GAS Today / November 2011

Issue 18November 2011

• The magazine for Australia’s natural gas industry •

Keep on truckin’ with Micro-LNG

North West Shelf wrapped up

sneak peek

A shiftInterview with Reg Nelson

in energy

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2 GAS Today / November 2011 3GAS Today / November 2011

Great Southern Press Pty Ltd A.C.N. 005 716 825(A.B.N. 28 096 872 004)GPO Box 4967 Melbourne Vic 3001 AustraliaTel: +61 3 9248 5100Fax: +61 3 9602 [email protected]: Lyndsie MewettAssociate Editor: Lauren MolanAssistant Editor: Stephanie ChanJournalists: Katherine St Lawrence, Alex York, Candice De ChalainSales Manager: Tim ThompsonSenior Account Manager: David MarshSales Representative: Matthew LushCreative Director: Michelle CrossSenior Designer: Bianca BotterDesigners: Venysia Kurniawan, Ben Lazaro, Susie Monte Event Manager: Elissa DuckPublisher: Chris Bland ISSN: 1832-0562

GreatSouthern

Press

Issue 18November 2011

• the magazine for Australia’s natural gas industry •

Keep on truckin’ with Micro-lNG

North West Shelf wrapped up

sneak peek

A shiftInterview with Reg Nelson

in energy

November 2011/Issue 18Go to page 61

For the latest

The magazine for Australia's entire natural gas industry

Cover image: Beach Energy’s Holdfast-1 well in the Cooper Basin. Image courtesy of Peter Morris.

This magazine is available to interested parties throughout Australia and overseas. The magazine is also available by subscription. The publisher welcomes editorial contributions from interested parties, however, the publisher accepts no responsibility for the content of these contributions and the views contained therein are not necessarily those of the publisher. The publisher does not accept responsibility for any claims made by advertisers.

Unless explicitly stated otherwise in writing, by providing editorial material to Great Southern Press (GSP), including text and images you are providing permission for that material to be subsequently used by GSP, whole or in part, edited or unchanged, alone or in combination with other material in any publication or format in print or online or howsoever distributed, whether produced by GSP and its agents and associates or another party to whom GSP has provided permission.

Average Net Distribution 3,348 Period ending March 2011

3GAS Today / November 20112 GAS Today / November 2011

REGION REVIEW – SOuth AuStRAlIA

50 A new shift in the global energy scene: Australian shale (cover article)

54 SEA-ing gas through to SA

38 Keep on truckin’ with lNG44 North West Shelf: Australia’s lNG

capital48 Rough waters ahead for lNG

shipping industry: Wood Mackenzie

lNG

REGulARS

4 Editor’s comment64 Advertisers’ index, Subscription

request, Coming soon in future editions

NEWS

6 Gas today update10 Global gas wrap

EVENtS

61 CNC Project Management signs on for FutureGAS Gold

62 Engineers Australia expands oil and gas interest group

63 2011 AGIt Gas Speak a raving success

63 Calendar of events

COMPANy NEWS

12 GSP establishes new Gas Industry Marketing Solutions division

14 Innovative solution for gas main upgrade

16 Great Southern Press opens new office in China

18 ABMARC paints rosy future for CNG vehicles

COAl SEAM GAS

22 Challenges in CSG gathering system design

26 Generating solutions for CSG water treatment

PRODuCtS & EQuIPMENt

30 Boddingtons negates third-party intervention

34 Managing data across the asset lifecycle

36 Winning with Win united

tRANSMISSION

58 Epic gas transmission60 APlNG: creating a world-scale

industry in Queensland

CORPORAtE SOCIAl RESPONSIBIlIty

20 Gorgon gets it right: prioritising conservation and profit equally

GAS Today / November 20114

Welcome to the November edition of Gas Today.

In this edition we discuss the current hot topics of the industry – coal seam gas (CSG), LNG, and the emerging shale gas industry.

Associate Editor Lauren Molan conducts an insightful interview with Beach Energy Managing Director Reg Nelson, outlines Beach’s current shale gas activity, and the opportunities present in the Australian industry.

Mr Nelson candidly discusses why Beach has chosen to focus on shale gas opportunities rather than coal seam gas, and shares the company’s insight into pursuing shale in Australia. Turn to page 50 to read.

In our CSG feature, industry experts OSD Pipelines and Clark Energy provide articles on the important infrastructure required to develop CSG fields.

OSD’s Peter Lather discusses the logistics of designing a gathering system for CSG projects, while Clark Energy discusses their involvement in providing a water treatment facility to QGC’s Kenya CSG fields, located in Queensland.

Our LNG feature not only covers a comprehensive overview of LNG export projects on the North West Shelf, but also a feature article on the companies providing LNG domestically for transport. Turn to page 44 to read more.

Looking forward to February Here in the Gas Today office, we have

been busy making preparations for the upcoming fourth FutureGAS Conference and Exhibition.

The event promises to be the biggest yet, with a larger exhibition space, two-stream conference program, and many networking opportunities.

Last year the social program was a particular highlight, including the Opening Cocktails, Engineers at the Exhibition Drinks, the Women in Energy: Gas networking breakfast, and the annual Gala Dinner.

FutureGAS reflects the dynamism of the natural gas industry – always growing and evolving. Such an industry requires recognition, and so this year we will be holding the inaugural FutureGAS awards, sponsored by Jemena.

To be presented at the Gala Dinner, the awards will recognise companies and individuals in the industry, with the particular categories of:

• Gas Industry Innovation award • Gas Industry Skills Development

award • Person of the Year award. We are excited to provide this

opportunity for companies to nominate themselves and others for industry best practice in the above areas.

See the FutureGAS Registration Brochure inserted in this copy of the magazine for more details on the award categories and how to nominate, or online at www.futuregas.com.au

You can also follow developments in the program, find out more about the event and also register to take advantage of the earlybird rates at www.futuregas.com.au

I look forward to seeing you there.

Lyndsie MewettEditor

Editor’s comment

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We bring energy to its destination

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In the past 10 years Nacap Australia has constructed over 3,000km of pipelines in Australia including small diameter steel/HDPE gathering/fl owlines to larger diameter welded steel transmission pipelines across the water, mining and oil & gas sectors. Contract values range from $2M to in excess of $500M and all projects have been delivered on time without any contractual disputes / litigation.

You can rely upon Nacap, as we have the proven track record to deliver your project objectives. If you need to be sure, you need to have Nacap.

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6 GAS Today / November 2011GAS Today / November 20116

Can’t wait for the next edition of Gas Today?

Get the latest news at www.gastoday.com.au/news

NEWSFull steam ahead for Wheatstone

A final investment decision has been reached by Chevron Australia to approve the $A29 billion Wheatstone LNG Development, located offshore Western Australia.

Chevron has said that construction has now commenced on the project.

The foundation phase of the Wheatstone LNG Development consists of two LNG processing trains with a combined capacity of 8.9 million tonnes per annum (MMt/a), a domestic gas processing plant at Ashburton North, and associated offshore infrastructure including a processing platform, subsea equipment, drilling and an export trunkline.

The domestic gas processing plant will have a production equivalent to 15 per cent of LNG sales.

Domestic gas supply will increase over time to around 500 terajoules per day with completion of the planned 25 MMt/a LNG export project, that will expand beyond the initial two trains.

Wheatstone is a joint venture between Chevron, Apache, Kuwait Foreign Petroleum Exploration Company and Shell. First gas export is scheduled to 2016.

Clarke Energy on board for NSW gas-fired power generation Clarke Energy has been contracted by Dart Energy for the design, supply,

installation, commissioning and operations and maintenance services of small-to mid-scale gas-fired power generation projects, which will source gas from Dart Energy’s New South Wales CSG licence portfolio.

Dart Energy holds seven CSG licences in New South Wales, covering over 23,000 sq km, with an independently certified prospective gas resource of approximately 19 trillion cubic feet.

The agreement between Dart Energy and Clarke Energy is for an initial term of three years. Dart Energy is targeting first gas sales and initial cashflows from the proposed New South Wales projects by the end of 2013.

Syngas successful in generating power Carbon Energy has achieved an Australian first by generating electricity at its

power plant in Bloodwood Creek, Queensland, using syngas produced through the process of underground coal gasification.

Carbon Energy Managing Director Andrew Dash said that this achievement represents a major step forward for the company as it moves closer to its first revenue milestone – connection to Ergon Energy’s local electricity grid, expected in October 2011.

Work also continues to progress with the Queensland Department of Environment and Resource Management on amendments to the company’s existing environmental approvals to ramp up production to 5 megawatts. These approvals are being progressed in parallel to the connection of the power station to the local grid.

Illustration of the Wheatstone LNG Development.

An aerial view of one of Clarke Energy’s power stations.

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The Bloodwood Creek power plant.

8 GAS Today / November 2011GAS Today / November 20118

Can’t wait for the next edition of Gas Today?

Get the latest news at www.gastoday.com.au/news

Time machine predicts CSG’s effects on groundwater A new centrifuge machine at the University of New South Wales Water (UNSW)

Research Laboratory can act as an environmental ‘time machine’, allowing researchers to preview CSG’s long-term effects on groundwater aquifers.

Researchers can use the centrifuge to study the movement of water and contaminants through clay layers, called aquitards, which often surround aquifers. By subjecting core samples of aquitards and ‘cap rocks’ to centrifuge testing, researchers can determine how much water or contaminant will move into or out of an aquifer once it is disturbed by drilling or pumping bores.

UNSW Connected Waters Initiative (CWI) Research Centre Director Professor Ian Acworth said that centrifuge testing could be included in environmental assessment processes for CSG extraction and coal mining to give a clear indication of which aquifers were suitable for mining operations, and which were vulnerable to compromise of water reserves.

New CNG plant planned for NarrabriEastern Star Gas (ESG) and Clean Energy Gas Australia (CEGA)

have signed a Memorandum of Understanding to pursue a feasibility study into building a compressed natural gas (CNG) plant near Narrabri, New South Wales.

The feasibility study follows preliminary studies that concluded CNG was technically and commercially viable. Natural gas will be compressed at ESG’s Wilga Park site and transported via cylinders to customers.

ESG Managing Director David Casey said “Gas from ESG’s Narrabri Gas Project will be used to produce CNG that will be very competitively priced with existing fuels, such as imported LPG and diesel. This in itself will foster further growth opportunities, meaning more jobs and profitability for local businesses.”

While ESG will not be directly involved in the front-line retailing and distribution of CNG to the end customers, the company will supply CEGA with a reliable supply of locally-produced CNG.

The initial commercialisation phase could be developed in the first half of 2012, subject to the required approvals.

CSG water irrigation trial begins Santos intends to demonstrate how CSG operations can co-exist with farming

and enhance agricultural production through the introduction of an irrigation partnership with a private landholder as part of its Fairview Irrigation Project, located at the Fairview and Springwater power stations near Injune in South East Queensland.

The processing facility will be located at Mount Hope Station and supply 700 megalitres of treated CSG water over the initial four-year partnership. The CSG water will go through stringent treatment at a reverse osmosis plant. A process of sodium absorption ratio amendment to achieve the desired water quality.

Santos has said that it will look to replicate this pilot project with other farmers in the region.

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From left to right: UNSW research staff Dr Wendy Timms, David Garces and Gyanendra Regmi with the centrifuge machine.

ESG’s Narrabri CSG Project.

10 GAS Today / November 2011 11GAS Today / November 2011 11GAS Today / November 2011

Global gas wrap

liwan Gas Project sanctionedHusky Energy has sanctioned

the development of the Liwan 3-1 and Liuhua 34-2 fields, the principal fields of the Liwan Gas Project in the South China Sea. Husky and China National Offshore Oil Corporation are jointly developing the project, which has an expected capacity of 300 MMcf/d by 2014.

Nord Stream begins commissioning processesThe 1,244 km twin Nord Stream Pipelines, which will carry

gas from Russia to Germany, have commenced commissioning activities on Line 1. Following construction and pre-commissioning (including pressure testing, cleaning, drying and filling with Nitrogen) AG Nordstream began filling the line with buffer gas.

lula – Mexilhão pipeline begins operation Petrobras has commenced operation of the

Lula – Mexilhão Gas Pipeline, located in the Santos Basin, offshore Brazil. The 216 km, 18 inch diameter pipeline connects the Cidade Angra dos Reis platform in the Lula Gas Field to the Mexilhão Platform. It has an operating pressure of 250 bar and will transport up to 10 MMcm/d of gas produced by the Pre-Salt Region of the Santos Basin.

Mozambique lNG gets Indian investmentBharat Petroleum (BPCL) will invest approximately

$A424 million for its 10 per cent stake in a proposed LNG facility to be located in Mozambique. KBR and Technip will perform pre-front-end engineering and design work for the project, which will process natural gas from the region. Partners in the project joint venture are Anadarko Petroleum, ENH, Mitsui E&P, BPCL, Videocon Mozambique Rovuma, and Cove Energy.

New CNG station expands NGV networkEncana Natural Gas has opened a

compressed natural gas (CNG) station in southern Alberta, Canada. The station, located in Strathmore, approximately 40 km east of Calgary, will fuel Encana’s fleet of 39 natural gas-powered vehicles (NGVs). Beginning in 2012, the company expects to offer the Strathmore station’s fueling services to other corporate fleets in the area and to the public at a later date.

Gas bus tested in liverpoolStagecoach has launched a six-week trial in Liverpool,

United Kingdom, of a new hi-tech bus powered by compressed natural gas (CNG). The 12 m single-decker EcoCity bus has an engine that is quieter than traditional diesel-engined vehicles and also has significantly lower greenhouse gas emissions than standard buses. MAN Truck and Bus UK has already supplied more than 7,000 CNG buses that now operate throughout the world. Fleets of MAN buses are already running on biomethane in both Sweden and the Netherlands.

Exxon and Rosneft join forces in explorationRosneft and ExxonMobil have executed a

strategic co-operation agreement under which the companies will undertake joint exploration and development of hydrocarbon resources in Russia, the United States and other countries, and commence technology and expertise sharing activities. The agreement includes approximately $A3.4 billion to be spent funding exploration of East Prinovozemelskiy Blocks 1, 2 and 3 in the Kara Sea and the Tuapse License Block in the Black Sea, offshore Russia.

JGC orders heat exchangers for Barzan gas plantJGC Corporation has placed an $A13.6 million order

with Alfa Laval for the supply of heat exchangers to the Barzan onshore gas plant, to be located north of Doha, Qatar. The Barzan project – managed by RasGas Company, a joint venture between Qatar Petroleum and ExxonMobil – is planned to start commercial production in 2014, and produce 1.4 Bcf/d of gas, mainly for the local market. The heat exchangers will be used for recovering energy in the gas cleaning process and for process cooling of the overall gas plant.

12 GAS Today / November 2011

Great Southern Press’ (GSP) new Industry Marketing Solutions division, managed by Jacinta Hannaford,

provides customised marketing services to businesses in the gas industry to deliver integrated marketing communications that drive revenue and growth.

“I look forward to bringing together my marketing knowledge with GSP’s strong understanding of the industry so that we can create campaigns that solve natural gas businesses’ unique problems in a new and exciting way,” says Ms Hannaford.

“As marketing now seeks to be more seamless for the customer and moves toward tailored techniques such as content

marketing, the boundaries between publishers and marketers are becoming less defined.”

Content marketing is a marketing technique in which unique and compelling content is developed and delivered to customers in order to cut through the daily marketing clutter and deliver strong, targeted marketing results.

“With our unique expertise in marketing and industry affairs, GSP is in a great position to provide integrated marketing communication campaigns across a variety of platforms such as micro-sites, custom magazines and webinars,” says Ms Hannaford.

The United States is seeing a growth in publishers that offer marketing services to clients. The American Business Media has said that 20 per cent of its members are now engaged with developing marketing solutions for their clients. This is because publishers can offer specialist knowledge and insight that is often lacking in marketing and advertising agencies that spread themselves across many disciplines.

And the trend is now starting to reach Australian shores, with GSP leading the way.

Managing Director of GSP Chris Bland says “Extensive knowledge of the gas industry’s sales cycle, buyers’ behaviours, products and services, goes a long way toward creating marketing that delivers results. We have been working closely with the Australian gas industry for many years and it’s a natural progression for us to assist our clients, with our marketing skills and our industry expertise.”

For more information on Industry Marketing Solutions, email Jacinta Hannaford via [email protected] or call 03 9248 5100.

Great Southern Press is pleased to announce the creation of a new department to help gas industry businesses market themselves.

GSP establishes new Gas Industry Marketing Solutions division

Gas Industry Marketing Services include:• Audienceandmarket

research;• Strategicplanning;• Contentcreationand

copywriting;• Graphicdesign;• Leadgeneration;• Websiteandsocialmedia

audits;• Custompublishing;and,• Projectmanagement.

traditional marketingThisistheformofmarketingthatmanyaudiencesarefamiliarwithandissometimescalledofflinemarketing.Itincludesadvertising,directmail,telemarketinganddirectories.

Content marketingContentmarketingisthecreationofuniquecontentthatisrelevanttothetargetedaudienceanddesignedtoelicitareactionfromcurrentandprospectivebuyers,suchasleadgeneration,brandawarenessorcustomereducation.Examplesofcontentmarketingarebrandedmicro-sites,custompublicationsandwhitepapers.

The Great Southern Press Gas Industry Marketing Solutions team, Manager Jacinta Hannaford (second from right).

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The upgrade was completed on the existing gas main in Wakehurst Parkway between Frenchs Forest and North Narrabeen, in the northern region of Sydney. It involved

inserting a new 250 mm diameter polyethylene (PE) gas main into an 11 km section of existing steel gas main in the roadway and road reserve along Wakehurst Parkway.

Jemena adopted a partnership approach with Georg Fischer on this project. Georg Fischer not only supplied product to Jemena, it also provided extensive onsite training and support, as well as regular site visits and installation monitoring by its staff.

The project involved the use of SDR 9 PE100 pipe supplied by Georg Fischer, and included Georg Fischer Elgef and butt weld fittings, electrofusion welders and installation tools.

The project is the first PE gas job in Australia designed to continuously operate at 1,050 kilopascals for the entirety of its service life, and there are high expectations on the pipe, as this has never been accomplished before. Significant engineering work was required to enable the new PE 100 SDR 9 material to be used and to allow it to operate at this pressure.

Jemena says that construction work started in September 2010 and was completed before the end of March 2011 on time, on budget and with no lost time injuries.

Jemena, in partnership with Georg Fischer, has recently delivered on a key project as part of the Jemena Gas Network’s $A810 million major capital upgrade program for the upgrade of the gas main in Wakehurst Parkway in Sydney, New South Wales.

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Polyethylene pipe used for the Wakehurst Parkway project.

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Working closely with the sales team, you’ll be involved with cost estimation, tender preparation and submission while providing design, quotation and applications support in order to win new business. You’ll focus on inquiry and specification reviewing including solutions development, P&ID, equipment and functional specification development.

You’ll have a strong design background in the oil and gas industry with extensive experience in gas treating and processing, modular process plant and process separation.

Contact Ana Kljajic at [email protected] or 02 9249 2299.

Lead Mechanical Engineer Adelaide. Rapidly expanding their global operations, this reputable consultancy continuously delivers a diverse range of turnkey EPCM solutions to the oil and gas sector. A Lead Mechanical Engineer is now required to support this expansion, providing specialist expertise through the key design phase on a number of national projects. The application of your knowledge across rotating equipment and pressure vessels will be critical in delivering design solutions on complex projects whilst mentoring and providing direction to a highly skilled team.

Complimenting your technical competencies will be commercial acumen and a commitment to achieving advanced results. In turn you’ll be recognised in remuneration, stature and the opportunity to influence the direction of this local office.

Contact Heath Wickins at [email protected] or 08 7221 4141.

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The new office in China will be headed by Daisy Liu, who has worked with the company since

2009. Ms Liu’s knowledge of Chinese markets will help Great Southern Press (GSP) and Gas Today provide customised marketing solutions to promote gas companies from around the world.

“Assisting the gas industry market their products and services to China, and assisting Chinese companies promote themselves to the rest of the world is a really exciting proposition,” says Ms Liu.

“Bringing together GSP’s industry knowledge with my local knowledge – this is what will give us the edge over

other agencies and other marketing and development companies.”

Ms Liu will leverage her networks within China, and provide on-the-ground advice connecting Australian contacts with those in China.

The new Qingdao office complements GSP’s offices in Houston, London, Toronto and Melbourne.

Publisher of Gas Today, Great Southern Press, is pleased to announce the opening of a new office in Qingdao, China.

Great Southern Press opens new office in China

Daisy Liu can be contacted at [email protected]

GSP’s Daisy Liu.

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Only of Australian vehicles are capable of operating on CNG,

despite the fact that nearly half of Australian residential and commercial premises are

connected to natural gas.

0.02%

ABMARC has released a report forecasting the future uptake of compressed natural gas (CNG) use in light and commercial vehicles. The report provides insight into resource availability, Australian natural gas connection density mapped down to capital city level, local and international government policy review, and price forecasting—including projections of the alternative fuels excise and proposed carbon tax in July 2015, analysis of natural gas vehicle systems and operating characteristics, and a comprehensive calculator which allows users to determine the potential benefits of switching to CNG for their specific fleet. Some figures from the report are outlined below and opposite.

ABMARC paints rosy future for CNG vehicles

13 million

Governments in the European Union and United States are supporting the use of CNG in the transport industry, reducing their emissions by 61%

of all vehicles in Pakistan run on CNG.

Natural Gas Australia: An Automotive Perspective is available from ABMARC. Contact Natalie Roberts, Principal Engineering Consultant on 03 5964 8402,

mobile 0438 352 530 or email [email protected] for further information.

vehicles globally operate on natural gas, and this number is increasing at the rate of approximately 18%

per year.

20–25% when compared directly to the petrol engine it replaces.


Barrow Island, the site for the majority of activities and development associated with the Gorgon LNG Development,

is an internationally significant nature reserve. The Gorgon joint venture partners have recognised the importance of Barrow Island’s conservation, and have taken considered steps toward its preservation.

The scope of the projectThe Gorgon LNG Development involves

a network of offshore gas drilling and subsea gathering pipelines, and onshore processing plants.

Three 5 million tonne per annum (MMt/a) LNG trains, to be located on the central-east coast of Barrow Island, will process natural gas from offshore wells. Reservoir CO2 will be removed and re-injected into deep saline reservoirs beneath the island. LNG will then be shipped to international markets, while compressed domestic gas will be delivered via a 90 km long, 508 mm diameter subsea pipeline to the WA mainland, interconnecting with the Dampier to Bunbury Natural Gas Pipeline.

Joint venture partners are Chevron Australia as operator, ExxonMobil, Shell, Osaka Gas, Tokyo Gas and Chubu Electric Power Company.

Project construction began in December 2009, and first gas is due in 2014.

A smaller footprint Chevron has worked to minimise the

project’s footprint on the island itself. A conventional survey – consisting of

clearing paths to accommodate heavy trucks that haul necessary equipment – would have disturbed almost 3 square km of land. Instead, it was arranged for a freight helicopter to do most of the heavy lifting for the Gorgon project. Approximately 15,000 separate lifts were made, while lighter equipment was carried by foot. This resulted in the disturbance of an area less than 0.2 square km.

Greenhouse gas managementChevron says that the project is a

“world-class example of environmental management” proving that “conservation and development can successfully co-exist”.

Since 1988, Chevron has:• Replaced the offshore gas processing

platform with an all subsea development;

• Changed LNG process technology, including the CO2 removal medium, use

of a dry compressor and hydrocarbon pump seals, and recovering flash gas from the nitrogen removal column and re-using it as fuel gas;

• Improved waste heat recovery on the gas turbines resulting in a significant reduction in the use of supplementary boilers and heaters; and,

• Significantly reduced greenhouse gas emissions resulting from the injection and subsurface storage of reservoir CO2.

When completed, the CO2 storage project at Gorgon will be the first in Australia to reduce greenhouse gas emissions by the injection of CO2 into an underground reservoir.

The CO2 injection will be located on the central eastern coast of Barrow Island near the gas processing plant. The injection wells will be directionally drilled from discrete surface locations to minimise the area of land required for the well sites, surface facilities, pipelines and access roads. Monitoring wells will provide a sample point within the injection area.

Once the carbon dioxide is injected into the subsurface, it will continue to move through the host reservoir, driven by the

Not only is the Gorgon LNG Development, located offshore Western Australia, one of Australia’s largest natural gas projects – it has also come to represent industry best practice in environmental management. Gas Today takes a look at how the Gorgon joint venture partners have successfully mitigated the project’s impact on its surrounding environment.

Gorgon gets it right: prioritising conservation and profit equally

injection pressure and natural buoyancy until it becomes trapped.

Chevron has said that the proposed LNG facility on Barrow Island has the potential to be among the most greenhouse gas efficient of its kind in the world. Natural gas can help reduce net greenhouse gases worldwide by displacing other fossil fuels. Gorgon LNG sold globally will result in about 45 MMt/a less global greenhouse emissions, compared to the use of coal.

Biodiversity protectionBarrow Island is a Class A Nature

Reserve, therefore the Gorgon project required an extensive and thorough environmental protection plan. It is the world’s largest non-government quarantine initiative.

It’s estimated that Barrow Island is currently home for up to 60,000 golden bandicoots, 5,000 boodies, 10,000 speckled hare wallabies, and 10,000 possums.

Some of Barrow Island’s thriving mammal populations are being relocated on the mainland as part of a unique conservation and restoration program in partnership with the Department of Environment and Conservation.

For more than 40 years, it has also been home to a turtle rookery. Sea turtles nest on Barrow Island beaches between October and March each year – peaking in December and January.

Chevron has conducted baseline studies of sea turtles nesting in the area. This involves turtle tagging, counting sand tracks of nesting adults and emerging hatchlings and nest success data.

Sea turtles also are tracked on their migration paths via a fitted satellite-linked tracking device.

Each tagged turtle can be monitored by the public via an independent website specifically designed to track the migration of various sea turtles.

For more information about the Gorgon project visit www.chevronaustralia.com

An aerial view of the Gorgon LNG plant site at Barrow Island.

An artist’s impression of the completed Gorgon LNG Development.

Site works at Barrow Island.

21GAS Today / November 2011

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Coal seam gas (CSG) gathering systems are a large logistical component of CSG projects and during peak construction

many kilometres of pipelines will need to be constructed every day – placing stress on time management, budgets and resource management. Stepping back from the design is like stepping back and looking at spaghetti thrown against the wall. The individual lines that form the gathering system travel in their own directions and have their own individual features. Therefore there is no one formula or rule when planning a CSG gathering system. Each individual project requires a great deal of ingenuity in order to overcome new obstacles faced.

CSG gathering systems are a comparatively new technology and have not been formally addressed by way of an applicable Australian Standard (although the Australian Pipeline Industry Association has recently developed a CSG Code of Practice).

There is, however, another entity within the gas industry that shares the spaghetti analogy: distribution networks. Some of the challenges faced by those in gathering system design have already been dealt with from a network point of view, such as high-density polyethylene (HDPE) welding preferences, material property restrictions for design, trench arrangements to include other services like communications and power cables, and location class for burial depths.

Challenges unique to CSG gathering systems include dealing with significant volumes of CSG water and its associated treatment. The presence of large volumes of water creates problems in the gathering system design, as there is water in the gas and gas in the water, even after the process of separation. In order to combat this low point, drains need to be designed to siphon

the water out of the gas, and high-point vents need to be designed to extract the gas from the water. Neither of these tools are an ‘off-the-shelf’ item, and instead require custom fabrication. Working out where to install vents and low-point drains can be a bit of a dark art. For example, a good location to place one of these low-point drains is at the lowest point of a pipeline, which is often in the middle of a creek or stream making access difficult.

Another issue that often arises is whether compression is required at well heads or strategic points to keep the gas and water products moving through the gathering system. In order to achieve this engineers are required to install electrical and communication cables in the gathering system for monitoring purposes. These cables have different installation requirements to plastic gas and water pipe, and the gathering system can bear some resemblance to what you may find under an urban footpath.

Challenges in CSG gathering system design

By Peter Lather, Pipeline Engineer, OSD Pipelines

With the boom of the coal seam gas industry many project managers, engineers and designers are continually presented with obstacles regarding pipeline gathering system design.

Continued on page 24 >

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HDPE pipe also presents new kinds of obstacles for this type of project. HDPE has wear properties that need to be considered when solids or chemicals form part of the product within. The life of HDPE is also affected by fluid temperatures above 25°C. Therefore the design life of the gathering system may have to be designed around the expected productive period of a well.

Plastic pipe may present some cost benefits by being cheaper and easier to install, when compared to steel, with some sizes delivered in spools and some installed by ploughing-in the pipe. However the jointing of pipes and fittings in these instances can be difficult. Preferences to either butt welding or using electro-fusion fittings needs to be determined Unlike steel, neither method can be non-destructively tested by x-ray. So the pressure test forms an important part of the construction, and this process needs to be considered in the gathering system design so that pipeline construction does not inhibit access for land owners or locals.

Even if the original concept or front-end engineering and design of the gathering system appears to be prudent and avoids

encroachment on residences, industries and farming activities, the design can only be finalised after the pipeline route is walked and inspected manually for flora, fauna and cultural heritage. A majority of national parks, state forests and wildlife corridors are well defined, however cultural heritage is difficult to see from aerial photography, a method most commonly used to design large-scale projects. If an area of cultural heritage, endangered wildlife or vegetation is discovered, then the system design has to be redesigned to avoid this area and reduce the impact. Redoing the design is often a simple enough task, but the modelling of the flowlines consequently need to be rechecked as well as changes to elevation, pipe wall thickness or pressure rating. In addition, placement of features like vents, drains and valves will need to be considered and at times moved to correspond with other changes.

The design of gathering systems is vastly different to that of high-pressure steel transmission pipelines. In fact, designing one steel pipeline can be considered easier than designing a CSG gathering system

as there are fewer variables to consider during design. While both may be an iterative process to a degree, retrospective changes to CSG gathering systems present further problems and will consume more design time and resources.

A final problem to consider, is obtaining staff that are familiar with this type of construction, techniques used, material and product properties, and have a good understanding of the process requirements.

Peter Lather was a recent participant and award

recipient at the Australian Gas Industry Trust’s 2011

Gas Speak Colloquium held at Parliament House.

For more information about the event turn to page 63.

For more information about OSD Pipelines go to

www.osdpipelines.com

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GE Power and Water is supplying its technology solutions to GELOR – a consortium of GE Betz and

Laing O’Rourke Construction – which is constructing a water treatment plant at QGC’s Kenya production site near Chinchilla, Queensland. The water treatment facility will have the capacity to treat up to 100 million litres per day (MML/d) to be used on farms, in industry and as town supply, and will integrate the CSG-fuelled Waukesha and Jenbacher gas engines for the first time.

The engines — which have been delivered to the site by Clarke Energy, GE’s exclusive gas engine distributor in Australia — will generate reliable, onsite

power for GE’s membrane and thermal water treatment technologies, which will, in turn, desalinate water produced during the extraction of CSG.

According to GE, Queensland is Australia’s focal point of CSG extraction,

GE Power and Water business is supplying an integrated solution of critical, onsite power generation and water filtration equipment to an energy consortium building a water treatment plant on behalf of QGC.

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Gas Today Nov 2011.indd 1 9/30/2011 8:52:05 AM


Gas to Energy Solutions Talk to the Experts

Clarke Energy, the largest worldwide distributor of GE Jenbacher gas engines, has installed over 220 MWe of generation capacity fuelled by coal seam gas. These plants all feature low operating costs and high availabilities proven under demanding Australian conditions. Islanded or grid connected coal seam gas fuelled power stations are well suited for powering upstream facilities such as associated water treatment plants, water gathering stations, and compressor stations. Ask our sales team how to achieve the optimum solution for your power generation project.

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accounting for more than 90 per cent of the country’s annual CSG production as the industry looks to expand from being a regional distributed energy supplier into a significant, global source of LNG. The company adds that using CSG to generate electricity instead of coal can reduce greenhouse emissions by up to 70 per cent.

To ensure QGC has reliable onsite power for its water treatment at its Kenya facility, GE is supplying the GELOR consortium with:• Three of GE’s Waukesha 12 volt

275GL+ mechanical drive engines, which are efficient, powerful, fuel-flexible engines that will power vapour compressors used to help treat brine water at the site

• Seven of GE’s 3.3 megawatt (MW) J620 Jenbacher gas engines. These will generate approximately 23.1 MW to support QGC’s Kenya water treatment plant, which will recycle wastewater created during the gas production process.

“As Australia’s growing CSG industry works to become a global supplier of

LNG, QGC’s Kenya project illustrates how GE Energy’s integrated portfolio offers customers a one-stop solution to meet their critical onsite power and water treatment technology needs and ensure that projects comply with various environmental regulations governing the CSG industry,” says GE Power and Water

Chief Executive Officer and President – Gas Engines Rafael Santana. “QGC’s Kenya project marks the first time that we are jointly deploying our Waukesha and Jenbacher gas engines for an onsite power project.”

The plant is expected to begin commercial operation in 2012.

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Queensland, and construction of an LNG plant on Curtis Island off Gladstone to expand production of CSG in the Surat Basin

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Buried pipelines can be subject to disruption from third parties unaware of the pipeline’s location, resulting in fatal and costly accidents. Gas Today speaks with protective mesh and safety tape provider Boddingtons about the methods that can be used to avoid dangerous intervention of pipelines by external parties.

Why is third-party intervention a big issue for owners and operators of pipelines?

Interference by a third party operating a backhoe or digging equipment can cause damage to nearby pipelines. This is a major risk, particularly when this damage occurs in a populated area where a gas leak can be very dangerous if there is a risk of explosion. In addition to human risk, there is also potential economic risk to the operators’ key asset – the pipeline. The commercial loss caused by the shutdown of damaged pipelines is not good news for the operator’s shareholders.

What kinds of innovations have we seen in detector technology over time? And how do these technologies work with Boddingtons’ products?

There are a number of different detection devices on the market. The features and benefits are varied depending on the model that is purchased. In recent years the manufacturers of these detection devices have produced equipment that provides exact depth measurements of buried pipeline detection tape or mesh.

In addition, through radio frequency transmission, locators are able to

detect the exact location and type of different cable or pipeline services that are buried together.

Boddingtons negates third-party intervention

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How can operators use Boddingtons’ products for best results, or to minimise third-party intervention?

We recommend that WAVELAY® and DETECTAMESH® are used for all underground pipeline and cable services for peace of mind. The cost per metre is minimal compared to the risk to the pipeline owner or operator if a third party damages their pipeline. Used in conjunction with above-ground marker posts, they provide the maximum warning to a third party who is digging near the pipeline.

In addition to these products, Boddingtons has a range of heavy-duty extruded mesh products for additional protection of underground pipelines.

PROTECTAMESHTM is a lighter and cheaper alternative to the traditional concrete or heavy plastic covers laid over underground pipelines. The product has excellent impact-resistant properties and because it is light, is easy to transport and install at site.

ROCKSHIELDTM is used for wrapping around coated steel pipelines to protect the coating systems and field joints.

The ROCKSHIELD® product provides added protection to the coated surface of the pipe, particularly where the pipe is being buried in rocky soils where scratches to the surface could lead to corrosion to the steel surface.

What specific features of WAVELAY® and DETECTAMESH® help to decrease the risk of third-party intervention?

The gas industry has traditionally used a plastic underground marker tape or mesh laid in the trench above the pipeline with a thin copper wire buried beside it. The copper wire is then subject to corrosion, particularly where the soil has acidic characteristics.

The WAVELAY® and DETECTAMESH®

products from Boddingtons are manufactured from a virgin ‘non-rotable’ polyethylene with a stainless steel Grade 316 tracer wire embedded within the product. Our products are an all-in-one solution, which saves time in terms of installation, and provides peace of mind that the plastic – and more particularly the tracer wire – will last for a long time.

In addition, WAVELAY® and DETECTAMESH® can both be found quickly and easily using a handheld electronic location or detection device. The products also act as a warning to a third party who is digging near the underground gas pipeline. As WAVELAY® and DETECTAMESH® are laid approximately 300 mm above the actual pipeline, the person digging will strike or hook into the product before they hit the pipeline. The product is brightly coloured and has a specific warning message printed on it.

Using WAVELAY® or DETECTAMESH® provides the pipeline operator or owner with an all-in-one product that acts as a warning in the case of third-party intervention, as well as enabling easy location with a simple above-ground detection device.

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Construction simulationAccording to Bentley Systems Global Oil

and Gas Solutions Executive, John Sanins, owners need to be able to construct a suitable gas processing plant quickly and with low risk to reflect growing market demand and to stay ahead of competition when bringing a product to market.

“When an owner has identified the market demand and acquired the raw materials for a gas processing plant, a crucial business imperative is to develop and bring the new asset online as soon as possible. In the case of LNG facilities, this means they can address the market more quickly and begin production earlier, resulting in earlier profits,” says Mr Sanins.

“Once production has begun, one of the owner’s main imperatives is then to maintain the capacity, utilisation and availability of the operating plant. Thus, the owner’s two main time constraints are the time it takes to design, build and start up the new facility (time to market), and the time that they are able to maintain the facility’s operational availability and output capacity (time in market).”

Through its virtual construction planning and simulation software, ConstructSim, Bentley has developed a way for owner-operators to monitor the progress of construction by simulating the plant construction process and ultimately validate plant start-up by recognising the importance of a project’s time to market and time in market.

The new technology compiles data from external software applications as well as from the internal organisation to create a virtual construction model. The software is then used for construction status visualisation, work package planning and overall construction status planning, and linked to monitor delivery of all materials and associated plant items needed to construct the plant.

In addition to being able to plan the construction phases, ConstructSim is also

able to manage all the resources linked to construction including material procurement processes, project employees, localised craft cost rates and associated construction resources, such as scaffolding and cranes.

“ConstructSim helps the individual construction craft teams work together more effectively,” says Mr Sanins. “Traditionally, all these activities would be managed on paper. ConstructSim is the first technology to support this kind of management in a digital environment.”

Further to being able to assist in the planning of project construction, ConstructSim is also able to assist with project management after construction is completed during system turn-over and the mechanical completion phases moving into pre-commissioning.

“Successful construction of a project relies on three things: accuracy of materials and associated procurement information, a good construction planning system, and the complete handover of project data leading into the commissioning phase,” explains Mr Sanins. “The interrelationship between these systems – the so-called ‘procurement/construction/commissioning

triad’ – provides a more integrated approach during construction compared to current or historical methods.

“ConstructSim is able to facilitate this approach as it can then exchange associated project information with third-party commissioning systems or internal enterprise-based systems being used by an operator or commissioning team.”

A multidisciplinary approach to construction

Mr Sanins says that today’s gas processing plants are much larger and more complex than in the past.

“Operators are trying to maximise efficient operations through economies of scale; larger processing plants mean more production. The challenge with this is that larger facilities required for multiple LNG trains, bring with them much larger volumes of engineering and associated data. This information must still be managed and be accessible compared with smaller plants built in the past,” says Mr Sanins.

The scale of modern ‘mega projects’ and the number of contractors, vendors and

As more and more gas discoveries are made in Australia, and as the scale of gas projects becomes progressively larger, appropriate management of project data and documentation has become a critical factor in the successful delivery of a project. Gas Today speaks with Bentley Systems Global Oil and Gas Solutions Executive, John Sanins, to find out more.

Managing data across the asset lifecycle

ConstructSim compiles project data from various sources to simulate the plant construction process.

suppliers involved in a project means that there is a need to share all project-related data in a more open, federated way in what Bentley refers to as a ‘federated information workflow’ (FIW).

Mr Sanins explains, “In the mid-1980s, digital infrastructure used to support capital projects could be characterised as being monolithic and task-driven. It was localised to individual offices – even work groups – which was not a sustainable data management environment for today’s more complex projects. In contrast, today’s digital infrastructure is more process-driven as there are so many more people involved in these mega projects. FIW broadens accessibility to all project information in a more open, federated way. This allows for information to be distributed more widely. As the system builds and grows, it creates a more sustainable, collaborative environment.

“To illustrate these points, engineering software used during the 1980s was developed on closed, usually proprietary databases or file systems resulting in large, monolithic systems specific to an individual software vendor. These early systems usually imposed fixed work processes in the way engineers could use the software to undertake specific engineering tasks. As a result, these systems were dictatorial in how to use specific software used by specific engineering disciplines or groups with limited interaction or data exchange. Clearly, the resulting digital infrastructure, whilst offering tools to support discrete engineering functions, did not address the need to provide and share data in a more controlled environment across a broader user community.

“In contrast, today’s engineering, analysis and information management systems support a more open, federated approach to creating, sharing, using , ‘consuming’ and managing evolving engineering information better suited to the increased number of people and organisations involved. Through better data and applications via the use of industry data standards such as ISO 15926, the resulting digital infrastructure is more process-driven, reflecting a more democratic way to distribute and use engineering data during all phases of the lifecycle. As projects grow

larger, this federated approach simply adapts and expands thus offering a more sustained environment to support projects both today and in the future.

“In practical terms, FIW, by implication, supports a broader geographically distributed workforce, providing a more open, collaborative network environment that allows different information to go to different stakeholders in different formats,” adds Mr Sanins.

Bentley Systems in practiceBentley’s software has already assisted

in the successful delivery of a number of major Australian and regional gas projects, including the North Rankin 2 Project in Western Australia.

Bentley’s ProjectWise software is a project information management environment, which is used by the engineering, procurement and construction contractor during the early stages of conceptual, front-end engineering and detailed design to manage project data as it matures through the detailed design phase. The environment supports collaborative ‘work-in progress’ workflows to ensure the latest released data is available to all project participants.

The North Rankin Redevelopment Project recovers low-pressure gas from the North Rankin and Perseus gas fields located

offshore near the town of Karratha, Western Australia. The project involved installation of a second platform – North Rankin B (NRB) – with gas compression facilities, low-pressure separators, utilities and accommodation.

The Eos joint venture — a 50/50 joint venture between KBR and WorleyParons — was contracted for the front-end engineering and design, detailed design, and procurement management for the NRB integrated deck float-over topsides and substructure. To better co-ordinate information across the many parties and to improve handover of information into operations, an information management strategy was put in place that called for a single integrated information set throughout the asset’s lifecycle. Bentley’s ProjectWise data warehouse served as the central asset register for the whole NRB facility.

Mr Sanins says “The resulting benefits were considerable, with the real-time information and other project tools being made available on the project dashboard/portal, allowing enhanced decision-making.”

An extended version of this article is available online.

To read more visit www.gastoday.com.au

Bentley addresses twelve specific solutions for gas infrastructure. For more information visit www.bentley.com

A schematic of the North Rankin Redevelopment Project, which used Bentley’s ProjectWise software.


Family-owned company Win United specialises in the supply and delivery of industrial hose and fittings. The company has grown rapidly and is now the preferred supplier for many civil construction, industry and drilling companies, mines and government utilities across Australia.

Win United imports, sources ormanufactures products in bulk and sells them directly, without

distributors. The Win United Australian rubber hose manufacturing plant allows the company to manufacture hoses in sizes ranging up to 560 mm. Win United can also design and construct hoses for a diverse range of applications, with a complete range of fittings and materials such as stainless steel, titanium and brass.

Win United is an industry specialist in large tender works. The company’s fully-qualified engineers can produce solutions

from plans and specifications provided, and offer a complete solution that is compliant with Australian Standards and regulations.

Win United provides up-to-date pricing and specification information on its range of products in its bi-annual catalogue. All orders placed before midday are dispatched that day when in stock at the Sydney, Melbourne or Brisbane warehouses. Australian-wide express delivery services also ensure products arrive on time at remote destinations.

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Trucking LNG through TasmaniaIn March 2006, a group of forest

industry transport operators approached the Launceston office of the Tasmanian Department of Economic Development, seeking advice on using natural gas for heavy vehicles.

The idea behind using natural gas to fuel their trucks was to provide them with some security against rising diesel prices.

Over the next few months, an alternative fuels consultancy had assessed the feasibility of using natural gas for heavy vehicle operation and a project concept was formalised, with an application made to the Commonwealth Government for funding assistance under the Tasmanian Forest Industry Development Program.

Tasmanian forestry trucks complete the highest number of miles on average and carry the heaviest loads of any trucks in Tasmania, resulting in heavy fuel use and emissions. There are 1,500 prime movers in Tasmania, all of which cover 200,000 km per year as opposed to delivery or refrigerated trucks that cover 50–60,000 km per year.

By September 2006, the group of transport operators had registered a new company — LNG Refuellers — establishing the first

commercial pipeline-to-truck supply of LNG for heavy vehicle transport in Australia.

The consortium is comprised of: • KJ Padgett and Co;• Chas Kelly Transport;• Kevin Morgan;• Aprin Transport;• Exeter Sawmill;• Les Walkden Enterprises; and,• Country Roadways.

LNG Refuellers Chief Executive Officer Alvaro Ascui says that using LNG as an alternative to other fuels has a number of benefits.

Mr Ascui explains that natural gas vehicles typically deliver lower greenhouse gases than conventional vehicles, with the more sophisticated gas engines able to deliver emissions savings of up to 20 per cent. The Westport GX engine is the only engine that is able to generate carbon credits that are tradeable under the voluntary trading scheme. Nineteen of these trucks exist in Tasmania today.

Despite the lower energy content of LNG when compared to diesel (1.65 litres of LNG is required to substitute 1 litre of diesel), the lower price of LNG means it delivers annual fuel savings of approximately 30 per cent.

Another major benefit for micro-LNG users is that it reduces noise pollution, as engines run quietly.

The price of natural gas in Australia is largely regulated by the Australian Energy Market Operator and the Economic Regulation Authority in WA, and has been historically stable relative to volatile diesel prices.

In mid-August 2008, a deal was finalised between LNG Refuellers and BOC for the supply of LNG fuel for over 120 natural gas vehicles. This was achieved through the construction and operation of Australia’s first micro-LNG plant at Westbury, Tasmania, as well as the supply of five refuelling stations, which are located at Westbury, Launceston, Burnie, Scottsdale, and Bridgewater.

Mr Ascui says that greater investment in re-fuelling infrastructure will see the use of LNG as a transport fuel rise.

Ensuring security of energy supply with LNG

BOC began producing LNG at its CryoCentre in Dandenong over 50 years ago, and continues be a leader in developing new economical low-emissions fuel alternative technology for the trucking and other sectors.

It officially opened its first micro-LNG plant at Westbury in February 2011. The plant has the capacity to produce 50 tonnes per day (t/d) of LNG – the equivalent of 70,000 litres of conventional diesel.

The Westbury plant is seen as a forerunner to similar technology the company hopes to roll out on the mainland in a long-term commitment to supporting the domestic gas industry and reducing greenhouse emissions.

Other significant LNG projects being undertaken by BOC include an extension to its Victorian CryoCentre and the intention to supply micro-LNG to industry in Queensland’s Surat Basin, through a contract with Australian CSG explorer and producer QGC.

Natural gas is recognised as a clean-burning fuel to bridge the gap between coal-fired power generation and renewable energy. Here, Gas Today looks at three companies which have explored and implemented ways of using LNG domestically as a transport fuel to lower operational emissions.

Keep on truckin’ with LNGBy Stephanie Chan

Tankers at KIeenheat’s LNG plant at Kwinana, Western Australia. Continued on page 40 >

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The company is also working to develop ‘an LNG highway’ to refuel transport fleets along the east coast of Australia. The planned LNG fleet refuelling network will include transport company depot refuellers located at the transport company yard, and public refuellers located at selected truck-focused service stations and roadhouses around Australia.

Alongside these heavy vehicle fleet fuelling activities, BOC will also focus on marine, locomotive and mining vehicle refuelling applications.

BOC Strategic Marketing Director Bruce Currie says that because LNG is a

locally-produced, Australian ‘indigenous fuel’, it is therefore not exposed to international crude oil prices, or lack of availability caused by European demand cycles or fluctuations in the Australian dollar relative to other currencies. As a result, BOC – and its subsidiary company ELGAS – is able to give customers a higher degree of operating cost certainty, compared to imported LPG or diesel.

However, distributing LNG has a large operating cost associated with it.

“Micro-LNG would be beneficial for companies with existing access to natural gas or who are positioned close to an area where a plant can be placed, as this would ensure

a reliable and secure supply of energy,” says Mr Currie.

With regard to the future of micro-LNG, Mr Currie says “As the world grows more and more environmentally aware, LNG — the cleanest burning fossil fuel available — will play an increasingly important role in delivering an economical low-emissions fuel alternative.”

Exploring the potential of LNGWesfarmers’ Kleenheat Gas, through its

brand EVOL LNG, is also exploring the vast potential of LNG for the domestic market. EVOL LNG currently supplies LNG and supporting refuelling facilities to more than 200 trucks in WA and Victoria, with plans to expand into New South Wales, Queensland and South Australia.

Kleenheat Business Manager – LNG Nick Rea says that the company has spent many years testing and developing LNG as a cleaner and more economical energy alternative to diesel for a range of industry applications.

“Various engine systems were trialled and developed in co-operation with the Commonwealth Government and the engine manufacturers over a period of a few years,” says Mr Rea.

When asked why LNG’s properties are well suited to being used as a domestic fuel, Mr Rea explains, “Firstly, LNG has the lowest carbon content of all fossil fuels with the potential to really reduce a user’s carbon footprint. As a cryogenic liquid, LNG vaporises very quickly into natural gas if ever it comes into contact with ambient air. Natural gas is lighter than air so it dissipates rather than accumulating in drains and pits as can happen with LPG. It also has the highest auto ignition temperature of all the hydrocarbon fuels, making it inherently safer as well.”

LNG Refuellers CEO Alvaro Ascui. Image courtesy of Peter Havery.



Mr Rea says that the possibilities for micro-LNG to be used in the heavy vehicle and industrial markets are very real and very exciting, and added that micro-LNG can be used for remote power generation as well.

“LNG is trucked to site by cryogenic tankers and stored in large vacuum-insulated tanks which provide a few days of supply,” Mr Rea explains. “The LNG is returned to gas using ambient air vaporisers and supplied to the power station as natural gas.”

In 2008, Kleenheat invested in the construction of an $A140 million integrated project in WA that included a 175 t/d LNG plant at Kwinana, south of Perth. In addition, the company supplies two LNG-fuelled power stations and a growing network of LNG refuelling facilities around the country.

Kleenheat integrated gas processing for the new LNG plant with the existing liquid petroleum gas (LPG) extraction plant established in 1988 at Kwinana.

“The capital and operating costs of the new LNG facility were significantly reduced by leveraging off the existing facilities in the LPG plant,” says Mr Rea. “This included control room, hot oil, low LPG feed gas, gas pipeline

connections, utilities – including flare, air, nitrogen, water and refrigerant.”

Mr Rea points to the US as an example of how micro-LNG has been embraced as a transport fuel: “Take the Chesapeake Energy Corporation, for example, which announced in July 2011 that it will invest $US150 million in 150 truck refuelling stations across the US.”

This interest is reflected locally by the thousands of natural gas buses operating in Australia’s public transport fleets – Sydney, Brisbane, Adelaide, Perth and Canberra in particular.

“Testing of an ADR80/03 15-Litre 550 HP Westport gas engine showed it produced 25–30 per cent less greenhouse gas emissions than the equivalent diesel engine,” says Mr Rea. “This engine is available factory-fitted by Kenworth. There are several aftermarket conversions available today, although numerous other original equipment manufacturers are investigating their own LNG-powered trucks.”

EVOL LNG will soon be distributing American Power Group’s (APG’s) new aftermarket dual-fuel conversion for heavy-duty

vehicles, having recently entered into an exclusive agreement with APG.

While the micro-LNG industry is certainly attracting interest, Mr Rea says its further development will not be without its challenges. “There are many challenges from the production and distribution of LNG right through to the marketing and conversion of customers,” says Mr Rea. “The challenge is to understand these issues and allow for them all. It has taken EVOL LNG many years of trial and error to accumulate its knowledge.”

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addition to a domestic gas facility for the WA market.

The Woodside-operated project is underpinned by 15-year sales agreements with Kansai Electric and Tokyo Gas for up to 3.75 MMt/a of LNG, and an agreement with Petronas for the delivery of up to 19 cargoes of LNG through to 2014. Kansai Electric and Tokyo Gas became project participants in January 2008, each acquiring a 5 per cent interest in the foundation project.

Gorgon LNG DevelopmentThe Chevron-operated Gorgon LNG

Development also presides in the NWS, and is one of the world’s largest natural gas projects and the largest single-resource project in Australia’s history.

The Gorgon LNG Development is based on the installation of a subsea gathering system and pipelines from the Gorgon and Jansz fields to Barrow Island. Three 5 MMt/a LNG trains to be located on the central-east coast of Barrow Island will process the gas. Reservoir CO2 will be removed and reinjected into deep saline reservoirs beneath the island. LNG will then be shipped to international markets, while compressed domestic

gas would be delivered via a 90 km long, 508 mm diameter subsea pipeline to the WA mainland, interconnecting with the Dampier to Bunbury Natural Gas Pipeline (DBNGP).

Construction began in December 2009, and first gas is due in 2014. More than 9 MMt/a of output LNG has been contracted to a number of Asian customers.

Western Australian Premier Colin Barnett has suggested that the state could become the world’s

largest producer of LNG within ten years. The Federal Government has more conservative projections, setting Australia at number two behind Qatar.

However, despite weather delays, the threat of reduced foreign investment, and impending tax reform, natural gas activity at the North West Shelf (NWS) continues to flourish.

North West Shelf Gas ProjectArguably the most significant gas

project in the area is the Woodside Petroleum-operated NWS Gas Project, which involves both a domestic gas facility and LNG for export terminal.

Representing an investment of $A27 billion, the NWS project facilities constitute Australia’s largest oil and gas resource development and currently account for more than 40 per cent of Australia’s oil and gas production. Since 1989, the project has shipped more than 3,000 LNG cargoes to international markets.

In 2008, the NWS joint venture partners reached a final investment decision on

the North Rankin 2 Project, including the construction of the 23,600 tonne North Rankin B Platform and refurbishment of North Rankin A. Upon completion, both platforms will be operated as a single integrated facility. This project is expected to extend the field life of the North Rankin and Perseus gas fields to approximately 2040.

The $A5 billion project is expected to be completed and operational in 2013. At the time of writing, the project is facing delays due to slower than expected progress on topside fabrication. The project is now 69 per cent complete and remains on budget.

Woodside has begun the environmental approvals process for the development of 14 gas fields in the Greater Western Flank area of the NWS, located west of Goodwyn, Western Australia, and positioned as an expansion of the NWS Gas Project.

Planning has begun for the Greater Western Flank development including a five-well subsea development, GWF-1, that will tap the Goodwyn H and Tidepole natural gas fields, which will be tied back through a 16 km pipeline to the existing Goodwyn A production platform.

Goodwyn A has a capacity of approximately 3 trillion cubic feet (Tcf) of gas and approximately 100 million barrels (MMbbl) of condensate.

Pluto Gas ProjectWoodside Petroleum’s Pluto Gas

Project is, at the time of writing, very close to completion. The project began commissioning in March 2011, and first gas is expected in the second half of 2011.

The initial project phase involves a single LNG production train at the Burrup LNG Park with forecast production of 4.3 million tonnes per annum (MMt/a) of LNG. The train is connected via a 180 km, 914 diameter mm offshore pipeline to a platform in 85 m of water, which in turn will be connected to five subsea big bore wells on the Pluto field. A second and third LNG train, producing by 2014, are expected to be added, in

The Australian economy has managed to survive the global financial crisis with far less damage than many Western countries, largely due to what has been labelled a ‘resources boom’. The North West Shelf houses two of Australia’s largest LNG developments contributing in no small part to what many believe will be a golden age of gas.

North West Shelf: Australia’s LNG capital

North West Shelf Gas ProjectNo. of trains: 5Capacity: 16.3 MMt/aTotal pipeline length: 420.4 kmPipeline diameter: 305-1,066 mmContractors: Advanced Geochemicals (SSIV and spools uplift analysis; installation frame review), Fortress Systems (valve interlocking), Clough (construction), ETPM (construction), Stena (construction). Participating interests: BHP Billiton Petroleum, BP Developments, Chevron Australia, Japan Australia LNG, Shell Development Australia, Woodside Energy.

LNG tanker at the North West Shelf Gas Project’s Karratha gas plant loading terminal.

Woodside’s platform at the Pluto Development.


Pluto Gas ProjectNo. of trains: 1Capacity: 4.3 MMt/aPipeline length: 180 kmPipeline diameter: 914 mmContractors: Foster Wheeler and WorleyParsons (front-end engineering and design (FEED)-onshore), Eos joint venture (FEED-offshore). Participating interests: Kansai Electric (5 per cent) and Tokyo Gas (5 per cent).

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Wheatstone LNG DevelopmentChevron Australia’s other major project

in the area is the Wheatstone LNG Development. A couple of years behind the schedule of Gorgon, first gas from Wheatstone is expected in 2016.

Chevron has proposed a two-train, 8.6 MMt/a LNG project, to be located at Ashburton North on the Pilbara Coast. Approval is also being sought for an additional three trains that would extend the project’s capacity to 25 MMt/a. Gas for the project would be sourced from the company’s Wheatstone and Iago gas fields, located 145 km off the Pilbara coast, in water depths of approximately 200 m, as well as from joint venture partners Apache Corporation and Kuwait Foreign Petroleum Exploration Company’s Brunello and Julimar fields.

LNG offtake contracts have been signed with Kyushu Electric Power Company, Tokyo Electric Power Company and Korea Gas Company.

Scarborough Gas FieldMore recently announced was the

development of the Scarborough Gas Field into an LNG project. An equal joint venture between ExxonMobil subsidiary Esso Australia as operator, and BHP Billiton, the Scarborough field is estimated to contain around 8–10 Tcf of gas. The field is located approximately 285 km offshore from the Pilbara town of Onslow in 900 m of water.

BHP has said that a number of options to commercialise the field are being considered, including the construction of an offshore LNG facility, a standalone facility at Onslow, or the possibility of working with other projects such as Wheatstone or Pluto.

WA Premier Colin Barnett has suggested that the Scarborough field should integrate with existing LNG facilities instead of operating as a separate new facility, citing the NWS Gas Project or Pluto Gas Project as potential options. Mr Barnett said that he shared concerns, voiced by the NWS joint venture participants, that the capacity of the NWS Gas Plant and other Western Australian-based LNG projects might be under-utilised in 20 years’ time.

Gorgon lNG DevelopmentNo. of trains: 3Capacity: 15 MMt/aPipeline length: 90 kmPipeline diameter: 508 mmContractors: Technip and JP Kenny (upstream front-end engineering and design (FEED)), Kellogg Joint Venture (downstream FEED), Monadelphous (onshore pipeline construction), Subsea 7 (installation of subsea umbilicals), Velocious (intricate tooling components), Rosen Group (baseline pipeline inspections), CB&I and Kents Corporation (strucutral, mechanical, piping, electrical, and instrumentation and commissioning support), Civmec Construction and Engineering (fabrication and supply of steel), McLaren Software (engineering software), Enerflex (meter station), Transfield Worley Services (hook up and commissioning). Participating interests: Chevron (47 per cent), ExxonMobil (25 per cent), Shell (25 per cent), Osaka Gas (1.25 per cent), Tokyo Gas (1 per cent), Chubu Electric Power (0.417 per cent).

Wheatstone lNG DevelopmentNo. of trains: 2Capacity: 25 MMt/a Pipeline length: 220 kmPipeline diameter: 860 mmContractors: Wood Group (ready-for-start-up operation support services), Bechtel Oil, Gas and Chemicals front-end engineering and design (FEED), Intecesa (design of gas gathering facilities and pipelines), Technip (design of field production platform). Participating interests: Apache Corporation (13 per cent), Kuwait Foreign Petroleum Exploration Company (7 per cent), and Shell (6.4 per cent).

Scarborough Gas FieldField capacity: 8–10 TcfContractors: Mustang Engineering, FloaTech, JP Kenny (upstream pre-front-end engineering and design)Participating interests: ExxonMobil (Esso), BHP Billiton.

An aerial view of the horizontal drilling sites on Barrow Island for the Gorgon LNG Development.

Map of the Wheatstone LNG Development.

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The report, titled Shifting trade moves LNG shipping out of the doldrums, warns that while near-term prospects

remain good, the danger is that tankers ordered in today’s rising market are likely to be delivered into a declining freight market with limited employment opportunities.

Wood Mackenzie Senior LNG Shipping Analyst Andrew Buckland says “45 new LNG ships have been ordered so far in 2011, compared with just five in 2010, and most of these have been ordered on a speculative basis. Ships ordered now which will be delivered around 2014–15 have no guarantee that new supply projects will choose to charter these vessels rather than order their own purpose-built ships.

“In the short to medium term we expect significant growth in Asian demand will be met by increased trade from the Middle East and Atlantic Basin, which will further tighten the shipping market. The Pacific Basin is expected to be tightest at 2014, requiring over 40 million tonnes per annum (MMt/a) of incremental LNG. However at this juncture, we forecast shorter haul Intra-Pacific trade to begin displacing long-haul Atlantic to Pacific LNG trade as new projects come online.”

According to Wood Mackenzie, the revival in new orders can be accounted for by a steep increase in LNG charter rates in 2011. Charter rates have more than trebled between the summer of 2010 and 2011 from below $A30,000–100,000 per day.

Wood Mackenzie says that this is, in part, caused by a decline in new tanker deliveries coinciding with the start-up of new liquefaction capacity; stronger demand for LNG after the Fukushima earthquake in Japan; the redirection of some LNG tanker capacity to use as floating regasification

terminals; and, the hoarding of capacity by some shipping capacity holders. Wood Mackenzie says that the key factor is the rise in sub-optimal shipping utilisation, driven by the demise of North American LNG imports and Qatari cargoes being withheld from Asia.

“Freight rates can rise considerably because Asian markets short on regional supply will pull more LNG from long-haul Atlantic suppliers while Qatar continues to push LNG into the Atlantic Basin,” says Mr Buckland.

“This is in part to protect its Asian pricing policy, but in part also to give employment to its fleet of large LNG vessels that can only call at a limited number of Asian terminals. Since few new LNG ships are scheduled

for delivery until late 2013, there will be no relief from new shipping capacity.”

However, Wood Mackenzie says that the shipping market will loosen and charter rate pressure will diminish when:1. The recent tanker orders are delivered;

and;2. New LNG supply projects in the Pacific

Basin come on-stream. Australian supply in particular is expected to displace the need for long-haul Atlantic supply.

Also, Wood Mackenzie says it expects increased Qatari LNG supply toward Asian markets as more Pacific buyers sign long-term contracts and sufficient time is allocated for terminals to upgrade to accept larger Qatari vessels.

“Freight rates are expected to continue rising and could go considerably higher in the near term. However, an expected decline in long-haul LNG trades and the possible preference for purpose-built vessels by some new LNG projects, implies that if the recent wave of speculative LNG ship orders were to continue they would risk uncertain employment upon delivery,” concludes Mr Buckland.

With first LNG export for a number of major projects expected within the next five years, numerous orders have been made for LNG tankers. However, a report released by Wood Mackenzie warns against this sudden ordering boom.

Rough waters ahead for LNG shipping industry: Wood Mackenzie

PROJECT CAPACITY SCHEDULED FIRST LNG EXPORT

QueenslandCurtisLNG Upto12MMt/a 2014

LNGNewcastleProject 4MMt/a 2015

APLNG Upto18MMt/a 2015

GLNG Upto10MMt/a 2015

GorgonLNG 15MMt/a 2015

Wheatstone 8.9MMt/a 2016

Ichthys 8.4MMt/a 2016

ArrowLNGproject 16MMt/a 2017

BrowseLNGproject 14MMt/a 2017

Australian supply in particular is expected to displace the need for long-haul Atlantic supply. We know gas.

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51GAS Today / November 2011GAS Today / November 201150

Beach then embarked on the second phase of its drilling program and began fracture stimulation, starting with the Holdfast-1 well.

Mr Nelson says “The whole fracture stimulation process was experimental as we wanted to understand the best way to stimulate the target zones, how to measure the fractures, what sort of orientation they would take, and what size of proppant would work most effectively.”

Proppant refers to sand particles used to ‘prop’ the factures open so that gas can flow after the fracture stimulation process.

“We tested seven zones and experimented with each zone in terms of fluid viscosity, perforation techniques and proppant size. We were able to learn a lot about the stimulation process and which zones were more amenable to it.”

Initial flow rates were then calculated and the results “were beyond anyone’s wildest dreams” according to Mr Nelson.

“We would have been very happy with some flow of gas to surface, even a few hundred thousand cubic feet per day would have been an excellent result, but we ended up with 2 million cubic feet (MMcf) in the initial flow, which was well beyond expectations! To get that sort of flow rate from seven pinpoint fracs from a vertical well was outstanding in every possible way.”

Following such careful and extensive testing, Mr Nelson reflects on the moment

when the well began to flow. “There was a lot of champagne! It was really one of those wonderful moments.”

Beach’s next move was to book a contingent resource for each well, based on a 100 square km grid. “We knew from seismic data that the shales are continuous, which gave us the confidence to book a 2C contingent resource of 1 trillion cubic feet (Tcf) of gas per well. So we now have a contingent resource booking of 2 Tcf of recoverable sales gas.

“PEL 218 is 1,600 square km, so by extrapolation there is certainly potential

for at least 15–20 Tcf of gas in terms of 2C resources. We intend to assess that potential by drilling at least five vertical exploration wells in 2012 in selected areas around the permit,” says Mr Nelson.

Looking forwardBeach has contracted a new-build rig

that is based on rigs that are used to drill horizontal wells into the Haynesville Shale in the US. This rig is due to arrive in April 2012. Similar rigs in the US are able to

An aerial of Holdfast-1 in the Cooper Basin.

A dust storm at the Encounter-1 well.


Beach Energy’s first foray into unconventional gas was in the CSG business in conjunction with Arrow

Energy, where the companies developed a project for a local power station.

Early in the project development, Beach identified issues in terms of land ownership and water disposal associated with CSG operations and decided to explore other options. Mr Nelson says “At the time I was aware of what was developing in the United States (US) in terms of shale gas, and the fact that shale gas had overtaken CSG in terms of production.”

The company then moved out of the burgeoning CSG industry and into the relative unknowns of the shale gas industry, which had at that point failed to receive recognition in terms of investment and production development within Australia.

Beach began looking within its permits for ideal shale development opportunities, and originally considered drilling in the Otway Basin where the company had witnessed gas flowing from shale fractures during drilling operations. However, it was decided that the Otway site had greater potential for conventional oil and gas, and Beach cast its net wider, looking at prospective basins around Australia. The company found the best acreage in the Cooper Basin.

“We saw that in terms of gas potential the Nappameri Trough in the Cooper Basin was probably superior in terms

of shale gas production due to the thickness of the shales and the over-pressured reservoirs,” says Mr Nelson. “We saw very strong similarities to Haynesville Shale in the US, and so that was our initial drive.”

Beach then moved quickly toward an aggressive and dominant tenement position within the Cooper Basin, sighting the Nappameri Trough as the key objective with a focus on the principal permits of PEL 218 in SA and ATP 588 in Queensland. This allowed Beach to add to its portfolio of tenements, which already included interests in the Santos/Origin Energy joint venture.

“We have a very strong net acreage position in the Cooper Basin, I would say in excess of a million acres if you want to talk in US terms,” says Mr Nelson.

Having secured the ideal tenements according to seismic research, the company set out on a thorough and considered test drilling campaign.

Mr Nelson says “The next process was to start drilling some wells to test the thickness of the shales, the thermal maturity or the degree of over pressuring, the organic content of the shales, and particularly the mechanical properties – that is how amenable the target zones would be to fracturing.”

The first test was the Encounter-1 well, which spud in late 2010, followed closely by the Holdfast-1 well. “These were quite important wells because we deliberately drilled them in the deepest parts of the trough away from

any structures. Structures can be faults or seal rocks that have the potential to trap gas, so if you are able to prove that gas exists outside of these structural closures, you have a strong chance of gas occurring right across the basin,” Mr Nelson says.

Beach gambled what was an expensive drilling program on this premise, hoping for a reasonable shale thickness in the Roseneath-Epsilon-Murteree (REM) sequence and a decent flow rate of gas.

However, the company’s discovery changed the outlook for the development of this unconventional opportunity entirely.

“We proved that not just the shales of the REM sequences were gas-saturated, over-pressured and thicker than we first thought, but we also found that the sandstones and other lithologies located above and below our target shales were gas-saturated. So, on top of what we thought was a highly prospective shale gas play, we believe we have what is effectively known as a basin-centred gas play. This means that the shales are probably still generating gas, and there is a very thick section of normal tight gas potential.”

This encouraging discovery was delivered off the back of Beach undertaking an extensive core analysis of the wells. “We drilled these two wells and took extensive core, which is very expensive. It was a very bold play to drill off-structure in the centre of the basin and take the amount of core that we did, but it was well worth the cost.”

Ensign-16 drills Encounter-1. (Images courtesy of Peter Morris).

Beach Energy’s Holdfast-1 well became Australia’s first exploratory shale gas well in South Australia’s Cooper Basin on 12 July 2011. Gas Today Associate Editor Lauren Molan speaks with Managing Director Reg Nelson to discuss how the junior explorer turned an unconventional idea into a real-life revolution, and sheds light on the future of Australia’s newly established shale industry.

A new shift in the global energy scene: Australian shale


more particularly what price they can get the gas. If you are able to produce shale gas at a price that is competitive with CSG, or perhaps even better, it will offer the end-user a more competitive choice,” says Mr Nelson.

Cost comparisons: CSG versus shale

Mr Nelson says that the cost structures between CSG and shale gas vary. “The capital cost of drilling in a shale gas well is much greater than a CSG well, but you end up with more recoverable gas per shale gas well. In addition, the operating costs of shale wells are lower, mainly because wells are spaced with less density and there is no need to de-water, as is the case with CSG. Profitability really comes down to the unit cost of developing and operating gas production over the entire lifetime of the well.”

“We think we understand drilling costs pretty well in the Cooper Basin as we have been there for decades. We believe that fracture stimulation will be available at the right prices. It really then comes back to production rates and how much

expected ultimate recovery you get per well. These are things we don’t know yet, but of course that will be the objective of these pilot production wells next year that will give us the answer to this question.”

Success in a shale play comes down to the quality of the acreage held and Beach believes it has secured the sweetest spot in the Cooper Basin. “The best place to be is in the centre of the basin, where the shales are thick and over-pressured. The economics there are likely to be markedly different from the marginal areas.”

Managing shale’s reputationSimilar to the Australian CSG industry,

shale in the US has faced negative public perception and landholder issues.

When asked how Beach would minimise issues such as these, Mr Nelson replies with confidence, “We deliberately chose the Nappameri Trough first of all because it’s right in the centre of the Cooper Basin gas operations to begin with. It’s located in semi-desert country, there are few pastoral activities and we have a very good relationship with the station owners. They are familiar with the industry.

“The difference between shale and CSG is that there is a lot less density per well, and there are no water disposal issues. For us, we’re also not drilling in an area of prime agricultural land. The separation between the shales we are looking at and the nearest aquifer of any consequence is around 1,000–1,500 m.”

Mr Nelson believes that shale will offer consumers choice as to where their gas is sourced and the methods of extraction used.

Beach’s advice for those looking to drill shale gas

Mr Nelson says that Beach’s entry into the shale gas industry was careful and considered. “Our objective was to learn as quickly as possible, and the most important advice that we received was ‘spend money doing your homework first”.

“It is important not to race in and start drilling and fracture stimulating. We took a bold step in drilling and coring the Encounter and Holdfast wells, but what we learnt from them was of immense value that will hopefully result in expediting our project.”

drill to a depth of 3,000 m, and horizontally to a distance of 1,500 m.

“Typically, to get production level flow rates from these shales, you want to maximise the exposure of the well bore to the shales. The Cooper Basin shales and sands in the heart of the Nappameri Trough present a target zone of up to and possibly in excess of 1 km thick”, says Mr Nelson.

“We are importing this rig, which is on a two-year extendable contract, and we plan to drill three horizontal pilot production wells, on top of the five planned vertical exploration wells. We will then undertake multi-stage fracture stimulation in each of these wells, which we expect to generate much higher flow rates than that delivered from our Holdfast-1 well.”

In comparison, Haynesville horizontal shale wells can generate initial flow rates of up to 20 MMcf/d, which Beach is hoping to replicate.

“We hope that the five-well vertical exploration program for 2012 will build our resource base considerably. 2 Tcf is a great start, so if we achieve 1 Tcf per vertical exploration well, this could increase our

unconventional resource by a further 5 Tcf, and confirm the concept of the basin-centred gas play. It is worth noting that the basin-centred gas play has the potential to double the resource per well.”

Beach has also strategically chosen to explore shale in the Cooper Basin due to its close proximity to existing pipeline and processing infrastructure. Beach has a 20 per cent interest in a nearby sales gas pipeline and the Moomba processing facility. Mr Nelson concedes that “the ability to get anything to market is critical”.

The future of shale in AustraliaBeach’s view of Australia’s future in

shale is bright. Mr Nelson says “This is a new shift in the global energy scene in terms of oil and gas. Shale gas has had a profound impact on the US and is starting to impact on other countries. The International Energy Agency has identified Australia in particular as the fourth largest in terms of shale potential.”

Companies developing shale in Australia have the benefit of looking to the US for direction. Mr Nelson says “The US was short on gas until about five years ago,

then the shale gas revolution came along in such volumes that the US is now looking to export that gas, rather than import it.”

Mr Nelson points out that unfortunately for the US the development of its shale reserves coincided with the global financial crisis, which saw a drop in gas demand and subsequent decrease in gas prices.

Australia has remained relatively financially stable to this point, and the development of the local shale industry is taking place during a more financially prosperous time. Mr Nelson points out that analysts’ predictions for Australia’s gas prices are trending upward.

“The Australian situation, particularly on the eastern seaboard, is interesting in the sense that at least 80 per cent of the CSG reserves are in the control of the large companies looking to convert it to LNG for export. Most commentators see the gas prices locally going from $A4 to $A7 or $A9 a gigajoule in the next few years, so there’s certainly going to be demand.

“What it will really boil down to is the ability for people to have a choice as to where the gas is coming from, and

Since 1968 Since 1968


When was South East Australia Gas (SEA Gas) first established? How has the company evolved over time?

The company itself was established in 2001 when energy companies International Power and Origin Energy first set out with what they called a ‘customer-led solution’ to the South Australia (SA) Government’s call for a second source of gas supply to the state.

TXU joined the partnership in 2002 just as construction began. The SEA Gas project became operational on 1 January 2004.

The company is now jointly owned by APA Group and the Retail Employees Superannuation Trust.

How many kilometres of transmission pipeline does SEA Gas own and operate?

The SEA Gas pipeline system consists of three pipelines: the 687 km Port Campbell to Adelaide Pipeline (PCA), which stretches from Port Campbell in southwest Victoria to Pelican Point in Adelaide, and two much shorter pipelines; the Port Campbell to Iona Pipeline, and the so-called ‘WUGS Lateral’, both of which are approximately 10 km. Due to its size, the PCA is often referred to as the SEA Gas Pipeline.

We also operate and maintain the Mortlake Pipeline in Victoria for Origin Energy.

How has SEA Gas’ operations changed over the last five years?

We celebrated five years of operation in January 2009. We are a small team but we believe we have a good culture, and have been fortunate in that we have enjoyed a high staff retention rate. As ‘the energy link’ we carry out the nationally important role of connecting Adelaide and Melbourne in the rapidly developing eastern gas market. Currently, we deliver a little over half of Adelaide’s gas requirements.

Our current purpose is to look for business opportunities that add value to our pipeline system. Accordingly, operations have certainly been honed but have not changed greatly as the asset was a state-of-the-art system when built.

What innovations has the company adopted to improve its operating procedures?

As a flow-controlled system with a state-of-the-art control system, much of our innovation has been in improving specific services for our shippers, such as hourly profiling and allocation.

The imposition of the Short-Term Trading Market placed an added burden that is

disproportionate to the representative throughput, but again the system has now been programmed and should provide for our responsibilities under the market processes.

What have been some of the issues involved with encroach-ment and the SEA Gas Pipeline? How have these been resolved?

As a relatively new pipeline, SEA Gas was designed for known and anticipated land use at the time of construction. It was somewhat disconcerting to find that when it was introduced in 2010, the SA 30-Year Plan had little reference to the existence of gas transmission pipelines and that the proposed land use in some areas in the vicinity of the pipeline route was not compatible with the design of the pipeline.

Fortunately, we have worked closely with the South Australian Department of Planning and local government and developers, and to date, sensible outcomes have been achieved. We are very supportive of the Australian Pipeline Industry Association’s efforts in endeavouring to achieve a lateral distance either side of pipelines within which pipeline operators should be notified of proposed development activity in time to ensure pipeline and public safety objectives are met.

Since January 2004, the SEA Gas Pipeline has been integral in supplying gas to South Australia. Gas Today speaks with SEA Gas General Manager Ashley Kellett to find out more about the company behind the pipeline.

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SEA Gas compression facility and pipe work located at Coomandook, South Australia.


How did the availability of the SEA Gas Pipeline assist in ameliorating the consequences of the incident at Santos’ gas processing facility on New Year’s Day in 2004?

I don’t think I will ever forget that early morning phone call. It was pure ’happenstance’ of course that we should be undertaking final commissioning to become operational on that day when, after 33 years of one source of supply and one pipeline, there was an explosion and disruption of supply from the Moomba processing facility.

Adelaide would have had little or no gas for weeks except for the fact that SEA Gas was able to deliver gas on that very day. We supplied approximately 80 per cent of the state’s needs for about three weeks. I do not know how the state could have coped without us, particularly given that at the time, some 60 per cent of power generation was from gas.

Are there any further expansions planned for the pipeline systems?

The way ahead will be very interesting as energy industry participants react to the

carbon question along with the gas pricing outcomes from LNG developments.

We anticipate there will be services required that no one has really thought of as yet, along with challenges of using pipelines for the removal of waste gases from coal-fired plants. We also anticipate further development of open-cycle gas-fired plants, and more innovative peaking transportation services will need to be developed. Adelaide is served by two pipelines and both have relatively low average utilisation rates, so failing a step change in energy demand in the state, organic expansion is unlikely in the near term.

Does SEA Gas have any other pipeline laterals planned over the next five years?

As you would expect, we receive numerous enquiries about services and we are always anxious to provide ideas and to discuss options. At this time, it would be premature of me to elaborate but I would be very surprised if we were not involved with further system extensions in the next few years.

What challenges or trends does the company see on the cards for the pipeline industry in the future?

Those who know me may be surprised that I do not rank ‘regulatory risk’ first. However, I think the horse has bolted there; governments and the economic regulators have removed the incentive for pipeliners to take capacity risk and so in my view we will continue to see just-in-time, fully-contracted pipeline infrastructure rather than innovative measures that would have maximised gas supply competition.

Apart from the issues with urbanisation discussed previously, I expect the challenges are going to relate to Australia’s carbon future and there are numerous facets of this, including increased load factors as more peaking services are called for, the provision of pipeline services through brownfield areas to replace inefficient coal-fired power stations, and ensuring consistency and suitability of pipeline materials both for natural gas as well as evolving waste gas transmission pipelines.

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HistoryIn 1994, United States energy company

Tenneco Energy established a small development office in Brisbane and won the right to build, own and operate the 756 km South West Queensland Pipeline (SWQP) from Ballera to Wallumbilla to supply gas to southeast Queensland. The SWQP, which was constructed in less than 12 months, was commissioned in 1996. The construction project set high standards in Australia for safety and environmental and cultural protection.

On 30 June 1995, Tenneco Energy expanded its portfolio when it acquired the assets of the Pipelines Authority of South Australia (SA) (PASA). Originally known as the Natural Gas Pipelines Authority of South Australia, PASA was formed as a statutory authority by an Act of Parliament in 1967 to construct, own and operate the Moomba to Adelaide Pipeline System (MAPS), with a lateral to Angaston Cement Works. PASA remained a transporter of gas until 1974 when the Act was amended to include the purchase and sale of gas. At the time of the

sale to Tenneco Energy, the purchase and sale of wholesale gas was retained under Government ownership.

Construction of the MAPS commenced on 25 October 1968 and was completed on 1 October 1969. First deliveries of gas to Adelaide on 19 November 1969 heralded a new era of energy supply for SA and an opportunity to transform the state’s economy. At the official opening ceremony, then Premier Steele Hall said that the ceremony was about launching SA into the 1970s. The MAPS was important to SA; securing a long-term energy supply for the state, reducing its reliance on coal and providing a source of energy for large industrial users.

In 1996, following a merger between parent company Tenneco Energy and El Paso Energy Corporation, El Paso Energy invited other companies to become shareholders in the new Australian company. The result was Epic Energy, with El Paso Energy and CNG International holding 30 per cent each and Australian firms Allgas Energy, AMP Investments, Axiom Funds Management

and Hastings Funds Management each holding a 10 per cent shareholding.

With its Queensland and SA assets running smoothly, Epic turned its attention to the west. In 1998, Epic acquired the Dampier to Bunbury Natural Gas Pipeline (DBNGP) and the Pilbara Energy Pipeline (PEP) in Western Australia (WA), moved its head office from Brisbane to Perth, and turned its focus to the organic growth of its existing pipelines.

Over the next four years, Epic completed major upgrades of both MAPS and DBNGP through additional compression and looping, and also constructed the Burrup Extension Pipeline and Wodgina Lateral in the Pilbara region of WA.

In 2004, Epic experienced a major shake-up of its assets; the company sold the DBNGP, and Hastings Funds Management acquired 100 per cent ownership of the MAPS, the SWQP, the South East Pipeline and the PEP.

The following year Epic relocated its head office to Melbourne. The company turned its focus to recontracting long-term gas transportation agreements on the MAPS and implementation of operational efficiencies in light of the commissioning of the SEA Gas Pipeline.

From 2007, Epic has also focused on establishing reverse flow on the SWQP to provide Queensland (QLD) CSG with new markets, which led to the construction of the QSN Link between Ballera and Moomba in 2008 and the QSN 3 looping expansion, which began in 2010 and is currently in progress.

Expansion to the east and westEpic Energy Managing Director Matt

Brassington says that the continued growth in natural gas usage in the eastern states due to power generation, coupled with the discovery of new gas sources in central QLD, has had a positive impact on Epic’s operations. Customers’ requirements to transport gas to meet increased market demands has resulted in a major expansion of Epic’s assets.

As the owner and operator of approximately 2,400 km of pipelines in Queensland, South Australia and Western Australia, and the manager of 659 km of pipeline for other owners, Epic Energy remains true to its name as a gas supply and transmission company of epic proportions.

Epic gas transmission

A map of Epic Energy’s pipeline assets across Australia.

“The construction of the QSN Link pipeline, which connects Epic’s SWQP with MAPS and APA Group’s Moomba to Sydney Pipeline, signified the beginning of a truly integrated pipeline system that, for the first time, has enabled Queensland’s CSG reserves to reach southern markets.”

In June 2010, Epic commenced construction of a 937 km duplication of the SWQP that will more than double its capacity to meet growing demand. The new 450 mm diameter pipeline will be offset 10 m from the existing pipeline and follow the same route from Wallumbilla in QLD through to Moomba in SA. Both pipelines and the QSN Link will operate as one pipeline when completed in late 2011.

Demand has seen gas flow in different directions through the SWQP over its 15-year history. Until 2007, gas flowed eastward from the Cooper Basin to Wallumbilla, where it was reversed and flowed in a westerly direction. With an eastern haul contract established in January 2011, following the completion of the QSN3 expansion, the SWQP will be converted into a bi-directional pipeline to provide flexibility in the changing gas market.

In WA, Epic continues to develop the PEP with a new lateral added in 2009 to transport gas from the PEP to a new power station in Karratha. In 2010, Epic leased a portion of the capacity on the Burrup Extension Pipeline to DBP, the current owner and operator of the DBNGP.

The challenges of operating pipelines in Australia

“Pipeline operation essentially deals with the management of hazards associated with pressurised hydrocarbons, the infrastructure that contains the hydrocarbons and the people that interface with the infrastructure.

One of the biggest challenges for pipeline operators is to mitigate risk associated with their assets,” says Epic Energy General Manager Operations Clive D’Cruz.

In terms of mitigating risks to its infrastructure, Epic follows the relevant Australian standards to maintain its pipeline system, and is committed to ensuring that its maintenance practices are robust to provide ongoing continuity of supply to its customers.

Mr D’Cruz says “We are continually reviewing and looking at improvements in this area as we believe it is important to learn from what others do and be open to changing practices. We have embarked on a program of utilising a number of internal experts to provide technical training of staff in the operations and maintenance activities of its assets. This has proved successful in the past and is continuing to be developed.”

Epic says another challenge facing pipeline operators is the shortage of skilled labour.

“In the last decade, the impact in the operations area of experienced personnel either leaving the industry due to retirement or to pursue other opportunities has been noticeable. This issue is likely to remain with the industry over the coming years,” says Mr D’Cruz.

Epic says that it sees its employees as its greatest asset, which is why the company invests heavily in training. “Helping employees to develop is crucial to the achievement of Epic’s goals. A minimum number of training days per employee per year is set as part of our business key performance indicators.

“We are also currently developing an onsite technical training facility at our Dry Creek depot in SA, which will assist us in

delivering core practical training on actual pipeline equipment,” Mr D’Cruz says.

Looking aheadEpic is continually looking ahead to

anticipate the needs of the gas market to ensure that it can meet the transportation needs of its customers.

“Changing gas market dynamics in eastern Australia arising from the development of an LNG export industry at Gladstone and the potential for enormous reserves of shale gas in the Cooper Basin will determine the way Epic expands its pipeline system,” says Matt Brassington.

“Ironically, even though the SWQP has been expanded to increase capacity to export gas from QLD to southern states, there is nothing preventing the reversal and further expansion of that pipeline to supply shale or other unconventional gas to eastern QLD. If configured as a bi-directional pipeline, the SWQP could play a major role in providing security of gas supply to southern states whilst also providing a high capacity route to export markets for Cooper Basin gas.

“In addition to interest from a number of customers in SWQP capacity, we are continuing to see a strong demand for gas transportation to new power station projects in the Pilbara as a result of the mining boom. We expect a number of these projects may come to fruition over the next 12–24 months.”

Mr Brassington adds “Looking ahead, some of the key challenges for the entire pipeline industry include higher capital costs for new projects, and recruiting and retaining skilled personnel in light of increased demand for skilled workers in the mining and LNG industries.”

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GAS Today / November 2011 59


The 18 million tonnes per annum (MMt/a) Australia Pacific LNG (APLNG) Project experienced

the latest in a number of exciting developments when MCJV, a joint venture between McConnell Dowell Constructors and Consolidated Contracting Company Australia, commenced construction of the 444 km main export pipeline and associated facilities in early September 2011.

The commencement of construction on the 1,070 mm diameter gas pipeline and associated facilities follows MCJV’s completion of the front-end engineering design (FEED) and early works contract, which was awarded in December 2009.

Project parameters APLNG is a joint venture between Origin

Energy, ConocoPhillips and Sinopec. The project includes the development of a four-train CSG-to-LNG project utilising Origin’s Queensland CSG reserves. Origin will act as the upstream CSG operator and ConocoPhillips will be the downstream LNG operator, with the joint venture company to market the LNG.

The APLNG Project involves a main pipeline system, which will transport dehydrated and compressed CSG from the gas fields in the Surat and Bowen basins to the LNG processing plant, to be located at

Laird Point on Curtis Island, off Gladstone. The APLNG pipeline system will include

two lateral pipelines, 44 km and 38 km in length, connecting the Condabri and Woleebee developments, respectively, with the main pipeline.

Beginning east of the Wandoan at the junction of the two lateral pipelines, the main pipeline will run north through the Banana Shire, before turning east toward Gladstone, with a marine crossing at The Narrows.

The pipeline will be buried to a depth of 750 mm.

The final route is the result of extensive studies and surveys, including topography, ecology, geology and cultural heritage, landowner consultation and stakeholder negotiations. Origin will continue to act as the local liaison point for landholders on behalf of proponent APLNG.

The pipeline will be constructed with API 5L X70 steel and externally coated with dual-layer fusion-bonded epoxy.

McConnell Dowell General Manager Pipeline Mark Tywcross said “MCJV will have a peak workforce of more than 1,000 people and will deliver the large diameter gas pipeline and associated facilities over a two-year construction program.”

Construction of the pipeline is expected to take approximately 18 months and is proposed to begin by mid-2012.

Positive developmentsThe project’s environmental impact

statement was approved last year by the Queensland and Federal Governments, in what APLNG Project Director Page Maxson calls a significant milestone in realising its potential benefits.

Mr Maxson says, “The stringent conditions contained in the Co-ordinator-General’s report... should give the community confidence that the project will meet the high standards required during constructions and operation.

“The project will form part of a burgeoning world-scale, long-term industry in Queensland, utilising APLNG’s substantial CSG resources in the Surat and Bowen basins,” he says.

The Australia Pacific LNG Project has been gaining momentum over the last month, with construction of its 444 km pipeline now underway.

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From left to right: MCJV representatives Moyally Jabara (CCC) and Mark Twycross (McConnall Dowell) with APLNG representatives Janet Hann (Origin), Adrian Land (Origin) and Page Maxson (APLNG)

The FutureGAS 2012 Conference and Exhibition, to be held from 27–29 March at the Brisbane

Convention and Exhibition Centre, will connect gas industry members across Australia and provide them with a forum to discuss and learn about the latest industry developments, as well as do business face-to-face.

As a Gold Sponsor, CNC Project Management will gain high-level exposure and highlights — their support for the Australian natural gas industry. The company will be sponsoring the much — anticipated Gala Dinner, which will provide delegates with an opportunity to network in a relaxed and entertaining setting - meeting new contacts and catching up with old faces. This is the second year CNC Project Management has sponsored the Gala Dinner.

CNC Project Management provides a broad spectrum of project facilitation services to infrastructure projects in

the gas industry. It has extensive history in environmental management and assessments; governmental and regulatory controls and permitting; landowner, stakeholder and community engagement; cultural heritage and Native Title; mapping; and, the selection and securing of sites and routes.

CNC Project Management joins MWM as sponsors of the 2012 FutureGAS Conference and Exhibition. Consult your registration brochure in this edition for delegate information, speaker program, sponsor bios and much more!

Stay tuned to the fortnightly Gas Today Update e-news for details of the networking program soon to be released including this year’s Gala Dinner venue and guest speaker.

CNC Project Management has signed on to be a Gold Sponsor of FutureGAS 2012. The company will sponsor the Gala Dinner and official Gala Dinner after party.

CNC Project Management signs on for FutureGAS Gold

CNC Project Management’s sponsorship of the Gala Dinner will continue in 2012.

From left to right: O2 Environment Director, Ben Starr; Upstream Eastern Facilities Star Gas Project Manager, Brett Langley; CNC Project Management Director, Dave Maloney.

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The 2011 FutureGAS Gala Dinner, held at the Brisbane Museum.

GAS Today / November 2011 61


As part of the industry’s brightest and best young professionals took part in a one-day intensive

public speaking workshop held by David Marshall from Talkforce Communications, where they polished and perfected the art of confident presentation skills, thinking on their feet in a number of impromptu speeches, and mastered the art of persuasive gesturing and stage presence.

Federal Minister for Resources and Energy the Hon. Martin Ferguson and Australian Pipeline Industry Association (APIA) Chief Executive Cheryl Cartwright addressed delegates, forecasting the future of the industry and the exciting prospects that lie ahead for those willing to take advantage.

Senior industry professionals were also present as mentors and presentation

adjudicators, including Australia Power and Gas Wholesale Gas General Manager Shelley Reed, S.I.T. Gas Controls Managing Director Andrew Creek, TRUenergy Regulatory Manager Mark Frewin, Rinnai Executive Technical Advisor Chris Blogg, and APIA Policy Advisor Steve Davies.

The second and third days of the event allowed delegates to present 20-minute speeches on a topic of their choice. Stand-outs for this year included APA Group’s Jayne Arthur who presented on the issue of the natural gas industry’s ageing workforce and Rubi Turna of GHD Engineering who addressed pipeline construction in developing countries. The Tuesday evening saw delegates and mentors mingle at the Boat House by the Lake, and all were inspired by guest

speaker Tristan Miller, who in 2010 successfully ran 52 marathons in 52 weeks across the globe.

The final day of Gas Speak ended with some outstanding impromptu speeches that highlighted skills. The award for Best Presentation was bestowed upon Josh Wickham of GPA Engineering for his presentation Environmental challenges in construction and operation in North America. The Encouragement Award was presented to Peter Lather of OSD Pipelines for his presentation Challenges in CSG Gathering System Design, see page 22 for more information. Finally, the award for Best Impromptu Speech was awarded to Oil Search’s Kila Pidi, who presented earlier in the week on CSG exploration drilling in Papua New Guinea.

2011 AGIT Gas Speak a raving success

By Lauren Molan

DAtE / VENuE EVENt WEBSItE31 October – 2 November 2011 Four Seasons Hotel, Sydney, NSW

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27–29 March 2012Brisbane Convention and Exhibition Centre, QLD

FutureGAS 2012 www.futuregas.com.au

4 – 8 June 2012 Kuala Lumpur, Malaysia

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Gas Speak presents an opportunity for young professionals in the natural gas industry to develop their public speaking skills, network, and learn about aspects of the industry outside their day-to-day operations.

Gas Speak will return in 2012, with details to be announced closer to the date. AGIT will shortly be calling on all young gas industry professionals who would like the opportunity to attend

the World Gas Conference – which will be held in Kuala Lumpur, Malaysia, in 2012. To apply visit www.agit.org.au

Delegates were put through their public speaking paces at the 30th Australian Gas Industry Trust Gas Speak event, held from 12–14 September at Old Parliament House in Canberra.

Calendar of events

Gas Today speaks with Amin Kashanchi about how Engineers Australia created a new Queensland Oil and Gas Facilities Group within its association to provide a targeted forum and networking opportunities for professional engineers in the industry.

Can you please tell our readers about Engineers Australia in a broad sense?

Engineers Australia is the largest professional engineering body in Australia and provides a national forum for the advancement of engineering and the professional development of engineers. It has 85,000 members across the country. There are 18,000 members in Queensland across 47 groups. The Oil and Gas Facilities group is a new addition to these 47 groups.

What is the focus of the Oil and Gas Facilities Group?

The group focus will be on facilities of the oil and gas industry. The Society of Petroleum Engineers covers the sub-surface aspect of the industry and this new group will cover the surface aspect from upstream all the way to downstream such as production equipment, gathering systems, processing plant, high-pressure pipeline, refinery and LNG plant.

How can people become a member of the new oil and gas special interest group?

To be a member of the Oil and Gas Facilities Group, the individual needs to become a member of Engineers Australia, which involves paying an annual fee, following which they can join the Oil and Gas Facilities Group for free.

The group will develop, promote and support the personal and professional development of engineers in the oil and gas industry specifically. Members of the group can attend technical presentations, social networking sessions, speaker nights, and share lessons learned and success stories of their projects.

What benefits do members receive?Members of the Oil and Gas Facilities

group can come along to monthly events at a subsidised rate.

They also have the chance to network with their counterparts in the industry and to attend technical forums that are specific to the oil and gas industry. Normally technical forums are not offered by associations. We allow the hours spent attending our forums to go towards attendees’ Continuing Professional Development (CPD) for Charter Status.

Why did you decide to establish the Oil and Gas Facilities Group?

There are a lot of other associations in the oil and gas industry but not all of them can offer the same services that our group can. There are industry bodies that offer conferences and exhibitions but not any technical event and they attract corporate members (not individual members).

Engineers Australia is recognised by State and Federal Government as a professional body for engineering in Australia. Engineers Australia is also one of three professional bodies appointed by the Board of Professional Engineering in Queensland for the assessment of engineers.

A group in Western Australia was established in 2007 and there is dialogue

underway for groups in South Australia and Victoria. Similar to Queensland, those groups will organise personal and professional development opportunities, with the hope of establishing a National Committee to look into national events.

The national group will also address some industry issues such as the engineering skills shortage, training and programs for oil and gas professionals, and the curriculum of undergraduate/postgraduate courses for engineering students.

What is the structure of your group?

The Oil and Gas Facilities Group is classified as a special interest group within the Queensland division of Engineers Australia. The committee includes a Chair, Vice Chair, Treasurer and Secretary who will meet once a month to organise events.

Engineers Australia expands oil and gas interest group

Attendees at the launch of the Engineer ’s Australia Oil and Gas Facilities Group in Queensland. (From left to right) Geoff Haigh, Deputy Chair of Board of Professional Engineers Queensland; Zvonko Pregelj, Vice Chair of QLD Oil and Gas Group; Mike Brady, immediate past President of Queensland division of Engineers Australia; Don McMillan, Queensland Representative on the SPE Australian Council; Roger Kelson, Chair of Queensland Oil and Gas Facilities Group; Peter Cox, President of Australian Pipeline Industry Association; Barbara Jinks, immediate past President of Queensland Petroleum Exploration Association; Malcolm Rushin, GHD.

For more information about Engineers Australia visit

www.engineersaustralia.org.au


February 2012 May 2012 Gas Today International edition August 2012 November 2012

Focus Power generationUnconventional gas

(Coal seam gas, shale, tight gas, UCG.)

Global trade and business LNG

Unconventional Gas (CSG, shale, tight

gas, UCG.)

FeatureExploration and

productionGas for transport Gas appliances

LNG/ Policy and economics/ Major world projects/

LNG shipping

Exploration and drilling Transmission

Region Focus Victoria Western Australia Malaysia PNG NZ

ServicesRecruitment

and skills Transport and logisticsMarine services/

construction contractorsMarine services/

offshoreTransport and

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technology Feature

Mapping, GIS and seismic

Construction contractors/ project management

NGV’s/ Transmission/

exploration and drillingNGV’s

Water treatment/ environmental

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ProductsInstrumentation

and SCADA Valves and meteringEnvironmental management/

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Gas safety Pipes and fittings

Deadline 3 February 2012 1 May 2012 20 April 2012 13 July 2012 5 October 2012

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ADVERtISERS’ INDEXAdtech FRP Pty Ltd 59Ampcontrol Pty Ltd 26Aust. Dynamic Technologies Co Pty Ltd 60Australia Gas 2011 56AXS PTY LTD 21B&R Ex Systems 28Black & Veatch 7Boddingtons Australia Pty Ltd 30Caltex 9Clarke Energy 27Clough Seam Gas 29Comdain OBCConocoPhillips 1Consolidated Contracting Company Australia Pty Ltd 43Draeger Safety Pacific Pty Ltd 23Emico Australia Pty Ltd 33Enerflex 25FutureGas 2012 47Gas Industry Marketing Solutions 49Gas Today Jobs 57GLP Group 42Great Southern Press IBCHays Specialist Recruitment 15HYTORC 52, 53, 55Inpex 45Jemena 17Murphy Pipe and Civil IFCMWM Energy Australia Pty Ltd 31Nacap Australia Pty Ltd 5Nationwide Hire 41OSD Pipelines 24PPI Corporation Pty Ltd 36Pressure & Safety Systems 22Safehouse Habitats Australia 14SPX Flow Technology 40Tyco Flexible Piping Systems 32Valve Tech Engineering Pty Ltd 16Wallenius Wilhelmsen Logistics 13WDS 39Win United 37

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A hands-on intelligent approachA leading infrastructure construction and maintenance services business specialising in the gas, irrigation and water sectors.

Comdain Infrastructure’s gas capabilities include urban transmission and networks construction, fabrication and installation of compressor stations, regulator structures and city gates, and operation and maintenance.

Comdain Infrastructure is accredited to the Federal Safety Commission’s Australian Government Building and Construction OHS Accreditation Scheme which complements the three year certification of our management systems by BSI Global as meeting the requirements of AS/NZS 4801, ISO14001 and ISO9001.

We place importance on professional excellence and best practice in all aspects of our construction and maintenance services work, most particularly on safety.

Recent projects

Geelong Ring Road Project Section 4a & b Realignment of 1.2km long, 250mm transmission pipeline

APA Networks New Services Contract Construction and installation of new service connections for domestic, industrial and commercial sites, and installation of new gas mains

APA Networks Insertions Project Replacement of 40km low pressure gas mains through insertion of PE pipe and upgrade of high pressure range from 315kPa to 578kPa

Robinson Road Transmission Pipeline Lowering Lowering of 250mm transmission main for Peninsula Freeway construction

Sale Transmission Pipeline Realignment Realignment of 1.2km of 150mm transmission main for new Sale Freeway

comdaininfrastructure.com.auIntelligent Doers, Dependable Delivery

Quality ISO9001

OHS AS/NZS 4801

Environment ISO14001

Cert

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Documents

GAS Today / November 2011