New export horizons

JUNE 2014ISSUE 20

New export horizons

AUSTRALIA

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ISSUE 20 | JUNE 2014

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REGULARS4 From the Editor

6 World wrap

64 Event calendar

64 Advertisers’ index

64 Coming in future issues

INDUSTRY NEWS8 Ukraine and Russia crisis: potential

impacts for Europe

10 Indian Oil Corporation awards pipeline coating contract to Denso

INTERVIEW12 The fall and rise of El Paso Corporation

REGION REVIEW16 Queensland: the forefront of Australia’s

LNG export pipelines

20 The road to LNG: constructing Australia’s export piplines

24 Spiderplough delivers a world-first in pipeline installation

28 Nacap setting the benchmark for pipeline construction in Australia

31 Lifting Australia’s pipe loads

34 CSG in focus: modernising the gathering system design process

PIGGING36 Perfect your pigging knowledge

38 Optimal selection of verification digs for in-line inspection

40 Nitrogen pumping for offshore pigging

OFFSHORE42 Revolutionary pipe-in-pipe installation for

the Rochelle Project

48 Innovation with the Ichthys offshore pipeline

PROJECTS IN FOCUS50 The Ichthys Export Pipeline

MACHINERY AND EQUIPMENT52 Regulation and re-routeing in Canada: a

Stopple Train case study

54 Enhancing pipeline security with distributed acoustic sensing

RISK MANAGEMENT56 Troubles with weightings

UPCOMING EVENTS58 Pipeline event opens up new markets

60 Countdown to the International Pipeline Conference and Exposition

62 Fix your pipeline problems in Berlin

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CONTENTS

2 PIPELINES INTERNATIONAL | JUNE 2014

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Speaking at the recent launch of the new report by the Carbon Tracker Initiative (CTI), CEO Anthony Hobley commented,

“Exxon saying there is no risk does not constitute prudent management of shareholder funds: it’s like King Canute assuming he can hold back the tide, but investors can see that a shift in energy is already coming in. Exxon has come clean that [it is] betting on 6o˚C of warming – but investors have no way of managing the risks associated with that trajectory and need to act to get the oil sector’s capital expenditure in line.”

Among the background issues to this recent report on the effect of global warming on the hydrocarbons industry, and hence on the pipeline industry (no new hydrocarbon developments equals no new pipelines) is the International Energy Agency’s confirmation that around two-thirds of fossil fuel reserves cannot be burnt if we are to limit CO2 emissions to a level that gives a reasonable chance of restricting global warming to 2˚C. This means there is a carbon budget to allocate across fossil fuels and, essentially, coal, oil and gas are competing to demonstrate they will get to use the budget. The more the oil sector expects to be used up for transport, the less will be available for burning coal or gas for power generation. Similarly, the more state-owned entities produce, the less scope there is for private companies. According to the CTI, BP acknowledges that reserves exceed a carbon budget for limiting global warming to 2o˚C in its latest sustainability report, but is less clear about the financial implications.

Getting companies to explain how they see their business adapting to the transition of the energy system away from high carbon sources starts a new debate which brings together corporate strategy and spending plans with climate-change policy positions. Long-term investors have an inherent interest in resolving these contradictions between supporting climate policy on one hand, but spending capital on increasing fossil-fuel reserves on the other. As the CTI points out, Shell – in its discussion of risk factors – acknowledges in its annual report that carbon regulation is increasing, and then also admits that the carbon intensity of its production is increasing, which appears an undesirable combination. Further probing is needed from investors on the logic behind this conscious pursuit of high-carbon assets.

Oil analysts have been highlighting that company cash-flow cannot support continued increasing capital expenditure and

maintaining dividends. Looking at future plans to spend capital on high-cost projects – which assume high oil prices – is prudent for investors. As Wood Mackenzie has put it, this is solving the value vs volume dilemma, and this builds on the issue raised in CTI’s Wasted capital and stranded assets report. If companies are betting on high oil prices, will they be able to maintain both dividends and planned Capex in a lower-price environment?

The oil sector is moving into higher-carbon unconventionals to try and maintain production. There is growing exposure to projects in ultra-deepwater, the Arctic, and in unconventional plays such as oilsands, all of which bring greater technical risk and higher costs. This will affect different companies to varying extents. The CTI report believes it is reasonable to expect a company to disclose the price and demand assumptions it is testing its capital expenditure decisions against: for example, the report quotes Shell as having indicated that it uses a range of $US70–110 /bbl. It would also be useful for a company to indicate its level of exposure at various oil prices, and the level at which it would start to impair assets: companies with higher exposure to projects that breakeven above $US80/bbl are less well-positioned to adapt to a low-price environment.

This debate, the CTI points out, is directly linked to expectations around oil demand and price. Oil-production costs have increased at a rapid rate, with Capex by the largest oil companies now five times the level it was in 2000. Yet over this time the level of production has stayed around the same level, rather than increasing in proportion to Capex levels. As the cost per barrel has increased, the profitability of operations has only been achieved by oil prices increasing to cover the cost increase. If the original price assumptions had played out, the projects would have seen major losses. Analysts are now questioning whether the price trajectory can continue to support the cost trajectory seen over the last decade.

The effect on new pipeline construction obviously remains to be seen, but if the past is anything to go by, even a minor fluctuation in the oil price has a magnified effect on such long-term projects.

John TiratsooEditor-in-Chief

FROM THE EDITOR

JUNE 2014ISSUE 20

New export horizons

AUSTRALIA

The entire 540 km QCLNG pipeline – seen here during construction at The Narrows in Gladstone, Queensland – has now been buried. Image courtesy of QGC.

ISSN: 1837-1167

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Editor-in-Chief: John TiratsooManaging Editor: Lyndsie ClarkAssociate Editor: Anna TupicoffSales Manager: Tim ThompsonSenior Account Manager: David MarshSales Representative: David EntringerCreative Director: Michelle CrossActing Design Manager: Bianca BotterDesigner: Kim BarryEvents Manager: Luke RowohltPublisher: Zelda Tupicoff

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To stay informed on this news and more, subscribe to the Pipelines International Update ›› www.pipelinesinternational.com

WORLD WRAP WORLD WRAP

TransCanada files Eastern Mainline Project description with National Energy BoardTransCanada has filed a project description with the National Energy Board of Canada for the Eastern Mainline Project, proposing new facilities to the company’s existing Canadian Mainline natural gas transmission system in south-eastern Ontario. The project description proposes the construction of as much as 370 kilometres of up to 36 inch diameter pipe and associated compression facilities adjacent to existing mainline facilities between the City of Markham and the Township of South Dundas in Eastern Ontario. Discussions between TransCanada and shippers are ongoing to determine the appropriate amount of capacity that will be required.

Alaska passes bill for Alaska LNG and pipeline project partnershipThe Alaskan State Legislature has passed a bill for the state of Alaska, USA, to partner with energy companies to develop the $US45–65 billion Alaska LNG Project, which involves a large-diameter natural gas pipeline. The legislation amends multiple state laws, and allows negotiations to proceed toward the state of Alaska becoming an equity partner in the project. The Alaska LNG Project partners are North Slope gas producers ExxonMobil, ConocoPhillips, and BP, pipeline company TransCanada, and the state of Alaska. The project involves construction of: • A gas treatment plant at Prudhoe Bay on

Alaska’s North Slope;• A 93 km gas pipeline from Point Thomson

gas field to Prudhoe Bay;• A 1,287 km, 42 inch diameter gas pipeline

from Prudhoe Bay to Nikiski, southwest of Anchorage along Cook Inlet; and,

• A 15–18 MMt/a LNG plant, storage and tanker terminal at Nikiski.

The pipeline would have a capacity of 3–3.5 Bcf/d of natural gas which would be distributed domestically as well as being used for LNG feedstock.

Sterling III NGL Pipeline completeONEOK Partners has completed its 869 km, 16 inch diameter Sterling III natural gas liquids (NGLs) pipeline, which runs from the United States’ Mid-Continent region to the Texas Gulf Coast. The Sterling III Pipeline has the capacity to transport 193,000 bbl/d of either unfractionated NGLs or pure NGL products from ONEOK’s NGL infrastructure at Medford, Oklahoma, to its storage and fractionation facilities at Mont Belvieu, Texas.The partnership’s existing Sterling I and II pipelines are being reconfigured to transport either unfractionated NGLs or NGL purity products, and are expected to be completed during the second quarter 2014. The cost for the Sterling III Pipeline and these reconfigurations is approximately $US760–790 million.

CNPC completes subsea section of Tanzania pipelineChina National Petroleum Corporation (CNPC) has completed the 29 km subsea portion of the Mnazi Bay to Dar es Salaam Gas Pipeline Project, in Tanzania, according to the China Times. The local news service reports that CNPC successfully laid and connected the subsea pipe on 15 April using the pipelay vessel CPP601, CNPC’s largest subsea pipelay vessel. The Mnazi Bay to Dar es Salaam Gas Pipeline project involves the construction of 532 km of pipeline to transport gas from Mnazi Bay in the Mtwara region and Songo Songo in the Kilwa District, to Dar es Salaam. The project consists of a 36 inch mainline and a 24 inch spur line. Upon completion, the pipeline is expected to have a capacity of 784 MMcf/d. The project began construction in September 2012, and is expected to be completed in January 2015.

Contract signed for second string of South Stream offshore sectionSouth Stream Transport has signed a contract with Swiss Allseas Group to lay the second string of the South Stream offshore gas pipeline in deep water in the Black Sea, and a contract with Saipem for providing complementary services for the construction.Pursuant to the contract, Allseas will lay approximately 900 km of pipe on the seabed, and will engage the new pipelay vessel Pieter Schelte, which is equipped with six welding and coating facilities to undertake the project.As part of laying the second string, Saipem will engineer, manage pipe storage terminals, and connect the offshore pipeline to the landfall sections using the above-water tie-ins.Allseas will start laying the second string in summer 2015, while Saipem will be laying the first one. The second string will be commissioned by the end of 2016.

Saipem awarded $US2.5 billion contract for Shah Deniz Stage IIThe Saipem, Bos Shelf, and Star Gulf consortium has been awarded a new offshore engineering and construction contract for the Stage II development of the Shah Deniz field, worth approximately $US2.5 billion.The field is located 90 km offshore Azerbaijan, in water depths between 75 m and 550 m. The contract’s scope of work includes the transportation and installation of jackets, topsides, and subsea production systems and structures, the laying of over 360 km of pipelines, diving-support services, and the upgrade of the pipelay barge Israfil Huseinov, dive-support vessel Tofiq Ismailov, and derrick barge Azerbaijan. The project will be completed by the end of 2017.

GLNG pipeline closer to completion after Gladstone Harbour crossingThe final section of the Santos GLNG Project’s gas transmission pipeline has successfully pushed through a tunnel beneath the Gladstone Harbour to the LNG plant on Curtis Island, Queensland.The 120 pipeline segments, each measuring 36 m, were welded and pushed through the 4.3 km tunnel using a large hydraulic jack, as the tunnel filled with seawater to buoy the 42 inch diameter pipeline.Pipeline pre-commissioning works are well underway, with clean and gauge activities nearing completion and about half of the required hydrotesting completed.The pipeline route will be fully rehabilitated with initial reinstatement works now more than 90 per cent complete.


The current political crisis between Russia and Ukraine has prompted governments and industry in Europe, and throughout the world, to assess the potential impact of a disruption to the transportation of Russian gas to Europe via Ukraine.

Wood Mackenzie’s latest analysis demonstrates the comparison of a potential disruption of two months in

the spring of 2014, with a six-month disruption during the winter of 2014/15, and how this could affect European and Asian LNG markets.

The global research group estimates that Europe imported 155 Bcm of gas from Russia in 2013, some 30 per cent of its overall gas demand. Ukraine is the key transit route for Russian gas to Europe, with 50 per cent (82 Bcm) transited through Ukraine in 2013.

Wood Mackenzie’s Senior Global Gas Analyst Stephen O’Rourke said “Central and Eastern Europe will be most affected by a Ukraine transit disruption, as eastward-flowing pipeline capacity [from Western Europe] would be insufficient to meet gas demand in Eastern Europe. The region will have to draw upon strategic storage volumes and some demand will not be fully met. On the other hand, north-west Europe has direct access to Russia’s Nord Stream pipeline, which mitigates the impact of any transit disruption.”

The consultancy’s Head of Global Gas Research Noel Tomnay said “Based on our analysis, if there is a two-month disruption to

the Ukrainian transit route in spring 2014, the Southern European countries of Turkey and Greece will require additional LNG, but this should be less than 2 MMt.”

Mr O’Rourke continued “If the disruption is more severe, for example a six-month duration over the 2014/15 winter, we expect further Southern European countries, including Spain, to call on extra LNG. But, robust European storage volumes going into the winter should limit overall additional LNG demand to less than five million tonnes.

“To try and alleviate the impact of a winter disruption of Russian gas flows, Ukraine would need to utilise its strategic storage reserves and prioritise gas demand in the residential and power sectors. Should the EU seek to supply Ukraine with gas, additional reverse flow capacity would need to be negotiated and accessed. While we believe deliveries to Ukraine would blunt the impact of a Russian disruption, they could exacerbate a difficult position for several Eastern European countries.”

The Oxford Institute for Energy Studies has also released a report entitled What the Ukraine crisis means for gas markets, asserting

that “The change of government in Kyiv, the Russian military action in Crimea, the diplomatic reaction by the Western powers, and the perceived danger of war, clearly have implications for all economic relations between Russia, Ukraine, and Europe, especially in the energy sphere. Russia supplies about 30 per cent of Europe’s natural gas, and more than half of these volumes are still transported via Ukraine. In Ukraine, gas supply issues are combined with the economic upheavals aggravated by political crisis.”

In a statement issued on 11 March, Gas Infrastructure Europe – an association that represents the interests of operators of transmission, storage, and LNG import infrastructure – said “Members of Gas Transmission Europe have now assessed the supply situation in close co-operation with their national competent authorities and expect that most of the European transmission systems currently can withstand a disruption of Russian gas through Ukraine. The pipeline network is available for diverting gas flows in case of supply problems from Russia from storage and LNG to market.”

Ukraine and Russia crisis: potential impacts for Europe

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Indian Oil Corporation Ltd (IOCL) aims to continuously rehabilitate sections of its more than 11,000 km pipeline grid after 40

years of operation, and this rehabilitation will be executed under operating conditions. A three-ply (inner wrap) and two-ply (outer wrap) PE/butyl-tape-systems has been selected by DENSO for the project, due to its proven outstanding technical performance and the easy application.

The 2.4 million square metres of DENSOLEN AS39P/R20HT coating that will be used equates to the area of more than 335 football pitches, and will be delivered in 2014 and 2015 for approximately 320 km of IOCL’s pipelines.

DENSO has previously delivered more than 2.6 million square metres of the tape system to IOCL for rehabilitation purposes.

DENSO has been a leading developer of high-quality corrosion-prevention and sealing technology since 1922. The company’s success story commenced with the world’s first passive corrosion-prevention for pipelines – DENSO tape (petrolatum-tape) – which was invented in 1927. Since then, the company has been producing a range of corrosion-prevention products, such as liquid coatings (DENSOLID), sealing-tapes (DENSIT), jetty pile protection (MarineProtect), heat-shrinkable sleeves

(DEKOTEC), and PE/butyl-tape-systems (DENSOLEN).

IOCL aims to protect its pipelines from corrosion for at least another 40 years, and the company’s technical committee is satisfied with the performance of the three-ply/two-ply and PE/butyl-tape-system technology. DENSOLEN tapes and tape-systems are some of the only corrosion-prevention systems worldwide with a proven long-term experience of more than 40 years. The high-performance tape system has successfully been used in numerous pipeline projects, with more than 100 million square metres applied over the last 40 years.

Indian Oil Corporation Ltd, India’s biggest pipeline operator and one of the world’s leading oil companies, has awarded a tender of more than 2.4 million square metres of high quality pipeline coating to DENSO GmbH of Germany.

Indian Oil Corporation awards pipeline coating contract to Denso

INDUSTRY NEWS

For more information, contact Michael Schad at [email protected], or visit www.denso.de

Application of DENSOLEN AS39 P/ R20HT at IOCL in India.

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Pipelines International recently spoke about culture transformation and leadership development with Sue Ortenstone, who was part of the team responsible for the remarkable turnaround of El Paso Corporation, which was on the verge of collapse on the heels of the 2001 Enron scandal.

The financial scandal and subsequent bankruptcy of American energy company Enron in 2001 caused

significant disruption across the whole American energy sector. One of the companies affected by the subsequent whole-of-industry shake-up and intense scrutinisation was one of North America’s largest natural gas companies, El Paso Corporation, whose stock plunged from $US72 to $US3. By 2003, the company was on the verge of collapse; it had a lot of debt and was selling-off assets to pay down its debt. Some wanted the management team thrown out, and shareholders and employees were understandably very angry and frustrated.

After a proxy fight, the management team managed to hang on but a new CEO, Doug Foshee, was put in place. As Mr Foshee put together his executive team, he wanted the head of human resources to have some operating and business experience as he felt that would be helpful in turning the company around with improved collaboration and

credibility, bringing all areas together to develop a new culture. Enter Sue Ortenstone.

Ms Ortenstone had spent approximately seven years on the engineering and operations side of Tennessee Gas Pipeline in a variety of roles with increasing responsibility. She then moved into business development and spent the next 18 years on the business side in a variety of areas including marketing, supply, strategy, and as CEO of EPIC Energy, which at that time was partially owned by El Paso Corporation. So, it was safe to say, she fitted the bill.

“While I did not have any formal training on the human resources front and I never imagined a career in the area, I was excited about the opportunity,” Ms Ortenstone says.

“Not only did I want to do what I could to help out in such a challenging time for El Paso, but also I have always been passionate about the people side of the business and enjoyed the leadership aspect of the roles I was in throughout my career.”

With their backs against the wall, it was time to get back to basics.

“We had gotten into over 20 different businesses across the energy spectrum and beyond including telecom, electric generation, and trading numerous commodities. Our

The fall and rise of El Paso Corporation

INTERVIEW

Sue Ortenstone.

CONTINUED ON PAGE 14 ››


initial focus was to get everybody aligned on the same set of values, create a purpose statement, and then we put a vision in place.

“Our purpose was to narrow our focus to natural gas and natural gas-related products, so that when a deal came up in the future, we’d look at it and say ‘Does this fit?’ and if it didn’t, we wouldn’t get involved in it. The two El Paso core businesses going forward were the natural gas pipeline and the exploration and production segments.

“The next step in turning the organisation around was addressing the issue of staff dissatisfaction. We surveyed our employees in 2004 and we knew it was going to be bad – less than 50 per cent of them were happy to work for El Paso. You can’t run a company when your people aren’t happy to be there.

“So, we looked back at what had happened over the last number of years, and we felt that we hadn’t been very clear with employees about what was expected from them. There was no focus on employee development and training, including for the leadership.”

The team set about implementing a series of programmes and initiatives surrounding performance management, compensation, and leadership development, with the aim of promoting careers, not jobs.

“We ended up having this great vision that was developed by a team of employees that was: ‘The place to work, the neighbour to have, the company to own.’ It’s so simple, but that’s what we wanted it to be, and we felt if we could get ‘the place to work’ right, the rest would take care of itself,” Ms Ortenstone continued.

Ms Ortenstone explains that, at the time, El Paso had a performance-management system in place but almost everybody got the top rating, so it wasn’t really representative of how people were performing.

“Most employee groups perform over a bell-curve-type distribution and we weren’t being true to that, so the first thing we decided to do was roll-out a compensation programme that put metrics in place so only a certain targeted percentage could be at the top end of the performance curve.

“We had metrics at several levels. We had corporate goals, business-unit goals, individual-group goals, and individual goals. So we went from measuring not much, to measuring a lot of things.

“We had five performance categories with descriptor words, as opposed to numbers, with the top category being ‘Outstanding’. We had percentage targets for these categories

that the managers had to generally hit so a leader couldn’t have 80 per cent of their people in the ‘Outstanding’ category, which is what had been happening prior to that.

“We had limited resources, and we felt that everybody should not get the same thing when it came to incentive compensation, but for those that go the extra mile, we should give them more, and for those that aren’t pulling their weight, we should give them less. Basically, a pay-for-performance structure was put in place.”

Initially, this was tough for both the managers, who had to conduct these more forensic and tough reviews, as well as the employees, the majority of whom had previously always been told that they were performing outstandingly. But it did lead to better performance discussions between leaders and their employees, resulting in improved performance across the company.

The other thing that El Paso did that was really important on top of the compensation and performance management, was leadership development.

“Our company, like a lot of the pipeline companies, had a lot of engineers and technical people. The thing about that is that a lot of people had been promoted because of their technical capabilities and not necessarily because of their leadership capabilities. We started to identify who our really strong leaders were and gave them opportunities, both on-the-job training and classroom training for developing those skills.

“Since we did not have many resources initially due to our financial challenges, we initially targeted a leadership-development programme for our officer team and partnered with Rice University to deliver the curriculum. We felt that if we started our officer team out with the basic training, it could help cascade it to our other levels of leadership.

“Later, we developed our own programme called ‘Lead the Way’ for our officer team that defined what it meant to be a leader at El Paso, established a common leadership language, provided leadership-development opportunities, and incorporated leadership competencies into performance accountabilities, succession planning, and the selection process.”

In addition to these initiatives, El Paso placed a major focus on transparency and communication throughout the whole process.

“One of the things we did when we surveyed employees was that we were transparent about the results, we summarised what they told us – we put it out there. For the things that we could change or we could address, we told people what we were going to do and if we couldn’t, we would explain why.”

In 2010, El Paso surveyed its employees again. Almost 100 per cent of employees participated in the survey and 90 per cent said that they were proud to work for El Paso – a far cry from the less 50 per cent satisfaction rate of 2004.

“The key was strong leadership, consistency, alignment and then results,” Ms Ortenstone says.

INTERVIEW

El Paso Corporation was a top performer in its peer group as measured by Total Shareholder Return when it was acquired by Kinder Morgan in May, 2012.

‹‹ CONTINUED FROM PAGE 12


Queensland, located in the northeast of Australia and the second-largest state in the country, is home to three of Australia’s most highly anticipated pipeline-construction projects; the Queensland Curtis LNG Project, the Australian Pacific LNG Project, and the Gladstone LNG Project. Pipelines International gives you all the latest project information and pipeline facts from these game-changing ventures.

Queensland: the forefront of Australia’s LNG export pipelines

REGION REVIEW

AUSTRALIA PACIFIC LNG PROJECT The Australia Pacific LNG (APLNG) Project involves the construction of a two-train coal seam gas (CSG)-to-LNG facility on Curtis Island utilising Origin’s Queensland CSG reserves and resources. The LNG plant will be four trains, to be constructed using Cascade technology, and will have the capacity to produce up to 18 million tonnes annually (MMt/a) of LNG.

The project includes the construction of a 530 km, 36–42 inch API 5L externally coated gas transmission pipeline from the Surat and Bowen basins to the LNG processing site. The pipeline will have a capacity of 1,560 TJ per day.

Manufacturing and transporting the steel pipe was a major logistical challenge, undertaken in 18 months, involving a total of 42,000 steel pipe joints, most at 18 m in length and 42 inch in diameter, and weighing approximately 270,000 tonnes, delivered via 45 ship movements, approximately 250,000 crane lifts, 307 train trips, and co-ordinated by teams in three countries.

With the main pipeline nearing completion at the time of print, the project remains on track for first LNG in mid-2015.

GLADSTONE LNG PROJECTThe Gladstone LNG (GLNG) Project involves the development of gas fields in the Bowen and Surat basins, the construction of a 420 km underground gas transmission pipeline, and a two-train LNG processing facility on Curtis Island.

The project includes an API 5L X70 PSL2-grade 420 km, 42 inch diameter gas-transmission pipeline, linking a compression station at Santos’ Fairview Bowen and Roma CSG fields in the Surat Basin to the liquefaction plant.

The project was approximately 80 per cent complete at the beginning of the fourth quarter in the 2013–14 financial year, and is progressing toward first gas in 2015 with the final modules arriving at Curtis Island in early 2014.

APLNG shareholders

Sinopec

25%

Origin (upstream operator)

37.5%

ConocoPhillips (downstream

operator)

37.5%

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GLNG shareholders

Santos

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27.5%

Petronas27.5%

KOGAS15%



REGION REVIEW

QCLNG PIPELINE DESIGN FEATURES• AS2885Part1,2,4and5–the

AustralianStandardforthedesignandconstructionofpetroleumpipelines.

• DN1050mmAPI5LPSL2manufacturedusingUOEpipewithwallthicknessesof0.55,0.71,and0.93inches.

• Withan0.8designfactor,0.71inchwall-thicknesspipehasbeenusedforroadcrossingsandhigh-consequenceareas,and0.93inchwall-thicknesspipehasbeenusedforhorizontal-directionaldrills(HDD)andtheNarrowsCrossing.

• Designedforclean,drynaturalgas.

• Coatedwith800–1,000micronsofdual-layerfusion-bondedepoxy.

• Internallylinedwith85micronsofepoxyflowliner.

• Inductionbendsusedforhorizontalbends>40degrees.

• PipejointcoatingsystemSPC2888–appliedbyPIH.

• FivelateralsandeightmainlinevalvesincludingtheReceiptStationnearWandoanandtheDeliveryStationonCurtisIsland.

• Cathodic-protectionsysteminstalledtohelppreventcorrosion.

QUEENSLAND CURTIS LNG PROJECTThe Queensland Curtis LNG (QCLNG) Project is an $8 billion onshore CSG-to-LNG production and export facility on the Queensland coast. The project includes a 340 km, 42 inch fusion-bonded-epoxy (external) and two-pack-epoxy (internal) coated export pipeline from Wandoan in the Surat Basin to northeast of Gladstone. It has a maximum operating pressure of 10.2 MPa using API 5L X70 grade steel pipes.

The pipeline system also includes the Narrows Crossing development, which is a 12.7 km pipeline from Gladstone to Curtis Island. The pipeline has an outside diameter of 42 inch, and is made of X70 steel with a yield strength of 485 MPa, coated with fusion-bonded epoxy.

The 540 km pipeline was mechanically completed and filled with gas at operating pressure this year.

This marked the completion of the a two-year task undertaken by MCJV, a joint venture of McConnell Dowell Constructors and Consolidated Contractors Company Australia, to lay more than 46,000 lengths of 1 m diameter steel pipe over 540 km, making it the longest large-diameter buried pipeline in Australia.

Arrival of first gas onto the island has enabled commissioning work to begin on the first of two LNG production trains being developed as part of the project.


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In the last six decades, the Consolidated Contractors Company has carried out over 17,000 km of challenging pipeline projects in the Middle East, Arabian Gulf, CIS, Africa, and recently in Australia. These pipelines were built in some of the most challenging areas of the world, in extreme hot and cold weather, across difficult terrains, and in some of the most environmentally sensitive areas.

The Consolidated Contractors Company (CCC) established its Australian base in 2010, and subsequently has worked on

high-profile pipeline projects worth over $US1.85 billion including the Queensland Curtis Island LNG (export and Narrows) and Australia Pacific LNG projects.

The complexity of QCLNGThe Queensland Curtis LNG (QCLNG)

Project will be one of Australia’s largest capital-investment projects, and will initially supply up to 8.5 MMt/a of LNG through the development of two LNG trains.

QGC engaged MCJV, a joint venture between CCC and McConnell Dowell Constructors, to undertake the QCLNG Export Pipeline, the Gas Collection Header, and the Narrows Crossing projects.

The joint venture brought together the local experience and knowledge of McConnell Dowell with the technical expertise and international experience of CCC to provide a world-class approach to the engineering, procurement, and construction of these projects.

The QCLNG Export Pipeline and Gas Collection Header include the engineering

and construction of a 540 km, 42 inch diameter gas pipeline network linking gas fields in the Surat Basin to the LNG plant on Curtis Island, just north of Gladstone.

This challenging project involved more than 1,800 people employed at peak, with approximately 12 million man hours completed on works including more than 1000 crossings of creeks, roads, access tracks, railway lines, and third-party utilities, as well as the construction of the pipeline network, with associated vehicles travelling more than 45 million km.

REGION REVIEW

The road to LNG: constructing Australia’s export pipelines

The QCLNG Export Pipeline – Narrows crossing. This is the largest diameter underwater pipe pull.


highest commitment to HSE, quality and social responsibility

Consolidated Contractors Companywww.ccc.gr / www.cccaus.com.au

Consolidated Contracting Company Australia Pty Ltd.Level 32 AMP Place ● 10 Eagle StreetBrisbane Qld 4000 ● AustraliaTel: +61 7 3230 0600Fax: +61 7 3230 0699

Consolidated Contractors Company62B Kifissias Avenue ● P.O. Box 61092Amaroussion 151 10 ● Athens, Greece

Tel: +30 210 6182 000 Fax: +30 210 6199 224

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International Pipeline and Offshore Contractors Association Health and Safety Awards.

“At CCC, we believe that every project – whatever the size – deserves our full attention and commitment,” explains President of CCC Engineering and Construction Samer Khoury.

“Our success over 60 years stems from understanding this and creating a family company which fosters relationships with our stakeholders, employees, partners, clients, the environment and the communities where we operate, and emphasises our commitment.”

CCC Regional Managing Director – Africa, Caribbean and the Pacific Moujally Jabara adds that “These Australian projects were the combined effort of four years of challenging and dedicated work, and their successful completion marks not just a significant milestone for both the APLNG and QCLNG Projects, but a triumph for those whose hard work and commitment made it possible.”

Crossing the NarrowsThe QCLNG Pipeline – Narrows Crossing

Project involved connection of the export pipeline at Main Line Valve #7 across the Narrows (marine channel) in Gladstone Harbour, to the LNG plant on Curtis Island. Part of the Narrows Crossing Project also includes construction of the Australia Pacific LNG pipeline in the same trench as QCLNG – the Bundled Crossing. The Narrows Crossing is one of the nearest points between the Queensland mainland and Curtis Island, and is also one of the most technically challenging locations through which to build a pipeline, because of the multitude of sensitive terrestrial and marine environments encountered.

Due to the sensitivity of the surrounding environment, the joint venture utilised environmental ‘best practices’ in the construction of the pipeline. Importantly, this commitment resulted in the Project adopting innovative construction approaches that went beyond the legislative compliance. The initial QCLNG Project concept was developed and implemented as a benchmark environmental project. Numerous complex engineering solutions were employed to support

construction of a twin pipeline project safely and environmentally responsibly.

The 2.45 km Narrows Crossing pipeline was laid across Gladstone harbour in February 2013 without injury or incident. This was a significant engineering achievement and Australia’s longest large-diameter underwater pipe-pull.

Constructing the APLNG pipelineAustralia Pacific LNG, a joint venture

owned by Origin, ConocoPhillips, and Sinopec, awarded the McConnell Dowell and CCC joint venture (MCJV) a multi-million dollar contract to build a 530 km gas transmission pipeline for the Australia Pacific LNG Project in Queensland.

The scope of the work included the design, engineering, and construction of the pipeline to transport coal seam gas from the Surat and Bowen basins to the LNG processing site located on Curtis Island, Gladstone.

The pipeline project brings many benefits to the economies of regional communities in Queensland and across Australia through the creation of over 1000 direct and indirect jobs and investment in local goods and services.

Through the dedication, commitment and collaboration between Australia Pacific LNG and MCJV, the Environment Management Team from Australia Pacific LNG has received an Australia Biosecurity Award and was the runner-up in the 2013

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CCC is a diversified global engineering and construction company with headquarters in Athens, Greece. In over six decades of operation, CCC has grown to become one of the leading contractors in the international construction market, with over 120,000 employees from more than 80 nationalities. CCC is a family-owned company offering a wide range of engineering and construction services across the engineering, procurement and construction value chain from feasibility studies into design, procurement, construction, commissioning, operations and maintenance.

The Narrows Crossing pipe-lay success was recognised in numerous industry award categories:

• 2013 – High Commendation in the Engineers Australia Queensland Division Excellence Award for the Environment

• 2013 – High Commendation in the Engineers Australia Queensland Division Excellence Award for Research, Development and Innovation

• 2013 – Finalists for the Queensland Major Contractors Safety Award

REGION REVIEW REGION REVIEW

The QCLNG Pipeline – Narrows Crossing Project.

The Australia Pacific LNG main pipeline contract.



The development and adaptation of the innovative Spiderplough pipeline technology by Murphy Pipe and Civil, an associated company of J Murphy & Sons Ltd, has provided new options for the oil, gas, and mining sectors.

The Spiderplough technology has shown that it can heighten safety performance, improve sustainability, and reduce costs

by up to 50 per cent, while achieving notable daily productivity rates of up to 17.2 km using a range of 4.3 inch to 24.8 inch high-density polyethylene (HDPE) pipe.

Research and development identifies a unique opportunity

Murphy Pipe and Civil (MPC) has been using the German-manufactured Föckersperger Spiderplough technology over the last three

years to install more than 3,000 km of HDPE pipe, ranging in diameter from 4.3–17.7 inches including dual 12.4 inches. Based on its experience with the technology, the company saw an opportunity to adapt the Spiderplough for 24.8 inch HDPE installations, as MPC Director Tony O’Sullivan explains.

“Our fleet is currently deployed on three projects across the Surat Basin in Western Queensland, Australia, including the 5000+ km 4.3–24.8 inch HDPE pipeline for the QCLNG Gathering Project. With the market continually looking for efficiencies in the

installation of gathering networks, the need to extend the Spiderplough technology to install larger diameter pipeline was becoming increasingly apparent.

“Utilising our experience with the technology, our research and development team identified a unique opportunity for the 17.7 inch Spiderploughs to be adapted and modified for use in 24.8 inch diameter applications. This was developed and trialled internally, in consultation with the manufacturer. Extensive modifications were made in order to deliver economic, safety, and environmental benefits through its

REGION REVIEW

Spiderplough delivers a world-first in pipeline installation

MPC’s adaptation of Spiderplough pipeline technology extends the limit of pipeline solutions.



of HDPE pipeline being installed in a single 12 hour shift.

While each pipeline installation contract varies, Spiderplough technology is generally seen as saving clients between 30–50 per cent in costs through reduced crew sizes, reduced fleet requirements, and shorter installation time leading to reduced contract periods.

One of the key advantages of the Spiderplough technology is the inherent safety benefits it brings from eliminating the open trench. Since its introduction MPC has achieved 2.7 million hours worked without any lost-time injury related to its use on projects. These milestones were further supported by MPC’s adoption of Murphy’s ‘Never harm

culture’ development programme which was rolled-out across MPC’s 1,600 employees in 2013. Since then, MPC’s total recordable case frequency ratio has been decreased by 83 per cent from 10.9 to 1.9 (the Australian industry average is 5.7) across its projects in the oil, gas, and mining sectors.

The method is also environmentally superior to trenching and ditching through a significantly narrower construction corridor. It can achieve outcomes within a 12–15 m right of way, far narrower than the conventionally-trenched 30 m allowance. In addition, a minimal work area is required, which significantly reduces the area to be reinstated. The adapted Spiderplough uses a blade to carve

aside earth and insert the pipeline during its pass over. This eliminates the need to remove or replace any top or subterranean soil, requiring only a light-grade post-installation to return the ground area to its former condition.

A key player in the active Australian coal seam gas gathering market, MPC today has the world’s largest fleet of Föckersperger Spiderploughs offering an inherently superior pipeline construction system. The leading-edge technology has been heralded as an industry-changing innovation, which delivers a positive balance between improved safety, high levels of pipeline construction productivity, cost reduction, and improved environmental performance.

operation, and to assess its viability for larger-diameter installations.”

A wide range of enhancements have been added to the ploughs, including a radical redesign of the pipeline-loading process to allow a pipeline to be loaded at ground level rather than at height, designing pipe couplings to safely handle larger pipelines of up to 24.8 inches in diameter, installing GPS equipment to ensure buried services were not disturbed while ploughing, and increased operator safety through step ladders, safety guard rails, and easily accessible safety-shut-off switches.

The Spiderploughs use a specially designed all-terrain, all-weather, winch vehicle to pull the plough using a cable. A blade on the plough forms and clears the laying bed to specific depths of up to 2.8 m, and the machine’s movement is accurately guided using GPS technology.

The plough’s ripper and pipe-insertion unit is pulled through the ground and the pipe is continuously laid. As the machine moves forward the narrow slot in the earth is quickly closed and compacted. The pipe is installed in a single pass: among the advantages over conventional installation systems is that the latter may require several passes.

Efficiency, safety, sustainability MPC’s continued investment into research

and development of the technology has produced considerable advances in performance, and at the end of 2013, QCLNG’s project crews were able to install an impressive 250+ km of 24.8 inch diameter HDPE pipeline each month.

Utilisation of Spiderplough technology for trenchless installation has been proved to offer significant efficiencies for MPC over conventional trench techniques. Evaluation data indicates many advantages, including fast and cost-effective pipeline installation, higher levels of safety through a closed trench system, improved environmental performance due to a narrower construction corridor, and less site preparation and ground reinstatement. Spiderplough has the ability to operate in all terrains and climate conditions, and as a result of the successful introduction of GPS guidance systems, is able to ensure accurate pipeline route installation.

The Spiderplough has been able to achieve significantly increased productivity rates for HDPE pipeline installation. Of particular note is the installation of 10+ km of dual 12.4 inch, 3.5 km of 24.8 inches, and an impressive 17.2 km

REGION REVIEWREGION REVIEW

Spiderplough achieves daily productivity rates of up to 17.2 km using a range of 110mm to 630mm HDPE pipeline.

Industry representatives turned out at a field day demonstration to see first-hand the installation of the 630 mm HDPE pipeline using the Spiderplough technology.


Spiderplough technology heightens safety performance, improves sustainability and reduces costs by up to 50 per cent.

The plough’s ripper and pipe insertion unit is pulled through the ground and the pipe is continuously laid.

The MPC fleet is deployed on projects across the Surat Basin in western Queensland.

Spiderplough has the ability to operate in all terrains and climate conditions, and as a result of the successful introduction of GPS guidance systems, is able to ensure accurate pipeline route installation.


Nacap has been active in the oil and gas, water, slurry, power, and telecommunication sectors in Australia for 15 years, with offices in Melbourne, Brisbane, and Perth, as well as a plant yard in Roma, Queensland. Pipelines International finds out more about this ever-expanding company, and some of the projects with which it is currently involved.

Nacap is part of Quanta Services Co, a US-based S&P 500 company with $US6 billion in revenue in 2012. Quanta

Services is a leading provider of specialised contracting services, delivering infrastructure solutions for the electric power, natural gas, pipeline, and telecommunication industries.

With an excellent safety record, and proven ability to provide a wide range of services from project management and design, to construction and commissioning, Nacap is a leading pipeline and horizontal directional drilling (HDD) construction contractor. Nacap’s clients include some of the largest

asset owners in Australia, as well as major multinational and Australian organisations in the LNG, oil, gas, and mining sectors.

Contract values range from $US2 million to in excess of $US500 million on the basis of construct only, and engineering, construction, and procurement, packages under an array of commercial frameworks.

Current projects in focus for NacapNacap has constructed over 3,000 km of

pipelines in Australia, ranging from small-diameter steel/HDPE gathering/flowlines to larger-diameter welded-steel transmission

pipelines. Nacap has also constructed long-distance power-transmission and telecommunication assets.

Although the company has constructed small pipelines of steel and HDPE over short distances for strategic clients, the bulk of Nacap’s work involves the delivery of larger pipelines with diameters of up to 2 m and lengths approaching 1,000 km.

Nacap’s latest activities in Australia include the Western Tranche Project, which involves the construction and testing of 71 km

REGION REVIEW

Nacap setting the benchmark for pipeline construction in Australia

Nacap works on the Woleebee Project.


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of DN450 and 55 km of DN600 high-pressure gas pipelines and associated end-line facilities in Queensland.

This project is expected to be completed in early 2015.

Also under construction is a Cooper Basin Project involving the construction and testing of 40 km of DN100-DN350 gas flowlines and associated end-line facilities, including 13 flowline manifolds.

“Working in the pipeline industry isn’t for everyone, but the things that I enjoy most are that no two days are ever the same,” explains Nacap’s Corporate HSE Manager Paul Whyte.

“We are always on the move, seeing different parts of the country and wildlife that most people never get to see. We get to meet people with different views, backgrounds, and stories to tell.

“I would have to say the best part is the camaraderie and mateship that is developed throughout time.”

Setting a benchmark for operations and logistics

Nacap has the logistical experience for the successful completion of projects in remote regions throughout Australia. Success is achieved with its highly-skilled and dedicated workforce, extensive plant and equipment resources, and robust financial backing.

Nacap owns a large fleet of modern and well-maintained specialised pipeline construction equipment including pipelayers, bending machines, trenchers, welding/coating tractors, and hydrostatic testing and air-drying equipment.

Nacap has significant local insight into the issues and opportunities for sustainable delivery of linear infrastructure. The company has successfully completed pipeline installation of the 392 km North Queensland Gas Pipeline (NQGP) for Enertrade from Moranbah to Townsville, which proved to be a benchmark

project in relationship contracting. Nacap has also delivered the QSN3 (Stage 3) expansion of the 938 km Queensland and South Australia pipeline system for Epic Energy.

This repeat business builds on Nacap’s previous successful delivery of Epic Energy’s QSN Link Pipeline, demonstrating client satisfaction with Nacap’s execution and testament to the integration, trust, respect, and co-operation achieved on this fast-track ECI project.

Nacap’s senior management and project personnel have extensive experience in collaborative contracting. The ability of the team to integrate into its client’s organisations and understand key project drivers is integral to in the company delivering real value. According to Nacap President Mark Bumpstead “there is no learning curve at project start-up. It is an integrated, total, package that makes the difference when it matters most.”

People powerNacap says that its differentiator is its

people, who are enthusiastic and results orientated; combined with their expertise and proven capabilities, the company has developed lasting relationships with clients, suppliers, and subcontractors – thereby creating repeat business. Working at Nacap means you mix with, and talk to, people at all levels. Nacap’s people enjoy a wide-range of different careers: project engineering, estimating, project control, scheduling, document control, quality control, facilities’ management, safety, total quality management, commercial and contracts’ management, risk management, procurement, land liaison, environment, finance, administration, marketing, and human resources.

Due to the nature and size of Nacap, it is an ideal place to gain a breadth of experience and opportunities that are not always available in larger organisations.

A new user and 15-year veteran of vacuum-lifting technology share their respective experiences with Vacuworx Lifting Systems on the docks in Melbourne, Australia, and in the field.

Vacuum-lifting technology is bolstering efficiencies on the docks and in the field for two Australian companies

tasked with handling the coated-steel pipe that is feeding a 28 km stretch of APA Group’s Victorian Northern Interconnect Expansion (VNIE) project.

The product – DN400 2LFBE-coated carbon steel gas pipe – was manufactured by Shanghai-based Baosteel Group, and began landing in March at QUBE Energy’s on-wharf facilities in the Port of Melbourne. Bound for a VNIE staging point managed by McConnell Dowell

Constructors Pty Ltd and approximately 27 km north of Melbourne, QUBE Energy had been relying on a third-party crane contractor to lift and help secure the pipe lengths – measuring 16 inches diameter – onto tractor trailers for transport to Wallan in country Victoria.

QUBE Energy – formerly known as Continental Freight Services and a division of port logistics services provider QUBE Ports Pty Ltd – had been relying on a material-handling method to load the trucks that required the use of a crane, a spreader bar, and hooks with straps or chains. In March, the company made

a decision to try-out vacuum-lifting technology, subsequently entering into an agreement to lease an MC 5 Series pipe-handling system manufactured by Tulsa, Oklahoma-based Vacuworx.

QUBE Energy is relatively new to the use of vacuum-lifting equipment, while McConnell Dowell, who announced in February that it had been retained by APA Group to construct Loop 1 of the VNIE project from Wollert to the Wandong Offtake in Victoria, has nearly 15 years of

REGION REVIEW

Lifting Australia’s pipe loadsBy Todd Razor, Three Razors, Des Moines, Iowa, USA

REGION REVIEW


NACAP’S PIPELINE INITIATIVES AND AWARDS

YEAR BODY AND CATEGORY INITIATIVE

2014 Quanta Services CEO Innovation and Entrepreneurship Award Code Safe Videos

2013 Australian Pipeline Industry Association (APIA) – Safety Award Code Safe Barcoding

2013 International Pipeline & Offshore Contractors’ Association (IPLOCA) Health and Safety Award Code Safe Barcoding

2013 WorkSafe Victoria (Finalist): Best solution to a specific workplace health and safety issue Hydraulic pig catcher

2011 Australian Pipeline Industry Association (APIA) – Safety Award Hydraulic pig catcher

The QSN3 Pipeline Project.

Nacap teamwork in action on the Victoria Desalination Pipeline.

Nacap have won awards for their Code Safe Barcoding initiactive.



An employee of QUBE Energy uses a Vacuworx MC 5 to load 16 inch gas-transmission pipes from the port holding area in Melbourne and onto trucks bound for a VNIE staging area in Wallan.

conjunction with compact carrier equipment, such as wheel-loaders or forklifts, according to the manufacturer.

“I watched the operator on QUBE’s wharf place his hands on the MC 5’s wireless remote control for the very first time,” Mr Guevara said.

“That initial lift appeared so natural, and it was satisfying to know the lifts we were performing in Melbourne would be reversed engineered, so to speak, when McConnell Dowell uses an RC 10 to unload these same trucks in Wallan. It’s interesting to see both sides of the vacuum-lifting equation from both an industrial setting and in the field.”

McConnell Dowell is one of Australia’s leading pipeline contractors operating worldwide and to date has delivered more than 200 projects totalling more than 30,000 km across Australia, New Zealand, Asia, and the Middle East. The company has also been using an RC 10 Series lifter to assist with handling 6 inch gas pipe for a 20 km gas pipeline project in the heart of Moomba, South Australia.

The initial stage of the VNIE includes the installation of two main line valves and end-of-line cross ties to existing DN300 pipeline. The project is scheduled for completion in June.

According to Vacuworx, the company has been busy building up a qualified network of distribution points and relationships in oil, gas, and other top energy or utility-oriented industries while stockpiling machines to serve markets in North America, Latin America, Australia, the Netherlands, and elsewhere. The manufacturer’s most recent product launch in May was a lightweight HDD pipe-handling system capable of lifting and positioning drill-stem in a rig via wireless

remote control at angles between 0 and 30 degrees.

Australia’s largest natural gas infrastructure business APA Group owns or operates $12 billion of energy assets with gas transmission pipelines spanning every state and territory on the mainland. APA developed a $US187 million proposal to expand its Victorian infrastructure to enable more gas to flow north into northern Victoria and New South Wales from southern supply basins.

Sections of the existing pipeline will be looped, including the Wollert Wodonga West Pipeline, to increase capacity, as well as increasing compression capacity north and south of the VNIE project.

experience with heavy-duty material-handling systems. Since March 2014, McConnell Dowell has been running two Vacuworx RC 10 Series pipe-handling systems – in conjunction with Komatsu CP300 excavator host equipment – to unload at a yard in Wallan, and string a stockpile of nearly 1,700 lengths of gas-transmission pipe along the right-of-way.

“We only need an operator and one additional worker to pick up the pipe and load or unload a truck,” said Darren Hayes, the McConnell Dowell plant and logistics manager responsible for ensuring safety and efficiency on the company’s sites in Australia.

“It’s a faster method, which is among the main reasons we continue to use Vacuworx product.”

Ken Colwell, an operations and project manager with QUBE Energy, said that he found the necessity of having to hire a crane was a “repetitive exercise”, and less cost-efficient than using company-owned assets and personnel. That ultimately led QUBE Energy to its trial of the Vacuum Lifting Systems.

“We had the equipment on-site,” he said. “We just needed a way of adapting it to lift pipe. That’s where the Vacuworx product was discovered. Now, instead of dealing with the cost of leasing a crane, we’ve actually improved our ability to perform more precision-lifts, while bolstering safety and lowering our expenses at the same time.”

QUBE Energy was working to boost efficiency by minimising the use of staff on the

wharf in Melbourne, yet Mr Colwell noted that the company was most interested in the safety aspect of vacuum-lifting technology, as it poses less risk to workers on the ground in nearly all weather conditions.

“There are no booms overhead or slings and hooks moving in the air,” he said.

“Everyone can see what’s going on, and now our operation can continue, even in wind or rain. It’s a much simpler operation.”

Though cranes have the ability to lift multiple pipe lengths at one time, Mr Colwell said, one advantage QUBE Energy has realised with the Vacuworx system is that it mitigates damage to pipe coatings, while features such as a 360-degree hydraulic rotator and wireless remote control allow for the precise placement of materials into scalloped timber cradles on the awaiting tractor-trailers.

“There are no hooks or collisions,” Mr Colwell said.

“It just doesn’t get damaged. The lifter picks up in the centre of the pipe, crimps down, and gives our operator complete control. Now we can get away with a forklift operator and one spotter or a two-man team, saving on one labour unit while still achieving the results we need.”

In an analysis of the global market for construction equipment, market-intelligence provider Grandview Research said that options to lease construction equipment are expected to drive cost effectiveness and fuel market growth as advances in technology lead

to machinery that “offers considerable benefits over mechanical equipment.” Applications that aid in meeting regulatory emission standards, as well as safety issues related to the mishandling of equipment, were each noted as areas of interest or concern.

In total, Mr Colwell confirmed that six ships carrying nearly 9,000 pipes either have been or will be routed from China, and through QUBE Energy’s wharf facilities for use in Loop 1 of the VNIE – as well as the future looping projects as part of APA Group’s construction of the larger Victorian Transmission System. The QUBE Energy team has been averaging the transport of about 90 pipes over the course of an 8 or 10-hour window, with three drivers each making round-trip journeys of approximately 250 km per workday. By late-April, they had delivered about 3,700 pipe lengths, including shipments to McConnell Dowell’s pipe yard in Wallan, as well as a staging area in Tallarook, Victoria and future shipments intended for a site in Benalla, Victoria.

Vacuworx is a US equipment manufacturer that recently opened a dedicated office in Brisbane, Australia, near one of 16 Sargent dealerships in the country that stock, maintain, and service its products. Luis Guevara, Vacuworx Business Development Manager in the Brisbane office, travelled to Melbourne and met with Sargent Product Manager Daron Wintzloff to help train an operator and to commission QUBE Energy’s new MC 5, which boasts a lifting capacity of 5 t. The MC 5 Series vacuum-lifting system is best suited for use in

REGION REVIEW REGION REVIEW

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OPERATIONS & MAINTENANCE• Pipeline and station O&M• Incident reporting• Integrity program management• Emergency response• Landowner liaison• ROW patrols & easement maintenance• Training.

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Staff looked on in March as a forklift operator trialled the use of a Vacuworx MC 5 pipe-handling system at QUBE Energy’s on-wharf facilities in Melbourne, Australia.


“It just doesn’t get damaged. The lifter picks up in the centre of the pipe, crimps down, and gives our operator complete control.”

– KEN COLWELL, QUBE ENERGY


the team when rules are broken, for example: • Is the right-of-way too close to a house? • Are valves appropriate for tie-in points?• Does the pipe sizing match the flow-

assurance modelling? Currently KEGS has over 100 automatic

integrity checks and these can be added to or modified with any new project. And the development is ongoing, explains Mr Axelby. “Early in the piece we did not have integration with flow assurance and did not use KEGS for cost estimating.

“It was simply not in our scope. It now is, and by doing so, we’ve streamlined the design process even further.”

Tools and reportingMr Axelby says that modernising the

service delivery was not about building yet another piece of software. It was about the end-to-end process: looking at the roles and relationships, looking at how the information supply chain could be improved, and taking a data-centric approach to field design.

“We found engineers loved using Google Earth and would provide hard copy maps or kml files to the design team” says Mr Axelby. “So we built KEGS with a 2D (and 3D) map interface plus software tools so they could perform the design themselves.”

Another deliberate strategy was to automate reporting as much as possible. GIS software for the generation of alignment

sheets has been around for some time, but rarely is the data centralised. This means that incorporating change is still laborious because the information sits in many GIS files. With the KEGS relational database as a single ‘point of truth’, deliverables such as alignment sheets can be generated via a single report from the database, and review of the sheets can be completed on-screen before printing.

Modernising the business modelBy embracing technology in this way OSD

is also changing its business model. Traditional service-delivery companies are

man-hour businesses and, for them, large teams are a prerequisite. This is unproductive, outdated, and inefficient. Innovations such as KEGS are a deliberate strategy for OSD to offer smarter engineering services with lean integrated teams. Engineering is not a creative art: it is based on rules and standards, and requires transparency and consistency. This makes it ideally suited to software automation and cloud-based efficiencies.

Mr Axelby says “OSD’s direction is technology. We intend to lead. It’s up to the others to decide whether to follow. We hope they do.”

The mainstream approach to route selection and gathering system design has changed little in the last decade. OSD, a technology focussed pipeline engineering company, is seeking to change this via new GIS-based collaborative software, recently used for two multi-billion dollar coal seam gas-to-LNG projects in Queensland, Australia.

Knowledge engineering for geospatial systems (KEGS) is a GIS-based collaborative platform for route

selection and integrated gathering-system design, and can be used to support operational management of the asset. Using a combination of lean manufacturing philosophies, agile software, and geospatial technologies, the software enables designers and operators to streamline and automate the design process in ways that until now have not been possible.

Typically, project knowledge and data is spread across team members, disciplines, and even organisations in delivering the project. KEGS brings this together into a web

and mobile interface with an embedded set of rules, workflows, design tools, and automated deliverables.

This results in lean and integrated teams working together, enabling:• Shorter project lifecycles;• Reduced social and environmental impacts;• Lower construction costs; and,• Reduction in operating costs.

KEGS has been used on large gathering-system developments including two multi-billion dollar coal seam gas (CSG) to LNG projects in Queensland, Australia.

KEGS is designed for project team members without the need for specialist CAD or GIS skills.

It is open-source technology and therefore vendor neutral. It conforms to the PODS pipeline data model, and can accommodate already- established data models within an organisation. As a result it is reconfigurable and is constantly being enhanced to further meet clients’ needs.

OSD General Manager Martin Axelby explains “It’s about speed. With KEGS we can ramp-up faster, design faster, and close-out the design stages faster.”

Technology and analyticsKEGS is built to be specifically fit-for-

purpose for gathering systems and pipelines. The relational database stores the business rules, library codes, and regulatory constraints. This means the software can automatically generate the routes and trench configuration as well as placing fittings and erosion control. The database performs automatic checks on the design and notifies

REGION REVIEW

CSG in focus: modernising the gathering system design process

REGION REVIEW

Benefits of the KEGS system • It has been built by engineers• Allows one ‘point of truth’ from concept to operations• Data are easily transferred from stage-to-stage• Allows rapid reconfiguration/evaluation of alternates• It is a simple, high-quality, low-cost, rules-based process• It is available online and via mobile apps, bringing the field and the office together• It is open source and can conform to any standards/formats• GIS is used for reporting (not manual, stand-alone editing).

The KEGS menu bar.

Delivery process maturity. KEGS process flow.

“OSD’s direction is technology. We intend to lead. It’s up to the others to decide whether to follow. We hope they do.”

– MARTIN AXELBY, OSD GENERAL MANAGER


Houston-based Clarion Technical Conferences and Tiratsoo Technical, a division of Great Southern Press, are offering a variety of practical pigging training courses throughout 2014, allowing great opportunities to expand your industry knowledge.

The knowledge and technology to improve pipeline performance is expanding constantly, and courses are a

great opportunity to update and broaden your knowledge, as well as meet industry peers and experts. Courses on offer in 2014 include:

Perfect your pigging knowledge

PIGGING

EXPAND YOUR PIGGING KNOWLEDGE

Make 2014 the year to broaden your pipeline knowledge and skills. For more information on all the above training courses, visit the Clarion Technical Conferences website: www.clarion.org

Onshore Practical Pigging Training 17–19 June 2014 TRICHT, THE NETHERLANDS

Presented by Penspen This training course provides a wide-ranging overview of all aspects of pigging operations for onshore pipelines. The site is A.Hak Industrial Services’ test loop facility in Tricht, The Netherlands. The facility has a 150 m, 12 inch water-driven pipeline, and a second 150 m, 24 inch line under construction. During the three days, the participants will typically participate in up to nine different runs of various tools.

Pipeline Pigging & Integrity Management Conference and Exhibition 9–12 February 2015 MARRIOTT WESTCHASE HOTEL IN HOUSTON, TEXAS

PPIM is a must-attend event on the international pipeline industry calendar, with its unique structure consisting of training courses, a detailed two-day conference programme, as well as an Exhibition that allows the whole pigging industry to gather in one place. Attendees meet with some of the best in the industry and discuss issues and developments in the pigging arena, one-on-one. PPIM is the one-stop event for those interested in pipeline pigging and integrity management, offering an unparalleled opportunity for those wishing to learn and share knowledge of the latest tools and services that keep pipeline assets safe and reliable.

Practical Pigging Training 1–5 September 2014, RIO DE JANEIRO, BRAZIL

Presented by PenspenThis training course provides the opportunity to get first-hand knowledge and a wide-ranging overview of all aspects of pigging operations. The course will be held at the CTDUT facility adjacent to Petrobas’ Duque de Caxias refinery, near Rio de Janeiro. The course uses CTDUT’s 14 inch, 120 m long, water and nitrogen/air-driven test loop at the site.During the five days, the participants typically perform up to nine different runs of various tools.

Subsea Practical Pigging Training 16–18 September 2014, BERGEN, NORWAY

Presented by Penspen and KTNThis training course will provide an extensive overview of all offshore aspects of pigging operations.The syllabus includes both hands-on exercises using the KTN test loop, as well as classroom instruction, and full documentation.

Pipeline Integrity Courses 1–5 December 2014 WESTIN CALGARY HOTEL, ALBERTA, CANADA

An intensive curriculum covering the latest in pipeline inspection and maintenance especially designed to facilitate regulatory compliance and operational excellence.December 1–2: Pigging and In-line Inspection December 1–3: Defect Assessment in PipelinesDecember 3–5: Defect Assessment Calculations WorkshopDecember 3–5: Pipeline Integrity ManagementDecember 4–5: Geohazard Management for Pipeline Engineers

Pipeline Integrity Courses 10–14 November 2014 HOUSTON, TEXAS

10–12 November: Pipeline Repair Methods, Hot Tapping, and In-Service Welding10–12 November: Pipeline Integrity Management12–14 November: Advanced Pipeline Risk Management13–14 November: DOT Pipeline Safety Regulations - Overview and Guidelines for Compliance


Thousands of features can be identified from a single in-line inspection. Due to resource constraints, the selection and priority of excavations requires significant effort and scrutiny. C-FER Technology’s Research Engineer – Integrity and Operations Dongliang Lu explains how best to decide which features require excavation.

In-line inspection (ILI) tools have been used by operators for many years to inspect operating pipelines for the

presence of pipeline features, and modern ILI tools detect and size various types of feature. After the ILI is completed, excavation of pipeline sections are carried out to address important features as identified by the tool and to verify the tool’s performance.

Given a detected feature, there are two types of errors that can arise, shown in the table on

the opposite page. The first type of error, a type-I error, is when a critical feature exists, but is not excavated because the ILI tool underestimates the severity of the feature. The second type of error, a type-II error, is when there are no critical features but the pipe is still excavated because the tool overestimated the severity of the feature, or the excavation criteria were too stringent. Type-I errors decrease reliability, whereas type-II errors add extra cost with little improvement to reliability.

Optimal selection of verification digs for in-line inspectionBy Dongliang Lu, Research Engineer-Integrity and Operations, C-FER Technologies, Canada, Edmonton.

PIGGING

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2013_Sept_Pipelines International_PIRAMID_Curved_resize.pdf 1 2/05/2014 9:17 am Dongliang Lu.

In the current practice, a fixed threshold is applied to determine if an excavation should be carried out. If severity of a feature, as reported by the ILI, exceeds this threshold then the pipeline section containing that anomaly is excavated and the severity of the anomaly is assessed. As illustrated in Figure 1, the probability of a type-I error decreases as the threshold size decreases, but at the price of having a higher chance of type-II errors. The shortcoming of the current approach is that the excavation threshold is defined prior to the ILI, and cannot be adjusted with respect to the characteristics of the pipeline under inspection and the actual performance achieved by the tool. To ensure that critical features are addressed, operators may choose a stringent excavation threshold, resulting in many excavations that do not require immediate repair. Some operators have attempted to adjust the threshold size

crudely if excavation data suggest that the predefined threshold is overly conservative. However, such crude adjustments are usually based on experience, and lack a scientific basis.

To overcome the shortcoming of using a fixed excavation threshold, a probabilistic approach was developed. This approach allows the operators to adjust the excavation threshold for a specific case according to properties of the pipeline under inspection and the actual performance of the tool. One of the key challenges of the new approach is to accurately assess the probabilities of having type-I and type-II errors for any given excavation threshold. This is done by conducting trial excavations for the most severe features reported by the ILI tool, and using the data to determine the relationship between the two types of error. The excavation threshold can then be selected by using a

cost-effectiveness model to optimise excavation selection and priority.

This new approach of selecting excavation threshold keeps operators risk-informed about excavation decisions. With the application of the new approach, operators can optimise the excavation threshold to achieve a consistent reliability level in ILIs, while at the same time lowering the associated costs.

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For more information, visit C-FER’s website at www.cfertech.com

Has critical features No critical features

Not to excavate Type-I error Correct

Excavate Correct Type-II error

Figure 7. Probability of type-I and type-II errors.


The connection between the pumping vessel and the platform is usually made (and maintained) during the approved weather window, as specified by the client’s marine department. This weather window is crucial, as it ensures the safety of the interface between the pumping vessel and the platform. Rough weather or sea conditions may cause stress on the hose connections, due to sea level changes, and may cause damage to both personnel and assets.

Extra-reinforced high-pressure hoses are used during pumping activities from vessels. Suitable quick-disconnect couplings are used (in a dual-redundancy set-up) to ensure a quick and safe disconnection from the platform should the weather change unexpectedly, endangering the pumping activity.

However, the most important advantage is the nitrogen pumping capacity. Pumping from platforms limits the volume of liquid nitrogen that can be used, since the offshore rated tanks are only 7600 li capacity each. Pumping

from vessels, however, does not have this limitation, since the larger-capacity onshore tanks have a volume of 20,000 li each. This ensures a larger, steady supply of nitrogen for pumping at rates of up to 15,000 m3/hr for up to six hours, and this high flow rate is crucial for larger-diameter lines.

Asphyxiation due to excessive amounts of nitrogen around the working area is a notable risk of using such large quantities of nitrogen. This risk is mitigated by ensuring that the vent point is elevated (usually at the top deck) to a height suitable for a full dispersion of nitrogen. PNS usually performs a dispersion-modelling calculation and recommends a suitable height/location for nitrogen venting.

Using nitrogen as a propellant during pigging may very well be the most viable option for lines which have a low flow rate and pressure. Nitrogen as the propellant also eliminates the need to worry about waste disposal and contamination of the sea (and potential harm to aquatic life). The nitrogen

exiting the receiving end can be vented to atmosphere without any adverse effects to people or the environment.

After all, the atmosphere is made up of 78 per cent nitrogen.

The use of nitrogen as a pigging propellant in offshore applications is usually not considered due to the incorrect impression of needing a large footprint for the pumping equipment.

However, nitrogen pumping for offshore applications – whether purging, pressure-testing, leak

testing, or pigging – is a service which Pipeline Nitrogen Services BV (PNS) has been providing to clients, including Total and NAM, in the North Sea sector for the past eight years.

PNS has performed several nitrogen pumping projects for in-line inspections, which require a constant, controlled, pressure and flow rate to ensure optimal data quality.

As pigging activities are usually performed during shutdown campaigns, it is understandable that storage space on platforms would mostly be taken up by equipment required for the shutdown work. In consequence, nitrogen pumping is usually performed from nearby vessels (work barges or supply vessels), to minimise the space taken-up on the platforms. The nitrogen pumps, liquid nitrogen storage tanks, and other equipment is placed on the work barges (or supply vessels) and sea fastened

at the port area, before sailing to the location. All rig-up work is performed either in harbour or during sailing, to ensure minimal downtime once the vessel reaches the intended location.

Full and complete HAZOP (hazard and operability study) and SIMOPS (simultaneous operations) analyses are performed before each pumping activity, to ensure all risks associated with the activity are correctly identified and steps taken to eliminate those risks or, at the very least, to mitigate the risks to an acceptable level.

Nitrogen pumping for offshore piggingBy Sharmini V. Jayaraman, Pipeline Nitrogen Services BV, Groningen, Netherlands

PIGGING

Pipeline Nitrogen Services BV is a full member of the Pigging Products & Services Association.

A typical set-up for nitrogen pumping from a work vessel.

PIGGING

Rough weather or sea conditions may cause stress on the hose connections, due to sea level changes, and may cause damage to both personnel and assets.


surveys, and pre-commissioning. The water depths along the pipeline route range from 137 m to 146 m.

Subsea engineering challengesField surveys carried out prior to work

commencing on the Rochelle fields indicated soft clay seabed soil and multiple pockmarks (seabed depressions) throughout the field. This resulted in detailed engineering analysis to ensure adequate pipeline support at the trench transitions and crossings. Feedback from both the survey and the trenching vessels initially on the field enabled Technip to identify and correlate the information required to ensure an efficient offshore construction operation.

Technip used its extensive trenching database to predict the risks of trenching in very soft to soft clay. Shorter transition lengths at the transition-in and-out locations, as well as buoyancy and soft-soil skids, were implemented to prevent excessive sinkage. The soil-bearing capacity for the mid-span support to allow the 10 inch/14 inch pipe-in-pipe to cross two 30 inch pipelines was also

assessed, and a stress analysis was carried out on the 30 inch pipeline (using ABAQUS finite-element analysis) to evaluate possible soil settlement in order to ensure the pipe was not at risk of buckling.

Breakthrough in pipelay technologies

The Rochelle project demonstrated a breakthrough in pipelay technologies. Technip’s recently upgraded Evanton spoolbase was used for both the fabrication and spooling of the 10 inch/14 inch pipe-in-pipe. The size and wall thickness of the pipe-in-pipe used for the project had very high stiffness levels, and the project

team developed innovative engineering solutions in order to facilitate reeling the fabricated pipe-in-pipe on to Technip’s pipelay vessel, the Apache II. The detailed and comprehensive onshore activities contributed to an extremely successful offshore campaign.

Technip’s revised approach incorporated reelable and end bulkheads, a pawn head with split-head adaptor system to connect the pipe on to the vessel reel, and pipeline-fixed laydown lengths within the subsea target boxes. The development and introduction of the reelable bulkheads dramatically reduced the vessel’s offshore time, and also resulted in a reduced amount of welds and therefore non-destructive examination (NDE) being carried out offshore, decreasing the amount of time required to perform the connections onboard. The knock-on effect of these innovations was that the required weather window for pipelay offshore was also reduced.

As well as saving time offshore, the adoption of the pawn head and adaptor

With an increasing number of developments in deeper water and more challenging environments, infrastructure and its associated installation has to be adaptable and capable of coping with unique conditions.

The Rochelle area lies approximately 185 km north east of Aberdeen, and is a combination of two gas condensate

fields. The East Rochelle development –which was discovered in April 2000 – is located on Block 15/27, and the West Rochelle field, which encompasses blocks 15/26b and 15/26c, was discovered in October 2010. The Rochelle unit area is jointly owned by Endeavour International Corporation (44 per cent), Nexen Petroleum UK Ltd (41 per cent), and Premier (15 per cent).

In June 2011, Endeavour Energy UK, a wholly owned subsidiary of Endeavour International Corporation, awarded subsea specialist Technip an engineering, procurement, construction, and installation (EPCI) contract for the East Rochelle development. The contract scope encompassed full project management and detailed design, procurement, fabrication, installation, and pre-commissioning of 30 km of production pipe-in-pipe, flexible riser, free-issue umbilicals, and subsea isolation

valves and manifolds. It also included construction and tie-in of spools to the wellhead structure, trenching, backfill, and rockdumping work. A further contract award for a 7 km extension to connect the West Rochelle well to the East well followed the initial agreement. Both wells are tied-back to the production facilities on the Scott platform through a subsea isolation valve umbilical (SSIV) and manifold. Other work included platform flexible and umbilical pull-ins and commissioning, crossings’ installation,

Revolutionary pipe-in-pipe installation for the Rochelle ProjectBy Harry McIntosh, UKBU Project Manager, Subsea Construction, Technip UK, Aberdeen, UK

OFFSHORE OFFSHORE

THE ROCHELLE PROJECT750,000 man-hours

0 incidents

9 vessels

37 km pipe-in-pipe installed

in 25 days

The Skandi Arctic.



system minimised the amount of time the vessel spent in port while the pipe-in-pipe was reeled and loaded on to the vessel. Fixed laydown lengths subsequently saved time on vessel topsides’ work during the laydown of the pipe-in-pipe. The savings to the vessel in terms of operational time at the spoolbase were in the region of 15 per cent.

These innovations resulted in the installation of the pipe-in-pipe being carried out in record time. The Apache II was deployed to undertake the installation and took five trips – lasting a total of 25 days – to lay the required 37 km of pipe-in-pipe. This represents a reduction of approximately 32 per cent against the initial time estimate for this work.

The ability to reduce the in-field laydown times for each trip was particularly valuable, as some of the work took place during the winter months. Traditionally, operations carried out at this time of year are subject to fewer and smaller weather windows due to wind speeds and sea states that are incompatible with the necessary operations.

International resources and client relationships

Resources from across Technip were used to fulfill the contract. 37 km of Technip’s innovative rigid, reelable pipe-in-pipe were welded at Technip’s spoolbase in Evanton, while the flexible riser was manufactured at the company’s flexible manufacturing unit in Le Trait, France.

International mobility within Technip was key to the success of the project. The

Rochelle project team was made up of staff from Australia, Canada, Malaysia, Nigeria, Norway, and the UK. Drawing from Technip’s global team ensured the right skillsets were available as and when they were required. In addition to ensuring the project was delivered safely with no lost time incidents, on time and within budget, this approach gives Technip the opportunity to ‘take it further’. It presents new challenges and exposes them to different environments in terms of geography as well as functional and segmental diversity.

Endeavour Energy UK’s CEO William L. Transier recognised this effect whilst working with Technip.

“Technip’s installation performance and attention to HSE at the Rochelle development has been excellent,” he said.

“Innovations in pipelay technologies introduced by the integrated Technip/ Endeavour teams established the ability to complete the work scope in record time and within budget.

“The successful installation performance, even during the winter months, demonstrates the value Endeavour sees in partnering with companies like Technip to create innovations that benefit the entire industry.”

Work on the Rochelle project to date has been completed in 750,000 man-hours with no recordable HSE incidents or accidents. Innovation combined with clear and effective communication between all involved in the project from Technip, Endeavor Energy UK, and third-party contractors ensured the smooth

running of the project and the record-breaking delivery of the pipe-in-pipe installation.

Pipe-in-pipe fabricationIndividual 12 m lengths of pipe are

fabricated into pipe stalks at Technip’s custom-built Evanton spoolbase in the Cromarty Firth. Following numbering and a pre-weld inspection, the pipes are rolled on to an alignment welding station, where the ends are pre-heated. This is the start of a welding line and cycle that welds the sections in to 1 km long pipe stalks. At predetermined cycle times, a new section of pipe is added to the stalk, and each joint receives the required amount of weld passes at up to eight separate stations.

WeldingWelding is crucial to the entire process and

the full range of mechanised and manual technologies are available. As the whole pipe-in-pipe fabrication process is onshore, the welding can be done in a controlled way to the highest technical standards and if there are any problems they can be dealt with quickly and effectively.

Weld inspection/non-destructive examination (NDE)

Following welding, the pipe moves through the visual weld inspection area to the non-destructive examination area. The primary examination techniques are traditional radiography, digital radiography, and automated ultrasonic examination, backed

OFFSHORE


The Skandi Arctic leaving Aberdeen.



OFFSHORE


up by manual ultrasonic, magnetic particle, and/or dye-penetrant inspection as required.

The coating of the weld area is the next stage in the process. This is carried out in the field-joint coating area; generally mechanised three-layer polypropylene tape wrap, injection moulded polyurethane, or polypropylene are used.

1 km pipe stalks are fabricated for both the outer carrier pipe and the inner flowline in a pipe-in-pipe application. The completed pipe stalks are stored on the stalk racks or on the causeway waiting for pipe-in-pipe assembly.

The assembly of pipe-in-pipe stalksTechnip has designed and manufactured

portable hydraulically operated pushframes to push the inner flowline pipe stalks into the outer carrier pipe stalks.

The carrier pipe stalk, fitted with a bell-mouth guide, is secured in a fixed clamp at one end of the pushframes, and the inner flowline pipe stalk is held in a sliding trolley clamp at the opposite end. There is a 4 m workspace between the two sets of clamps to allow the spacers and insulation to be fitted to the inner flowline. A hydraulic mechanism, capable of 100 tonnes of force, simply pushes one pipe stalk inside the other, 4 m at a time. It takes around 250 pushes to produce a 1 km long pipe-in-pipe stalk.

The completed pipe-in-pipe stalks are stored on the stalk racks or the causeway ready for spooling on to the reel lay vessel being used for the project.

SpoolingThe first pipe-in-pipe stalk is pulled

through a tie-in station situated within the hydraulic pushframe. It is pulled along the spooling rollers and through a set of approach rollers onto the vessel’s reel. A pawn-head/split-head adaptor system is then used to connect the larger carrier pipe lead string to the vessel’s reel. The next pipe stalk is then ready to be connected to the first. This is done in the hydraulic pushframe and involves first welding the two inner flowline ends together. Once NDE of the weld has been carried out, the stick-out areas are then covered with insulation. A fire-retardant blanket is fitted over the insulation before the landward carrier-pipe stalk is pushed over the inner flowline weld area. After completing the carrier tie-in weld, the trailing end of the inner flowline stalk is cut

to the desired 500 mm stick-out, rebevelled, and cleared by NDE ready for the next tie-in. The whole process is repeated until the required pipe-in-pipe pipeline is onboard the relay vessel in one continuous length, ready for deployment in the field. Each vessel trip is dependent on reel capacity, which in turn dictates either total pipeline weight or volume.

Apache IITechnip operates with some of the most

advanced pipelay vessels in the offshore industry. The Apache II, which was used during the Endeavour Rochelle project, plays a major role in delivering subsea infrastructure around the globe. Once offshore, advanced technology on-board the vessel delivers all of the additional

advantages of the reel-laying method. During the pipelay process, a pipe-straightener and -tensioner system are utilised prior to the pipe passing through a welding station situated on the ramp. Here anodes, valves, flanges, T-pieces, and miscellaneous equipment can be attached to the pipe as and when required. Thereafter, a monitoring system ensures lay-catenary parameters are maintained on deployment of the pipe. On multiple trip applications, subsequent tie-in welding, NDE, and field joint coating are carried out on the next trip as required.

With sophisticated dynamic-positioning systems and a range of offshore construction equipment, the reel-lay vessel can lay pipe with an unrivalled degree of accuracy in deep or shallow water and close to offshore installations.

The Evanton Spool Base.

The Apache II at the Evanton Spool Base.

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PIPELINES INTERNATIONAL | JUNE 2014 49

The Castorone is a unique vessel in that it will pre-assemble (weld) triple-joints inside the vessel before the triple-joint string is moved into the firing line for assembling into the main pipeline.

How will the offshore pipeline be stabilised?

Concrete coating is the primary means of stabilisation. Trenching and rock cover is also used within Darwin Harbour to protect the pipe.

Whereabouts is the pipe lay beginning and where will be the final stage of the pipe lay?

The installation starts at the Darwin end with pipe-lay progressing towards to Ichthys Field.

Firstly, a shore pull will be undertaken by the Semac-1 in Darwin Harbour, approximately 2 km north of Channel Island, to pull the

pipeline on to land. The Semac-1 will then pull away and lay approximately 130 km of the pipeline.

The Castorone will then be used as the main pipe-lay vessel to lay the remaining 760 km of pipeline to the Ichthys Gas Field.

What other contractors are involved in the offshore pipe lay?

Boskalis is the main subcontractor to Saipem and is responsible for all pipeline dredging, shore crossing civil construction, rock quarrying, and rock installation onto the pipeline.

How are the onshore facilities progressing, and when does INPEX anticipate that the pipeline will reach the onshore facility?

Construction of the onshore facilities is progressing well. Site clearance is complete

and civil works well advanced at the LNG facilities site at Blaydin Point, Darwin.

The Darwin Harbour dredging is nearly completed and the pipe lay is due to be completed in early 2016.

Will there be any tie-backs, spools, or additional flowlines associated with the offshore pipeline? And what onshore pipeline will there be, if any?

Yes. There are other pipelines associated with the Ichthys Project, including corrosion-resistant-alloy (CRA) flowlines and mono-ethylene glycol (MEG) pipelines which are located offshore at the Ichthys Gas-Condensate Field, as well as onshore pipelines.

OFFSHORE

The location of the Ichthys Field, off the coast of Darwin.A graphic of the onshore facility at Blaydin Point, Darwin, NT

The Castorone pipelay vessel.

See pages 50–51 for a visual overview of the Ichthys offshore pipeline.

A graphic of the central processing facility.

As far as offshore pipelines in Australia, it doesn’t get any bigger than the offshore export pipeline for the INPEX-operated Ichthys Project.

Once completed, the 889 km, 48 inch diameter pipeline will be the longest subsea pipeline in the southern

hemisphere. It will transport gas from the Ichthys Gas Field, located in permit WA-37-R in the Browse Basin, approximately 200 km offshore northwest Australia, to an onshore LNG processing facility located at Blaydin Point, Darwin.

Before leaving the gas field, the gas will undergo preliminary processing at the offshore central processing facility (CPF) to remove water and raw liquids, including a large proportion of the condensate. This condensate will be pumped to a floating production, storage, and offloading (FPSO) facility anchored nearby, from which it will be transferred to tankers for export.

Estimated reserves for the project stand at over 12 Tcf of gas and around 500 MMbbl of condensate. The project is initially expected to produce 8.4 MMt/a of LNG from two trains, 1.6 MMt/a of LPG and 100,000 bbl/d of condensate at peak. The facilities will include two 165,000 cubic metre LNG storage tanks.

The Ichthys LNG Project equity interest is INPEX (operator, 66.070 per cent), Total (30 per cent), Tokyo Gas (1.575 per cent), Osaka

Gas (1.2 per cent), Chubu Electric Power (0.735 per cent), and Toho Gas (0.42 per cent).

Saipem has been awarded the pipe-lay contract for the offshore pipeline, following-on from initial front-end engineering and design works undertaken by JP Kenny and AMEC. Boskalis is also subcontracted to Saipem to assist with associated pipeline works.

To catch up on the where the pipeline’s construction is at, Pipelines International spoke with INPEX General Manager External Affairs and Joint Venture Bill Townsend, who provided an update.

At what engineering phase is the subsea pipeline currently?

The entire linepipe has been produced and coated. Pipe laying is scheduled to begin in the middle of the year.

How many people does Saipem have currently working on the contract, and what is Saipem using to undertake the pipe lay?

Saipem has a team of approximately 50 people in its Perth office and has support for the engineering team from the Saipem offices in London, Fano (Italy), Singapore, and Rijeka (Croatia).

The newly-built Castorone fourth-generation pipe-lay vessel and the Semac-1 pipe-lay barge will be used for the shore pull and the shallow sections near Darwin, respectively.

Will INPEX be using any particular innovations for the installation?

The Castorone itself is a main innovation introduced to the Ichthys Project. Approximately 600 people will work on this vessel assembling on-board triple joints.

OFFSHORE

Innovation with the Ichthys offshore pipeline

The Ichthys Project’s onshore LNG facilities under construction at Blaydin Point, Darwin.

Bill Townsend.

DARWIN

WESTERN AUSTRALIA

NORTHERN TERRITORY

AUSTRALIA

ICHTHYSFIELD

PIPELINES INTERNATIONAL | JUNE 2014 5150 PIPELINES INTERNATIONAL | JUNE 2014

PROJECTS IN FOCUSPROJECTS IN FOCUS

The Ichthys Export PipelineThe INPEX-operated Ichthys export subsea pipeline will connect the Ichthys Gas Field, located approximately 200 km offshore northwest Australia in the Browse Basin, to an onshore processing facility located at Blaydin Point, Darwin, which will make it the longest subsea pipeline in the southern hemisphere and the fifth longest offshore gas pipeline in the world.

The pipeline will use 690,000 tonnes of steel 1.2 million tonnes of concrete coated pipeline

and will take

2 YEARS to manufacture 75,000 joints and coat with concrete, and 1 YEAR to install

THE ICHTHYS LNG PROJECT PARTICIPANTS

TOTAL (30%)

Tokyo Gas (1.575%)

Osaka Gas (1.2%)

Chubu Electric Power (0.735%)

Toho Gas (0.42%)INPEX (66.07%)

ESTIMATED RESERVES FOR THE PROJECT: Over 12 Tcf of gas 500 MMbbl of condensate

BY 2020 Australia is expected to become the world’s first or second ranked LNG exporting country

TRANSFERRED TO TANKERS FOR DELIVERY TO MARKETS

600 personnel will be required on the pipelay barge during the pipeline construction phase

In Darwin Harbour, from approximately 15 km from the shore crossing near Blaydin Point, the pipeline will be placed in a trench and covered with rock for added protection. This part of the pipeline will become an artificial reef just like the existing 500 km offshore Bayu–Undan pipeline which carries gas from the Bayu–Undan Field to the Darwin LNG plant at Wickham Point, operated by Conoco Phillips.

PRODUCTION AT PEAK: 8.4 MMt/a of LNG from two trains

1.6 MMt/a of LPG

100,000 bbl/d of condensate

The Ichthys Field represents the largest discovery of hydrocarbon liquids in Australia in 40 years

Ichthys LNG will be thefirst Japaneseoperated LNG projectin the world

FLOATING PRODUCTION STORAGE AND OFFLOADING FACILITY Condensate is then pumped to the FPSO.

CENTRAL PROCESSING FACILITY The gas will undergo preliminary processing to remove water and raw liquids, including a large proportion of the condensate.

ICHTHYS GAS EXPORT PIPELINE

42 inch

889 km


Following an upgrade in safety–class on a Canadian pipeline, T.D.Williamson was called in to handle hot-tap and plugging operations on a 30 inch diameter pipeline requiring relocation. The pipeline supplies one third of Canada’s population with gas, so it was imperative that the supply of gas was not interrupted.

Most people who have spent any amount of time in Canada will agree that it’s a scenic country. From the

Rockies in British Columbia, to the bays and estuaries of Nova Scotia, and the miles of forests, hills, and lakes in between, Canada is rich in natural beauty.

Canada is also rich in oil and gas. In fact, the nation’s estimated oil reserves rank third in the world, following only Saudi Arabia and Venezuela. Western Canada has the largest collection of oil sands. And the country is the fourth largest producer of natural gas, most of which flows from west to east through a 30 inch diameter pipeline.

The pipeline is responsible for supplying many of the nation’s gas companies and one third of Canada’s population. It is important, understandably, to keep the pipeline flowing at all times.

Compliance and the NEBIn early 2013, the operator of the 30 inch

diameter pipeline was handed a challenge: the

area around a section of its main pipeline received a safety-class upgrade, which required the company to relocate part of the line.

Canada’s National Energy Board (NEB) states in section 42 of its Onshore Pipelines Regulations that “if the class location of a section of a pipeline changes to a higher designation that has a more stringent location factor, the company shall, within six months after the change, submit the proposed plan to deal with the change to the Board.” The safety standards for each class are outlined in the Canadian Standards Association (CSA) Z662, a document that is updated approximately every four years.

“Safety–classes are based on a bunch of criteria – like population and proximity of residences to the pipeline,” explains Rebecca Taylor, a communications adviser at the NEB. “When a class changes, companies are required to mitigate any hazards related to their pipelines.”

In this specific case, a new subdivision was under construction near the pipeline, and

the developing area was too close to comply with the NEB’s regulations.

To help create a safer environment, the operator decided to cut-out a 274 m section of the pipeline and build a new section further from the developing area. In order to keep gas flowing, the pipeline would need to be isolated upstream from the construction area, and re-routed through a by-pass line.

The proposed worksite was in an environmentally sensitive area, and safety was of utmost concern. The new section of pipeline would run along the edge of a national park in Quebec, and near a Mohawk native reservation. In addition, any incident during the pipeline project would have dire political consequences for the operator and any other oil and gas companies that want to begin large projects in the region.

Double-block-and-bleedDesiring to maximise jobsite safety

without shutting down the line, the operator contracted pipeline service provider T.D.

MACHINERY AND EQUIPMENT

Regulation and re-routeing in Canada: a Stopple Train case study

Williamson (TDW) to handle the hot-tap and plugging operations. The operator’s specifications called for a double-block-and-bleed methodology.

Traditional double-block-and-bleed isolation requires two fittings, two hot taps, and two plugging heads. More taps on a pipeline means more risk, in addition to increasing set-up time and leaving more permanent equipment on the line. However, TDW’s Stopple Train system reduces the overall number of hot taps and plugging heads used in the operation by inserting two plugging heads through a single entry point in the line. The two sealing elements also provide greater safety. Once the seals are in the set position, a bleed port is placed on the line in between the two heads. The bleed is left open and monitored, and any product that escapes past the first seal goes into the bleed port and is removed from the line. The two seals provide a ’zone of zero energy’ and an extra layer of safety for the technicians working downstream on the pipeline.

“The redundancy provided by this method of double-block-and-bleed is very important to operators,” says Philippe Mari, Account Manager at TDW.

“The Stopple Train system uses half the amount of fittings, less equipment, smaller excavations, and it’s more cost-effective.”

In addition to saving money, performing an isolation using the system “makes the operation just that much safer,” says David Turner, Director of Hot Tapping and Plugging at TDW.

“It means fewer welds and less equipment on the lines.”

Under pressureRelocating this segment would be a big

job. Because work needed to begin within a few months to ensure it was completed before the safety-class change, a plan of action was created that included TDW building and testing new custom 30 inch Stopple Train equipment within ten weeks. Once the fleet was ready to go, the team mobilised to Quebec.

One of the supporting team members was Mr Turner, who contributed engineering calculations and analysis of the pipeline before beginning the isolation. “This particular operator is very thorough. They expect the highest degree of engineering, quality, and safety,” says Mr Turner.

“We worked together to make sure that the force on the plugging heads, created by

the flow of product, was well within the tolerance of the equipment.”

First-time successThe success of a traditional isolation job

hinges on creating a seal, but an acceptable seal is not always achieved on the first attempt. Mr Turner says that “one of the greatest advantages of the Stopple Train technology over traditional isolation techniques is that it greatly increases the likelihood of achieving an acceptable seal on the first attempt.

“Getting an acceptable first-time seal reduces the number of times you need to remove equipment from the line in order to try again. And as each attempt can take quite some time, especially when working with larger diameter lines, reducing that waiting time has a quantifiable value to operators.

“By providing a greater first-time success rate and less jobsite downtime, the Stopple Train system can even help reduce the cost of labour and machinery. It also minimises the number of times you need to handle equipment, which lowers the chances of damage or incident.”

After TDW achieved a 100 per cent seal with the system and completed the isolation, the gas was re-routed, and the job completed with no issues. Natural gas continued to flow through the temporary bypass, supplying Eastern Canada. By the end of the project, a new pipeline segment was completed, built at a safe distance from the new subdivision. The entire project was completed with minimal disturbance to Canada’s pristine natural environment.


For more information on TDW’s products and services visit www.tdwilliamson.com

A diagram of 30 inch Stopple Train isolation and by-pass.

30 inch Stopple Train plugging system prior to isolation.

30 inch sandwich valves being installed on the line.


Oil theft from pipelines is a major international issue, and it’s not just regions such as the Niger Delta – which attract high levels of media attention – that are affected. Recently we have seen instances of pipelines being tapped as close to home as Hampshire, UK, with 30,000 cubic metres of diesel being stolen.

As well as theft, leak detection and maintenance are equally important issues for pipeline operators –

particularly as some well-established pipelines are 40 or 50 years old.

Pipelines are inherently difficult things to monitor, often covering huge distances in remote areas. To date, technological solutions, such as CCTV surveillance, have been either unable to provide solutions for monitoring across the long distances required for pipelines, or they have been too complex to deliver the simple and actionable information that offers benefits for security operatives working on the pipeline.

Pipeline operators need technology that can distinguish – simply, effectively, and in real time – actual threat activities from the vast amount of regular population movement or agriculture that can be occurring on or around the entire length of their pipeline. Distributed acoustic sensing (DAS) is demonstrating itself as a technology with the ability to provide this level of visibility.

DAS explainedDAS uses an optical technique that

involves laser light being pulsed in a standard single-mode fibre-optic cable. When the pulses of light encounter a sound or vibration,


Enhancing pipeline security with distributed acoustic sensingBy Chris Shannon, CEO, Fotech Solutions, Church Crookham, Hants, UK

Fotech Solutions’ CEO Chris Shannon.

it causes interference that manifests as signal backscatter, which is reflected back down the fibre to the sensor. It is from the analysis of these interference patterns that vital information about activity in or around the pipeline can be gleaned. Each individual fibre-optic cable can cover up to 40 km of pipeline.

By analysing the frequency, amplitude, and temporal characteristics of the interference in the backscatter signals it receives, the DAS system can determine what the potential threat actually is. Footsteps and manual digging can be detected from within 15 m of the pipeline. Larger threats such as heavy vehicles and mechanical excavators can be detected within 50 m. However, further filtering is applied so that the system only alarms on activities that could be a potential threat to the pipeline, thus presenting an operator with a reliable alarming mechanism.

As well as detecting external threats, DAS can also detect pipeline leakage, as the vibrations caused by disrupted product flow become visible to pipeline monitors who can ‘see’ an irregularity at a certain point on the pipeline. The ability to track events and disturbances also means DAS is a useful tool for processes such as pig tracking.

Critically, all of this analysis of external and internal factors is done in real time. In this way, DAS can provide complete integrity monitoring along the whole length of a pipeline.

With Fotech’s Helios DAS system, this data and analysis is then fed into a very simple user interface, which shows each section of the pipeline and flashes alerts when issues are detected. All of the analysis is done ‘behind the scenes’ and doesn’t require specially trained security staff to be able to interpret and analyse the raw data.

From experience, Fotech has found that monitoring systems can be too complex – many operators will initially ask for in-depth minute-by-minute data of any and every event along a pipeline, which they must interpret themselves. However, after a few months of operation there is a quick realisation that the most valuable system is one that can tell them, in very simple terms: is there a threat on my pipeline or isn’t there?

That’s not to say that the information used by the Helios system to makes these decisions is not valuable in itself, particularly for analysing long-term trends of activity across the pipeline. System data is accessible to pipeline security personnel and engineers at any given time and may be used for further analysis or system optimisation. However, operatives monitoring the pipeline need to make fast, informed, decisions in real time. False alarms are a significant hindrance to the efficient management of a pipeline and operatives need tools that are able to interpret data quickly and reliably in order to minimise these false alarms and provide the necessary support for their

decision-making when a genuine threat or issue is detected.

DAS and the pipeline industryWhat DAS brings to operators is an extra

layer of surveillance, monitoring, and alerting across a wide area of coverage, and it is not a direct replacement for security guards manning remote-monitoring stations and other surveillance techniques. However, DAS delivers a complementary layer of intelligence by providing real-time information and enhanced visibility of the pipeline to personnel monitoring it.

DAS is geared primarily towards providing clear and manageable information, which can be interpreted by non-technical personnel. Fotech’s solution is designed to ensure that better decisions can be made as quickly as possible to deal with incidents appropriately and effectively. As pipeline operators all around the world look to add security layers to their assets, DAS has the potential to be an extremely powerful tool in the fight against oil and gas theft.


The Helios DAS LivePipe operator interface – a field map indicating a disturbance along a DAS fibre-optic cable.

The Helios DAS system can provide complete integrity monitoring along the whole pipeline.


There is currently a great disparity in approaches and level of rigour applied to risk assessment by pipeline operators largely due to the absence of complete standards or guidelines covering this complex topic. The disparity leads to inconsistent and problematic risk management, as was discussed in a previous column.

Most operators desire sound and useful risk assessment to support their decision-making. Weaknesses in an

operator’s risk-assessment practice are almost entirely due to insufficient guidance. This column strives to improve this situation by challenging past practice as well as discussing proper methods for pipeline risk assessment.

Focusing this time on our past missteps, the use of ‘weightings’ should be a target of critical review in any risk-assessment practice. Weightings have been used in some older risk assessments to give more importance to certain factors. They were usually based on a factor’s perceived importance in the majority of historical pipeline-failure scenarios. For instance, the potential for AC-induced corrosion is usually very low for many kilometres of pipeline, so assigning a low numerical weighting appeared appropriate for that phenomenon. This was intended to show that AC-induced corrosion is a rare threat.

Used in this way, weightings steer risk-assessment results toward predetermined outcomes. Implicit in this use is the assumption of a predictable distribution of future incidents and, most often, an accompanying assumption that the future

distribution will exactly track the past distribution. This practice introduces a bias that will almost always lead to very wrong conclusions for some pipeline segments.

The first problem with the use of weightings is finding a representative basis for the weightings. Weightings were usually based on historical incident statistics – ‘20 per cent of pipeline failures from external corrosion’; ‘30 per cent from third-party damage’; etc. These statistics were usually derived from experience with many kilometres of pipeline over many years of operation. However, different sets of pipeline kilometre-years show different experience. Which past experience best represents the pipeline being assessed? What about changes in maintenance, inspection, and operation over time? Shouldn’t those influence which data sets are most representative to future expectations?

It is difficult, if not impossible, to know which set of historical population behaviour best represents the future behaviour of the segments undergoing the current risk assessment. If weightings are based on, for example, average country-wide history, the non-average behaviour of many kilometres of pipeline is discounted. Using national statistics means including many pipelines with vastly different characteristics from the system being assessed.

If the weightings are based on a specific operator’s experience, then (hopefully) only a very limited amount of data is available. Statistics using small data sets are always problematic. Furthermore, a specific pipeline’s accident experience will probably change with the operator’s changing risk-management focus. When an operator experiences many corrosion failures, he will presumably take actions to specifically reduce the potential for corrosion occurring and, over time, a different mechanism should then become the chief failure cause. So, the weightings would need to change periodically and would always lag behind actual

experience, therefore having no predictive contribution to risk management.

The bigger issue with the use of weightings is the underlying assumption that the past behaviour of a large population will reliably predict the future of an individual. Even if an assumed distribution is valid for the long term population behaviour, there will be many locations along a pipeline where the pre-set distribution is not representative of the particular mechanisms at work there. In fact, the weightings can fully obscure the true threat. The weighted modelling of risk may fail to highlight the most important threats when certain numerical values are kept artificially low, making them virtually unnoticeable.

Use of weightings as a significant source of inappropriate bias in risk assessment is readily demonstrated. One can easily envisage numerous scenarios where, in some segments, a single failure mode should dominate the risk assessment and result in a very high probability of failure rather than only some percentage of the total.

Consider threats such as landslides, erosion, or subsidence, classed as failure mechanisms called geohazards. An assumed distribution of all failure mechanisms will almost certainly assign a very low weighting to this class since most pipelines are not significantly threatened by the phenomenon and, hence, incidents are rare. For example, to match a historical record that shows 30 per cent

RISK MANAGEMENT

Troubles with weightingsBy W.Kent Muhlbauer, WKM Consultancy, LLC, Houston, TX, USA

of pipeline incidents are caused by corrosion and 2 per cent by geohazards, weightings might have been used to make corrosion point totals 15 times higher than geohazard point totals (assuming more points means higher risk) in an older scoring methodology.

But a geohazard phenomenon is a much localised and very significant threat for some pipelines, and may dominate all other threats in some segments. Assigning a 2 per cent weighting masks the reality that, perhaps, 90 per cent of the failure probability on this segment is due to geohazards. So, while the assumed distribution may be valid on average, there will be locations along some pipelines where the pre-set distribution is very wrong. It would not at all be representative of the dominant failure mechanism at work there. The weightings will often completely mask the real threat at such locations.

This is a classic difficulty in moving between the behaviour of statistical populations and individual behaviour. The former is often a reliable predictor – hence the

success of insurance actuarial analyses –but the latter is not.

In addition to masking location-specific failure potential, use of weightings can force only the higher-weighted threats to be perceived ‘drivers’ of risk, at all points along all pipelines. This is rarely realistic. Risk management can become driven solely by the pre-set weightings rather than actual data and conditions along the pipelines. Forcing risk-assessment results to resemble a predetermined incident history will almost certainly create errors.

Since weightings can obscure the real risks and interfere with risk management, their use should be discontinued. Using actual measurements of risk factors avoids the incentive to apply artificial weightings (see the previous column on the need for measurements). Therefore, migration away from older scoring or indexing approaches to a modern risk-assessment methodology will automatically avoid the misstep of weightings.

RISK MANAGEMENT

Kent Muhlbaner contributes a column to each edition of Pipelines International tackling specifics of pipeline risk in bite-sized portions to make this challenging subject more approachable.

FUTURE COLUMN TOPICS

• Consequences of failure–ID the scenarios

• The “Perfect Storm” chain of events

• How do I handle non-pipe assets?

• Getting info from SME’s – facilitation!

• Monetisation of risks – a useful common denominator

• How safe is “safe enough”?

• Damage vs failure – an important distinction

• Q&A on risk assessment evolution

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One can easily envisage numerous scenarios where, in some segments, a single failure mode should dominate the risk assessment and result in a very high probability of failure rather than only some percentage of the total.


Clarion Technical Conferences and Tiratsoo Technical are proud to announce the Pipeline Operations and Management Middle East (POMME) Conference and Exhibition, to be held in Saudi Arabia, one of the world’s leading oil-producing countries, in April 2016.

The event will be held in Dhahran, Saudi Arabia in April 2016 to meet the demand of the huge Saudi Arabian and wider

Middle Eastern petroleum industry. The POMME Conference and Exhibition

has evolved out of the biennial Best Practices in Pipeline Operations and Management Conference and Exhibition, last held in Bahrain in 2013 and supported by Platinum Elite sponsor Saudi Aramco.

Clarion’s Director BJ Lowe explains the move: “We recognise that the Middle East represents a great opportunity for the industry service-provider companies with whom we work

globally. Our aim is to open up a potentially new market to these companies – one that they may not otherwise be able to access — and to expand the opportunities for those companies who may already have a presence there.”

Saudi Arabia holds one-sixth of the world’s proven oil reserves and the world’s fifth largest accumulation of natural gas reserves. It is the second-largest exporter of petroleum to the United States. According to the Organisation of the Petroleum Exporting Countries’ (OPEC) Annual Statistical Bulletin 2012, petroleum exports accounted for approximately 90 per cent of total Saudi export revenues in 2011. Given

this economic dependence on petroleum exports, Saudi Arabia and its national petroleum and natural gas company Saudi Aramco, is willing to invest heavily in the country’s oil and gas industry, including its pipelines.

According to Saudi Arabia’s Foreign Investment Policy, “The Kingdom of Saudi Arabia realises that achieving its ambitious economic goals requires a steady flow of technology and expertise into the country…its policy is to welcome foreign capital and invite it to participate in economic development projects in co-operation with Saudi business.”

UPCOMING EVENTS

Pipeline event opens up new markets

Delegates at the 2013 conference in Bahrain.

Access Middle Eastern pipeline markets

at POMME Make the most of yourattendance at the POMMEConference and Exhibition by visiting nearby MiddleEastern markets.

» Fly to UAE in under an hour

» Drive to Kuwait and Qatar in an hour

» Fly to Oman in an hour and a half

» Fly to Azerbaijan in two and a half hours.

SAUDI ARABIA

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Mr Lowe says “The business opportunities for international and Middle Eastern pipeline products and service companies are vast. According to analysts, Saudi Arabia’s economy has grown by 29.6 per cent since 2008. We anticipate a greater opportunity and return for suppliers by locating the POMME event in Saudi Arabia.”

Tiratsoo Technical’s Director John Tiratsoo adds “The event also provides a pipeline-specific forum to discuss the unique operations, system-integrity, and maintenance issues faced by Middle Eastern pipeline operators. There is currently no other event that brings Middle East-based pipeline companies within the region together in this way.

“Pipeline integrity and maintenance strategies in the region are constantly being adapted, and there is a real drive for industry innovation. Our conference programme aims to facilitate this conversation and knowledge-sharing within the industry.”

Mr Tiratsoo says “The region is a key focus for Clarion and Tiratsoo Technical, and as our relationships strengthen in the region, we want to ensure that others’ do too.”

UPCOMING EVENTS

Delegates at a networking event.

Attendees discuss pipeline operations with exhibitors.Event organisers BJ Lowe, Frances Webb and John Tiratsoo.


enters a new ageIntroducing the digital edition

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JUNE 2014

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New export horizons

AUSTRALIAJUNE 2014ISSUE 20

New export horizons

AUSTRALIA

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With only a few months remaining until the 10th International Pipeline Conference and Exposition kicks-off in Calgary, Canada, the event’s Official Media Partner Pipelines International gives you the latest information on this exciting industry event.

Thousands of the world’s leading pipeline industry professionals will gather for the biennial event from

29 September–3 October 2014.The International Pipeline Conference

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A world-class ExpositionThe International Pipeline Exposition will

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The 2014 Exposition will be held from Tuesday 30 September to Thursday 2 October, so be sure to exchange knowledge and remain current with advances in corrosion, integrity, detection, testing, inspection, and pigging.

Meet the Pipelines International team

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UPCOMING EVENTS

Event attendees enjoying the networking opportunities at the 2010 International Pipeline Conference.

SAVE THE DATE!

29 September– 3 October, 2014 The Hyatt Regency Hotel and the TELUS Convention CentreCalgary, Alberta, Canada


Don't miss out on the opportunity to learn from top industry professionals from around the world at the upcoming Fixing Pipeline Problems Conference and Exhibition, to be held from 21–24 October 2014 at the Estrel Hotel, Berlin, Germany.

The international event, organised by Tiratsoo Technical, a division of Great Southern Press, and Houston-based

Clarion Technical Conferences, will provide both a forum for discussion as well as a platform to showcase the industry’s latest achievements.

A wide variety of issues concerning pipeline rehabilitation will be covered, ranging from the initial stages of evaluation of a pipeline's condition, to the steps required to undertake rehabilitation of the structure to ensure its continued fitness-for-purpose and prolong its economic lifetime.

The event provides a unique opportunity to meet face-to-face with the pipeline industry personnel, showcasing the latest achievements in pipeline rehabilitation.

The Fixing Pipeline Problems (FPP) conference programme will be divided into the following broad areas of interest: • Repair and rehabilitation practices and

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An opportunity not to be missedThe event will not only discuss the

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The conference programme will be of relevance to all involved in the operation and lifetime planning of pipelines that transport all types of hazardous hydrocarbons both on- and offshore, in particular oil and gas, as well as to those involved in their regulation and safety.

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UPCOMING EVENTS

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Focus Valves and pumps Welding Trenchless technology Compressors

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Feature Major pipeline logistics Pipe manufacture Safety Offshore

Integrity and Maintenance

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DEADLINE 8 August 2014 7 November 2014 20 February 2015 24 June 2015

COMING IN FUTURE ISSUES

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Pigging & In-line InspectionHouston, USA 2–3 June 2014

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DOT Pipeline Safety Regulations - Overview and Guidelines for Compliance

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Pipeline Integrity Courses, Houston 2014


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Pipeline Integrity Management


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The Pipeline Defects ClinicHouston, USA 2–4 June 2014

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Advanced Pipeline Risk Management


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Defect Assessment Calculations Workshop


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Advanced Pipeline Risk Management


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Global Petroleum Show Calgary, Canada 10–12 June 2014

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Global Pipe Tech SummitRome, Italy

29 September– 3 October 2014

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International Pipeline Exposition and Conference

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JUNE 2014ISSUE 20

New export horizons

AUSTRALIA

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New export horizons