Oil & Gas Today March 2020 by Prime Creative Media

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MARCH 2020

The rise of Australian gas APA Groupâ&#x20AC;&#x2122;s Kevin Lester and his journey in a growing sector

APPEA PROFILE

ASSET MANAGEMENT

LNG MARKET OUTLOOK

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A new horizon for Australian oil and gas As Australia becomes a world leader in the LNG sector, a new resource for the oil and gas industry has been launched. BEN CREAGH

elcome to the first edition of Oil & Gas Today, brought to you by Prime Creative Media. With Australia’s oil and gas industry operating billions of dollars worth of projects, Oil & Gas Today will provide up-to-date information on today’s operations and profiles of the personalities driving the industry into the future. Oil & Gas Today will be your guide to the latest products, technology and techniques that are paramount for business leaders to make informed operational decisions. With Oil & Gas Today, Prime Creative Media strengthens its commitment to the Australian resources sector, as the publisher of Australian Mining, Safe to Work, Oil & Gas Bulletin and Oil & Gas Industry News. We are consolidating our support to help grow the resources industry with the launch of this new publication, which amalgamates PPO Projects, Gas Today and Oil & Gas Industry News. Our first edition sets the foundation for this exciting new resource. The publication provides a positive platform

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PUBLISHER Christine Clancy MANAGING EDITOR Ben Creagh Tel: (03) 9690 8766 Email: ben.creagh@primecreative.com.au JOURNALIST Molly Hancock Tel: (03) 9690 8766 Email: molly.hancock@primecreative.com.au

for the industry through in-depth coverage on new projects, integrity and maintenance, technology, and the people who power this great industry. The first edition of Oil & Gas Today arrives as Australia has become the leading exporter of liquefied natural gas (LNG) in the world, a journey to the top highlighted in this issue. We discuss this rapid expansion in profiles with two important figures from the gas sector, APA Group’s group executive of infrastructure development, Kevin Lester, and Australian Petroleum Production & Exploration Association chief executive, Andrew McConville. While both men are ecstatic about Australia’s recent achievements, they are just as optimistic about the opportunities in front of the industry. We look at what’s ahead for Australia’s oil and gas sector now it has reached this pinnacle in an interview with Deloitte Australia’s national oil & gas leader Bernadette Cullinane. Oil & Gas Today incorporates PPO Projects, previously a standalone publication, within the magazine. PPO will continue to provide readers with updates on the latest activities

CLIENT SUCCESS MANAGER janine clements Tel: (02) 9439 7227 Email: janine.clements@primecreative.com.au SALES MANAGER jonathan duckett Tel: (02) 9439 7227 Mob: 0498 091 027 Email: jonathan.duckett@primecreative.com.au DESIGN PRODUCTION MANAGER Michelle Weston ART DIRECTOR Blake Storey GRAPHIC DESIGNERS Kerry Pert, Madeline McCarty

at Australia’s major operations with a comprehensive project database. PPO also remains a premium online subscription-based news service, providing daily updates on company news, as well as the project database. We are excited to be involved in the oil and gas industry and look forward to your feedback about the first edition.

Ben Creagh Managing Editor bencreagh@primecreative.com.au

FRONT COVER Kevin Lester of APA Group

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IN THIS ISSUE FEATURES

Lester finds 12 Kevin satisfaction in rise of gas APA Group’s role in the energy infrastructure market future of oil and gas? 16 The Deloitte’s Bernadette Cullinane shares some industry trends leads the LNG 20 Australia world How the nation has become the number one LNG exporter Australia benefits 22 Ensuring from oil and gas APPEA strengthens its voice for the industry

care for oil and 52 Top-quality gas LINX Cargo Care Group commits to becoming a household name

The history of PPO How Barry Wood started a national project database

PPO Project summaries

Pickles creates industry

The latest updates on Australia’s key projects, including project map

pivotal role of 54 The Australian natural gas

keynote speakers 60 AOG confirmed Woodside and Chevron experts take to the stage into eighth ADGO 63 Insight Domestic gas sector meets to discuss future direction

APGA chief executive shares his insights on the industry thermal gas 56 Advancing flow meters

platform The company’s oil and gas division gathers momentum

FCI meters offer a step forward for process and plant performance

REGULARS 6 64 66

News Products Events

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INDUSTRY NEWS

SCOMO VOICES SUPPORT FOR USE OF NATURAL GAS Prime Minister Scott Morrison believes there is a need for greater use of natural gas as Australia strives to cut emissions and manage the transition to greater use of renewables and alternative energy sources. The Australian gas industry has welcomed the comments Morrison told the National Press Club in Canberra. Morrison said: “We need to get the gas from under our feet. There is no credible energy transition plan for an economy like Australia … that does not involve the greater use of gas.” “Gas can help us bridge the gap while our investments in batteries, hydrogen and pumped hydro energy storage bring these technologies to parity to traditional energy sources … so right now, we’ve got to get the gas.” Australian Petroleum Production and Exploration

Association chief executive Andrew McConville said the Prime Minister was right to highlight the critical role gas has to play in supporting increasing investment in renewable energy generation. He said gas’ role included delivering reliable and affordable power when solar or wind generation were not available, and in doing so with less than half the emissions of existing coal-fired power generation, which continued to provide more than 70 per cent of Australia’s electricity. “Natural gas has a key role to play, and not just when the wind isn’t blowing and the sun isn’t shining,” McConville said. “If industry can further explore and develop onshore and offshore resources with support from governments, Australia’s natural gas can continue to underpin a nation building shift to a lower carbon, sustainable energy economy.

OIL AND GAS DISCOVERIES HIT FOUR-YEAR HIGH Oil and gas companies discovered 12.2 billion barrels of oil equivalent (boe) in 2019, the highest volume since 2015, according to estimates from Rystad Energy. There were 26 discoveries of more than 100 million barrels of oil (mmboe) last year, with offshore regions dominating the list of new oil and gas deposits. Guyana continued to be a success story. ExxonMobil added four new discoveries within its offshore Stabroek block, while Tullow Oil’s Jethro and Joe exploration wells established the presence of a working petroleum system to the west of the Stabroek block. Rystad estimates the discoveries in Guyana hold cumulative recoverable resources of around 1.8 billion boe. “ExxonMobil can be declared explorer of the year for a second year in a row thanks to its ongoing efforts and results in Guyana, along with significant investments in Cyprus. The supermajor was exceptional, both in terms of discovered

Oil discoveries have risen internationally.

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volumes and value creation from exploration,” Rystad Energy upstream senior analyst Palzor Shenga said. ExxonMobil discovered around 1.07 billion boe in additional net resources in 2019. Rystad estimates the value creation from these volumes to be around $2.7 billion, driven by the Guyana prospects. BP’s Orca gas field off the coast of Mauritania was not only the largest single discovery, but also the deepest-water find of 2019. Rystad estimates that Orca holds about 1.3 billion boe of recoverable resources. Recent gas discoveries in the region now support plans to build an additional LNG hub in the Bir Allah area in Mauritania, according to Rystad. Other key offshore discoveries in 2019 included Total’s Brulpadda in South Africa, ExxonMobil’s Glaucus in Cyprus, CNOOC’s Glengorm in the United Kingdom and Equinor’s Sputnik in the Norwegian sector of the Barents Sea.

INDUSTRY NEWS

Santos drill rig in the Cooper Basin. Image: Santos.

SANTOS EFFICIENCY GUIDES PRODUCTION RECORD Santos has delivered record annual production across its operations in 2019, as well as lower unit production costs that have been attributed to the company’s disciplined, cash generative operating model. The annual production of 75.5 million barrels of oil (mmboe), a new high for Santos, is a 28 per cent improvement on the previous year. Santos also confirmed record annual sales revenues of more than $4 billion (up 10 per cent), which was generated from sales volumes of 94.5 mmboe. The fourth quarter production of 18.7 mmboe was 5 per cent lower than the prior quarter (19.8 mmboe), primarily due to domestic gas customer outages in Western Australia. Santos increased production in the Cooper Basin for the second consecutive year, driven by strong operating performance and a record 115 wells drilled, compared with 85 wells in 2018. Thirty-four wells were spudded during the fourth quarter: 17 development wells, 13 appraisal wells and four near-field exploration wells. Santos’ production in the Cooper Basin increased to 4.1

mmboe in the fourth quarter compared with 4 mmboe in the previous year. The company logged higher GLNG sales on the back of enhanced upstream equity gas production, while a record 393 wells were drilled, 29 per cent higher than 2018, and 431 wells were connected (44 per cent higher). A target to deliver 6 million tonnes per annum (mtpa) equivalent run-rate at GLNG was achieved in October, with an annualised sales run-rate, including volumes redirected to the domestic market, exceeding 6 mtpa annualised. Santos is expecting an annualised sales run-rate of 6.2 mtpa at GLNG this year. Its gross GLNG-operated upstream sales gas production increased to 622 terajoules a day (TJ/ day) at the end of the quarter, supported by continued steady growth from Roma and Arcadia. The Adelaide-based company continued to steadily increase production at Roma in Queensland, resulting in gross daily production lifting to 137 TJ/day at the end of the quarter. Production from the Arcadia field grew to 15 TJ/d by the end of the quarter, supported by a growing contribution from the new Arcadia Valley wells, Santos reported.

ATTERIS EXPANDS WOODSIDE PARTNERSHIP Woodside has signed a major subsea and pipeline engineering services agreement with Atteris. The contract extends a longstanding partnership between the two companies that dates back to 2000. According to Atteris, the partnership has resulted in value being added to multiple greenfield and brownfield projects in terms of quality in engineering, innovation, health and safety, and environmental care. The contract will enable Woodside to continue to use Atteris’ subsea and pipeline engineering services across all project lifecycle phases. Atteris general manager Dermot O’Brien said the signing of

the contract demonstrated the trusting relationship between the two companies over the past 19 years. “It reaffirms Woodside’s confidence in our ability to provide leading-edge engineering solutions that are safe, reliable, environmentally sustainable and highly efficient,” O’Brien said. “We remain committed to continue adding value to the Woodside business.” Atteris’ services cover subsea and pipelines, flow assurance, dynamic systems, asset and integrity management, operations and production readiness support, life extension assessments and decommission studies.

OILANDGASTODAY.COM.AU / MARCH 2020 / 7

INDUSTRY NEWS

WEST ERREGULLA NAMED LEADING ONSHORE GAS DISCOVERIES Strike Energy has completed one of its most formative quarters to end 2019 with production testing and resource booking at the West Erregulla gas field, which has been named one of Australia’s largest, high quality, onshore conventional gas discoveries. With the discovery at the West Erregulla gas field, Strike reported that activities executed in the Perth Basin during the quarter centred around defining the subsurface and commencing development planning. Its activities also included delineating the additional near-term targets within the acreage owned by the company. During the December quarter, after the drilling and completion of West Erregulla-2, Strike conducted a multi-rate flow and pressure build-up test. Strike reported that gas flowed to surface from the Kingia sandstone from 48m of perforations across the target interval in the Kingia formation. At the largest choke setting, the well flowed at a rate of 69 million standard cubic feet per day (mmscf/d) with a wellhead pressure of 700 psig. This result is the second highest flow rate achieved by any Perth Basin well and shows the highly producible nature of the West Erregulla resource. Strike managing director and chief executive officer Stuart Nicholls said the discovery at West Erregulla had proven the existence of a deep, conventional gas fairway within the Permian sequence of the Perth Basin. “This discovery, together with the activity of neighbouring operators, validates Strike’s commercial and geological strategy, with Strike now holding the largest land and equity position within what is fast becoming one of Australia’s most prolific onshore conventional gas basins,” Nicholls said. “Having booked 593 BCF 2C Strike share and with a Wagina prospective resource of 137 BCF P50 Strike share, the previous quarter has set the foundations for 2020 to be a year of strong progress against our strategy to become a major Australian gas producer.” Joint venture processes concluded in the fourth quarter, with the partners approving the work program and budget items for drilling.

Strike is making rapid progress at West Erregulla.

Strike is targeting a final investment decision (FID) for the Phase 1 development at the end of the fourth quarter in 2020 and continues to advance this milestone as the company’s highest priority. During the quarter Strike concluded negotiations with Traditional Owners for the Native Title Agreement, which is in the process of being executed. Strike expects the permits will be granted by the Western Australian Government by end of the first quarter 2020.

CENTRAL PETROLEUM SETS UP NT FARM-OUT Central Petroleum has taken a key step towards securing partners for its 2020 exploration program at a range of Northern Territory oil and gas projects. The company has appointed Flagstaff Partners as an advisor for the farm-out of its exploration targets and associated operating assets, including the Mereenie oil and gas field, Palm Valley gas field, Dingo gas field and Surprise oil field. Central has already started the farm-out process, with critical items for its 2020 exploration program, such as well design and procurement of long lead items, being progressed to maintain drilling targets.

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The farm-out is targeted for completion by mid-2020, according to the Brisbane-based company. Central managing director and chief executive Leon Devaney said the company’s operating assets in the Northern Territory were now delivering gas to an east coast gas market critically short of term gas supply. “Our CY2020 exploration program is targeting a significant increase in gas reserves to leverage existing production facilities and to provide high marginal value,” Devaney said. “This provides us with an opportunities to capitalise on an attractive farm-out package that creates near-term value.”

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INDUSTRY NEWS

SENEX CONTINUES GROWTH WITH PRODUCTION INCREASE Senex Energy has achieved significant expansion and outstanding operational performance to finish 2019. Managing director and chief executive officer Ian Davies said the December quarter was outstanding for the company, as new gas molecules were delivered to the domestic market and gas production in the Surat Basin outperformed expectations. The company revealed that its quarterly production increased by 35 per cent to 447,000 barrels of oil equivalent (boe). In gas, the company’s production rose to 621,000 boe, a 72 per cent increase due to the Roma North (Surat Basin) rampup and initial production from Project Atlas (Surat Basin) and the Gemba field (Cooper Basin). Its oil production was up by 3 per cent to 186,000 boe, compared with 180,000 boe in the previous quarter and 178,000 boe in the same quarter of the 2019 financial year. Senex’s quarterly revenue increased from $23.9 million in the previous quarter to $29 million, marking a 23 per cent increase. The company reported that gas revenues increased significantly by 64 per cent to $10 million, with first gas sales achieved from Atlas and the Gemba field.

During the quarter, Senex signed new gas sales agreements with CleanCo, CSR and Otota, for varying volumes, tenors and supply terms, bringing the contracted total to more than 32 petajoules (PJ) of natural gas from Atlas. The Roma North production exceeded 13.5 terajoules a day (TJ/day) and Atlas produced above 6.5 TJ/day from 23 well during the early ramp-up phase. A total of 49 wells were drilled in Senex’s current campaign, with an impressive 33 wells in production and the remaining set on the verge of being online (at time of writing). Senex also achieved first gas sales from the Gemba field, Cooper Basin and has a free-carry drilling program completed. Material exploration targets were also identified from Westeros 3D survey. “Production performance clearly demonstrated the quality and potential of our Surat Basin acreage, and the execution capabilities of the Senex team,” Davies said. “We have significant running room ahead with 612 PJ of 2P gas reserves booked and more acreage to be appraised. “In the Cooper Basin, completing the free-carry drilling campaign and interpretation of the Westeros 3D survey have provided a large inventory of material exploration and appraisal leads to pursue.”

CHEVRON, WOODSIDE JOIN HYDROGEN COUNCIL The Hydrogen Council has introduced a wave of new members, growing its numbers to 81 companies and 22 new members, representing the full hydrogen supply chain and several regions of the world with expanding hydrogen markets. Oil and gas giants Chevron and Woodside Energy are two of the 12 new supporting members to join the council. The Hydrogen Council is a CEO-led global initiative of leading energy, transport and industry companies with a united vision and long-term ambition for hydrogen to foster the energy transition. The addition of the newest members is the culmination of a year of strong progress in 2019.

United States-based Chevron is one of the world’s leading integrated energy companies. The company, which explores for, produces and transports crude oil and natural gas, refines, markets and distributes transportation fuels and lubricants, has established a strong presence in Australia, including at the Gorgon and Wheatstone liquified natural gas (LNG) projects. Perth-based Woodside is a pioneer of the LNG industry in Australia and a leading natural gas producer in the country. Woodside is focussed on establishing collaborative partnerships to share and improve knowledge and facilitate problem solving across the hydrogen value chain. The push for hydrogen is gathering momentum.

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COVER FEATURE

Kevin Lester finds satisfaction in rise of gas As industry moves to a lower carbon future and the role of gas increases, Kevin Lester shares how APA Group plays a pivotal role in the energy infrastructure market. Molly Hancock writes.

APA Group executive infrastructure development officer Kevin Lester.

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evin Lester has watched on with pride as gas has grown from a secondary fuel in Australia to play a key role in the country’s energy mix. In fact, he has played an important part in this growth himself during 35 years in the gas sector, including the past eight years with energy infrastructure business, APA Group. Natural gas use in Australia has expanded to account for a quarter of the country’s energy consumption in recent years, a major shift from when Lester started his career. Gas’ role has risen on the back of increased production in Western Australia to support the expansion of LNG exports, according to the Australian Energy Update 2019. Queensland, more recently, has also contributed significantly to this growth with the introduction of LNG plants up the state’s coast. While Lester’s career has featured many memorable and rewarding moments, it is this rise of gas as a fuel in Australia and on the export market that stands out. “Overall, for me, it has been seeing the role and importance of gas in Australia grow at such an incredible rate from a secondary fuel, to now being an essential part of the Australian energy mix,” Lester told Oil & Gas Today. With the use of natural gas increasing, leading to growing demand for energy infrastructure, APA Group has a central responsibility connecting gas supply sources to markets. Since its inception in 2000, APA Group has emerged as a key player in the growth and expansion of the domestic gas industry and broader energy industry. As APA Group’s infrastructure development executive, Sydney-based

COVER FEATURE

Lester is instrumental in the success and development of the company’s portfolio. He is responsible for the project development, engineering, procurement and delivery of the company’s infrastructure expansion projects. Lester finds satisfaction when working with customers to achieve positive outcomes, add value and improve their bottom line. He thrives on all the aspects involved with a new project, which has been a sustaining factor of his extensive career. “I enjoy starting a project from scratch, while working with a team to take a project from concept, through the approvals stage, and then all the way through to engineering, procurement, construction, commissioning and handover,” Lester said. Building APA’s market status Lester describes APA Group as an ambitious growth-focussed business, which gives him opportunities to take on new projects. APA is a leading Australian energy infrastructure business, owning and/or operating around $21 billion of assets. It has built an asset portfolio that includes over 15,400km of pipelines spanning every state and territory on mainland Australia and delivering around half of the nation’s gas usage. APA also owns or has interests in gas distributon assets, gas fired and renewable power generation,

gas storage and processing facilities and electricity transmission. The company’s high-profile projects have included creation of the East Coast Grid, the Moomba and Wallumbilla compressor station projects, the Eastern Goldfields Pipeline and the Reedy Creek Pipeline. APA also acquired the QGC LNG pipeline (renamed Wallumbilla Gladstone Pipeline) during Lester’s tenure and has diversified further into the gas processing, and power generation sectors including renewables. “The last few years have been incredibly exciting for APA. Major recent projects include the Yamarna Gas Pipeline and Gruyere Power Station, the Badgingarra wind and solar farms, the Darling Downs solar farm, the Victorian Northern interconnect expansion and the upgrade to the Orbost gas plant,” Lester said. Proud of his work at APA Group, Lester is grateful for being able to help develop a highly experienced team that is capable of delivering all of its capital growth projects. He said APA Group worked to create a robust governance structure with a strong focus on delivering projects to customer requirements, on schedule and on budget. “In addition, we have enhanced the team that supports the operations of the assets from an asset engineering

The Victorian Transmission System comprises approximately 1992 km of pipelines.

perspective,” Lester said. APA has further developed its process safety capability and introduced reliability centred maintenance and risk-based inspections to ensure the company invests capital efficiently. Next ventures? Lester identifies the East Coast Grid as ground-breaking and a forward-thinking development amongst APA’s growth. The East Coast Grid has revolutionised gas supply on the east coast of Australia with the development of a 7600km interconnected transmission pipeline grid. It provides the ability to move gas from multiple gas production facilities to users across five states and territories and to the LNG export market. It comprises of approximately 40 receipt points and 100 delivery points. “(The East Coast Grid) allows us to offer seamless and flexible services to our customers. We can transport gas in all directions across four states with a single contract and we can store and move gas to suit customers requirements at any time,” Lester explains. APA’s work elsewhere includes the growth in capacity on the Goldfields Gas Pipeline (Western Australia) and Amadeus gas pipeline (Northern Territory), both crucial assets that are supporting local communities and mines across sparse locations with a reliable energy source. The Goldfields, Pilbara and Parmelia pipelines and the Mondarra Gas Storage and Processing Facility link key gasproducing areas with iron ore, nickel and gold mining provinces, as well as providing pipeline and storage services that deliver supply security to Perth and the South West region. In addition, APA owns and operates the Amadeus Gas Pipeline at the Central Region Pipelines. The infrastructure transports natural gas to Darwin, Alice Springs and regional centres, primarily to fuel power generation. The company also has interests in a number of complementary energy investments across Australia and manages and operates these assets on behalf of the investment partners. These assets include gas-fired power stations, gas processing plants, electricity

OILANDGASTODAY.COM.AU / MARCH 2020 / 13

COVER FEATURE

Moomba Compressor Station provides the capability to ship Eastern Haul Gas through South-West Queensland Pipeline.

interconnectors, and a number of gas transmission pipelines. Lester reinforced that the importance of the power reliability to remote communities should not be underestimated. “These pipelines have been instrumental in ensuring that local communities and mines across these geographically-remote locations can enjoy a reliable energy supply,” Lester said. Tech’s role in a green future As the industry starts a new decade, APA Group is optimistic about what the future has in store. A firm believer that gas is a critical element for Australia’s energy future, Lester emphasises the role it will play in transitioning to a lower carbon future. Drawing reference from the latest World Energy Outlook, Lester identifies gas as an essential product in the world’s energy mix due to its versatility and environmental advantages. “Boston Consulting Group’s Global Gas Report forecast that gas will be the number two energy source behind oil by 2040, achieved through a combination of increased supply, availability and growing liquidity in the LNG market,” Lester said. However, Lester believes it is important that federal and state governments play a significant role by “facilitating investment and making the approvals process more efficient and streamlined.”

With technology rapidly evolving, the oil and gas industry has proved it is keeping up with the times by incorporating the latest advances. “There is no doubt that the energy industry is very different now than it was 10 years ago – let alone 35 years ago when I first joined it,” Lester said. “We are an industry of engineers, meaning we are driven by both new ideas and pragmatism, as well as an overwhelming desire to build bigger and better things. “It is the perfect environment for fostering ground-breaking innovations in our infrastructure projects.” Technology isn’t limited to new projects; it has been a crucial aspect at a number of older assets in APA’s infrastructure portfolio. Through the use of the latest technology, the company has been able to check the integrity of its pipelines, especially through intelligent pigging. The technology is an ultrasonic system that allows a more accurate depiction of the pipeline and draws focus on the primary maintenance requirements. Lester said other technology advances at APA included remote monitoring of its facilities and Cathodic protection test points to acquire real-time data; and the creation of its integrated operation centre (IOC) in Brisbane, which controls its pipeline and facility assets. The company puts significant

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effort into research and gives ongoing and significant support to the APGA Research and Standard Committee and the Future Fuels CRC to develop research and opportunities. Maintaining growth APA has a growth strategy and will continue to develop new assets and hence more energy to the market, while maintaining a long-term investment philosophy. “It will require significant new investment in energy infrastructure and a portfolio solution to power generation, energy transportation and storage,” Lester said. Lester believes it will be important for APA Group to consider each opportunity for future fuels that can be transported in its pipelines. By grasping a better understanding about the safety aspects of biogases, hydrogen and renewable methane, he said APA Group’s “infrastructure needs to evolve to support these emergent fuel sources”. “On a more day-to-day basis we have processes in place that ensure we are always using our assets, and servicing our clients, in the most optimal way,” Lester concluded. “Our focus is on investment, innovation and increasing supply. Generating more gas supply, and ensuring reliability, will require collaboration between the industry, government, regulators and endusers.”

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FUTURE OF OIL & GAS

What will shape the future of oil and gas? Deloitte’s national oil and gas leader Bernadette Cullinane highlights the major trends that will impact the industry at the start of a new decade. Molly Hancock writes.

he oil and gas industry in Australia has emerged from a period of major structural, political and technological changes that have accompanied unprecedented expansion in the country. Entering the new decade, the industry is set to embrace these changes as energy demand, emerging markets, urbanisation and improving living standards gather momentum. Characterised by Deloitte partner and national oil and gas leader Bernadette Cullinane as a fascinating time for the oil and gas industry, she anticipates that a number of factors will influence company strategies as they face the future. Cullinane, who has worked across the oil and gas value chain in multiple countries, believes workforce management, technological change and sustainable energy will be pivotal elements of future operating models. As an advisor helping companies reduce cost, improve business performance, grow and be globally competitive, Cullinane highlights how companies can navigate these challenges.

The role of the workforce In an industry where talent is in demand and the rise of millennials is reshaping the workforce, it is important that companies have a clear message and identity what will enable them to be successful in competing for the best talent. Cullinane believes millennials, who are rapidly increasing in numbers in the workforce, are questioning the role of the oil and gas sector more critically than previous generations. “This generation is certainly having an influence on the future direction of the industry,” Cullinane told Oil & Gas Today. “There are already skill shortages in

Deloitte Australia national oil and gas leader Bernadette Cullinane.

“This bold risk-taking approach is a characteristic of the industry, solving problems through engineering and technology excellence to create positive outcomes for stakeholders.” Bernadette Cullinane Deloitte partner certain areas in the industry, and the future depends on getting the right mix of skills. Companies will increasingly compete to attract the next generation of top talent.” With the future of work being different to that in the past, Cullinane said companies need to create an “employee value proposition that is really clear and crisp and one that ties

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to compelling business models”. “Companies that are not aware of these big changes and are not rethinking their business models now run the risk of becoming left behind,” she said. As the industry shifts to more collaborative models with partnershipfocussed initiatives, companies are critically evaluating the skills

FUTURE OF OIL & GAS

and assets they need for the future and having the right talent in the organisation is key. Cullinane’s observations reflect the thoughts of Woodside chief executive officer and managing director Peter Coleman, who believes all jobs are going to change. Woodside will need employees who are ready to learn and willing to continue learning, according to Coleman. “This transformation has big implications for how companies hire. We need education and training systems that support this lifelong learning,” Coleman said during a November 2019 speech. “It’s a decision that is paying off as we head into a growth phase and see opportunities to harness these technologies to improve project execution, deliver savings on maintenance costs and design what we call intelligent plant.”

The benefits of embracing technology The oil and gas industry is no stranger to the innovation that technology can provide. Increasingly driven by digital technology, a number of evolutions within the oil and gas sector have been off the back of breakthrough initiatives. Cullinane said the oil and gas industry had the right DNA and mindset to take bold risks, positioning it well for a digital future. “What other industry explores, develops and operates big, complex projects in remote and risky places around the world?” Cullinane asked. “The oil and gas industry hasn’t just been doing it for the past decades, but for more than 150 years. “This bold risk-taking approach is a characteristic of the industry, solving problems through engineering and technology excellence to create positive outcomes for stakeholders. I believe

FAST FACT • Woodside is Australia’s premier LNG operator, producing 6 per cent of global LNG supply. • Woodside CEO Peter Coleman said the company’s strategy was underpinned by its ongoing strong base business, world-class asset performance and disciplined execution of committed projects. • Woodside has set a goal to become carbon neutral by 2025 by offsetting emissions from its Pluto development. • Australia has been named as the world number one exporter of LNG in 2019. • Australia’s natural gas production (LNG and domestic use) increased by 16 per cent in 2018 compared with 2017. Production has more than doubled over the last five years.

Bernadette Cullinane believes a fascinating period is emerging for the industry.

OILANDGASTODAY.COM.AU / MARCH 2020 / 17

FUTURE OF OIL & GAS

Western Australia, has led the adoption of technologies like data analytics, artificial intelligence and automation, recognising the benefits for increased efficiency and improved safety,” Coleman said. “It’s time for Australia to get serious about artificial intelligence.” Coleman urged the industry to collaborate with technology firms to establish operations and employ and develop local talent. Woodside has backed a number of local tech start-ups with the potential to transform the industry, from the way ocean conditions are surveyed to enhancing cybersecurity for operation systems. “We have a fantastic robotics laboratory and data science team, but it is really since we have taken the technology out of the lab that we are seeing tangible value creation,” Coleman explained. “That has been driven by integration of our technology and digital teams…we are working for a future where technology helps us solve real-world challenges.” Bernadette Cullinane shares her insight into the trends of the oil and gas industry.

FAST FACT • Modelling undertaken by Deloitte Access Economics estimated that over the current LNG projects’ investment phase, oil and gas investment and construction activity would create about 103,000 (full-time equivalent) jobs across the Australian economy. • Bernadette Cullinane has more than 26-years of experience across the oil and gas value chain and all stages of the capital project to operations lifecycle. She has worked with companies in the upstream, downstream, midstream, LNG and trading segments as well as in conventional and unconventional oil and gas. • Cullinane believes the next generation will be influential on the future of the oil and gas industry. • Companies in the industry are analysing the assets and skillsets needed to secure the right talent.

the oil and gas industry of the future will build on the success of the past.” Australia finished the last decade reflecting on an extraordinary construction phase in the liquefied natural gas (LNG) sector that culminated in it becoming the leading exporter of the commodity in the world. A major trend moving forward will be how the industry transitions towards sustainable energy synonymous with the digital and technology transformation, according to Cullinane. “These new technologies will help companies make a step change in operational excellence, productivity and will improve bottom-line results,” Cullinane said. Woodside represents a leading example of how technology is being prioritised at an oil and gas organisation to ensure a sustainable future. Coleman noted that technology had changed the way that Woodside’s employees worked and lived through a number of emerging initiatives. “The resources sector, particularly in

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Greener energy attracts investment Social expectations are pushing oil and gas companies and the industry towards a greener future. The Department of the Environment and Energy’s 2019 Australia’s emissions projections estimated that Australia would exceed its 2020 target by 238 million tonnes of carbon dioxide equivalent (Mt CO2-e), an improvement of 43 Mt on 2018. Australia has a target of reducing emissions to 5 per cent below 2000 levels by 2020, with this year expected to be 534 Mt CO2-e. The report also noted that electricity emissions from LNG facilities are set to decline slightly over the next five years as the Darwin LNG facility goes offline for maintenance. From 2025, emissions will increase again as production increases because of the return of the Darwin LNG facility, and the addition of another train at Pluto in Western Australia. Cullinane is confident that oil and gas companies will see the benefits of investing in greener energy. To achieve this, Cullinane believes companies will have to shift towards

FUTURE OF OIL & GAS

“The resources sector, particularly in Western Australia, has led the adoption of technologies like data analytics, artificial intelligence and automation, recognising the benefits for increased efficiency and improved safety. It’s time for Australia to get serious about artificial intelligence.” Peter Coleman Woodside CEO and MD a lower carbon energy mix while extracting value from new technologies. She said now is the time to “really leverage these ideas and not just talk about them”. “There are some companies that are ahead in terms of what they are doing and what investments they have in greener and cleaner energy,” Cullinane said.

Woodside is aspiring to become carbon neutral by 2025 by offsetting emissions from its Pluto development and has signed an agreement with Greening Australia. The company plans to offset equity reservoir CO2 across its entire portfolio from next year. However, Cullinane stated that on average across the industry only “1.3

per cent of capital expenditure in 2018 went into low carbon projects”. “Companies need to invest in greener energy to safeguard their assets and revenue base. Their social license is being increasingly scrutinised by investors and by customers,” Cullinane said. “With a big focus on ESG (environmental, social and governance), companies must ensure they are attractive to investors, customers and the talent they require for their organisations.” Coleman reinforced Woodside’s intention to work towards a lower carbon future and why it would be important for the sustainability of the company. “We are working for a future where Australia draws value from its rich and diverse resource endowment and charts an energy path that is sustainable in both an environmental and an economic sense,” Coleman said.

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info@beamex.com OILANDGASTODAY.COM.AU / MARCH 2020 / 19

MARKET OUTLOOK

Australia leads the LNG world EnergyQuest founder Graeme Bethune discusses how Australia has risen to become the world’s number one exporter of LNG.

ustralia is sitting on top of the LNG world after becoming the leading exporter of the commodity in 2019. This year and the decade ahead are shaping up to be even stronger with the planned ramp up of numerous Australian projects. News broke in January this year that Australia had overtaken Qatar to become the world’s top LNG exporter. Statistics revealed that Australia shipped 77.5 million tonnes at an export value of $49 billion in 2019, with the fuel becoming increasingly important in the global energy mix. The figures, released by energy consultancy EnergyQuest, confirmed Australia’s LNG shipments for the 2019 calendar year increased 11.4 per cent on the previous year, due largely to INPEX’s expansion of the Ichthys project in the Timor Sea. The feat follows a succession of massive LNG projects starting production in Australia over the past decade, including Pluto LNG (2012),

Queensland Curtis LNG (2014), Gladstone LNG (2015), Gorgon (2016), Wheatstone (2017), Ichthys (2018) and Prelude FLNG (2019). While Qatar’s 2019 production figures were yet to be released (at the time of writing), its output is expected to be 2.5 million tonnes lower at 75 million tonnes, according to EnergyQuest’s analysis. Western Australia was the nation’s dominant LNG exporter, accounting for 57 per cent of shipments, with the Woodside-managed North West Shelf project the largest single contributor. With a number of projects transitioning from construction into production in recent years, EnergyQuest chief executive officer Graeme Bethune believes the next significant movement will come from Woodside-led projects, Scarborough and Browse. Bethune, who founded EnergyQuest in 2005, has more than 40 years’ experience in economic and financial analysis, including 10 years in senior business development and finance roles with Santos.

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He has a passion for natural gas, LNG, oil and transport fuel, electricity and renewables and is the chair of the Australian Gas Industry Trust, and a member of the Executive Committee of the International Gas Union. “For Australia it means LNG is now our third biggest export, with a current revenue of 55 million tonnes a year. This is a huge export revenue,” Bethune told Oil & Gas Today. “Qatar produced around 76 million tonnes in 2019, and if Australia gets close to producing 80 million tonnes it will create a significant gap between the two. “Qatar has announced that they want to expand their capacity to 110 million tonnes, but that won’t be for a few years.” Bethune points out that Australia previously achieved the global LNG title in some individual months, but 2019 is the first time the country topped the globe on a sustained annual basis. “There is always uncertainty about the future, but Australia’s capacity is about 88 million tonnes, and we

MARKET OUTLOOK

Australia has been named the world’s top exporter of LNG. Image: Woodside.

2019, there remains opportunity going forward to lift the current production milestone even higher. “We will most likely see movement in Woodside’s Scarborough and Browse projects, the first being Scarborough moving towards filing an investment decision.” The Scarborough gas field is 270km north-west of Onslow in the Carnarvon Basin offshore Western Australia. Woodside (75 per cent) is operator

the Scarborough project that is within Commonwealth waters will be assessed by the Australian Government, under the Environment Protection and Biodiversity Conservation Act 1999, which includes the consideration of greenhouse gas emissions. The JV expects to make a final investment decision on the Scarborough gas field in 2020, with first gas forecast in 2023.

“For Australia it means LNG is now our third biggest export.” Graeme Bethune EnergyQuest CEO

produced 77.5 million tonnes in 2019,” Bethune said. “However, with only 88 per cent of total nameplate capacity used over

Pluto LNG Plant was one of seven LNG projects to go online in the past decade. Image: Woodside.

of Scarborough in a joint venture agreement with BHP (25 per cent). The field lies in the WA-1-R licence in water depths of 900m to 1500m. Woodside announced in January that the Western Australian Environmental Protection Authority (EPA) had recommended approval for the state component of an LNG pipeline that forms part of the Woodside-led Scarborough project. The proposal would see the installation of a gas trunkline 32.7km long adjacent to the existing Pluto LNG facility 8km north east of Dampier in the Pilbara. The remaining portion of

Bethune said Browse would also make “good progress on getting all the joint ventures aligned and signed off.” The Browse JV between operator Woodside (36 per cent), Shell Australia (27 per cent), BO Developments Australia (17.33 per cent), Japan Australia LNG (14 per cent) and PetroChina International Investment (10.67 per cent), is proposing to develop the Brecknock, Calliance and Torosa fields 425km north of Broome offshore Western Australia. The JV has estimated contingent resources are 13.9 trillion cubic feet (Tcf) of dry gas, and 390 million barrels of condensate. The project would include two floating production storage and offloading facilities and a 900km gas pipeline to existing infrastructure on the North West Shelf. EnergyQuest statistics reveal that Western Australia alone is now the world’s second largest LNG producer, with Queensland ranking a significant sixth. The consultancy’s data further underpins the emergence of the Northern Territory as Australia’s third LNG force, producing 14 per cent of the country’s 2019 LNG export. “There are critical benefits of the substantial export revenue, plus there are also a large number of people employed to produce LNG in both Queensland, Western Australia and the Northern Territory,” Bethune concluded.

OILANDGASTODAY.COM.AU / MARCH 2020 / 21

PROFILE APPEA

Ensuring Australia benefits from oil and gas Andrew McConville is dedicated to maintaining APPEA’s voice in the oil and gas industry, while ensuring Australia understands the value of natural gas in the future. Molly Hancock writes.

ndrew McConville may have only been the Australian Petroleum Production & Exploration Association (APPEA) chief executive officer for 11 months, but his drive and passion for the oil and gas industry is clear. After 11 years in Switzerland as global head of external affairs and communications for Syngenta, one of the world’s largest agricultural technology companies, McConville was keen to move back to home soil. However, only a job with the right structures and strategies in place would coax McConville from the lush scenes of Switzerland back to Australia. When he was approached by APPEA to take on the role as CEO, McConville said it “ticked all the right boxes” and by April last year he had started his new position. From the start McConville was determined to continue APPEA’s leadership and guidance of the oil and gas industry’s major contribution to the Australian economy through exports, job opportunities and taxation revenue. There was also a big push from McConville to introduce a new strategic direction for the organisation. “I really wanted to craft a new narrative and sharpen the focus of the organisation on to members and the value we add for them,” McConville told Oil & Gas Today. “Every organisation has to be clear on what it wants to achieve, so it needs an articulate vision and strategy. I think the importance of getting that in place early has been very significant.” While his tenure as CEO is yet to reach a year, McConville believes he has learnt a lot, especially the importance of explaining the role natural gas plays in the future and the benefits the industry brings to local communities.

Andrew McConville, chief executive of APPEA.

Australia’s current resources of natural gas, both offshore and onshore, are enough for more than 50 years, based on current production. Natural gas is the nation’s third largest energy resource, after coal and uranium, and is a crucial part of Australia’s energy mix, providing a quarter of the nation’s needs. McConville believes the opportunities for Australia’s natural gas fall into three classes. The first is the way Australia conducts operations and how effective and environmentally responsible the industry in the country can become. “Using technology to ensure we are minimising emissions. Whether that be a commitment to reducing routine flaring, minimising fugitive emissions,

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or supporting the development of larger technology such as carbon capture and storage to reduce the impact we have in developing our oil and gas resources,” McConville said. Secondly, it is about understanding the role natural gas can play in implementing renewables. McConville is a firm believer that natural gas has strong potential as an efficient and effective source of energy with lower emissions than coal and which complements the development of renewables. “As we want to increase our renewable energy, I think it is really important to know the role natural gas can play as a transition fuel. Natural gas has evidence to show it has half the emissions of coal as an efficient energy

PROFILE APPEA

source,” McConville said. Finally, the flow-on effect of Australia maintaining the status as the world’s largest exporter of LNG and the impact it has internationally. “$50 billion worth of exports is a very important contribution to the Australian economy, and we need to see that continue both in terms of jobs, foreign exchange and strengthening of the Australian economy,” McConville said. “We need to make sure we are maintaining our competitiveness overseas for LNG while also ensuring we have adequate supplies of natural gas here for domestic manufacturing.” With Australian gas exported to China, India and other parts of Asia, McConville said it was effectively replacing higher emissions energy sources, helping to reduce importing country emissions from energy generation by up to 50 per cent. “The government’s own research suggests exports of natural gas could reduce up to around 150 million metric tonnes of greenhouse gas emissions from China which is the equivalent of one quarter of Australia’s annual emissions,” McConville said.

McConville said it was pivotal that the industry focussed on making sure there was access to Australia’s resources and developed them in a way that responsibly generates revenues. To achieve this in the next decade, science-based regulations that are predictable and transparent with minimal government inferences will be needed, he added. “One of the things we see is that it costs a lot of money and takes a lot of time to develop natural gas resources. Over the last decade we have seen around $350 billion worth of investment into the industry and now that exploration has dropped off,” McConville said. “We want to ensure we have an investment policy that encourages innovation investment, including good environmental regulations.” McConville said it was essential that government understood its position on a range of issues that led to adequate investment policy being introduced. This includes viewing APPEA and the industry as part of the solution, not just part of a problem. “It’s about understanding the

objectives of government and coming forward with how we can help meet those objectives,” McConville said. APPEA is also introducing new initiatives to ensure the industry has a future talent pool, addressing a recent skills shortage. Its Bright Sparks initiative has been designed to celebrate young people in the industry, showcasing what they do in their careers. APPEA is working to collaborate with universities and other institutions around the nation so the association can talk to the students of tomorrow about career opportunities. “If we don’t start thinking about this now, then by the time the gap is there, it will be too late. We need to get ahead of it and be out there talking about the benefits the industry can bring and the opportunities that exist with world-class jobs, in a world-class industry right here in Australia, often in regional areas,” McConville concluded. “We see ourselves as very privileged to represent the industry and we are absolutely focussed on being the voice of industry.”

APPEA believes natural gas has a strong potential as an efficient and effective source of energy.

OILANDGASTODAY.COM.AU / MARCH 2020 / 23

PPO: an essential part of the pipeline sector Barry Wood has been pivotal in the way PPO has become a valuable tool in the industry today.

hat first started as an idea in 1969 to the online database it is today, Pipeline, Plant and Offshore (PPO) continues to play a key role in the oil and gas industry. Founded by Australian pipeline industry great, Barry Wood, PPO stemmed from those he worked alongside and their desire to know what and where the next major project was. After some encouragement from American senior pipeline inspector Bennie Beattie, while they both worked on the Westernport – Altona – Geelong (WAG) oil pipeline, the PPO legacy was born. The first edition of the newsletter went to print in September 1972, all from the comforts of Wood’s home. However, the first PPO was not a All hands on deck at the Brooklyn to Altona pipeline project. Barry Wood (standing) works on the project.

Barry Wood (far left) working on the Brooklyn to Altona Pipelines project.

solo effort, it took Wood, his wife and six children on the loungeroom floor with an electric typewriter, staplers and envelopes to produce. “The first edition didn’t get much response, but I kept persevering and found out there was quite a big interest from the business side of the industry, and then that side of the subscriptions started to grow and we put the price up a bit,” Wood told Oil & Gas Today. With PPO not gaining much traction at first, Wood continued to work full time in the pipeline industry, often away during the week before rushing home on weekends to put the newsletter together. Soon PPO became a vital piece of information for those who worked in the industry, providing companies with where the next project was and businesses the opportunity to supply the right products for construction. After Wood’s wife Esther went back to work as a school teacher, he was given the opportunity to start growing its readership. “Esther working enabled me to work on it full time. First working out of the house, then a small office and then a bigger one in Balwyn before moving into the city,” Wood said. “Back in those days it was purely a newsletter and as long as the

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information was there, people weren’t fussed about the quality of printing.” More than five decades after Wood saw a gap in the market, PPO is now a leading online project database which contains all proposed, under construction and completed projects. The news service informs its loyal subscribers daily with an e-newsletter and the website is updated online in real-time so subscribers can search the latest developments with accuracy any time. PPO is now included as a standalone section in every edition of the bi-monthly Oil & Gas Today – Powered by PPO magazine. With its original focus on pipelines, PPO still carries the same traits. Reflecting on how the pipeline sector has changed over the years, Wood said technology had played a part in today’s progress. “Technically there have been a many advancements,” he said. “Lots of innovations that have contributed to the change include technology, which you don’t see physically but improves efficiency and quality. It also Improves construction, timing and quality of products.” Not only has technology changed the way the industry operates, but Wood recalls the time when only

Barry Wood receives the Outstanding Contribution to the Australian Pipeline Industry award from Warren Entsch and Bruch Andrews in 1998.

construction people would be on site at a pipeline project. “I was talking to an old-timer recently who I asked what the greatest differences are that he noticed,” Wood explained. “He said when he started, and we would go out to a camp project there would be about say 60 construction workers. Now there are about the same number of construction workers, plus an equal number of safety and environment people, it has changed a lot in that regard. “It has changed in terms of safety and environmental regulations as well.” Reminiscing about some of his favourite pipeline projects he has been involved with, Wood said the most impressive was the WAG pipeline. WAG is an interconnect oil pipeline transporting Gippsland crude oil between the Esso/BHP crude oil storage facility at Westernport to refineries at Altona and Geelong. Completed in 1972, the development of the pipeline involved challenges during both the planning and construction phases. The pipeline was constructed and

commissioned by WAG Pipeline, in which Shell (52.3 per cent), Mobil (31 per cent) and Esso Standard Oil (16.7 per cent) all had interests in. Starting in Hastings on Western Port, the WAG Pipeline runs through the Melbourne suburbs of Moorabbin and Brighton, closely following Port Phillip Bay through Elwood, St Kilda and South Melbourne before

continuing on to the Altona Refinery and Geelong. The pipeline passes through 764 non-company-owned land parcels, of which 387 are road reserve, 55 are public reserve, 14 are rail reserve, 51 are Crown land and 253 are private land. Throughout his lengthy career in the Australian pipeline industry, Wood has made a lasting impact on the industry, most notably through his work with PPO. “It was a great time in the industry, and I worked alongside great people,” Wood concluded. “The pipeline industry still has a lot more to give and people will always want to know about the next project.”

Australian pipeline greats gather, including Barry Wood seated on the left.

OILANDGASTODAY.COM.AU / MARCH 2020 / 25

VICTORIA CRIB POINT TO PAKENHAM PIPELINE

ONSHORE | GAS PIPELINE | IN PLANNING | PROPONENT: AGL ENERGY AGL Energy Level 22 101 Miller Street North Sydney NSW 2060 P: 02 9921 2999 PIPE STATS Length: 55-60km Diameter: 600mm

OWNERSHIP APA Group 100%

SCOPE Proposed by AGL Energy, the Crib Point to Pakenham Pipeline is intended to relieve gas supply pressures on the Victorian market by connecting interstate and international LNG ships to the local market via the floating storage and regassification unit (FSRU) at the existing Crib Point jetty. The high-pressure buried pipeline will transport gas from 12 to 40 LNG ships each year and will connect to the existing network via a link in Pakenham. The project consists of a bidirectional pipeline, as well as some plant and equipment setup, including metering and odourisation. PREVIOUS HISTORY November 2019: Still battling approvals. AGL’s import terminal and subsequent pipeline are now anticipated to be operational in 2022. AGL purchased 50 PJ of gas from Esso to keep its supplies strong until it can import LNG using the proposed facilities, scheduled to be connected to the project’s compression station starting October 2019. July 2019: According to media reports, approvals for AGL’s import terminal and the APA Group Crib Point to Pakenham may not be received until mid-2020 and may require design changes and extra costs. June 2019: AGL Energy has pushed out the expected date for first gas from its Crib Point LNG import terminal by another 12 months, further pushing out APA’s pipeline. AGL said it now expected first gas to be delivered in the second half of the 2022 financial year, an extension from its original goal of the 2021 financial year. May 2019: The Liberal, Labor, Greens and Independent candidates in the federal election for the seat of Flinders said they were opposed to AGL’s LNG import terminal and the subsequent Crib Point to Packenham pipeline. The project will require both state and federal approvals to go ahead. April 2019: Federal Health Minister Greg Hunt, representative of the Flinders electorate where the development is located, has once again stated his opposition to AGL’s import terminal and pipeline project, saying he was clearly, unequivocally and absolutely” opposed to it. The completed environmental assessment is due in September this year. March 2019: According to media reports, AGL chief executive Bett Redman said the environmental assessment of the import terminal and subsequent pipeline had forced the timing of the final investment decision to be pushed back into 2020. December 2018: The Commonwealth Department of Environment and Energy said the project would require assessment and approval under the Environment Protection and Biodiversity Conservation Act 1999. AGL and pipeline operator APA will now be required to provide an environmental impact statement detailing the likely effects the project will have on surrounding ecosystem and how these will be dealt with. The final scoping requirements will be made public in 2019. November 2018: According to The Australian, AGL’s Victorian LNG import plant at Crib Point could be delayed after the Victorian Government decided to conduct a full environmental assessment of the project. The import facility and its associated pipeline will undergo an environmental effects statement, which could see AGL struggle to meet its target of starting imports in the first half of 2020. October 2018: On September 10, 2018, APA Group made an application for a pipeline licence under the Pipelines Act 2005 and requested for state and Commonwealth Governments to make a determination on whether formal assessment for the project would be required under the Environment Protection and Biodiversity Conservation Act 1999 and the Environment Effects Act 1978. The project is pushing ahead with AGL Energy now targeting first imports at its planned Crib Point LNG import terminal for the first half of 2020, bringing forward its previous goal of a 2020-21 start date. According to The Australian, AGL has submitted documents to the Victorian Government to progress its $250 million import project, with the company expecting gas shortfalls to hit from 2021.

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VICTORIA SOLE GAS PROJECT ONSHORE AND OFFSHORE | PIPELINE |UNDER CONSTRUCTION | PROPONENT: COOPER ENERGY SCOPE Previous operator Santos proposed the development of the Sole gas field, located off the coast of Victoria. A 40km subsea pipeline will connect the field to the existing Patricia Baleen gas plant on the Victorian coast, 10km from Orbost. Operations at the Patricia-Baleen gas processing plant involve separation, compression and dehydration of raw gas. Sales gas is then transported to the Eastern Gas Pipeline. Current capacity is approximately 43 TJ/d, however the plant has been sized to process 75 TJ/d in anticipation of gas from other suppliers in the region. Santos sold the Sole project to Cooper Energy in 2016.

Cooper Energy Level 10 60 Waymouth Street Adelaide SA 5000 Tel: 08 8100 4900 PIPE STATS Capacity: 68 TJ/day

UPDATE January 2020: APA Group, which is completing the upgrade to Cooper Energy’s Sole gas project in the Gippsland region, has advised that non-essential personnel were evacuated from the area and those remaining are safe from the bushfires that have engulfed the region. The upgrade to the Orbost gas processing plant in the Gippsland has also been affected by bushfires in the area. First gas from Sole to the plant was expected to take place in February (at time of writing).

OWNERSHIP Cooper Energy 100% PIPELINE CONTRACTORS Diamond Offshore: Drilling contractor Subsea 7: Subsea pipeline and installation

PREVIOUS HISTORY October 2019: First gas from the Sole gas project is now expected in December this year, approximately five months later than originally planned, with upgrades still ongoing at the Orbost gas plant. The western section of the plant is currently undergoing commissioning and the electrical system is connected to the Sole control umbilical; however, the remaining commissioning activities are not expected to commence until November. June 2019: Repairs to a damaged section of the Sole’s 65km subsea pipeline have been completed. The project’s onshore facility is still on track for the 2019 September quarter. March 2019: Cooper Energy says the Sole gas project is 93 per cent complete and within budget. In a report released by the company, Cooper said the offshore project was due for completion at the end of May 2019, while the onshore Orbost gas plant would likely be finished sometime in the September quarter. January 2019: Cooper Energy announced the Sole project was 86 per cent complete and on budget. The company expects the project will be completed within six months. December 2018: A wall thickness opening has been identified in the pipeline connecting the Sole production wells to the Orbost gas plant. Cooper Energy reported that after the 65km pipeline was laid on the seabed, a through wall thickness opening at one location on the pipeline was discovered whilst conducting the acceptance pressure test with water. This opening has prevented the pipeline, which is not connected to the gas fields or carrying hydrocarbons, from holding internal pressure. Plans to repair the damage to the pipeline are currently in development, with the hydrotest set to resume once this operation has been carried out. November 2018: Cooper Energy’s quarterly report, released on October 15, 2018, shows the company’s Sole gas project is nearing completion. As of September 30, the $355 million offshore development, located in the Gippsland Basin, was 74 per cent complete, and on schedule and within budget constraints. Production at Sole is expected to commence in approximately nine months. October 2018: In a presentation at the Good Oil Conference on September 13, 2018, managing director of Cooper Energy David Maxwell reported that the Sole gas project was 70 per cent complete and still progressing within schedule and budget. The umbilical crossing and gas pipeline crossing are now complete, while the Sole-4 clean up and flow back has also been finished. First gas sales are expected in July 2019. August 2018: Cooper Energy’s first two production wells for its Sole gas project (Sole-3) have experienced successful testing of clean up and flow-back operations. The Sole-3 testing was undertaken over a 26-hour period on the 97m completed section of the Top LaTrobe Group sandstone reservoir.

SUBSCRIBE TO PPO PROJECTS FOR REAL-TIME UPDATES: WWW.PPO.COM.AU / MARCH 2020 / 27

QUEENSLAND PROJECT ATLAS

ONSHORE | CSG | IN OPERATION | PROPONENT: SENEX ENERGY Senex Energy: Level 14 144 Edward Street Brisbane QLD 4000 Tel: 07 3335 9000

SCOPE Project Atlas involves the delivery of natural gas from coal seams on acreage located near Wandoan and Miles in Queensland’s Surat Basin. The 56km2 acreage is estimated to contain P50 recoverable gas volumes of 201 PJ, with expected investment of more than $200 million to drill around 100 wells and construct associated infrastructure. First gas was achieved in November 2019. UPDATE January 2020: Senex revealed that its quarterly production at the company increased by 35 per cent. In gas, its output rose to 621,000 boe, a 72 per cent increase, with initial production from Project Atlas driving the higher output.

OWNERSHIP Senex Energy 100% PIPELINE CONTRACTORS Pipeline: Jemena Compressions Station Construction: Valmec

PREVIOUS HISTORY December 2019: Valmec has achieved mechanical completion on Jemena’s Atlas Gas Compressor Facility project. Commissioning by the Jemena team is under way with first gas achieved on November 29. October 2019: Natural gas has begun flowing at Project Atlas. Senex has drilled 11 wells since the project’s drilling campaign began in August this year, with the first four wells to be brought online now producing gas. October 2019: Jemena has reached mechanical completion of the Atlas Gas pipeline less than three months since construction began. Construction of the Project Atlas gas processing facility is still ongoing and commissioning of both is to begin soon. September 2019: Senex has now drilled and completed for production from the first five wells of its latest Project Atlas drilling campaign, which will consist of approximately 60 wells in total. Drilling reports say the wells have seen net coal intersections of up to 43m and all wells are scheduled to be connected to the project’s compression station from October 2019. August 2019: Senex has spudded its first well at Project Atlas as part of the 110-well Surat Basin drilling campaign. July 2019: Jemena has commenced construction of the Atlas Gas Pipeline in Queensland. Jemena executive general manager of gas markets Antoon Boey said the pipeline should be commissioned before the end of the year. The pipeline will be eight inches (203mm) in diameter, buried at a depth of 1200 to 2000mm and will have the capacity to transport 40 TJ of gas per day. March 2019: Senex has begun civil works for a well drilling campaign across Project Atlas and the Roma North development. Senex plans to drill approximately 110 wells in the Surat Basin projects, with the campaign expected to commence in the fourth quarter of FY19. The company has awarded the contract for initial well pads and access roads to local Queensland company T&W Earthmoving, while contracts for drilling rig and well site services will be awarded in the near future. February 2019: The Queensland Government granted the Atlas Gas pipeline project a Petroleum Facility Licence for a natural gas processing facility. Jemena can now progress to the next stage of planning for the facility’s construction. January 2019: Jemena has awarded Valmec a facility construction works contract for the Atlas Gas Pipeline Project. Valued at approximately $22 million, the contracted works are expected to commence immediately with a completion date aimed for later in 2019. November 2018: Senex Energy reached a final investment decision to develop Project Atlas in the Surat Basin during October. About 60 wells will be drilled for the initial project development, with Senex expecting to deliver more than 200PJ of gas for the domestic market throughout the life of Project Atlas. The processing plant and 60km pipeline associated with the project will be built, owned and operated by Jemena. Project proponents are still targeting first gas delivery in late 2019, with development still subject to regulatory approvals from state and federal government bodies.

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QUEENSLAND GLENARAS GAS PROJECT

ONSHORE | CSG | UNDER CONSTRUCTION | PROPONENT: GALILEE ENERGY Galilee Energy Level 26 71 Eagle Street Brisbane QLD 4000 Tel: 07 3177 9970

OWNERSHIP Galilee Energy 100%

SCOPE Galilee Energy’s Glenaras gas project is located in the ATP 2019 (formerly ATP 529) tenement in the western section of the Galilee Basin. The project is designed to evaluate the quantity and quality of CSG in the Betts Creek and Aramac Coal Beds. In 2015, Galilee resumed full ownership of the project. The company is aiming to convert the project’s resources to reserves before supplying gas to Australia’s east coast market. In October 2017, Galilee announced the signing of a binding memorandum of understanding with Jemena to work together to deliver the Glenaras gas project to the domestic market. The agreement fast-tracks Jemena’s plans to build a new pipeline delivering gas produced by Galilee Energy to the east coast. PREVIOUS HISTORY December 2019: Galilee Energy has installed and commissioned a newer, larger and higher capacity pump for the Glenaras 15L well after the original pump causes issues. All five lateral wells are now back online and are expected to be kept on production for an extended period of time. November 2019: Galilee said metered rates have been reported at 25-30 Mscfd in aggregate and the rates have continued to increase as fluid levels in the wells are reduced further and more coal is drawn down below the critical desorption pressure. Pump capacity at Glenaras 15L has been increased due to the well’s high productivity and with these modifications the five wells are flowing at 6700 bwpd in aggregate, significantly below peak rates of 7500 bwpd, which Galilee said indicates material depletion of the coal within the pilot area. October 2019: Galilee said the Glenaras 15L well’s deliverability has been beyond the initial design criteria, but production and downhole pump issues have risen as the company attempts to maximise the well’s drawdown. Galilee has secured a workover rig and expects a larger downhole pump system to be installed within the next two weeks, meanwhile the other four wells in the Glenaras pilot are continuing to produce at maximum performance. Gas rates had been measured at up to 35–40 Mscfd in aggregate prior to the Glenaras 15L issues. Galilee managing director Peter Lansom said the pilot was continuing to demonstrate strong productivity. October 2019: Galilee said metered gas rates have been reported at 25–30 Mscfd in aggregate and the rates have continued to increase as fluid levels in the wells are reduced further and more coal area is drawn down below the critical desorption pressure. Pump capacity at Glenaras 15L has been increased due to the well’s high productivity and with these modifications the five wells are flowing at approximately 6700 bwpd in aggregate, significantly below peak rates of 7500 bwpd. August 2019: Galilee has brought all five lateral wells online at Glenaras. The company reported that over the past two weeks the surface facilities and flowlines at its multi-lateral pilot program had been fully installed, with each of the five lateral Glenaras wells having undergone initial flow production tests. All wells have now been brought online for continuous production, and Galilee reported strong productivity had been observed in each of the wells, putting the program’s intended objective of accelerating the depressurisation process and achieving commercial gas flow rates on track. July 2019: Jemena has unveiled proposed route of the Galilee Gas Pipeline (GGP). The pipeline transport gas to the Glenaras gas project, near Longreach in the Galilee Basin, to the operator’s Queensland Gas Pipeline near Injune. July 2019: Jemena has lodged an environmental impact statement application for the Galilee Gas Pipeline. Additionally, the company has formally lodged an Environment Protection and Biodiversity Conservation Act referral for the pipeline, which would transport gas from Galilee Energy’s Glenaras gas project in Central Queensland to the east coast domestic market. Front end engineering and design work on both the pipeline and gas field are targeted to begin later this year, with an objective of first gas to market in 2020.

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QUEENSLAND ROMA EAST PROJECT

ONSHORE | CSG | UNDER CONSTRUCTION | PROPONENT: SANTOS Santos 60 Flinders Lane Adelaide SA 5000 Tel: 08 8116 5000

OWNERSHIP Santos 100%

SCOPE The Roma East project will involve bringing online 480 wells, including the drilling around 430 new wells, connecting existing appraisal wells, and drilling pre-developed wells in the Roma region. The project will also include around 420km of water, gas gathering and other pipelines, 120 TJ per day of additional compression, 670km of power lines and around 25km of fibreoptic cables. A water-handling facility for irrigation and more than 200 hectares of additional irrigation in the Roma area will improve livestock carrying capacity. The project is expected to add nearly 50 PJ a year to gas production in Queensland in 2020 â&#x20AC;&#x201C; equivalent to about 8 per cent of expected east coast domestic gas demand in 2018. UPDATE January 2020: Drilling continues at the Roma East project with 327 wells drilled and 302 wells online to date, Santos reported in its December 2019 quarter update. Continued steady production from Roma resulted in gross daily production increasing to 137 TJ/day at the end of the December quarter. PREVIOUS HSITORY November 2019: Santos reported in its September quarter update it had drilled 274 wells and brought 223 wells online at the Roma East Project. October 2019: Santos is continuing drilling operations towards its 480 wells targeted wells at Roma East. In its 2019 half year results, the company reported the project had maintained an average cost of $0.83 million/well. August 2019: Operations are continuing with 222 wells drilled and 181 well online. Santos said production from the project is building in line with expectation as dewatering continues. May 2019: Drilling continues at the project with 158 wells drilled. There are now 109 wells online and Santos achieved first gas sales from the development during the first quarter of 2019. March 2019: 86 wells are now online at the project, with a forecast of 380 wells online by the end of the year. February 2019: Drilling continues at Roma East with 121 wells drilled with 80 wells now on flare. At the end of December 2018, gross daily production had increased to 82 TJ/day. November 2018: Drilling on the Roma East project continues, with 95 well drilled, 15 wells on flare and early dewatering commenced as at October 18, 2018. October 2018: Santos has awarded the Roma East Backbone project to MPC Group. This includes 34km of DN500 gas pipelines, 34km of DN400 water pipeline and 35km of 66kV overhead powerline. MPC Groupâ&#x20AC;&#x2122;s team has mobilised to a site near Roma and commenced mainline operations. August 2018: Drilling continues in the Roma East project with 51 wells drilled to date. May 2018: The Roma East project has commenced, and two drilling rigs have drilled 15 wells to date. April 2018: Santos and its GLNG partners will invest $900 million in upstream developments in the Maranoa, Western Downs, Central Highlands and Banana regions in 2020. As well as upstream developments around the Fairview, Scotia and Arcadia fields, this investment includes the first year of funding for the new $750 million Roma East project which will be developed over the next three years.

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QUEENSLAND SURAT GAS PROJECT

ONSHORE | UNCONVENTIONAL | IN PLANNING | PROPONENT: ARROW ENERGY Arrow Energy Level 39 111 Eagle Street Brisbane QLD 400 Tel: 07 3012 4000

OWNERSHIP Arrow Energy 100%

SCOPE Arrow Energy, a joint venture between Shell and PetroChina, is undertaking the Surat gas project with the aim of commercialising gas resources located in an area 160km west of Brisbane in Queensland’s Surat Basin. The project received its environmental approval from the Australian Government on December 20, 2013, and by the Queensland Government on October 25, 2013. In December 2017, the company signed a seven-year gas supply deal with the Queensland Curtis LNG development to commercialise the majority of the company’s gas reserves in the basin, which would reduce the amount of new infrastructure needed for the project. PREVIOUS HISTORY August 2019: While aiming to begin development of the project in late 2019, Arrow has expressed that this is not a forgone conclusion as political decisions are made regarding east coast gas shortages, According to The Australian Financial Review, Shell said the project needed consistent attention to keep it on track and the company is concerned about a 25 per cent increase in gas production royalties recently announced in Queensland. June 2019: Arrow Energy has awarded a joint venture a contract for construction on two of its major projects. Under the contract, a JV comprising China Petroleum Engineering and Construction and Nacap (CNJV) will deliver off plot construction management services for Arrow for construction works in the Surat and Bowen basins in Queensland. CNJV will include construction of the surface well pad infrastructure, as well as Arrow’s gathering networks. March 2019: The Queensland Government has approved the $10 billion project. Arrow Energy has been granted a total of 14 petroleum leases between Dalby and Wandoan for the southwest Queensland project, covering approximately 2500km². The project is estimated to bring in 5000 PJ of gas to market over 27 years. March 2016: An Arrow Energy spokesperson told PPO that development options for Arrow’s Surat Basin gas reserves are being progressed. April 2015: An Arrow Energy spokesperson told PPO that the company is continuing to reframe options for its operations in the Surat Basin. March 2015: An Arrow Energy spokesperson told PPO News that the company is continuing to reframe options for its operations in the Surat Basin. February 2015: Development options for Arrow’s Surat Basin gas reserves are being progressed, and collaboration discussions with third parties are continuing, to identify the best option for monetising Arrow’s gas reserves.

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QUEENSLAND WESTERN SURAT GAS PROJECT

ONSHORE | CSG | UNDER CONSTRUCTION | PROPONENT: SENEX ENERGY Senex Energy Level 14 144 Edward Street Brisbane QLD 4000 Tel: 07 3335 9000

SCOPE The Western Surat gas project will focus on the development of the Glenora and Eos blocks, and appraisal of the Mimas and Tethys blocks (collectively, Roma North) in its initial stages. The primary objective is to reach minimum initial production of 16 TJ/day, with potential for expansion to 24 TJ/day. Up to 425 wells and associated infrastructure are expected to be constructed for the project. UPDATE January 2020: Senex Energy is delivering its Surat Basin natural gas development program in Queensland on schedule and on budget, with production outperformance at Roma North and Atlas. The company reported that Roma North production had exceeded 13.5 TJ/day and was tracking towards the plant’s initial capacity of 16 TJ/day.

OWNERSHIP Senex Energy 100%

PREVIOUS HISTORY December 2019: Gas production at Roma North is now more than 11 TJ/d and gas processing facility has been commissioned. October 2019: Daily gas production at Roma North has continued to increase in line with existing forecasts following the completion in September of the first 10 wells in Senex’s approximately 50-well Roma North drilling campaign. As of October, the natural gas production has increased to 11 TJ/d, which is up approximately 40 per cent since the end of the June quarter. Senex expects to deliver an annual Surat Basin gas production rate of 18 PJ by the end of 2021 financial year. September 2019: Senex has drilled and completed the first 10 wells of its Roma North drilling campaign, for which around 50 wells are targeted. Four of these wells have been tied to the Roma North compression station and the first train is currently operating at maximum capacity and above 8 TJ/d. July 2019: Senex reported it had improved well performance at Roma North and with commissioning activities currently taking place at the development’s compressor station an upswing in production has resulted in the company achieving rates of 8.4 TJ/day. Senex has now drilled nine wells of its Surat Basin drilling campaign, which will eventually result in approximately 110 wells drilled across Roma North and the nearby Project Atlas. Ten wells will be drilled at Roma North prior to the mobilisation of the Easternwell Rig 27 to Atlas at the end of July. March 2019: Senex has begun civil works for a well drilling campaign across Project Atlas and the Roma North development. Senex plans to drill approximately 110 wells in the Surat Basin projects, with the campaign expected to commence in the fourth quarter of 2019 financial year. The company has awarded the contract for initial well pads and access roads to local Queensland company T&W Earthmoving, while contracts for drilling rig and well site services will be awarded in the near future. February 2019: Civil works and pipeline construction have been completed at the Roma North development. In addition to the completion of civil works, four gas compressors – each weighing up to 40 tonnes – were recently delivered and lifted into position. More than 520 steel piles have been put into the foundations to support the compressors and associated infrastructure. December 2018: Civil works have commenced in the Roma North section of the Senex project after the company awarded a major construction contract to Wasco (Australia) following a competitive tender. Under the terms of the contract, Wasco, which has been active in the Roma area since Senex first engaged the business for natural gas construction works in 2016, will construct a gas processing facility and an associated pipeline.

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QUEENSLAND MAHALO PROJECT

ONSHORE | CSG | UNDER CONSTRUCTION | PROPONENT: COMET RIDGE Comet Ridge GPO Box 798 Brisbane QLD 4001 Tel: 07 3221 3661

OWNERSHIP Comet Ridge 40% Santos 30% APLNG 30%

SCOPE The Mahalo project is located in the ATP 337P permit in the Denison Trough. This area is prospective for coal seam gas in Permian aged coals that are draped over a large northsouth trending structural high known as the Comet Ridge. These coals have proven to be productive at the Origin Energy Spring Gully coal seam gas development project 150km to the south on the same structural high. The Mahalo project has a range of potential volumes of gas in place ranging from a minimum of 181 Bcf up to a maximum of 990 Bcf. The most likely volume is estimated to be in excess of 400 Bcf. PREVIOUS HISTORY December 2019: Comet Ridge, Mahaloâ&#x20AC;&#x2122;s major equity holder, is considering using the project as a route to market for potential gas from nearby authority to prospect recently allocated to the company. The company said gas from this location could be brought to Mahalo for processing. October 2019: The joint venture has lodged two petroleum lease applications (PLS) to the Queensland Governmentâ&#x20AC;&#x2122;s Department of Natural Resources, Mines and Energy. The PLAs cover the initial development area for the Mahalo gas project and are the first step in the process to convert a shorter-term exploration tenure into a longer petroleum lease. The joint venture is aiming for a 30-year lease term, which will carry a requirement to commence production within two years. The development will include a series of wells, a modular gas plant likely to be sized with an 80 TJ/d capacity and a pipeline connection of 65km in length. September 2019: The joint venture plans to submit key state and federal government applications within the next month and is targeting a final investment decision date of June 2020. August 2019: The Mahalo JV has been working this year to agree on the most economically efficient development for the project, with well design locations, plant location, export pipeline and the government application preparation work all agreed upon for the CSG project, while contractor studies on a processing facility for the 65km pipeline is also nearing completion. The pipeline would have a capacity of up to 120 TJ/d and would connect to two available export pipelines located to the south of the project. March 2019: Production tests are running to plan at the project, with two wells starting to produce gas at low rates. Comet Ridge reported the Memooloo 2, Struan 3/2 and Sirius Road 2/1 wells in the Mahalo Block had been brought online at very low pump speeds, resulting in rates of approximately 10 to 12 barrels of water per day. With pump speeds being progressively increased, all three wells were still running smoothly with water rates now between 20 and 26 barrels of water per day. The company said both Struan 3/2 and Sirius Road 2/1 were starting to produce gas.

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PETROLEUM INFRASTRUCTURE OF AUSTRALIA

WA.2

Shell Prelude FLNG Project Shell Development Australia 3.6 MMt/a LNG; 0.4 MMt/a LPG; 1.3 MMt/a condensate, 2017

Bayu-Undan Field

BONAPARTE BASIN NT8

Blacktip Gas Field NT6

Ichthys Gas Field

BROWSE BASIN

Browse Development

Broome

WA.1 Woodside Energy, 25 MMt/a, TBA Gorgon Project

WA.4 Chevron Australia, 15.6 MMt/a, 2016

WA.7 Pluto Gas Project

Woodside Petroleum, 4.3 MMt/a, 2012

W11 W13

W12 W9

Wheatstone Project

WA.3 Chevron Australia, 8.9 MMt/a, 2017

W24

NWS LNG Plant

W7 W10

W21

BASIN WA.6 CANNING North West Shelf Australia L

Port Hedland

Dampier W16

W14

16.3 MMt/a, 1989

Telfer W8

W17 W23

W19

Scarborough Gas Field LNG

W20

WA.5 Development

Woodside Energy, 10 MMt/a, TBA

WESTERN AUSTRALIA

CARNARVON BASIN W25 W18

Mount Magnet W22

Windimurra

Geraldton

Kalgoorlie

PERTH BASIN

Kambalda W15 W1 W5

PERTH W2

Bunbury

Esperance

0 100 200 300 400 500

LEGEND Compressor Pump Station LNG Project

Proposed

P.1

Project Name Proponent, Total planned capacity, Commissioning Year

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Greater Sunrise Gas Fields Development

Ichthys LNG Project

NT.1 INPEX, 8.4 MMt/a LNG; 1.6 MMt/a LPG;

NT.3 Woodside Petroleum,

100,000 bbl/d condensate, 2017

NT5

4 MMt/a, TBA

Darwin LNG Project NT.2 ConocoPhillips, 3.24 MMt/a, 2003

DARWIN

Bonaparte FLNG GDF SUEZ, 2 MMt/a, 2018

NT.4

NT7

BEETALOO BASIN

Abbot Point LNG

NT2

Q.1 Energy World Corporation, 2 MMt/a, TBA

Karumba NT1

NORTHERN TERRITORY Tennant Creek

Santos, 7.8 MMt/a, 2016

NT10

Townsville

QUEENSLAND

Tanami Mt Isa

NT11

LNG

Q.2 GLNG Project

Q11

Century Mine

Q.3 QCLNG Project

QGC, 8 MMt/a, 2015

Mackay

Q10

Cannington

GEORGINA BASIN

BOWEN BASIN

Q29

Moranbah NT3

Alice Springs

Mereenie Palm Valley

AMADEUS BASIN

Barcaldine

ADAVALE BASIN

NT4

Q28

NT9

Gladstone Q3

Gilmore Gas Field

Q22

COOPER-EROMANGA BASIN Moomba

Q15

S1 Q17

Bundaberg

Roma Q19 Q18

Q20

Jackson

Q13

Q6 Q14

COOPER BASIN

Moonie Q27

SOUTH AUSTRALIA

BRISBANE Toowoomba

Q.4 Origin Energy, Sinopec and

NEW SOUTH WALES

Port Bonython

Tamworth N8

Whyalla

Parkes

Port Pirie Angaston S4

N11

VICTORIA

Mount Gambier S8

Tumut CANBERRA

Carisbrook

Wollongong

ACT

Wagga Wagga

Horsham

Wodonga

Wollert Mortlake Portland

V12

MELBOURNE

Geelong V14

V16 V8

Longford

SYDNEY BASIN

Orbost

V15

V17

V13

V10

Casino Gas Field

SYDNEY

Griffith N3

Newcastle Orange

Forbes Mildura

N10

Dubbo

ADELAIDE

ConocoPhillips, 9 MMt/a, 2016

GUNNEDAH BASIN

APLNG Project

SURAT BASIN

N4 N5

Q24

Q21

Wallumbilla

Cheepie

Q23

Q26

Tarbat

Ballera Q16

Q25

Q12

Bass Strait Fields

V11

GIPPSLAND BASIN

OTWAY BASIN

BASS BASIN T2

TASMANIA

HOBART

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NAME

OWNER

PRODUCT

LENGTH (km)

NT1

Amadeus Gas Pipeline

APA Group

Gas

1,658 km

NT2

Daly Waters - McArthur River Mine Gas Pipeline

Power and Water Corporation

Gas

330 km

NT3

Mereenie - Alice Springs Oil Pipeline (decommissioned)

Santos

Oil

270 km

NT4

Palm Valley - Alice Springs Pipeline

Australian Gas Networks

Gas

140 km

NT5

Bayu-Undan - Darwin Gas Pipeline

ConocoPhillips

Gas

502 km

NT6

Blacktip Gas Field Development

Eni Australia B.V.

Gas and Condensate 110 km

NT7

Bonaparte Gas Pipeline

Energy Infrastructure Investments

Gas

286 km

NT8

Ichthys Gas Export Pipeline

INPEX

Gas

890 km

NT9

Dingo Gas Field Pipeline

Central Petroleum

Gas

50 km

NT10 Northern Gas Pipeline

Jemena

Gas

622 km

NT11 Tanami Gas Pipeline

Australian Gas Infrastructure Group Gas

440 km

Eastern Gas Pipeline

Jemena

Gas

797 km

Interconnect Pipeline Culcairn - Wodonga

APA Group

Gas

57 km

Interconnect Pipeline Wagga Wagga - Culcairn

APA Group

Gas

88 km

Moomba - Sydney Pipeline

APA Group

Gas

2,081 km

Moomba - Sydney Ethane Pipeline

Ethane Pipeline Income Fund

Ethane

1,375 km

Central West Pipeline

APA Group

Gas

255 km

Sydney - Newcastle Liquids Pipeline

Caltex

Liquids

211 km

Central Ranges Gas Pipeline

APA Group

Gas

294 km

Queensland Hunter Gas Pipeline (P)

QHGP Pty Ltd

Gas

831km

N10

Liddell Gas Pipeline (P)

AGL Energy

Gas

76km

N11

Western Slopes Pipeline (P)

APA Group

Gas

450km

North Queensland Gas Pipeline

Palisade

Gas

391 km

Queensland Gas Pipeline

Jemena

Gas

629 km

Wide Bay Pipeline

Australian Gas Networks

Gas

274 km

Cheepie - Barcaldine Gas Pipeline

Ergon Energy

Gas

404 km

South West Queensland Pipeline

APA Group

Gas

937 km

Roma - Brisbane Pipeline

APA Group

Gas

438 km

Jackson - Moonie Pipeline (no longer in service)

Santos

Oil

797 km

Moonie - Brisbane Pipeline (no longer in service)

Santos

Oil

307 km

Carpentaria Gas Pipeline

APA Group

Gas

840 km

Q10

Cannington Lateral

APA Group

Gas

96 km

Q11

Century - Karumba Slurry Pipeline

MMG Century

Zinc and lead slurry

304 km

Q12

Comet Ridge - Wallumbilla Pipeline

Santos

Gas

127 km

Q13

Braemar 1 Pipeline

Alinta Energy Group

Gas

115 km Â

Q14

Braemar 2 Pipeline

ERM Power and Arrow Energy

Gas

110 km

Q15

Spring Gully - Wallumbilla Gas Pipeline

Jemena

Gas

87 km

Q16

QSN Link

APA Group

Gas

182 km

Q17

Jackson - Moomba Pipeline

Santos

Oil

273 km

Q18

Berwyndale to Wallumbilla Pipeline

APA Group

Gas

112 km

Q19

Darling Downs Pipeline

Jemena

Gas

292 km

Q20

Silver Springs to Wallumbilla Pipeline

AGL

Gas

101 km

Q21

Peat Lateral

APA Group

Gas

121 km

Q22

Tarbat - Jackson Pipeline

Santos

Oil

130 km

Q23

Australia Pacific LNG (APLNG) Pipeline

Origin Energy

Gas

530 km

Q24

Wallumbilla to Gladstone Pipeline (WGP) (formerly QCLNG) Pipeline APA Group

Gas

540 km

Q25

GLNG Pipeline

Santos

Gas

435 km

Q26

Atlas Gas Pipeline

Jemena

Gas

60 km

Q27

Kenya to Goondiwindi Pipeline (P)

ERM Power

Gas

204km

Q28

Bowen Gas Pipeline (P)

Arrow Energy

Gas

200km

Q29

Arrow Bpwen Pipeline (P)

Arrow Energy

Gas

430km

Ballera - Moomba Pipeline

Santos

Raw Gas/Liquids

180 km

Moomba - Port Bonython Pipeline

Santos

Oil/Condensate

659 km

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PIPELINE KEY NAME

OWNER

PRODUCT

LENGTH (km)

Moomba - Adelaide Pipeline System

QIC Global Infrastructure

Gas

1,184 km

Angaston - Mildura Pipeline

Australian Gas Networks

Gas

379 km

SESA Pipeline

APA Group

Gas

45 km

SEA Gas Pipeline

APA Group (50%)/SEA Gas (50%)

Gas

680 km

Whyalla Slurry Pipeline

OneSteel

Slurry

62 km

South East Pipeline System

QIC Global Infrastructure

Gas

82 km

Tasmania Gas Pipeline

Palisade Investment Partners

Gas

734 km

Tasmanian Savage River Magnetite Slurry Line

Grange Resources Limited

Slurry

83 km

Victorian Transmission System

APA Group

Gas

1,993 km

Carisbrook - Horsham Pipeline

Gas Pipelines Victoria

Gas

183 km

South West Pipeline

APA Group

Gas

144 km

WAG Pipeline

Viva Energy Australia

Liquids

136 km

Long Island - Altona Ethane Pipeline

Esso/BHP Billiton

Ethane

78 km

Longford - Dandenong Pipeline

APA Group

Gas

174 km

Longford - Long Island LPG Pipeline

Esso/BHP Billiton

LPG

188.3 km

Longford - Long Island Point Oil Pipeline

Esso/BHP Billiton

Oil

185 km

BassGas Pipeline

Origin Energy

Gas

215 km

V10

Casino Gas Pipeline

Santos

Gas

32 km

V11

Otway Gas Pipeline

Origin Energy

Gas

33 km

V12

Mortlake Gas Pipeline

SEA Gas (Mortlake)

Gas

83 km

V13

South Gippsland Natural Gas Pipeline

Duet Group

Gas

65.5 km

V14

Brooklyn to Corio Pipeline

APA Group

Gas

50.7 km

V15

Kipper Tuna Turrum Project

Esso Australia/BHP Billiton

Gas

34.8 km

V16

Longford Gas Conditioning Plant to Long Island Point Plant Replacement Pipeline

Esso/BHP Billiton

Oil

188.3 km

V17

Sole Gas Project

Cooper Energy

Gas

65 km

Dampier - Bunbury Natural Gas Pipeline (DBNGP)

DBP

Gas

1,489 km

Parmelia Gas Pipeline

APA Group

Gas

416 km

Midwest Pipeline

APA Group/Horizon Power

Gas

364 km

Goldfields Gas Pipeline

APA Group

Gas

1,378 km

Kambalda - Esperance Gas Pipeline

Esperance Pipeline Company

Gas

342 km

Pilbara Pipeline System

APA Group

Gas

219 km

Port Hedland - Telfer Pipeline

Energy Infrastructure Investments

Gas

442 km

Nifty Pipeline

Energy Infrastructure Investments

Gas

45 km

North West Shelf Trunkline 1

North West Shelf Joint Venture

Gas and Condensate 134 km

W10

North West Shelf Trunkline 2

North West Shelf Joint Venture

Gas and Condensate 135 km

W11

Angel Export Pipeline (to North Rankin A)

North West Shelf Joint Venture

Gas and Condensate 49 km

W12

Wanaea/Cossack export line

CWLH Joint Venture

Oil

W13

Pluto Trunkline

Woodside Petroleum

Gas and Condensate 180 km

W14

33 km

Wodgina Lateral

APA Group

Gas

85 km

W15

Neerabup Pipeline

ERM Power and Energy Infrastructure Trust

Gas

30 km

W16

Reindeer Raw Gas Pipeline

Apache Energy

Gas

102 km

W17

Griffin/Tubridgi Pipeline (no longer in service)

Australian Gas Infrastructure Group Gas

88 km

W18

Jaguar Lateral

Jabiru

Gas

33 km

W19

Fortescue River Gas Pipeline

DBP Development Group and TEC Pilbara

Gas

207 km

W20

West Angelas Pipeline

Rio Tinto

Gas

85 km

W21

Cape Preston Slurry Pipeline

CITIC Pacific

Slurry

25 km

W22

Eastern Goldfields Gas Pipeline

APA Group

Gas

293 km

W23

Macedon Gas Pipeline

BHP Billiton

Gas

67 km

W24

Wheatstone to Ashburton West Pipeline

Australian Gas Infrastructure Group Gas

109 km

W25

Yamarna Gas Pipeline

APA Group

198 km

Gas

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QUEENSLAND KINCORA GAS PROJECT

ONSHORE | CSG | UNDER CONSTRUCTION | PROPONENT: ARMOUR ENERGY Armour Energy Level 27 111 Eagle Street Brisbane QLD 4000 Tel: 07 3303 0620

OWNERSHIP Armour Energy 100%

SCOPE Armour Energy completed the acquisition of petroleum resources, tenures, production and transportation infrastructure assets on the Roma Shelf in the Bowen-Surat Basin, Queensland from Origin Energy in September 2016. The project consists of gas, LPG condensate processing and gas compression facilities at Kincora, a gas storage facility with a capacity of 7.5 PJ, over 3000km² acreage containing 15 production licences, four authorities to prospect and four petroleum pipeline licences. These assets are all located near the Wallumbilla gas hub on Australia’s east coast. UPDATE January 2020: Armour Energy has commenced the workover and completed operations at the PL227 Horseshoe 4 prospect. Part of the company’s Kincora project on the Roma Shelf, Horseshoe 4 was drilled to a total depth of 2169m in November 2019, and logging operation identified gas potential in both Triassic and Permian Sands. Following the completion of the workover and installation of 2-3/8-inch production tubing, the Horseshoe 4 was perforated in both Triassic and Permian sands and flow tested. PREVIOUS HISTORY December 2019: Armour Energy has successfully completed drilling of the Horseshoe 4 well and stated results from logging and testing had so far been “very encouraging”. The company expects gas from the well to hit the market before the end of 2019. November 2019: Armour Energy has carried out open hole wireline logging and modular formation dynamic testing (MDT) at Myall Creek North 1 which the company said indicated very encouraging results across thick Tinowon sand packages. Armour said the findings also indicated the Tinowon packages included gassy sands with potentially sufficient pressure and permeability for conventional production. Once work on MCN1 is completed, the Silver City Drilling Rig 20 will move to the Horseshoe 4 well pad to drill the well. October 2019: The Kincora gas plant was brought back online three weeks after it suffered an outage on its C1010 compressor. While offline, Armour took the opportunity to compete additional maintenance activities that were scheduled for later in the year. The project is now back to producing 9TJ/d gas. September 2019: Armour Energy reported the Kincora gas plant had suffered an outage on its C101 compressor – an integral part of the LPG gas circuit and a required component to produce sales quality gas for export to the market. With the LPG gas circuit now offline, the production from a number of wells across the Kincora gas project has been reduced until such time as the part can be repaired and brought back into service. Armour estimates it will take approximately two weeks to have the circuit back online. June 2019: Armour has connected the Myall Creek 5A well to the gas pipeline network; however, the initial gas flow rate 56,633m3/d from the well could not be sustained due to an unanticipated production of formation water resulting in the well currently being shut in. Meanwhile, a successful workover operation on the Myall Creek 4A well has been completed and the well has resumed production at a rate of 14,158m3/d. March 2019: Due to an additional well being drilled at Myall Creek, as well as geological and engineering studies undertaken across the project, Armour Energy has updated the 2P reserves estimate of Kincora to 123.6 PJ. February 2019: As a result of increased production at Kincora, Armour Energy is now selling 1 TJ/day of gas into the Queensland spot market. Armour is targeting production figure of 20 TJ/ day of gas from the project. December 2018: Armour Energy spudded its Myall Creek 5A well in the PL511 licence area after the well was drilled through the production zone to 2244.5m depth. Logging of the open hole production zone was also completed. is ‘saturated’ with hydrocarbons.

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SOUTH AUSTRALIA LEIGH CREEK ENERGY PROJECT

ONSHORE | GAS | UNDER CONSTRUCTION | PROPONENT: LEIGH CREEK ENERGY Leigh Creek Energy PO Box 12 Rundle Mall Adelaide SA 5000 Tel: 08 8132 9100

OWNERSHIP Leigh Creek Energy 100%

SCOPE The Leigh Creek Energy (LCK) project is located at Leigh Creek in central South Australia, 550km north of Adelaide, and plans to develop commercial quantities of gas in late 2018 for sale into the existing pipeline network. The project sits within the existing Leigh Creek coal mine area and will develop deep coal resources that are unable to be accessed by open-cut mining. Energy will be produced from coal using a process known as in-situ gasification (ISG). The ISG process converts coal from its solid state into purely gaseous form, resulting in the production of methane or natural gas, along with other valuable gases such as hydrogen. The gas production from the project will be transported via new pipeline which will access the east coast gas network. Some gas produced will be used to create electricity on site for use within the project and for the town of Leigh Creek. Construction of the pipeline connecting the project to the east coast gas market is expected to commence in 2017-18. PREVIOUS HISTORY December 2019: In its September quarter update CK managing director Phil Stavely said the company was pleased with the progress of the Leigh Creek Energy project (LCEP) and said analysis for the commercialisation of pipeline quality gas and the fertiliser business case can be pursued concurrently. October 2019: Leigh Creek Energy said a concept select study undertaken by Thyssenkrupp Industrial Solutions, combined with further subsurface gasifier enhancements at LCEP, has calculated an indicative cost of less than $1/GJ for syngas delivered into a proposed fertiliser plant at Leigh Creek site. The company said its cheap gas would disrupt the market, believing it can provide syngas feedstock at less than $40/t of urea, while competitors are currently charging $320 if gas is at $8/GJ. September 2019: LCK reports a concept select study undertaken by Thyssenkrupp Industrial Solutions, combined with further subsurface gasifier enhancements at the LCEP has calculated an indicative cost of less than $1/GJ for syngas delivered into a proposed fertiliser plant at the Leigh Creek site. The company believes it can provide syngas feedstock at less than $40/t of urea, while competitors are currently charging $320 if gas is at $8/GJ. LCK managing director Phil Staveley said entering the fertiliser market was an attractive proposition. August 2019: LCK has completed a placement of 14.32 million ordinary shares in order to raise approximately $3.2 million, which the company says will contribute to the commercial development of its gas project. LCK managing director Phil Staveley said the company had been working closely with the SA Regulatory Authorities Department of Energy and Mining (DEM) on an agreed pathway to commercial approvals. June 2019: Leigh Creek Energy managing director Phil Staveley said the company is making “rapid progress” with its potential partners to form commercial arrangements regarding the gas project. Staveley said the commercial discussions ranged from gas sales agreements to offers of investment or project finance. February 2019: LCK reported it had achieved a peak flow rate of 8913m3/h at the Leigh Creek Energy Project (LCEP) pre-commercial demonstration plant, and now had sufficient information to upgrade a portion of the company’s resource upgraded to ‘reserve’ status. January 2019: Flow rates at the LCEP are consistently in excess of 1000m3 per hour, 20 times what was seen two weeks prior. The syngas composition has been consistently recorded up to 20 per cent methane and between 5 per cent and 10 per cent hydrogen, aligning with previous gas flow at lower rates.

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WESTERN AUSTRALIA EQUUS GAS PROJECT

OFFSHORE | GAS | IN DESIGN | PROPONENT: WESTERN GAS Western Gas 4/189 Stirling Highway Nedlands WA 6009 Tel: 08 6468 0667

OWNERSHIP Western Gas 100%

SCOPE Privately-owned Australian company Western Gas acquired 100 per cent of the Equus gas project on the North West Shelf offshore Western Australia in 2017. Western Gas acquired four permits and retention eases from Hess Corporation, comprising of 11 gas and condensate field with an independently certified resource of more than 2 Tcf of gas and 42 MMbbl of condensate. The permits and lease comprise WA-390-P, WA-474-P, WA-518-P, WA-519-P and WA-70-R offshore in the Carnarvon Basin, about 200km northwest of Onslow. The Equus gas project is development ready with exploration and appraisal already completed, and engineering activities at an advanced stage. With a resource of more than 2 Tcf, Equus has enough gas to supply a quarter of Western Australia’s domestic gas demand for more than 20 years. The project is strategically located in the North West Shelf, surrounded by world-class infrastructure, production facilities and pipelines, providing access to Western Australia’s large-scale gas market. PREVIOUS HISTORY October 2019: An upstream LNG development plan has been completed at the Equus project. Engineering and design operations will now focus on development proposals for the subsea, floating production and storage offtake, pipeline and floating LNG work packages. Western Gas is confident of achieving first gas from the project in 2024. September 2019: The engineering and design process for the development plan for Equus has been completed by McDermott International and Baker Hughes, a GE company (BHGE). It comprises three production wells tied back to a floating production storage and offtake (FPSO), as well as a 160km dry gas export pipeline to a nearshore 2Mtpa floating LNG (FLNG) facility and an onshore pipeline connection. Western Gas said engineering and design operations would now focus on development proposals for the subsea, FPSO, pipeline and FLNG work packages, with a goal of first gas in 2024. April 2019: Speaking at the Australian Oil and Gas Exhibition and Conference in March, Western Gas executive director Will Barker flagged the company’s intention to use gas from Equus for both the WA domestic market and also as a new export opportunity. February 2019: Western Gas is proposing to build its own LNG plant to develop gas from the Equus project. Previous plans for development have included processing the gas at existing WA LNG plants owned by Chevron or Woodside. However, Western Gas executive director Andrew Leibovitch said the proposed facility was drawing interest from potential partners. December 2018: Western Gas has signed a memorandum of understating with McDermott International and Baker Hughes, a GE company, for the provision of project development services from pre-front end engineering and design (FEED) and feed studies through to engineering, procurement, construction, installation and commission (EPCIC) phases of the project. Pre-FEED work will commence immediately and is estimated for completion by the second quarter of 2019, after which McDermott and Baker Hughes will continue with FEED work. June 2018: The Equus gas project has moved to the next phase of development, with operator Western Gas seeking a partner for the project. Basis for design of the development has been completed, with Western Gas issuing a request for proposals to secure a world-class development partner. Project development services being sought for full field development include drilling, subsea, offshore processing and a gas pipeline to shore. Front end engineering and design (FEED) will commence once customer arrangements are secured, with a final investment decision expected in late 2019.

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WESTERN AUSTRALIA GREATER ENFIELD PROJECT

OFFSHORE | OIL | IN OPERATION | PROPONENT: WOODSIDE SCOPE The Greater Enfield project involved the development of oil fields located within the offshore Carnarvon Basin, approximately 60km north-west of Exmouth, Western Australia. The fields are within production licence WA-59-L and production licence WA-28-L. The project involved the development of six subsea production wells and six water injection wells, which are tied back to the Ngujima-Yin floating production storage and offloading (FPSO) vessel. The vessel is within the neighbouring Vincent Field in WA-28-L, via a 31km-long subsea pipeline. First production was achieved in late 2019.

Woodside Energy 11 Mount Street Perth WA 6000 Tel: 08 9348 4000

UPDATE January 2020: Outlined in Woodside’s December quarter results, Greater Enfield guided an increase in the company’s production from 24.9 million barrels of oil equivalent (MMboe) in the September 2019 quarter to 25.7 MMboe in the December 2019 quarter.

OWNERSHIP Woodside Energy 60% Mitsui E&P Australia 40%

PREVIOUS HISTORY December 2019: The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) has issued a notice to Woodside over a still-in-place Riser Turret Mooring (RTM) located in the Enfield oil field. NOPSEMA said the condition of the RTM had not been maintained and was a considerable threat to the surrounding environment. Woodside said it was exploring options to safely remove it. November 2019: All 12 development wells at the project are completed and the project is producing oils as expected. October 2019: Woodside has reported that first oil has been produced at Greater Enfield project. The oil was produced through the Ngujima-Yin floating production vessel, which is located over the Vincent field. September 2019: First oil production from the project is imminent with the development progressing on time and on schedule. August 2019: Commissioning operations are continuing at the project with the floating, production, storage and offloading vessel having been at the field for more than a month. July 2019: At a shareholder meeting, Woodside managing director and CEO Peter Coleman said the project was 91 per cent complete with 10 of the 12 development wells drilled. Offshore commissioning operations have commenced, and the company expects production to begin in the near future. June 2019: At Woodside’s general meeting, CEO and managing director Peter Coleman said the Greater Enfield project was expected to come online late in the year. May 2019: Woodside reported the project was on schedule and 89 per cent complete. Subsea infrastructure installation is nearly finished and nine of the project’s 12 development wells are complete. Commissioning of some key FPSO equipment is targeted for second quarter 2019. March 2019: Construction of the project is nearing completion with Woodside now targeting first oil in mid-2019. November 2018: This project remains on budget and, as at October 18, 2018, was 72 per cent complete. Five development wells in the Laverda field have been completed and offshore drilling continues as planned. Planned subsea infrastructure installation continues, with all subsea flowlines installed during the July quarter. October 2018: In its half yearly results, Woodside reported that the Greater Enfield project was on target to reach start-up in mid-2019. During September, AAL completed a ‘one-ship-solution’ to deliver Thermotite ‘ULTRA’ subsea pipes and other subsea equipment to the project. September 2018: Offshore drilling continue, and the 10 top holes have now been drilled and cased, and one water injector completed. August 2018: The project remains on budget and is now 63 per cent complete. Since the last update, subsea pipeline and vessel demobilisation has been completed. Offshore drilling continues, and the Ngujima-Yin FPSO successfully suspended operations as it transited to the Keppel shipyard in Singapore.

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WESTERN AUSTRALIA SHELL PRELUDE FLNG PROJECT

OFFSHORE | LNG | IN OPERATION | PROPONENT: SHELL AUSTRALIA Shell Australia PO Box 872K Melbourne VIC 3000 Tel: 03 9666 5444 FLNG STATS Capacity: 3.6 MMt/a of LNG; 0.4 MM t/a of LPG; 1.3 MM t/a of gas condensate

OWNERSHIP Shell 67.5% INPEX 17.5% KOGAS 10% CPC 5%

SCOPE Shell is developing the Prelude, Concerto and Crux gas fields, located in permits WA44L and AC/L9 in Western Australia’s offshore Browse Basin, using floating LNG (FLNG) technology. The Prelude FLNG facility is located in the Browse Basin, approximately 475km north-northeast of Broome and more than 200km from the nearest point on the coast of the Kimberley region in Western Australia. The hull of the facility was floated in late 2012, and is intended to remain over the Prelude field for 25 years, with the project designed to annually produce at least 3.6MMt of LNG, 0.4 MMt of LPG and 1.3 MMt of gas condensate during that time. The FLNG facility is 488m long and 74m wide, and when fully loaded weighs approximately 600,000 tonnes. Approximately 260,000 tonnes of that weight consists of steel. The facility includes six LNG storage tanks with a total capacity of 222,000m3. Upstream facilities include seven wells, four flowlines approximately 3km in length, umbilicals and flexible risers. The facility will be moored for the duration of operations by four groups of mooring chains in 250m deep water. Each mooring chain will be held to the sea floor by suction piles. The project also has a number of onshore support facilities, with drilling, aviation and marine support based in Broome, along with head office out of Perth, and maintenance support in Darwin. UPDATE February 2020: Shell suspended production at the Prelude floating LNG vessel offshore Western Australia after its reserve power generation failed. The Prelude FLNG facility experienced an electrical trip on February 1, forcing production to stop, Shell confirmed in a statement. Shell has reported that due to technical issues there was a delay in starting up the back-up diesel generators, which impacted certain amenities on board. PREVIOUS HSITORY October 2019: Since exporting its first such cargo in June, Prelude has reportedly been shipping about one LNG tanker each week. September 2019: Prelude is reportedly exporting gas with temperatures that exceed the limit for its customers in Asia. According to media reports, the heating value of gas has been as high as 1170 btu/scf (43.59 mj/m3), a temperature too high for China’s gas market, while Japan’s maximum level for gas is 1160 btu/scf (43.22 mj/m3). Additional ethane in the LNG is reportedly causing the increase in heat and, while injecting nitrogen into the mix can lower the temperature, this would result in additional costs. It is not currently known how Shell has been addressing the issue. August 2019: According to project stakeholder INPEX, Prelude has now shipped its first cargo of LPG. The project has a capacity of 0.4Mt/a of LPG. July 2019: Shell has shipped its first cargo of LNG from the Prelude FLNG facility, with the Valencia Knutsen vessel departing with its first shipment for delivery to Asia. June 2019: Prelude is yet to ship a cargo of LNG six months after production began but Shell vice president for Prelude Rob Jager told The West Australian the company was not driven by schedule, but rather focussed on ensuring a safe start up. April 2019: Prelude FLNG has shipped its first cargo of condensate, marking the first export from the project. March 2019: While some wells have been opened and initial phase of production has begun, Shell Australia chair Zoe Yujnovich said the company was not “rushing” the commissioning process and production would be in full swing when it was safe to do so.

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WESTERN AUSTRALIA WEST ERREGULLA (EP 469)

OFFSHORE | UNDER CONSTRUCTION | PROPONENT: STRIKE ENERGY Strike Energy 1/31-35 George Street Thebarton SA 5031 Tel: 08 7099 7464

OWNERSHIP Strike Energy 50% Warrego Energy 50%

SCOPE Located in the EP 469 licence area, the West Erregulla prospect has a best total prospective resource estimate of 32.8 billion m3 of gas. Strike and Warrego both hold a 50 per cent interest in the acreage and are exploring in order to produce a new source of gas for Australia’s east coast market. UPDATE January 2020: Strike Energy has continued testing and resource booking at the West Erregulla gas field, which has been named one of Australia’s largest, high quality, onshore conventional gas discoveries. During the quarter, Strike conducted a multi-rate flow and pressure build-up test after the drilling and completion of West Erregulla-2 (WE-2). During this testing period WE-2 flowed gas to surface from the Kingia sandstone from 48m of perforations across the target interval (4799m–4951m measured depth) in the Kingia formation. At the largest choke setting (two-inch), the well flowed at a rate of 69 million standard cubic feet per day (mmscf/d) with a wellhead pressure of 700 psig. PREVIOUS HISTORY December 2019: Strike has released a resource statement confirming the West Erregulla field contains a 2C contingent resource estimate of 1185 BCF (33.55 billion m3) of gas. Strike said the estimate is likely to increase as the current total does not include the Wagina sandstone, of which an accurate resource assessment is subject to further testing. November 2019: The flow test package has commenced mobilisation to the West Erregulla-2 well site in preparation for production testing. Mobilisation commenced following the completion of West Erregulla-2 and the installation of the Christmas tree, where Esternwell Rig 106 was then demobilised from location. Strike’s forward plan is to commence a multistage production flow test once the equipment arrives and is rigged up on site to gather formation pressure and performance data that will indicate gas column and field boundary. October 2019: Flow tests conducted at the West Erregulla 2 well have produced high quality results, with Strike reporting the Kingia Sandstone zone is currently being tested, with 48m of perforations placed across the interval between 4799 and 4951m measured depth. Through a two-inch (51mm) choke, a flow rate of approximately 1.95 million m3/day was achieved with 700 psig wellhead pressure over a one-hour period. September 2019: Drilling and completion actions have been finalised at West Erregulla-2, with Strike Energy successfully perforating the well across the Kingia zone, having set the packer and run the 3.5-inch (89mm) production tubing string into West Erregulla-2. The wellhead is now being installed and the Easternwell 106 rig has been released from the well, marking the end of the drilling program. Strike and Warrego report the find in the Kingia sandstone in the West Erregulla-2 well is very significant, with Strike managing director Stuart Nicholls calling the discovery “truly an exceptional outcome”. August 2019: Strike reported drilling operations at the West Erregulla-2 well had observed hydrocarbons throughout the targeted Wagina sandstone, which was found to be approximately 74m in thickness. The well section was finished without observing the end of Wagina, creating the potential for further sands to be encountered in other sections, while the secondary target – the Basal Wagina sandstone – is yet to be encountered. Strike managing director Stuart Nicholls said all the signs were pointing to a large gas resource.

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WESTERN AUSTRALIA BROWSE LNG PROJECT

ONSHORE | GAS PIPELINE | IN PLANNING | PROPONENT: WOODSIDE Woodside Energy 11 Mount Street Perth WA 6000 Tel: 08 9348 4000

OWNERSHIP: Woodside 30.6% Shell 27% BP Developments Australia 17.33% Japan Australia LNG 14.4% PetroChina International Investment 10.67%

SCOPE Led by operator Woodside, the Browse joint venture proposes to develop the Brecknock, Calliance and Torosa fields located approximately 425km north of Broome in the offshore Browse Basin. The JV has estimated contingent resources are approximately 13.9 trillion cubic feet (Tcf) of dry gas, and approximately 390 million barrels of condensate. The project would include two floating production storage and offloading facilities and a 900km gas pipeline to existing infrastructure on the North West Shelf. PREVIOUS HISTORY December 2019: According to The West Australian, Australian Resources Minister Matt Canavan said recent meetings with the Browse JV partners had been positive and there was still a chance the gas processing deals could be finalised by the end of the year. November 2019: Western Australia Premier Mark McGowan has urged the Browse joint venture partners, including Shell and BP, to prioritise resolving the project’s gas processing disagreements. Woodside is aiming for a final investment decision on the project in 2020. September 2019: Woodside CEO Peter Coleman said slow negotiations with some of the North West Shelf joint venture partners regarding processing gas from the Browse fields was opening the door for rival LNG projects to capture the market share. The company is still aiming to begin front end engineering and design works by the end of 2019. August 2019: According to The Australian Financial Review, Woodside said the Browse joint venture partners are heading towards a commitment to begin engineering and design work by the end of 2019. July 2019: Federal Resources Minister Matt Canavan said he would seek alternative developers for Browse if Woodside doesn’t develop the resource fast enough. “We need to see not just good intentions and words – I want to see real investment plans and hopefully a real decision on FID,” Canavan said. June 2019: Woodside is still expecting to make a final investment decision on the Browse project in late 2020, with Woodside CEO Peter Coleman saying at the APPEA Conference in Brisbane he did not expect current weak LNG prices to affect that timing. Meanwhile, equity holder BP said it was still evaluating investment in the project due to its high emissions potential. May 2019: Woodside is undertaking gas processing agreement negotiations, while the project will also be assessed by an environmental impact statement. March 2019: Woodside has expressed its desire to commence FEED activities for Browse in 2019 with a 2020 target for final investment decision. February 2019: An initiation to tender was issued for the FPSO FEED and engineering, procurement and project management support services, as well as an initiation to tender for the TMS FEED and engineering, procurement and construction. Additionally, a metocean survey program has commenced along the proposed pipeline route.

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WESTERN AUSTRALIA SCARBOROUGH GAS FIELD

OFFSHORE | IN PLANNING | PROPONENT: WOODSIDE Woodside Energy 11 Mount Street Perth WA 6000 Tel: 08 9348 4000

OWNERSHIP Woodside 75% BHP 25%

SCOPE The Scarborough field is approximately 285 km offshore from the Pilbara town of Onslow in 900 m of water and is estimated to contain around 8–10 Tcf of gas. Woodside holds a 75 per cent interest in WA-1-5, and a 50 per cent interest in WA-62-R, WA-63-R and WA-61-R, covering Scarborough, North Scarborough, Thebe and Jupiter gas fields respectively. Woodside, as operator of the Scarborough joint venture with BHP (25 per cent), is proposing to develop the Scarborough gas resource through new offshore facilities connected by an 345km pipeline to a proposed expansion of the existing Pluto LNG onshore facility (Pluto Train 2). The proposal is to initially develop the Scarborough gas field with up to seven subsea, highrate gas wells, tied back to a semi-submersible floating production unit (FPU) moored in 950m of water close to the Scarborough field. UPDATE January 2020: The Western Australian Environmental Protection Authority (EPA) has recommended approval for the state component of a liquid natural gas (LNG) pipeline that forms part of the Scarborough project. The proposal would see the installation of a gas trunkline 32.7km long, located adjacent to the existing Pluto LNG facility 8km north east of Dampier in the Pilbara. The remaining portion of the Scarborough project that is within Commonwealth waters will be assessed by the Australian Government, under the Environment Protection and Biodiversity Conservation Act 1999, which includes the consideration of greenhouse gas emissions. PREVIOUS HISTORY November 2019: Woodside and BHP have reached an agreement for the price of processing gas from the Scarborough fields at the Pluto LNG facility on the Burrup Peninsula, with the deal having been one of the last remaining hurdles to clear before a final investment decision (FID) on the project will be made. The toll is based on BHP maintaining a maximum 25 per cent interest in Scarborough up to an FID. Woodside CEO Peter Coleman said the two companies would look to finalise the required conditional binding agreements by the end of the first quarter of 2020. May 2019: Woodside has awarded Canada-based SNC-Lavalin two contracts for the Scarborough project. SNC will provide front end engineering design (FEED) support for the semi-submersible hull and mooring, model testing scoping and supervision, and ancillary scopes for the development’s floating production unit. The company will also provide overall technical safety, formal safety assessment and risk engineering services to support Scarborough’s engineering design activities. January 2019: Woodside has awarded contracts for Scarborough FEED work to McDermott Australia, Subsea Integration Alliance, Saipem Australia and Intecsea. McDermott will undertake engineering studies for the floating production unit, while Subsea Integration will take on studies for the subsea umbilical risers and flowlines. Both companies have the option to progress to an engineering, procurement and construction contract for the execution phase. Saipem is to provide export trunkline engineering support services with an option to execute line pipe coating and installation activities, while Intecsea has been awarded the contract for export trunkline engineering. March 2018: Woodside has completed the $444 million acquisition of ExxonMobil’s interest in the Scarborough gas field offshore Western Australia. The company announced the agreement to acquire ExxonMobil’s share of the Scarborough gas field located in the Carnarvon Basin Australia in February 2018. Scarborough owns 75 per cent of the asset after the acquisition.

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WESTERN AUSTRALIA CRUX PROJECT

OFFSHORE | IN PLANNING | PROPONENT: SHELL AUSTRALIA Shell Australia Shell Home 562 Wellington Street Perth WA 6000 Tel: 08 9338 6600

OWNERSHIP Shell Australia 82% Seven Group Holdings 15% Osaka Gas 3%

SCOPE Shell, with joint venture partners Seven Group Holdings and Osaka Gas, is planning to develop the Crux gas field approximately 160km northeast of the Prelude field in WA’s Browse Basin. The proposal consists of an unmanned platform and five production wells, with minimal processing and utility systems tied back to the existing Prelude FLNG facility via a 26-inch (660mm), 165km export pipeline. PREVIOUS HISTORY September 2019: Seven Group’s stake in Crux is officially up for grabs, with Morgan Stanley expected to take bids on the project until around November 2019. INPEX, CPC Corporation and joint venture partners Osaka Gas are reportedly among the interested parties. August 2019: The front-end engineering and design process is continuing as the project builds towards a possible final investment decision next year. June 2019: Seven Group Holdings has enlisted Morgan Stanley to look for a buyer for its 15 per cent interest in the Crux project. The Australian reported that final bids were due in June and that when questioned Seven said it was only “exploring options”. February 2019: Wood and KBR have been awarded front-end engineering design (FEED) contracts for the Crux project. Under the terms of the multimillion-dollar deal, Wood and KBR’s services will be delivered over 18-months and will provide a single integrated FEED for the Crux topsides, jacket, export pipeline and subsea pipeline end manifold. Shell and its joint venture partners have submitted a proposal to the National Offshore Petroleum Safety and Environmental Management Authority to develop the field. Front-end engineering and design works are intended to commence in 2019 and a final investment decision (FID) is targeted for 2020. The project is anticipated to take around five years to construct once an FID is made and is anticipated to have a 20-year design life.

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PAPUA NEW GUINEA PAPUA LNG PROJECT

ONSHORE | LNG | IN PLANNING | PROPONENT: TOTAL S.A. Total S.A. 2, Place Jean Miller La Defense 6 92078 Paris La Defense Cedex France Tel: +33 (0) 1 47 44 45 46

OWNERSHIP Total 40% ExxonMobil 36.5% Oil Search 22.8% Minorities 0.5%

SCOPE The Papua LNG project will encompass two LNG trains of 2.7Mt/a each and will be developed in synergy with the existing PNG LNG project facilities. Total and its partners have agreed to launch the first phase of the engineering studies of this project. Under the concept, one of the processing trains would be supplied partly by gas from Exxon-operated assets that feed the existing PNG LNG project. Two additional trains would be fed from the Elk-Antelope gas fields, which are part of the separate Total-led project called Papua LNG. According to Total, production should begin by 2024. UPDATE February 2020: The Papua New Guinea Government has pulled the plug on negotiations with ExxonMobil in regards to developing the P’nyang gas project because of the company’s “unwillingness to agree to reasonable terms”. The P’nyang field is key to helping feed the expansion of Exxon’s PNG LNG plant. Joint venture partner Oil Search has expressed disappointment about Exxon and PNG not being able to agree on the appropriate balance of value and benefits for a gas agreement. PNG Prime Minister James Marape said he was willing to allow international oil companies to develop the field and achieve decent return by exporting most of the gas, but PNG must also benefit. PREVIOUS HISTORY December 2019: PNG has started negotiations with ExxonMobil regarding the P’nyang gas project, with a deal expected in a matter of weeks. PNG said it would be pursuing a deal more beneficial to the country than the Papua Gas Agreement. November 2019: Despite the projects being closely related, PNG Petroleum Minister Kerenga Kua said the P’nyang Gas Agreement would not be on the same terms as the recently upheld Papua Gas Agreement. The government said it aims to sign this new agreement in November. Oil Search said it was targeting an agreement by the end of 2019. October 2019: The PNG Government plans to stand by the Papua LNG Gas Agreement that was signed in April 2019 by former Prime Minister Peter O’Neil. Minister for Petroleum Kerenga Kua said the government had cleared the way for project operator, Total, to proceed “full steam ahead” with the implementation of the Papua LNG project. Minister Kua also said the government had authorised the project to proceed in accordance with the terms of the gas agreement. September 2019: The PNG Government is seeking to renegotiate the terms of the Papua LNG gas agreement, with PNG Minister for Petroleum Kerenga Kua to travel to Singapore with a negotiating team to discuss new terms. A statement signed by Minister Kau acknowledged that a breakdown in negotiations could have serious ramifications, with a collapse of the deal also affecting the expansion of the Exxon-led PNG LNG Project. August 2019: The Papua New Guinea Government claims it will stand by the Papua LNG Gas Agreement “in principle”. PNG Minister for Petroleum Kerenga Kua said the government reserved the right to discuss matters with the developers and that finalising the details of the deal should not take longer than two weeks. July 2019: Despite a new PM in PNG, Oil Search managing director and CEO Peter Botten said he didn’t “anticipate there would be any changes to the Papua LNG gas accord.”

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TECHNOLOGY

How process safety management improves workplaces Delivering superior process safety performance is a given for ABB when it develops technological solutions for companies in the oil and gas sector.

he oil and gas industry presents a number of highly hazardous environments that potentially keep safety risks hidden under the surface of operational control panels. To ensure an operation remains secure, process safety management has been introduced to thoroughly assess and mitigate these potential hazards from the design phase through to the safety control system operation. Process safety management is about preventing major accidents such as fires, explosions and major losses of containment in an industrial setting like oil and gas plants. In 2005, a fuel depot outside the town of Hemel Hampstead, 40km northwest of London, had unleaded motor fuel pumped into a storage tank when the tank safeguards failed, leading to the disaster known as the Buncefield fuel depot fire. None of the staff working at the depot realised its capacity had been reached and it overflowed, resulting in a rapid formation of a rich fuel and air vapour that caused an explosion and fire to break out. The fire engulfed 20 large storage tanks, with emergency services declaring it as a major emergency that required 25 fire engines, 20 support vehicles and 180 firefighters on site to extinguish the blaze. This incident led to the implementation of three key process safety questions that are relatable across all industries: what can go wrong? What protective layers are in place to prevent it? What information assures those protective layers are being effective? The three questions underpin the process ABB uses to approach Safety Lifecycle Management in the

ABB software gives operators transparency to the plant’s operational risks.

ABB digital lead and product marketing manager Erica Barrett.

oil and gas sector. ABB Ability SafetyInsight software guides oil and gas companies through the hazards and risk assessments required by these first two questions, as well as aplications to gather contextualised information to reliably

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monitor risk control effectiveness. Not only do each of these elements have to function well, but they have to link to the other areas effectively and be consistent. For example, risk control systems must be designed for specific hazards identified during the hazard identification stage and the auditing process must ensure that all safety functions perform as per design assumptions. With a full lifecycle approach to safety, ABB extends its process safety from the risk assessment stage, to the design phase through to the control system safety implementations phase and into the operations phase. Digital lead and product marketing manager Erica Barrett said it was through ABB’s software and hardware that the company supported its customers through the full process. “Initially when a customer is trying to run through what hazards exist at its plant, what the protective layers

TECHNOLOGY

ABB Safety Lifecycle Management provides intelligent applications, services and technolgy to support risk management associated with operating high hazard processes.

that are needed to protect against those hazards and should any of those protective layers need additional safety function, ABB solve this through its risk assessment software to support intuitive and efficient workshops, evergreen recording and safety instrument function (SIF) design,” Barrett told Oil & Gas Today. “If the operator then wants to make the hazardous event risk matrix dynamic, we pull in the live operating data that is captured from the control system and Computerised Maintenance Management Systems (CMMS). Then we are able to identify

which barriers are currently degraded and their relationships to understand the accumulative operating risk.” “The pull-through value lies in contextualising this basis of safety engineering data into the operations space.” In the situation, when there is an unplanned or planned shutdown of a production site, Barrett said ABB’s software was able to record all of the expected causes and events, pinpoint them immediately and collate data. “The data is captured and able to give an actionable insight to the operational team, making the safety

performance validation easily visible,” Barrett said. Due to ever-advancing technology, ABB is using industry standard protocols to extract information from agnostic operational systems, and developing software new releases and being responsive to customer requests for new features. ABB is a digital leader in the oil and gas industry through heavy investment in how the company supports the sector’s management of operational safety risks. The company’s focus areas include helping oil and gas organisations develop cyber security solutions, and support the next level of asset performance and sustainable energy management. “Customers are driving towards a digital automation future and that’s where ABB is supporting their journey as well,” Barrett said. “We are looking at all the different technologies customers are wanting from us and building on those.” Barrett reinforced the Australian oil and gas sector’s emphasis on safety and security, which is also the priority for ABB in the development of its technology solutions. “ABB’s approach is to digitalise what has been designed, collect near-real time data, and make accessible what is happening at the customer’s operations,” Barrett concluded.

ABB Ability SafetyInsight software enables the oil and gas industry to sustain safe and reliable operations.

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OIL & GAS EQUIPMENT

Pickles creates platform for oil and gas division The oil and gas sector has received a boost after Pickles established a dedicated oil and gas division.

ickles Oil & Gas is a key international auction and valuation specialist that resources the purchasing of oil and gas equipment, connecting buyers globally to quality offshore and subsea assets. Providing a wide range of oil and gas equipment and parts available for sale on behalf of leading industry clients, Pickles Oil & Gas division has been setup specifically to remarket equipment for operators. Pickles business development manager of oil and gas Stephen Amy said the company identified a gap in the market when working with Shell.

“All of the programs we do are global programs, so we had to look at how we were going to target buyers globally that were looking for oil and gas equipment. “It’s not just something we can isolate to Australia; we need to take those marketing campaigns globally.” By only selling oil and gas equipment, Amy said it would give the business the ability to “specialise in that equipment and understand it properly, know the markets we are targeting, know what we are talking about when we are discussing that equipment type with potential buyers”. “It has also enabled us to go to

“A lot of the time this equipment is taking up valuable space in yards and it is costly for the operator and the fact that they do have other equipment coming in – it was a bonus for the oil and gas companies.” Stephen Amy Pickles business development manager - Oil & Gas “We thought the type of equipment they were giving us needed a dedicated vertical within the Pickles business and it also needed a specialised approach to how we treat this equipment, go about remarketing it,” Amy said.

other oil and gas operators and offers them that dedication and service,” he said. Launched about a year ago, the dedicated division

Pickles provides a wide range of oil and gas equipment and parts for both onshore and offshore operations.

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has since grown into a thriving business with 23 branches across 28 sites. Despite the business tossing up the idea for a small amount of time, the concept soon became a sought-after aspect of the oil and gas industry. “Because we are a very large auction and remarketing business, we have a lot of branches Australia wide and a lot of space we can take on a lot of equipment, which was appealing to oil and gas companies,” Amy said. “It was the fact we could take on their surplus equipment and store it and give it the time and effort of putting a remarketing program together. “A lot of the time this equipment is taking up valuable space in yards and it is costly for the operator and the fact that they do have other equipment coming in – it was a bonus for the oil and gas companies.” The key to Pickles’ dedicated and tailored sales program is it assesses the equipment for the best fit sales program. “It is a matter of sitting down and inspecting the equipment and then going back to the vendor and explaining the type of package that will be the best sales method to sell this equipment,” Amy said. “This way we are definitely getting

OIL & GAS EQUIPMENT

Pickles Oil & Gas doesn’t limit its services to the industry only in Australia, but operates globally to auction equipment.

better financial results for the vendor.” Amy emphasised that a lot of the subsea equipment it sold was by expression of interest, reaching a global market. “At the end of the day we are really trying to find the best buyers for that equipment and therefore once that buyer is found we are then achieving the maximum result for the vendor,” he said. By deciding to create a specific landing page, Pickles is able to market equipment for clients at the click of a fingertip.

“It allows clients to not have to go into the main Pickles page and sift through all the equipment we are selling, they are able to go to the landing page, and see clearly the oil and gas equipment and the dedication,” Amy said. “The landing site gives Pickles Oil & Gas more of a personalised approach for both the seller and buyer.” The Pickles company was created in 1964 and has since brought people together by delivering value for its clients. The privately-owned company was

built by people who are passionate about the industry, with a commitment to innovation, experience, quality of relationship and the ability to solve complex problems to strive for the maximum return on all assets. Through the dedicated oil and gas division, Amy is confident Pickles has established a strong network within Australia and internationally. “We have been selling this equipment for a year and we are building a really good network for type of equipment globally,” he concluded.

FAST FACT

Pickles has brought people together since 1964 by delivering value for its clients across several industries.

• Pickles Oil & Gas division is the new resource for purchasing oil and gas equipment. • The company connects buyers globally to quality offshore and subsea assets. • The privately-owned company started in 1964 and now has 23 branches nationally. • Pickles conducts over 150 auctions a month nationally, including weekly motor vehicle auctions and monthly industrial auctions.

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TECHNOLOGY

Top-quality care for the oil and gas industry LINX Cargo Care Group is dedicated to becoming a household name in the oil and gas community by embracing the latest technology and reinforcing the importance of its core values.

ompanies servicing the oil and gas sector are finding innovative ways to capitalise on the benefits of virtual reality (VR) technology for subsurface studies, training and simulation, and for developing and improvising processes and products. According to Deloitte, delivering VRbased, on-demand training sessions that leverage in-person walk-throughs, computers, and other advances can improve knowledge retention and reduce traditional classroom training costs. Deloitte reported that oil and gas VR training is highly realistic for dangerous situations and can test safety and compliance protocols, and improve procedural execution in the event of an emergency safety incident. GlobalData also found that VR allows companies to create a digital twin to replicate the performance of an oilfield, refinery, or any other operational unit on a virtual platform. This helps to minimise risks and costs associated with new process

implementation in oil and gas operations. LINX Cargo Care Group is introducing VR to its operations as it strives to bring the best specialist service to the industry through all phases of exploration, drilling and production. The company is now using VR as part of its training programs to gain effectiveness in its safety and has plans to include it at its oil and gas operationsÂ in the future. VR first and foremost improves LINXâ&#x20AC;&#x2122;s safety processes, but the

LINX group manager business development for Western Australia and Northern Territory Neil David.

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company also expects to see productivity benefits as the technology is rolled out. Tech role in enhancing efficiency and safety In order to maintain a strong production flow and continue to build the companyâ&#x20AC;&#x2122;s status, LINX knows the importance of embracing the latest technology to enhance its efficiency and safety. LINX group manager business development for Western Australia and Northern Territory Neil David said the

TECHNOLOGY

“There is an efficiency gain because you don’t have to do training on-site in a machine and stay in a productive environment, the benefit is the ability to train multiple people at the same time,” Neil David LINX group manager business development for Western Australia and Northern Territory company would use VR to train people in hazardous environments without the physical risk. “There is an efficiency gain because you don’t have to do training on-site in a machine and stay in a productive environment, the benefit is the ability to train multiple people at the same time,” David, who has more than 30 years of experience in the transport and logistics sector, said. As a result, the company has found it is able to verify employee competence in a shorter time frame, increase

confidence and reduce risk. Despite not using VR in the oil and gas industry yet, LINX has flagged it as a sector where the technology will provide advantages. “One of our challenges is delivering consistent training across our many sites around Australia and New Zealand. We are figuring out how to get the biggest bang for buck and identify the common operational tasks,” David said. “At the moment we are working on this. We know that the technology works, and it has delivered great results at some LINX Cargo Care Group has been using virtual reality for training purposes across its operations.

sites. So, the next thing we do is try and make it relatable, efficient and effective to most sites.” David hopes that through the evolution of technology and the continued successful work LINX provides the oil and gas industry, the company will become a household service to the market. The commitment to implementing the latest technology reflects the company’s values to ensure it performs at the highest level possible, while maintaining the safety of its employees. The importance of work values LINX’s reliable work ethic is underpinned by LINX’s core values, which were introduced by group chief executive officer Anthony Jones. With a big emphasis on the company’s values and being authentic, Jones believes in visible leadership, which he identifies as the core to instilling trust amongst staff, while giving him the chance to show his appreciation. Communication is a must, having a direct link to your people is key to success at LINX. The company values: be brave, be bold; we are one; home safely, every day; act like you own it; powered by people; are LINX’s guiding principles to which the organisation is run. This includes from the way it works with each other, its customers, partners and shareholders. “Anthony is a very authentic man and I think employees are always looking for authenticity in their leaders. This is the key to having your values to be seen as real,” David said. With a passion to continue to build the LINX reputation up as a household name, David said building a good reputation is an important aspect in reaching this goal. Through the use of net provider scores and customer feedback surveys, LINX has been able to improve its latest net score across the country, meaning more customers are willing to recommend the company’s services. “It is also just as important to delve into the feedback from people who are neutral or negative and see what areas we need to improve on,” David concluded.

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INDUSTRY COMMENT

Realising the value of Australian gas Gas is a critical and major contributor to Australia’s energy supply. Australian Pipelines & Gas Association chief executive Steve Davies believes the public opinion of gas doesn’t appear to appreciate its value or the magnitude of the role that it plays.

his year marks the start of a new decade and the unprecedented bushfires across Australia this summer have put climate change back to front and centre of the public discourse. We cannot discuss climate change without discussing energy policy. The interrelationship between Australia’s overall emissions, our historical (and ongoing) reliance on coal for electricity generation and the emissions associated with our economically critical energy exports mean it will always be thus. For discussions that are all about science, technology and markets, it is truly remarkable how much ideology and belief is involved. We only need to look to some of the response to the Prime Minister’s recent

APGA chief executive officer Steve Davies.

comments about natural gas during his speech at the National Press Club in January to see this. “There is no credible energy transition plan for an economy like

Australia in particular, that does not involve the greater use of gas as an important transition fuel,” Morrison said. “There are plenty of other mediumto longer-term alternative fuel arrangements and prospects, but they will not be commercially scalable and available for at least a decade, is our advice. “Gas has a critical role to play as a backstop to our record investment in renewable energy generation. “It helps ensure we can keep the lights on when the wind isn’t blowing and the sun isn’t shining.” Naturally, these comments have not been well-received in some circles. I don’t think there can be any doubt that natural gas has an image problem these days. I also think there is very Welding joints on a pipeline as part of a Santos project in Queensland.

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INDUSTRY COMMENT The Northern Gas Pipeline under construction.

little understanding of just how much energy, and what kind of energy, natural gas provides to Australia. The PM’s comments were largely focussed on the role of gas in electricity generation. And he is right. Natural gas is the only option to provide the dispatchable, on demand generation capacity that is required to support the delivery of increased renewables into our electricity system. This is not a belief; this is a fact. One that is clearly demonstrated each and every day in South Australia, which has Australia’s highest penetration of renewables at 51 per cent of total supply. The day after the PM’s speech proved the point perfectly. On a hot and windy Thursday January 30 in South Australia, renewable energy provided 83 per cent of electricity supply at 11am. As often happens, the wind dropped off late in the afternoon and, as always happens, the sun started to go down. Gas power stations across the state ramped up and by 7:30pm, provided 75 per cent of South Australia’s electricity. Overall, natural gas is currently providing 21 per cent of Australia’s total electricity supply, mostly as

flexible, dispatchable generation keeping the system going when it is needed most. Gas-fired power plants have as little as one-third the carbon intensity of some coal plants. In its own right it is a low-emission technology. If we were to displace coal with an even mix of renewables and gas, as has been done in South Australia, we could easily reduce emissions from the electricity sector by 75 per cent or more. That would be an amazing result and a huge step forward for Australia. While much of the attention is on electricity, it is crucial to effective energy policy development that there is a proper understanding of the entire energy demands of Australia. Natural gas plays an even bigger role in final energy consumption. The total electricity supply consumed in Australia was 835 petajoules (PJ) of energy in 2017-18, 21 per cent of which was generated by gas. The direct burning of natural gas for heat in the same year provided 943 PJ. This number does not include the gas that was used to generate electricity. Yes, natural gas is providing

more usable energy to the Australian economy that the entire electricity system. Refined petroleum products provided a further 2234 PJ of energy, exceeding gas and electricity combined, and shows just how critical the petroleum industry is. The task of decarbonising the electricity system is enormous, and as I have suggested above, natural gas can play a big role in supporting the role out of more renewables. It is simply unfeasible to contemplate to simultaneously decarbonise electricity and expand supply to take on the heat load of natural gas or the transport load of refined products. Yes, in some applications we will see electrification. The gas industry understands the need to decarbonise. For us, hydrogen, renewable methane and biogas offer new opportunities to secure a permanent role in the energy mix post 2050. In the meantime, the design of our energy policy must be cognisant of the hugely important role natural gas, and oil, will continue to play in the coming decades to power the country and support the implementation of the clean energy future.

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ASSET MANAGEMENT

Advancing thermal mass gas flow meters for 21st century needs Fluid Components International technical staff member Gerardo Vargas discusses how the ST100 Flow Meter sets a new benchmark in flexibility for the thermal mass flow meter industry.

rocess, instrument and plant engineers are challenged continuously by productivity and plant operating efficiency objectives, as well as ensuring plant compliance with an ever-expanding list of regulations. This situation burdens the plant’s process engineering and operations team with requirements for more data and information about the processes to better manage, control and report on them all under the scrutiny of being cost effective. The bar keeps being raised for accuracy, repeatability, data, information, communications, diagnostics, record keeping, reducing maintenance and increasing service life. This challenge was heard over and over again as Fluid Components International (FCI) listened to what

Figure 1: FCI ST100 Series Thermal Mass Air/Gas Flow Meter.

users required in their process gas flow meters to support their current plant needs and what they expected to meet their vision for the plant of the future. With this voice of the customer’s feedback, FCI’s engineering team began the process several years ago of developing its next generation thermal mass air/gas flow meter. It is not surprising that thermal mass flow meters, applied in air/gas flow measurements, have been one of the top three fastest growing flow technologies the past six years1 and projected to be the fastest growing, non-custody transfer driven technology over the next five years2. Leading engineers in the process community are increasingly recognising thermal dispersion flow meter technology, a direct mass flow measuring technology, as an extremely effective, no maintenance, highly reliable and low-cost solution for their gas flow applications. What is surprising is that the vast majority of thermal flow meters in the market deploy sensor and electronics conceived and designed 20 or more years ago and are inherently limited by them. While effective in their basic measurement capabilities, their ability to provide process data and diagnostics information is extremely limited. These older designs do not have the core processing capability, internal bus speeds or I/O linkage to support modern field bus communications. Older microprocessors, A/D and D/A converters have limited raw computing power and resolution that restrict application of sophisticated linearisation techniques that improve

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output accuracy and resolution, store calibration and process data and perform diagnostics. FCI has addressed these modern and dynamic engineering needs for industrial plant and process gas flow measurements by developing an all new thermal mass flow meter, the ST100 Series Thermal Mass Air/Gas Flow Meter. A great communicator, adaptable Whether the need is for conventional 4-20 mA analog, frequency/pulse, alarm relays or advanced digital bus communications such as HART, FOUNDATION fieldbus, PROFIBUS or Modbus, the new ST100 Series Flow Meter is the solution (Figure 1). Should a plant’s needs change over time or an upgrade be desirable, the ST100 Flow Meter adapts as necessary with a plug-in card replacement that can be changed out by plant technicians in the field. Revisions or upgrades to communications and new supporting firmware can be uploaded into the ST100’s bus communications interface card to support it and keep current. This design approach takes “never obsolete” to a whole new level in flow measurement instrumentation. HART is standard and included with the analogue outputs interface. All of the outputs are interchangeable at any time. All measurements, including flow rate, total flow, temperature, and pressure with the STP models, are provided on outputs or over the bus communications. All ST100 Flow Meters also include a serial I/O port via a standard USB interface for direct connection to a PC and an Ethernet port with its own

ASSET MANAGEMENT

available with the ST100 Series include remote interrogation and troubleshooting by FCI staff over the instrument’s built-in Ethernet connection. Standard on all ST100 models is an on-board data logger, capable of storing 21 million readings on removable 2GB micro-SD card. It stores and recalls up to five unique calibrations and with extended calibration routines achieves up to 1000:1 turndowns. Flow ranges to as low as 0.25 SFPS (0.07 NMPS) up to 1000 SFPS (305 NMPS) are available and accurate to ± 0.75 percent of reading, ± 0.5 percent of full scale.

The FCI meter is a step forward for process and plant performance.

assigned IP address, which allows ease of access and interrogation by service personnel. The ST100’s HART I/O is fully compatible with the latest Version 7 standards. Today, the ST100 is with the HART organisation undergoing the final stages of its testing for independent certification by the organisation. The ST100 already has received its certification from the FOUNDATION fieldbus organisation and was one of the first two instruments ever to be certified to meet its advanced diagnostics criteria.

Figure 2: LCD Display/Readout

Data and information The ST100 Flow Meter features a sophisticated LCD display/readout (Figure 2) that brings new meaning to the term “process information.” The ST100’s unique graphical, multivariable, backlit LCD display provides the industry’s most comprehensive process information with continuous display of all measurements and alarm status, and the ability to interrogate for service diagnostics. All process parameters are continuously available, including flow, total flow, temperature and alarm status. The versatile ST100 Series’ STP models also include pressure measurement, which makes this FCI instrument the first and only triplevariable (flow, temperature and pressure measurement) thermal dispersion flow meter in the world. Adding temperature and pressure capability reduces the need for separate instruments and wiring runs to greatly reduce installation costs. The display also includes diagnostics data, which is made available via bus communications. The ST100 was the first thermal mass flow meter certified by the Fieldbus Foundation with advanced diagnostics. The advanced diagnostic features

Advancements and choices in sensor designs3 With the ST100, FCI becomes the industry’s first thermal mass sensor technology manufacturer to offer three different types of flow sensors to best match user applications (Figure 3). The FPC-style is a fast response type that features an integral, patent pending flow conditioner and protective shroud optimised for compressed air and clean gas applications. The FP-style is a fast response, general purpose design with a protective shroud and is also the sensor used with FCI’s VeriCal in-situ calibration option. For applications with wet or dirty gases, or erratic flows, the unshrouded S-style facilitates easy cleaning and provides a smoothed response. The ST100 Series is comprised of two core model families: the ST and STP. The ST family measures both mass flow and temperature, and the exclusive STP family adds a third parameter — pressure. The STP configuration makes the ST100 the world’s first triple-variable thermal flow meter, measuring flow, temperature and pressure. Both families include single-point and dualelement models as configurations outfitted with FCI’s exclusive in-situ calibration option, VeriCal. The ST100 can be calibrated to measure virtually any process gas, including wet gas, mixed gases and dirty gases. The basic insertion style air/gas meter features a thermal flow

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ASSET MANAGEMENT

Figure 3: Multiple Sensor Heads (– FPC Style Element; – FP Style Element; – S Style Element).

sensing element that measures flow from 0.25 SFPS to 1000 SFPS (0.07 NMPS to 305 NMPS) with accuracy of ± 0.75 percent of reading, ± 0.5 percent of full scale. For ease of installation, the ST100 Series features an etched depth gauge in both English and metric units on the sensor probe. The depth gauge takes the guesswork out of installing the insertion style flow meter sensor probe, allowing for precision sensor head placement in the centre of the pipe for optimum contact with the flow stream. By placing the sensor into the centre of the flow stream, accurate and repeatable flow measurement is ensured. Dual sensors option, dual purpose Models ST102, ST112, STP102 and STP112 are dual-element systems that can be applied in an averaging mode or as two discrete and independent sensors operating through a single transmitter (Figure 4). A single dual-element instrument can result in significant cost and space savings compared to installing and integrating two single-element instruments. Two-in-one configuration: Two sensors sharing single transmitter – a totally new and unique concept offered by FCI. Plants or applications with two or more flow meters can realise cost savings of 25 per cent or more by multiplexing two separate flow elements into a single transmitter.

The flow elements’ process connection and calibration(s) can be the same or completely different and independent. Each of the flow elements is interfaced and controlled by its own front-end electronic circuit board within the transmitter. Any of the available 4-20 mA analog outputs or relays can be assigned to either sensor. The digital readout is settable to display measurements from either sensor, selected by the user or automatically alternating between the two. In units with bus communications, all data from both sensors is continuously available and transmittable over the bus. This can provide even more savings because the cost of the bus communications is reduced by 50 per cent, bus wiring is reduced by 50 per cent and only half of the nodes are required. Two sensor averaging system: Applications involving line sizes 406mm or greater can realise improved installation accuracy and repeatability by averaging the flow rates of two elements. Distorted, swirling and nonrepeatable flow profiles can result in decreased accuracy of single point meters. In many cases, it is impractical or impossible to provide the required straight-run for a fully developed flow profile in large lines. Models ST102, ST112, STP102 and STP112 overcome these flow profile concerns with a simple, economical “dual-element averaging system.” The transmitter electronics will average

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the input from two independent flow elements into a single output. Each flow element can be independently configured for insertion length and process connection to allow installation flexibility. One flow element can be integral with the flow transmitter, or both can be configured as remote to accommodate easy access to terminal blocks and the optional digital display/optical four button interface. The flow transmitter also provides independent information for each flow element, saving time when performing service checks. Unsurpassed calibration capability4 While a single calibration is sufficient for many operations, the ST100 Series can provide up to five unique calibration groups. Depending on your application need, this feature can provide significant cost and time savings. Some examples include: • Broaden measuring range – Extend the turndown ratio up to 1000:1 or have different ranges for the same gas to maximise accuracy and resolution under changing conditions. This is particularly beneficial with flares, which can require both a low flow range for normal operation and leak detection, and also a very high flow range for upset conditions. Multiple calibration group settings save on the cost of using multiple flow meters. • Different mixtures of same gases – Embed calibrations to optimise flow measurement accuracy in dynamic or seasonally affected processes (e.g. Digester Gas Group 1 is 65 per cent CH4, 35 per cent CO2; Group 2 is 62 per cent CH4, 38 per cent CO2). • Different gases – Portable or temporary installations for multiple applications, or to reduce spare parts inventory in plants with multiple installations and applications. Multiple gases, such as dual fuel sources (e.g. natural gas and propane). The ST100 is calibrated in FCI’s own calibration laboratory to the user’s plant gas, as compared to air-equivalency method that is typical throughout the industry. FCI’s flow meters are calibrated under

ASSET MANAGEMENT

the user’s plant conditions with the actual gas and temperature to ensure the best installed accuracy performance. With over 40 years of flow instrumentation experience, FCI operates one of the industry’s leading flow analysis and calibration laboratories. All laboratory equipment is National Institute of Standards (NIST) traceable, as well as certified to ISO 9001:2000 and AS9000 compliant. The laboratory also meets MIL-STD-45662A and ANSI/ NCSL-Z-540 requirements. FCI’s Flow Calibration Laboratory provides gas flow calibration capabilities ranging as low as 0.001 SCFM (0.00017 NCMH) to ranges that exceed 5000 SCFM (8500 NCMH) and higher for line sizes in excess of 250mm. Flow calibrations for applications with temperature ranges from -73°C to 538°C and pressure ranges from 0 psig to 1000 psig (0 atmospheres to 68 atmospheres) are commonly performed for many fluid services. This advanced flow calibration laboratory is used across the aerospace, aviation, process control and discrete

manufacturing industries for precision thermal flow/level sensor design, manufacture, calibration and research. The company’s laboratory has supported a large number of leadingedge development programs, including preflight testing sensors for the F22 Raptor Fighter, the V-22 Osprey Helicopter, the Global Express Program and others. Rugged design, agency approved for demanding processes ST100 Flow Meters are designed for rugged industrial process and plant applications, including service up to 454°C. Both integral and remote (up to 300 metres) electronics versions are available. The complete ST100 instrument is agency approved for installation in hazardous environments. Often other suppliers evade or mask that their approvals are on the enclosure only. FCI and the ST100 approvals are for the entire instrument, sensor element, electronics/transmitter and the enclosure.

Figure 4: Dual Sensor Configuration.

Instrument approvals (submitted and pending) include: FM and FMc: Class 1, Division 1, hazardous locations, Groups B, C, D, E, F, G; ATEX and IECEx: Zone 1, II 2 GD Ex d IIC T4. The rugged enclosure is NEMA 4X/IP67 rated and is the only thermal flow meter with fourconduit ports to provide best-practice wiring isolation and signal integrity. Another feature only obtainable with state-of-art electronics and which can be a big cost avoidance in process installation is the use of optically activated programming and interrogation buttons that come with the digital display. The buttons are activated through the front panel glass, no need to open the instrument. In hazardous gas installations, this means the instrument does not need to be removed from service or the area decommissioned to change settings or obtain information about the unit. Conclusion With the thermal mass flow meter industry’s widest selection of outputs and compatible digital communication protocols plus the flexibility to change communication protocols easily, the ST100 Flow Meter sets a new benchmark in flexibility. Its triple variable measurement capability — flow, temperature and pressure — along with built-in datalogger provides process and plant engineers with all the data they need by installing a single instrument requiring a single wiring interface. The long list of additional ST100 Flow Meter capabilities, such as its graphics-based LCD digital display with through the glass touch control, multiple calibration groups built-in, SpectraCal gas equivalency calibration and more, provide exceptional functionality and ease-of-use. Process and plant engineers will find this instrument offers exceptional value to help them increase plant efficiency and reduce total operational costs.

References 1 The World Market for Thermal Flowmeters, October 2009; Flow Research 2 The World Market for Flowmeters - 2011 Edition; September 2011; IMS Research 3 Advances in Thermal Dispersion Flow Meter Accuracy, 2007, D. McQueen, Fluid Components International 4 See FCI Calibration Laboratory video: http://www.youtube.com/watch?v=b3Blg6sQQvc

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EVENT SPOTLIGHT

Woodside, Chevron line up AOG keynote speakers The Australasian Oil and Gas (AOG) Exhibition & Conference returns to Perth this year with a range of high-profile speakers again involved.

ajor LNG operators Woodside Energy and Chevron Australia have thrown their support behind the 39th annual Australasian Oil and Gas (AOG) Exhibition & Conference by confirming key speakers for the event. Woodside Energy executive vice president development Meg O’Neill and Chevron Australia director of operations Kory Judd will join Western Australian Premier Mark McGowan for the opening address of the event. O’Neill is responsible for design and execution of onshore and offshore capital projects, the engineering function, Browse, Scarborough and Senegal and Judd is responsible for overseeing the safe and reliable operations of the Gorgon LNG, Wheatstone LNG, Western Australian Oil and domestic gas assets. The confirmation comes as the

free-to-attend conference program was finalised; it includes an Industry Supply Forum, Subsea Forum and Knowledge Forum featuring experts across a range of industry sectors from machine learning to renewables, decarbonisation, diversity and technology. The speakers and program will support the theme for AOG 2020 of “Forward Together – Driving Opportunity, Generating Confidence”. This theme takes on many important connotations. Built in collaboration with various stakeholders, including government, major operators and the supply chain, forward together reflects the current state of the industry and how the entire supply chain will unite at AOG this year. Integral to this is theme is the presentations of operator forward work plans at the event – which is the next step in the Western

Australian Government’s LNG Jobs Taskforce vision. Operator briefing sessions will give attendees the opportunity to engage directly with the four operators presenting Forward Work Plans – Woodside Energy, Chevron Australia, Shell Australia and Santos. The Forward Work Plans are a two-year outlook designed to facilitate improved planning of potential contracting activity and supply chain capability. This is an exclusive opportunity to AOG attendees and a first for the event this year. This comes as AOG confirms a collaborative LNG Jobs Taskforce stand at the exhibition hosting Woodside, Chevron, Shell, Santos, INPEX and the Western Australian Department of Jobs, Tourism, Science and Innovation. A further opportunity for attendees to engage directly with the major operators.

AOG provides the opportunity to learn from international speakers.

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EVENT SPOTLIGHT

In addition to the exhibition and conference offering, the event will also feature a technology station presented by the National Energy Resources Australia (NERA), which will showcase new technologies from entrepreneurs demonstrating their innovative products and services in the fields of data and digitisation, automation and robotics, artificial intelligence and machine learning. This is a comprehensive program supporting the discovery, commercialisation and deployment of innovation and technologies across Australia. AOG event director Bill Hare said the high-profile speaker confirmation and demand for exhibition space showed the importance of the industry to the Western Australian economy. “We are proud to welcome our keynote speakers who will open this year’s event, which is set to be 20 per cent bigger than 2019. We have already sold more than 90 per cent of the exhibition space and have had great support from both government and industry,” Hare said. In conjunction with the exhibition and conference offering, there are exclusive networking events available to industry professionals. From welcome drinks to an opening celebration and thoughtprovoking breakfasts, attendees will have the opportunity to meet new prospects, connect with old colleagues

The conference explores specialised industry zones showcasing the latest in the industry.

“We are proud to welcome our keynote speakers who will open this year’s event, which is set to be 20 per cent bigger than 2019.” Bill Hare AOG event director and celebrate the industry. AOG is the only event in the year where the entire industry stops to gather together and look forward to future opportunities and discover the latest insights. Running from March 11-13 at the Perth Convention and Exhibition Centre, the annual AOG is the biggest oil and

gas event in Australia, and a vehicle for collaboration. The free exhibition and conference brings together the entire supply chain: more than 9000 attendees, 300 exhibitors for a three-day showcase of local and international technology and services, with extensive networking opportunities.

FAST FACT • AOG is a showcase of the latest products and services and attracts over 8000 global visitors providing opportunities to network and learn about the latest technological and innovative breakthroughs which will drive the industry into the future. • Discover the latest products and innovations from hundreds of Australian and international leading distributors and manufacturers that are driving the industry forward.

Hundreds of exhibitors will be on display at AOG.

OILANDGASTODAY.COM.AU / MARCH 2020 / 61

, D E E N U T. O Y E R R E ER N. V E F O T N A O H IS H W D IT RC A N I E F ES TH

RELY ON AUSTRALIA’S MANUFACTURING, MINING AND INDUSTRIAL HUB 70,000 monthly users can’t be wrong. Find what you’re looking for with over 12,000 business listings and 8,000 specific product listings. Access relevant information and resources, empowering you to make a qualified purchase decision. You can always rely on your industry hub.

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MHD Supply Chain Solutions

EVENT SPOTLIGHT

Insight into the eighth ADGO The Australian Domestic Gas Outlook conference in Sydney is the annual meeting place for the domestic gas industry, with CEOs and senior executives from the entre gas value chain coming together to network, debate policy issues and analyse market dynamics.

Rod Sims, chairman of the Australian Competition and Consumer Commission.

he Australian Domestic Gas Outlook (ADGO) conference takes place in March, with more than 300 industry leaders set to provide high-level discussion on engaging and topical content related to the gas industry. Founded in 2013, ADGO has become a significant event on the gas industry’s calendar, the conference is now in its eight year and has built a loyal following within the industry. The last decade has been a turbulent time for domestic gas markets and with the launch of the Queensland-based LNG export trains, moratoriums on fracking in various states and rapidly rising domestic prices just some of the big topics of discussion over the years. During this period ADGO has helped to address some of these issues by encouraging cross-industry collaboration and bringing together panels and speakers from all facets of the market to debate them. Many challenges still exist in 2020

Paul Adams, past Jemena managing director.

and they will be the focus of the event in Sydney on March 16–20. Rod Sims has become a key regulator in the industry, with the ACCC tasked by the federal government to conduct an ongoing inquiry into the East Coast gas market. Not only do his recommendations carry weight with the federal government, they are also extremely important to the Australian people. His keynote at this year’s event is highly anticipated. Other policy highlights on the program include Western Australian and New South Wales’ Ministers Bill Johnston and Matthew Kean, who will each talk to the state of play in their states and future policy direction. The 2020 event also features some of the most significant producers of domestic gas on the program, including the CEOs of Senex, Strike Energy, Cooper Energy, Beach Energy, as well as senior executives from BHP, ExxonMobil and Origin. They will explore the opportunities for new supply to come to market as well as discuss

some of the opportunities for optimising the regulatory and policy environment to better suit the market. They will also be joined by the leaders of the pipeline sector with CEOs from APA Group, Jemena and AGIG all delivering keynote presentations. Jeanne Johns, CEO of Incitec Pivot and Stephen Bell, CEO of Qenos are two of the major manufacturers that will be speaking, joined by leading associations and independent experts. The 2020 event also features a day dedicated to the opportunity that a hydrogen export industry could represent for the domestic gas industry. Many view hydrogen as Australia’s next big export, though there is still a huge amount of work to be done before this is a reality. The day – Hydrogen and Gas 2030 – is bringing together speakers who are actively investing in hydrogen already to talk about their feasibility projects, including Fortescue Metals Group, Origin, Stanwell, AGIG and Jemena. To find out more about the event visit www.adgoconfernece.com.au

OILANDGASTODAY.COM.AU / MARCH 2020 / 63

PRODUCTS

MSA GX2 AUTOMATED TEST SYSTEM GAS DETECTOR RSEA Safety has introduced an automated test stand suitable for ALTAIR 4X gas detectors. It provides simple and intelligent testing and calibration of MSA Altair and Altair Pro single-gas detectors, as well as Altair 4X and Altair 5X multigas detectors, driven by the most advanced technology available in any portable gas detector: MSA XCell Sensors. The easy-to-use automated test stand offers high performance as either a stand-alone unit or an integrated portable detector management system, enabling total data access and control of a MSA Altair gas detector fleet. The device also allows flexibility with up to 10 test stations, four-cylinder holders and multi-unit charger within one Galaxy GX2 system detector bank. rsea.com.au

BOLLE’S ULTRA-PANORAMIC 180 GOGGLES Bolle Safety has launched its new ultra-panoramic 180 goggle, a combination of safety and comfort thanks to a flexible bi-material ventilated frame. The goggles feature an indirect vent that uses covered vents to increase air flow, providing better protection from splashed liquids and dust. As well as improved air flow, this model features Bolle’s signature platinum coating on both sides of the lens, giving it high scratch resistance and delays fogging beyond the minimum required standards. Providing all-round vision, the 180 goggles also feature a wide, adjustable strap, are compatible with respirator marks and fit over prescription glasses. store.bolle.com.au

GRIPPS TETHERING STATION One of the main concerns when developing a safe working at height plan, is the impact to working efficiencies. Gripps has developed the Gripps Tethering Station (GTS). It combines the most valuable features for at height workers with a robust tool tethering system. Supported by a rigid backboard that prevents twisting or distortion, the GTS is great at organising tools. Dual general-purpose pouches are reinforced with innerstitched plating – perfect for battery tools. A range of stretchwebbing and canvas sheaths keep a full kit of hand-tools and heavy equipment organised and accessible. Fully load rated straps allow it to be hung directly off of rales, scaffolding or elevated work platform cages. The slimline design means it doesn’t take up any working area and takes tools off the floor. Constructed from an extra heavy duty, fire retardant 26-ounce canvas, the minimal/isolated use of metals and non-

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conductive tether anchors make the GTS-20T safe for work around live electricity. gripps.com.au

PRODUCTS

SPECIALISED TOOLBOX WITH DRAWER Bendtech has created many specialised toolboxes for jobs on sites that have specific tooling requirements. The toolboxes provide a lean and segregated approach to ensure that operators can confirm that they have all the tooling they need prior to performing a job and also, during the job. Each tool is clearly in view and easy to access, with specific signage and stickers available on request. The toolboxes are made to suit the particular set of tools for each job and Bendtech make sure it is certified and load rated to Australian standards. Each tool has a specifically CNC routed cutout and the toolbox has forklift slots to enable easy movement around

site, as well as the option for wheels to be added. Benchtech has ensured the toolbox is made from heavy-duty steel construction and has gas struts for the lid.

bendtechgroup.com

ALTURA’S VERSATILE ZENITH DRONE Ariealtronics has created the world’s most versatile commercial drone with the Altura Zenith. With up to 40 minutes flying time, high level redundancy and the largest payload range, the Altura Zenith sets a precedent for the design of unmanned aircraft systems. The drone has a combination of state-of-the-art technology with a remarkably flat, compact and lightweight carbon fibre design. With the company starting from scratch, it enabled the creation of a radically novel idea: developing a multirotor aircraft system that can meet a wide variety of application requirements without compromising on design. The drone can also fly up to 18km in distance, has 35-plus cameras and sensors and is capable of flying in high wind speeds. arieltronics.com

INNOVATIONSUITE SOFTWARE FactoryTalk InnovationSuite is a software collaboration between Rockwell Automation and PTC, designed to improve connectivity and functionality for the resources business. This product provides improved connectivity for operational technology devices on the site floor, improving day-to-day communications through data optimisation from a variety of different sources. This data, combined with information technology applications and systems, allows decision makers to gain a complete digital representation of their site. Data can be checked for anomalies and crossreferenced from different sites across the globe in order to aid decision-making. FactoryTalk InnovationSuite gives workers the ability to contextualise data, orchestrate processes and deliver powerful user experiences. The InnovationSuite incorporates FactoryTalk Analytics

and manufacturing operations management (MOM) platforms, as well as PTC’s ThingWorx Industrial Internet of Things platform, which includes industrial connectivity from Kepware, and the Vuforia augmented reality solution. rockwellautomation.com

OILANDGASTODAY.COM.AU / MARCH 2020 / 65

EVENTS

CONFERENCES, SEMINARS & WORKSHOPS AUSTRALASIAN OIL & GAS EXHIBITION & CONFERENCE, PERTH, MARCH 11-13 The Australasian Oil & Gas Exhibition & Conference (AOG) is a showcase of the latest products and services. Held at the Perth Convention and Exhibition Centre, AOG attracts more than 8000 global visitors. The event provides opportunities to network and to learn about the latest technological and innovative breakthroughs which will drive the industry into the future. The conference is a chance to explore specialised industry zones showcasing the latest in instrumentation control and automation, asset integrity, subsea, health, safety and environment, drilling and completion. aogexpo.com.au AUSTRALIAN DOMESTIC GAS OUTLOOK CONFERENCE, SYDNEY, MARCH 16-19 Each year, the Australian Domestic Gas Outlook (ADGO) conference brings together the whoâ&#x20AC;&#x2122;s who of the industry, for high-level discussions that will set out the future direction of the industry. Attendees will debate policy imperatives and discuss how commercial opportunities can be seized. The conference attracts leading gas producers, pipeline operators, retailers,

end-users, regulators and policy makers to have their say, and engage in the debate. Now in its eighth year, the event has built a loyal following within the industry and is well known for its high calibre of speakers and timely, relevant content. adgoconference.com.au MEGATRANS, MELBOURNE, APRIL 1-3 MEGATRANS returns in 2020 to facilitate cross-industry collaboration in a multidimensional and integrated conference and exhibition for the freight and logistics industry. For the first time, MEGATRANS2020 will take place in conjunction with the specialised bulk handling expo, Australian Bulk Handling Expo 2020. The two events will be held side-by-side, with one ticket entry into both. MEGATRANS2020 will showcase the latest in artificial intelligence, robotics, automated racking, telematics and route optimisation, warehouse automation, intelligent fleet systems, blockchain, IoT, big data and advanced analytics. megatrans.com.au

successes of companies across the logistics, supply chain and materials handling sectors. These awards are an opportunity for you to recognise and reward your operations, team, or individuals who are making a difference in the logistics industry. The Mercury Awards is the official awards program of MEGATRANS, a biennial business-to-business trade event focussing on the freight and logistics supply chain. mercuryawards.com.au APPEA 2020 CONFERENCE AND EXHIBITION, PERTH, MAY 18-21

MHD MERCURY AWARDS, MELBOURNE, APRIL 2

The APPEA Oil and Gas Conference and Exhibition is the largest annual upstream oil and gas event in the southern hemisphere, attracting delegates from across the country and around the world. Held at the Perth Convention and Exhibition Centre, the conference highlights and defines the issues and challenges of upstream petroleum exploration and development on a national and international level. The APPEA Conference program will include international keynote presentations, case study presentations, technical updates and panel discussions with the theme â&#x20AC;&#x201C; energy for a better Australia. appea.com.au

The Mercury Awards recognise the outstanding achievements and

WOMEN IN INDUSTRY AWARDS, MELBOURNE, AUGUST 13 The Women in Industry Awards is an event that acknowledges the exceptional women who have achieved success through their invaluable leadership, innovation and commitment to their sector. The annual awards recognise and reward the achievements of women working within the mining, oil and gas, engineering, manufacturing, process control industries and commercial road transport industries. They aim to raise the profile of women within each of these industries, as well as promote and encourage excellence. womeninindustry.com.au

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Subscribe to PPO Projects Founded in 1969, Pipeline, Plant and Offshore (PPO) has grown with the needs of the industry and evolved into a premium subscription emailed daily news service and an extensive project database.

The online PPO Projects database contains all proposed, under construction, and completed projects. It is also updated online in real-time so subscribers can search the latest developments with accuracy any time. The highly engaged subscribers include: asset owners, project proponents, sales and business development teams in the oil and gas industry. Subscribe at ppo.com.au/register/

GLOBAL OIL & GAS ASSET REMARKETING & VALUATION SPECIALISTS Pickles Oil & Gas division is the new resource for purchasing Oil and Gas equipment, connecting buyers globally to quality Offshore and Subsea assets. On behalf of industry leading clients, we have a wide range of Oil and Gas equipment and parts available for sale.

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