that the big operators are no longer targeting 20 wells a year, it’s 10. The portfolio is spread carefully across highly scrutinised 2D and 3D seismic mapping, and gone are the days of dumping all you have into one or two lucrative wells. Today’s explorers want an exploration strike rate of 20 per cent at a sub $US4/b cost of discovery. The day rate

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

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SUMMER 2016 // ISSUE 3

FEATURES SCHEDULE

Autumn 2016 MAJOR FEATURE

Deadline: 15 April 2016

Winter 2016 MAJOR FEATURE

ICT

Deadline: 17 June 2016

Drilling equipment

Telecommunications, radio, SCADA,

Rigs and rig technology, rig maintenance,

IT, security, big data, mobile devices,

fraccing, fluids and proppants, water

cloud computing

management

PRODUCTS SHOWCASE

Transport

PRODUCTS SHOWCASE

Power generation

INDUSTRY ANALYSIS

Regulatory review

INDUSTRY ANALYSIS

Global energy outlook

BASIN FOCUS

Amadeus

BASIN FOCUS

Beetaloo

GEOGRAPHIC FOCUS

Northern Territory

GEOGRAPHIC FOCUS

Western Australia

DISTRIBUTION

APPEA 2016

Spring 2016 MAJOR FEATURE

Deadline: 26 August 2016

Logistics

Summer 2017 MAJOR FEATURE

Deadline: 9 December 2016

Safety

Land access and management,

Personal safety gear, facility safety

road construction, accommodation,

equipment, gas monitoring equipment

rig maintenance, recruitment and HR PRODUCTS SHOWCASE

Water management

PRODUCTS SHOWCASE

Pipes and processing

INDUSTRY ANALYSIS

Reserves update

INDUSTRY ANALYSIS

Performance scorecard

BASIN FOCUS

Gunnedah

BASIN FOCUS

Canning

GEOGRAPHIC FOCUS

Queensland

GEOGRAPHIC FOCUS

South Australia

ADVERTISERS’ INDEX

AJ Lucas Group Ltd ��OBC

Pivotel................................................................................29

APPEA................................................................................33

Pressure And Safety Systems �� 9,45

Australian Domestic Gas Outlook...................................59

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

LAB SA �� 3

Vacuworx Australia �� 15

Monkey Media �� IBC

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

SUMMER 2016 // ISSUE 3

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